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**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

**FORM40-F**

 

[Check one]

 
| o          | ** ** | **REGISTRATION STATEMENT PURSUANT TO  SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934**    |
|------------|------------|----------------------------------------------------------------------------------------------|
| **OR**     |
| ** ** | ** ** | ** **                                                                                   |
| R          | ** ** | **ANNUAL REPORT PURSUANT TO SECTION 13(a)  or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |

 

**Forthe fiscal year ended: December 31, 2009     Commission File Number:  1-34513**

 

**CENOVUSENERGY INC.**

(Exact name of Registrant as specified in its charter)

 

**Notapplicable**

(Translation of Registrant’s name into English (if applicable)

 

**Canada**

(Province or other jurisdiction of incorporation or organization)

 

**1311**

(Primary StandardIndustrial

ClassificationCode Number (if applicable))

 

**Notapplicable**

(I.R.S. Employer

IdentificationNumber (if applicable))

 

**4000,421-7th Avenue S.W.Calgary, Alberta, Canada T2P 4K9(403) 766-2000**

(Address andtelephone number of Registrant’s principal executive offices)

 

**CTCorporation System111 8th****AvenueNew York, New York 10011**

**(212)894-8641**

(Name, address (including zip code) and telephone number (includingarea code)

of agent for service in the United States)

 

Securitiesregistered or to be registered pursuant to Section 12(b) of the Act.

 

| Title of each class                                                                      |       | Name of each exchange on which registered |
|------------------------------------------------------------------------------------------|------------|-------------------------------------------|
|                                                                                     |       |                                      |
| **Common  shares, no par value (together with associated common share purchase rights)** | ** ** | **New  York Stock Exchange**              |

 

Securitiesregistered or to be registered pursuant to Section 12(g) of the Act.

 

**None**

(Title of Class)

 

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Securities for which there is a reporting obligationpursuant to Section 15(d) of the Act.

 

**None**

(Title of Class)

 

For Annual Reports indicate by check mark theinformation filed with this Form:

 

 

R Annual information form      R Audited annual financial statements

 

Indicate the number ofoutstanding shares of each of the issuer’s classes of capital or common stockas of the close of the period covered by the annual report:

 

**751,308,563**

 

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

 
| Yes o 82- |   |   | No R |
|-----------|--------|--------|------|

 

Indicate by check mark whether the Registrant (1) hasfiled all reports to be filed by Section 13 or 15(d) of the Exchange Act duringthe preceding 12 months (or for such shorter period that the Registrant wasrequired to file such reports) and (2) has been subject to filing requirementsfor the past 90 days.

 

Yes o   No R

 

Indicate by check mark whether the Registrant hassubmitted electronically and posted on its corporate Web site, if any, everyInteractive Data File required to be submitted and posted pursuant to Rule 405of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (orfor such shorter period that the Registrant was required to submit and postsuch files).

 

Yes o   No o

 

The Annual Report on Form 40-F shall be incorporatedby reference into or as an exhibit to, as applicable, each of the Registrant’sRegistration Statements under the Securities Act of 1933:  Form S-8 (File No. 333-163397).
|   |
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40-F-2

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**Principal Documents**

 

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

 
| (a)    | Annual Information Form of  Cenovus Energy Inc. for the fiscal year ended December 31, 2009.                                                                                                                       |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                               |
| (b)    | Management’s  Discussion and Analysis of Cenovus Energy Inc. for the fiscal year ended  December 31, 2009.                                                                                                    |
|   |                                                                                                                                                                                                               |
| (c)    | Consolidated Financial Statements of Cenovus Energy  Inc. as at December 31, 2009 *(Note 21 to the  Consolidated Financial Statements relates to United States Accounting  Principles and Reporting (U.S. GAAP)).* |

 

40-F-3

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**CENOVUS ENERGY INC.**

 

 

**ANNUAL INFORMATION FORM**

 

**FOR THE YEAR ENDED DECEMBER 31, 2009**

 

 

**February 18, 2010**

 

 

Cenovus Energy Inc. AnnualInformation Form for the year ended December 31, 2009

 

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**TABLE OF CONTENTS**

 
| NOTICE TO READER                                     |   | 1  |
|------------------------------------------------------|--------|----|
| CORPORATE STRUCTURE                                  |   | 3  |
| Intercorporate  Relationships                        |   | 3  |
| GENERAL  DEVELOPMENT OF OUR BUSINESS                 |   | 4  |
| The Arrangement                                      |   | 4  |
| Our Business                                         |   | 5  |
| NARRATIVE DESCRIPTION OF OUR BUSINESS                |   | 7  |
| Integrated  Oil Division                             |   | 8  |
| Canadian  Plains Division                            |   | 12 |
| RESERVES AND OTHER OIL AND GAS INFORMATION           |   | 17 |
| Reserves Quantities Information                      |   | 17 |
| Other Disclosures About Oil and Gas Activities       |   | 25 |
| Production Volumes and Per-Unit Results              |   | 28 |
| Drilling  Activity                                   |   | 33 |
| Location  of Wells                                   |   | 33 |
| Interest in Material Properties                      |   | 34 |
| Capital Expenditures, Acquisitions and Divestitures  |   | 35 |
| Delivery  Commitments                                |   | 35 |
| GENERAL                                              |   | 36 |
| Competitive  Conditions                              |   | 36 |
| Environmental  Protection                            |   | 36 |
| Social and Environmental Policies                    |   | 37 |
| Employees                                            |   | 38 |
| Foreign  Operations                                  |   | 38 |
| DIRECTORS AND EXECUTIVE OFFICERS                     |   | 39 |
| Directors                                            |   | 39 |
| Five Year Occupational History of Directors          |   | 40 |
| Other Reporting Issuer Experience of Directors       |   | 42 |
| Executive  Officers                                  |   | 43 |
| Five Year Occupational History of Executive Officers |   | 43 |
| Corporate Cease Trade Orders or Bankruptcies         |   | 44 |
| Conflicts  of Interest                               |   | 45 |
| STATEMENT OF EXECUTIVE COMPENSATION                  |   | 46 |
| Compensation Discussion and Analysis                 |   | 46 |
| Tables                                               |   | 52 |
| Director  Compensation                               |   | 56 |
| AUDIT  COMMITTEE                                     |   | 58 |
| Composition of the Audit Committee                   |   | 58 |
| Pre-Approval Policies and Procedures                 |   | 59 |
| External  Auditor Service Fees                       |   | 59 |
| STATEMENT OF CORPORATE GOVERNANCE PRACTICES          |   | 60 |
| Board of  Directors                                  |   | 60 |
| Board  of Directors’ Mandate                    |   | 61 |
| Position  Descriptions                               |   | 62 |
| Orientation and Continuing Education of Directors    |   | 63 |
| Ethical  Business Conduct                            |   | 63 |
| Nomination  of Directors                             |   | 64 |
| Compensation                                         |   | 65 |
| Audit  Committee                                     |   | 65 |
| Reserves  Committee                                  |   | 65 |

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | i |
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| Safety, Environment and Responsibility Committee                                        |   | 65  |
|-----------------------------------------------------------------------------------------|--------|-----|
| Board  Assessments                                                                      |   | 65  |
| Key  Governance Documents                                                               |   | 66  |
| DESCRIPTION OF CAPITAL STRUCTURE                                                        |   | 67  |
| Common Shares                                                                           |   | 67  |
| Preferred  Shares                                                                       |   | 67  |
| Employee  Stock Option Plan                                                             |   | 67  |
| SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY  COMPENSATION PLANS                     |   | 71  |
| DIVIDENDS                                                                               |   | 71  |
| MARKET  FOR SECURITIES                                                                  |   | 71  |
| CREDIT  RATINGS                                                                         |   | 72  |
| PRIOR SALES                                                                             |   | 73  |
| Debt  Securities                                                                        |   | 73  |
| RISK FACTORS                                                                            |   | 73  |
| Risks relating to the Arrangement                                                       |   | 73  |
| Risks  relating to our Business                                                         |   | 74  |
| Other  Risk Factors                                                                     |   | 80  |
| LEGAL PROCEEDINGS AND REGULATORY ACTIONS                                                |   | 80  |
| INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL  TRANSACTIONS                            |   | 80  |
| INTERESTS  OF EXPERTS                                                                   |   | 81  |
| TRANSFER  AGENTS AND REGISTRARS                                                         |   | 81  |
| MATERIAL  CONTRACTS                                                                     |   | 81  |
| PROMOTER                                                                                |   | 83  |
| ADDITIONAL  INFORMATION                                                                 |   | 83  |
| NOTE REGARDING FORWARD-LOOKING STATEMENTS                                               |   | 84  |
| NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS  INFORMATION                         |   | 86  |
| GLOSSARY                                                                                |   | 87  |
| ABBREVIATIONS                                                                           |   | 89  |
| APPENDIX A - Report on Reserves Data by Independent  Qualified Reserves Evaluators      |   | A-1 |
| APPENDIX B - Report of Management and Directors on  Reserves Data and Other Information |   | B-1 |
| APPENDIX  C - Audit Committee Mandate                                                   |   | C-1 |
| APPENDIX  D - Board of Directors’ Mandate                                          |   | D-1 |

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | ii |
|-----------------------------------------------------------------------------------|--------|----|

 

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**NOTICE TO READER**

 

This is the annualinformation form of Cenovus Energy Inc. for the year ended December 31,2009. In this annual information form, unless otherwise specified or thecontext otherwise requires, reference to “we”, “us”, “our” or “Cenovus”includes reference to subsidiaries of, and partnership interests held by,Cenovus Energy Inc. and its subsidiaries subsequent to the Effective Date andthe Cenovus Assets, as held by EnCana prior to the Effective Date. We acquiredthe Cenovus Assets from EnCana on the Effective Date in connection with theArrangement.

Unless otherwisespecified, all dollar amounts are expressed in U.S. dollars and all referencesto “dollars”, “US$” or to “$” are to U.S. dollars and all references to “C$”are to Canadian dollars.

Unless otherwiseindicated, all financial information included in this annual information formis determined using Canadian GAAP, which differs from U.S. GAAP in certainmaterial respects, and thus may not be comparable to financial statements andfinancial information of U.S. companies. The notes to our audited consolidatedfinancial statements for the year ended December 31, 2009 contain adiscussion of the principal differences between the financial resultscalculated under Canadian GAAP and under U.S. GAAP.

Certain historicalinformation contained in this annual information form has been provided by, orderived from information provided by, certain third parties, including EnCana.Although we have no knowledge that would indicate that any such information isuntrue or incomplete, we assume no responsibility for the completeness oraccuracy of such information or the failure by such third parties to discloseevents which may have occurred or may affect the completeness or accuracy ofsuch information, but which are unknown to us.

We commencedindependent operations on December 1, 2009 following the completion of theArrangement. The description of our business, recent significant developments,the presentation of financial statements and other information throughout thisannual information form in respect of periods prior to December 1, 2009 isbased on information with respect to the Cenovus Assets as operated by EnCanaprior to December 1, 2009. See “General Development of our Business - TheArrangement” for further information on the Arrangement. Such financialinformation has been derived from the historical consolidated financialstatements of EnCana for each of the relevant periods on a carve-out basis fromsuch historical consolidated financial statements of EnCana for the relevantperiod and should be read in conjunction with our audited consolidatedfinancial statements for the year ended December 31, 2009 and thecarve-out consolidated financial statements in relation to Cenovus Energy forthe year ended December 31, 2008 and the Management’s Discussion andAnalysis thereon, each as set out in the Information Circular of EnCana dated October 20,2009 relating to an arrangement involving Cenovus Energy Inc., and theunaudited interim carve-out consolidated financial statements in relation toCenovus Energy for the nine months ended September 30, 2009 and theManagement’s Discussion and Analysis thereon which are accessible on the SEDARprofile of EnCana at ***www.sedar.com***and have been filed with the SEC and are available via EDGAR at ***www.sec.gov***.

“Cenovus Energy”represents the historical operations, assets, liabilities and cash flows of theIntegrated Oil and Canadian Plains Divisions of EnCana (prior to the completionof the Arrangement), as well as a portion of the Market Optimization andCorporate functions of EnCana (prior to the completion of the Arrangement). Asa result, comparative historical financial results may not be indicative ofthose that would have resulted had we existed as a stand-alone entity duringthose periods. See “Risk Factors”.

This annual information formcontains certain forward-looking statements or information within the meaningof applicable securities legislation. Forward-looking statements or 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 1 |
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information aretypically identified by words such as “projected”, “anticipate”, “believe”, “expect”,“plan”, “intend” or similar words suggesting future outcomes or statementsregarding an outlook. All statements other than statements of historical factcontained in this annual information form are forward-looking statements orinformation. See “Note Regarding Forward-Looking Statements”.

NI 51-101 imposesoil and gas disclosure standards for Canadian public companies engaged in oiland gas activities. We have obtained an exemption from the Canadian securitiesregulatory authorities to permit us to provide disclosure in accordance withthe relevant legal requirements of the SEC. This facilitates comparability ofour oil and gas disclosure with that provided by U.S. and other internationalissuers, given that we are active in the U.S. capital markets. Accordingly, theproved and probable reserves data and much of the other oil and gas informationincluded in this annual information form is disclosed in accordance with U.S.disclosure requirements. Such information, as well as the information that weanticipate disclosing in the future in reliance on such exemption, may differfrom the corresponding information prepared in accordance with NI 51-101standards. Pursuant to U.S. reporting protocols, production and reserves informationis required to be presented on an after royalties basis. In addition, toprovide more complete information on our business, we are voluntarily providingproduction and reserves information on a before royalties basis. The probablereserves data contained in this annual information form is also being providedon a voluntary basis. See “Reserves and Other Oil and Gas Information” and “NoteRegarding Reserves Data and Other Oil and Gas Information”.

Unless otherwise noted, capitalizedterms used in this annual information form have the meaning ascribed theretounder the heading “Glossary”.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 2 |
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**CORPORATE STRUCTURE**

 

Cenovus Energy Inc.was incorporated on September 24, 2008 under the CBCA as 7050372 CanadaInc. Pursuant to the Arrangement, 7050372 and Subco amalgamated under the CBCAon the Effective Date with the amalgamated company’s name being “Cenovus EnergyInc.”. Our executive and registered office is located at #4000, 421 - 7 AvenueS.W., Calgary, Alberta, Canada T2P 4K9. Prior to completion of the Arrangement,7050372 did not carry on any active business and did not issue any shares.

For a furtherdescription of the Arrangement, see “General Development of Our Business – TheArrangement”.

**Intercorporate Relationships**

We have the following principalsubsidiaries and partnerships which have total assets that exceed ten percentof our total consolidated assets or sales and revenues which exceed ten percentof our total consolidated sales and revenues as at and for the year ended December 31,2009:

 
| **Subsidiaries & Partnerships** | ** ** | **Percentage Owned****(1)** | ** ** | **Jurisdiction of  Incorporation,  Continuance,  Formation or  Organization** |
|------------------------------------------|------------|-----------------------------|------------|-------------------------------------------------------------------------------|
| Cenovus  FCCL Ltd.                       |       | 100                         |       |                                                                          | Alberta |
| FCCL  Partnership                        |       | 50                          |       |                                                                          | Alberta |
| Cenovus  Downstream Holdings ULC         |       | 100                         |       |                                                                          | Alberta |
| Cenovus US  Refineries, LLC              |       | 100                         |       |                                                                          | Delaware |
| Cenovus US  Refinery Holdings            |       | 100                         |       |                                                                          | Delaware |
| WRB  Refining LLC                        |       | 50                          |       |                                                                          | Delaware |

**Note:**

(1) Includes indirect ownership.

 

The above table does not include allof our subsidiaries and partnerships. The assets and revenues of our unnamedsubsidiaries and partnerships did not exceed 20 percent of our totalconsolidated assets or total consolidated sales and revenues as at and for theyear ended December 31, 2009.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 3 |
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**GENERAL DEVELOPMENT OF OUR BUSINESS**

 

Cenovus is anintegrated oil company headquartered in Calgary, Alberta. Our operationsinclude enhanced oil recovery (“EOR”) properties and established crude oil andnatural gas production in Alberta and Saskatchewan. We also have ownershipinterests in two refineries in Illinois and Texas, USA.

We beganindependent operations on December 1, 2009 following the split of EnCanainto two independent publicly traded energy companies – Cenovus and EnCana.Although we are a new company, we have operated a number of our assets fordecades.

**The Arrangement**

The division ofEnCana into two highly focused and independent publicly traded energy companieswas completed on November 30, 2009. It resulted in, among other things,the establishment of our company as an independent integrated oil companyanchored by stable production and cash flow from well-established crude oil andnatural gas plays, integrated from crude oil production through to refinedproducts.

Pursuant to theArrangement and a number of preliminary transactions completed on or prior tothe Effective Date, we indirectly acquired:

(a)                                 those assetsassociated with EnCana’s Integrated Oil Division, which included EnCana’sinterests in the Foster Creek, Christina Lake, Narrows Lake and Borealis areasand the U.S. refinery interests in addition to certain of EnCana’s otherbitumen interests and natural gas assets located in the Athabasca area;

(b)                                 those assetsassociated with EnCana’s Canadian Plains Division, which included the majorityof EnCana’s legacy oil and natural gas assets in southern Alberta andSaskatchewan. This Division included the EOR properties located at Weyburn andPelican Lake, as well as the Southern Alberta oil and gas properties; and

(c)                                 those assetsassociated with the foregoing businesses, including marketing, corporate andoffice space (including a proportionate share of The Bow office project).

Pursuant to thePre-Arrangement Reorganization in connection with the Arrangement, EnCanatransferred the Cenovus Assets to Subco in exchange for, among other things, aninterest bearing demand intercompany note in the amount of $3.5 billion(the “Demand Note”).

The AssumedLiabilities assumed, directly or indirectly, in connection with the Arrangementincluded, among others, those liabilities relating to EnCana’s Integrated Oiland Canadian Plains Divisions described above.

As a result of theArrangement, each shareholder of EnCana (other than a Dissenting Shareholder)received one new EnCana common share (such shares being represented by existingEnCana common share certificates) and one Common Share for each EnCana commonshare held. On the Effective Date, 751,273,307 Common Shares were issued tosuch former holders of EnCana common shares.

In connection withthe Arrangement and in order to provide ongoing liquidity, including workingcapital requirements, prior to the completion of the Arrangement, we obtainedcommitments from a syndicate of banks to make available an unsecured creditfacility in the amount of C$2.5 billion. The revolving syndicated creditfacility consists of two tranches, a C$2.0 billion three-year tranche anda C$500 million 364-day tranche. The terms of each of these facilitiescommenced on the Effective Date.

On September 18, 2009, apredecessor entity of Cenovus completed, in three tranches, a $3.5 billionprivate offering of debt securities (comprised of the 2014 Notes, 2019 Notesand 2039 Notes) which are exempt from the registration requirements of the U.S.Securities Act 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 4 |
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under Rule 144Aand Regulation S (the “Cenovus Note Offering”). See “Prior Sales”. The netproceeds of the Cenovus Note Offering were placed into an escrow accountpending the completion of the Arrangement. Upon completion of the Arrangement,the net proceeds, together with other pre-funded amounts, were released fromescrow and were applied to repay all of the amounts outstanding under theDemand Note.

We have filed abusiness acquisition report in Form 51-102F4 in respect of theArrangement. The business acquisition report is accessible under our profile onSEDAR at ***www.sedar.com***and in our Form 6-K filed with the SEC on December 16, 2009,available via EDGAR at ***www.sec.gov***.

**Our Business**

Our operations areorganized into two operating divisions:

·                  **Integrated Oil**Division, which includes all of the assets within theupstream and downstream integrated oil business with our joint venture partner,as well as other bitumen interests and the Athabasca natural gas assets. TheIntegrated Oil Division has assets in both Canada and the U.S. including twomajor EOR properties: (i) Foster Creek; and (ii) Christina Lake; aswell as two refineries: (i) Wood River; and (ii) Borger.

·                  **Canadian Plains**Division, which contains established crude oil and naturalgas development assets in Alberta and Saskatchewan and includes two major EORproperties: (i) Weyburn; and (ii) Pelican Lake; as well as theSouthern Alberta oil and gas properties. The Division also markets Cenovus’scrude oil and natural gas, as well as third-party purchases and sales ofproduct that provide operational flexibility for transportation commitments,product type, delivery points and customer diversification.

For financialstatement reporting purposes, our operating and reportable segments are:

·                  **Upstream Canada**, which includes Cenovus’s development and production of bitumen, crudeoil, natural gas and natural gas liquids (“NGLs”) and other related activitiesin Canada. This includes the Foster Creek and Christina Lake operations whichare jointly owned with ConocoPhillips, an unrelated U.S. public company, andoperated by Cenovus.

·                  **Downstream Refining**, which is focused on the refining of crude oil into petroleum andchemical products at two refineries located in the United States. Therefineries are jointly owned with ConocoPhillips and operated byConocoPhillips.

·                  **Corporate andEliminations**, which primarily includesunrealized gains or losses recorded on derivative financial instruments as wellas other Cenovus-wide costs for general and administrative and financingactivities. As financial instruments are settled, realized gains and losses arerecorded in the operating segment to which the derivative instrument relates.Eliminations relate to sales and operating revenues and purchased productbetween segments recorded at transfer prices based on current market prices andto unrealized intersegment profits in inventory.

In addition to theArrangement, the following describes the significant events of the last threeyears in respect of our business:

***2009***

·                  In the firstquarter of 2009, two new expansion phases at Foster Creek were commissioned.Phases D and E added a total of 60,000 barrels per day of bitumen productioncapacity, increasing the total production capacity of Foster Creek toapproximately 120,000 barrels per day.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 5 |
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·                  In the second quarter of 2009, ajoint regulatory application for Foster Creek phases F, G and H wassubmitted to the Energy Resources Conservation Board (“ERCB”) and Alberta Environment.Each phase is expected to increase production capacity by 30,000 barrelsper day of bitumen.

·                  In the fourth quarter of 2009, FCCLsanctioned the next phase, phase D, of expansion at Christina Lake, whichis expected to increase production capacity by 40,000 barrels per day ofbitumen in 2013.

·                  In the fourth quarter of 2009, ajoint regulatory application for Christina Lake phases E, F and G wassubmitted to the ERCB and Alberta Environment. Each phase is expected toincrease production capacity by 40,000 barrels per day of bitumen.

***2008***

·                  In the second quarter of 2008,Christina Lake phase B expansion was commissioned. This phase added8,000 barrels per day of production capacity, increasing the totalproduction capacity at Christina Lake to approximately 18,000 barrels perday of bitumen.

·                  In the third quarter of 2008, theWood River refinery received regulatory approvals to start construction on theCORE project. Our 50 percent share of the CORE project is expected to costapproximately $1.8 billion and is anticipated to be completed and inoperation in 2011. The expansion is expected to more than double heavy crudeoil refining capacity to approximately 240,000 barrels per day andincrease crude oil refining capacity by 50,000 barrels per day to approximately356,000 barrels per day.

***2007***

·     The creationof the integrated oil business venture, consisting of upstream and downstreamassets, with ConocoPhillips was completed on January 3, 2007. It iscomprised of two 50-50 operating entities, a Canadian upstream enterpriseoperated by Cenovus and a U.S. downstream enterprise operated byConocoPhillips, with both ConocoPhillips and Cenovus having contributed equallyvalued assets and equity. The integrated oil business provides greatercertainty of execution for our Foster Creek and Christina Lake EOR projects andallows us to participate in the full value chain from crude oil productionthrough to refined products.

·                 In the first quarter of 2007, FosterCreek phase C expansion was commissioned. This phase added30,000 barrels per day of production capacity, increasing the totalproduction capacity at Foster Creek to approximately 60,000 barrels perday of bitumen.

·                 In the second quarter of 2007, a25,000 barrel per day coker addition at the Borger refinery was completed. Therefinery was shut down for approximately one month to complete a major plannedturnaround timed to coincide with bringing the new coker online. The refinerystarted up again in June 2007 and ran its first barrel of Canadian heavyoil on July 10, 2007, marking a major milestone for the refinery.

·                 In the third quarter of 2007,regulatory approval and sanctioning was received for the Christina Lakephase C expansion, which is expected to increase production capacity by40,000 barrels per day of bitumen in 2011.

·                  In the fourthquarter of 2007, a joint regulatory application for development of the Borealisproperty was submitted to the ERCB and Alberta Environment that would allow forthe construction of a SAGD facility with production capacity of approximately35,000 barrels per day of bitumen.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | 6 |
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**NARRATIVEDESCRIPTION OF OUR BUSINESS**

 

Thefollowing maps outline the location of our assets, including our majorproperties and refining assets as at December 31, 2009.

 

 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 7

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Onehundred percent of our reserves and production are located in Canada. At December 31,2009, we had a land base of approximately 7.8 million net acres and aproved reserves base (our share after royalties) of approximately719 million barrels of bitumen reserves, 232 million barrels of crudeoil and NGLs reserves and 1,474 billion cubic feet of natural gasreserves. The estimated proved reserves life index as at December 31, 2009was approximately 14.7 years. We also had probable reserves (our shareafter royalties) of approximately 403 million barrels of bitumen,127 million barrels of crude oil and NGLs and 405 billion cubic feetof natural gas as at December 31, 2009.

 

Thefollowing narrative describes each of our operating divisions in greaterdetail.

 

**Integrated Oil Division**

 

TheIntegrated Oil Division includes all of the assets within the integrated oilbusiness with ConocoPhillips described below, as well as other bitumeninterests and the Athabasca natural gas assets. The Integrated Oil Division hasassets in both Canada and the U.S. and contains two EOR properties: (i) FosterCreek; and (ii) Christina Lake; as well as two refineries at Wood Riverand Borger. In 2009, the Integrated Oil Division had capital investment ofapproximately $1,383 million, which included continued development of theCORE project, as well as the drilling of approximately 80 net wells(including 40 stratigraphic test wells).

 

Asat December 31, 2009, we held bitumen rights of approximately1,055,000 gross acres (760,000 net acres) within the Athabasca andCold Lake areas, as well as the exclusive rights to lease an additional652,000 net acres on our behalf and/or our assignee’s behalf on the ColdLake Air Weapons Range.

 

Thefollowing table summarizes landholdings for the Integrated Oil Division as at December 31,2009.

 
| ** **                             | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total**   | ** ** | **Average** | ** ** |
|----------------------------------------|------------|---------------|------------|-----------------|------------|-------------|------------|-------------|------------|
| ** **                             | ** ** | **Acreage**   | ** ** | **Acreage**     | ** ** | **Acreage** | ** ** | **Working** | ** ** |
| **Landholdings (thousands of  acres)** | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross**   | ** ** | **Net**     | ** ** | **Gross** | ** ** | **Net** | ** ** | **Interest** | ** ** |
| Foster  Creek                          |       | 7             |       | 4               |       | 65          |       | 32          |       | 72 |   | 36 |   | 50% |   |
| Christina  Lake                        |       | 1             |       | -               |       | 24          |       | 12          |       | 25 |   | 12 |   | 50% |   |
| Narrows  Lake(1)                       |       | -             |       | -               |       | 25          |       | 15          |       | 25 |   | 15 |   | 60% |   |
| Borealis                               |       | -             |       | -               |       | 36          |       | 36          |       | 36 |   | 36 |   | 100% |   |
| Athabasca                              |       | 520           |       | 443             |       | 355         |       | 283         |       | 875 |   | 726 |   | 83% |   |
| Other                                  |       | 23            |       | 10              |       | 923         |       | 675         |       | 946 |   | 685 |   | 72% |   |
| Integrated  Oil Total                  |       | 551           |       | 457             |       | 1,428       |       | 1,053       |       | 1,979 |   | 1,510 |   | 76% |   |

**Note:**

(1)          Underan area of mutual interest arrangement, ConocoPhillips made an election toparticipate in a certain Cenovus lease acquisition through ConocoPhillips’sinterest in FCCL, reducing Cenovus’s working interest share to 50 percenton January 1, 2010.

 

Thefollowing table sets forth our share of daily average production figures forthe periods indicated.

 
| ** **                       | ** ** | **Crude Oil** | ** ** | ** **      | ** ** | ** **           | ** ** |
|----------------------------------|------------|---------------|------------|-----------------|------------|----------------------|------------|
| ** **                       | ** ** | **and NGLs**  | ** ** | **Natural Gas** | ** ** | **Total Production** | ** ** |
| ** **                       | ** ** | **(bbls/d)**  | ** ** | **(MMcf/d)**    | ** ** | **(BOE/d)**          | ** ** |
| **Production (annual  average)** | ** ** | **2009**      | ** ** | **2008**        | ** ** | **2009**             | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Foster Creek                     |       | 36,654        |       | 25,947          |       | -                    |       | - |   | 36,654 |   | 25,947 |   |
| Christina Lake                   |       | 6,527         |       | 4,236           |       | -                    |       | - |   | 6,527 |   | 4,236 |   |
| Athabasca                        |       | -             |       | -               |       | 49                   |       | 63 |   | 8,167 |   | 10,500 |   |
| Other                            |       | 2,553         |       | 2,729           |       | -                    |       | - |   | 2,553 |   | 2,729 |   |
| Integrated Oil Total             |       | 45,734        |       | 32,912          |       | 49                   |       | 63 |   | 53,901 |   | 43,412 |   |

 

 
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Thefollowing table summarizes the Integrated Oil Division’s interests in producingwells as at December 31, 2009. These figures exclude wells which werecapable of producing, but that were not producing as of December 31, 2009.

 
| ** **                             | ** ** | **    Producing**  | ** ** | **Producing** | ** ** | **Total**           | ** ** |
|----------------------------------------|------------|-----------------------------------|------------|---------------|------------|---------------------|------------|
| ** **                             | ** ** | **    Oil  Wells** | ** ** | **Gas Wells** | ** ** | **Producing Wells** | ** ** |
| **Producing Wells (number of  wells)** | ** ** | **Gross**                         | ** ** | **Net**       | ** ** | **Gross**           | ** ** | **Net   ** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Foster  Creek                          |       | 171                               |       | 86            |       | -                   |       | - |   | 171 |   | 86 |   |
| Christina  Lake                        |       | 16                                |       | 8             |       | 8                   |       | 4 |   | 24 |   | 12 |   |
| Athabasca                              |       | -                                 |       | -             |       | 683                 |       | 647 |   | 683 |   | 647 |   |
| Integrated  Oil Total                  |       | 187                               |       | 94            |       | 691                 |       | 651 |   | 878 |   | 745 |   |

 

Thefollowing describes major producing areas or activities in the Integrated OilDivision.

 

***Integrated Oil Business***

 

OnJanuary 3, 2007, the creation of the integrated oil business withConocoPhillips was completed. The integrated oil business includes Canadianupstream assets contributed by Cenovus and U.S. downstream assets contributedby ConocoPhillips. The business is comprised of two 50-50 operating entities, aCanadian upstream entity, FCCL, operated by Cenovus and a U.S. downstreamenterprise, WRB, operated by ConocoPhillips.

 

FCCLowns the Foster Creek and Christina Lake EOR projects. Cenovus FCCL Ltd., ourwholly-owned subsidiary, is the operating and managing partner of FCCL. WRBowns the Wood River and Borger refineries. ConocoPhillips held adisproportionate economic interest in the Borger refinery of 85 percent in2007 and 65 percent in 2008, before reverting to 50 percent in 2009.ConocoPhillips is the operator and manager of WRB. FCCL has a management committee,while WRB has a board of directors; both are composed of three of ourrepresentatives and three of ConocoPhillips’s representatives, with eachcompany holding equal voting rights.

 

AtDecember 31, 2009, the combined production capacity of the Foster Creekand Christina Lake properties was approximately 138,000 barrels per day.FCCL plans to increase production capacity to approximately218,000 barrels of bitumen per day from the combined facilities at FosterCreek and Christina Lake with the completion of the Christina Lake phase Cexpansion in 2011 and phase D expansion in 2013.

 

AtDecember 31, 2009, WRB had processing capability to refine up toapproximately 70,000 barrels per day of bitumen equivalent. WRB plans torefine approximately 150,000 barrels per day of bitumen equivalent toprimarily motor fuels with the completion of the CORE project in 2011.

 

*Foster Creek*

 

Wehave a 50 percent interest in Foster Creek, an EOR property which usesSAGD technology and produces from the McMurray formation. We hold surfaceaccess rights from the Governments of Canada and Alberta and bitumen rights forexploration, development and transportation from areas within the Cold Lake AirWeapons Range which were granted by the Government of Alberta. In addition, wehold exclusive rights to lease several hundred thousand acres of bitumen rightsin other areas on the Cold Lake Air Weapons Range on our behalf and/or ourassignee’s behalf. In the first quarter of 2009, two new expansion phases werecompleted at Foster Creek adding production capacity of approximately60,000 barrels of bitumen per day and increasing total production capacityto approximately 120,000 barrels of bitumen per day.

 

Wecontinually research and develop technologies to increase bitumen recovery,decrease costs of extracting bitumen and reduce our environmental footprint.One focus area is alternate methods of artificial lift where we utilize newpump designs that are expected to enable us to optimize SAGD performance byoperating at lower pressures, thereby realizing lower steam-oil ratios anddecreasing facility capital and operating costs. As at 

 

 
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December 31,2009, electrical submersible pumps were in use on 133 wells at FosterCreek and we expect to continue to utilize this technology on new SAGD wells.

 

Inaddition, we have successfully piloted another technology at Foster Creekwhereby an additional well, a wedge well, is drilled between two producing wellpairs to produce bitumen that is heated by proximity to a steam chamber, but isnot recoverable by the adjacent production wells. We have received a U.S.patent for this technology, with the Canadian patent pending and expected to bereceived in the first half of 2010. This technology requires no additionalsteam, thus it helps reduce the overall steam-oil ratio. In 2009, we drilled18 wedge wells (2008 - four wells). As at December 31,2009, there were 27 wedge wells producing. This process will be piloted atour Christina Lake property in the first quarter of 2010.

 

Wealso focus on reducing our reliance on natural gas for the generation of steamused in SAGD production operations. The Solvent Aided Process (“SAP”) isdiscussed under “Christina Lake” below.

 

Weoperate an 80-megawatt natural gas-fired cogeneration facility in conjunctionwith the SAGD operation at Foster Creek. The steam and power generated by thefacility is presently being used within the SAGD operation and the excess powergenerated is being sold into the Alberta Power Pool.

 

*Christina Lake*

 

Wehave a 50 percent interest in a SAGD EOR project at Christina Lake whichproduces from the McMurray formation. During 2008, the phase B expansionwas completed which increased production capacity to approximately18,000 barrels of bitumen per day.

 

Thephase C expansion, which is expected to add an additional 40,000 barrelsper day of bitumen production capacity, is currently under construction and isexpected to be completed in 2011, increasing total bitumen production capacityto 58,000 barrels per day.

 

Duringthe fourth quarter of 2009, the phase D expansion was sanctioned by FCCL.This expansion is expected to add an additional 40,000 barrels per day ofbitumen production capacity at Christina Lake. We have accelerated thecompletion of phase D by six months and it is expected to be completed inmid-2013. Regulatory approval for this additional phase was received in 2008.

 

Therehave been several innovations to SAGD technology that have been undertaken atChristina Lake over the past several years. One major project that started in2009 is a new SAP pilot. This SAP pilot utilizes a mixture of steam and solventto enhance recovery of the bitumen by reducing the steam-oil ratio andincreasing the overall recovery of the oil in place. Business cases arecurrently being evaluated for the potential use of this technology in theChristina Lake and Narrows Lake development plans.

 

Anotherinnovation was undertaken in 2007, whereby a remote water disposal system wasutilized to successfully manage bottom water pressures and further reduce thesteam-oil ratio.

 

*Narrows Lake*

 

Wehold a 50 percent interest in the Narrows Lake area which is locatedwithin the greater Christina Lake regional area. We are preparing developmentplans and regulatory applications for a project at Narrows Lake that wouldinclude two to three phases with each phase expected to add approximately40,000 barrels per day of bitumen production capacity.

 

*Wood River Refinery*

 

Wehave a 50 percent interest in the Wood River refinery, located in Roxana,Illinois. As at December 31, 2009, the Wood River refinery had aprocessing capacity of approximately 306,000 barrels per day of crude oil.It processes light, low-sulphur and heavy, high-sulphur 

 

 
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crudeoil that it receives from North American crude oil pipelines to producegasoline, diesel and jet fuel, petrochemical feedstocks and asphalt. Thegasoline and diesel are transported via pipelines to markets in the upperMidwest. Other products are transported via pipeline, truck, barge and railcarto markets in the Midwest. In 2007, the refinery completed the construction ofa proprietary sulphur removal unit that produces low-sulphur gasoline. In September 2008,regulatory approval was received to proceed with the CORE project at Wood Riverwhich is expected to increase crude oil refining capacity by approximately50,000 barrels per day, increase coking capacity by approximately65,000 barrels per day, more than double heavy crude oil refining capacityto approximately 240,000 barrels per day and increase the cleantransportation fuels yield by approximately ten percent to approximately89 percent. Capital expenditures for the CORE project are estimated at$3.6 billion ($1.8 billion net to Cenovus) and the project isscheduled to be completed in 2011. At December 31, 2009, the CORE projectwas 71 percent complete, on schedule and on budget.

 

*Borger Refinery*

 

Wehave a 50 percent interest in the Borger refinery, located in Borger,Texas. As at December 31, 2009, the Borger refinery had a processingcapacity of approximately 146,000 barrels per day of crude oil andapproximately 45,000 barrels per day of NGLs. It processes mainly medium,high-sulphur and heavy, high-sulphur crude oil and NGLs that it receives fromNorth American pipeline systems to produce gasoline, diesel and jet fuel alongwith NGLs and solvents. The refined products are transported via pipelines tomarkets in Texas, New Mexico, Colorado and the U.S. Mid-Continent. In July 2007,a new coker with a capacity of approximately 25,000 barrels per day wasbrought into service along with a new vacuum unit and revamped gas, oil anddistillate hydrotreaters. This project has enabled the refinery to processheavy oil blends, particularly Canadian heavy oil, and comply with clean fuelregulations for ultra-low sulphur diesel and low-sulphur gasoline. The projecthas also enabled compliance with required reductions of sulphur dioxide andother air emissions.

 

Thefollowing table summarizes the combined refineries’ key operational results forthe periods indicated.

 
| **Refinery Operations****(1)** | ** ** | **2009** | ** ** | ** ** | **2008** | ** ** | ** ** |
|--------------------------------|------------|----------|------------|------------|----------|------------|------------|
| Crude  Oil Capacity (Mbbls/d)  |       | 452      |       |       | 452      |       |       |
| Crude  Oil Runs (Mbbls/d)      |       | 394      |       |       | 423      |       |       |
| Crude  Utilization (%)         |       | 87       |       |       | 93       |       |       |
| Refined  Products (Mbbls/d)    |       |     |       |       |     |       |       |
| Gasoline                       |       | 223      |       |       | 230      |       |       |
| Distillates                    |       | 120      |       |       | 139      |       |       |
| Other                          |       | 74       |       |       | 79       |       |       |
| Total                          |       | 417      |       |       | 448      |       |       |

**Note:**

(1)  Represents 100 percent of the Wood River andBorger refinery operations.

 

***Other Integrated Oil Division Properties***

 

*Borealis*

 

Wehold a 100 percent working interest in the Borealis area, which is locatedapproximately 90 kilometres northeast of Fort McMurray. Borealis is notincluded in the integrated oil business with ConocoPhillips. Approximately200 delineation wells have been drilled in the greater Borealis area as atDecember 31, 2009. A joint application for development has been submittedto the ERCB and Alberta Environment that would allow for the construction of aSAGD facility with production capacity of approximately 35,000 barrels ofbitumen per day. We continue to evaluate the greater Borealis area in supportof the development application.

 

 
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*Athabasca Gas*

 

Weproduce natural gas from the Cold Lake Air Weapons Range and severalsurrounding landholdings located in northeast Alberta and hold surface accessand natural gas rights for exploration, development and transportation fromareas within the Cold Lake Air Weapons Range that were granted by theGovernments of Canada and Alberta. The majority of our natural gas productionin the area is processed through wholly-owned and operated compressionfacilities.

 

Naturalgas production continues to be impacted by the September 2003, July 2004,September 2004, July 2007 and October 2009 ERCB decisions toshut-in natural gas production from the McMurray, Wabiskaw and Clearwaterformations that may put at risk the recovery of bitumen resources in the area.The decisions resulted in a decrease in annualized natural gas production ofapproximately 25 million cubic feet per day in 2009 (26 million cubicfeet per day in 2008). The Alberta Government’s Department of Energy isproviding financial assistance in the form of a royalty credit, which is equalto approximately 50 percent of the cash flow lost as a result of theshut-in wells.

 

**Canadian Plains Division**

 

TheCanadian Plains Division encompasses crude oil development and productionactivities in Alberta and Saskatchewan, as well as established natural gasdevelopment and production activities in both southern and northern Alberta andsouthern Saskatchewan. Three major properties are located in the CanadianPlains Division: EOR projects at Pelican Lake and Weyburn, as well asconventional oil and natural gas in Southern Alberta. The Division also marketscrude oil and natural gas, including third-party purchases and sales of productthat provide operational flexibility for transportation commitments, producttype, delivery points and customer diversification.

 

Asat December 31, 2009, the Canadian Plains Division had an established landposition of approximately 6.7 million gross acres (6.3 million netacres), of which approximately 4.3 million gross acres (4.1 millionnet acres) are developed. The mineral rights on approximately 50 percentof the total net acreage are owned in fee title by Cenovus, which means thatproduction is subject to a mineral tax that is generally less than the Crownroyalty imposed on production from land where the government owns the mineralrights. In 2009, the Canadian Plains Division had capital investment ofapproximately $478 million and drilled approximately 614 net wells.Of our capital expenditures, 56 percent was oil focused, while43 percent of the capital expenditure was natural gas focused.

 

Plansfor 2010 include further EOR initiatives, continued drilling, welloptimizations, well recompletions (including coalbed methane (“CBM”)) andinvestment in facility infrastructure necessary for continued development.

 

 
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Thefollowing table summarizes the landholdings for the Canadian Plains Division asat December 31, 2009.

 
| ** **                             | ** ** | **   Developed     Acreage** | ** ** | **  Undeveloped   Acreage** | ** ** | ** Total  Acreage** | ** ** | **Average  Working** | ** ** |
|----------------------------------------|------------|--------------------------------------------------|------------|---------------------------------------|------------|-------------------------------|------------|----------------------|------------|
| **Landholdings (thousands of  acres)** | ** ** | **Gross**                                        | ** ** | **Net**                               | ** ** | **Gross**                     | ** ** | **Net**              | ** ** | **Gross** | ** ** | **Net** | ** ** | **Interest** | ** ** |
| Weyburn                                |       | 99                                               |       | 87                                    |       | 383                           |       | 377                  |       | 482 |   | 464 |   | 96% |   |
| Pelican  Lake                          |       | 133                                              |       | 133                                   |       | 279                           |       | 264                  |       | 412 |   | 397 |   | 96% |   |
| Southern  Alberta                      |       |                                             |       |                                  |       |                          |       |                 |       |   |   |   |   |   |   |
| Suffield                               |       | 928                                              |       | 917                                   |       | 63                            |       | 60                   |       | 991 |   | 977 |   | 99% |   |
| Brooks  North                          |       | 569                                              |       | 567                                   |       | 8                             |       | 8                    |       | 577 |   | 575 |   | 100% |   |
| Langevin                               |       | 1,132                                            |       | 1,022                                 |       | 371                           |       | 345                  |       | 1,503 |   | 1,367 |   | 91% |   |
| Drumheller                             |       | 356                                              |       | 345                                   |       | 19                            |       | 16                   |       | 375 |   | 361 |   | 96% |   |
| Total  Southern Alberta                |       | 2,985                                            |       | 2,851                                 |       | 461                           |       | 429                  |       | 3,446 |   | 3,280 |   | 95% |   |
| Other                                  |       | 1,058                                            |       | 986                                   |       | 1,303                         |       | 1,193                |       | 2,361 |   | 2,179 |   | 92% |   |
| Canadian  Plains Total                 |       | 4,275                                            |       | 4,057                                 |       | 2,426                         |       | 2,263                |       | 6,701 |   | 6,320 |   | 94% |   |

 

Thefollowing table sets forth our share of daily average production figures forthe periods indicated.

 
| ** **                      | ** ** | **   Crude Oil** | ** ** | ** **             | ** ** | ** **                  | ** ** |
|---------------------------------|------------|----------------------------|------------|------------------------|------------|-----------------------------|------------|
| ** **                      | ** ** | **   and NGLs**  | ** ** | **  Natural Gas** | ** ** | **  Total Production** | ** ** |
| ** **                      | ** ** | **   (bbls/d)**  | ** ** | **  (MMcf/d)**    | ** ** | **  (BOE/d)**          | ** ** |
| **Production (annual average)** | ** ** | **2009 **             | ** ** | **2008 **         | ** ** | **2009**                    | ** ** | **2008** | ** ** | **2009** | ** ** | **2008** | ** ** |
| Weyburn                         |       | 14,960                     |       | 14,056                 |       | -                           |       | - |   | 14,960 |   | 14,056 |   |
| Pelican  Lake                   |       | 20,105                     |       | 21,975                 |       | -                           |       | 1 |   | 20,105 |   | 22,102 |   |
| Southern  Alberta               |       |                       |       |                   |       |                        |       |   |   |   |   |   |   |
| Suffield                        |       | 12,038                     |       | 13,054                 |       | 213                         |       | 231 |   | 47,567 |   | 51,621 |   |
| Brooks  North                   |       | 1,104                      |       | 839                    |       | 260                         |       | 273 |   | 44,373 |   | 46,339 |   |
| Langevin                        |       | 8,293                      |       | 9,111                  |       | 185                         |       | 203 |   | 39,044 |   | 43,029 |   |
| Drumheller                      |       | 2,122                      |       | 2,276                  |       | 81                          |       | 93 |   | 15,679 |   | 17,776 |   |
| Total  Southern Alberta         |       | 23,557                     |       | 25,280                 |       | 739                         |       | 800 |   | 146,663 |   | 158,765 |   |
| Other                           |       | 5,428                      |       | 6,027                  |       | 36                          |       | 41 |   | 11,489 |   | 12,748 |   |
| Canadian  Plains Total          |       | 64,050                     |       | 67,338                 |       | 775                         |       | 842 |   | 193,217 |   | 207,671 |   |

 

Thefollowing table summarizes the Canadian Plains Division’s interests inproducing wells as at December 31, 2009. These figures exclude wells whichwere capable of producing, but that were not producing, as of December 31,2009.

 
| ** **                             | ** ** | **    Producing**  | ** ** | **    Producing**  | ** ** | **Total**            | ** ** |
|----------------------------------------|------------|-----------------------------------|------------|-----------------------------------|------------|----------------------|------------|
| ** **                             | ** ** | **    Oil  Wells** | ** ** | **    Gas  Wells** | ** ** | **Producing  Wells** | ** ** |
| **Producing Wells (number of  wells)** | ** ** | **Gross **                   | ** ** | **Net **                     | ** ** | **Gross **      | ** ** | **Net ** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Weyburn                                |       | 764                               |       | 482                               |       | -                    |       | - |   | 764 |   | 482 |   |
| Pelican  Lake                          |       | 445                               |       | 445                               |       | 9                    |       | 9 |   | 454 |   | 454 |   |
| Southern  Alberta                      |       |                              |       |                              |       |                 |       |   |   |   |   |   |   |
| Suffield                               |       | 745                               |       | 745                               |       | 10,348               |       | 10,330 |   | 11,093 |   | 11,075 |   |
| Brooks  North                          |       | 57                                |       | 57                                |       | 7,338                |       | 7,230 |   | 7,395 |   | 7,287 |   |
| Langevin                               |       | 251                               |       | 246                               |       | 7,028                |       | 6,388 |   | 7,279 |   | 6,634 |   |
| Drumheller                             |       | 121                               |       | 118                               |       | 1,612                |       | 1,552 |   | 1,733 |   | 1,669 |   |
| Total  Southern Alberta                |       | 1,174                             |       | 1,166                             |       | 26,326               |       | 25,550 |   | 27,500 |   | 26,665 |   |
| Other                                  |       | 665                               |       | 626                               |       | 1,173                |       | 1,154 |   | 1,838 |   | 1,780 |   |
| Canadian  Plains Total                 |       | 3,048                             |       | 2,719                             |       | 27,508               |       | 26,663 |   | 30,556 |   | 29,381 |   |

 

 
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The following describes majorproducing areas or activities in the Canadian Plains Division.

 

***Weyburn***

 

We have a 62 percent workinginterest (50 percent economic interest) in the unitized portion of theWeyburn crude oil field in southeast Saskatchewan. The Weyburn unit produceslight and medium sour crude from the Mississippian Midale formation and covers78 sections of land. Cenovus is the operator and we are increasingultimate recovery in the EOR area of the field with a carbon dioxide (“CO2”) miscibleflood project. As at December 31, 2009, approximately 70 percent ofthe approved and planned CO2 flood pattern development at the Weyburn unitwas complete. Since the inception of the project, approximately 15 milliontonnes of CO2 have been injected as part of the EOR program.We estimate that another 15 million tonnes will be injected as part of theEOR project. The CO2 is delivered by pipeline directly to the Weyburnfacility from a coal gasification project in North Dakota.

 

***Pelican Lake***

 

Pelican Lake produces heavy crudeoil from the Cretaceous Wabiskaw formation in northeast Alberta throughhorizontally drilled waterflood and polymer EOR methods. Facility infrastructureexpansion in this area continued in 2009 to accommodate higher total fluidproduction volumes associated with its waterflood and polymer projects. Thepolymer flood program was expanded by 50 injection wells during 2009.

 

In addition to the heavy crude oilin the Wabiskaw formation, large deposits of bitumen have been identified inthe Cretaceous Grand Rapids and the Devonian Grosmont formations in the PelicanLake area which we continue to evaluate. In 2009, 17 stratigraphic testwells were drilled to acquire technical data on these formations.

 

We hold a 38 percentnon-operated interest in a 110-kilometre, 20-inch diameter crude oil pipelinewhich connects the Pelican Lake area to a major pipeline that transports crudeoil from northern Alberta to crude oil markets.

 

In August 2008, we entered intoan agreement with Pembina Pipeline Corporation (“Pembina”) to transport blendedheavy oil from Utikuma, Alberta to Edmonton, Alberta via Pembina’s100,000 barrels per day capacity pipeline. This pipeline will be used totransport heavy oil from our Pelican Lake property to crude oil markets. Theparties also agreed to transport condensate, used as diluent for transportingheavy oil, from Whitecourt, Alberta to Utikuma, Alberta via a22,000 barrel per day capacity pipeline. The initial term of the agreementis ten years from the in-service date, which is estimated to be in mid-2011.

 

***Southern Alberta***

 

We own all the mineral rights acrossthe majority of our fee title lands in southern Alberta and we lease themajority of the Cretaceous rights in Suffield and parts of southeasternAlberta. Approximately 59 percent of the land we hold in this area is feesimple or freehold and approximately 41 percent is Crown land. OurSouthern Alberta properties are comprised of both oil and gas fields.

 

*Southern Alberta - OilProperties*

 

We hold interests in multiple zones,primarily in the Early Cretaceous, in the Suffield, Langevin, Brooks North andDrumheller areas in southern Alberta with a mix of medium and heavy oil production.Development in this area focuses on infill drilling, optimization of existingwells and EOR schemes. We operate water handling facilities to effectivelymanage primary and enhanced oil production.

 

 
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The following table sets forth netoil wells drilled and daily average oil production figures for the periodsindicated.

 
| ** **                                 | ** ** | **  Net Wells** | ** ** | ** Light/Medium** | ** ** | **Heavy Oil** | ** ** |
|--------------------------------------------|------------|---------------------------|------------|------------------------|------------|---------------|------------|
| **Net Wells Drilled and**                  | ** ** | **  Drilled**   | ** ** | ** (bbls/d)**     | ** ** | **(bbls/d)**  | ** ** |
| **Production (annual average)**            | ** ** | **2009**                  | ** ** | **2008 **         | ** ** | **2009**      | ** ** | **2008 ** | ** ** | **2009  ** | ** ** | **2008  ** | ** ** |
| Suffield                                   |       | 40                        |       | 47                     |       | -             |       | - |   | 12,038 |   | 13,054 |   |
| Brooks North                               |       | 18                        |       | 3                      |       | 894           |       | 642 |   | - |   | - |   |
| Langevin                                   |       | 14                        |       | 16                     |       | 8,053         |       | 8,862 |   | - |   | - |   |
| Drumheller                                 |       | 28                        |       | 1                      |       | 1,421         |       | 1,595 |   | - |   | - |   |
| Southern Alberta - Oil Properties -  Total |       | 100                       |       | 67                     |       | 10,368        |       | 11,099 |   | 12,038 |   | 13,054 |   |

 

*Southern Alberta - NaturalGas Properties*

 

We hold interests in multiple zones,primarily in the Late Cretaceous, in the Suffield, Brooks North, Langevin andDrumheller areas in southern Alberta.

 

Development in this area focuses oninfill drilling up to 16 wells per section, recompletions and optimizationof existing wells.

 

The following table sets forth netgas wells drilled and daily average gas production figures for the periodsindicated.

 
| ** **                                         | ** ** | ** **            | ** ** | **Gas Production** | ** ** |
|----------------------------------------------------|------------|-----------------------|------------|--------------------|------------|
| **Net Wells Drilled and**                          | ** ** | **Net Wells Drilled** | ** ** | **(MMcf/d)**       | ** ** |
| **Production (annual average)**                    | ** ** | **2009**              | ** ** | **2008**           | ** ** | **2009** | ** ** | **2008** | ** ** |
| Suffield                                           |       | 170                   |       | 468                |       | 213 |   | 231 |   |
| Brooks North                                       |       | 163                   |       | 478                |       | 260 |   | 273 |   |
| Langevin                                           |       | 109                   |       | 248                |       | 185 |   | 203 |   |
| Drumheller                                         |       | 56                    |       | 172                |       | 81 |   | 93 |   |
| Southern Alberta - Natural Gas  Properties - Total |       | 498                   |       | 1,366              |       | 739 |   | 800 |   |

 

Included in the Brooks North andLangevin area lands is the Belly River Cretaceous formation where Cenovus isproducing CBM. In 2009, approximately 500 wells were recompleted whichadded approximately 14 million cubic feet per day of natural gasproduction by the end of the year. The CBM assets are long-life and low declineand are expected to generate production for future growth in a capitalefficient manner.

 

Suffield is one of the core areas ofour Southern Alberta major property. The Suffield area is largely made up ofthe Suffield Block, where operations are carried out pursuant to an agreementamong Cenovus, the Government of Canada and the Province of Alberta governingsurface access to CFB Suffield. In 1999, the parties agreed to permit access tothe Suffield military training area to additional operators. Our predecessorcompanies, Alberta Energy Company Ltd. and EnCana Corporation, have operated atCFB Suffield for over 30 years. On October 6, 2008, pursuant to theCanadian *Environmental Assessment Act*, a jointreview panel (“JRP”), made up of provincial and federal regulators, heard ourapplication for a shallow gas infill development in the National Wildlife Area(“NWA”) at CFB Suffield. The hearing was completed in late October 2008.On January 27, 2009, the JRP released its recommendations, concluding thatthe proposed project could proceed provided two key pre-conditions were met:first, critical habitat assessments for certain specific species of plants andanimals must be finalized by Environment Canada within the NWA; and second, therole of the Suffield Environmental Advisory Committee (“SEAC”) must beclarified by the parties to the surface access agreement, and SEAC must beresourced adequately to provide proper environmental oversight of the project.The JRP also concluded that other mitigations and recommendations should befollowed once the two key pre-conditions were met. We are working withnecessary interested parties to proceed with this project.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 15

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***Other Properties***

 

We have started evaluating mediumand light oil prospects in the Bakken and Shaunavon areas in Saskatchewan.

 

We also hold interests in otherconventional oil and natural gas producing properties, primarily located ineast central and northern Alberta.

 

***Crude Oil and Natural GasMarketing***

 

Our Marketing group is focused onenhancing the netback price of our proprietary production. Canadian Plainsdivisional results include third-party purchases and sales of product toprovide operational flexibility for transportation commitments, productquality, delivery points and customer diversification. The Marketing and Powergroup is also focused on ensuring reliable sourcing and lowest delivered costof power at the field level.

 

We also seek to mitigate the marketrisk associated with future cash flows by entering into various risk managementcontracts relating to produced products. Details of those transactions relatedto our various risk management positions for crude oil, natural gas and powerare found in the notes to our consolidated financial statements for the yearended December 31, 2009.

 

*Crude Oil Marketing*

 

We manage the transportation andmarketing of crude oil for our upstream operating divisions. Our objective isto sell production to achieve the best price within the constraints of adiverse sales portfolio, as well as to obtain and manage condensate supply,inventory and storage to meet diluent requirements. During 2009, our blendvolumes on behalf of FCCL were 120,894 barrels per day (2008 -80,866 barrels per day), while our non-partnership blend volumes were78,303 barrels per day (2008 - 86,560 barrels per day).

 

*Natural Gas Marketing*

 

Our natural gas is primarilymarketed to industrials, other producers and energy marketing companies. In2009, approximately 25 percent of our sales of natural gas were directlymarketed by us to industrials. The remaining 75 percent of sales ofnatural gas were marketed to other producers and energy marketing companies.Prices received by us are based primarily upon prevailing index prices fornatural gas. Prices are impacted by competing fuels in such markets and byNorth American regional supply and demand for natural gas.

 

 
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**RESERVES AND OTHER OIL AND GAS INFORMATION**

 

We retain independent qualifiedreserves evaluators (“IQREs”) to evaluate and prepare reports on100 percent of our bitumen, crude oil, NGLs and natural gas reservesannually. These evaluators are McDaniel & Associates Consultants Ltd.and GLJ Petroleum Consultants Ltd. The following reserves information isderived from the reserves reports prepared for us by each of these companies.

 

We have a Reserves Committee (asdefined herein) of independent Board members which reviews the qualificationsand appointment of the IQREs. The Reserves Committee also reviews theprocedures for providing information to the evaluators.

 

Cenovus’s Vice-President, StrategicPlanning and Reserves Governance and two other staff under this individual’sdirection oversee the preparation of the reserves estimates by the IQREs.Currently, this internal staff of two professional engineers have combinedrelevant experience of over 65 years. The Vice-President and otherengineering staff are all members of the appropriate provincial professionalassociations and are members of various industry associations such as theSociety of Petroleum Engineers.

 

The evaluations by the IQREs areconducted from the fundamental petrophysical, geological, engineering,financial and accounting data. Processes and procedures are in place to ensurethat the IQREs are in receipt of all relevant information. Reserves areestimated based on material balance analysis, decline analysis, volumetriccalculations or a combination of these methods, in all cases having regard toeconomic considerations. In the case of producing reserves, the emphasis is ondecline analysis where volumetric analysis is considered to limit forecasts toreasonable levels. Non-producing reserves are estimated by analogy to producingoffsets, with consideration of volumetric estimates of in place quantities.

 

There are numerous uncertaintiesinherent in estimating quantities of crude oil and natural gas reserves. See “RiskFactors - Risks relating to our Business - Our crude oil and natural gasreserves data and future net revenue estimates are uncertain”. Classificationsof reserves as proved or probable are only attempts to define the degree ofuncertainty associated with the estimates. In addition, whereas proved reservesare those reserves that can be estimated with reasonable certainty to beeconomically producible, probable reserves are those additional reserves thatare less certain to be recovered than proved reserves, but which, together withproved reserves, are as likely as not to be recovered. Therefore, probablereserves estimates, by definition, have a higher degree of uncertainty thanproved reserves.

 

**Reserves Quantities Information**

 

Revised reserves disclosurerequirements issued by the SEC at the end of 2008 require separate disclosureof our bitumen reserves from our crude oil and NGLs reserves. The followinginformation in this annual information form reflects this separation for eachof the years presented.

 

The majority of our bitumen reserveswill be recovered and produced using SAGD technology. SAGD involves injectingsteam into horizontal wells drilled into the bitumen formation and recoveringheated bitumen from producing wells located below the injection wells. Thistechnique has a surface footprint comparable to conventional oil production. Wehave no bitumen reserves that require mining techniques to recover the bitumen.

 

 
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***Total Proved ReservesAfter Royalties***

 

In 2009, bitumen reserves increasedby approximately eight percent, largely as a result of Christina Lakephase D receiving approval to proceed. The increase was partially offsetby reductions attributed to higher royalty bitumen rates resulting from ahigher WTI price. In addition, as a result of the new Alberta RoyaltyFramework, where royalties are determined on a sliding scale depending on theprice of bitumen, when prices are between C$55 per barrel and C$120 per barrel,pre-payout royalty rates range from one to nine percent of gross revenue. Oncea project reaches payout, the royalty is based on the greater of one to ninepercent of a project’s gross revenue or 25 to 40 percent of netrevenue. The actual royalty rate that is payable within these ranges isdetermined based on the WTI U.S. dollar price of crude oil, translated intoCanadian dollars. In 2008, bitumen reserves increased by approximately12 percent, largely due to lower royalties resulting from a lower WTIprice. In 2007, bitumen reserves decreased by approximately 26 percent, asa consequence of 50 percent of the Foster Creek and Christina Lakereserves being contributed into the integrated oil business withConocoPhillips. The subsequent approval of Christina Lake phase C andother minor additions and revisions in the year restored 52 percent of thecontributed reserves.

 

In 2009, crude oil and NGLs reservesdecreased by approximately four percent as aggregate additions and revisionswere insufficient to replace production. During 2008, crude oil and NGLsreserves increased by approximately four percent as reserve additions exceededproduction and negative revisions. During 2007, crude oil and NGLs reservesdecreased approximately four percent as reserves additions were more thanoffset by production.

 

In 2009, natural gas reservesdecreased by approximately 21 percent as production and negative revisionsto undeveloped reserves due to low gas prices, exceeded additions and positiverevisions. Natural gas reserves during 2008 decreased by approximately eightpercent, with positive revisions and additions insufficient to offsetproduction. In 2007, natural gas reserves decreased by approximately ninepercent, as positive revisions and additions only replaced approximately46 percent of production.

 

*Impact of SEC Modernizationof Oil and Gas Reporting Requirements*

 

SEC reporting requirements havechanged with respect to prices used to estimate reserves and in the definitionof proved oil and gas reserves. Our IQREs have determined that no changes toreserves have occurred as a result of the definition changes. However, thechanges related to prices did impact our reserves at December 31, 2009.The following is a summary of the impact of using the new pricing rules (average2009 prices) as compared to the old pricing rules (price on December 31,2009): bitumen reserves are higher by 28 million barrels and oil and NGLsreserves are higher by seven million barrels, both as a result of lower royaltyrates, and natural gas reserves are lower by 156 billion cubic feet as aresult of low gas prices.

 

 
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**Net Proved Reserves (Share After Royalties)**(1)(2)

**Constant Pricing**
|                            |       |                      |       |                                             |       |                         |       |   |   |   |
|---------------------------------|------------|---------------------------|------------|--------------------------------------------------|------------|------------------------------|------------|--------|--------|--------|
| ** **                      | ** ** | **Bitumen**               | ** ** | **Crude Oil and  Natural Gas Liquids** | ** ** | **Natural Gas**              | ** ** |
| ** **                      | ** ** | **(millions of barrels)** | ** ** | **(millions of barrels)**                        | ** ** | **(billions of cubic feet)** | ** ** |
| **2007**                        |       |                      |       |                                             |       |                         |       |   |   |   |
| Beginning of year               |       | 800                       |       |                                             | 240        |                         |       | 2,209  |   |   |
| Revisions and improved recovery |       | 63                        |       |                                             | 12         |                         |       | 47     |   |   |
| Extensions and discoveries      |       | 142                       |       |                                             | 5          |                         |       | 116    |   |   |
| Purchase of reserves in place   |       | -                         |       |                                             | -          |                         |       | -      |   |   |
| Sale of reserves in place       |       | (398                      | )          |                                             | -          |                         |       | -      |   |   |
| Production                      |       | (11                       | )          |                                             | (26        | )                            |       | (353   | )      |   |
| End of year                     |       | 596                       |       |                                             | 231        |                         |       | 2,019  |   |   |
| Developed                       |       | 72                        |       |                                             | 184        |                         |       | 1,818  |   |   |
| Undeveloped                     |       | 524                       |       |                                             | 47         |                         |       | 201    |   |   |
| Total                           |       | 596                       |       |                                             | 231        |                         |       | 2,019  |   |   |
| **2008**                        |       |                      |       |                                             |       |                         |       |   |   |   |
| Beginning of year               |       | 596                       |       |                                             | 231        |                         |       | 2,019  |   |   |
| Revisions and improved recovery |       | 84                        |       |                                             | 27         |                         |       | 93     |   |   |
| Extensions and discoveries      |       | -                         |       |                                             | 8          |                         |       | 75     |   |   |
| Purchase of reserves in place   |       | -                         |       |                                             | -          |                         |       | -      |   |   |
| Sale of reserves in place       |       | -                         |       |                                             | -          |                         |       | (1     | )      |   |
| Production                      |       | (12                       | )          |                                             | (25        | )                            |       | (331   | )      |   |
| End of year                     |       | 668                       |       |                                             | 241        |                         |       | 1,855  |   |   |
| Developed                       |       | 126                       |       |                                             | 175        |                         |       | 1,715  |   |   |
| Undeveloped                     |       | 542                       |       |                                             | 66         |                         |       | 140    |   |   |
| Total                           |       | 668                       |       |                                             | 241        |                         |       | 1,855  |   |   |
| **2009**                        |       |                      |       |                                             |       |                         |       |   |   |   |
| Beginning of year               |       | 668                       |       |                                             | 241        |                         |       | 1,855  |   |   |
| Revisions and improved recovery |       | (88                       | )          |                                             | 8          |                         |       | (128   | )      |   |
| Extensions and discoveries      |       | 160                       |       |                                             | 6          |                         |       | 50     |   |   |
| Purchase of reserves in place   |       | -                         |       |                                             | -          |                         |       | -      |   |   |
| Sale of reserves in place       |       | (4                        | )          |                                             | -          |                         |       | (2     | )      |   |
| Production                      |       | (17                       | )          |                                             | (23        | )                            |       | (301   | )      |   |
| End of year                     |       | 719                       |       |                                             | 232        |                         |       | 1,474  |   |   |
| Developed                       |       | 108                       |       |                                             | 170        |                         |       | 1,450  |   |   |
| Undeveloped                     |       | 611                       |       |                                             | 62         |                         |       | 24     |   |   |
| Total                           |       | 719                       |       |                                             | 232        |                         |       | 1,474  |   |   |

**Notes:**

(1)                Definitions:

(a)              “Net”reserves are the remaining reserves attributable to the Cenovus Assets, afterdeduction of estimated royalties and including royalty interests.

(b)              “Proved” oiland gas reserves are those quantities of oil and gas, which, by analysis ofgeoscience and engineering data, can be estimated with reasonable certainty tobe economically producible from a given date forward, from known reservoirs andunder existing economic conditions, operating methods and governmentregulations.

(c)              “ProvedDeveloped” reserves are reserves that can be expected to be recovered throughexisting wells with existing equipment and operating methods.

(d)              “ProvedUndeveloped” reserves are reserves that are expected to be recovered from newwells on undrilled acreage, or from existing wells where a relatively majorexpenditure is required for recompletion.

(2)                Estimates oftotal net proved bitumen, crude oil or natural gas reserves are not filed withany U.S. federal authority or agency other than the SEC.

 

 
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***Supplemental ReservesDisclosure***

*** ***

The volatility of our net bitumen reserves and the net oilreserves at Pelican Lake due to the linkage of royalty rates to the WTI oilreference price has led Cenovus to conclude that it would facilitatecomprehension of our assets to disclose our reserves on a before royalty basis,in addition to the above disclosure on a net, or after royalty, basis. Thiswill provide a clearer understanding of the outcome of our reserves developmentactivities.

 

***Total Proved ReservesBefore Royalties***

*** ***

In 2009, bitumen reserves increased by approximately24 percent, as a result of the approval of Christina Lake phase D. In2008, bitumen reserves were unchanged, as minor revisions offset production inthe year. In 2007, bitumen reserves decreased by approximately 22 percent,as a consequence of 50 percent of the Foster Creek and Christina Lakereserves being contributed into the integrated oil business effectiveJanuary 2, 2007. The subsequent approval of Christina Lake phase Cand other minor additions and revisions in the year restored approximately57 percent of the contributed reserves.

 

In 2009, crude oil and NGLs reserves remained relatively constantas additions and revisions very slightly exceeded production. During 2008,crude oil and NGLs reserves decreased by approximately four percent as reservesadditions and positive revisions were exceeded by production and negativerevisions. During 2007, crude oil and NGLs reserves decreased approximately onepercent as reserves additions nearly offset production.

 

In 2009, natural gas reserves decreased by approximately21 percent as production and negative revisions to undeveloped reservesdue to low gas prices exceeded additions and positive revisions. Natural gasreserves during 2008 decreased by approximately nine percent, with positiverevisions and additions insufficient to offset production. In 2007, natural gasreserves decreased by approximately nine percent, as positive revisions andadditions only replaced approximately 43 percent of production.

 

*Impact of SEC Modernizationof Oil and Gas Reporting Requirements*

* *

SEC reporting requirements have changed with respect toprices used to estimate reserves and in the definition of proved oil and gasreserves. Our IQREs have determined that no changes to reserves have occurredas a result of the definition changes. However, the changes related to pricesdid impact our reserves at December 31, 2009. The following is a summaryof the impact of using the new pricing rules (average 2009 prices) as comparedto the old pricing rules (price on December 31, 2009): bitumen reservesare unchanged, oil and NGLs reserves are slightly down by one million barrelsand natural gas reserves are lower by 164 billion cubic feet as a resultof low gas prices.

 

 

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**Company Share Proved ReservesBefore Royalties**(1)(2)

**Constant Pricing**

 
| ** **                      | ** ** | **Bitumen****(millions of barrels)** | ** ** | **Crude Oil and  Natural Gas Liquids****(millions of barrels)** | ** ** | **Natural Gas****(billions of cubic feet)** |
|---------------------------------|------------|--------------------------------------|------------|-----------------------------------------------------------------|------------|---------------------------------------------|
| **2007**                        |       |                                 |       |                                                            |       |                                        |   |   |   |
| Beginning of year               |       | 901                                  |       |                                                            | 292        |                                        |   | 2,342 |   |
| Revisions and improved recovery |       | 93                                   |       |                                                            | 23         |                                        |   | 37 |   |
| Extensions and discoveries      |       | 165                                  |       |                                                            | 5          |                                        |   | 122 |   |
| Purchase of reserves in place   |       | -                                    |       |                                                            | -          |                                        |   | - |   |
| Sale of reserves in place       |       | (449                                 | )          |                                                            | -          |                                        |   | - |   |
| Production                      |       | (11                                  | )          |                                                            | (31        | )                                           |   | (374 | ) |
| End of year                     |       | 699                                  |       |                                                            | 289        |                                        |   | 2,127 |   |
| Developed                       |       | 82                                   |       |                                                            | 228        |                                        |   | 1,917 |   |
| Undeveloped                     |       | 617                                  |       |                                                            | 61         |                                        |   | 210 |   |
| Total                           |       | 699                                  |       |                                                            | 289        |                                        |   | 2,127 |   |
| **2008**                        |       |                                 |       |                                                            |       |                                        |   |   |   |
| Beginning of year               |       | 699                                  |       |                                                            | 289        |                                        |   | 2,127 |   |
| Revisions and improved recovery |       | 12                                   |       |                                                            | 7          |                                        |   | 76 |   |
| Extensions and discoveries      |       | -                                    |       |                                                            | 8          |                                        |   | 79 |   |
| Purchase of reserves in place   |       | -                                    |       |                                                            | -          |                                        |   | - |   |
| Sale of reserves in place       |       | -                                    |       |                                                            | -          |                                        |   | - |   |
| Production                      |       | (12                                  | )          |                                                            | (28        | )                                           |   | (345 | ) |
| End of year                     |       | 699                                  |       |                                                            | 276        |                                        |   | 1,937 |   |
| Developed                       |       | 135                                  |       |                                                            | 202        |                                        |   | 1,790 |   |
| Undeveloped                     |       | 564                                  |       |                                                            | 74         |                                        |   | 147 |   |
| Total                           |       | 699                                  |       |                                                            | 276        |                                        |   | 1,937 |   |
| **2009**                        |       |                                 |       |                                                            |       |                                        |   |   |   |
| Beginning of year               |       | 699                                  |       |                                                            | 276        |                                        |   | 1,937 |   |
| Revisions and improved recovery |       | 28                                   |       |                                                            | 22         |                                        |   | (151 | ) |
| Extensions and discoveries      |       | 161                                  |       |                                                            | 6          |                                        |   | 51 |   |
| Purchase of reserves in place   |       | -                                    |       |                                                            | -          |                                        |   | - |   |
| Sale of reserves in place       |       | (5                                   | )          |                                                            | -          |                                        |   | (3 | ) |
| Production                      |       | (17                                  | )          |                                                            | (27        | )                                           |   | (305 | ) |
| End of year                     |       | 866                                  |       |                                                            | 277        |                                        |   | 1,529 |   |
| Developed                       |       | 132                                  |       |                                                            | 203        |                                        |   | 1,504 |   |
| Undeveloped                     |       | 734                                  |       |                                                            | 74         |                                        |   | 25 |   |
| Total                           |       | 866                                  |       |                                                            | 277        |                                        |   | 1,529 |   |

**Notes:**

(1)                Definitions:

(a)              “Company Share” reserves are the remaining reservesattributable to the Cenovus Assets, before deduction of estimated royalties,but including royalty interests.

(b)              “Proved” oil and gas reserves are thosequantities of oil and gas, which, by analysis of geoscience and engineeringdata, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs and under existing economicconditions, operating methods, and government regulations.

(c)              “Proved Developed” reserves are reserves that can beexpected to be recovered through existing wells with existing equipment andoperating methods.

(d)              “Proved Undeveloped” reserves are reserves that are expectedto be recovered from new wells on undrilled acreage, or from existing wellswhere a relatively major expenditure is required for recompletion.

(2)                Estimates of total Company Share proved bitumen, crude oilor natural gas reserves are not filed with any U.S. federal authority or agencyother than the SEC.

 

 
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*** ***

***Optional Disclosure ofProbable Reserves***

*** ***

In addition to providing total proved reserves results, bothbefore and after royalties, we are also providing information on our probablereserves. Probable reserves are those additional reserves quantities ofbitumen, crude oil, natural gas and NGLs that are less certain to be recoveredthan proved reserves, but which, together with proved reserves, are as likelyas not to be recovered.

 

Probable reserves were estimated at the same time as theIQREs estimated the proved reserves, and incorporate the same technical andeconomic data in their estimation.

 

***Total Probable ReservesAfter Royalties***

*** ***

At the end of 2009, probable bitumen reserves were403 million barrels, or approximately 35 percent less than theprevious year, due to the reclassification of Christina Lake phase D toproved reserves from probable reserves. In 2008, bitumen reserves were624 million barrels, an increase of approximately 16 percent. In2007, bitumen reserves were 537 million barrels.

 

At the end of 2009, probable crude oil and NGLs reserveswere 127 million barrels, a decrease of approximately seven percent. In2008, crude oil and NGLs reserves were 136 million barrels, an increase ofapproximately 14 percent. In 2007, crude oil and NGLs reserves were119 million barrels.

 

At the end of 2009, probable natural gas reserves were405 billion cubic feet, a decrease of approximately 22 percent.Natural gas reserves in 2008 were 522 billion cubic feet, a decrease ofapproximately eight percent. In 2007, natural gas reserves were569 billion cubic feet.

** **

**Net Probable Reserves (ShareAfter Royalties)**(1)(2)

**Constant Pricing**

 
| ** **  | ** ** | **Bitumen****(millions of barrels)** | ** ** | **Crude Oil and  Natural Gas Liquids****(millions of barrels)** | ** ** | **Natural Gas****(billions of cubic feet)** |
|-------------|------------|--------------------------------------|------------|-----------------------------------------------------------------|------------|---------------------------------------------|
| **2007**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 537                                  |       |                                                            | 119        |                                        |   | 569 |   |
| **2008**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 624                                  |       |                                                            | 136        |                                        |   | 522 |   |
| **2009**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 403                                  |       |                                                            | 127        |                                        |   | 405 |   |
| Developed   |       | 10                                   |       |                                                            | 69         |                                        |   | 362 |   |
| Undeveloped |       | 393                                  |       |                                                            | 58         |                                        |   | 43 |   |
| Total       |       | 403                                  |       |                                                            | 127        |                                        |   | 405 |   |

**Notes:**

(1)                Definitions:

(a)              “Net” reserves are the remaining reserves attributable tothe Cenovus Assets, after deduction of estimated royalties, but includingroyalty interests.

(b)              “Probable” reserves are those additional reserves quantitiesof bitumen, crude oil, natural gas and NGLs that are less certain to berecovered than proved reserves, but which, together with proved reserves, areas likely as not to be recovered.

(c)              “Probable Developed” reserves are reserves that can beexpected to be recovered through existing wells with existing equipment andoperating methods.

(d)              “Probable Undeveloped” reserves are reserves that areexpected to be recovered from new wells on undrilled acreage, or from existingwells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total net probable bitumen, crude oil ornatural gas reserves are not filed with any U.S. federal authority or agencyother than the SEC.

 

 
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***Supplemental ReservesDisclosure***

*** ***

As with proved reserves, the impact of oil price variationson royalty rates on probable reserves from year to year can create an unclearview of the development of our bitumen business. We are providing probable reserveson a before royalty basis below to assist understanding of our business.

 

***Probable Reserves Before Royalties***

*** ***

At the end of 2009, probable bitumen reserves were479 million barrels, or approximately 25 percent less than theprevious year, due to the reclassification of Christina Lake phase D toproved reserves from probable reserves. In 2008, bitumen reserves were637 million barrels, an increase of approximately two percent. In 2007,bitumen reserves were 622 million barrels.

 

At the end of 2009, probable crude oil and NGLs reserveswere 156 million barrels, a decrease of approximately one percent. In2008, crude oil and NGLs reserves were 158 million barrels, an increase ofapproximately five percent. In 2007, crude oil and NGLs reserves were150 million barrels.

 

At the end of 2009, probable natural gas reserves were436 billion cubic feet, a decrease of approximately 23 percent.Natural gas reserves in 2008 were 566 billion cubic feet, a decrease ofapproximately eight percent. In 2007, natural gas reserves were618 billion cubic feet.

 

**Company Share Probable ReservesBefore Royalties**(1)(2)

**Constant Pricing**

 
| ** **  | ** ** | **Bitumen****(millions of barrels)** | ** ** | **Crude Oil and  Natural Gas Liquids****(millions of barrels)** | ** ** | **Natural Gas****(billions of cubic feet)** |
|-------------|------------|--------------------------------------|------------|-----------------------------------------------------------------|------------|---------------------------------------------|
| **2007**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 622                                  |       |                                                            | 150        |                                        |   | 618 |   |
| **2008**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 637                                  |       |                                                            | 158        |                                        |   | 566 |   |
| **2009**    |       |                                 |       |                                                            |       |                                        |   |   |   |
| End of year |       | 479                                  |       |                                                            | 156        |                                        |   | 436 |   |
| Developed   |       | 12                                   |       |                                                            | 84         |                                        |   | 393 |   |
| Undeveloped |       | 467                                  |       |                                                            | 72         |                                        |   | 43 |   |
| Total       |       | 479                                  |       |                                                            | 156        |                                        |   | 436 |   |

**Notes:**

(1)                Definitions:

(a)              “Company Share” reserves are the remaining reservesattributable to the Cenovus Assets, before deduction of estimated royalties,but including royalty interests.

(b)              “Probable” reserves are those additional reserves quantitiesof bitumen, crude oil, natural gas and NGLs that are less certain to berecovered than proved reserves, but which, together with proved reserves, areas likely as not to be recovered.

(c)              “Probable Developed” reserves are reserves that can beexpected to be recovered through existing wells with existing equipment andoperating methods.

(d)              “Probable Undeveloped” reserves are reserves that areexpected to be recovered from new wells on undrilled acreage, or from existingwells where a relatively major expenditure is required for recompletion.

(2)                Estimates of total Company Share probable bitumen, crude oilor natural gas reserves are not filed with any U.S. federal authority or agencyother than the SEC.

 

 
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***Development of ProvedUndeveloped Reserves***

 

*Bitumen*

 

At the end of 2009, we had proved undeveloped bitumenreserves of 611 million barrels after royalties, or approximately85 percent of our total proved bitumen reserves. Our existing reserveswill be recovered using SAGD. Typical SAGD project development involvesinstalling a steam generation facility, at a cost much greater than drilling aproduction/injection well pair, and drilling sufficient SAGD wells to fullyutilize the available steam.

 

Proved bitumen reserves have been determined in compliancewith Canadian Oil and Gas Evaluation Handbook standards. Proved developedbitumen reserves are differentiated from proved undeveloped bitumen reserves bythe presence of drilled production/injection well pairs at the reservesestimation effective date. Because a steam plant has a long life relative towell pairs, in the early stages of a SAGD project, only a small portion ofproved reserves will be developed as the number of well pairs drilled will belimited by the available steam capacity.

 

The forecast production of Cenovus’s proved bitumen reservesextends over 40 years, based on existing facilities. Production of thecurrent proved developed portion is estimated to last ten years.

 

*Oil*

 

We have a significant CO2 EOR project at Weyburn and a significantwaterflood/polymer flood EOR project at Pelican Lake. These projects occur inlarge, well-developed reservoirs, where undeveloped reserves are notnecessarily defined by the absence of drilling, but by improved recoveryassociated with development of the EOR schemes. Extending both EOR schemesrequires intensive capital investment in infrastructure development and willoccur over many years.

 

At Weyburn, investment in proved undeveloped reserves isprojected to continue for well over 30 years, with drilling ofsupplementary wells taking place over the next six years and CO2 flood advancement continuing many years beyondthat. At Pelican Lake, investment in proved undeveloped reserves is projectedto continue for over 20 years, with a combination of infill drilling andpolymer flood advancement.

 

*Material Changes to Proved Undeveloped Reserves*

*** ***

The approval of Christina Lake phase D added approximately160 million barrels of proved undeveloped bitumen reserves in 2009.Natural gas reserves were reduced by approximately 108 billion cubic feetdue to low gas prices.

 

*Development Progress*

*** ***

In 2009, approximately $240 million was spent toconvert 17 million barrels of bitumen, eight million barrels of oil and41 billion cubic feet of natural gas from proved undeveloped to proveddeveloped reserve status.

 

*Aging of Proved Undeveloped Reserves*

*** ***

The only current proved undeveloped reserves that haveremained undeveloped for five years or more are located in the Pelican Lake EORproject. Limited polymer flooding to date has provided positive indications forbroader application throughout the reservoir.

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 |   | 24

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***Commodity Prices forReserves Evaluation***

*** ***

To estimate Cenovus’s reserves, theIQREs used the following 2009 reference prices:

 
| ** **                | ** ** | **2009        **  | ** ** | **2008        **  | ** ** | **% Change    ** |
|---------------------------|------------|-----------------------------------------------------------|------------|-----------------------------------------------------------|------------|--------------------------------------|
| **Crude Oil ($/bbl)**     |       |                                                      |       |                                                      |       |                                 |
| WTI                       |       | 61.18**        ** |       | 44.60**        ** |       | 37**    **       |
| WCS (C$)                  |       | 58.65**        ** |       | 41.98**        ** |       | 40**    **       |
| **Natural Gas ($/MMbtu)** |       |                                                      |       |                                                      |       |                                 |
| Henry Hub                 |       | 3.87**        **  |       | 5.71**        **  |       | (32)**   **           |
| AECO (C$)                 |       | 3.77**        **  |       | 6.22**        **  |       | (39)**   **           |

 

The 2009 prices reflect the new SEC requirements that pricesbe determined by using the average of the first day of the month price for eachof the 12 months preceding the effective date of the evaluation. The 2008reference prices were based on prices at December 31, 2008.

 

**Other Disclosures About Oil and Gas Activities**

** **

The tables in this section set forth oil and gas informationprepared by us in accordance with the U.S. Financial Accounting StandardsBoard’s ASC 932-10, “Extractive Activities - Oil and Gas”.

 

***Standardized Measure ofDiscounted Future Net Cash Flows and Changes Therein***

*** ***

In calculating the standardized measure of discounted futurenet cash flows for 2009, 12-month average price and cost assumptions wereapplied to our annual future production from proved reserves to determine cashinflows. For the 2008 and 2007 calculations of standardized measure ofdiscounted future net cash flows, the prices were based on the year-end pricefor each of the respective years. Future production and development costs arebased on average price assumptions and assume the continuation of existingeconomic, operating and regulatory conditions. Future income taxes arecalculated by applying statutory income tax rates to future pre-tax cash flowsafter provision for the tax cost of the oil and natural gas properties basedupon existing laws and regulations. The discount was computed by application ofa ten percent discount factor to the future net cash flows. The calculation ofthe standardized measure of discounted future net cash flows is based upon thediscounted future net cash flows prepared by the IQREs in relation to thereserves they respectively evaluated, and adjusted to the extent provided bycontractual arrangements such as price risk management activities, in existenceat year-end and to account for asset retirement obligations and future incometaxes.

 

We caution that the discounted future net cash flowsrelating to proved oil and gas reserves are an indication of neither the fairmarket value of our oil and gas properties, nor the future net cash flowsexpected to be generated from such properties. The discounted future net cashflows do not include the fair market value of exploratory properties andprobable or possible oil and gas reserves, nor is consideration given to theeffect of anticipated future changes in crude oil and natural gas prices,development, asset retirement and production costs and possible changes to taxand royalty regulations. The prescribed discount rate of ten percent may notappropriately reflect future interest rates. The computation also excludesvalues attributable to the marketing of our proprietary production and third-partypurchases and sales of product.

 

 
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Table of Contents

 

**Standardized Measure ofDiscounted Future Net Cash Flows**

**Relating to Proved Oil and GasReserves**

 
| ** **                                                               | ** ** | **2009 **    | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------------------------------------------|------------|-------------------|------------|----------|------------|----------|------------|
|                                                                     |       | ($ millions) |       |     |
| Future cash inflows                                                      |       | 48,006            |       | 31,626   |       | 57,706   |       |
| Less future:                                                             |       |              |       |     |       |     |       |
| Production costs                                                         |       | 16,757            |       | 15,001   |       | 17,345   |       |
| Development costs                                                        |       | 5,313             |       | 4,334    |       | 4,635    |       |
| Asset retirement obligation payments                                     |       | 2,954             |       | 1,669    |       | 1,769    |       |
| Income taxes                                                             |       | 5,553             |       | 2,142    |       | 7,641    |       |
| Future net cash flows                                                    |       | 17,429            |       | 8,480    |       | 26,316   |       |
| Less 10 percent annual discount for estimated timing  of cash flows |       | 9,816             |       | 3,366    |       | 13,472   |       |
| Discounted future net cash flows                                         |       | 7,613             | (1)        | 5,114    |       | 12,844   |       |
|                                                                          |            |                   |            |          |            |          |            |  |

**Note:**

(1)     2009discounted future net cash flows have been calculated using 12-month averageprices of: crude oil - WTI of $61.18/bbl and WCS of C$58.65/bbl; naturalgas - Henry Hub of $3.87/MMbtu and AECO of C$3.77/MMbtu. Future net cashflows would have been $12,524 million using the following single dayDecember 31, 2009 prices: WTI of $79.36/bbl and WCS of C$75.21/bbl;natural gas - Henry Hub of $5.78/MMbtu and AECO of C$5.63/MMbtu. In 2008and 2007, future net cash flows were calculated using the December 31period end price for the respective years.

 

**Changes in Standardized Measureof Discounted Future Net Cash Flows**

**Relating to Proved Oil and GasReserves**

 
| ** **                                                                                   | ** ** | **2009**   | ** ** | **2008**          | ** ** | **2007**   | ** ** |
|----------------------------------------------------------------------------------------------|------------|------------|------------|-------------------|------------|------------|------------|
|                                                                                         | ** ** | ** ** |       | ($ millions) | ** ** | ** ** |
| Balance, beginning of year                                                                   |       | 5,114      |       | 12,844            |       | 8,963      |       |
| Changes resulting from:                                                                      |       |       |       |              |       |       |       |
| Sales of oil and gas produced during the period                                              |       | (3,330     | )          | (3,896            | )          | (3,151     | )          |
| Discoveries and extensions, net of related costs                                             |       | 817        |       | 165               |       | 1,330      |       |
| Purchases of proved reserves in place                                                        |       | –     |       | –            |       | 3          |       |
| Sales of proved reserves in place                                                            |       | (11        | )          | (2                | )          | (1,244     | )          |
| Net change in prices and production costs                                                    |       | 5,561      |       | (10,401           | )          | 6,206      |       |
| Revisions to quantity estimates                                                              |       | (270       | )          | 1,589             |       | 524        |       |
| Accretion of discount                                                                        |       | 632        |       | 1,647             |       | 1,127      |       |
| Previously  estimated development costs incurred net of changes in future development  costs |       | (92        | )          | 670               |       | 468        |       |
| Other                                                                                        |       | 180        |       | 89                |       | (73        | )          |
| Net change in income taxes                                                                   |       | (988       | )          | 2,409             |       | (1,309     | )          |
| Balance, end of year                                                                         |       | 7,613      |       | 5,114             |       | 12,844     |       |
|                                                                                              |            |            |            |                   |            |            |            |  |

 

 
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Table of Contents

 

***Results of Operations,Capitalized Costs and Costs Incurred***

*** ***

**Results of Operations**(1)

** **
| ** **                                                                                    | ** ** | **2009**          | ** ** | **2008**   | ** ** | **2007** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|-------------------|------------|------------|------------|----------|------------|
|                                                                                          | ** ** | ($ millions) | ** ** | ** ** |
| Oil and gas revenues, net of royalties, transportation and  selling costs                     |       | 4,058             |       | 4,732      |       | 3,883    |       |
| Less:                                                                                         |       |              |       |       |       |     |       |
| Operating costs, production and mineral taxes, and accretion  of asset retirement obligations |       | 728               |       | 836        |       | 732      |       |
| Depreciation, depletion and amortization                                                      |       | 1,090             |       | 1,103      |       | 1,217    |       |
| Operating income                                                                              |       | 2,240             |       | 2,793      |       | 1,934    |       |
| Income taxes                                                                                  |       | 634               |       | 815        |       | 574      |       |
| Results of operations                                                                         |       | 1,606             |       | 1,978      |       | 1,360    |       |
|                                                                                               |            |                   |            |            |            |          |            |  |

**Note:**

(1)  All of our proved oil and gas reserves arelocated within Canada.

 

**Capitalized Costs**

 
| ** **                                           | ** ** | **2009 **    | ** ** | **2008 ** | ** ** | **2007 ** | ** ** |
|------------------------------------------------------|------------|-------------------|------------|----------------|------------|----------------|------------|
|                                                 |       | ($ millions) |       |           |
| Proved oil and gas properties                        |       | 19,975            |       | 16,423         |       | 19,105         |       |
| Unproved oil and gas properties                      |       | 615               |       | 177            |       | 160            |       |
| Total capital cost                                   |       | 20,590            |       | 16,600         |       | 19,265         |       |
| Accumulated depreciation, depletion and amortization |       | 10,945            |       | 8,476          |       | 9,707          |       |
| Net capitalized costs                                |       | 9,645             |       | 8,124          |       | 9,558          |       |
|                                                      |            |                   |            |                |            |                |            |  |

 

**Costs Incurred**

 
| ** **           | ** ** | **2009**          | ** ** | **2008** | ** ** | **2007** | ** ** |
|----------------------|------------|-------------------|------------|----------|------------|----------|------------|
|                 |       | ($ millions) |       |     |
| Acquisitions         |       |              |       |     |       |     |       |
| – Unproved      |       | 3                 |       | –   |       | –   |       |
| – Proved        |       | –            |       | –   |       | 14       |       |
| Total acquisitions   |       | 3                 |       | –   |       | 14       |       |
| Exploration costs    |       | 60                |       | 195      |       | 101      |       |
| Development costs    |       | 894               |       | 1,305    |       | 1,140    |       |
| Total costs incurred |       | 957               |       | 1,500    |       | 1,255    |       |
|                      |            |                   |            |          |            |          |            |  |

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 |   | 27 |
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Table ofContents

 

**Production Volumes and Per-Unit Results**

 

***ProductionVolumes***

 

The following tables summarize ournet daily production volumes, after royalties, on a quarterly basis for theperiods indicated.

 
| ** **                                          | ** ** | **Production Volumes - 2009** | ** ** |
|-----------------------------------------------------|------------|-------------------------------|------------|
| ** **                                          | ** ** | **Year  **          | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| **PRODUCTION VOLUMES**                              |       |                          |       |   |   |   |   |   |   |   |   |
| **Oil and Natural Gas Liquids (bbls/d)**            |       |                          |       |   |   |   |   |   |   |   |   |
| Heavy Oil                                           |       |                          |       |   |   |   |   |   |   |   |   |
| Foster Creek                                        |       | 36,654                        |       | 45,035 |   | 38,954 |   | 34,249 |   | 28,170 |   |
| Christina Lake                                      |       | 6,527                         |       | 7,022 |   | 6,097 |   | 6,428 |   | 6,559 |   |
| Integrated Oil – Other(1)                      |       | 2,553                         |       | 1,921 |   | 4,401 |   | 1,800 |   | 2,069 |   |
| Canadian Plains                                     |       | 32,143                        |       | 30,338 |   | 31,684 |   | 31,508 |   | 35,097 |   |
| Light and Medium Oil – Canadian  Plains        |       | 30,721                        |       | 29,110 |   | 30,676 |   | 31,183 |   | 31,946 |   |
| Natural Gas Liquids(2) – Canadian  Plains |       | 1,186                         |       | 1,164 |   | 1,216 |   | 1,162 |   | 1,201 |   |
| **Total Oil and Natural Gas Liquids**               |       | 109,784                       |       | 114,590 |   | 113,028 |   | 106,330 |   | 105,042 |   |
| **Natural Gas (MMcf/d)**                            |       |                          |       |   |   |   |   |   |   |   |   |
| Integrated Oil – Other                         |       | 49                            |       | 31 |   | 51 |   | 72 |   | 42 |   |
| Canadian Plains                                     |       | 775                           |       | 734 |   | 775 |   | 792 |   | 800 |   |
| **Total Natural Gas**                               |       | 824                           |       | 765 |   | 826 |   | 864 |   | 842 |   |
| **Total (BOE/d)**                                   |       | 247,117                       |       | 242,090 |   | 250,695 |   | 250,330 |   | 245,375 |   |

**Notes:**

(1)  Senlacproperty sold November 2009.

(2)  Naturalgas liquids include condensate volumes.

 
| ** **                                          | ** ** | **Production Volumes - 2008** | ** ** |
|-----------------------------------------------------|------------|-------------------------------|------------|
| ** **                                          | ** ** | **Year  **          | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| **PRODUCTION VOLUMES**                              |       |                          |       |   |   |   |   |   |   |   |   |
| **Oil and Natural Gas Liquids (bbls/d)**            |       |                          |       |   |   |   |   |   |   |   |   |
| Heavy Oil                                           |       |                          |       |   |   |   |   |   |   |   |   |
| Foster Creek                                        |       | 25,947                        |       | 28,955 |   | 26,979 |   | 21,038 |   | 26,770 |   |
| Christina Lake                                      |       | 4,236                         |       | 6,113 |   | 4,568 |   | 3,633 |   | 2,606 |   |
| Integrated Oil – Other                         |       | 2,729                         |       | 2,133 |   | 2,273 |   | 3,009 |   | 3,514 |   |
| Canadian Plains                                     |       | 35,029                        |       | 32,843 |   | 34,655 |   | 34,618 |   | 38,029 |   |
| Light and Medium Oil – Canadian  Plains        |       | 31,128                        |       | 32,147 |   | 30,134 |   | 30,479 |   | 31,752 |   |
| Natural Gas Liquids(1) – Canadian  Plains |       | 1,181                         |       | 1,126 |   | 1,147 |   | 1,189 |   | 1,262 |   |
| **Total Oil and Natural Gas Liquids**               |       | 100,250                       |       | 103,317 |   | 99,756 |   | 93,966 |   | 103,933 |   |
| **Natural Gas (MMcf/d)**                            |       |                          |       |   |   |   |   |   |   |   |   |
| Integrated Oil – Other                         |       | 63                            |       | 59 |   | 61 |   | 67 |   | 65 |   |
| Canadian Plains                                     |       | 842                           |       | 820 |   | 831 |   | 856 |   | 860 |   |
| **Total Natural Gas**                               |       | 905                           |       | 879 |   | 892 |   | 923 |   | 925 |   |
| **Total (BOE/d)**                                   |       | 251,083                       |       | 249,817 |   | 248,423 |   | 247,799 |   | 258,100 |   |

**Note:**

(1)  Naturalgas liquids include condensate volumes.

 
| ** **                                          | ** ** | **Production Volumes - 2007** | ** ** |
|-----------------------------------------------------|------------|-------------------------------|------------|
| ** **                                          | ** ** | **Year  **          | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| **PRODUCTION VOLUMES**                              |       |                          |       |   |   |   |   |   |   |   |   |
| **Oil and Natural Gas Liquids (bbls/d)**            |       |                          |       |   |   |   |   |   |   |   |   |
| Heavy Oil                                           |       |                          |       |   |   |   |   |   |   |   |   |
| Foster Creek                                        |       | 24,262                        |       | 24,869 |   | 26,243 |   | 25,132 |   | 20,739 |   |
| Christina Lake                                      |       | 2,552                         |       | 2,321 |   | 2,497 |   | 2,862 |   | 2,530 |   |
| Integrated Oil – Other                         |       | 2,688                         |       | 3,040 |   | 2,235 |   | 2,489 |   | 2,990 |   |
| Canadian Plains                                     |       | 38,784                        |       | 38,581 |   | 38,647 |   | 38,408 |   | 39,510 |   |
| Light and Medium Oil – Canadian  Plains        |       | 32,156                        |       | 31,706 |   | 32,064 |   | 31,740 |   | 33,129 |   |
| Natural Gas Liquids(1) – Canadian  Plains |       | 1,260                         |       | 1,422 |   | 1,209 |   | 1,206 |   | 1,203 |   |
| **Total Oil and Natural Gas Liquids**               |       | 101,702                       |       | 101,939 |   | 102,895 |   | 101,837 |   | 100,101 |   |
| **Natural Gas (MMcf/d)**                            |       |                          |       |   |   |   |   |   |   |   |   |
| Integrated Oil – Other                         |       | 91                            |       | 69 |   | 105 |   | 98 |   | 91 |   |
| Canadian Plains                                     |       | 875                           |       | 876 |   | 858 |   | 874 |   | 891 |   |
| **Total Natural Gas**                               |       | 966                           |       | 945 |   | 963 |   | 972 |   | 982 |   |
| **Total (BOE/d)**                                   |       | 262,702                       |       | 259,439 |   | 263,395 |   | 263,837 |   | 263,768 |   |

**Note:**

(1)  Naturalgas liquids include condensate volumes.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 28

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***Per-UnitResults***

 

The following tables summarize ournet per-unit results on a quarterly basis, after royalties, for the periodsindicated. The results exclude the impact of realized financial hedging.

 
| ** **                                                        | ** ** | **Per-Unit Results–2009** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                        | ** ** | **Year **                 | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| Crude Oil – Heavy – Foster Creek  ($/bbl)               |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 50.07                          |       | 60.41 |   | 56.76 |   | 46.98 |   | 27.08 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 2.27                           |       | 1.69 |   | 2.33 |   | 3.02 |   | 2.19 |   |
| Operating                                                         |       | 10.75                          |       | 10.28 |   | 10.19 |   | 10.25 |   | 12.96 |   |
| Netback                                                           |       | 37.05                          |       | 48.44 |   | 44.24 |   | 33.71 |   | 11.93 |   |
| Crude Oil – Heavy – Christina Lake  ($/bbl)             |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 47.66                          |       | 54.06 |   | 59.28 |   | 49.25 |   | 26.08 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 2.78                           |       | 0.95 |   | 5.06 |   | 2.46 |   | 2.74 |   |
| Operating                                                         |       | 14.76                          |       | 17.75 |   | 14.41 |   | 11.92 |   | 14.78 |   |
| Netback                                                           |       | 30.12                          |       | 35.36 |   | 39.81 |   | 34.87 |   | 8.56 |   |
| Crude Oil – Heavy – Canadian Plains  ($/bbl)            |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 48.49                          |       | 57.48 |   | 57.30 |   | 48.22 |   | 31.34 |   |
| Production and mineral taxes                                      |       | (0.01                          | )          | 0.02 |   | (0.01 | ) | 0.02 |   | (0.07 | ) |
| Transportation and selling                                        |       | 1.12                           |       | 0.81 |   | 1.10 |   | 1.37 |   | 1.17 |   |
| Operating                                                         |       | 9.80                           |       | 13.24 |   | 8.74 |   | 9.61 |   | 7.82 |   |
| Netback                                                           |       | 37.58                          |       | 43.41 |   | 47.47 |   | 37.22 |   | 22.42 |   |
| Crude Oil – Heavy – Total ($/bbl)                       |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 49.24                          |       | 58.81 |   | 57.14 |   | 47.90 |   | 29.08 |   |
| Production and mineral taxes                                      |       | 0.03                           |       | 0.03 |   | 0.05 |   | 0.05 |   | (0.03 | ) |
| Transportation and selling                                        |       | 1.84                           |       | 1.32 |   | 2.07 |   | 2.26 |   | 1.74 |   |
| Operating                                                         |       | 10.72                          |       | 11.94 |   | 9.76 |   | 10.42 |   | 10.71 |   |
| Netback                                                           |       | 36.65                          |       | 45.52 |   | 45.26 |   | 35.17 |   | 16.66 |   |
| Crude Oil – Light and Medium –  Canadian Plains ($/bbl) |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 55.29                          |       | 67.84 |   | 61.76 |   | 55.00 |   | 37.51 |   |
| Production and mineral taxes                                      |       | 2.14                           |       | 1.74 |   | 2.26 |   | 1.86 |   | 2.69 |   |
| Transportation and selling                                        |       | 0.87                           |       | 0.71 |   | 0.76 |   | 1.02 |   | 0.96 |   |
| Operating                                                         |       | 10.04                          |       | 11.16 |   | 10.22 |   | 9.35 |   | 9.50 |   |
| Netback                                                           |       | 42.24                          |       | 54.23 |   | 48.52 |   | 42.77 |   | 24.36 |   |
| Crude Oil – Total ($/bbl)                                    |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 50.96                          |       | 61.13 |   | 58.39 |   | 50.00 |   | 31.75 |   |
| Production and mineral taxes                                      |       | 0.63                           |       | 0.47 |   | 0.65 |   | 0.59 |   | 0.83 |   |
| Transportation and selling                                        |       | 1.56                           |       | 1.17 |   | 1.72 |   | 1.89 |   | 1.50 |   |
| Operating                                                         |       | 10.53                          |       | 11.74 |   | 9.89 |   | 10.10 |   | 10.33 |   |
| Netback                                                           |       | 38.24                          |       | 47.75 |   | 46.13 |   | 37.42 |   | 19.09 |   |
| Natural Gas Liquids - Canadian  Plains ($/bbl)                    |       |                           |       |   |   |   |   |   |   |   |   |
| Netback                                                           |       | 43.51                          |       | 55.89 |   | 44.88 |   | 38.36 |   | 34.86 |   |
| Total Liquids ($/bbl)                                             |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 50.87                          |       | 61.08 |   | 58.25 |   | 49.88 |   | 31.78 |   |
| Production and mineral taxes                                      |       | 0.62                           |       | 0.47 |   | 0.64 |   | 0.58 |   | 0.82 |   |
| Transportation and selling                                        |       | 1.55                           |       | 1.15 |   | 1.70 |   | 1.87 |   | 1.48 |   |
| Operating                                                         |       | 10.41                          |       | 11.62 |   | 9.78 |   | 9.99 |   | 10.21 |   |
| Netback                                                           |       | 38.29                          |       | 47.84 |   | 46.13 |   | 37.44 |   | 19.27 |   |
| Natural Gas – Total ($/Mcf)                                  |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 3.60                           |       | 3.95 |   | 2.86 |   | 3.22 |   | 4.41 |   |
| Production and mineral taxes                                      |       | 0.04                           |       | 0.03 |   | 0.04 |   | 0.06 |   | 0.04 |   |
| Transportation and selling                                        |       | 0.14                           |       | 0.12 |   | 0.14 |   | 0.13 |   | 0.15 |   |
| Operating                                                         |       | 0.76                           |       | 0.80 |   | 0.77 |   | 0.70 |   | 0.78 |   |
| Netback                                                           |       | 2.66                           |       | 3.00 |   | 1.91 |   | 2.33 |   | 3.44 |   |
| Total ($/BOE)                                                     |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 34.58                          |       | 41.36 |   | 35.80 |   | 32.36 |   | 28.69 |   |
| Production and mineral taxes                                      |       | 0.42                           |       | 0.31 |   | 0.42 |   | 0.46 |   | 0.49 |   |
| Transportation and selling                                        |       | 1.14                           |       | 0.93 |   | 1.24 |   | 1.25 |   | 1.14 |   |
| Operating(1)                                                      |       | 7.17                           |       | 8.02 |   | 6.97 |   | 6.69 |   | 7.00 |   |
| Netback                                                           |       | 25.85                          |       | 32.10 |   | 27.17 |   | 23.96 |   | 20.06 |   |

**Note:**

(1)  Operatingcosts for the year include costs related to long-term incentives of $0.09/BOE.

 

 
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Table ofContents

 
| ** **                                                        | ** ** | **Per-Unit Results–2008** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                        | ** ** | **Year **                 | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| Crude Oil – Heavy – Foster Creek  ($/bbl)               |       |                           |       |   |   |   |   |   |   |   |   |
| Price(1)                                                          |       | 62.88                          |       | 17.97 |   | 92.07 |   | 95.64 |   | 59.95 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 2.21                           |       | 1.90 |   | 1.98 |   | 2.63 |   | 2.46 |   |
| Operating                                                         |       | 14.38                          |       | 10.08 |   | 14.42 |   | 19.90 |   | 14.90 |   |
| Netback                                                           |       | 46.29                          |       | 5.99 |   | 75.67 |   | 73.11 |   | 42.59 |   |
| Crude Oil – Heavy – Christina Lake  ($/bbl)             |       |                           |       |   |   |   |   |   |   |   |   |
| Price(2)                                                          |       | 59.63                          |       | 29.61 |   | 86.06 |   | 81.02 |   | 56.94 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 3.34                           |       | 2.78 |   | 2.81 |   | 3.62 |   | 5.25 |   |
| Operating                                                         |       | 22.79                          |       | 14.07 |   | 22.24 |   | 30.92 |   | 33.66 |   |
| Netback                                                           |       | 33.50                          |       | 12.76 |   | 61.01 |   | 46.48 |   | 18.03 |   |
| Crude Oil – Heavy – Canadian Plains  ($/bbl)            |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 74.08                          |       | 31.30 |   | 95.86 |   | 98.65 |   | 70.44 |   |
| Production and mineral taxes                                      |       | 0.03                           |       | 0.06 |   | 0.07 |   | (0.10 | ) | 0.07 |   |
| Transportation and selling                                        |       | 1.60                           |       | 1.13 |   | 2.42 |   | 1.60 |   | 1.29 |   |
| Operating                                                         |       | 9.04                           |       | 7.17 |   | 7.62 |   | 11.30 |   | 9.93 |   |
| Netback                                                           |       | 63.41                          |       | 22.94 |   | 85.75 |   | 85.85 |   | 59.15 |   |
| Crude Oil – Heavy – Total ($/bbl)                       |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 68.98                          |       | 25.39 |   | 94.05 |   | 96.35 |   | 66.12 |   |
| Production and mineral taxes                                      |       | 0.07                           |       | 0.05 |   | 0.10 |   | 0.02 |   | 0.12 |   |
| Transportation and selling                                        |       | 1.97                           |       | 1.62 |   | 2.29 |   | 2.10 |   | 1.91 |   |
| Operating                                                         |       | 12.26                          |       | 9.13 |   | 11.62 |   | 15.92 |   | 12.89 |   |
| Netback                                                           |       | 54.68                          |       | 14.59 |   | 80.04 |   | 78.31 |   | 51.20 |   |
| Crude Oil – Light and Medium –  Canadian Plains ($/bbl) |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 84.84                          |       | 41.60 |   | 107.59 |   | 107.08 |   | 85.90 |   |
| Production and mineral taxes                                      |       | 3.33                           |       | 2.05 |   | 4.70 |   | 3.97 |   | 2.72 |   |
| Transportation and selling                                        |       | 1.20                           |       | 0.96 |   | 1.41 |   | 1.27 |   | 1.16 |   |
| Operating                                                         |       | 10.56                          |       | 8.28 |   | 9.40 |   | 13.05 |   | 11.60 |   |
| Netback                                                           |       | 69.75                          |       | 30.31 |   | 92.08 |   | 88.79 |   | 70.42 |   |
| Crude Oil – Total ($/bbl)                                    |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 73.95                          |       | 30.31 |   | 98.26 |   | 99.82 |   | 72.36 |   |
| Production and mineral taxes                                      |       | 1.09                           |       | 0.66 |   | 1.53 |   | 1.29 |   | 0.94 |   |
| Transportation and selling                                        |       | 1.73                           |       | 1.42 |   | 2.02 |   | 1.83 |   | 1.68 |   |
| Operating                                                         |       | 11.73                          |       | 8.87 |   | 10.93 |   | 14.99 |   | 12.48 |   |
| Netback                                                           |       | 59.40                          |       | 19.36 |   | 83.78 |   | 81.71 |   | 57.26 |   |
| Natural Gas Liquids - Canadian  Plains ($/bbl)                    |       |                           |       |   |   |   |   |   |   |   |   |
| Netback                                                           |       | 78.91                          |       | 45.13 |   | 98.34 |   | 96.34 |   | 75.09 |   |
| Total Liquids ($/bbl)                                             |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 74.00                          |       | 30.47 |   | 98.26 |   | 99.77 |   | 72.39 |   |
| Production and mineral taxes                                      |       | 1.08                           |       | 0.65 |   | 1.51 |   | 1.28 |   | 0.93 |   |
| Transportation and selling                                        |       | 1.71                           |       | 1.40 |   | 2.00 |   | 1.81 |   | 1.66 |   |
| Operating                                                         |       | 11.59                          |       | 8.78 |   | 10.80 |   | 14.81 |   | 12.33 |   |
| Netback                                                           |       | 59.62                          |       | 19.64 |   | 83.95 |   | 81.87 |   | 57.47 |   |
| Natural Gas – Total ($/Mcf)                                  |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 7.76                           |       | 5.63 |   | 8.66 |   | 9.50 |   | 7.19 |   |
| Production and mineral taxes                                      |       | 0.11                           |       | 0.06 |   | 0.16 |   | 0.16 |   | 0.06 |   |
| Transportation and selling                                        |       | 0.24                           |       | 0.21 |   | 0.25 |   | 0.24 |   | 0.25 |   |
| Operating                                                         |       | 0.84                           |       | 0.72 |   | 0.62 |   | 1.00 |   | 1.03 |   |
| Netback                                                           |       | 6.57                           |       | 4.64 |   | 7.63 |   | 8.10 |   | 5.85 |   |
| Total ($/BOE)                                                     |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 57.55                          |       | 32.39 |   | 70.37 |   | 73.39 |   | 54.82 |   |
| Production and mineral taxes                                      |       | 0.83                           |       | 0.47 |   | 1.19 |   | 1.07 |   | 0.58 |   |
| Transportation and selling                                        |       | 1.54                           |       | 1.34 |   | 1.69 |   | 1.57 |   | 1.57 |   |
| Operating(3)                                                      |       | 7.68                           |       | 6.19 |   | 6.54 |   | 9.38 |   | 8.62 |   |
| Netback                                                           |       | 47.50                          |       | 24.39 |   | 60.95 |   | 61.37 |   | 44.05 |   |

**Notes:**

(1)                  The FosterCreek price for 2008 includes the impact of the write-down of condensateinventories to net realizable value (2008 - $4.68/bbl; Q4 2008 -$12.53/bbl; Q3 2008 - $3.59/bbl).

(2)                  The ChristinaLake price for 2008 includes the impact of the write-down of condensateinventories to net realizable value (2008 - $0.25/bbl; Q4 2008 -$0.84/bbl).

(3)                  Operatingcosts for the year include a recovery of costs related to long-term incentivesof $0.06/BOE.

 

 
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|-----------------------------------------------------------------------------------|------------|

 

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Table ofContents

 
| ** **                                                        | ** ** | **Per-Unit Results–2007** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------|------------|
| ** **                                                        | ** ** | **Year **                 | ** ** | **Q4   ** | ** ** | **Q3   ** | ** ** | **Q2   ** | ** ** | **Q1   ** | ** ** |
| Crude Oil – Heavy – Foster Creek  ($/bbl)               |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 40.48                          |       | 45.76 |   | 43.87 |   | 39.44 |   | 33.33 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 2.74                           |       | 2.55 |   | 2.24 |   | 3.11 |   | 3.03 |   |
| Operating(1)                                                      |       | 13.44                          |       | 12.75 |   | 10.98 |   | 13.37 |   | 16.49 |   |
| Netback                                                           |       | 24.30                          |       | 30.46 |   | 30.65 |   | 22.96 |   | 13.81 |   |
| Crude Oil – Heavy – Christina Lake  ($/bbl)             |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 36.72                          |       | 42.64 |   | 34.50 |   | 39.08 |   | 32.69 |   |
| Production and mineral taxes                                      |       | –                         |       | – |   | – |   | – |   | – |   |
| Transportation and selling                                        |       | 4.31                           |       | 5.21 |   | 0.90 |   | 8.75 |   | 3.36 |   |
| Operating(1)                                                      |       | 24.57                          |       | 29.98 |   | 25.50 |   | 20.65 |   | 23.19 |   |
| Netback                                                           |       | 7.84                           |       | 7.45 |   | 8.10 |   | 9.68 |   | 6.14 |   |
| Crude Oil – Heavy – Canadian Plains  ($/bbl)            |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 43.91                          |       | 49.52 |   | 48.22 |   | 40.70 |   | 37.22 |   |
| Production and mineral taxes                                      |       | 0.05                           |       | 0.07 |   | 0.06 |   | 0.06 |   | (0.01 | ) |
| Transportation and selling                                        |       | 1.18                           |       | 1.13 |   | 1.36 |   | 1.19 |   | 1.03 |   |
| Operating                                                         |       | 7.59                           |       | 9.06 |   | 7.27 |   | 7.56 |   | 6.48 |   |
| Netback                                                           |       | 35.09                          |       | 39.26 |   | 39.53 |   | 31.89 |   | 29.72 |   |
| Crude Oil – Heavy – Total ($/bbl)                       |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 42.23                          |       | 47.38 |   | 45.98 |   | 40.12 |   | 35.74 |   |
| Production and mineral taxes                                      |       | 0.04                           |       | 0.04 |   | 0.06 |   | 0.06 |   | 0.01 |   |
| Transportation and selling                                        |       | 1.93                           |       | 1.81 |   | 1.71 |   | 1.72 |   | 2.48 |   |
| Operating                                                         |       | 10.93                          |       | 11.64 |   | 9.85 |   | 10.84 |   | 11.39 |   |
| Netback                                                           |       | 29.33                          |       | 33.89 |   | 34.36 |   | 27.50 |   | 21.86 |   |
| Crude Oil – Light and Medium –  Canadian Plains ($/bbl) |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 56.41                          |       | 68.78 |   | 59.68 |   | 52.43 |   | 44.81 |   |
| Production and mineral taxes                                      |       | 2.37                           |       | 2.36 |   | 2.16 |   | 2.37 |   | 2.59 |   |
| Transportation and selling                                        |       | 1.33                           |       | 1.22 |   | 1.39 |   | 1.27 |   | 1.43 |   |
| Operating                                                         |       | 9.20                           |       | 10.34 |   | 8.84 |   | 9.10 |   | 8.55 |   |
| Netback                                                           |       | 43.51                          |       | 54.86 |   | 47.29 |   | 39.69 |   | 32.24 |   |
| Crude Oil – Total ($/bbl)                                    |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 46.52                          |       | 54.07 |   | 50.23 |   | 43.94 |   | 38.12 |   |
| Production and mineral taxes                                      |       | 0.77                           |       | 0.76 |   | 0.73 |   | 0.78 |   | 0.80 |   |
| Transportation and selling                                        |       | 1.74                           |       | 1.62 |   | 1.61 |   | 1.96 |   | 1.78 |   |
| Operating                                                         |       | 10.39                          |       | 11.23 |   | 9.53 |   | 10.29 |   | 10.52 |   |
| Netback                                                           |       | 33.62                          |       | 40.46 |   | 38.36 |   | 30.91 |   | 25.02 |   |
| Natural Gas Liquids - Canadian  Plains ($/bbl)                    |       |                           |       |   |   |   |   |   |   |   |   |
| Netback                                                           |       | 59.98                          |       | 73.12 |   | 61.29 |   | 56.08 |   | 46.69 |   |
| Total Liquids ($/bbl)                                             |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 46.69                          |       | 54.33 |   | 50.36 |   | 44.08 |   | 38.22 |   |
| Production and mineral taxes                                      |       | 0.76                           |       | 0.75 |   | 0.72 |   | 0.77 |   | 0.79 |   |
| Transportation and selling                                        |       | 1.72                           |       | 1.60 |   | 1.59 |   | 1.94 |   | 1.76 |   |
| Operating                                                         |       | 10.27                          |       | 11.08 |   | 9.42 |   | 10.17 |   | 10.41 |   |
| Netback                                                           |       | 33.94                          |       | 40.90 |   | 38.63 |   | 31.20 |   | 25.26 |   |
| Natural Gas – Total ($/Mcf)                                  |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 6.08                           |       | 6.22 |   | 5.23 |   | 6.64 |   | 6.24 |   |
| Production and mineral taxes                                      |       | 0.10                           |       | 0.03 |   | 0.11 |   | 0.12 |   | 0.11 |   |
| Transportation and selling                                        |       | 0.27                           |       | 0.26 |   | 0.26 |   | 0.27 |   | 0.28 |   |
| Operating                                                         |       | 0.74                           |       | 0.89 |   | 0.66 |   | 0.74 |   | 0.69 |   |
| Netback                                                           |       | 4.97                           |       | 5.04 |   | 4.20 |   | 5.51 |   | 5.16 |   |
| Total ($/BOE)                                                     |       |                           |       |   |   |   |   |   |   |   |   |
| Price                                                             |       | 40.51                          |       | 44.04 |   | 38.85 |   | 41.48 |   | 37.74 |   |
| Production and mineral taxes                                      |       | 0.65                           |       | 0.42 |   | 0.70 |   | 0.75 |   | 0.71 |   |
| Transportation and selling                                        |       | 1.65                           |       | 1.58 |   | 1.56 |   | 1.74 |   | 1.70 |   |
| Operating(2)                                                      |       | 6.75                           |       | 7.59 |   | 6.12 |   | 6.66 |   | 6.64 |   |
| Netback                                                           |       | 31.46                          |       | 34.45 |   | 30.47 |   | 32.33 |   | 28.69 |   |

**Notes:**

(1)                   First quarteroperating costs include a prior year under accrual of operating costs ofapproximately $1.75/bbl for Foster Creek and $2.53/bbl for Christina Lake.

(2)                   Operating costs forthe year include a recovery of costs related to long-term incentives of$0.21/BOE.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 31

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|-----------------------------------------------------------------------------------|------------|

 

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Table ofContents

 

Thefollowing tables show the impact of our realized financial hedging on per-unitresults.

 
| ** **          | ** ** | **2009** | ** ** |
|---------------------|------------|----------|------------|
| ** **          | ** ** | **Year** | ** ** | **Q4 ** | ** ** | **Q3 ** | ** ** | **Q2 ** | ** ** | **Q1 ** | ** ** |
| Liquids ($/bbl)     |       | 0.98     |       | (0.05 | ) | (0.01 | ) | 1.39 |   | 2.86 |   |
| Natural Gas ($/Mcf) |       | 3.22     |       | 2.24 |   | 4.04 |   | 3.68 |   | 2.82 |   |
| Total ($/BOE)       |       | 11.18    |       | 7.07 |   | 13.25 |   | 13.24 |   | 11.02 |   |
|                |       |     |       |   |   |   |   |   |   |   |   |
| ** **          | ** ** | **2008** | ** ** |
| ** **          | ** ** | **Year** | ** ** | **Q4 ** | ** ** | **Q3 ** | ** ** | **Q2 ** | ** ** | **Q1 ** | ** ** |
| Liquids ($/bbl)     |       | (6.07    | )          | 2.71 |   | (8.85 | ) | (12.50 | ) | (6.63 | ) |
| Natural Gas ($/Mcf) |       | (0.30    | )          | 1.07 |   | (1.15 | ) | (1.41 | ) | 0.34 |   |
| Total ($/BOE)       |       | (3.50    | )          | 4.85 |   | (7.69 | ) | (10.01 | ) | (1.43 | ) |
|                |       |     |       |   |   |   |   |   |   |   |   |
| ** **          | ** ** | **2007** | ** ** |
| ** **          | ** ** | **Year** | ** ** | **Q4 ** | ** ** | **Q3 ** | ** ** | **Q2 ** | ** ** | **Q1 ** | ** ** |
| Liquids ($/bbl)     |       | (3.40    | )          | (9.98 | ) | (4.94 | ) | (1.47 | ) | 2.60 |   |
| Natural Gas ($/Mcf) |       | 0.75     |       | 0.85 |   | 1.04 |   | 0.42 |   | 0.71 |   |
| Total ($/BOE)       |       | 1.40     |       | (0.87 | ) | 1.84 |   | 0.98 |   | 3.58 |   |

 

 

 
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Table of Contents

 

**DrillingActivity**

 

The following tables summarize our gross participation andnet interest in wells drilled for the periods indicated.

 
|             | ** ** | **Exploration Wells Drilled      ** | ** ** | ** **    | ** ** | ** **                      | ** ** | ** **                                        | ** ** |
|------------------|------------|-------------------------------------------------------------------|------------|---------------|------------|---------------------------------|------------|---------------------------------------------------|------------|
|             | ** ** | **Oil **                                                     | ** ** | **Gas**       | ** ** | **Dry &****Abandoned** | ** ** | **Total    Working    Interest  ** | ** ** | ** Royalty** | ** ** | **Total** |
|             | ** ** | **Gross**                                                         | ** ** | ** Net** | ** ** | **Gross**                       | ** ** | **Net**                                           | ** ** | ** Gross** | ** ** | **Net** | ** ** | ** Gross ** | ** ** | **Net  ** | ** ** | ** Gross** | ** ** | **  Gross** | ** ** | **Net** |
| **2009:**        |       |                                                              |       |          |       |                            |       |                                              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Canadian  Plains |       | 4                                                            |       | 4        |       | -                               |       | -                                                 |       |   - |   | - |   | 4 |   | 4 |   | 8      |   | 12 |   | 4  |   |
| Total  Canada    |       | 4                                                            |       | 4        |       | -                               |       | -                                                 |       |   - |   | - |   | 4 |   | 4 |   | 8      |   | 12 |   | 4  |   |
| **2008:**        |       |                                                              |       |          |       |                            |       |                                              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Canadian  Plains |       | 1                                                            |       | 1        |       | 5                               |       | 3                                                 |       |   2 |   | 1 |   | 8 |   | 5 |   | 34      |   | 42 |   | 5  |   |
| Total  Canada    |       | 1                                                            |       | 1        |       | 5                               |       | 3                                                 |       |   2 |   | 1 |   | 8 |   | 5 |   | 34      |   | 42 |   | 5  |   |
| **2007:**        |       |                                                              |       |          |       |                            |       |                                              |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Canadian  Plains |       | 3                                                            |       | 3        |       | 4                               |       | 4                                                 |       |   - |   | - |   | 7 |   | 7 |   | 89      |   | 96 |   | 7  |   |
| Total  Canada    |       | 3                                                            |       | 3        |       | 4                               |       | 4                                                 |       |   - |   | - |   | 7 |   | 7 |   | 89      |   | 96 |   | 7  |   |

 
|             | ** ** | **       Development  Wells Drilled**(1)(2)(3) | ** ** | ** **    | ** ** | ** **                      | ** ** | ** **                       | ** ** | ** **              |
|------------------|------------|-----------------------------------------------------------------------------------|------------|---------------|------------|---------------------------------|------------|----------------------------------|------------|-------------------------|
|             | ** ** | **Oil**                                                                           | ** ** | **Gas**       | ** ** | **Dry &****Abandoned** | ** ** | **Total****Working****Interest** | ** ** | **  Royalty** | **Total** |
|             | ** ** | **Gross**                                                                         | ** ** | **Net ** | ** ** | **Gross**                       | ** ** | **Net  **              | ** ** | **Gross**               | **Net** | ** ** | **  Gross** | **Net ** | ** ** | **Gross** | ** ** | **Gross** | ** ** | **Net** |
| **2009:**        |       |                                                                              |       |          |       |                            |       |                             |       |                    |   |   |   |   |   |   |   |   |   |   |   |   |
| Integrated  Oil  |       | 45                                                                      |       | 24            |       | 8                               |       | 8                                |       | 8                       |   | 8 |   | 61 |   | 40 |   | 10   |   | 71 |   | 40 |
| Canadian  Plains |       | 107                                                                     |       | 106           |       | 555                             |       | 502                              |       | 2                       |   | 2 |   | 664 |   | 610 |   | 261   |   | 925 |   | 610 |
| Total  Canada    |       | 152                                                                     |       | 130           |       | 563                             |       | 510                              |       | 10                      |   | 10 |   | 725 |   | 650 |   | 271   |   | 996 |   | 650 |
| **2008:**        |       |                                                                              |       |          |       |                            |       |                             |       |                    |   |   |   |   |   |   |   |   |   |   |   |   |
| Integrated  Oil  |       | 41                                                                      |       | 21            |       | 13                              |       | 13                               |       | 4                       |   | 4 |   | 58 |   | 38 |   | 41   |   | 99 |   | 38 |
| Canadian  Plains |       | 105                                                                     |       | 92            |       | 1,489                           |       | 1,372                            |       | 7                       |   | 7 |   | 1,601 |   | 1,471 |   | 503   |   | 2,104 |   | 1,471 |
| Total  Canada    |       | 146                                                                     |       | 113           |       | 1,502                           |       | 1,385                            |       | 11                      |   | 11 |   | 1,659 |   | 1,509 |   | 544   |   | 2,203 |   | 1,509 |
| **2007:**        |       |                                                                              |       |          |       |                            |       |                             |       |                    |   |   |   |   |   |   |   |   |   |   |   |   |
| Integrated  Oil  |       | 55                                                                      |       | 29            |       | 6                               |       | 2                                |       | 6                       |   | 4 |   | 67 |   | 35 |   | 43   |   | 110 |   | 35 |
| Canadian  Plains |       | 161                                                                     |       | 138           |       | 2,215                           |       | 2,115                            |       | 4                       |   | 3 |   | 2,380 |   | 2,256 |   | 466   |   | 2,846 |   | 2,256 |
| Total  Canada    |       | 216                                                                     |       | 167           |       | 2,221                           |       | 2,117                            |       | 10                      |   | 7 |   | 2,447 |   | 2,291 |   | 509   |   | 2,956 |   | 2,291 |

**Notes:**

(1)  “Gross” wells are the total number of wells inwhich we will have an interest.

(2)  “Net” wells are the number of wells obtained byaggregating our working interests in each of the gross wells.

(3)  At December 31, 2009, 11 gross wells(seven net wells), all in Canada, were being drilled.

 

Inaddition to the above tables, we drilled stratigraphic test wells during theyear ended December 31, 2009, with the Integrated Oil Division havingdrilled 79 gross wells (40 net wells) and the Canadian PlainsDivision having drilled 22 gross wells (22 net wells).

 

**Location ofWells**(1)(2)

 

Thefollowing table summarizes our interests in producing wells, including wellsmechanically capable of producing, as at December 31, 2009.

 
|                | ** ** | ** ** | **Oil**   | ** ** | **Gas**             | ** ** | **Total** | ** ** |
|---------------------|------------|------------|-----------|------------|---------------------|------------|-----------|------------|
|                | ** ** | ** ** | **Gross** | ** ** | **  Net** | ** ** | **Gross** | ** ** | **  Net** | ** ** | **Gross** | ** ** | **  Net** | ** ** |
| **Alberta:**        |       |       |      |       |                |       |      |       |   |   |   |   |   |
| Integrated  Oil     |       | 187        |      | 94         |                | 767        |      | 716        |   | 954 |   | 810 |   |
| Canadian  Plains    |       | 3,151      |      | 3,066      |                | 28,342     |      | 27,469     |   | 31,493 |   | 30,535 |   |
| Total  Alberta      |       | 3,338      |      | 3,160      |                | 29,109     |      | 28,185     |   | 32,447 |   | 31,345 |   |
| **Saskatchewan:**   |       |       |      |       |                |       |      |       |   |   |   |   |   |
| Canadian  Plains    |       | 864        |      | 557        |                | 452        |      | 418        |   | 1,316 |   | 975 |   |
| Total  Saskatchewan |       | 864        |      | 557        |                | 452        |      | 418        |   | 1,316 |   | 975 |   |
| **Total**           |       | 4,202      |      | 3,717      |                | 29,561     |      | 28,603     |   | 33,763 |   | 32,320 |   |

**Notes:**

(1)      Cenovus alsohas varying royalty interests in 9,450 natural gas wells and4,229 crude oil wells which are producing or capable of producing.

(2)      Includes wellscontaining multiple completions as follows: 24,868 gross natural gas wells(24,037 net wells) and 1,504 gross crude oil wells (1,292 netwells).

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 33 |
|-----------------------------------------------------------------------------------|----|

 

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**Interest inMaterial Properties**(1)

 

The following table summarizes our developed, undevelopedand total landholdings as at December 31, 2009.

 
| ** **                     | ** ** | **Developed**                         | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|--------------------------------|------------|---------------------------------------|------------|-----------------|------------|-----------|------------|
| ** **                     | ** ** | **Gross**                             | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| ** **                     | ** ** | **(thousands of  acres)  ** |       |
| **Alberta:**                   |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| Integrated  Oil                |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| –  Crown(2)               |       | 551                                   |       | 457             |       | 1,428     |       | 1,053 |   | 1,979 |   | 1,510 |   |
| Canadian  Plains               |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| –  Fee(3)                 |       | 1,910                                 |       | 1,910           |       | 450       |       | 450 |   | 2,360 |   | 2,360 |   |
| –  Crown(2)               |       | 2,088                                 |       | 1,907           |       | 844       |       | 743 |   | 2,932 |   | 2,650 |   |
| –  Freehold(4)            |       | 68                                    |       | 55              |       | 21        |       | 18 |   | 89 |   | 73 |   |
| Total  Alberta                 |       | 4,617                                 |       | 4,329           |       | 2,743     |       | 2,264 |   | 7,360 |   | 6,593 |   |
| **Saskatchewan:**              |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| Canadian  Plains               |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| –  Fee(3)                 |       | 68                                    |       | 68              |       | 438       |       | 438 |   | 506 |   | 506 |   |
| –  Crown(2)               |       | 124                                   |       | 103             |       | 369       |       | 313 |   | 493 |   | 416 |   |
| –  Freehold(4)            |       | 14                                    |       | 10              |       | 42        |       | 40 |   | 56 |   | 50 |   |
| Total  Saskatchewan            |       | 206                                   |       | 181             |       | 849       |       | 791 |   | 1,055 |   | 972 |   |
| **Manitoba:**                  |       |                                  |       |            |       |      |       |   |   |   |   |   |   |
| Canadian  Plains – Fee(3) |       | 3                                     |       | 3               |       | 261       |       | 261 |   | 264 |   | 264 |   |
| Total  Manitoba                |       | 3                                     |       | 3               |       | 261       |       | 261 |   | 264 |   | 264 |   |
| **Total**                      |       | 4,826                                 |       | 4,513           |       | 3,853     |       | 3,316 |   | 8,679 |   | 7,829 |   |

**Notes:**

(1)                This table excludes approximately 2.4 million gross acresunder lease or sublease, reserving to us, royalties or other interests.

(2)                Crown/Federal lands are those lands owned by the federal orprovincial government or the First Nations, in which we have purchased aworking interest lease.

(3)               Fee lands are those lands in which we have a fee simpleinterest in the mineral rights and have either: (i) not leased out all ofthe mineral zones; or (ii) retained a working interest. The current feelands acreage summary now includes all fee titles owned by us, that have one ormore zones that remain unleased or available for development.

(4)                Freehold lands are those lands owned by individuals (otherthan a government or Cenovus) in which Cenovus holds a working interest lease.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 34 |
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**CapitalExpenditures, Acquisitions and Divestitures**

 

Ourgrowth in recent years has been achieved primarily through internal growth. Wehave a large inventory of internal growth opportunities and continue to examineselect acquisition opportunities to develop and expand our major properties.Acquisition opportunities may include corporate or asset acquisitions. We mayfinance any such acquisitions with debt, equity, cash generated fromoperations, proceeds from asset divestitures or a combination of these sources.

 

The following table summarizes our net capital investment for2009 and 2008.

 
|                                          | ** ** | **2009**          | ** ** | **2008** | ** ** |
|-----------------------------------------------|------------|-------------------|------------|----------|------------|
| ** **                                    |       | ($ millions) |
| **Capital  Investment**                       |       |              |       |     |       |
| Upstream  Canada                              |       |              |       |     |       |
| Foster  Creek                                 |       | 231               |       | 336      |       |
| Christina  Lake                               |       | 198               |       | 218      |       |
| Canadian  Plains                              |       | 478               |       | 872      |       |
| Other                                         |       | 47                |       | 90       |       |
|                                          |       | 954               |       | 1,516    |       |
| Downstream  Refining                          |       | 907               |       | 478      |       |
| Corporate                                     |       | 31                |       | 52       |       |
| **Capital  Investment**                       |       | 1,892             |       | 2,046    |       |
| **Acquisitions**                              |       | 3                 |       | -        |       |
| **Divestitures**                              |       | (209              | )          | (47      | )          |
| **Net  Acquisition and Divestiture Activity** |       | (206              | )          | (47      | )          |
| **Net Capital  Investment**                   |       | 1,686             |       | 1,999    |       |

 

**DeliveryCommitments**

 

Aspart of the Arrangement, we assumed, under existing contracts and agreements,and we have, as part of our ordinary business operations, a number of deliverycommitments to provide crude oil and natural gas. We have sufficient reservesof natural gas and crude oil to meet these commitments. More detailedinformation relating to such commitments can be found in the notes to ouraudited consolidated financial statements for the year ended December 31,2009.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 35 |
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**GENERAL**

 

**CompetitiveConditions**

 

Allaspects of the oil and gas industry are highly competitive and we activelycompete with other companies, particularly in the following areas: (i) explorationfor and development of new sources of bitumen, crude oil and natural gasreserves; (ii) reserves and property acquisitions; (iii) transportationand marketing of oil, natural gas, NGLs, diluents and electricity; (iv) supplyof refinery feedstock and the market for refined products; (v) access toservices and equipment to carry out exploration, development or operatingactivities; and (vi) attracting and retaining experienced industry personnel.The oil and gas industry also competes with other industries that providealternative forms of energy to consumers. Competitive forces can lead to costincreases or result in an oversupply of oil and natural gas, both of whichcould have a negative impact on our financial results.

 

**EnvironmentalProtection**

 

Ouroperations are subject to laws and regulations concerning protection of theenvironment, pollution and the handling and transport of hazardous materials.These laws and regulations generally require us to remove or remedy the effectof our activities on the environment at present and former operating sites,including dismantling production facilities and remediating damage caused bythe use or release of specified substances. The Safety, Environment andResponsibility Committee of our Board (the “SER Committee”) reviews andrecommends to our Board for approval environmental policies and overseescompliance with government laws and regulations. Monitoring and reportingprograms for environmental, health and safety (“EH&S”) performance inday-to-day operations, as well as inspections and assessments, have beendesigned to provide assurance that environmental and regulatory standards aremet. Contingency plans have been put in place for a timely response to anenvironmental event and remediation/reclamation programs have been put in placeand utilized to restore the environment.

 

Werecognize that there is a cost associated with carbon emissions and we believethat greenhouse gas regulations and the cost of carbon at various price levelscan be adequately accounted for as part of business planning. As part of ourfuture planning, management and the Board review the impact of a variety ofcarbon constrained scenarios on our strategy, with a current price range from$15 to $65 per tonne of emissions applied across a range of regulatory policyoptions. A major benefit of applying a range of carbon prices at the strategiclevel is that it provides direct guidance to the capital allocation process.Although uncertainty remains regarding potential future emissions regulation,we will continue to assess and evaluate the cost of carbon relative to ourinvestments across a range of scenarios.

 

Wealso examine the impact of carbon regulation on our major projects, includingboth our SAGD operations and refining assets. We continue to closely monitorpotential greenhouse gas legislation developments in the U.S. Some of theclimate change legislation being contemplated in the U.S. would requirerefiners to obtain emission allowances for emissions of greenhouse gases,including CO2 based on the carboncontent of their fuels. If this type of legislation is enacted into law, thiscould have a material impact on the cost structure of refined petroleumproducts that would be passed onto the consumer.

 

Weexpect to incur abandonment and site reclamation costs as existing oil and gasproperties are abandoned and reclaimed. In 2009, expenditures beyond normalcompliance with environmental regulations were not material. We do notanticipate making material expenditures beyond amounts paid in respect ofnormal compliance with environmental regulations in 2010. Based on estimates atDecember 31, 2009, the total anticipated undiscounted future cost ofabandonment and reclamation costs to be incurred over the life of our provedreserves is estimated at approximately $5.4 billion.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 36 |
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**Social andEnvironmental Policies**

 

Wehave a Corporate Responsibility Policy (the ‘‘Policy’’) that applies to anyactivity undertaken by or on behalf of Cenovus. The Policy has specificrequirements in the areas of: (i) leadership commitment; (ii) sustainablevalue creation; (iii) governance and business practices; (iv) humanrights; (v) labour practices; (vi) EH&S; (vii) stakeholderengagement; and (viii) socio-economic and community development.

 

ThePolicy and any revisions are approved by our executive team and our Board.Accountability for implementation of the Policy is at the operational levelwithin Cenovus’s business units. Business units have established processes toevaluate risks and programs are implemented to minimize that risk. Resultsrelated to the commitments are tied to the individual performance assessmentprocess.

 

ThePolicy states the following with respect to the environment: (i) Cenovuswill safeguard the environment and will operate in a manner consistent withrecognized global industry standards in EH&S; (ii) we will strive tomake efficient use of resources, to minimize our environmental footprint and toconserve habitat diversity and the plant and animal populations that may beaffected by our operations; and (iii) we will strive to reduce ouremissions intensity and increase our energy efficiency.

 

Withrespect to Cenovus’s relationship with the communities in which we do business,the Policy states that: (i) we engage in collaborative, consultative andpartnership approaches in our community investment and programs, recognizingthat no corporation is solely responsible for changing the fundamentaleconomic, environmental and social situation in a community or country; and (ii) throughour activities, Cenovus will assist in local capacity-building and developmutually beneficial relationships, to make a positive difference in thecommunities and regions where we operate.

 

Withrespect to human rights, the Policy states that Cenovus will not take part inhuman rights abuse and will not engage or be complicit in any activity thatsolicits or encourages human rights abuse.

 

Throughthe Policy, Cenovus is committed to protecting the health and safety of allindividuals affected by our activities, including our workforce and the public.We will not compromise the health and safety of any individual in the conductof our activities. Cenovus will strive to provide a safe and healthy workingenvironment and we expect our workers to comply with the health and safetypractices established for their protection.

 

Someof the steps that Cenovus has taken to embed the corporate responsibilityapproach throughout the organization include: (i) an EH&S managementsystem; (ii) a security program to regularly assess security threats tobusiness operations and to manage the associated risks; (iii) corporateresponsibility performance metrics to track our progress; (iv) an energyefficiency program that focuses on reducing energy use at Cenovus’s operationsand supports initiatives at the community level while also incentivizingemployees to reduce energy use in their homes; (v) an InvestigationsPractice and an Investigations Committee to review and resolve potentialviolations of Cenovus policies or practices and other regulations; (vi) anIntegrity Helpline that provides an additional avenue for Cenovus’sstakeholders to raise their concerns as well as the corporate responsibilitywebsite which allows people to write to Cenovus about non-financial issues ofconcern; (vii) an internal corporate EH&S audit program that evaluatesCenovus’s compliance with the expectations and requirements of the EH&Smanagement system; (viii) related policies and practices such as anAlcohol and Drug Policy, a Code of Business Conduct & Ethics andguidelines for correct behaviours with respect to the acceptance of gifts,conflicts of interest and the appropriate use of Cenovus equipment andtechnology in a manner that is consistent with leading ethical businesspractices; and (ix) a requirement for acknowledgement and sign-off on keypolicies from our Board and employees. In addition, our Board approves suchpolicies and is advised of significant contraventions thereof, and 

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 37 |
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receives updates on trends, issues or events which could havea significant impact on Cenovus.

 

**Employees**

 

AtDecember 31, 2009, we employed 2,221 full-time equivalent (“FTE”)employees as set forth in the following table.
|                      | ** ** | ** **        |
|---------------------------|------------|-------------------|
|                      | ** ** | **FTE Employees** |
| Integrated  Oil Division  |       | 804               |   |
| Canadian  Plains Division |       | 859               |   |
| Cenovus-wide              |       | 558               |   |
| Total                     |       | 2,221             |   |

 

We also engage a number of contractors and serviceproviders.

 

**ForeignOperations**

 

Onehundred percent of our reserves, production and assets are located in NorthAmerica, which limits our exposure to risks and uncertainties in countriesconsidered politically and economically unstable. Any of our future operationsand related assets outside North America may be adversely affected by changesin governmental policy, social instability or other political or economicdevelopments which are not within our control, including the expropriation ofproperty, the cancellation or modification of contract rights and restrictionson repatriation of cash.

 

 
| Cenovus Energy Inc. Annual Information Form for the year  ended December 31, 2009 | 38 |
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**DIRECTORS AND EXECUTIVE OFFICERS**

 

**Directors**

 

The names, province or state andcountry of residence, position(s) of, and the number of Common Shares, asat December 31, 2009, beneficially owned, or controlled or directed,directly or indirectly by, the persons who serve as our directors are set outbelow.

 
| **Name and Residence**(1)                                       | **Office Held**                                           | **Principal Occupation**                                                                                                                                                     | **Common Shares**

**Held** |
|-----------------------------------------------------------------|-----------------------------------------------------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------------------|
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Ralph S.  Cunningham(2,4,5,7)

Houston,  Texas,

United  States | Director                                                  | President &  Chief Executive Officer

EPE  Holdings, LLC

(Midstream  energy services)                                                                              | 0                           |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Patrick D.  Daniel(2,3,4,5)

Calgary,  Alberta, Canada          | Director                                                  | President &  Chief Executive Officer

Enbridge  Inc.

(Energy  delivery)                                                                                            | 39,348                      |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Ian W.  Delaney(2,4,5,7)

Toronto,  Ontario, Canada             | Director                                                  | Chairman  and Chief Executive

Officer  Sherritt International Corporation

(Nickel/cobalt  mining, oil and natural gas production, electricity generation and coal  mining) | 58,600                      |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Brian C.  Ferguson(8)

Calgary,  Alberta, Canada                | Director,

President &

Chief  Executive Officer | President &  Chief Executive Officer

Cenovus  Energy Inc.                                                                                                          | 97,887                      |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Michael A.  Grandin(2,5,9)

Calgary,  Alberta, Canada           | Chair                                                     | Corporate  Director                                                                                                                                                          | 123,120                     |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Valerie A.A.  Nielsen(2,3,5,6)

Calgary,  Alberta, Canada       | Director                                                  | Corporate  Director                                                                                                                                                          | 44,217                      |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Charles M.  Rampacek(5,6,7)

Dallas,  Texas,

United  States    | Director                                                  | Corporate  Director                                                                                                                                                          | 0                           |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Colin  Taylor(3,4,5)

Toronto,  Ontario, Canada                 | Director                                                  | Corporate  Director                                                                                                                                                          | 2,300                       |
|                                                            |                                                      |                                                                                                                                                                         |                        |
| Wayne G.  Thomson(2,5,6,7)

Calgary,  Alberta, Canada           | Director                                                  | President

Enviro  Valve Inc.

(Private  technology company)                                                                                                                 | 0                           |

**Notes:**

(1)             Each of thedirectors became members of our Board pursuant to the Arrangement.

(2)             Formerdirector of EnCana.

(3)             Member of theAudit Committee.

(4)             Member of theHuman Resources and Compensation Committee.

(5)             Member of theNominating and Corporate Governance Committee.

(6)             Member of theReserves Committee.

(7)             Member of theSafety, Environment and Responsibility Committee.

(8)             As an officerand a non-independent director, Mr. Ferguson is not a member of any of theCommittees of our Board.

(9)            Ex-officionon-voting member of all other Committees of our Board. As an ex-officionon-voting member, Mr. Grandin attends as his schedule permits and mayvote when necessary to achieve a quorum.

 

Each of the directors was appointedas a member of our Board effective November 30, 2009 pursuant to theArrangement and will hold office until the first annual meeting of the holdersof Common Shares or until his or her successor is duly elected or appointed,unless his or her office is earlier vacated. Additional directors may beappointed by our Board prior or subsequent to the first annual meeting ofholders of Common Shares in accordance with our articles. We have been grantedan exemption by the TSX from being required to hold our first annual meeting ofholders of Common Shares within six months of December 31, 2009. As aresult, the first annual meeting of holders of Common Shares is expected to 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 39 |
|-----------------------------------------------------------------------------------|----|

 

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occur in the second quarter of 2011and, in any event, not later than May 31, 2011, at which time holders ofCommon Shares will vote on the election of our directors and appointment of ourauditors.

 

**Five Year Occupational History of Directors**

 

***RalphS. Cunningham***

 

Mr. Cunningham has been adirector and President and Chief Executive Officer of EPE Holdings, LLC, thesole general partner of Enterprise GP Holdings L.P. (a publicly tradedmidstream energy holding company) since August 2007. From February 2006until July 2007, he served as Group Executive Vice President and ChiefOperating Officer and, from June 2007 to July 2007, also served asInterim President and Chief Executive Officer of Enterprise Products GP, LLC,the sole general partner of Enterprise Products Partners L.P. (a publiclytraded midstream energy company). In addition, he has served as a director ofEnterprise Products GP, LLC, the general partner of Enterprise ProductsPartners, L.P., since February 2006. He is also a director of Agrium Inc.(agricultural chemicals company), a director of LE GP, LLC, the general partnerof Energy Transfer Equity, L.P. (a publicly traded energy partnership) and adirector and Chairman of TETRA Technologies, Inc. (energy services andchemicals company). He was President and Chief Executive Officer of CITGOPetroleum Corporation (energy company) from May 1995 until his retirementin May 1997. In the not-for-profit sector, he is a member of the AuburnUniversity Chemical Engineering Advisory Council and the Auburn UniversityEngineering Advisory Council.

 

***Patrick D. Daniel***

 

Mr. Daniel has been President &Chief Executive Officer of Enbridge Inc. (energy delivery) since January 2001and a director since May 2000. He has been a senior executive officer ofEnbridge or its predecessor since 1994 and is a director of a number ofEnbridge subsidiaries. He is a director of Canadian Imperial Bank of Commerceand a member of the North American Review Board of American Air LiquideHoldings, Inc. (industrial and medical gases and related services). In thenot-for-profit sector, he is a member of the National Petroleum Council (an Oiland Natural Gas Advisory Committee to the U.S. Secretary of Energy) and adirector of the American Petroleum Institute.

 

He holds a Bachelor of Science (Universityof Alberta) and Master of Science (University of British Columbia), both inchemical engineering.

 

***Ian W. Delaney***

 

Mr. Delaney has been Chairmanof Sherritt International Corporation (nickel/cobalt mining, oil and naturalgas production, electricity generation and coal mining) since 1995 and assumedthe additional responsibilities of Chief Executive Officer of SherrittInternational Corporation in January 2009. He is also Chairman of TheWestaim Corporation (technology investment company) and a director of OPTICanada Inc. (oilsands development and upgrading company).

 

***Brian C. Ferguson***

 

Mr. Ferguson became President &Chief Executive Officer of Cenovus on November 30, 2009. Prior to hisexecutive leadership role at Cenovus, he was appointed Executive Vice-President &Chief Financial Officer of EnCana on March 1, 2006. At the time of themerger between Alberta Energy Company Ltd. and PanCanadian Energy Corporationin 2002, Mr. Ferguson was appointed Executive Vice-President, CorporateDevelopment with responsibility for three primary functions: investorrelations; business development, which included corporate strategic planning,acquisitions and divestitures, and corporate reserve evaluations; and acombined legal and corporate secretarial team.

 

Mr. Ferguson is a member of theCanadian Institute of Chartered Accountants (CICA) and is currently serving asChairman of CICA’s Risk Oversight and Governance Board.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 40 |
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He earned a Bachelor of Commercedegree, with distinction, from the University of Alberta in 1980 and receivedhis Chartered Accountant designation in 1983.

 

***Michael A. Grandin***

 

Mr. Grandin is a CorporateDirector. He is a director of BNS Split Corp. II (investment company) and HSBCBank Canada. He was Chairman and Chief Executive Officer of Fording CanadianCoal Trust (publicly traded mining trust) from February 2003 to October 2008when it was acquired by Teck Cominco Limited. He was President of PanCanadianEnergy Corporation from October 2001 to April 2002 when it mergedwith Alberta Energy Company Ltd. to form EnCana. He was also ExecutiveVice-President and Chief Financial Officer of Canadian Pacific Limited from December 1997to October 2001. Mr. Grandin served as Dean of the Haskayne School ofBusiness, University of Calgary from April 2004 to January 2006.

 

***Valerie A.A. Nielsen***

 

Ms. Nielsen is a CorporateDirector. She is a director of Wajax Income Fund (diversified company engagedin the sale and after-sales parts and service support of mobile equipment,diesel engines and industrial components). In the not-for-profit sector, she isa director of the Canada Olympic Committee. She was a member and past chair ofan advisory group on the General Agreement on Tariffs and Trade (GATT), theNorth America Free Trade Agreement (NAFTA) and international trade matters pertainingto energy, chemicals and plastics from 1986 to 2002.

 

She holds a Bachelor of Science(Hon.) (Dalhousie University).

 

***Charles M. Rampacek***

 

Mr. Rampacek is a CorporateDirector. Since June 2003, Mr. Rampacek has provided business andmanagement consulting services to the energy industry. Since 2006, Mr. Rampacekhas served as a director of Enterprise Products GP, LLC, the sole generalpartner of Enterprise Products Partners, L.P. (a publicly traded midstreamenergy company), and since 1998 he has been a director of Flowserve Corporation(a publicly traded manufacturer of industrial pumps, valves and seals). From August 2000until May 2003, he served as Chairman and President and Chief ExecutiveOfficer of Probex Corporation (a publicly held energy technology company) and,from January 1996 through August 2000, Mr. Rampacek wasPresident and Chief Executive Officer of Lyondell-Citgo Refining, L.P. (a crudeoil refiner and manufacturer of petroleum products). From 1982 to 1995, he heldvarious executive positions with energy-related subsidiaries of Tenneco Inc. (apublicly traded energy company) including President of Tenneco GasTransportation Company, Executive Vice President of Tenneco Gas Operations andSenior Vice President of Refining and Natural Gas Liquids. In thenot-for-profit sector, Mr. Rampacek serves on the Engineering AdvisoryCouncil for the University of Texas and the College of Engineering LeadershipBoard for the University of Alabama.

 

***Colin Taylor***

 

Mr. Taylor is a CorporateDirector. From June 1996 until May 2004, Mr. Taylor served twoconsecutive four-year terms as Chief Executive and Managing Partner of Deloitte &Touche LLP. Subsequently, he was Senior Counsel at Deloitte & ToucheLLP until his retirement in May 2008. He has held a number ofinternational management and governance responsibilities throughout hisprofessional career. Mr. Taylor also served as Advisory Partner to anumber of public and private company clients of Deloitte & Touche LLP.

 

***Wayne G. Thomson***

 

Mr. Thomson has been Presidentand a director of Enviro Valve Inc. (private company manufacturing proprietarypressure relief valves) since July 2009. He has also been President and adirector of Virgin Resources Limited (private junior international oil and gasexploration company focused in Yemen) since February 2005. He is also adirector of TG World Energy Corp. (TSX Venture listed international oil and gasexploration company). He 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 41 |
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has served as President and adirector of private and public companies in the oil and gas sector, namely,EcoMax Energy Services Ltd., Airborne Pollution Control, Hadrian Energy Corp.,Gardiner Oil and Gas Limited and Petrocorp Exploration Limited (New Zealand oiland gas company).

 

**Other Reporting Issuer Experience of Directors**

 

The following table sets out our directorsthat are directors of other reporting issuers (or the equivalent) in Canada ora foreign jurisdiction:

 
| **Name**              | **Name of Reporting Issuer**                                                                                                             |
|-----------------------|------------------------------------------------------------------------------------------------------------------------------------------|
|                  |                                                                                                                                     |
| Ralph S.  Cunningham  | Agrium Inc.

DEP  Holdings, LLC(1)

Enterprise  Products GP, LLC(2)

EPE  Holdings, LLC(3)

LE GP, LLC(4)

TETRA Technologies, Inc. |
|                  |                                                                                                                                     |
| Patrick D.  Daniel    | Canadian  Imperial Bank of Commerce

Enbridge  Inc.                                                                                      |
|                  |                                                                                                                                     |
| Ian W.  Delaney       | OPTI Canada  Inc.

Sherritt  International Corporation

The Westaim  Corporation                                                         |
|                  |                                                                                                                                     |
| Michael A.  Grandin   | BNS Split  Corp. II

HSBC Bank  Canada                                                                                                   |
|                  |                                                                                                                                     |
| Valerie  A.A. Nielsen | Wajax  Income Fund                                                                                                                       |
|                  |                                                                                                                                     |
| Charles M.  Rampacek  | Enterprise  Products GP, LLC(2)

Flowserve  Corporation                                                                                  |
|                  |                                                                                                                                     |
| Wayne G.  Thomson     | TG World  Energy Corp.                                                                                                                   |
| **Notes:**            |
| (1)                   | The sole  general partner of Duncan Energy Partners L.P.                                                                                 |
| (2)                   | The general  partner of Enterprise Products Partners L.P.                                                                                |
| (3)                   | The sole  general partner of Enterprise GP Holdings L.P.                                                                                 |
| (4)                   | The general  partner of Energy Transfer Equity L.P.                                                                                      |
|                       |                                                                                                                                          |  |

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 42 |
|-----------------------------------------------------------------------------------|----|

 

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**Executive Officers**

 

The names, province and country ofresidence and positions of the persons who serve as our executive officers areset out below.

 
| **Name and Residence**                         | **Office Held and Principal Occupation**                                          |
|------------------------------------------------|-----------------------------------------------------------------------------------|
|                                           |                                                                              |
| Brian C.  Ferguson

Calgary,  Alberta, Canada  | Director,  President & Chief Executive Officer                           |
|                                           |                                                                              |
| Ivor M.  Ruste

Calgary,  Alberta, Canada      | Executive  Vice-President & Chief Financial Officer                      |
|                                           |                                                                              |
| John K.  Brannan

Calgary,  Alberta, Canada    | Executive  Vice-President

*(President, Integrated Oil Division)*                 |
|                                           |                                                                              |
| Harbir S.  Chhina

Calgary,  Alberta, Canada   | Executive  Vice-President, Enhanced Oil Development & New Resource Plays |
|                                           |                                                                              |
| Kerry D.  Dyte

Calgary,  Alberta, Canada      | Executive  Vice-President, General Counsel &

Corporate  Secretary       |
|                                           |                                                                              |
| Judy A.  Fairburn

Calgary,  Alberta, Canada   | Executive  Vice-President, Environment &

Strategic  Planning            |
|                                           |                                                                              |
| Sheila M.  McIntosh

Calgary,  Alberta, Canada | Executive  Vice-President, Communications &

Stakeholder  Relations      |
|                                           |                                                                              |
| Donald T.  Swystun

Calgary,  Alberta, Canada  | Executive  Vice-President

*(President, Canadian Plains Division)*                |
|                                           |                                                                              |
| Hayward J.  Walls

Calgary,  Alberta, Canada   | Executive  Vice-President, Organization &

Workplace  Development        |

 

**Five Year Occupational History of Executive Officers**

 

***John K. Brannan***

 

Mr. Brannan is our ExecutiveVice-President (*President, Integrated Oil Division*).From November 2004 to November 2009, Mr. Brannan held thefollowing positions with EnCana: Executive Vice-President (*President,Integrated Oil Division*) effective January 1, 2007; ManagingDirector, Frontier and International New Ventures effective July 1, 2005;and from November 19, 2003 to June 30, 2005, Managing Director,International & New Ventures.

 

***Harbir S. Chhina***

 

Mr. Chhina is our ExecutiveVice-President, Enhanced Oil Development & New Resource Plays. From November 2004to November 2009, Mr. Chhina held the following positions withEnCana: Vice-President, Upstream Operations, Integrated Oil Division effective January 1,2007; and from April 16, 2003 to December 31, 2006, Vice-President,Oil Recovery Business Unit.

 

***Kerry D. Dyte***

 

Mr. Dyte is our ExecutiveVice-President, General Counsel & Corporate Secretary. Mr. Dyteheld the following positions with EnCana: from January 1, 2007 to November 2009,Vice-President, General Counsel & Corporate Secretary; and from December 1,2002 to December 31, 2006, General Counsel & Corporate Secretary.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 43 |
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***Judy A. Fairburn***

 

Ms. Fairburn is our ExecutiveVice-President, Environment & Strategic Planning. From April 2002to November 2009, Ms. Fairburn held the following positions withEnCana: Vice-President, Environment & Corporate Responsibilityeffective May 1, 2009; Vice-President, Environment & StrategicPlanning effective December 2008; Vice-President, Downstream Operationseffective January 2007; Vice-President, Weyburn Business Unit effective July 2004;Vice-President, Portfolio Management, Upstream Operations effective April 2003;and Vice-President, Strategic Planning, Onshore North America effective April 2002.

 

***Sheila A. McIntosh***

 

Ms. McIntosh is our ExecutiveVice-President, Communications & Stakeholder Relations. From November 2004to November 2009, Ms. McIntosh held the following positions withEnCana: Executive Vice-President, Corporate Communications effective January 1,2007; and from November 19, 2003 to December 31, 2006,Vice-President, Investor Relations.

 

***Ivor M. Ruste***

 

Mr. Ruste is our ExecutiveVice-President & Chief Financial Officer. From May 2006 to November 2009,Mr. Ruste held the following positions with EnCana: ExecutiveVice-President, Corporate Responsibility & Chief Risk Officereffective May 1, 2009; Executive Vice-President & Chief RiskOfficer effective January 1, 2008; Vice-President, Finance for theIntegrated Oil Division effective January 1, 2007; and Vice-President,Finance of the Corporate Finance Group effective May 1, 2006. From February 2003to April 2006, he was a partner and the Office Managing Partner for theEdmonton, Alberta office of KPMG LLP, as well as the Alberta Region ManagingPartner for KPMG LLP. During this period, he was also a member of the Board ofDirectors of KPMG Canada and, from December 2003 to March 2006, hewas Vice Chair of the Board of Directors for KPMG Canada.

 

***Donald T. Swystun***

 

Mr. Swystun is our ExecutiveVice-President (*President, Canadian Plains Division*).From November 2004 to November 2009, Mr. Swystun held thefollowing positions with EnCana: Executive Vice-President, (*President, Canadian Plains Division*) effective January 1,2007; Executive Vice-President, Corporate Development effective March 1,2006; and from September 1, 2001 to February 28, 2006, President,Ecuador Region.

 

***Hayward J. Walls***

 

Mr. Walls is our ExecutiveVice-President, Organization & Workplace Development. From November 2004to November 2009, Mr. Walls held the following positions with EnCana:Executive Vice-President, Corporate Services effective January 1, 2006;and effective November 19, 2003, Vice-President, Information Services &Chief Information Officer.

 

As of December 31, 2009, all ofour directors and executive officers, as a group, beneficially owned orexercised control or direction over, directly or indirectly,1,020,399 Common Shares or approximately 0.14 percent of the numberof Common Shares that were outstanding as of such date.

 

**Corporate Cease Trade Orders or Bankruptcies**

 

To our knowledge, other than asdescribed below, none of our current directors or executive officers is, as atthe date of this annual information form, or has been, within ten years beforethe date of this annual information form, a director, chief executive officeror chief financial officer of any company that:

 

(a)                             was subjectto a cease trade order, an order similar to a cease trade order or an orderthat denied the relevant company access to any exemption under securitieslegislation, that was in effect for a period of more than 30 consecutivedays 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 44 |
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(collectively,an “Order”) and that was issued while that person was acting in the capacity asdirector, chief executive officer or chief financial officer; or

 

(b)                            was subjectto an Order that was issued after the director or executive officer ceased tobe a director, chief executive officer or chief financial officer of thecompany being the subject of such an Order and which resulted from an eventthat occurred while that person was acting in the capacity as director, chiefexecutive officer or chief financial officer.

 

To our knowledge, other than asdescribed below, none of our directors or executive officers:

 

(a)                            is, at thedate of this annual information form, or has been within ten years before thedate of this annual information form, a director or executive officer of anycompany that, while that person was acting in that capacity, or within a yearof that person ceasing to act in that capacity, became bankrupt, made aproposal under any legislation relating to its own bankruptcy or insolvency orwas subject to or instituted any proceedings, arrangement or compromise withcreditors or had a receiver, receiver manager or trustee appointed to hold itsassets; or

 

(b)                            has, withinten years before the date of this annual information form, become bankrupt,made a proposal under any legislation relating to bankruptcy or insolvency, orbecome subject to or instituted any proceedings, arrangement or compromise withcreditors, or had a receiver, receiver manager or trustee appointed to hold theassets of the director or executive officer.

 

Mr. Rampacek was the Chairmanand President and Chief Executive Officer of Probex Corporation (“Probex”) in2003 when Probex filed a petition seeking relief under Chapter 7 of theBankruptcy Code (United States). In 2005, two complaints seeking recovery ofcertain alleged losses were filed against former officers and directors ofProbex, including Mr. Rampacek, as a result of the bankruptcy. Thesecomplaints were defended under Probex’s director and officer insurance by AIGand settlement was reached and paid by AIG with bankruptcy court approval inthe first half of 2006. An additional complaint was filed in 2005 againstnoteholders of certain Probex debt, of which Mr. Rampacek was a party. Asettlement of $2,000 was reached and similarly approved in the first half of2006.

 

**Conflicts of Interest**

 

There are potential conflicts ofinterest to which our directors and officers may be subject in connection withour operations. In particular, certain of our directors and officers are, ormay be, involved in managerial or director positions with other oil and gascompanies whose operations may, from time to time, be in direct competitionwith ours or with entities which may, from time to time, provide financing to,or make equity investments in, competitors of ours. Conflicts, if any, will besubject to the procedures and remedies available under the CBCA. The CBCAprovides that, in the event a director or officer has an interest in a materialcontract or transaction, whether made or proposed, with the corporation, thedirector or officer shall disclose his interest in such contract or transactionand shall refrain from voting on any matter in respect of such contract orunless otherwise provided by the CBCA. As at the date of this annualinformation form, we are not aware of any existing or potential materialconflicts of interest between us and any of our directors or officers.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 45 |
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**STATEMENT OF EXECUTIVE COMPENSATION**

 

The amounts reported in thisStatement of Executive Compensation are reported in U.S. dollars. As theamounts are paid in Canadian dollars, we have converted the amounts to U.S.dollars using the exchange rate of C$1.00 = US$0.9555, which is the exchangerate for Canadian dollars to U.S. dollars on December 31, 2009 based onthe daily noon buying rate published by the Bank of Canada.

 

**Compensation Discussion and Analysis**

 

***Introduction***

 

To ensure we meet our commitments toour shareholders, our employees and the communities in which we conduct ourbusiness, we depend on our highly-skilled, committed and experienced team ofexecutive officers to execute on our strategy.

 

Our executive compensation programwill focus on attracting, motivating, rewarding and retaining a strong team ofexecutive officers and will encourage short and long-term performance, toensure that the interests of our executive officers are aligned with theinterests of our shareholders.

 

***Compensation Philosophy***

 

Our compensation philosophy willdemonstrate how we value our employees and our executive officers and how wealign their interests with the interests of our shareholders. Our compensationphilosophy is being developed to include the following elements:

 

·                                     In ourbusiness, against the companies we compete with, we strive to be an employer ofchoice.

 

·                                     Ourcompensation is results-oriented and includes competitive salaries andbenefits, plus annual and long-term incentives.

 

·                                     We provide atotal compensation package, where all elements of the compensation program playa role in attracting, motivating, rewarding and retaining our employees and ourexecutive officers and which incorporates clear differentiation of pay based onindividual and company performance.

 

·                                     Our totalcompensation is designed to be competitive and to position the totalcompensation of our executive officers to be in the top quartile of our peergroup for outstanding performance. Similarly, for lesser performance, we willprovide lower total compensation through our annual and long-term incentiveprograms.

 

·                                      We recognizethat total compensation may be impacted by increases and decreases in commodityprices that may occur as a result of the cyclical nature of our business.Therefore, we will test the total compensation of our executive officers forvarious performance outcomes to understand how these changes will impactcompensation.

 

***Committee Oversight***

 

Our compensationprogram is overseen and governed by our Human Resources and CompensationCommittee (“HRC Committee”). As outlined in its mandate, the HRCCommittee’s responsibilities include:

 

·                                      Review andmonitor our compensation philosophy and compensation program design on at leastan annual basis.

 

·                                      Reviewcompetitive analysis and performance data to make recommendations regarding thecompensation of our President & Chief Executive Officer to our Board and toapprove the compensation of our other executive officers and report it to our Board.

 

·                                      Review andrecommend succession planning for our executive officers to our Board.

 

·                                      Review andmonitor our short and long-term incentive programs, including making recommendationsregarding the related incentive plans for approval by our Board and, in thecase of our Employee Stock Option Plan, for approval by our shareholders (whererequired), and approve grants of long-term incentives.

 

·                                      Review andmonitor our pension and investment plans and programs and recommend pension andinvestment matters to the Board where necessary.

 

***Market Data Comparisonsand Our Peer Group***

 

We will participate in annualcompensation surveys that are conducted by various compensation consultants to monitorhow we are doing. These surveys are useful for determining compensation trendsand will give us guidance to help us determine how well we are meeting ourcompensation program principles.

 

We target to have the total directcompensation of our executive officers provided at a level that is consistentwith the total direct compensation provided by our peer group to theirexecutive officers. Specifically, we target the total direct compensation forour executive officers at the 50th percentile of our peer group and allow for theability to provide higher compensation for superior performance. For theinitial compensation review conducted for our executive officers, we identifiedthe following companies as our peer group:

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 46 |
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·                                          CanadianNatural Resources Limited

·                                          Devon EnergyCorporation

·                                          EnbridgeInc.

·                                          EnCanaCorporation

·                                          Husky EnergyInc.

·                                          Imperial OilLimited

·                                          Marathon OilCorporation

·                                          Murphy OilCorporation

·                                          Nexen Inc.

·                                          SuncorEnergy Inc.

·                                          TalismanEnergy Inc.

·                                          TransCanadaCorporation

 

This peer group is comprised ofNorth American oil and gas companies of similar size and complexity to Cenovus,taking into consideration market capital and revenue.

 

We engage the services of TowersWatson, a respected compensation consultant, to advise us on thecompetitiveness of the compensation of our executive officers and on thecompetitiveness of our compensation program as a whole. Specifically, we obtainadvice from Towers Watson on the following items:

 

·                                     Regularcompetitive analysis of the elements of our compensation program, includingbase salary, annual bonus program, long-term incentive program, retirement andpension benefits and other compensation, which are provided to our executiveofficers.

 

·                                     Theobjectives and principles that we use to design our compensation philosophy andprogram, including advice regarding the peer group.

 

·                                     Trends andbest practices in compensation philosophy and program design, using variousresearch methods including compensation and workforce surveys.

 

·                                     Provision ofcomprehensive retirement programs and pension plan advice, including acting asour actuary for pension plan matters and as asset management consultant for ourpension and investment plans.

 

Our HRC Committee has directlyretained Towers Watson to advise it specifically regarding matters relating tothe compensation of our executive officers, including commenting and advisingon the information provided to the HRC Committee by management concerningour executive officers and particularly regarding the compensation of ourPresident & Chief Executive Officer. The retainer of Towers Watson byour Board is independent from the advice provided to management. The terms ofthe retainer will be stated in a formal mandate that outlines the role ofTowers Watson and the terms of reference as an independent advisor to theHRC Committee. To ensure independence, there is a clear reportingrelationship between Towers Watson and the HRC Committee, regular meetingsare held between Towers Watson and the HRC Committee without managementpresent, and executive compensation consulting work is retained and manageddirectly by the Chair of the HRC Committee.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 47 |
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***The Elements of ourCompensation Program***

 

*Base Salary*

 

Base salary provides a level offixed cash compensation which is consistent with market practice. We determinethe base salary of our executive officers annually based upon comparisons tothe most recently available market data, and considering experience, scope ofresponsibilities, individual performance and strategic leadership over thecourse of the year.

 

*Annual Bonus Program*

 

We are developing the details of ourannual bonus program with the objective of rewarding short-term performance andresults in a manner consistent with market practice.

 

Our executive officers will identifyperformance objectives for each calendar year. In determining annual bonusawards, our program will involve evaluation of the following on an annualbasis:

 

·                                     Individualperformance as compared to stated objectives; and

 

·                                     Companyperformance on the basis of objective financial and operational measures aswell as certain more subjective measures such as corporate and environmentalresponsibility, corporate governance and employment practices, all of whichwill be identified more particularly over the course of the year.

 

Bonus awards will be payable in thefirst quarter of each year, based upon the prior year’s achievement of statedcorporate and individual objectives.

 

*Long-Term Incentive Program*

 

We are developing our long-termincentive program to align the interests of our executive officers with ourshareholders through holdings of significant equity interests and to providefor long-term retention. In addition to the intrinsic performance riskcontained within equity-based incentives, we also believe it is important toinclude achievement of additional performance measures that will determinevesting of a portion of long-term incentives that may be granted.

 

We currently expect to grantlong-term incentives on an annual basis, in conjunction with our annualcompensation cycle, using guidelines based on a review of competitive marketdata and on individual performance. Our long-term incentive programs providefor the granting of stock options and performance share units.

 

We plan to use recycle ratio as thekey performance measure for vesting of performance-based long-term incentives.We believe that recycle ratio is the key measure of total value added as itmeasures our ability to generate operating cash flow in excess of the all-incosts of adding reserves. Recycle ratio is calculated as follows:

 

                                      RecycleRatio =                   Netback                     

                                                                    Finding &Development Costs

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 48 |
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Netback is calculated based upon:

 

·                                          operating &administrative costs;

·                                          commodityprice;

·                                          royalties;and

·                                          transportation.

 

Finding & Development Costsare calculated based upon:

 

·                                          capitalspending (capital efficiency); and

·                                          reportedproved reserves additions.

 

The balance of the long-termincentives will vest based upon prescribed time vesting criteria over a periodof three years.

 

Cenovus Options have associatedtandem stock appreciation rights (“TSARs”). A TSAR entitles the optionholder tosurrender the right to exercise the Cenovus Option to purchase a specifiednumber of Common Shares and to receive cash (or, at our election, CommonShares) instead. The optionholder will be paid the closing price of a CommonShare on the TSX on the last trading day preceding the date the TSAR isexercised less the grant price of the Cenovus Option, multiplied by the numberof Cenovus Options surrendered. When a TSAR is exercised, the Cenovus Option itis associated with is surrendered and the underlying right to purchase a CommonShare is forfeited.

 

The grant price of Cenovus Optionswill be the closing price of the Common Shares on the TSX on the dayimmediately prior to the day the Cenovus Options are granted.

 

*Replacement Stock Options*

 

Pursuant to the Arrangement,replacement stock options (with associated TSARs) were granted to our employeesand executive officers. For each EnCana stock option held as of November 30,2009, our employees and executive officers received one EnCana ReplacementOption and one Cenovus Replacement Option. The grant price of the previouslyheld EnCana stock options was adjusted as required by the EnCana Key EmployeeStock Option Plan using a stated formula based upon the one day volume weightedaverage trading price of a common share of each of EnCana (as traded on the TSXon a pre-Arrangement basis), new EnCana (as traded on the TSX on an if, as andwhen issued basis) and Cenovus (as traded on the TSX on an if, as and whenissued basis) on December 2, 2009. All of the replacement stock optionshave associated TSARs.

 

The Cenovus Replacement Options havea five year term from their original grant date and vest according to theiroriginal grant date based upon the following schedule: 30 percent on thefirst anniversary date of the original grant, 30 percent on the secondanniversary date of the original grant and the remaining 40 percent on thethird anniversary date of the original grant. For two-thirds of the CenovusReplacement Options which replaced grants from 2007 to 2009, there is anadditional vesting requirement related to achievement of a stated recycleratio. Specifically:

 

·                                      0 percent ofthe performance-based Cenovus Replacement Options vest where the recycle ratiois equal to or less than 1.0.

 

·                                      50 percentof the performance-based Cenovus Replacement Options vest where the recycleratio is 2.0 or greater.

 

·                                      100 percent ofthe performance-based Cenovus Replacement Options vest where the recycle ratiois 3.0 or greater.

 

·                                      Recycleratios of between 1.0 and 3.0 will result in vesting of performance-basedCenovus Replacement Options on a linear basis such that portions of the grantmay vest.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 49 |
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·                                      Performance-basedCenovus Replacement Options that do not vest in a particular year are forfeitedand cancelled.

 

***Deferred Share Units***

 

We have a Deferred Share Unit Planfor Employees (“DSU Plan”) under which our employees (including our executiveofficers) may elect, irrevocably and in the prior calendar year, to converteither 25 percent or 50 percent of their annual bonus (which wouldotherwise be paid in cash) to deferred share units (“DSUs”). In addition, theDSU Plan allows the HRC Committee to award a grant of DSUs on terms andconditions it determines at the time of the grant. Dividend equivalents arepaid in the form of additional DSUs, consistent with dividends declared onCommon Shares.

 

DSUs generally vest when they arecredited to the individual’s account, unless the HRC Committee determinesotherwise. DSUs may only be redeemed upon the departure of the individual fromCenovus, either by resignation, termination or retirement. When an individualdeparts, he or she must redeem the DSUs in his or her account by December 15of the first calendar year following the year of his or her departure fromCenovus. The value of DSUs that may be redeemed is equal to the number of DSUsin the individual’s account on the date of redemption multiplied by the tradingprice of a Common Share on the day prior to the date of redemption. This amountis paid to the individual in cash on an after-tax basis.

 

Pursuant to the Arrangement, DSUs ofEnCana held by employees of Cenovus were exchanged for Cenovus DSUs. The fairvalue of the Cenovus DSUs credited to each employee was based on the fair marketvalue of Cenovus Common Shares relative to EnCana common shares prior to theEffective Date of the Arrangement.

 

***Retirement and PensionBenefits***

 

We believe it is important to providefor the future retirement of our executive officers through retirement andpension benefits. Our program provides competitive retirement and pensionbenefits, gives long-term financial security and aids with retention.

 

Certain of our executive officers,including our President & Chief Executive Officer, participate in theDefined Benefit Option of Cenovus’s Canadian Pension Plan (our “DB Plan”).Under our DB Plan, normal retirement is at age 65, although employeesmay retire as early as age 55 with a reduced pension for earlycommencement. We pay pensions from our DB Plan up to the permitted levelsfor registered pension plans.

 

Certain of our other executiveofficers, including our Executive Vice-President & Chief FinancialOfficer, participate in the Defined Contribution Option of Cenovus’s CanadianPension Plan (our “DC Plan”). Under the terms of the DC Plan,contributions are made to an account for each employee or executive officer inthe amount of eight percent of base salary. Each executive officer individuallymanages the investments made within their accounts. A specified number ofinvestment options are made available by Cenovus within the DC Plan andthe accounts held by executive officers.

 

Our Canadian Pension Plan, whichincludes both our Defined Benefit Option and Defined Contribution Option, is aregistered pension plan. Additional pension benefits may be payable from theCenovus Energy Inc. Canadian Supplemental Pension Plan for pension benefitsbeyond the limits permitted from a registered pension plan. Pension benefitsare based on years of credited service and final average pensionable earningsfor DB Plan participants.

 

***Other Compensation***

 

To achieve a competitive totalcompensation package, we provide additional elements of compensation such as anannual allowance, company-paid parking, financial and retirement planningservices, company matching of personal contributions to an investment plan ofup 

 

 
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to five percent of base salary and,in some cases, membership fees associated with the personal use of clubs.

 

***2009 Compensation for ourNamed Executive Officers***

 

Our Board considered availablemarket data, taking into account the size and nature of our business, peercomparisons, experience, leadership and individual performance to determine thecompensation to be provided to our executive officers in their capacity asexecutive officers of Cenovus in December 2009.

 

Effective December 1, 2009, theannual base salary of Brian C. Ferguson, our President & ChiefExecutive Officer, is $859,950 and of Ivor M. Ruste, our ExecutiveVice-President & Chief Financial Officer, is $429,975.

 

For the annual bonus award for the2009 performance year, our Board considered the performance of our executiveofficers in their capacities as executive officers of Cenovus in December 2009and also took into consideration their role, leadership and guidance throughthe Arrangement and through the transition period following the successfulcompletion of the Arrangement.

 

Our President & ChiefExecutive Officer, Mr. Ferguson, was the strategic leader for Cenovusthrough the course of the Arrangement and in the transition period thatfollowed. Our Board identified that Mr. Ferguson’s performance wasoutstanding for his role leading up to the completion of the Arrangement and intransition activities that resulted in Cenovus becoming a fully independentcompany in December 2009. In addition, our Board recognized the successfuloperating and financial performance measures for the year for the IntegratedOil and Canadian Plains Divisions, which are our key operations. In recognitionof the strong operating and financial performance of EnCana and Cenovus in2009, and Mr. Ferguson’s role in the Arrangement and in the transition in December 2009,our Board awarded a maximum bonus award. The amount of Mr. Ferguson’s bonusearned in December 2009 was $119,438 (representing 1/12th of the amount of the total award). Inaddition, our Board used its discretion to include in this bonus amount $47,775representing a special award relating to the significant contributions of Mr. Fergusonto the successful completion of the Arrangement that was made in the form of agrant of DSUs that vest one-half on the date of grant and one-half one yearfrom the date of grant.

 

Mr. Ruste, ExecutiveVice-President & Chief Financial Officer, also achieved outstandingresults in his role relating to the Arrangement and in the transition in December 2009.Of particular note, Mr. Ruste provided leadership in structuring andobtaining financing that allowed the Arrangement to proceed and that provides astrong foundation for Cenovus. In recognition of the strong operating andfinancial performance of EnCana and Cenovus, and Mr. Ruste’s role in theArrangement and in the transition in December 2009, Mr. Ruste wasawarded a maximum bonus award, attributable to December 2009, of $62,440(representing 1/12th of the total bonus award). This bonus awardincludes an amount of $35,831 representing a special award relating to thesignificant contributions of Mr. Ruste to the successful completion of theArrangement that was made in the form of a grant of DSUs that vest one-half onthe date of grant and one-half one year from the date of grant.

 

For 2009, the bonus target for allour employees, including our executive officers, was increased by ten percentto reinforce the achievement of significant capital budget savings in 2009. Thesuccessful achievement of this program was reflected in the December 2009annual bonus payment of our executive officers.

 

Our executive officers were notgranted any long-term incentives in December 2009 by Cenovus. CenovusReplacement Options that were granted on November 30, 2009 as a result ofthe Arrangement are reported in the Outstanding Option-Based Awards Table thatfollows this Compensation Discussion and Analysis.

 

 
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***ShareOwnership Guidelines***

 

We believe it is important toclosely align the interests of our executive officers with our shareholders andone key way to accomplish this is to require that they maintain certain minimumholdings of Common Shares. As a result, our HRC Committee approved thefollowing Common Share ownership guidelines in December 2009:

 
| President & Chief Executive Officer | 4 times  annual base salary |
|----------------------------------------------|-----------------------------|
| Other Executive Officers                     | 2 times  annual base salary |

 

The executive officers who heldexecutive officer positions with EnCana are required to achieve these CommonShare ownership guidelines by December 1, 2012. For those new executiveofficers appointed at the time of successful completion of the Arrangement orin future years, achievement of the Common Share ownership guidelines will berequired within five years of their appointment as an executive officer. Theexecutive officers newly appointed at the time of successful completion of theArrangement have until December 1, 2014 to achieve these guidelines.

 

***Performance Graph***

 

The following chart compares thecumulative total shareholder return for Cenovus on the TSX of $100 invested inCommon Shares (assuming reinvestment of dividends) over the period of time thatCenovus Common Shares traded on the TSX in December 2009.

 

 

Cenovus began trading on a regularbasis on the TSX on December 3, 2009. Therefore, we are unable todetermine any trends at this very early stage in respect of the compensation ofour executive officers as compared to total shareholder return for the month ofDecember 2009 as shown in the Performance Graph.

 

**Tables**

 

The amounts reported in thefollowing tables are reported in U.S. dollars. As the amounts are paid inCanadian dollars, we have converted the amounts to U.S. dollars using the exchangerate of C$1.00 = US$0.9555, which is the exchange rate for Canadian dollars toU.S. dollars on December 31, 2009 based on the daily noon buying ratepublished by the Bank of Canada.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 52 |
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***SummaryCompensation Table***

 

Cenovus commenced independentoperations on December 1, 2009. The compensation earned in December 2009by the President & Chief Executive Officer and the ExecutiveVice-President & Chief Financial Officer, in their capacities asexecutive officers of Cenovus, as discussed in the Compensation Discussion andAnalysis, is summarized in the following table.

 
| ** **                                                                          | ** ** | ** **                       | ** ** | ** **             | ** ** | **Non-Equity  Incentive Plan  Compensation** | ** ** | ** **                   | ** ** | ** **                            | ** ** | ** **                   | ** ** |
|-------------------------------------------------------------------------------------|------------|----------------------------------|------------|------------------------|------------|----------------------------------------------|------------|------------------------------|------------|---------------------------------------|------------|------------------------------|------------|
| **Name and****Principal Position**(1)

** **                                   | ** ** | **Year**

                  | ** ** | **Salary  ($)**        | ** ** | **Annual Incentive  Plans  ($)**             | ** ** | **Pension  Value**(2)**($)** | ** ** | **All Other  Compensation**(3)**($)** | ** ** | **Total  Compensation  ($)** | ** ** |
|  

Brian C.  Ferguson 

President &  

Chief  Executive Officer       | ** ** | **2009**

** **             |       | 71,662

          |       | 119,438(4)

                            |       | 33,421

                |       | 7,195

                          |       | 231,716

               |       |
|                                                                                | ** ** | ** **                       |       |                   |       |                                         |       |                         |       |                                  |       |                         |       |
| Ivor M.  Ruste 

Executive  Vice-

President &  Chief 

Financial  Officer | ** ** | **2009**

** **

** ** |       | 35,831

 

  |       | 62,440(4)

 

                     |       | 2,867

 

         |       | 5,117

 

                  |       | 106,255

 

       |       |

**Notes:**

(1)               No other executiveofficer of Cenovus was paid Total Compensation (excluding Pension Value) for December2009 in his or her capacity as an executive officer of Cenovus of more than$150,000.

(2)               Pension Valuerepresents the compensatory change from November 30, 2009 to December 31,2009 set out in the Compensatory Change column of the Defined Benefit PensionTable or the Defined Contribution Pension Table, as applicable.

(3)              All OtherCompensation represents Mr. Ferguson’s and Mr. Ruste’s annual allowanceand company matching of contributions to the investment plan for December 2009.There was no other compensation paid by Cenovus in 2009 to Mr. Fergusonand Mr. Ruste.

(4)               The Annual IncentivePlans amounts include the amount of the annual bonuses paid to Mr. Fergusonand Mr. Ruste that were earned in their capacities as executive officersof Cenovus for the month of December 2009. These amounts were paidpartially in cash and partially in the form of DSUs under the DSU Plan.

 

***Outstanding Option-BasedAwards***

 

The following table outlines theoption-based awards outstanding as at December 31, 2009. There are nooutstanding share-based awards.

 
| **Name**

** ** | **Number of  securities  underlying  unexercised  options**(1)

**(#)** | **Grant Date of  Cenovus  Replacement  Options**

** ** | **Original  Grant Date**

** **               | **Option  Exercise  price**(2)

**(C$)** | **Option  expiration  date**

** **           | **Value of  unexercised  in-the-money  options**(3)**(US$)** |
|----------------------|-------------------------------------------------------------------------|--------------------------------------------------------------|----------------------------------------------------|------------------------------------------|----------------------------------------------------|--------------------------------------------------------------|
|                 |                                                                    |                                                         |                                               |                                     |                                               |                                                         |
| Brian C.  Ferguson   | 80,000

134,250

138,750

150,000                                       | 30-Nov-2009

30-Nov-2009

30-Nov-2009

30-Nov-2009           | 13-Feb-2006

13-Feb-2007

13-Feb-2008

11-Feb-2009 | 22.91

26.64

32.96

26.27               | 13-Feb-2011

13-Feb-2012

13-Feb-2013

11-Feb-2014 | 274,420

0

0

32,965                                        |
|                 |                                                                    |                                                         |                                               |                                     |                                               |                                                         |
| Ivor M.  Ruste       | 50,000

67,125

69,375

90,000                                          | 30-Nov-2009

30-Nov-2009

30-Nov-2009

30-Nov-2009           | 01-May-2006

13-Feb-2007

13-Feb-2008

11-Feb-2009 | 26.54

26.64

32.96

26.27               | 01-May-2011

13-Feb-2012

13-Feb-2013

11-Feb-2014 | 0

0

0

19,779                                              |

**Notes:**

(1)               The number ofsecurities underlying unexercised options includes stock options that havevested and options that have not yet vested. For the 2007, 2008 and 2009 stockoption grants, performance-based Cenovus Replacement Options that do not vestin a given year will be cancelled and deducted from the amounts stated in thistable.

(2)               The exercise priceof the previously held EnCana stock options was adjusted, as required by theEnCana Key Employee Stock Option Plan, using a formula based upon the one dayvolume weighted average trading price of a common share of each of EnCana (astraded on the TSX on a pre-Arrangement basis), new EnCana (as traded on the TSXon an if, as and when issued basis) and Cenovus (as traded on the TSX on an if,as and when issued basis) on December 2, 2009.

(3)               The value ofunexercised in-the-money options is based on the December 31, 2009 closingprice of the Common Shares of C$26.50 on the TSX.

 

 
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***Incentive Plan Awards –Value Vested or Earned During the Year***

 

This table provides the value ofnon-equity incentive plan compensation that was earned in December 2009. Nooption-based or share-based awards vested during December 2009.

 
| **Name**          | ** ** | **Non-Equity Incentive Plan  Compensation –  Value Earned During the Year****(1)****($)** | ** ** |
|-------------------|------------|------------------------------------------------------------------------------------------------|------------|
| Brian C. Ferguson |       | 119,438                                                                                        |       |   |
| Ivor M. Ruste     |       | 62,440                                                                                         |       |   |

**Note:**

(1)                  Non-EquityIncentive Plan Compensation includes the amount of the annual bonuses paid to Mr. Fergusonand Mr. Ruste that were earned in their capacities as executive officersof Cenovus for the month of December 2009. These amounts were paidpartially in cash and partially in the form of a grant of DSUs under the DSU Plan.

 

***Defined Benefit PensionTable***

 

The following table outlines theestimated annual benefits, accrued pension obligations and compensatory andnon-compensatory changes under the DB Plan.

 
| **Name**          | ** ** | **Number of  Years of  Credited  Service  (#)** | ** ** | **Annual Benefits  Payable  ($)** | ** ** | **Accrued  Obligation  at Start of  Year**(1)**($)** | ** ** | **Compensatory  Change**(2)**($)** | ** ** | **Non-  Compensatory  Change**(3)**($)** | ** ** | **Accrued  Obligation  at Year  End  ($)** | ** ** |
|-------------------|------------|-------------------------------------------------|------------|-----------------------------------|------------|------------------------------------------------------|------------|------------------------------------|------------|------------------------------------------|------------|--------------------------------------------|------------|
| ** **        | ** ** | ** **                                      | ** ** | **At Year  End**                  | ** ** | **At Age  65**                                       | ** ** | ** **                         | ** ** | ** **                               | ** ** | ** **                                 | ** ** | ** ** | ** ** |
| Brian C. Ferguson |       | 27.25(4)                                        |       | 379,967                           |       | 548,509                                              |       | 9,649,835(5)                       |       | 33,421                                   |       | (337,671)                                  |       | 9,345,585(6) |   |

**Notes:**

(1)                The accruedobligation at the start of year is as of November 30, 2009 and isdetermined using the same methodology and assumptions described in the pensionaccounting information letter reflecting the company split from EnCana**.**

(2)                Includesservice cost net of employee contributions plus the difference between actualand estimated earnings.

(3)                Includesinterest on the accrued obligation as of November 30, 2009, employeecontributions plus changes in the discount rate and exchange rates and othernet experience as at December 31, 2009.

(4)                Includesthree additional years of service granted under an individual agreement.

(5)                Includesincremental obligation of $4,452,253 arising as a result of Mr. Ferguson’sappointment as President & Chief Executive Officer (and the change inhis base salary and bonus entitlement for pension inclusion purposes). Also includesoptional contributions account balance of $51,833, as of November 30,2009, which represents the accumulated value of employee paid optionalcontributions to purchase optional DB pension benefits.

(6)                Includesoptional contributions account balance of $53,815, as of December 31,2009, which represents the accumulated value of employee paid optionalcontributions to purchase optional DB pension benefits.

 

***Defined ContributionPension Table***

 

The following table outlines thechange in value of DC Plan holdings over the course of 2009.

 
| **Name**      | ** ** | **Accumulated  Value at Start  of Year  ($)** | ** ** | **Compensatory  Change  ($)** | ** ** | **Non-  Compensatory  Change  ($)**(1) | ** ** | **Accumulated  Value at Year  End  ($)** | ** ** |
|---------------|------------|-----------------------------------------------|------------|-------------------------------|------------|----------------------------------------|------------|------------------------------------------|------------|
| Ivor M. Ruste |       | 119,340                                       |       | 2,867                         |       | 2,909                                  |       | 125,116                                  |       |

**Note:**

(1)  Includes investmentearnings during 2009.

 

***Employment, Severance andChange in Control Arrangements***

 

Cenovus has entered into change incontrol agreements with our executive officers. In addition, our executiveofficers receive the same treatment as other employees on a change in controlin respect of vesting of a portion of their replacement stock options as specificallystated in the replacement stock option grant agreements. Cenovus has notentered into any other employment or severance arrangements with our executiveofficers.

 

The change in control agreements that have been entered intowith our executive officers provide for a “double trigger” for payment ofseverance benefits. First, a change in control 

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 | 54

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as defined in the agreement mustoccur. Secondly, the employment of the executive officer must terminate (otherthan for cause, disability, retirement or death), which would includetermination by the executive officer for certain specified reasons such as achange in responsibilities or a reduction in salary and benefits.

 

The terms of the change in controlagreements provide for the following severance benefits should both aspects ofthe double trigger be activated (change in control and termination ofemployment):

 

·                  A lump sumseverance payment representing the amount of salary and bonus, for a period of36 months for our President & Chief Executive Officer and for aperiod of 24 months for our other executive officers. The bonus isdetermined based upon the average of the bonus payments paid to the executive officerover the preceding five-year period, which for our executive officers willinclude consideration of high performance reward program awards paid while atEnCana.

 

·                  Medical, dental andinsurance benefits continue, for a period of 36 months for our President &Chief Executive Officer and for a period of 24 months for our otherexecutive officers.

 

·                  All time-based replacementstock options and 50 percent of the performance-based replacement stockoptions would immediately vest and be available for exercise, for a period of36 months for our President & Chief Executive Officer and for aperiod of 24 months for our other executive officers. The remaining50 percent of the performance-based replacement stock options vest uponthe achievement of the stated performance criteria as outlined in the grantagreements for the replacement stock options.

 

·                  Pension benefitscontinue to accrue, for a period of 36 months for our President &Chief Executive Officer and for a period of 24 months for our otherexecutive officers.

 

Under the terms of the CenovusReplacement Option grant agreements, on a change in control, immediate vestingof time-based and 50 percent of the performance-based Cenovus ReplacementOptions would occur for all optionholders.

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 | 55

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***Change in Control Table***

 

The following table outlines theamounts that would be payable to our President & Chief ExecutiveOfficer and our Executive Vice-President & Chief Financial Officer ifa change in control occurred on December 31, 2009 and, in the case of thechange in control agreements, employment terminated as a result of the changein control on December 31, 2009.
| ** **        | ** ** | ** **                                    | ** ** | ** **          | ** **                                      | ** **                     | ** ** | ** **                                 | ** ** | ** **            | ** ** | ** **                               | ** ** | ** ** | ** **   |
|-------------------|------------|-----------------------------------------------|------------|---------------------|-------------------------------------------------|--------------------------------|------------|--------------------------------------------|------------|-----------------------|------------|------------------------------------------|------------|------------|--------------|
| ** **        | ** ** | ***Long-Term  Incentive  Grant  Agreements*** | ** ** | ** **          | ***Change in Control  Agreements***

** ** | ** **                     |
| **Name**          | ** ** | **Value of  Exercisable  Vested LTIs**(1)     | ** ** | **Cash  Severance** | ** **                                      | **Annual  Incentive  Plan**(2) | ** ** | **Value of  Exercisable  Vested  LTIs**(1) | ** ** | **Pension  Benefits** | ** ** | **Other  Compensation  and Benefits**(3) | ** ** | **Total**  | ** **   |
| Brian C. Ferguson |       | 21,977                                        |       |                |                                            | 2,579,850                      |       |                                       | 2,256,980  |                  |       | 21,977                                   |       |       | 5,087,764(4) |   | 259,020 |   | 10,205,591 |   |
| Ivor M. Ruste     |       | 13,186                                        |       |                | 859,950                                         |                           |       | 799,621                                    |       |                  | 13,186     |                                     |       | 96,314(5)  |         | 122,808 |   | 1,891,879 |   |

**Notes:**

(1)                The value ofexercisable vested LTIs is calculated by multiplying the number of options thatwould vest on a change in control by the difference between the grant price andC$26.50, the closing price of a Common Share on December 31, 2009.

(2)                The AnnualIncentive Plan amount is calculated based upon the average of the bonuspayments paid to Mr. Ferguson over the preceding five-year period and Mr. Rusteover the preceding four-year period (Mr. Ruste has four years of priorservice), which for our executive officers will include consideration of highperformance reward program awards paid while at EnCana. The average is thenapplied to a period of 36 months for Mr. Ferguson and over a periodof 24 months for Mr. Ruste.

(3)                The value ofOther Compensation and Benefits is the amount in the column titled “OtherCompensation” in the Summary Compensation table multiplied by 36 for Mr. Fergusonand by 24 for Mr. Ruste.

(4)                Thecalculation of Mr. Ferguson’s five-year annual average pensionableearnings is based on his annual base salary plus bonus (67 percent ofsalary). The early retirement reduction factor applicable under the CenovusEnergy Inc. Canadian Supplemental Pension Plan is calculated at the age he wouldhave attained at December 31, 2012. This incremental lump sum pensionvalue is equal to the difference between the actuarial present values of Mr. Ferguson’saccrued pension, as modified, less the accrued pension, unmodified, using the commutedvalue basis for the DB Plan as of December 31, 2009. The discountrates used are 3.9 percent for ten years and 5.4 percent thereafter.

(5)                This incrementallump sum pension value is equal to eight percent of two times his annual basesalary plus bonus (40 percent of salary).

 

**Director Compensation**

 

In December 2009, thecompensation to be paid to our non-employee directors was determined followinga review of the elements and level of compensation for directors of a companyof comparable size and scope to Cenovus. Our President & Chief Executive Officer does not receivecompensation for serving as a director of Cenovus.

 

***Fees***

 

Each non-employee director of ourBoard is paid an annual retainer of $28,665 per year. This annual retainer ispaid in quarterly installments and is pro-rated for periods of partial service.For each meeting of the Board (excluding our annual organization meeting forwhich no attendance fee is payable), a fee of $1,433 is paid to eachnon-employee director who attends in person or by telephone. For each meetingof a Committee of the Board, a fee of $1,433 is paid to each Committee memberwho attends in person or by telephone.

 

Each non-employee director isreimbursed for travel and other expenses for attending Board or Committeemeetings. In addition, for each meeting of the Board where the director is 

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 | 56

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normally resident outside of westernCanada, or when the location of a meeting of the Board or a Committee of theBoard is outside of western Canada and away from the director’s place ofresidence, an additional fee equal to the normal meeting fee is paid to thedirector.

 

The Chair of each Committee of theBoard is paid an additional fee of $7,166 per annum for each Committee whichthe director chairs. The Audit Committee Chair is paid a supplemental fee of$7,166 per year. Our non-executive Chair of the Board receives an additionalannual retainer of $238,875.

 

***Deferred Share Units***

 

Each non-employee director isprovided with an annual grant of 7,500 DSUs under the Deferred Share Unit Planfor Directors of Cenovus Energy Inc. This annual grant of DSUs is made on January 1of each year, the first grant occurring on January 1, 2010. Dividendequivalents are paid in the form of additional DSUs consistent with dividendsdeclared on Common Shares. Newly appointed or elected directors receive theirinitial grant of DSUs upon joining the Board. We also provide the option to ournon-employee directors to take all or a portion of their annual retainer andmeeting fees in the form of DSUs.

 

DSUs vest when they are credited tothe director’s account. DSUs may only be redeemed upon the departure of thedirector from Cenovus, either by resignation, termination or retirement. When adirector departs, he or she must redeem the DSUs in his or her account by December 15of the first calendar year following the year of his or her departure as adirector. The value of DSUs that may be redeemed is equal to the number of DSUsin the director’s account on the date of redemption multiplied by the tradingprice of a Common Share on the day prior to the date of redemption. This amountis paid to the director in cash on an after-tax basis.

 

Pursuant to the Arrangement, DSUs ofEnCana held by the directors of Cenovus were exchanged for Cenovus DSUs. Thefair value of the Cenovus DSUs credited to each director was based on the fair marketvalue of Cenovus Common Shares relative to EnCana common shares prior to theEffective Date of the Arrangement.

 

***Share Ownership Guidelines***

 

In December 2009, weimplemented share ownership guidelines for our non-employee directors. Eachdirector (excluding our non-executive Chair of our Board) is required tobeneficially own voting shares of Cenovus, which may include holdings of DSUs,at least equal in value, based on the market price of Common Shares, to$477,750. Our non-executive Chair of our Board is required to beneficially ownvoting shares of Cenovus, including DSUs, at least equal in value, based on themarket price of Common Shares, to $955,500. Each director is required toachieve the share ownership guidelines by the later of December 1, 2014 orwithin five years after the director joins the Board.

 

The following table summarizes theannual compensation of our directors paid by Cenovus from November 30,2009 to December 31, 2009.

 

**Director Compensation Table**

 
| **Name**             | ** ** | **Fees Earned  ($)** | ** ** | **All Other  Compensation**(1)**($)** | ** ** | **Total  ($)  ** | ** ** | ** ** |
|----------------------|------------|----------------------|------------|---------------------------------------|------------|----------------------------|------------|------------|
| Ralph S. Cunningham  |       | 7,416                |       |                                  | 1,433      |                       |       | 8,849      |   |   |
| Patrick D. Daniel    |       | 9,472                |       |                                  | 0          |                       |       | 9,472      |   |   |
| Ian W. Delaney       |       | 7,416                |       |                                  | 1,433      |                       |       | 8,849      |   |   |
| Michael A. Grandin   |       | 30,188               |       |                                  | 0          |                       |       | 30,188     |   |   |
| Valerie A.A. Nielsen |       | 8,226                |       |                                  | 0          |                       |       | 8,226      |   |   |
| Charles M. Rampacek  |       | 6,792                |       |                                  | 1,433      |                       |       | 8,226      |   |   |
| Colin Taylor         |       | 8,226                |       |                                  | 1,433      |                       |       | 9,659      |   |   |
| Wayne G. Thomson     |       | 7,416                |       |                                  | 0          |                       |       | 7,416      |   |   |

**Note:**

(1)  Represents travel fees paidto directors as applicable.

 

 
| Cenovus Energy  Inc. Annual Information Form for the year ended December 31, 2009 | 57

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**AUDIT COMMITTEE**

 

*The full text of the AuditCommittee mandate is included in Appendix C of this annual information form.*

 

**Composition of the Audit Committee**

 

The Audit Committee consists ofthree members, all of whom are independent and financially literate inaccordance with the definitions in National Instrument 52-110 *Audit Committees* (“NI 52-110”). The relevant education andexperience of each of the members of the Audit Committee is outlined below.

 

***Patrick D. Daniel (AuditCommittee Chair)***

 

Mr. Daniel holds a Bachelor ofScience (University of Alberta) and a Master of Science (University of BritishColumbia), both in chemical engineering. He also completed Harvard University’sAdvanced Management Program. He is President and Chief Executive Officer and adirector of Enbridge Inc. (energy delivery company), as well as a director of anumber of Enbridge subsidiaries. He is a past director and member of the Audit Committeeof Enerflex Systems Income Fund (compression systems manufacturer). He is alsoa past director and Chair of the Finance Committee of Synenco Energy Inc.(oilsands mining) which was acquired by Total E&P Canada Ltd. in August 2008.

 

***Valerie A.A. Nielsen***

 

Ms. Nielsen holds a holds aBachelor of Science (Hon.) (Dalhousie University). She is a professionalgeophysicist who has held management positions in the oil and gas industryand/or provided consulting services to industry for over 30 years. She hasalso completed a variety of finance and accounting courses at the universitylevel. Ms. Nielsen was a member and past chair of an advisory group on theGeneral Agreement on Tariffs and Trade (GATT), the North America Free TradeAgreement (NAFTA) and international trade matters pertaining to energy,chemicals and plastics from 1986 to 2002. She was also a director of the Bankof Canada. She is a director and serves on the Audit Committee of Wajax IncomeFund (diversified company engaged in the sale and after-sales parts and servicesupport of mobile equipment, diesel engines and industrial components).

 

***Colin Taylor (FinancialExpert)***

 

Mr. Taylor is a charteredaccountant, as well as a member and Fellow of the Institute of CharteredAccountants of Ontario. He also completed Harvard University’s AdvancedManagement Program. Mr. Taylor served two consecutive four-year terms (June 1996to May 2004) as Chief Executive and Managing Partner and was SeniorCounsel of Deloitte & Touche LLP until his retirement in May 2008.He has held a number of international management and governanceresponsibilities throughout his professional career. Mr. Taylor alsoserved as Advisory Partner to a number of public and private company clients ofDeloitte & Touche LLP.

 

The above list does not includeMichael A. Grandin who is an ex-officio member of the Audit Committee.

 

 
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**Pre-Approval Policies and Procedures**

 

We have adopted policies andprocedures with respect to the pre-approval of audit and permitted non-auditservices to be provided by PricewaterhouseCoopers LLP. The Audit Committee hasestablished a budget for the provision of a specified list of audit andpermitted non-audit services that the Audit Committee believes to be typical,recurring or otherwise likely to be provided by PricewaterhouseCoopers LLP. Thebudget generally covers the period between the adoption of the budget and thenext meeting of the Audit Committee, but, at the option of the Audit Committee,it may cover a longer or shorter period. The list of services is sufficientlydetailed as to the particular services to be provided to ensure that: (i) theAudit Committee knows precisely what services it is being asked to pre-approve;and (ii) it is not necessary for any member of management to make ajudgment as to whether a proposed service fits within the pre-approvedservices.

 

Subject to the following paragraph,the Audit Committee has delegated authority to the Chair of the Audit Committee(or if the Chair is unavailable, any other member of the Audit Committee) topre-approve the provision of permitted services by PricewaterhouseCoopers LLPwhich are not otherwise pre-approved by the Audit Committee, including the feesand terms of the proposed services (“Delegated Authority”). Any required determinationabout the Chair’s unavailability will be required to be made by the good faithjudgment of the applicable other member(s) of the Audit Committee afterconsidering all facts and circumstances deemed by such member(s) to berelevant. All pre-approvals granted pursuant to Delegated Authority must bepresented by the member(s) who granted the pre-approvals to the full AuditCommittee at its next meeting.

 

The fees payable in connection withany particular service to be provided by PricewaterhouseCoopers LLP that hasbeen pre-approved pursuant to Delegated Authority: (i) may not exceedC$200,000, in the case of pre-approvals granted by the Chair of the AuditCommittee, and (ii) may not exceed C$50,000, in the case of pre-approvalsgranted by any other member of the Audit Committee.

 

All proposed services or the feespayable in connection with such services that have not already beenpre-approved must be pre-approved by either the Audit Committee or pursuant toDelegated Authority. Prohibited services may not be pre-approved by the AuditCommittee or pursuant to Delegated Authority.

 

**External Auditor Service Fees**

 

During fiscal 2009, no fees werebilled to Cenovus for professional services rendered by PricewaterhouseCoopersLLP. Prior to the Arrangement, all fees had been billed to EnCana.

 

We did not rely on the *de minimus* exemption provided by Section (c)(7)(i)(C) ofRule 2-01 of SEC Regulation S-X in 2009.

 

 
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**STATEMENT OF CORPORATE GOVERNANCE PRACTICES**

 

Cenovus and the Board are committedto attaining the highest standards of corporate governance. We maintainappropriate governance practices as fundamental to generating long-termshareholder value. We continually assess and update our practices and believewe employ a leading system of corporate governance to ensure the interests ofour shareholders are well protected.

 

The securities regulatoryauthorities in all of the provinces and territories of Canada (collectively,the “CSA”) adopted National Policy 58-201 *Corporate GovernanceGuidelines* (“NP 58-201”) effective June 30, 2005 and NationalInstrument 58-101 *Disclosure of Corporate Governance Practices*(“NI 58-101”) effective June 30, 2005, as amended effective December 31,2007 and March 17, 2008. Disclosure of governance practices is required inaccordance with NI 58-101.

 

With respect to the U.S., we arerequired to comply with the provisions of the *Sarbanes-OxleyAct of 2002* and the rules adopted by the SEC pursuant to thatAct, as well as the governance rules of the NYSE, in each case asapplicable to foreign issuers. Most of the NYSE corporate governance standards arenot mandatory for Cenovus as a non-U.S. company, but we are required todisclose the significant differences between our corporate governance practicesand the requirements applicable to U.S. companies listed on the NYSE under NYSEcorporate governance standards. Except as summarized on our website ***www.cenovus.com***, we are incompliance with the NYSE corporate governance standards in all significantrespects.

 

Our Board and its Committeescontinually evaluate and enhance our corporate governance practices bymonitoring Canadian and U.S. regulatory developments affecting corporategovernance, accountability and transparency of public company disclosure.

 

The following statement of ourcorporate governance practices is made in accordance with Form 58-101F1 ofNI 58-101. Statements are also included with respect to certain applicableprovisions of the *Sarbanes-Oxley Act of 2002*,related SEC rules, NYSE rules and Canadian rules relating to auditcommittees pursuant to NI 52-110. Our approach to corporate governance meets orexceeds the best practices enunciated under NP 58-201.

 

**Board of Directors**

 

***Independence***

 

Our Board is currently composed ofnine directors, eight of whom are independent directors. Mr. Ferguson, ourPresident & Chief Executive Officer, is the only member of our Boardwho is a member of our management. The remainder of the directors areindependent directors on the basis that such directors have no direct orindirect material relationship with us which could be reasonably expected tointerfere with the exercise of a member’s independent judgment.

 

Our Board is responsible fordetermining whether or not each director is independent within the meaning ofsuch term set forth in NI 58-101. In applying this definition, our Boardconsiders all relationships of our directors with us, including business,family and other relationships.

 

Pursuant to our By-Laws, our Chairand the Chief Executive Officer shall not be the same person, except in verylimited circumstances. The Chair of our Board is required to ensure that ourBoard is properly organized, functions effectively and meets its obligationsand responsibilities including those relating to corporate governance matters.

 

 
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***Majority Voting forDirectors***

 

Our Board has a policy requiringthat a director tender his or her resignation if the director receives more “withheld”votes than “for” votes at any meeting where shareholders vote on theuncontested election of directors. Our Board will consider the resignation and,in the absence of special circumstances, will accept the resignation consistentwith an orderly transition. The director will not participate in any Committeeor our Board deliberations on the resignation offer. Our Board will make itsdecision to accept or reject the resignation within 90 days. Our Board mayfill a vacancy in accordance with our articles, By-Laws and applicablecorporate laws.

 

***Other Directorships***

 

Our Board has not adopted a formalpolicy limiting the number of outside directorships of our directors. Otherpublic company board memberships held by our directors are described in “Directorsand Executive Officers - Other Reporting Issuer Experience of Directors”in this annual information form. Directors who serve together on other boardsare Mr. Cunningham and Mr. Rampacek who are directors of EnterpriseProducts GP, LLC, the sole general partner of Enterprise Products Partners, L.P.We do not believe this interlocking board relationship will impact on theability of these directors to act in our best interests.

 

**Board of Directors’ Mandate**

 

The fundamental responsibility ofour Board pursuant to our Board of Directors’ Mandate (the “Board Mandate”) isto appoint a competent executive team and to oversee the management of thebusiness, with a view to maximizing shareholder value and ensuring corporate conductin an ethical and legal manner via an appropriate system of corporategovernance and internal control. The Board Mandate sets out the keyresponsibilities of our Board in its stewardship and includes the followingprimary responsibilities. The Board Mandate is set out as Appendix D to thisannual information form.

 

***Supervision of Management***

 

Our Board is responsible forappointing the Chief Executive Officer and monitoring the Chief ExecutiveOfficer’s performance against a set of mutually agreed upon corporateobjectives directed at maximizing shareholder value. The HRC Committeeprovides recommendations to our Board on succession planning, on seniormanagement development and on the performance of management in relation to theaccomplishment of their annual objectives. The HRC Committee is comprisedexclusively of independent directors. Annually, the HRC Committee measuresmanagement’s performance and total compensation against the combined set ofobjectives comprised in our annual budget and our strategic plan. Our Boardsupports management’s commitment to training and developing all employees.

 

***Our Strategic Plan***

 

Our Board is responsible for theannual review and approval of our strategic plan. Key objectives of thestrategic plan, as well as quantifiable operating and financial targets, andsystems for the identification, monitoring and mitigation of principal businessrisks, are incorporated into the annual strategy review. Our Board discussesand reviews all materials relating to the strategic plan with management andreceives updates from management on the strategic plan throughout the year. Managementis required to seek our Board’s approval for any transaction that would have asignificant impact on our strategic plan.

 

 
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***Risk Management***

 

Our Board is responsible for ensuringthat a system is in place to identify our principal risks, includingoperational risks, and to monitor the process to manage such risks. The AuditCommittee reviews management’s identification of significant financial risks orexposures and meets regularly to review reports and discuss significant riskareas with the internal and external auditors. In addition, our Board ensuresthat an adequate system of internal control exists.

 

***Communications***

 

Our Board is responsible forapproving a communications policy or policies to ensure that a system forcorporate communications to all stakeholders exists, including processes forconsistent, transparent, regular and timely public disclosure, and tofacilitate feedback from stakeholders.

 

We provide detailed information onour business, operating and financial results in accordance with our continuousdisclosure requirements under applicable securities laws. Our news releases andother prescribed documents are required to be filed on the electronic databasemaintained by the CSA known as “SEDAR” at ***www.sedar.com***and that maintained by the SEC known as “EDGAR” at ***www.sec.gov***.

 

Our Board receives regular reportson any key communications issues. Procedures to facilitate feedback fromshareholders include the following:

 

(a)                                 shareholdersmay send comments via email to ***investor.relations@cenovus.com***;

 

(b)                                 aconfidential and, where desired, anonymous Integrity Helpline to reportconcerns by telephone to 1-877-445-3222, or by written correspondence to ourcorporate offices at P.O. Box 766, 421 – 7 Avenue S.W., Calgary,Alberta, Canada T2P 0M5; and

 

(c)                                 our transferagent, CIBC Mellon Trust Company, has a website (***www.cibcmellon.com***)and a toll-free number (1-800-387-0825) to assist shareholders.

 

***Expectations of Directors***

 

The Board Mandate also sets out theexpectations and business duties of the directors, including the expectationfor directors to attend all meetings and the responsibility to ensure thatBoard materials are distributed to all directors in advance of regularlyscheduled meetings to allow for sufficient review. Our Board has a code ofbusiness conduct and ethics for directors, officers, employees, contractors andconsultants, and monitors compliance with the practice, and approves anywaivers of the practice, for officers and directors.

 

***Corporate Governance***

 

Our Board is responsible forestablishing an appropriate system of corporate governance, including policiesand practices to ensure our Board functions independently of management and toensure that processes are in place to address applicable regulatory, corporate,securities and other compliance matters.

 

**Position Descriptions**

 

We have established writtenguidelines for each of the President & Chief Executive Officer, theChair of our Board and each Committee Chair which are available on our websiteat ***www.cenovus.com***. Our Board isresponsible for monitoring the Chief Executive Officer’s performance againstmutually agreed corporate objectives directed at maximizing shareholder value. Aspart of this process, the HRC Committee reviews and approves corporategoals and objectives relevant to the President & Chief ExecutiveOfficer’s compensation and evaluates the President & Chief ExecutiveOfficer’s performance in light of 

 

 
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these corporate goals and objectives.Our Board has established clearly defined limits with respect to management’sauthority.

 

**Orientation and Continuing Education of Directors**

 

The Nominating and Corporate GovernanceCommittee of our Board (the “NCG Committee”) is responsible forimplementing procedures for the orientation and education of new Board membersconcerning their role and responsibilities and for the continued development ofexisting members of our Board. We have established a formal program for newdirectors which includes a series of interviews and orientation sessions withsenior management and field tours of major producing properties and areas ofoperations hosted by the respective division executive and senior operatingstaff. As part of the formal orientation, new directors will receive an informationpackage containing our strategic planning materials, directors’ informationhandbook, recently issued disclosure materials and independent third-party peercomparison information. In addition to the formal program, new members to ourBoard are encouraged to conduct their own due diligence through independentmeetings with the Chair of our Board, President & Chief ExecutiveOfficer or any other director.

 

We provide continuing educationopportunities for all directors so that individual directors can enhance theirskills and have a current understanding of our business environment.

 

In addition to ongoing internalcontinuing education programs, directors have the opportunity to attendexternal educational programs to assist in their development as a director. Allsuch external programs will be approved through the Chair of our Board.

 

**Ethical Business Conduct**

 

We have a set of guiding principlesand values outlining the basis on which we operate as a high performance,principled corporation. These principles and values, in conjunction with our CorporateResponsibility Policy, establish our commitment to conducting businessethically and legally. To provide further guidelines in this regard, we haveestablished a written code of business conduct and ethics (the “Code ofBusiness Conduct & Ethics”).

 

The Code of Business Conduct &Ethics applies to all officers, employees, contractors, consultants anddirectors. The Code of Business Conduct & Ethics makes specificreference to the protection and proper use of our assets, fair dealings withour stakeholders, detection and prevention of fraud and compliance with lawsand regulations. All of our officers, employees, contractors, consultants anddirectors are asked to review the Code of Business Conduct & Ethicsand confirm on a regular basis that they understand their individualresponsibilities and agree to its requirements.

 

Any waiver of the Code of BusinessConduct & Ethics for officers or directors may only be made by ourBoard and will be promptly disclosed to shareholders as required by law.

 

We have established theInvestigations Practice to provide an effective, consistent and appropriateprocedure by which all incidents that potentially violate our policies orpractices, or are potential violations under statutes, regulations, rules andpolicies applicable to us, are properly received, reviewed, investigated,documented and brought to appropriate resolution. For this purpose, theInvestigations Committee conducts, reviews and oversees investigations. TheInvestigations Committee also refers violations related to any accounting,internal accounting controls or auditing matters to the Audit Committee. Theapplicable Committees of our Board, including specifically the Audit Committee,receive quarterly summaries on the nature and status of ongoing investigationsand the resolutions of any investigations since the previous report. These Committeeswill report any significant or material investigations to our Board.

 

We have an Integrity Helpline whichprovides an additional avenue for stakeholders to communicate concerns abouthow we conduct our business. Concerns can be reported to the Integrity Helplineorally or in writing and may be made confidentially or anonymously. Allconcerns reported through the Integrity Helpline relating to violations ofpolicies or practices are handled in accordance with the InvestigationsPractice. A report of 

 

 
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investigations and Integrity Helplinecomplaints, which preserves confidentiality and anonymity, is prepared on aquarterly basis and provided to the applicable Committees of our Board atregularly scheduled Committee meetings.

 

In addition to the statutoryobligations of directors to address conflict of interest matters, we haveestablished a protocol to assist our executive team in managing in advance anypotential conflicts of interest that may impact individual directors. Theprotocol requires an executive team member to: confirm an individual director’spotential conflict with the Chief Executive Officer; provide advice to theChair for advance notice to the affected director; ensure the portion ofwritten reference material which gives rise to a conflict is excluded from thepre-meeting distribution to the affected director; and, with respect to theparticular item in question, recommend directly to the affected director thathe or she abstain from participating in the meeting or excuse himself orherself from the meeting.

 

We have established a policy on Disclosure,Confidentiality and Employee Trading that governs the conduct of all staff,contractors, consultants and directors and restricted trading and insiderguidelines for directors and senior officers.

 

President & Chief ExecutiveOfficer general guidelines have been established which require the President &Chief Executive Officer to foster a corporate culture that promotes ethicalpractices and encourages individual integrity and social responsibility.

 

The Corporate Responsibility Policy,Code of Business Conduct & Ethics and the President & ChiefExecutive Officer General Guidelines are available at ***www.cenovus.com***.

 

**Nomination of Directors**

 

The NCG Committee is comprisedof all of the independent directors of our Board. The NCG Committee has awritten mandate establishing the NCG Committee’s purpose which includesassessing and recommending new nominees to our Board. In assessing newnominees, the NCG Committee seeks to ensure that there is a sufficientrange of skills, expertise and experience to ensure that our Board can carryout its mandate and function effectively. The NCG Committee receives andevaluates suggestions for candidates from individual directors, the President &Chief Executive Officer and from professional search organizations.

 

The NCG Committee alsoconsiders the appropriate size of our Board for the ensuing year and, on aperiodic basis, oversees the evaluation and assessment of the effectiveness ofour Board as a whole, the Committees of our Board and the contribution ofindividual members.

 

The NCG Committee isresponsible for reviewing, reporting and providing recommendations forimprovement to our Board with respect to all aspects of corporate governance. TheNCG Committee is responsible for this Statement of Corporate GovernancePractices. The NCG Committee monitors best practices among major Canadianand U.S. companies to help ensure we adhere to high standards of corporategovernance.

 

The NCG Committee has theauthority to retain and terminate any search firm to be used by the NCG Committeeor our Board to identify candidates. The NCG Committee, upon approval by amajority of the members, may engage any outside resources deemed advisable.

 

 
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**Compensation**

 

The HRC Committee is comprisedexclusively of independent directors. The HRC Committee has a writtenmandate establishing the responsibilities of the HRC Committee. TheHRC Committee is authorized to engage outside resources if deemedadvisable and has the authority to retain and terminate any consultant used inthe evaluation of executive officer compensation.

 

The HRC Committee has twoprimary functions:

 

·                            to assistour Board in carrying out its responsibilities by reviewing compensation andhuman resources issues in support of the achievement of our business strategyand making recommendations to our Board as appropriate. The HRC Committeeis responsible for reviewing and approving corporate goals and objectivesrelevant to the President & Chief Executive Officer compensation,evaluating the President & Chief Executive Officer’s performanceagainst those goals and objectives and making recommendations to our Board withrespect to the President & Chief Executive Officer’scompensation; and

 

·                          to assistour Board in carrying out its fiduciary responsibilities in reviewing pensionissues and overseeing the investment management of our savings and investmentplans.

 

Our Board reviews the adequacy andform of the directors’ compensation to ensure that it realistically reflectsthe responsibilities and risks involved in being a director. The HRC Committeerecommends to our Board, for approval, the directors’ compensation and theremuneration for the non-executive Chair of our Board.

 

**Audit Committee**

 

For further information about our AuditCommittee and a copy of the Audit Committee Mandate, please see “AuditCommittee” in this annual information form and Appendix C to this annualinformation form, respectively.

 

**Reserves Committee**

 

One hundred percent of our reservesare evaluated by independent qualified reserves evaluators. We have a reservescommittee of our Board (the “Reserves Committee”), which is comprised solely ofindependent directors. The Reserves Committee reviews the qualifications andappointment of the independent qualified reserves evaluators, the proceduresfor providing information to the evaluators and the annual reserves estimatesprior to public disclosure.

 

**Safety, Environment and Responsibility Committee**

 

The SER Committee’s primaryfunction is to assist our Board in fulfilling its role in oversight andgovernance by reviewing, reporting and making recommendations to our Board onour policies, standards and practices with respect to corporate responsibility,including the environment, occupational health, safety and overall businessconduct and ethics.

 

**Board Assessments**

 

We have established appropriatepractices for the regular evaluation of the effectiveness of our Board, its Committeesand its members.

 

The NCG Committee isresponsible for assessing the effectiveness of our Board and Committees of ourBoard. As part of its process, the Chair of the NCG Committee meetsperiodically with each director to discuss the effectiveness of our Board, Committeesof our Board and each director. To assist the Chair in the review, eachdirector is required to complete an anonymous effectiveness questionnaireannually as well as periodic self and peer evaluation forms. Formal long-form effectivenessquestionnaires are expected to be 

 

 
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used every two years and moreabbreviated forms are expected to be used in alternating years. The assessmentswill include a review of an individual director’s knowledge, skills, experienceand meaningful contributions.

 

The Vice-Chair of the NCG Committeealso meets periodically with the Chair of the NCG Committee to discuss hiseffectiveness as the Chair of the Board, Chair of the NCG Committee and asa member of our Board. The NCG Committee assesses the adequacy ofinformation given to directors, communication between our Board and managementand the processes of our Board and its Committees.

 

The NCG Committee recommends toour Board any changes that would enhance the performance of our Board based onall of the NCG Committee’s assessments.

 

**Key Governance Documents**

 

Many policies and practices supportour corporate framework. The following documents constitute key components ofour corporate governance system and are available at ***www.cenovus.com***:

 
| ·                  Code of Business  Conduct & Ethics

·                  Corporate  Responsibility Policy

·                  Board of  Directors’ Mandate

·                  Chair of the  Board of Directors and Committee Chair General Guidelines

·                  President &  Chief Executive Officer General Guidelines

·                  Audit Committee  Mandate |   | ·                                                   | Human Resources and Compensation Committee Mandate |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|----------------------------------------------------------|----------------------------------------------------|
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | · | Nominating and Corporate Governance Committee Mandate    |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | · | Reserves Committee Mandate                               |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | · | Safety, Environment and Responsibility Committee Mandate |

 

 
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**DESCRIPTION OF CAPITAL STRUCTURE**

 

The following is a summary of therights, privileges, restrictions and conditions which are attached to theCommon Shares and the Preferred Shares. We are authorized to issue an unlimitednumber of Common Shares, an unlimited number of First Preferred Shares and anunlimited number of Second Preferred Shares. As of December 31, 2009,there were approximately 751 million Common Shares outstanding and noPreferred Shares have been issued.

 

**Common Shares**

 

The holders of Common Shares areentitled to receive dividends if, as and when declared by our Board. Theholders of Common Shares are entitled to receive notice of and to attend all meetingsof shareholders and are entitled to one vote per Common Share held at all suchmeetings. In the event of the liquidation, dissolution or winding up or otherdistribution of our assets among our shareholders for the purpose of winding upour affairs, the holders of Common Shares will be entitled to participaterateably in any distribution of our assets.

 

We have a Shareholder Rights Planthat was adopted to ensure, to the extent possible, that all our shareholdersare treated fairly in connection with any take-over bid for us. The ShareholderRights Plan creates a right that attaches to each issued Common Share. Untilthe separation time, which typically occurs at the time of an unsolicitedtake-over bid, whereby a person acquires or attempts to acquire 20 percentor more of our Common Shares, the rights are not separable from the CommonShares, are not exercisable and no separate rights certificates are issued.Each right entitles the holder, other than the 20 percent acquiror, fromand after the separation time (unless delayed by our Board) and before certainexpiration times, to acquire Common Shares at 50 percent of the marketprice at the time of exercise. The Shareholder Rights Plan must be reconfirmedby our shareholders at our annual shareholder meeting to be held in 2012 andevery third annual shareholder meeting thereafter until its expiry.

 

**Preferred Shares**

 

Preferred Shares may be issued inone or more series. Our Board may determine the designation, rights,privileges, restrictions and conditions attached to each series of PreferredShares before the issue of such series. Holders of Preferred Shares are notentitled to vote at any meeting of our shareholders, but may be entitled tovote if we fail to pay dividends on that series of Preferred Shares. The FirstPreferred Shares are entitled to priority over the Second Preferred Shares andthe Common Shares with respect to the payment of dividends and the distributionof our assets in the event of any liquidation, dissolution or winding up of ouraffairs. Our Board is restricted from issuing First Preferred Shares or SecondPreferred Shares if by doing so the aggregate amount payable to holders of eachsuch class of shares as a return of capital in the event of liquidation,dissolution or winding up or any other distribution of our assets among ourshareholders for the purpose of winding up our affairs would exceedC$500 million.

 

**Employee Stock Option Plan**

 

Our employee stock option plan(“ESOP”) was approved by shareholders in connection with the Arrangement. Thepurpose of the ESOP is to provide eligible employees with an incentive toachieve the longer-term objectives of Cenovus; to give suitable recognition tothe ability and industry of such persons who contribute materially to thesuccess of Cenovus; and to attract and retain in the employ of Cenovus or anyof our subsidiaries, persons of experience and ability by providing them withthe opportunity to acquire an increased proprietary interest in Cenovus.Non-employee directors of Cenovus are not entitled to receive Cenovus Optionsunder the ESOP.

 

The ESOP is administered by the HRC Committee.The HRC Committee has the authority to interpret the ESOP and any optiongranted thereunder and the discretion to attach TSARs to 

 

 
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the options. The following is asummary of the principal terms of the ESOP. Further information relating to theCenovus Replacement Options is also set out under the heading “Statement ofExecutive Compensation – Compensation Discussion and Analysis – The Elements ofour Compensation Program – Long-Term Incentive Program – Replacement StockOptions”.

 

***Common Shares Reserved***

 

A maximum of 64 million CommonShares have been reserved for issuance under the ESOP, representingapproximately 8.52 percent of the total number of outstanding CommonShares as at December 31, 2009. There were 39,603,522 Cenovus Optionsoutstanding under the ESOP and 24,361,222 Cenovus Options available for grant,representing approximately 5.27 percent and 3.24 percent,respectively, of the total number of outstanding Common Shares as atDecember 31, 2009. Any Common Share subject to a Cenovus Option thatexpires or terminates without having been fully exercised may be made thesubject of a further option.

 

***Grant of Options, ExercisePrice, Vesting and Expiry***

 

Cenovus Options may be granted fromtime to time to eligible employees of Cenovus and our subsidiaries. Subject toregulatory requirements, the terms, conditions and limitations of CenovusOptions granted under the ESOP will be determined by the HRC Committee andset out in an option agreement to be entered into effective as at the time ofthe grant.

 

The number of Common Shares reservedfor issuance at any time pursuant to Cenovus Options granted to insiders (assuch term is defined in the TSX Company Manual) under the ESOP, and all othersecurity-based compensation arrangements of Cenovus, shall not exceed tenpercent of the number of Common Shares then outstanding, calculated on anon-diluted basis, and the aggregate number of Common Shares issued to insiderspursuant to Cenovus Options, and all other security-based compensationarrangements of Cenovus, within any one year period, shall not exceed tenpercent of the number of the Common Shares outstanding, calculated on anon-diluted basis.

 

Except in respect of the CenovusReplacement Options, the exercise price of a Cenovus Option will not be lessthan the market price of the Common Shares at the grant date, calculated as theclosing price of the Common Shares on the TSX on the last trading day precedingthe date on which the option agreement granting the option is made, or, if theCommon Shares shall not have traded that day, on the next preceding day onwhich Common Shares were traded. See “Statement of Executive Compensation –Compensation Discussion and Analysis – The Elements of our Compensation Program– Long-Term Incentive Program – Replacement Stock Options”.

 

The HRC Committee has the rightto determine at the time of grant that a particular option will be exercisablein whole or in part on different dates or for reasons other than the passage oftime. Each Cenovus Option (unless sooner terminated in accordance with theterms, conditions and limitations of the option) shall be exercisable duringsuch period, not exceeding sevenyears from the date the option was granted as the HRC Committee maydetermine. Prior to Board approval onFebruary 9, 2010 of an amendment to the ESOP, options could be granted fora period not exceeding five years from the date of grant. Shareholder approvalwill not be sought for this amendment because it was approved in accordancewith the specific amendment provision in the ESOP and does not requireshareholder approval. Cenovus ReplacementOptions have a term of fiveyears. Cenovus Options generally vest 30 percent on the first anniversary,30 percent on the second anniversary and an additional 40 percent onthe third anniversary of the grant, and, in certain cases, subject to thesatisfaction of certain performance conditions.

 

***Performance VestingCriteria***

 

A portion of the Cenovus Optionsthat will be granted may be performance-based and may vest not only upon thepassage of time, but also upon the achievement of a prescribed 

 

 
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performance measure, which Cenovushas currently determined to be a recycle ratio. For more detailed informationconcerning the performance vesting criteria, see “Statement of ExecutiveCompensation – Compensation Discussion and Analysis – The Elements of ourCompensation Program – Long-Term Incentive Program”.

 

Two-thirds of the CenovusReplacement Options granted in connection with the Arrangement are also subjectto additional vesting requirements dependent upon a recycle ratio. See“Statement of Executive Compensation – Compensation Discussion and Analysis –The Elements of our Compensation Program – Long-Term Incentive Program –Replacement Stock Options”.

 

***TSARs***

 

All Cenovus Replacement Options haveassociated TSARs which entitle the optionholder to surrender the right toexercise his or her option to purchase a specified number of Common Shares andto receive cash or Common Shares (at Cenovus’s discretion) in an amount equalto the excess of the closing price of the Common Shares on the TSX on the lasttrading day preceding the date of exercise of the TSAR, over the exercise pricefor the Cenovus Option, multiplied by the number of optioned Common Sharessurrendered. Where a TSAR is exercised, the right to the underlying CommonShare is forfeited and such number of Common Shares are returned to the CommonShares reserved and available for new option grants. Cenovus Options that maybe granted in the future will also have associated TSARs.

 

***Non-Assignable and NoRights as a Shareholder***

 

A Cenovus Option may be exercisedonly by the optionholder and will not be assignable, except on death. Anoptionholder only has rights as a shareholder of Cenovus with respect to CommonShares that the optionholder has acquired through exercise of a Cenovus Optionor through the holding of Common Shares otherwise acquired. Nothing in the ESOPor in any option grant agreement confers or will confer on any optionholder anyright to remain as an employee of Cenovus or any of our subsidiaries.

 

***Adjustments***

 

Adjustments will be made to theexercise price of a Cenovus Option, the number of Common Shares delivered to anoptionholder upon exercise of an option and the maximum number of Common Sharesthat may at any time be reserved for issuance pursuant to options granted underthe ESOP in certain circumstances, such as a stock dividend, split,recapitalization, merger, consolidation, combination or exchange of Common Sharesor other similar corporate change.

 

***Blackout Period***

 

If the exercise period of a CenovusOption expires during, or within ten business days following, a period whenoption exercising is prohibited by Cenovus (the “Blackout Period”), then theexercise period of such option will be extended to the date which is tenbusiness days after the last day of the Blackout Period (the “BlackoutExtension Period”), after which time such option shall expire and terminate.

 

***Amendments***

 

The Board may, at any time and fromtime to time, amend, suspend, discontinue or terminate the ESOP in whole or inpart; provided, however, no such amendment, suspension, discontinuance ortermination may, without the consent of any optionholder, adversely alter orimpair the rights under any Cenovus Option previously granted. Any amendment tobe made to the ESOP or a Cenovus Option under the ESOP is subject to the priorapproval of the TSX. The Board has the power and authority to approveamendments relating to the ESOP or a specific option without further approvalof the shareholders of Cenovus, examples of which include, but are not limitedto:

 

 
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| (i)                                                                                  | extending or, in the event of a  change in control, retirement, death or disability, accelerating the terms of  vesting applicable to any Cenovus Option or group of Cenovus Options; |
|--------------------------------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                 |                                                                                                                                                                                  |
| (ii)                                                                                 | altering the terms and conditions  of vesting applicable to any Cenovus Option or group of Cenovus Options;                                                                           |
|                                                                                 |                                                                                                                                                                                  |
| (iii)                                                                                | changing the termination  provisions of the ESOP or any Cenovus Option, provided that the change does  not provide for an extension beyond the original expiry date of such option;   |
|                                                                                 |                                                                                                                                                                                  |
| (iv)                                                                                 | accelerating the expiry date in  respect of a Cenovus Option;                                                                                                                         |
|                                                                                 |                                                                                                                                                                                  |
| (v)                                                                                  | determining the adjustment  provisions pursuant to the ESOP. See “Adjustments” above;                                                                                       |
|                                                                                 |                                                                                                                                                                                  |
| (vi)                                                                                 | amending the definitions contained  within the ESOP and other amendments of a “housekeeping” nature; and                                                                    |
|                                                                                 |                                                                                                                                                                                  |
| (vii)                                                                                | amending or modifying the  mechanics of exercise of a Cenovus Option or TSAR.                                                                                                         |
|                                                                                 |                                                                                                                                                                                  |
| Approval  by shareholders of Cenovus will be required for amendments that relate to: |
|                                                                                 |                                                                                                                                                                                  |
| (i)                                                                                  | accelerating the terms of vesting  applicable to any Cenovus Option or group of Cenovus Options other than in  the event of a change in control, retirement, death or disability;     |
|                                                                                 |                                                                                                                                                                                  |
| (ii)                                                                                 | any increase in the number of  shares reserved for issuance under the ESOP;                                                                                                           |
|                                                                                 |                                                                                                                                                                                  |
| (iii)                                                                                | any reduction in the grant price  or cancellation and reissue of Cenovus Options;                                                                                                     |
|                                                                                 |                                                                                                                                                                                  |
| (iv)                                                                                 | any extension of the term of a  Cenovus Option beyond the original expiry date, except as permitted under the  Blackout Extension Period;                                             |
|                                                                                 |                                                                                                                                                                                  |
| (v)                                                                                  | any increase to the length of the  Blackout Extension Period;                                                                                                                         |
|                                                                                 |                                                                                                                                                                                  |
| (vi)                                                                                 | the inclusion of non-employee  directors, on a discretionary basis, as eligible participants;                                                                                         |
|                                                                                 |                                                                                                                                                                                  |
| (vii)                                                                                | any allowance for the  transferability or assignability of Cenovus Options other than for estate  settlement purposes;                                                                |
|                                                                                 |                                                                                                                                                                                  |
| (viii)                                                                               | amendments to the specific  amendment provision of the ESOP; and                                                                                                                      |
|                                                                                 |                                                                                                                                                                                  |
| (ix)                                                                                 | amendments required to be approved  by shareholders of Cenovus under applicable law (including, without  limitation, the rules, regulations and policies of the TSX).                 |

 

 
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**SECURITIES AUTHORIZED FOR ISSUANCE UNDEREQUITY COMPENSATION PLANS**

 

Our ESOP is the only compensationplan under which our equity securities have been authorized for issuance. As ofDecember 31, 2009, there were an aggregate of 39,603,522 optionsoutstanding under the ESOP, the details of which are as follows:

 
| **Plan Category**                                                  | **Number of  securities to be  issued upon  exercise of  outstanding  options** | **Weighted-average  exercise price of  outstanding  options** | **Number of securities  remaining available  for future issuance  under equity  compensation plans  (excluding securities  reflected in column  (a))** |
|--------------------------------------------------------------------|---------------------------------------------------------------------------------|---------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                               | (a)                                                                             | (b)                                                           | (c)                                                                                                                                                    |
| Equity compensation plans approved  by securityholders — ESOP | 39,603,522                                                                      | $27.19                                                        | 24,361,222                                                                                                                                             |
| Equity compensation plans not  approved by securityholders         | -                                                                               | -                                                             | -                                                                                                                                                      |
| Total                                                              | 39,603,522                                                                      | $27.19                                                        | 24,361,222                                                                                                                                             |

 

**DIVIDENDS**

 

The declaration of dividends is atthe sole discretion of our Board and is considered quarterly.

 

In the fourth quarter of 2009, wepaid a dividend of $0.20 per Common Share. Our Board has established a quarterlydividend of C$0.20 per Common Share. A first quarter dividend of C$0.20 wasdeclared payable on March 31, 2010 to holders of Common Shares of recordon March 15, 2010.

 

**MARKET FOR SECURITIES**

 

All of the outstanding Common Sharesare listed and posted for trading on the TSX and the NYSE under the symbol CVE.The following table outlines the share price trading range and volume of sharestraded by month in 2009.

 
|                    | **TSX**                                | **NYSE**   |
|-------------------------|----------------------------------------|------------|
|                    |   Share  Price Trading Range |       |   Share Price Trading  Range |   |
|                    | High                                   | Low        | Close | Share  Volume | High | Low | Close | Share  Volume |
|                    | (C$ per  share)                   | (millions) | ($ per  share) | (millions) |
| **  2009**    |                                   |       |   |   |   |   |   |   |
|   December(1) | 27.18                                  | 24.68      | 26.50 | 59.0 | 25.70 | 23.37 | 25.20 | 24.5 |

**Note:**

(1)  The Common Shares began trading on the TSX onDecember 3, 2009 and on the NYSE on December 9, 2009.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 71 |
|-----------------------------------------------------------------------------------|----|

 

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**CREDIT RATINGS**

 

The following table outlines theratings and outlooks of Cenovus’s debt as of December 31, 2009:

 
|                                                  | **Standard & Poor’s**

**Ratings Services**

**(“S&P”)** | **Moody’s Investors**

**Service**

**(“Moody’s”)** | **DBRS Limited**

**(“DBRS”)** |
|-------------------------------------------------------|--------------------------------------------------------------------------------------|-------------------------------------------------------------------------|------------------------------------------|
| Senior unsecured

   Long-Term Rating  | BBB+/Stable                                                                          | Baa2/Stable                                                             | A  (low)/Stable                          |
| Commercial Paper

   Short-Term Rating | A-1(Low)/Stable                                                                      | P-2/Stable                                                              | R-1  (low)/Stable                        |

 

Credit ratings are intended toprovide an independent measure of the credit quality of an issue of securities.The credit ratings assigned by the rating agencies are not recommendations topurchase, hold or sell the securities nor do the ratings comment on marketprice or suitability for a particular investor. A rating may not remain ineffect for any given period of time and may be revised or withdrawn entirely bya rating agency in the future if, in its judgment, circumstances so warrant.

 

S&P’s long-term credit ratingsare on a rating scale that ranges from AAA to D, which represents the rangefrom highest to lowest quality of such securities rated. A rating of BBB+ byS&P is within the fourth highest of ten categories and indicates that theobligation exhibits adequate protection parameters. However, adverse economicconditions or changing circumstances are more likely to lead to a weakenedcapacity of the obligor to meet its financial commitment on the obligation. Theaddition of a plus (+) or minus (-) designation after a rating indicates therelative standing within the major rating categories. S&P’s Canadiancommercial paper ratings scale ranges from A-1(High) to D, which represents therange from highest to lowest quality. A rating of A-1(Low) is the third highestof eight categories and indicates that the obligor has satisfactory capacity tomeet its financial commitments. A ratings outlook gives the potential directionof a short- or long-term rating and the “stable” designation indicates that arating is not likely to change.

 

Moody’s long-term credit ratings areon a rating scale that ranges from Aaa to C, which represents the range fromhighest to lowest quality of such securities rated. A rating of Baa2 by Moody’sis within the fourth highest of nine categories and is assigned to debtsecurities which are considered medium-grade (i.e., they are subject tomoderate credit risk). Such debt securities may possess certain speculativecharacteristics. The addition of a 1, 2 or 3 modifier after a rating indicatesthe relative standing within a particular rating category. The modifier 1indicates that the issue ranks in the higher end of its generic ratingcategory, the modifier 2 indicates a mid-range ranking and themodifier 3 indicates a ranking in the lower end of that generic ratingcategory. Moody’s short-term credit ratings are on a scale that ranges from P-1(highest quality) to NP (lowest quality). A rating of P-2 is the second highestof four categories and indicates that the issuer has a strong ability to repayshort-term debt obligations.

 

DBRS’ long-term credit ratings areon a rating scale that ranges from AAA to D, which represents the range fromhighest to lowest quality of such securities rated. A rating of A(low) by DBRSis within the third highest of ten categories and is assigned to debtsecurities considered to be of satisfactory credit quality. Protection ofinterest and principal is substantial, but the degree of strength is less thanthat of higher rated securities. Entities in the A category are considered tobe more susceptible to adverse economic conditions and have greater cyclicaltendencies than higher-rated securities. The assignment of a “(high)” or“(low)” modifier within each rating category indicates relative standing withinsuch category. DBRS’ short-term credit ratings are on a scale ranging from R-1(high) to D, which represents the range from highest to lowest quality. Arating of R-1(low) is the third highest of ten categories and indicates thatthe short-term debt is of satisfactory credit 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 72 |
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quality. The overall strength andoutlook for key liquidity, debt, and profitability ratios is not normally asfavorable as with higher rating categories, but these considerations are stillrespectable. Any qualifying negative factors that exist are consideredmanageable, and the entity is normally of sufficient size to have someinfluence in the industry.

 

**PRIOR SALES**

 

**Debt Securities**

 

On September 18, 2009, apredecessor entity of Cenovus completed, in three tranches, a $3.5 billionprivate offering of debt securities (comprised of the 2014 Notes, 2019 Notesand 2039 Notes) which are exempt from the registration requirements of the U.S.Securities Act under Rule 144A and Regulation S. The net proceeds ofthe Cenovus Note Offering were placed into an escrow account pending thecompletion of the Arrangement. Upon completion of the Arrangement, the netproceeds, together with other pre-funded amounts, were released from escrow andwere applied to repay all of the amounts outstanding under the Demand Note.

 

The Notes are our direct, unsecuredand unsubordinated obligations and rank equally and rateably with all of ourother existing and future unsecured and unsubordinated indebtedness. The Notesare structurally subordinate to all existing and future indebtedness andliabilities of any of our corporate and partnership subsidiaries.

 

We have agreed to use ourcommercially reasonable efforts to cause a registration statement with respectto an offer to exchange the Cenovus Notes for a new issue of notes registeredunder the U.S. Securities Act to be declared effective no later thanSeptember 18, 2010.

 

**RISK FACTORS**

 

If any event arises from the riskfactors set forth below, our business, prospects, financial condition, resultsof operation or cash flows and, in some cases, our reputation could bematerially adversely affected.

 

**Risks relating to the Arrangement**

 

***As a result of theArrangement, any financing that we may require will be obtained on a standalone basis.***

 

As a result of the Arrangement, weare independent of EnCana and any financing that we may require in the futurewill be obtained by us on a stand alone basis. In addition, our credit ratingsare determined independently of, and without reference to, the historical orcurrent ratings of EnCana. Differences in credit ratings affect the interestrate charged on financings, as well as the amounts of indebtedness, types offinancing structures and debt markets that may be available to us.

 

As a result, we may not be able tosecure adequate debt or equity financing or otherwise raise the capital werequire on the same terms as EnCana (as it existed historically or existscurrently), desirable terms or at all.

 

***We may be unable to makethe changes necessary to operate as an independent entity and may incur greatercosts.***

 

As a result of the Arrangement, weseparated from the other businesses of EnCana and such separation maymaterially adversely affect us. We may not be able to implement successfullythe changes necessary to operate independently. We may incur additional costsrelating to operating independently that could materially affect our cash flowand results of operations. We require EnCana to provide us with certainservices (including, but not limited to, information technology services) on atransitional basis. We may, as a result, be dependent on such services until weare able to provide our own.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 73 |
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*** ***

***The historical financialinformation of our assets may not be representative of our results as anindependent entity, and, therefore, may not be reliable as an indicator of ourhistorical or future results.***

 

Our assets were integrated withinthe business units of EnCana for 11 of the 12 months of 2009; consequently, ourfinancial information has been derived, in substantial part, from theconsolidated financial statements and accounting records of EnCana and reflectcertain assumptions and allocations. Our financial position, results ofoperations and cash flows could differ from those that would have resulted hadwe operated autonomously or as an entity independent of EnCana for all offiscal 2009.

 

***Our separate operatinghistory as a stand alone entity.***

 

We became an independent publiccompany on November 30, 2009. The operating history of EnCana in respectof our assets cannot be regarded as our operating history. Our ability to raisecapital, satisfy our obligations and provide a return to our shareholders willbe dependent upon our future performance. We will not be able to rely on thecapital resources and cash flows of EnCana. Our future operating results and performancemay be materially different than those we would have achieved had we beenoperating as part of EnCana.

 

**Risks relating to our Business**

 

***A substantial or extendeddecline in crude oil, natural gas and refined products prices could have amaterial adverse effect on us.***

 

Our financial performance andcondition are substantially dependent on the prevailing prices of crude oil,natural gas and refined products. Fluctuations in crude oil, natural gas andrefined products prices could have an adverse effect on our operations andfinancial condition, the value and amount of our proved reserves and the valueof our refining assets. Prices for crude oil, natural gas and refined productsfluctuate in response to changes in the supply of and demand for crude oil,natural gas and refined products, market uncertainty and a variety ofadditional factors beyond our control. Crude oil prices are determined byinternational supply and demand. Factors which affect crude oil prices includethe actions of the Organization of Petroleum Exporting Countries, worldeconomic conditions, government regulation, political stability in the MiddleEast and elsewhere, the foreign supply of crude oil, the price of foreignimports, the availability of alternate fuel sources and weather conditions.Natural gas prices realized by us are affected primarily by North Americansupply and demand, weather conditions and by prices of alternate sources ofenergy (including refined product and imported liquefied natural gas). Ourrefined products margins are impacted by, among other things: marketcompetitiveness, the cost of inputs and fluctuations in the supply and demandfor refined products. Any substantial or extended decline in the prices ofcrude oil, natural gas or refined products could result in a delay orcancellation of existing or future drilling, development or constructionprograms or curtailment in production at some properties or could result inunutilized long-term transportation commitments and low utilization levels atthe refineries, all of which could have an adverse effect on our revenues,profitability and cash flows.

 

The market prices for heavy oil arelower than the established market indices for light and medium grades of oil,due principally to the higher transportation and refining costs associated withheavy oil. As well, bitumen prices are lower still than heavy oil prices due tothe cost of diluent blending. Also, the market for heavy oil is more limitedthan for light and medium grades, making it more susceptible to supply anddemand changes. Future price differentials are uncertain and any increase inthe heavy oil differentials could have an adverse effect on our business.

 

We will conduct an annual assessmentof the carrying value of our assets in accordance with Canadian GAAP. If crudeoil and natural gas prices decline, the carrying value of our assets could besubject to financial downward revisions and our earnings could be adverselyaffected.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 74 |
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***Our ability to operate andcomplete projects is dependent on certain factors outside of our control.***

 

Our ability to operate, generatesufficient cash flows and complete projects will depend upon numerous factorsbeyond our control. In addition to commodity prices and continued market demandfor our products, these non-controllable factors include, but are not limitedto: general business and market conditions; economic recessions and financialmarket turmoil; the ability to secure and maintain cost effective financing forour commitments; environmental and regulatory matters; unexpected cost increases;royalties; taxes; the availability of drilling and other equipment; the abilityto access lands; weather; the availability of processing capacity; theavailability and proximity of pipeline capacity; the availability of diluentsto transport crude oil; technology failures; accidents; the availability ofskilled labour; and reservoir quality.

 

Current market conditions arechallenging with the global recession negatively impacting commodity prices aswell as access to credit and capital markets. These conditions impact ourcustomers and suppliers and may alter our spending and operating plans. Theremay be unexpected business impacts from this market uncertainty.

 

Our downstream operations will besensitive to refined products margins. Margin volatility is impacted bynumerous conditions including: fluctuations in the supply and demand forrefined products; market competitiveness; the costs of crude oil; labour;maintenance; electricity; chemicals and other inputs; unplanned productiondisruptions due to equipment failure; power disruptions and other factorsincluding weather. It is expected that all of these and other factors willcontinue to impact downstream margins for the foreseeable future. As a result,it can be reasonably expected that downstream results will fluctuate over timeand from period to period.

 

We will undertake a variety ofprojects including exploration and development projects and the construction orexpansion of facilities, refineries and pipelines. Project delays may delayexpected revenues and project cost overruns could make projects uneconomic.

 

All of our operations are subject toregulation and intervention by governments that can affect or prohibit thedrilling, completion and tie-in of wells, production, the construction orexpansion of facilities and refineries and the operation and abandonment offields. Contract rights can be cancelled or expropriated. Changes to governmentregulation could impact our existing and planned projects.

 

Certain of our operations require usto obtain certain approvals from various regulatory authorities and there canbe no assurance that we will be able to obtain all necessary licenses, permitsand other approvals that may be required to carry out certain exploration anddevelopment activities on our properties. In addition, obtaining certainapprovals from regulatory authorities can involve, among other things,stakeholder consultation, environmental impact assessments and public hearings.Regulatory approvals that are obtained may also be subject to the satisfactionof certain conditions, including, but not limited to, security depositobligations, regulatory oversight of projects by third parties, habitatassessments and other commitments or obligations. Failure to obtain applicableregulatory approvals or satisfy any of the conditions thereto on a timely basison satisfactory terms could result in delays, abandonment or restructuring ofprojects and increased costs, all of which could have a material adverse effecton our business, financial conditions, results of operations and cash flow.

 

***Our crude oil and naturalgas reserves data and future net revenue estimates are uncertain.***

 

There are numerous uncertaintiesinherent in estimating quantities of crude oil and natural gas reserves, includingmany factors beyond our control. The reserves data in this annual informationform represent estimates only. In general, estimates of economicallyrecoverable crude oil and natural gas reserves and the future net cash flowstherefrom are based upon a number of variable factors and assumptions, such asproduct prices, future 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 75 |
|-----------------------------------------------------------------------------------|----|

 

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operating and capital costs,historical production from the properties and the assumed effects of regulationby governmental agencies, including with respect to royalty payments, all ofwhich may vary considerably from actual results. All such estimates are to somedegree uncertain and classifications of reserves are only attempts to definethe degree of uncertainty involved. For those reasons, estimates of theeconomically recoverable bitumen, crude oil and natural gas reservesattributable to any particular group of properties, classification of suchreserves based on risk of recovery and estimates of future net revenuesexpected therefrom, prepared by different engineers or by the same engineers atdifferent times, may vary substantially. Our actual production, revenues, taxesand development and operating expenditures with respect to our reserves mayvary from such estimates and such variances could be material.

 

Estimates with respect to reservesthat may be developed and produced in the future are often based uponvolumetric calculations and upon analogy to similar types of reserves, ratherthan upon actual production history. Estimates based on these methods generallyare less reliable than those based on actual production history. Subsequentevaluation of the same reserves based upon production history will result invariations, which may be material, in the estimated reserves.

 

***Our hedging activitiescould result in realized and unrealized losses.***

 

The nature of our operations resultsin exposure to fluctuations in commodity prices, interest rates and foreignexchange rates. We will monitor our exposure to such fluctuations and, where wedeem it appropriate, utilize derivative financial instruments and physicaldelivery contracts to help mitigate the potential impact of declines in crudeoil, natural gas and refined product prices, changes in interest rates andforeign exchange rates. Under Canadian GAAP, derivative instruments that do notqualify as hedges, or are not designated as hedges, are marked-to-market withchanges in fair value recognized in current period net earnings. Theutilization of derivative financial instruments may therefore introducesignificant volatility into our reported net earnings.

 

The terms of our various hedgingagreements, if any, may limit the benefit to us of commodity price increases orchanges in interest rates and foreign exchange rates. We may also sufferfinancial loss because of hedging arrangements if:

 

·                                          we areunable to produce oil, natural gas or refined products to fulfill deliveryobligations; or

 

·                                          counterpartiesto our hedging agreements are unable to fulfill their obligations under thehedging agreements.

 

***Our ability to secure andmaintain cost effective financing for our capital and other commitments.***

 

The nature of our operations willrequire significant capital commitments; consequently, failure to achievetimely and cost effective financing could have a negative impact on our futureplans. Unpredictable financial markets and associated credit impacts may impedeour ability to secure and maintain cost effective financing and limit ourability to achieve timely access to capital markets.

 

***Our business is subject toenvironmental legislation in all jurisdictions in which we operate and anychanges in such legislation could negatively affect our results of operations.***

 

All phases of the crude oil, naturalgas and refining businesses are subject to environmental regulation pursuant toa variety of Canadian, U.S. and other federal, provincial, territorial, stateand municipal laws and regulations (collectively, “environmental legislation”).

 

Environmental legislation requiresthat wells, facility sites, refineries and other properties associated with ouroperations be constructed, operated, maintained, abandoned and reclaimed to thesatisfaction of applicable regulatory authorities. In addition, certain types 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 76 |
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of operations, including explorationand development projects and changes to certain existing projects, may requirethe submission and approval of environmental impact assessments or permitapplications. Environmental legislation imposes, among other things,restrictions, liabilities and obligations in connection with the generation,handling, use, storage, transportation, treatment and disposal of hazardoussubstances and waste and in connection with spills, releases and emissions ofvarious substances to the environment. It also imposes restrictions,liabilities and obligations in connection with the management of fresh orpotable water sources that are being used, or whose use is contemplated, inconnection with oil and gas operations. Compliance with environmentallegislation can require significant expenditures, including expenditures forclean up costs and damages arising out of contaminated properties and failureto comply with environmental legislation may result in the imposition of finesand penalties. Although it is not expected that the costs of complying withenvironmental legislation will have a material adverse effect on our financialcondition or results of operations, no assurance can be made that the costs ofcomplying with environmental legislation in the future will not have such aneffect.

 

Various federal, provincial andstate governments have announced intentions to regulate greenhouse gasemissions and other air pollutants and a number of legislative and regulatorymeasures to address greenhouse gas emissions are in various phases of review,discussion or implementation in the United States and Canada. These includeproposed federal legislation and state actions in the United States to developstatewide or regional programs, each of which could impose reductions ingreenhouse gas emissions.

 

Adverse impacts to our business ifcomprehensive greenhouse gas legislation is enacted in any jurisdiction inwhich we operate, may include, among other things, increased compliance costs,permitting delays, substantial costs to generate or purchase emission creditsor allowances adding costs to the products we produce, and reduced demand forcrude oil and certain refined products. In particular, some of the climatechange legislation being contemplated in the U.S. would require refiners toobtain emission allowances for emissions of greenhouse gases, including CO2 based on the carbon content of their fuels. Ifthis approach was enacted into law, this could have a material impact on thecost structure of refined petroleum products.

 

Beyond existing legal requirements,the extent and magnitude of any adverse impacts of any of these additionalprograms cannot be reliably or accurately estimated at this time becausespecific legislative and regulatory requirements have not been finalized anduncertainty exists with respect to the additional measures being considered andthe time frames for compliance.

 

***If we fail to acquire orfind additional crude oil and natural gas reserves, our reserves and productionwill decline materially from their current levels.***

 

Our future crude oil and natural gasreserves and production, and therefore our cash flows, are highly dependentupon our success in exploiting our current resource base and acquiring,discovering or developing additional reserves. Without reserves additionsthrough exploration, acquisition or development activities, our reserves and productionwill decline over time as reserves are depleted. The business of exploring for,developing or acquiring reserves is capital intensive. To the extent cash fromoperating activities is insufficient and external sources of capital becomelimited, our ability to make the necessary capital investments to maintain andexpand our crude oil and natural gas reserves will be impaired. In addition,there can be no certainty that we will be able to find and develop or acquireadditional reserves to replace production at acceptable costs.

 

***Our operations are subjectto the risk of business interruption and casualty losses.***

 

Our business is subject to all ofthe operating risks normally associated with the exploration for, developmentof and production of crude oil and natural gas and the operation of refiningfacilities. These risks include, but are not limited to, blowouts, explosions,fire, gaseous leaks, migration of harmful substances and crude oil and refinedproducts spills, acts of 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 77 |
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vandalism and terrorism, any ofwhich could cause personal injury, result in damage to, or destruction of,crude oil and natural gas wells or formations or production facilities orrefineries and other property, equipment and the environment, as well asinterrupt operations. In addition, all of our operations are subject to all ofthe risks normally incident to the transportation, processing, storing,refining and marketing of crude oil, natural gas and other related products,drilling and completion of crude oil and natural gas wells, and the operation anddevelopment of crude oil and natural gas properties, including, among others,encountering unexpected formations or pressures, premature declines ofreservoir pressure or productivity, blowouts, equipment failures and otheraccidents, sour gas releases, uncontrollable flows of crude oil, natural gas orwell fluids, adverse weather conditions, pollution and other environmentalrisks.

 

The occurrence of a significantevent against which we are not fully insured could have a material adverseeffect on our financial position.

 

***We do not operate all ofour properties and assets.***

 

Other companies operate a portion ofthe assets in which we have interests. We will have limited ability to exerciseinfluence over operations of these assets or their associated costs. Ourdependence on the operator and other working interest owners for theseproperties and assets and our limited ability to influence operations andassociated costs could materially adversely affect our financial performance.The success and timing of our activities on assets operated by others thereforewill depend upon a number of factors that are outside of our control,including: timing and amount of capital expenditures; timing and amount ofoperating and maintenance expenditures; the operator’s expertise and financialresources; approval of other participants; selection of technology; and riskmanagement practices.

 

All of our downstream operations areoperated by ConocoPhillips. The success of our downstream operations isdependant on the ability of ConocoPhillips to successfully operate thisbusiness and maintain the operations of the refineries.

 

***We are exposed to risksassociated with the use of current technology, and the pursuit of newtechnology, which could negatively affect our results of operations.***

 

Current SAGD technologies forenhanced recovery of heavy oil are energy intensive, requiring significantconsumption of natural gas and other fuels in the production of steam that isused in the recovery process. The amount of steam required in the productionprocess can also vary and affect costs. The performance of the reservoir canalso affect the timing and levels of production using this technology. A largeincrease in recovery costs could cause certain projects that rely on SAGDtechnology to become uneconomical, which could have a negative effect on ourresults of operations.

 

There are risks associated withgrowth and other capital projects that rely largely or partly on newtechnologies and the incorporation of such technologies into new or existingoperations. The success of projects incorporating new technologies cannot beassured.

 

***There are a number ofrisks particular to oil recovery operations that could have a material adverseimpact on us.***

 

Producing oil through enhancedrecovery methods and upgrading and refining heavy oil requires high levels ofinvestment and involves particular risks and uncertainties. Our oil operationsare susceptible to loss of production, slowdowns, shutdowns, or restrictions onour ability to produce higher value products due to the interdependence of ourcomponent systems. While there are virtually no finding costs associated withbitumen resources, delineation of the resources, the costs associated withproduction, including drilling wells for SAGD operations, and the costsassociated with upgrading heavy oil can entail significant capital outlays. Thecosts associated with oil production are largely fixed in the short-term and,as a result, operating costs per unit are largely dependent on levels of production.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 78 |
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***Fluctuations in exchangerates could affect expenses or result in realized and unrealized losses.***

 

Worldwide prices for crude oil,natural gas and refined products are set in U.S. dollars. However, many of ourexpenses outside of the U.S. will be denominated in Canadian dollars.Fluctuations in the exchange rate between the U.S. dollar and the Canadiandollar could impact our expenses and have an adverse effect on our financialperformance and condition.

 

***We may become subject toclaims by third parties.***

 

From time to time, we may be thesubject of litigation arising out of our operations. Claims under suchlitigation may be material or may be indeterminate and the outcome of suchlitigation may materially impact our financial condition or results ofoperations. We may be required to incur significant expenses or devotesignificant resources to defend ourself against any such litigation.

 

***We may be adverselyaffected by certain terms of the Separation Agreement.***

 

Pursuant to the SeparationAgreement, EnCana and Cenovus have each agreed to cooperate fully with eachother and our respective counsels in the investigation, prosecution, defenseand resolution of the Joint Litigation (as defined herein), which includes,without limitation, certain judicial actions to which EnCana is a partyrelating to the entitlement to CBM. The possible impacts and effects of suchagreement are uncertain. Our obligation to cooperate fully with EnCana and itscounsel in respect of the Joint Litigation and the limitation this may place onthe position that Cenovus may otherwise wish to take with respect to thesematters may have an adverse affect on Cenovus. The outcome of any of the JointLitigation matters cannot be predicted and may materially impact our financialcondition or results of operations. In addition, the existence of suchagreement and our obligations thereunder may have an affect on the manner inwhich we determine to conduct our business or operations until such time thatall of the Joint Litigation is resolved.

 

***We have certain post-Arrangementindemnification and other obligations under each of the Arrangement Agreementand Separation Agreement***

 

EnCana and Cenovus have agreed toindemnify each other for certain liabilities and obligations associated with,among other things, in the case of EnCana’s indemnity, the business and assetsretained by EnCana, and in the case of our indemnity, the Cenovus Businessesand the Cenovus Assets. At the present time, we cannot determine whether wewill have to indemnify EnCana for any substantial obligations under the termsof the Arrangement. We also cannot assure that if EnCana has to indemnifyCenovus and our affiliates for any substantial obligations, EnCana will be ableto satisfy such obligations.

 

In connection with the Arrangement,EnCana and Cenovus entered into the Arrangement Agreement which contains anumber of representations, warranties and covenants, including agreement byeach of the parties to indemnify and hold harmless each other against any losssuffered or incurred resulting from a breach of certain tax-related covenants.One of these covenants was that each party would not take any action, omit totake any action or enter into any transaction that could adversely impact theCanadian Tax Ruling or the U.S. Tax Ruling. With respect to Canadian incometaxation, there are a variety of transactions that the parties were or areprohibited from undertaking prior to and after the implementation of theArrangement. One of these is that no party is permitted to dispose of orexchange property having a fair market value greater than ten percent of thefair market value of its property, net of liabilities, or undergo anacquisition of control where such disposition or control acquisition is forCanadian tax purposes part of the “series of transactions or events” thatincludes the Arrangement, except in limited circumstances.

 

Under the Separation Agreement,(i) we have agreed to indemnify EnCana and its affiliates from and againstany liabilities associated with, among other things, the Cenovus Assets 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 79 |
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and Cenovus Businesses, whetherrelating to the period, or arising, prior to or after the Reorganization Time,and (ii) EnCana has agreed to indemnify us and our affiliates from andagainst any liabilities associated with, among other things, the assets ownedby EnCana or any affiliate of EnCana and the businesses carried on by EnCana orany affiliate of EnCana after the Reorganization Time, whether relating to theperiod, or arising, prior to or after the Reorganization Time.

 

Any indemnification claim against uspursuant to the provisions of the Arrangement Agreement or Separation Agreementcould have a material adverse effect.

 

***Our success is dependenton successful recruitment, retention and succession.***

 

Our success is dependent upon ourmanagement and the quality of our personnel. Failure to retain currentemployees or to attract and retain new employees with the necessary skillscould have a material adverse effect on our growth and profitability. Althoughthe demand for personnel has recently reduced, competition for key oil and gasprofessionals remains high.

 

***Our ability to operate isdependent upon a variety of information systems.***

 

We depend on a variety ofinformation systems to operate effectively. A failure of any one of theinformation systems or a failure among the systems could result in operationaldifficulties, damage or loss of data, productivity losses or result inunauthorized knowledge and use of information.

 

**Other Risk Factors**

 

A discussion of additional riskswhich may impact our business, prospects, financial condition, results ofoperation and cash flows, and in some cases our reputation, can be found in ourManagement’s Discussion and Analysis for the year ended December 31, 2009which is accessible on our SEDAR profile at ***www.sedar.com***and on EDGAR at ***www.sec.gov***.

 

**LEGAL PROCEEDINGS AND REGULATORY ACTIONS**

 

There are no legal proceedings towhich we are or were a party, or that any of our property is or was the subjectof, which is or was, or can be reasonably considered to be, material to us orany of our properties and we are not aware of any such legal proceedings thatare contemplated.

 

Since incorporation, there have notbeen any penalties or sanctions imposed against us by a court relating toprovincial and territorial securities legislation or by a securities regulatoryauthority, nor have there been any other penalties or sanctions imposed by acourt or regulatory body against us, and we have not entered into anysettlement agreements before a court relating to provincial and territorialsecurities legislation or with a securities regulatory authority.

 

**INTERESTS OF MANAGEMENT AND OTHERS IN MATERIALTRANSACTIONS**

 

None of our directors or executiveofficers or any person or company that beneficially owns, or controls ordirects, directly or indirectly, more than ten percent of any class or seriesof our outstanding voting securities, of which there are none that we areaware, or any associate or affiliate of any of the foregoing persons, in eachcase, as at the date of this annual information form, has or has had anymaterial interest, direct or indirect, in any past transaction or any proposedtransaction that has materially affected or is reasonably expected tomaterially affect us.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 80 |
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**INTERESTS OF EXPERTS**

 

Our independent auditors arePricewaterhouseCoopers LLP, Chartered Accountants, who have issued anindependent auditors’ report dated February 17, 2010 in respect of ourconsolidated financial statements as at December 31, 2009 andDecember 31, 2008 and for each of the years in the three year period endedDecember 31, 2009 and Cenovus’s internal control over financial reportingas at December 31, 2009. PricewaterhouseCoopers LLP has advised that theyare independent with respect to Cenovus within the meaning of the Rules ofProfessional Conduct of the Institute of Chartered Accountants of Alberta andthe rules of the SEC. Prior to November 30, 2009,PricewaterhouseCoopers LLP was the auditor of EnCana and, on November 30,2009, was appointed auditor of Cenovus.

 

Information relating to reserves inthis annual information form has been calculated by GLJ Petroleum ConsultantsLtd. and McDaniel & Associates Consultants Ltd. as independentqualified reserves evaluators. The principals of each of GLJ PetroleumConsultants Ltd. and McDaniel & Associates Consultants Ltd., in eachcase, as a group own beneficially, directly or indirectly, less than onepercent of any class of our securities.

 

**TRANSFER AGENTS AND REGISTRARS**

 
| In Canada:                                                                                                          | In the United States: |
|---------------------------------------------------------------------------------------------------------------------|-----------------------|
|                                                                                                                |                  |   |   |
| CIBC  Mellon Trust Company

P.O. Box  7010

Adelaide  Street Postal Station

Toronto,  Ontario M5C 2W9

Canada |                  | BNY Mellon  Shareowner Services

480  Washington Blvd.

Jersey  City, New Jersey 07310

U.S.A.

  |   |

 

Tel:1-866-332-8898

Website:

***www.cibcmellon.com/investorinquiry***

 

**MATERIAL CONTRACTS**

 

The only contracts that canreasonably be regarded as material to us, other than contracts entered into inthe ordinary course of business, are as follows:

 

(a)           ArrangementAgreement. The Arrangement Agreement provided for the implementation of thePlan of Arrangement pursuant to Section 192 of the CBCA and, among otherthings, certain representations, warranties and covenants of the parties andcertain indemnities among Cenovus and EnCana.

 

(b)           SeparationAgreement. In connection with the Arrangement, we entered into the SeparationAgreement and several ancillary agreements to complete the transfer of theCenovus Businesses to us. The Separation Agreement sets forth the agreement ofthe parties with respect to the indirect transfer of assets from EnCana to usand the indirect assumption of the Assumed Liabilities by us and certaintransitional arrangements governing the relationship between EnCana and usfollowing the Reorganization Time.

 

The SeparationAgreement allocates between EnCana and Cenovus responsibility and liability foroutstanding legal actions based on whether such legal actions relate primarilyto the Cenovus Businesses or the Cenovus Assets (on the one hand) or theretained businesses and assets of EnCana (on the other hand). With respect tooutstanding legal actions that affect both EnCana and us or unknown or futurelegal actions brought after the Reorganization Time, the Separation Agreementprovides that each party will be liable for its proportionate share of allcosts and liabilities arising out of or relating to such legal actions based onthe extent to which such 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 81 |
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legal actionsrelate to the Cenovus Businesses or the Cenovus Assets (in our case) or theretained businesses and assets (in the case of EnCana).

 

Pursuant to theSeparation Agreement, Cenovus and EnCana have agreed, in respect of certainlitigation matters, including, without limitation, certain judicial actionsrelating to CBM involving EnCana (collectively, the “Joint Litigation”), tocooperate fully with the other and its counsel in the investigation,prosecution, defense and resolution of such Joint Litigation. Subject tocertain exceptions contained within the Separation Agreement, EnCana hasexclusive authority and control over the investigation, prosecution, defenseand appeal of all Joint Litigation. See “Risk Factors” in this annualinformation form.

 

Under the terms ofthe Separation Agreement, we have generally agreed to indemnify EnCana and itsaffiliates from and against any liabilities associated with, among otherthings, the Cenovus Businesses or the Cenovus Assets, whether relating to the period,or arising, prior to or after the Reorganization Time. The Separation Agreementcontains a reciprocal indemnity under which EnCana generally agrees toindemnify us and our affiliates from and against any liabilities relating to,among other things, the businesses and assets retained by EnCana. Cenovus andEnCana will indemnify each other with respect to non-performance of ourrespective obligations under the Separation Agreement including the obligationnot to do anything after the Arrangement which could interfere with anytransactions outlined in the Canadian Tax Ruling and the U.S. Tax Ruling. See“Risk Factors”.

 

Other mattersgoverned by the Separation Agreement include responsibility for taxes, accessto books and records, confidentiality, insurance and dispute resolution.

 

(c)                                 NoteIndenture. On September 18, 2009, we issued the Notes, which were issuedand are governed under the terms of the Note Indenture.

 

Pursuant to theNote Indenture, the Notes:

 

(i)                                     are ourdirect unsecured and unsubordinated obligations ranking equally and ratably inright of payment with all of our other unsecured and unsubordinatedindebtedness;

 

(ii)                                  the 2014Notes bear interest to be paid semi-annually in arrears on March 15 andSeptember 15 of each year, commencing March 15, 2010; the 2019 Notesbear interest to be paid semi-annually in arrears on April 15 andOctober 15 of each year, commencing April 15, 2010; and the 2039Notes bear interest to be paid semi-annually in arrears on May 15 andNovember 15 of each year, commencing May 15, 2010; and

 

(iii)                               bearinterest on overdue principal, and overdue interest, at the rate otherwiseapplicable to the Notes.

 

Interest iscomputed on the basis of a 360-day year of twelve 30-day months. The interestperiod relating to an interest payment date shall be the period from but notincluding the preceding interest payment date to and including the relevantinterest payment date.

 

Payment of theprincipal, premium, if any, and interest on the Notes will be made in UnitedStates dollars.

 

We have agreed touse our commercially reasonable efforts to cause a registration statement withrespect to an offer to exchange the Notes for a new issue of notes registeredunder the U.S. Securities Act to be declared effective no later than September 18,2010.

 

Copies of these agreements may beinspected at our registered office located at #4000, 421 – 7 Avenue S.W.,Calgary, Alberta, Canada T2P 4K9 during normal business hours and are availableon our SEDAR profile at ***www.sedar.com***and on EDGAR at ***www.sec.gov***.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 82 |
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**PROMOTER**

 

Under applicable Canadian securitieslaws, EnCana was considered a promoter of Cenovus in that it took theinitiative in our founding for the purpose of implementing the Arrangement. Weacquired our assets from EnCana pursuant to the Arrangement, as described inthis annual information form. As consideration for the acquisition of ourassets pursuant to the Arrangement, we issued the Demand Note payable to EnCanain the aggregate amount of $3.5 billion. The value of the Demand Note wasdetermined through the equitable allocation of the pre-Arrangement value ofEnCana’s debt as determined by, among other things, an assessment of assets andliabilities to be transferred to Cenovus pursuant to the Arrangement, anallocation of then current income tax payable, an allocation of transactioncosts related to the Arrangement and appropriate capital structures. The DemandNote was repaid in full on the Effective Date.

 

Subsequent to the completion of theArrangement, Cenovus made a payment to EnCana in the amount of $250 millionto adjust the cash balances of both companies as at the Effective Date to theagreed upon amounts pursuant to the Separation Agreement.

 

As of the date hereof, EnCana doesnot beneficially own or control or direct, directly or indirectly, any CommonShares.

 

We are independent of EnCana to thegreatest extent practicable. Certain ongoing contractual arrangements betweenEnCana and Cenovus are generally limited to our mutual obligations under, amongothers, the Arrangement Agreement, the Separation Agreement and the ancillaryagreements contemplated in the Separation Agreement (including the EmployeeMatters Agreement), including indemnification in certain circumstances, andconfidentiality and access to records necessary to comply with, among otherthings, continuous disclosure requirements. In addition, we may require EnCanato provide us with certain services (including, but not limited to, informationtechnology services) on a transitional basis.

 

Pursuant to the Employee MattersAgreement, we are required to make certain reimbursement payments to EnCana inrespect of any cash payments made by EnCana on the surrender of EnCanaReplacement Options by our employees.

 

**ADDITIONAL INFORMATION**

 

Additional information relating tous is available via SEDAR at ***www.sedar.com***and also via EDGAR at ***www.sec.gov***.

 

Additional financial information iscontained in our audited consolidated financial statements and Management’sDiscussion and Analysis for the year ended December 31, 2009.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 83 |
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**NOTE REGARDING FORWARD-LOOKING STATEMENTS**

 

This annual information formcontains certain forward-looking statements or information (collectivelyreferred to in this note as “forward-looking statements”) within the meaning ofapplicable securities legislation. Forward-looking statements are typicallyidentified by words such as “projected”, “anticipate”, “believe”, “expect”,“plan”, “intend” or similar words suggesting future outcomes or statementsregarding an outlook. All statements other than statements of historical factcontained in this annual information form are forward-looking statements,including, but not limited to, statements relating to the anticipated benefitsof the Arrangement, operational information, future exploration and developmentplans, future acquisition or disposition opportunities, potential dividends,estimates of proved and probable reserves, production growth rates over thelong-term, cash flow, financial metrics (including debt to capitalization anddebt to adjusted EBITDA), future net capital investment, anticipated futureproduction, estimates of reserves decline rates and capital efficiency,production capacity and annual production growth rate, our corporate structure,division of our assets, successful use of new technology and innovations toincrease recovery and decrease costs, the ability to receive patents for ourtechnology and the expected timing thereof, possible internal and externalgrowth opportunities for our assets and the possible form of financing for thesame, capital requirements, estimated cost of carbon and abandonment and sitereclamation costs, our development plans, the timing of completion andanticipated capacities of the Foster Creek and Christina Lake expansions, theanticipated capacities of and the timing of capacity expansions for the WoodRiver refinery, including the timing of completion of the CORE project and thecapital expenditures for such expansions, the ability of ConocoPhillips andCenovus to successfully manage and operate the integrated oil business and theability of the parties to obtain regulatory approvals, expectations that wewill continue to carry out certain market optimization and risk mitigationactivities in the marketing of crude oil and natural gas, expectations offuture cash flows, our ability to meet delivery commitments of crude oil,natural gas and refined products, our ability to meet social and environmentallegislation and policies, the expectation that the location of our assets inNorth America limits our exposure to risks and uncertainties, the amounts,types, terms and conditions of financing that may be made available to us, ourestimated capitalization and adequacy thereof and the financing plans andinitiatives that may be undertaken by us.

 

Readers are cautioned not to placeundue reliance on forward-looking statements contained in this annualinformation form, which reflect the analysis of our management only as of thedate of this annual information form. All such forward-looking statements aresubject to important risks, uncertainties and assumptions. These statements areforward-looking because they are based on our current expectations, estimatesand assumptions. Some of the assumptions, risks and other factors which couldcause results to differ materially from those expressed in the forward-lookingstatements contained in this annual information form include, but are notlimited to: volatility of and assumptions regarding oil and gas prices,assumptions based upon our current guidance, fluctuations in currency andinterest rates, product supply and demand, market competition, risks inherentin our and our subsidiaries’ marketing operations, including credit risks, imprecisionof reserves estimates and estimates of recoverable quantities of oil, bitumen,natural gas and NGLs from properties and other sources not currently classifiedas proved or probable and life index of proved reserves, our and oursubsidiaries’ ability to replace and expand oil and gas reserves, the abilityof ConocoPhillips and Cenovus to successfully manage and operate the NorthAmerican integrated heavy oil business and the ability of the parties to obtainregulatory approvals, refining and marketing margins, potential disruption orunexpected technical difficulties in developing new products and manufacturingprocesses, potential failure of new products to achieve acceptance in themarket, unexpected cost increases or technical difficulties in constructing ormodifying manufacturing or refining facilities, unexpected difficulties inmanufacturing, transporting or refining synthetic crude oil, risks 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 84 |
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associated with technology and theapplication thereof to our business, our ability to generate sufficient cashflow from operations to meet our current and future obligations, our ability toaccess external sources of debt and equity capital, the timing and the costs ofwell and pipeline construction, our and our subsidiaries’ ability to secureadequate product transportation, changes in royalty, tax, environmental,greenhouse gas, carbon and other laws or regulations or the interpretations ofsuch laws or regulations, political and economic conditions in the countries inwhich we and our subsidiaries operate, the risk of war, terrorist threats,hostilities, civil insurrection and instability affecting countries in which weand our subsidiaries operate, risks associated with existing and potentialfuture lawsuits and regulatory actions made against us and our subsidiaries,the financing plans and initiatives that may be undertaken by us, thecapitalization and adequacy thereof for us, the expected impacts of theArrangement on our employees, operations, suppliers, business partners andstakeholders, our ability to obtain financing in the future on a stand alonebasis, that the historical financial information pertaining to our assets asoperated by EnCana prior to December 1, 2009 may not be representative ofour results as an independent entity, that we have a limited operating history,as a separate entity, and other risks and uncertainties described from time totime in the reports and filings made with securities regulatory authorities byus.

 

Statements relating to “reserves”are deemed to be forward-looking statements, as they involve the impliedassessment, based on certain estimates and assumptions, that the reservesdescribed exist in the quantities predicted or estimated, and can be profitablyproduced in the future. Readers are cautioned that the foregoing list of importantfactors is not exhaustive. All such forward-looking statements are madepursuant to the “safe harbor” provisions of the United States *Private Securities Litigation Reform Act of 1995* andapplicable Canadian securities legislation.

 

The forward-looking statementscontained in this annual information form are made as of the date hereof and wedo not undertake any obligation to release publicly the results of any revisionto these forward-looking statements which may be made to reflect events orcircumstances after the date of this annual information form or to reflect theoccurrence of unanticipated events, except as required by applicable Canadiansecurities laws. The forward-looking statements contained in this annualinformation form are expressly qualified in their entirety by the foregoing.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 85 |
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**NOTE REGARDING RESERVES DATA AND OTHER OIL AND GASINFORMATION**

 

NI 51-101 imposes oil and gasdisclosure standards for Canadian public companies engaged in oil and gasactivities. We have obtained an exemption from the Canadian securities regulatoryauthorities to permit us to provide disclosure in accordance with the relevantlegal requirements of the SEC. This facilitates comparability of our oil andgas disclosure with that provided by U.S. and other international issuers,given that we are active in the U.S. capital markets. Accordingly, the provedand probable reserves data and much of the other oil and gas informationincluded in this annual information form is disclosed in accordance with U.S.disclosure requirements. Such information, as well as the information that weanticipate disclosing in the future in reliance on such exemption, may differfrom the corresponding information prepared in accordance with NI 51-101standards.

 

In 2008, the SEC amended its oil andgas reporting requirements effective for Cenovus’s 2009 year end reporting. TheU.S. Financial Accounting Standards Board also amended its oil and gas reserveestimation and disclosure requirements to align with the amended SECrequirements. The amendments included changing the price used to calculatereserves from a year-end single day price to a historical 12-month averageprice, permitting optional disclosure of probable reserves and the sensitivityof reserves to price and requiring the separate disclosure of bitumen reservesfrom crude oil and NGLs reserves.

 

The primary differences between thecurrent U.S. requirements and the NI 51-101 requirements are that: (i) theU.S. standards require disclosure only of proved reserves, whereas NI 51-101requires disclosure of proved and probable reserves; and (ii) the U.S.standards require that the reserves and related future net revenue be estimatedunder existing economic and operating conditions, i.e., historic 12-monthaverage price, whereas NI 51-101 requires disclosure of reserves andrelated future net revenue using forecast prices and costs. The definitions ofproved reserves also differ, but according to the Canadian Oil and GasEvaluation Handbook, the reference source for the definition of proved reservesunder NI 51-101, differences in the estimated proved reserves quantities basedon constant prices should not be material.

 

According to the SEC, proved oil andgas reserves are those quantities of oil and gas, which, by analysis ofgeoscience and engineering data, can be estimated with reasonable certainty tobe economically producible from a given date forward, from known reservoirs andunder existing economic conditions, operating methods and governmentregulations. Prices include consideration of future price changes only to theextent provided by contractual arrangements in existence at year-end.

 

The current U.S. requirementspermit, but do not require, the disclosure of probable reserves information.The SEC has defined probable reserves as those additional reserves that areless certain to be recovered than proved reserves, but which, together withproved reserves, are as likely as not to be recovered.

 

Under U.S. disclosure standards,reserves and production information is required to be disclosed on a net basis(after royalties). The Alberta Government has implemented an oilsands royaltyscheme which ties the bitumen royalty rate to the West Texas Intermediatereference oil price, in Canadian dollars. Since oil price is unregulated andcan have significant volatility, this in turn means the royalty rate can varysignificantly. For example, our year-end 2008 proved bitumen reserves weresubject to a forecasted average royalty rate of four percent, while year-end2009 proved bitumen reserves face a forecasted average royalty rate of16 percent. This oil price dependent volatility can mask the impact of ourdevelopment activities. To provide more complete information on our business,we are voluntarily providing reserves and production information for bothproved and probable reserves, on a before royalties basis, as well as on anafter royalties basis.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 86 |
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**GLOSSARY**

 

The following is a glossary ofcertain terms used in this annual information form:

 

“**2014 Notes**”means the $800,000,000 aggregate principal amount of 4.50% senior notes dueSeptember 15, 2014 issued by Subco on September 18, 2009;

 

“**2019 Notes**”means the $1,300,000,000 aggregate principal amount of 5.70% senior notes dueOctober 15, 2019 issued by Subco on September 18, 2009;

 

“**2039 Notes**”means the $1,400,000,000 aggregate principal amount of 6.75% senior notes dueNovember 15, 2039 issued by Subco on September 18, 2009;

 

“**7050372**”means 7050372 Canada Inc., a corporation incorporated under the CBCA, whichamalgamated with Subco on the Effective Date with the resulting amalgamatedcorporation being named “Cenovus Energy Inc.”;

 

“**Arrangement**”means an arrangement under Section 192 of the CBCA involving, amongothers, EnCana, 7050372 and Subco, which became effective on the EffectiveDate;

 

“**ArrangementAgreement**” means the Arrangement Agreement dated as ofOctober 20, 2009 among EnCana, 7050372 and Subco;

 

“**AssumedLiabilities**” means the liabilities assumed by Subco pursuant to theSeparation Agreement and described under “General Development of Our Business –The Arrangement”;

 

“**Board**”means our board of directors;

 

“**CanadianGAAP**” means generally accepted accounting principles as in effect inCanada;

 

“**Canadian TaxRuling**” means the advance income tax rulings and opinions receivedfrom the Canada Revenue Agency with respect to certain aspects of thePre-Arrangement Reorganization, the Arrangement and certain other transactions,and includes any replacements thereof and amendments and supplements theretoreceived or anticipated to be received from the Canada Revenue Agency;

 

“**CBCA**”means the *Canada Business Corporations Act*, R.S.C.1985, c.C-44, as amended, and the regulations thereunder;

 

“**CenovusAssets**” means the assets transferred by EnCana to Subco pursuant tothe Separation Agreement and described under “General Development of OurBusiness – The Arrangement”;

 

“**CenovusBusinesses**” means, collectively, the Integrated Oil Division and theCanadian Plains Division of EnCana as they existed prior to the Effective Date;

 

“**CenovusOptions**” means the options to acquire Common Shares, including anyassociated tandem stock appreciation rights, granted by us pursuant to theCenovus Employee Stock Option Plan and, unless otherwise specified, includesCenovus Replacement Options;

 

“**CenovusReplacement Options**” means the options to acquire Common Shares, includingany associated tandem stock appreciation rights, granted by us to the holdersof options of EnCana pursuant to the Arrangement;

 

“**CommonShares**” means the common shares in the capital of Cenovus EnergyInc.;

 

“**CORE**”means the coker and refinery expansion project at the Wood River Refinery inIllinois, United States;

 

“**DissentingShareholder**” means a shareholder of EnCana that validly exercisedits dissent rights in connection with the special resolution to approve theArrangement;

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 87 |
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“**EDGAR**”means the U.S. Electronic Data-Gathering Analysis and Retrieval system;

 

“**EffectiveDate**” means November 30, 2009, the date upon which theArrangement became effective;

 

“**EmployeeMatters Agreement**” means the employee and benefits matters agreementdated November 23, 2009 among EnCana, 7050372 and Subco regarding certaintransitional employee matters in respect of us and EnCana after completion ofthe Arrangement, as it may be amended, modified or supplemented from time totime in accordance with its terms;

 

“**EnCana**”means EnCana Corporation, a corporation existing under the CBCA;

 

“**EnCanaReplacement Options**” means the options to acquire common shares ofEnCana, including any associated tandem stock appreciation rights, granted byEnCana to the holders of options to acquire common shares of EnCana pursuant tothe Arrangement;

 

“**FCCL**”means FCCL Partnership, a general partnership formed under the *Partnership Act*, R.S.A. 2000, c.P-3, as amended;

 

“**FirstPreferred Shares**” means the first preferred shares in the capital ofCenovus Energy Inc.;

 

“**NI 51-101**”means National Instrument 51-101 *Standards of Disclosurefor Oil and Gas Activities* of the Canadian SecuritiesAdministrators;

 

“**NoteIndenture**” means the indenture dated as of September 18, 2009between Subco and The Bank of New York Mellon;

 

“**Notes**”means, collectively, the 2014 Notes, the 2019 Notes and the 2039 Notes;

 

“**NYSE**”means the New York Stock Exchange;

 

“**Plan ofArrangement**” means the plan of arrangement involving, among others,Cenovus Energy Inc. and EnCana;

 

“**Pre-ArrangementReorganization**” means the reorganization mechanics effected prior tothe Arrangement becoming effective;

 

“**PreferredShares**” means, collectively, the First Preferred Shares and SecondPreferred Shares;

 

“**ReorganizationTime**” means the time that all or substantially all of the CenovusAssets were transferred by EnCana to Subco and the Assumed Liabilities wereassumed by Subco, which was 12:10 a.m. (Calgary time) on the EffectiveDate;

 

“**SAGD**”means steam assisted gravity drainage;

 

“**SEC**”means the U.S. Securities and Exchange Commission;

 

“**SecondPreferred Shares**” means the second preferred shares in the capitalof Cenovus Energy Inc.;

 

“**SEDAR**”means the Canadian System for Electronic Document Analysis and Retrieval;

 

“**SeparationAgreement**” means the separation and transition agreement datedNovember 30, 2009 involving, among others, EnCana, 7050372 and Subcoregarding the transfer of the Cenovus Assets from EnCana to Subco, theassumption of the Assumed Liabilities by 7050372 and Subco and certaintransitional arrangements after completion of the Arrangement, as it may beamended, modified or supplemented from time to time in accordance with itsterms;

 

“**ShareholderRights Plan**” means our shareholder rights plan dated as ofOctober 20, 2009 and restated as of November 30, 2009;

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 88 |
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“**Subco**”means Cenovus Energy Inc. (formerly EnCana Finance Ltd.), a corporationcontinued under the CBCA, which amalgamated with 7050372 on the Effective Datewith the resulting amalgamated corporation being named “Cenovus Energy Inc.”;

 

“**TSX**”means the Toronto Stock Exchange;

 

“**UnitedStates**” and “**U.S.**” means theUnited States of America;

 

“**U.S. GAAP**”means generally accepted accounting principles as in effect in the UnitedStates;

 

“**U.S.Securities Act**” means the United States *SecuritiesAct of 1933*, as amended;

 

“**U.S. TaxRuling**” means the private letter ruling received from the U.S.Internal Revenue Service confirming the U.S. federal income tax consequences ofcertain aspects of the Pre-Arrangement Reorganization, the Arrangement andcertain other transactions, and includes any amendments and supplementsthereto; and

 

“**WRB**”means WRB Refining LLC.

 

**ABBREVIATIONS**

 
| Oil and  Natural Gas Liquids | Natural Gas                                 |
|------------------------------|---------------------------------------------|
| bbl                          | barrel                                      | Tcf | trillion  cubic feet |
| bbls/d                       | barrels per  day                            | Bcf | billion  cubic feet |
| Mbbls/d                      | thousand  barrels per day                   | Mcf | thousand  cubic feet |
| MMbbls                       | million  barrels                            | MMcf | million  cubic feet |
| NGLs                         | natural gas  liquids                        | MMcf/d | million  cubic feet per day |
| BOE                          | barrel of  oil equivalent                   | MMbtu | million  British thermal units |
| BOE/d                        | barrel of  oil equivalent per day           |   |   |
| MBOE                         | thousand barrels  of oil equivalent         |   |   |
| MBOE/d                       | thousand  barrels of oil equivalent per day |   |   |

 

In this annual information form,certain natural gas volumes have been converted to BOE or MBOE on the basis ofsix Mcf to one bbl. BOE and MBOE may be misleading, particularly if used inisolation. A conversion ratio of one bbl to six Mcf is based on an energyequivalency conversion method primarily applicable at the burner tip and doesnot represent value equivalency at the well head.

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 | 89 |
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**APPENDIX A**

 

**REPORT ON RESERVES DATA****BY INDEPENDENT QUALIFIED RESERVES EVALUATORS**

 

To the Boardof Directors of Cenovus Energy Inc. (the “Corporation”):

 

1.             We have evaluatedthe Corporation’s reserves data as at December 31, 2009. The reserves dataconsists of the following:

 

(a)            estimated proved andprobable oil and gas reserves quantities as at December 31, 2009 usingconstant prices and costs; and

 

(b)            the relatedestimates of discounted future net cash flows under the standardized measurecalculation for proved oil and gas reserves quantities.

 

2.             The reservesdata are the responsibility of the Corporation’s management. Our responsibilityis to express an opinion on the reserves data based on our evaluation.

 

We carried out ourevaluation in accordance with standards set out in the Canadian Oil and GasEvaluation Handbook (the “COGE Handbook”) prepared jointly by the Society ofPetroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute ofMining, Metallurgy & Petroleum (Petroleum Society) with the necessarymodifications to reflect definitions and standards under the U.S. FinancialAccounting Standards Board policies (the “FASB Standards”) and the legalrequirements of the U.S. Securities and Exchange Commission (“SEC Requirements”).

 

3.             Thosestandards require that we plan and perform an evaluation to obtain reasonableassurance as to whether the reserves data are free of material misstatement. Anevaluation also includes assessing whether the reserves data are in accordancewith the principles and definitions outlined above.

 

4.             The followingtable sets forth both the estimated proved reserves quantities (afterroyalties) and related estimates of future net cash flows (before deduction ofincome taxes) assuming constant prices and costs and calculated using adiscount rate of 10 percent, included in the reserves data of the Corporationevaluated by us for the year ended December 31, 2009:

 
| ** **                                                              | ** ** | ** **             | ** ** | **Estimated  Proved Reserves  Quantities After  Royalty** | ** ** | ** ** | ** ** |
|-------------------------------------------------------------------------|------------|------------------------|------------|---------------------------------------------------------------------|------------|------------|------------|
| **Evaluator and********Preparation Date of Report** | ** ** | **Reserves  Location** | ** ** | **Liquids**                                                         | ** ** | **Gas**    | ** ** | **Related Estimates  of Future Net Cash  Flow BTax,********10% discount rate** | ** ** |
| ** **                                                              |       |                   |       | (MMbbl)                                                             |       | (Bcf)      |       | (US$MM) |   |
| McDaniel &  Associates Consultants Ltd. January 11, 2010  |       | Canada                 |       | 879                                                                 |       | 1,386      |       | 8,881 |   |
| GLJ  Petroleum Consultants Ltd. January 11, 2010                   |       | Canada                 |       | 72                                                                  |       | 88         |       | 1,004 |   |
| **Totals**                                                              |       |                   |       | 951                                                                 |       | 1,474      |       | 9,885 |   |

 

5.             In ouropinion, the reserves data respectively evaluated by us have, in all materialrespects, been determined and are in accordance with the COGE Handbook asmodified by the FASB Standards and SEC Requirements.

 

6.             We have noresponsibility to update our reports referred to in paragraph 4 for events andcircumstances occurring after their respective preparation dates.

 

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

 

Executed asto our report referred to above:

 
|   |   | /s/ McDaniel &  Associates Consultants Ltd. |   |   |   | /s/ GLJ  Petroleum Consultants Ltd. |
|--------|--------|------------------------------------------------------|--------|--------|--------|-------------------------------------|
|   |   | McDaniel &  Associates Consultants Ltd.     |   |   |   | GLJ  Petroleum Consultants Ltd.     |
|   |   | Calgary,  Alberta, Canada                            |   |   |   | Calgary,  Alberta, Canada           |

 

February 9,2010

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | A-1 |
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**APPENDIX B**

 

**REPORT OF MANAGEMENT AND DIRECTORS****ON RESERVES DATA AND OTHER INFORMATION**

 

Management anddirectors of Cenovus Energy Inc. (the “Corporation”) are responsible for thepreparation and disclosure of information with respect to the Corporation’s oiland gas activities in accordance with securities regulatory requirements. Inthe case of the Corporation, the regulatory requirements are covered underNI 51-101, as amended by a Decision dated October 20, 2009, andrequire disclosure of information contemplated by, and consistent with, U.S.Disclosure Requirements (as defined in the Decision). Required informationincludes reserves data, which consist of the following:

 
| (i)    | proved oil  and gas reserves quantities estimated as at December 31, 2009 using  constant prices and costs; and                               |
|--------|----------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                               |
| (ii)   | the related  estimates of discounted future net cash flows under the standardized measure  calculation for proved oil and gas reserves quantities. |

 

The Corporation willalso be disclosing optional reserves information, consisting of probable oiland gas reserves quantities estimated as at December 31, 2009 usingconstant prices and costs.

 

Independent qualified reserves evaluators have evaluated theCorporation’s reserves data. A report from the independent qualified reservesevaluators dated February 9, 2010 (the “IQRE Report”), highlighting thestandards they followed and their results, accompanies this Report.

 

The ReservesCommittee of the board of directors of the Corporation, which Committee iscomprised exclusively of non-management and unrelated directors, has:

 
| (a)    | reviewed  the Corporation’s procedures for providing information to the independent  qualified reserves evaluators;                                                                                                      |
|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                          |
| (b)    | met with  the independent qualified reserves evaluators to determine whether any  restrictions placed by management affected the ability of the independent  qualified reserves evaluators to report without reservation; and |
|   |                                                                                                                                                                                                                          |
| (c)    | reviewed  the reserves data as outlined in the IQRE Report with management and each of  the independent qualified reserves evaluators.                                                                                        |

 

The board ofdirectors of the Corporation (the “Board of Directors”) has reviewed thestandardized measure calculation with respect to the Corporation’s proved oiland gas reserves quantities. The Board of Directors has reviewed theCorporation’s procedures for assembling and reporting other informationassociated with oil and gas activities and has reviewed that information withmanagement. The Board of Directors has approved:

 
| (a)    | the content  and filing with securities regulatory authorities of the proved oil and gas  reserves quantities, related standardized measure calculation, probable oil  and gas reserves quantities and other oil and gas activity information  contained in the annual information form of the Corporation accompanying this  Report; |
|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                  |
| (b)    | the filing  of the IQRE Report; and                                                                                                                                                                                                                                                                                                   |
|   |                                                                                                                                                                                                                                                                                                                                  |
| (c)    | the content  and filing of this Report.                                                                                                                                                                                                                                                                                               |

 

Because the reservesdata are based on judgments regarding future events, actual results will varyand the variations may be material. However, any variations should beconsistent with the fact that reserves are categorized according to theprobability of their recovery.

 
|   |   | /s/ Brian  C. Ferguson                        |   |   |   | /s/ Judy A.  Fairburn                  |
|--------|--------|-----------------------------------------------|--------|--------|--------|----------------------------------------|
|   |   | Brian C.  Ferguson                            |   |   |   | Judy A.  Fairburn                      |
|   |   | President &  Chief Executive Officer |   |   |   | Executive  Vice-President, Environment |
|   |   |                                          |   |   |   | and  Strategic Planning                |
|   |   |                                          |   |   |   |                                   |
|   |   | /s/ Michael  A. Grandin                       |   |   |   | /s/  Wayne G. Thomson             |
|   |   | Michael A.  Grandin                           |   |   |   | Wayne G.  Thomson                      |
|   |   | Director  and Chair of the Board              |   |   |   | Director  and Chair of the             |
|   |   |                                          |   |   |   | Reserves  Committee                    |

 

February 10,2010

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | B-1 |
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**APPENDIX C**

 

**AUDIT COMMITTEE MANDATE**

 

**I.****            ****PURPOSE**

 

The Audit Committee (the “Committee”)is appointed by the Board of Directors of Cenovus Energy Inc. (“Cenovus” or the“Corporation”) to assist the Board in fulfilling its oversightresponsibilities.

 

The Committee’s primary duties andresponsibilities are to:

 

·      Review and approve management’sidentification of principal financial risks and monitor the process to managesuch risks.

 

·      Oversee and monitor the Corporation’scompliance with legal and regulatory requirements.

 

·      Receive and review the reports of the AuditCommittee of any subsidiary with public securities.

 

·      Oversee and monitor the integrity of theCorporation’s accounting and financial reporting processes, financialstatements and system of internal controls regarding accounting and financialreporting and accounting compliance.

 

·      Oversee audits of the Corporation’sfinancial statements.

 

·      Oversee and monitor the qualifications,independence and performance of the Corporation’s external auditors andinternal auditing department.

 

·      Provide an avenue of communication among theexternal auditors, management, the internal auditing department, and the Boardof Directors.

 

·      Report to the Board of Directors regularly.

 

The Committee has the authority toconduct any review or investigation appropriate to fulfilling itsresponsibilities. The Committee shall have unrestricted access to personnel andinformation, and any resources necessary to carry out its responsibility. Inthis regard, the Committee may direct internal audit personnel to particularareas of examination.

 

**II.****           ****COMPOSITION AND MEETINGS**

 

**Committee Member’s Dutiesin addition to those of a Director**

 

The duties and responsibilities of amember of the Committee are in addition to those duties set out for a member ofthe Board of Directors.

 

**Composition**

 

The Committee shall consist of notless than three and not more than eight directors as determined by the Board,all of whom shall qualify as independent directors pursuant to NationalInstrument 52-110 *Audit Committees*(as implementedby the Canadian Securities Administrators and as amended from time to time) (“NI52-110”).

 

All members of the Committee shallbe financially literate, as defined in NI 52-110, and at least one member shallhave accounting or related financial managerial expertise. In particular, atleast one member shall have, through (i) education and experience as aprincipal financial officer, principal accounting officer, controller, publicaccountant or auditor or experience in one or more positions that involve theperformance of similar functions; (ii) experience actively supervising aprincipal financial officer, principal 

 

 
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accounting officer, controller,public accountant, auditor or person performing similar functions; (iii) experienceoverseeing or assessing the performance of companies or public accountants withrespect to the preparation, auditing or evaluation of financial statements; or (iv) otherrelevant experience:

 

·      An understanding of generally acceptedaccounting principles and financial statements;

 

·      The ability to assess the generalapplication of such principles in connection with the accounting for estimates,accruals and reserves;

 

·      Experience preparing, auditing, analyzing orevaluating financial statements that present a breadth and level of complexityof accounting issues that are generally comparable to the breadth andcomplexity of issues that can reasonably be expected to be raised by theCorporation’s financial statements, or experience actively supervising one ormore persons engaged in such activities;

 

·      An understanding of internal controls andprocedures for financial reporting; and

 

·      An understanding of audit committeefunctions.

 

Committee members may not, otherthan in their respective capacities as members of the Committee, the Board orany other committee of the Board, accept directly or indirectly any consulting,advisory or other compensatory fee from the Corporation or any subsidiary ofthe Corporation, or be an “affiliated person” (as such term is defined in the *United States Securities Exchange Act of 1934*, as amended(the *“Exchange Act”*), and the rules adoptedby the U.S. Securities and Exchange Commission (“SEC”) thereunder) of theCorporation or any subsidiary of the Corporation. For greater certainty,directors’ fees and fixed amounts of compensation under a retirement plan(including deferred compensation) for prior service with the Corporation thatare not contingent on continued service should be the only compensation anaudit committee member receives from the Corporation.

 

At least one member shall haveexperience in the oil and gas industry.

 

Committee members shall notsimultaneously serve on the audit committees of more than two other publiccompanies, unless the Board first determines that such simultaneous servicewill not impair the ability of the relevant members to effectively serve on theCommittee, and required public disclosure is made.

 

The non-executive Board Chairmanshall be a non-voting member of the Committee. See “Quorum” for furtherdetails.

 

**Appointment of Members**

 

Committee members shall be appointedby the Board, effective after the election of directors at the annual meetingof shareholders, provided that any member may be removed or replaced at anytime by the Board and shall, in any event, cease to be a member of theCommittee upon ceasing to be a member of the Board.

 

The Nominating and CorporateGovernance Committee will recommend for approval to the Board an unrelatedDirector to act as Chairman of the Committee. The Board shall appoint theChairman of the Committee.

 

If the Chairman of the Committee isunavailable or unable to attend a meeting of the Committee, the Chair shall askanother member to chair the meeting, failing which a member of the Committeepresent at the meeting shall be chosen to preside over the meeting by amajority of the members of the Committee present at such meeting.

 

The Chairman of the Committeepresiding at any meeting of the Committee shall not have a casting vote.

 

 
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The items pertaining to the Chairmanin this section should be read in conjunction with the Committee Chair sectionof the *Chair of the Board of Directors and Committee ChairGeneral Guidelines.*

 

Where a vacancy occurs at any timein the membership of the Committee, it may be filled by the Board.

 

The Corporate Secretary or one ofthe Assistant Corporate Secretaries of the Corporation or such other person asthe Corporate Secretary of the Corporation shall designate from time to timeshall be the Secretary of the Committee and shall keep minutes of the meetingsof the Committee.

 

**Meetings**

 

Committee meetings may, by agreementof the Chairman of the Committee, be held in person, by video conference, bymeans of telephone or by a combination of any of the foregoing.

 

The Committee shall meet at leastquarterly. The Chairman of the Committee may call additional meetings asrequired. In addition, a meeting may be called by the non-executive BoardChairman, the President & Chief Executive Officer, or any member ofthe Committee or by the external auditors.

 

The Committee shall have the rightto determine who shall, and who shall not, be present at any time during ameeting of the Committee.

 

Directors, who are not members ofthe Committee, may attend Committee meetings, on an ad hoc basis, uponprior consultation and approval by the Committee Chairman or by a majority ofthe members of the Committee.

 

The Committee may, by specificinvitation, have other resource persons in attendance.

 

The President & ChiefExecutive Officer, the Executive Vice-President & Chief FinancialOfficer, the Comptroller and the head of internal audit are expected to beavailable to attend the Committee’s meetings or portions thereof.

 

**Notice of Meeting**

 

Notice of the time and place of eachCommittee meeting may be given orally, or in writing, or by facsimile, or byelectronic means to each member of the Committee at least 24 hours prior to thetime fixed for such meeting. Notice of each meeting shall also be given to theexternal auditors of the Corporation.

 

A member and the external auditorsmay, in any manner, waive notice of the Committee meeting. Attendance of amember at a meeting shall constitute waiver of notice of the meeting exceptwhere a member attends a meeting for the express purpose of objecting to thetransaction of any business on the grounds that the meeting was not lawfullycalled.

 

**Quorum**

 

A majority of Committee members,present in person, by video conference, by telephone, or by a combinationthereof, shall constitute a quorum. In addition, if an ex officio, non-votingmember’s presence is required to attain a quorum of the Committee, then thesaid member shall be allowed to cast a vote at the meeting.

 

**Minutes**

 

Minutes of each Committee meetingshould be succinct yet comprehensive in describing substantive issues discussedby the Committee. However, they should clearly identify those items ofresponsibilities scheduled by the Committee for the meeting that have beendischarged by the Committee and those items of responsibilities that areoutstanding.

 

Minutes of Committee meetings shallbe sent to all Committee members and to the external auditors.

 

 
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The full Board of Directors shall bekept informed of the Committee’s activities by a report following eachCommittee meeting.

 

**III.****          ****RESPONSIBILITIES**

 

**Review Procedures**

 

Review and update the Committee’smandate annually, or sooner, where the Committee deems it appropriate to do so.Provide a summary of the Committee’s composition and responsibilities in theCorporation’s annual report or other public disclosure documentation.

 

Provide a summary of all approvalsby the Committee of the provision of audit, audit-related, tax and otherservices by the external auditors for inclusion in the Corporation’s annualreport filed with the SEC.

 

**Annual Financial Statements**

 

1.        Discuss andreview with management and the external auditors the Corporation’s and anysubsidiary with public securities annual audited financial statements andrelated documents prior to their filing or distribution. Such review toinclude:

 

(a)                The annualfinancial statements and related footnotes including significant issuesregarding accounting principles, practices and significant management estimatesand judgments, including any significant changes in the Corporation’s selectionor application of accounting principles, any major issues as to the adequacy ofthe Corporation’s internal controls and any special steps adopted in light ofmaterial control deficiencies.

 

(b)       Management’sDiscussion and Analysis.

 

(c)       A review ofthe use of off-balance sheet financing including management’s risk assessmentand adequacy of disclosure.

 

(d)       A review ofthe external auditors’ audit examination of the financial statements and theirreport thereon.

 

(e)       Review ofany significant changes required in the external auditors’ audit plan.

 

(f)        A review ofany serious difficulties or disputes with management encountered during thecourse of the audit, including any restrictions on the scope of the externalauditors’ work or access to required information.

 

(g)       A review ofother matters related to the conduct of the audit, which are to be communicatedto the Committee under generally accepted auditing standards.

 

2.        Review andformally recommend approval to the Board of the Corporation’s:

 

(a)       Year-end audited financialstatements. Such review shall include discussions with management and theexternal auditors as to:

 

(i)        Theaccounting policies of the Corporation and any changes thereto.

(ii)       The effectof significant judgments, accruals and estimates.

(iii)      The mannerof presentation of significant accounting items.

(iv)      The consistency of disclosure.

 

(b)       Management’s Discussion andAnalysis.

 

(c)       Annual Information Form as tofinancial information.

 

(d)       All prospectuses and informationcirculars as to financial information.

 

The review shall include a report from the externalauditors about the quality of the most critical accounting principles uponwhich the Corporation’s financial status

 

 
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|-----------------------------------------------------------------------------------|--------|-----|

 

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depends, and which involve the most complex,subjective or significant judgmental decisions or assessments.

 

**Quarterly FinancialStatements**

 

3.        Review withmanagement and the external auditors and either approve (such approval toinclude the authorization for public release) or formally recommend forapproval to the Board the Corporation’s:

 

(a)       Quarterly unauditedfinancial statements and related documents, including Management’s Discussionand Analysis.

 

(b)       Any significant changes to theCorporation’s accounting principles.

 

Review quarterly unaudited financial statements ofany subsidiary of the Corporation with public securities prior to theirdistribution.

 

**Other Financial Filings and Public Documents**

 

4.       Review anddiscuss with management financial information, including earnings pressreleases, the use of “pro forma” or non-GAAP financial information and earningsguidance, contained in any filings with the securities regulators or newsreleases related thereto (or provided to analysts or rating agencies) andconsider whether the information is consistent with the information containedin the financial statements of the Corporation or any subsidiary with publicsecurities. Such discussion may be done generally (consisting of discussing thetypes of information to be disclosed and the types of presentations to bemade).

 

**Internal Control Environment**

 

5.       Ensure thatmanagement, the external auditors, and the internal auditors provide to theCommittee an annual report on the Corporation’s control environment as itpertains to the Corporation’s financial reporting process and controls.

 

6.        Review anddiscuss significant financial risks or exposures and assess the stepsmanagement has taken to monitor, control, report and mitigate such risk to theCorporation.

 

7.        Reviewsignificant findings prepared by the external auditors and the internalauditing department together with management’s responses.

 

8.        Review inconsultation with the internal auditors and the external auditors the degree ofcoordination in the audit plans of the internal auditors and the externalauditors and enquire as to the extent the planned scope can be relied upon todetect weaknesses in internal controls, fraud, or other illegal acts. TheCommittee will assess the coordination of audit effort to assure completenessof coverage and the effective use of audit resources. Any significant recommendationsmade by the auditors for the strengthening of internal controls shall bereviewed and discussed with management.

 

**Other Review Items**

 

9.        Reviewpolicies and procedures with respect to officers’ and directors’ expenseaccounts and perquisites, including their use of corporate assets, and considerthe results of any review of these areas by the internal auditor or theexternal auditors.

 

10.      Review allrelated party transactions between the Corporation and any officers ordirectors, including affiliations of any officers or directors.

 

11.      Review withthe General Counsel, the head of internal audit and the external auditors theresults of their review of the Corporation’s monitoring compliance with each ofthe Corporation’s published codes of business conduct and applicable legalrequirements.

 

12.      Review legaland regulatory matters, including correspondence with regulators andgovernmental agencies, that may have a material impact on the interim or annual

 

 
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financial statements, related corporationcompliance policies, and programs and reports received from regulators orgovernmental agencies. Members from the Legal and Tax departments should be atthe meeting in person to deliver their reports.

 

13.      Reviewpolicies and practices with respect to off-balance sheet transactions andtrading and hedging activities, and consider the results of any review of theseareas by the internal auditors or the external auditors.

 

14.      Ensure thatthe Corporation’s presentations on net proved reserves have been reviewed withthe Reserves Committee of the Board.

 

15.      Reviewmanagement’s processes in place to prevent and detect fraud.

 

16.      Reviewprocedures for the receipt, retention and treatment of complaints received bythe Corporation, including confidential, anonymous submissions by employees ofthe Corporation, regarding accounting, internal accounting controls, orauditing matters.

 

17.      Review withthe President & Chief Executive Officer, the Executive Vice-President &Chief Financial Officer of the Corporation and the external auditors: (i) allsignificant deficiencies and material weaknesses in the design or operation ofthe Corporation’s internal controls and procedures for financial reportingwhich could adversely affect the Corporation’s ability to record, process,summarize and report financial information required to be disclosed by theCorporation in the reports that it files or submits under the *Exchange Act* or applicable Canadian federal and provinciallegislation and regulations within the required time periods, and (ii) anyfraud, whether or not material, that involves management of the Corporation orother employees who have a significant role in the Corporation’s internalcontrols and procedures for financial reporting.

 

18.      Meet on aperiodic basis separately with management.

 

**External Auditors**

 

19.      Be directlyresponsible, in the Committee’s capacity as a committee of the Board andsubject to the rights of shareholders and applicable law, for the appointment,compensation, retention and oversight of the work of the external auditors(including resolution of disagreements between management and the externalauditors regarding financial reporting) for the purpose of preparing or issuingan audit report, or performing other audit, review or attest services for theCorporation. The external auditors shall report directly to the Committee.

 

20.      Meet on aregular basis with the external auditors (without management present) and havethe external auditors be available to attend Committee meetings or portionsthereof at the request of the Chairman of the Committee or by a majority of themembers of the Committee.

 

21.      Review anddiscuss a report from the external auditors at least quarterly regarding:

 

(a)       All critical accountingpolicies and practices to be used;

 

(b)       All alternative treatmentswithin generally accepted accounting principles for policies and practicesrelated to material items that have been discussed with management, includingthe ramifications of the use of such alternative disclosures and treatments,and the treatment preferred by the external auditors; and

 

(c)      Othermaterial written communications between the external auditors and management,such as any management letter or schedule of unadjusted differences.

 

22.      Obtain andreview a report from the external auditors at least annually regarding:

 

(a)       The external auditors’ internalquality-control procedures.

 

 
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(b)                  Any material issues raised by the most recentinternal quality-control review, or peer review, of the external auditors, orby any inquiry or investigation by governmental or professional authorities,within the preceding five years, respecting one or more independent auditscarried out by the external auditors, and any steps taken to deal with thoseissues.

 

(c)                  To theextent contemplated in the following paragraph, all relationships between theexternal auditors and the Corporation.

 

23.                  Review anddiscuss with the external auditors all relationships that the external auditorsand their affiliates have with the Corporation and its affiliates in order todetermine the external auditors’ independence, including, without limitation, (i) receivingand reviewing, as part of the report described in the preceding paragraph, aformal written statement from the external auditors delineating allrelationships that may reasonably be thought to bear on the independence of theexternal auditors with respect to the Corporation and its affiliates, (ii) discussingwith the external auditors any disclosed relationships or services that theexternal auditors believe may affect the objectivity and independence of theexternal auditors, and (iii) recommending that the Board take appropriateaction in response to the external auditors’ report to satisfy itself of theexternal auditors’ independence.

 

24.                  Review andevaluate:

 

(a)                The external auditors’ and the lead partnerof the external auditors’ team’s performance, and make a recommendation to theBoard of Directors regarding the reappointment of the external auditors at theannual meeting of the Corporation’s shareholders or regarding the discharge ofsuch external auditors.

 

(b)                  The terms of engagement of the externalauditors together with their proposed fees.

 

(c)                  External audit plans and results.

 

(d)                  Any other related audit engagement matters.

 

(e)                  The engagement of the external auditors toperform non-audit services, together with the fees therefor, and the impactthereof, on the independence of the external auditors.

 

25.               Uponreviewing and discussing the information provided to the Committee inaccordance with paragraphs 21 through 24, evaluate the external auditors’qualifications, performance and independence, including whether or not theexternal auditors’ quality controls are adequate and the provision of permittednon-audit services is compatible with maintaining auditor independence, takinginto account the opinions of management and the head of internal audit. TheCommittee shall present its conclusions with respect to the external auditorsto the Board.

 

26.                  Ensure therotation of partners on the audit engagement team in accordance with applicablelaw. Consider whether, in order to assure continuing external auditorindependence, it is appropriate to adopt a policy of rotating the externalauditing firm on a regular basis.

 

27.                  Set clearhiring policies for the Corporation’s hiring of employees or former employeesof the external auditors.

 

28.                  Considerwith management and the external auditors the rationale for employing auditfirms other than the principal external auditors.

 

29.                  Consider andreview with the external auditors, management and the head of internal audit:

 

(a)                     Significantfindings during the year and management’s responses and follow-up thereto.

 

 
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(b)                     Anydifficulties encountered in the course of their audits, including anyrestrictions on the scope of their work or access to required information, andmanagement’s response.

 

(c)                     Anysignificant disagreements between the external auditors or internal auditorsand management.

 

(d)                     Any changesrequired in the planned scope of their audit plan.

 

(e)                     Theresources, budget, reporting relationships, responsibilities and plannedactivities of the internal auditors.

 

(f)                         The internalaudit department mandate.

 

(g)                     Internalaudit’s compliance with the Institute of Internal Auditors’ standards.

 

**Internal Audit Department and Independence**

 

30.                  Meet on aperiodic basis separately with the head of internal audit.

 

31.               Review andconcur in the appointment, compensation, replacement, reassignment, ordismissal of the head of internal audit.

 

32.                  Confirm andassure, annually, the independence of the internal audit department and theexternal auditors.

 

**Approval of Audit and Non-Audit Services**

 

33.                 Review and,where appropriate, approve the provision of all permitted non-audit services(including the fees and terms thereof) in advance of the provision of thoseservices by the external auditors (subject to the de minimus exception fornon-audit services described in the *Exchange Act* orapplicable Canadian federal and provincial legislation and regulations whichare approved by the Committee prior to the completion of the audit).

 

34.                 Review and,where appropriate and permitted, approve the provision of all audit services(including the fees and terms thereof) in advance of the provision of thoseservices by the external auditors.

 

35.                 If thepre-approvals contemplated in paragraphs 33 and 34 are not obtained, approve,where appropriate and permitted, the provision of all audit and non-auditservices promptly after the Committee or a member of the Committee to whomauthority is delegated becomes aware of the provision of those services.

 

36.                 Delegate, ifthe Committee deems necessary or desirable, to subcommittees consisting of oneor more members of the Committee, the authority to grant the pre-approvals andapprovals described in paragraphs 33 through 35. The decision of any suchsubcommittee to grant pre-approval shall be presented to the full Committee atthe next scheduled Committee meeting.

 

37.                 TheCommittee may establish policies and procedures for the pre-approvals describedin paragraphs 33 and 34, so long as such policies and procedures are detailedas to the particular service, the Committee is informed of each service andsuch policies and procedures do not include delegation of the Committee’sresponsibilities under the *Exchange Act* orapplicable Canadian federal and provincial legislation and regulations tomanagement.

 

**Other Matters**

 

38.                  Review andconcur in the appointment, replacement, reassignment, or dismissal of the ChiefFinancial Officer.

 

39.                  Upon amajority vote of the Committee outside resources may be engaged where and ifdeemed advisable.

 

 
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40.                ReportCommittee actions to the Board of Directors with such recommendations, as theCommittee may deem appropriate.

 

41.                Conduct orauthorize investigations into any matters within the Committee’s scope ofresponsibilities. The Committee shall be empowered to retain, obtain advice orotherwise receive assistance from independent counsel, accountants, or othersto assist it in the conduct of any investigation as it deems necessary and thecarrying out of its duties.

 

42.              TheCorporation shall provide for appropriate funding, as determined by theCommittee in its capacity as a committee of the Board, for payment (i) ofcompensation to the external auditors for the purpose of preparing or issuingan audit report or performing other audit, review or attest services for theCorporation, (ii) of compensation to any advisors employed by theCommittee and (iii) of ordinary administrative expenses of the Committeethat are necessary or appropriate in carrying out its duties.

 

43.                Obtainassurance from the external auditors that disclosure to the Committee is notrequired pursuant to the provisions of the *Exchange Act*regarding the discovery of illegal acts by the external auditors.

 

44.                TheCommittee shall review and reassess the adequacy of this Mandate annually andrecommend any proposed changes to the Board for approval.

 

45.              TheCommittee’s performance shall be evaluated annually by the Nominating andCorporate Governance Committee of the Board of Directors.

 

46.                Perform suchother functions as required by law, the Corporation’s mandate or bylaws, or theBoard of Directors.

 

47.                Consider anyother matters referred to it by the Board of Directors.

 

Approved:  November 30, 2009

 

 
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**APPENDIX D**

 

**BOARD OF DIRECTORS’ MANDATE**

 

The fundamental responsibility of theBoard of Directors (the “Board”) of Cenovus Energy Inc. (“Cenovus” or the “Corporation”)is to appoint a competent executive team and to oversee the management of thebusiness, with a view to maximizing shareholder value and ensuring corporateconduct in an ethical and legal manner via an appropriate system of corporategovernance and internal control.

 

**Executive Team Responsibility**

 

·                  Appoint the ChiefExecutive Officer (“CEO”) and senior officers, approve their compensation, andmonitor the CEO’s performance against a set of mutually agreed corporateobjectives directed at maximizing shareholder value.

 

·                  In conjunction withthe CEO, develop a clear mandate for the CEO, which includes a delineation ofmanagement’s responsibilities.

 

·                Ensure that a processis established that adequately provides for succession planning, including theappointing, training and monitoring of senior management.

 

·                  Establish limits ofauthority delegated to management.

 

**Operational Effectivenessand Financial Reporting**

 

·                  Annual review andadoption of a strategic planning process and approval of the corporatestrategic plan, which takes into account, among other things, the opportunitiesand risks of the business.

 

·                  Ensure that asystem is in place to identify the principal risks to the Corporation and thatthe best practical procedures are in place to monitor and mitigate the risks.

 

·                Ensure thatprocesses are in place to address applicable regulatory, corporate, securitiesand other compliance matters.

 

·                  Ensure that processesare in place for the Corporation to mitigate environmental impacts, addresshealth and safety matters that may arise with our activities, and operate in amanner consistent with recognized standards.

 

·                  Ensure that anadequate system of internal control exists.

 

·                  Ensure that duediligence processes and appropriate controls are in place with respect toapplicable certification requirements regarding the Corporation’s financial andother disclosure.

 

·                  Review and approvethe Corporation’s financial statements and oversee the Corporation’s compliancewith applicable audit, accounting and reporting requirements.

 

·                  Approve annualoperating and capital budgets.

 

·                  Review and considerfor approval all amendments or departures proposed by management from establishedstrategy, capital and operating budgets or matters of policy which diverge fromthe ordinary course of business.

 

·                  Review operatingand financial performance results relative to established strategy, budgets andobjectives.

 

 
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**Integrity / Corporate Conduct**

 

·                  Approve a communicationspolicy or policies to ensure that a system for corporate communications to allstakeholders exists, including processes for consistent, transparent, regularand timely public disclosure, and to facilitate feedback from stakeholders.

 

·                  Approve a code ofbusiness conduct and ethics for directors, officers, employees, contractors andconsultants and monitor compliance with the Practice and approve any waivers ofthe Practice for officers and directors.

 

**Board Process / Effectiveness**

 

·                Ensure that Boardmaterials are distributed to directors in advance of regularly scheduledmeetings to allow for sufficient review of the materials prior to the meeting.Directors are expected to attend all meetings.

 

·                  Engage in theprocess of determining Board member qualifications with the Nominating andCorporate Governance Committee including ensuring that a majority of directorsqualify as independent directors pursuant to National Instrument 58-101 *Disclosure of Corporate Governance Practices*(as implementedby the Canadian Securities Administrators and as amended from time to time).

 

·                  Approve thenomination of directors.

 

·                  Provide acomprehensive orientation to each new director.

 

·               Establish anappropriate system of corporate governance including practices to ensure theBoard functions independently of management.

 

·                  Establishappropriate practices for the regular evaluation of the effectiveness of theBoard, its committees and its members.

 

·                  Establishcommittees and approve their respective mandates and the limits of authoritydelegated to each committee.

 

·                  Review andre-assess the adequacy of the Audit Committee Mandate on a regular basis, butnot less frequently than on an annual basis.

 

·                  Review the adequacyand form of the directors’ compensation to ensure it realistically reflects theresponsibilities and risks involved in being a director.

 

·                  Each member of theBoard is expected to understand the nature and operations of the Corporation’sbusiness, and have an awareness of the political, economic and social trendsprevailing in all countries or regions in which the Corporation invests, or iscontemplating potential investment.

 

·                  Independentdirectors shall meet regularly, and in no case less frequently than quarterly,without non-independent directors and management participation.

 

·                In addition to theabove, adherence to all other Board responsibilities as set forth in theCorporation’s By-Laws, applicable policies and practices and other statutoryand regulatory obligations, such as approval of dividends, issuance ofsecurities, etc., is expected.

 

Approved:  November 30, 2009

 

 

 
| Cenovus  Energy Inc. Annual Information Form for the year ended December 31, 2009 |   | D-2 |
|-----------------------------------------------------------------------------------|--------|-----|

 

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Cenovus Energy Inc.

 

 

Management’sDiscussion and Analysis

For the year ended December 31,2009

(U.S. Dollars)

 

 

*This Management’s Discussion and Analysis (“MD&A”)for Cenovus Energy Inc. (“Cenovus” or “the Company”) should be read with theaudited Cenovus Energy Inc. Consolidated Financial Statements for the yearended December 31, 2009 (the “Consolidated Financial Statements”) as wellas EnCana Corporation’s**(“EnCana”)**Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. (the “InformationCircular”) dated October 20, 2009. Readers should also read the “Forward-LookingStatements” legal advisory contained at the end of this document and suchsimilar legal advisories contained in the Information Circular.*

 

*Management is responsible for preparing theMD&A, while the audit committee of the Board of Directors of Cenovus (the “Board”)reviews the MD&A and recommends its approval by the Board.*

 

*The Consolidated Financial Statements and comparative information havebeen prepared in United States (“U.S.”) dollars, except where another currencyhas been indicated, and in accordance with Canadian Generally AcceptedAccounting Principles (“GAAP”). Production and reserves volumes are presentedon an after royalties basis consistent with U.S. protocol reporting.  This document is dated February 17,2010.*

 

***Readers can find thedefinition of certain terms used in this document in the disclosure regardingOil and Gas Information and Currency, Non-GAAP Measures and References toCenovus contained in the Advisory section located at the end of this document,and such similar advisories set out in the Information Circular.***

** **

 
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**INTRODUCTION AND OVERVIEW OF CENOVUS ENERGY**

 

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Ouroperations include enhanced oil recovery (“EOR”) properties and establishedcrude oil and natural gas production in Alberta and Saskatchewan. We also haveownership interests in two refineries in Illinois and Texas, USA.

 

We began independent operations on December 1, 2009 following theArrangement with EnCana Corporation which created two independent publiclytraded energy companies – Cenovus and EnCana (the “Arrangement”). Although weare a new company, we have operated a number of assets for decades.

 

Our operations include our technology-driven EOR properties, coupled withestablished crude oil and natural gas production in Alberta andSaskatchewan.  Three of our four enhancedoil properties (Foster Creek, Christina Lake and Pelican Lake) are located inthe Athabasca region in northeast Alberta. The fourth, the Weyburn carbondioxide (“CO2”) sequestration EOR project, is located in southeasternSaskatchewan. We also have a 50 percent ownership interest in two refineries inIllinois and Texas, USA, enabling us to capture the full value from crude oilproduction through to refined products such as gasoline, diesel and jet fuel.

 

Our operational focus over the next five years will be to increaseproduction predominantly from our steam-assisted gravity drainage (“SAGD”)operations at Foster Creek and Christina Lake. We have proven our expertise andlow cost EOR development approach. Our established crude oil and natural gasproduction base is expected to generate stable production and cash flows whichwill enable further development of our core bitumen assets. In all ouroperations, whether bitumen, crude oil or natural gas, technology plays a keyrole in extracting the resource, increasing the amount recovered, reducingcosts and improving the way we extract the resources. One of our mostsignificant ongoing objectives is to advance technologies that reduce theamount of water, steam, natural gas and electricity consumed in our operationsand to minimize surface land disturbance.

 

Our future lies in developing the vast land position we hold in theAthabasca region in northeast Alberta. In addition to our Foster Creek andChristina Lake properties, we currently have two emerging properties in thisarea: Borealis and Narrows Lake. A joint application to the Energy ResourcesConservation Board and Alberta Environment for the development of Borealis hasbeen submitted for the construction of a SAGD facility with production capacityof 35,000 barrels (“bbls”) of bitumen per day. We hold a 50 percent interest inthe Narrows Lake play, through our interest in the FCCL Partnership, which islocated within the greater Christina Lake regional area.  We are preparing development plans andregulatory applications for a project at Narrows Lake that would include two tothree phases with each phase expected to add approximately 40,000 barrels perday (“bbls/d”) of bitumen production capacity.

 

We have a number of opportunities to deliver shareholder value,predominantly through production growth from our extensive bitumen resource.Most of the bitumen resource is undeveloped and the resource is currentlyexpected to assist in meeting consumer demand for decades to come. Growth atthese enhanced oil operations is expected to be internally funded through cashflow generated from our established crude oil and natural gas production base.Our natural gas production also provides a natural economic hedge for thenatural gas required as a fuel source at our upstream and downstreamoperations. Our low-cost refineries operated by ConocoPhillips, an unrelatedU.S. public company, enable us to integrate our bitumen production with thesale of refined products.

 

OURBUSINESS STRUCTURE

 

Ouroperations are organized into two operating divisions:

 

·      **IntegratedOil**Division, which includes allof the assets within the upstream and downstream integrated oil business withour joint venture partner, as well as other bitumen interests and the Athabascanatural gas assets. The Integrated Oil Division has assets in both Canada andthe U.S. including two major enhanced oil recovery properties: (i) FosterCreek; and (ii) Christina Lake; as well as two refineries: (i) WoodRiver; and (ii) Borger.

 

·      **CanadianPlains**Division, which containsestablished crude oil and natural gas development assets in Alberta andSaskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn;and 

 

 

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(ii) Pelican Lake; as well asthe Southern Alberta oil and gas properties. The division also markets Cenovus’scrude oil and natural gas, as well as third-party purchases and sales ofproduct that provide operational flexibility for transportation commitments,product type, delivery points and customer diversification.

 

Forfinancial statement reporting purposes, our operating and reportable segmentsare:

 

·      **UpstreamCanada,**which includes Cenovus’sdevelopment and production of bitumen, crude oil, natural gas and natural gasliquids (“NGLs”), and other related activities in Canada.  This includes the Foster Creek and ChristinaLake operations which are jointly owned with ConocoPhillips and operated byCenovus.

 

·      **DownstreamRefining,** which is focused on therefining of crude oil into petroleum and chemical products at two refinerieslocated in the United States. The refineries are jointly owned withConocoPhillips and operated by ConocoPhillips.

 

·      **Corporateand Eliminations,**which mainly includesunrealized gains or losses recorded on derivative financial instruments as wellas other Cenovus-wide costs for general and administrative and financingactivities.  As financial instruments aresettled, realized gains and losses are recorded in the operating segment towhich the derivative instrument relates. Eliminations relate to sales andoperating revenues and purchased product between segments recorded at transferprices based on current market prices and to unrealized intersegment profits ininventory.

 

OVERVIEW OF 2009

 

This past year washighlighted by a number of significant factors that had major influences on ouractivities and financial results. The most significant factor was the globalcredit crisis and recession which resulted in lower commodity prices,uncertainty in the financial markets and delayed our creation. However, in September 2009,with some improvement in economic conditions apparent, we were able to arrangea committed Canadian $2.5 billion bank credit facility and successfully raise$3.5 billion in unsecured notes. This allowed us to move forward with theArrangement, and on November 25, 2009, over 99 percent of the votes castby EnCana shareholders were in favour of our creation. The global recessionalso impacted commodity prices which were depressed for most of 2009; howeverwe did benefit from our natural gas and crude oil hedging program, and realized$692 million of after-tax financial hedging gains in 2009.

 

As a result of themarkets uncertainty, we increased focus on cost control and discipline in 2009through our “10 percent challenge” initiative. Through this focus on costreduction, we identified opportunities to reduce operating costs and adjust andredirect our capital program. Our reduction of capital expenditures was partlyresponsible for the nine percent decrease in natural gas production; andalthough we did reduce spending on our oil projects as well, our average dailyproduction grew 10 percent, with Foster Creek and Christina Lake productionincreasing 43 percent. Consistent with our long-term strategy to develop ourintegrated oil business, we continued with our development work at both FosterCreek and Christina Lake, as well as the Coker and Refinery Expansion (“CORE”)project at the Wood River refinery.

 

As part of thecreation of Cenovus, EnCana’s Canadian oil and gas partnership was dissolved,resulting in an acceleration of Cenovus’s share of current tax of approximately$400 million in 2009. This current tax is not added tax but are amounts whichotherwise would have been paid in 2010 had the dissolution not occurred.  This cash tax significantly reduced our CashFlow for the fourth quarter of 2009. Also, we were part of EnCana for 11 monthsof the year, and therefore our reported results for 2009 may not be typical ofthe results that we will achieve in future years as a stand-alone entity.

 

 

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In addition to theabove, the specific financial and operating highlights of 2009 are:
| · | 160 million  barrels, after royalties, of proved bitumen reserves extensions and  discoveries mainly due to projects sanctioned in the year; year over year  bitumen reserves, after royalties, grew eight percent;    |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · | Low  commodity prices reduced our revenues by 39 percent;                                                                                                                                                              |
| · | Production  from our Foster Creek and Christina Lake enhanced oil recovery properties  increased 43 percent; Foster Creek production exceeded 100,000 bbls/d (on a  100 percent basis) for the first time in December; |
| · | Operating  Cash Flows from Upstream decreased by $706 million on lower commodity prices;                                                                                                                               |
| · | Operating  Cash Flows from Downstream Refining operations increased by $551 million;                                                                                                                                   |
| · | Realized  financial hedge gains of $692 million, net of tax; (2008 – loss of $213  million, net of tax);                                                                                                          |
| · | Operating  earnings decreased by $317 million;                                                                                                                                                                         |
| · | Construction  on the CORE project at the Wood River refinery progressed to approximately 71  percent complete at the end of the year and is on schedule and on budget;                                                 |
| · | Acquisition  and divestiture activity for the year generated net proceeds of $206 million  and added additional bitumen lands at Narrows Lake; and                                                                     |
| · | Declared  and paid dividends of $151 million ($0.20 per share) in December. The  December dividend reflects an amount determined in connection with the  Arrangement based on carve-out earnings and cash flow.   |

 

OURBUSINESS ENVIRONMENT

 

Keyperformance drivers for our financial results include commodity prices, pricedifferentials, refining crack spreads as well as the U.S./Canadian dollarexchange rate. The following table shows selected market benchmark prices andforeign exchange rates to assist in understanding our financial results:

 
| ** **                                                    | ** ** | ** ** | ** ** | **2009 vs** | ** ** |   |   | 2008 vs |   |   |   |
|---------------------------------------------------------------|------------|------------|------------|-------------|------------|--------|--------|---------|--------|--------|--------|
| (Average for the year)                                        | ** ** | **2009**   | ** ** | **2008**    | ** ** | 2008   |   | 2007    |   | 2007   |   |
| **Crude  Oil Price***($/bbl)*                                 | ** ** |       |       |        |       |   |   |    |   |   |   |
| West Texas  Intermediate (WTI)                                | ** ** | **62.09**  | ** ** | **-38%**    |       | 99.75  |   | 38%     |   | 72.41  |   |
| Western Canadian  Select (WCS)                                | ** ** | **52.43**  | ** ** | **-34%**    |       | 79.70  |   | 61%     |   | 49.50  |   |
| Differential -  WTI/WCS                                       | ** ** | **9.66**   | ** ** | **-52%**    |       | 20.05  |   | -12%    |   | 22.91  |   |
| WCS as % of WTI                                               | ** ** | **84%**    | ** ** | ** **  |       | 80%    |   |    |   | 68%    |   |
| **Refining  Margin 3-2-1 Crack Spread******(1) *($/bbl)* | ** ** | ** ** | ** ** | ** **  |       |   |   |    |   |   |   |
| Chicago                                                       | ** ** | **8.54**   | ** ** | **-24%**    |       | 11.22  |   | -37%    |   | 17.67  |   |
| Midwest Combined  (“Group 3”)                       | ** ** | **8.09**   | ** ** | **-27%**    |       | 11.03  |   | -42%    |   | 19.11  |   |
| **Natural  Gas Price**                                        |       |       | ** ** | ** **  |       |   |   |    |   |   |   |
| AECO *(C$/Mcf)*                                               | ** ** | **4.19**   | ** ** | **-48%**    |       | 8.13   |   | 23%     |   | 6.61   |   |
| NYMEX *($/MMBtu)*                                             | ** ** | **3.99**   | ** ** | **-56%**    |       | 9.04   |   | 32%     |   | 6.86   |   |
| Basis Differential  - AECO/NYMEX *($/MMBtu)*                  | ** ** | **0.40**   | ** ** | **-67%**    |       | 1.23   |   | 64%     |   | 0.75   |   |
| **Average  Foreign Exchange**                                 | ** ** | ** ** | ** ** | ** **  |       |   |   |    |   |   |   |
| Average  U.S./Canadian Dollar Exchange Rate                   | ** ** | **0.876**  | ** ** | **-7%**     |       | 0.938  |   | 1%      |   | 0.930  |   |

 

(1)          3-2-1 Crack Spread is an indicator ofthe refining margin generated by converting three barrels of crude oil into twobarrels of gasoline and one barrel of ultra low sulphur diesel.

 

 

Afterreaching record highs in July of 2008, the price of WTI decreased over theremainder of the year to a closing price of $44.60 per bbl at December 31,2008. However, by December 31, 2009, WTI had increased to $79.36 per bblon signs of an economic recovery and production discipline by OPEC. Consistentwith the increase in WTI, WCS increased 103 percent from December 31, 2008to December 31, 2009. During 2009, the average differential between WTIand WCS narrowed to less than $10 per bbl for the year as WCS averaged 84percent of WTI.

 

During 2009,U.S. refining crack spreads reflected lower consumer demand, in response to thedepressed economy. This reduction in U.S. demand occurred during an overallincrease in global refinery capacity.

 

 

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2009 was thesecond consecutive annual decline in the consumption of refined products in theUnited States which resulted in lower prices for refined products and narrowingcrack spreads.

 

Throughout2009, natural gas prices in North America declined due to a combination of lowdemand in response to economic conditions and an increase in supply as newprolific shale gas plays began production and associated drilling commitmentswere completed. The result was above average volumes in storage during 2009 whichdecreased the price for natural gas. Cold weather during the latter part of 2009, particularly in the easternUnited States, helped the AECO price at December 31, 2009 increase fromearlier lows of $2.56 per Mcf to $5.25 per Mcf but still remained below lastyear’s year end level.

 

Our riskmitigation strategy has reduced our exposure to commodity price volatilitythrough our hedging program. Further information regarding this program can befound in the Risk Management section of this MD&A and the notes to theConsolidated Financial Statements.

 

**ANNUAL FINANCIAL INFORMATION**

 

TheConsolidated Financial Statements include the results for the period from January 1to November 30, 2009 (prior to the start of our independent operations on December 1,2009) in addition to the results for the period from December 1 to December 31,2009. The historical consolidated financial information prior to December 1,2009 has been derived from the accounting records of EnCana using thehistorical results of operations and historical basis of assets and liabilitiesof the businesses subsequently transferred to Cenovus on a carve-out accountingbasis. Further details are provided in the notes to the Consolidated FinancialStatements.

 

SELECTED ANNUAL CONSOLIDATEDFINANCIAL RESULTS

** **
|                                         | ** ** | ** ** |       | **2009 vs** |     |   |   | 2008 vs  |   |    |   |
|----------------------------------------------|------------|------------|------------|-------------|----------|--------|--------|----------|--------|---------|--------|
| ($ millions,  except per share amounts) | ** ** | **2009**   | ** ** | **2008**    |     | 2008   |   | 2007     |   | 2007    |   |
| Revenues, Net of  Royalties                  | ** ** | **$**      | **10,140** | ** **  | **-39%** |   | $      | 16,559   |   | 24**%** |   | $ | 13,406 |   |
| Operating Cash  Flow (1)                     | ** ** | **3,695**  | ** ** | **-4%**     |     | 3,850  |   | -11**%** |   | 4,344   |   |
| Cash Flow (1)                                | ** ** | **2,472**  | ** ** | **-20%**    |     | 3,088  |   | -13**%** |   | 3,536   |   |
| - per share –  diluted (2)              | ** ** | **3.29**   | ** ** | ** **  |     | 4.11   |   |     |   | 4.62    |   |
| Operating Earnings  (1)                      | ** ** | **1,312**  | ** ** | **-19%**    |     | 1,629  |   | -10%     |   | 1,802   |   |
| - per share –  diluted (2)              | ** ** | **1.74**   | ** ** | ** **  |     | 2.17   |   |     |   | 2.36    |   |
| Net Earnings                                 | ** ** | **648**    | ** ** | **-73%**    |     | 2,368  |   | 69%      |   | 1,404   |   |
| - per share –  basic (2)                | ** ** | **0.86**   | ** ** | ** **  |     | 3.16   |   |     |   | 1.87    |   |
| - per share –  diluted (2)              | ** ** | **0.86**   |       |        |     | 3.15   |   |     |   | 1.84    |   |
| Total Assets                                 | ** ** | **20,552** | ** ** | **11%**     |     | 18,466 |   | -12%     |   | 20,987  |   |
| Total Long-Term  Debt                        | ** ** | **3,493**  | ** ** | **15%**     |     | 3,036  |   | -18%     |   | 3,690   |   |
| Other Long-Term  Obligations                 | ** ** | **6,043**  | ** ** | **1%**      |     | 5,968  |   | -7%      |   | 6,437   |   |
| Capital  Expenditures                        | ** ** | **1,892**  | ** ** | **-8%**     |     | 2,046  |   | 39%      |   | 1,475   |   |
| Free Cash Flow (1)                           | ** ** | **580**    | ** ** | **-44%**    |     | 1,042  |   | -49%     |   | 2,061   |   |
| Cash Dividends (3)                           | ** ** | **151**    |       |        |     | -      |   |     |   | -       |   |
|                                              |            |            |            |             |          |        |        |          |        |         |        |  |  |  |

 

(1)          Non-GAAP measures which are definedwithin this MD&A.

(2)          Any per share amounts prior toDecember 1, 2009 have been calculated using EnCana’s common share balancesbased on the terms of the Arrangement where EnCana shareholders received onecommon share of Cenovus and one common share of the new EnCana.

(3)          We declared and paid a dividend of$0.20 per share in December 2009. The December dividend reflects an amount determined in connectionwith the Arrangement based on carve-out earnings and cash flow.

 

 

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REVENUEVARIANCE

 

 
| ($ millions)                   |               |       |       |
|-------------------------------------|--------------------|------------|------------|
| 2008 Revenue, Net  of Royalties     | $                  | 16,559     |       |
| Upstream                            | Price              | (2,138     | )          |
|                                | Realized hedging   | 1,328      |       |
|                                | Volume             | (15        | )          |
|                                | Other (1)          | (549       | )          |
| Downstream                          |               | (3,731     | )          |
| Corporate                           | Unrealized hedging | (1,366     | )          |
|                                | Other              | 52         |       |
| **2009  Revenue, Net of Royalties** | **$**              | **10,140** | ** ** |

 

(1) Revenue dollars reported include the value ofcondensate sold as heavy oil blend. Condensate costs are recorded intransportation and selling expense.

 

Total Revenues, Netof Royalties decreased $6,419 million in 2009 compared to 2008 primarily as aresult of lower average commodity prices, consistent with decreased benchmarkprices for 2009.

 

OPERATING CASH FLOW

 
| ($ millions)                | ** ** | **2009**  |      | 2008   |   | 2007   |   |
|----------------------------------|------------|-----------|-----------|--------|--------|--------|--------|
| Crude Oil and NGLs               |       |      |      |   |   |   |   |
| Foster Creek and  Christina Lake | ** ** | **$**     | **596**   |   | $      | 421    |   | $ | 213 |   |
| Canadian Plains                  | ** ** | **941**   |      | 1,508  |   | 946    |   |
| Natural Gas                      | ** ** | **1,798** |      | 2,099  |   | 2,049  |   |
| Other Upstream  Operations       | ** ** | **50**    |      | 63     |   | 62     |   |
|                             | ** ** | **3,385** |      | 4,091  |   | 3,270  |   |
| Downstream                       | ** ** | **310**   |      | (241)  |   | 1,074  |   |
| Operating Cash  Flow             | ** ** | **$**     | **3,695** |   | $      | 3,850  |   | $ | 4,344 |   |

 

Operating Cash Flowis a non-GAAP measure defined as Revenue, Net of Royalties less production andmineral taxes, transportation and selling, operating and purchased productexpenses and is used to provide a consistent measure of the cash generatingperformance of our assets and improves the comparability of our underlyingfinancial performance between periods.

 

In total, OperatingCash Flow from our Upstream and Downstream segments decreased by $155 million.Detail of the components that explain changes to Operating Cash Flow from 2008can be found in the Divisional Results section of this MD&A.

 

CASHFLOW

 

Cash Flow is anon-GAAP measure defined as cash from operating activities excluding net changein other assets and liabilities and net change in non-cash workingcapital.  Cash Flow is commonly used inthe oil and gas industry to assist in measuring the ability to finance capitalprograms and meet financial obligations.

 

 
| ($ millions)                           | ** ** | **2009**  |      | 2008   |   | 2007   |   |
|---------------------------------------------|------------|-----------|-----------|--------|--------|--------|--------|
| Cash From  Operating Activities             | ** ** | **$**     | **3,496** |   | $      | 2,687  |   | $ | 3,014 |   |
| (Add back) deduct:                          |       |      |      |   |   |   |   |
| Net change in  other assets and liabilities | ** ** | **(23)**  |      | (89)   |   | (48)   |   |
| Net change in  non-cash working capital     | ** ** | **1,047** |      | (312)  |   | (474)  |   |
| Cash Flow                                   | ** ** | **$**     | **2,472** |   | $      | 3,088  |   | $ | 3,536 |   |

 

 

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Our Cash Flowdecreased to $2,472 million in 2009, a decrease of $616 million from 2008($3,088 million). The decrease was the result of:

·                  Decrease inthe average natural gas price, excluding financial hedging, of $4.16 per Mcf or54 percent from 2008;

·                  Decrease inthe average liquids selling price, excluding financial hedging, of $23.13 perbbl, or 31 percent, from 2008;

·                  Current taxincreased $513 million primarily due to accelerated income tax as a result ofthe dissolution of a partnership as part of the Arrangement; and

·                  Decline ofnine percent in our production of natural gas.

 

The decreases in our2009 Cash Flow were offset by:

·                  Realizedfinancial hedging gains of $692 million, after tax, compared to realizedhedging losses of $213 million, after tax, in 2008;

·                  Animprovement in our operating cash flow from downstream operations of $551million;

·                  A decrease inour transportation and selling and operating expenses of $360 million; and

·                  10 percentincrease in our crude oil and NGLs production volumes compared to 2008.

 

Our Cash Flow in 2008of $3,088 million was lower than 2007 Cash Flow of $3,536 million by $448million, primarily due to:

·                  Operatingcash flows from downstream operations decreased $1,315 million primarily due toweaker refining margins and higher purchased product costs;

·                  Realizedfinancial crude oil, natural gas and other commodity hedging losses of $213million after-tax in 2008, compared to gains of $97 million after-tax in 2007;

·                  Natural gasproduction volumes in 2008 decreased six percent compared to 2007; and

·                  Increases intransportation and selling, operating, interest and general and administrativeexpenses.

 

The decreases in our2008 Cash Flow were offset by:

·                  Higheraverage natural gas prices, excluding financial hedges, of $7.76 per Mcf in2008 compared to $6.08 per Mcf in 2007; and

·                  Higheraverage liquids prices, excluding financial hedges of $74.00 per bbl in 2008compared to $46.69 per bbl in 2007.

 

OPERATINGEARNINGS

 

 
| ($ millions)                                                | ** ** | **2009**  |      | 2008   |   | 2007   |   |
|------------------------------------------------------------------|------------|-----------|-----------|--------|--------|--------|--------|
| Net Earnings, as  reported                                       | ** ** | **$**     | **648**   |   | $      | 2,368  |   | $ | 1,404 |   |
| Add back (losses)  and deduct gains:                             |       |      |      |   |   |   |   |
| Unrealized  mark-to-market accounting gain (loss), after-tax (1) | ** ** | **(473)** |      | 519    |   | (244)  |   |
| Non-operating  foreign exchange gain (loss), after-tax (2)       | ** ** | **(191)** |      | 220    |   | (301)  |   |
| Future tax  recovery due to tax rate reductions                  | ** ** | **-**     |      | -      |   | 147    |   |
| Operating Earnings                                               | ** ** | **$**     | **1,312** |   | $      | 1,629  |   | $ | 1,802 |   |

 

(1)          The unrealized mark-to-marketaccounting gains (losses), after-tax includes the reversal of unrealized gains(losses) recognized in prior periods. The realized gains (losses), after-tax represents the recording of thefinal settlement of hedge positions.

(2)          After-tax unrealized foreign exchangegains (losses) on translation of U.S. dollar denominated debt issued fromCanada and the partnership contribution receivable, after-tax realized foreignexchange gains (losses) on settlement of intercompany transactions and futureincome tax on foreign exchange recognized for tax purposes only related to U.S.dollar intercompany debt.

 

Operating Earningsis a non-GAAP measure defined as Net Earnings excluding non-operating itemsincluding the after-tax effect of unrealized mark-to-market accounting gains(losses) on derivative instruments, after-tax gains (losses) on translation ofU.S. dollar denominated debt issued from Canada and the partnership contributionreceivable, after-tax foreign exchange gains (losses) on settlement ofintercompany transactions, future income tax on foreign exchange recognized fortax purposes only related to U.S. dollar intercompany debt and the effect ofchanges in statutory income tax rates.

 

 

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We believe thatthese non-operating items reduce the comparability of our underlying financialperformance between periods. The above reconciliation of Operating Earnings hasbeen prepared to provide information that is more comparable between periods.The items identified above that affected our Cash Flow and below that affectedour Net Earnings also impacted our Operating Earnings.

 

NETEARNINGS

 

Net Earnings in 2009of $648 million were $1,720 million lower compared to 2008.  The items identified above that affected our2009 Cash Flow also impacted Net Earnings. Other significant factors thatreduced our 2009 Net Earnings included an unrealized mark-to-market loss of$667 million, compared to a $734 million gain in 2008 and unrealized foreignexchange loss of $313 million in 2009 compared to a gain in 2008 of $259million.  These reductions to NetEarnings and the increased current tax, which impacted Cash Flow, were offsetby a recovery of future income tax in 2009 of $551 million, compared to afuture income tax expense of $385 million in 2008.

 

Our Net Earnings in2008 were $2,368 million, which were $964 million higher than Net Earnings of$1,404 million in 2007. The items identified above that affected our 2008 CashFlow also impacted Net Earnings. Other significant factors that increased our2008 Net Earnings included an unrealized mark-to-market gain, after-tax, of$519 million, compared to a $244 million loss in 2007, non-operating foreignexchange gains of $220 million, after-tax, in 2008 compared to losses of $301million after-tax in 2007 as well as a $108 million decrease in depreciation,depletion and amortization.

 

As a means ofmanaging the volatility of commodity prices, we enter into various financialinstrument agreements. Changes in the mark-to-market gain or loss on theseagreements affect our Net Earnings and are the result of volatility in theforward commodity prices and changes in the balance of unsettled contracts. Our2009 and 2008 Net Earnings benefitted overall from this program, while in 2007,we reported a reduction in Net Earnings from our hedging program. The followinginformation has been provided in order to provide information that is morecomparable between periods:

 
| ($ millions)                                       | ** ** | **200** | **9**    | 200    | 8 | 200 | 7      |
|---------------------------------------------------------|------------|---------|----------|--------|---|-----|--------|
| Unrealized  Mark-to-Market Gains (Losses), after-tax(1) | ** ** | **$**   | **(473** | **)**  | $ | 519 |   | $ | (244 | ) |
| Realized  Hedging Gains (Losses), after-tax (2)         | ** ** | **692** |     | (213   | ) | 97  |   |
| Hedging  Impacts on Net Earnings                        | ** ** | **$**   | **219**  |   | $ | 306 |   | $ | (147 | ) |

 

(1)   Included inCorporate financial results.  Furtherdetail on unrealized mark-to-market gains (losses) can be found in theCorporate and Eliminations section of this MD&A.

(2)   Included inDivisional financial results.

 

NET CAPITALINVESTMENT

 
| ($ millions)          | ** ** | **2009**  |      | 2008   |   | 2007  |   |
|----------------------------|------------|-----------|-----------|--------|--------|-------|--------|
| Integrated Oil -  Upstream | ** ** | **$**     | **476**   |   | $      | 644   |   | $ | 450 |   |
| Canadian Plains            | ** ** | **478**   |      | 872    |   | 795   |   |
| Downstream  Refining       | ** ** | **907**   |      | 478    |   | 220   |   |
| Other                      | ** ** | **31**    |      | 52     |   | 10    |   |
| Capital Investment         | ** ** | **1,892** |      | 2,046  |   | 1,475 |   |
| Acquisitions               | ** ** | **3**     |      | -      |   | 14    |   |
| Divestitures               | ** ** | **(209)** |      | (47)   |   | -     |   |
| Net Capital  Investment    | ** ** | **$**     | **1,686** |   | $      | 1,999 |   | $ | 1,489 |   |

 

Capitalinvestment in 2009 was primarily focused on the continued development of ourEOR properties (Foster Creek, Christina Lake, Pelican Lake and Weyburn) and theexpansion of our downstream heavy oil refining capacity. During 2009, part ofthe reduction in our capital investment reflected our internal “10 percentchallenge”, as we scrutinized our spending in an effort to reduce costs.Capital investment for each of 2009, 2008 and 2007 was funded by Cash Flow.Further information regarding our capital investment can be found in the DivisionalResults section of this MD&A.

 

 

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Acquisitionsand Divestitures

 

In 2009, acquisitionand divestiture activity resulted in net proceeds of $206 million from variousdivestitures, including the sale of the Senlac heavy oil assets, a farm-outtransaction and one minor acquisition.

 

Our acquisitions anddivestitures in 2009 also included a property swap under the terms of which weacquired strategic bitumen lands at Narrows Lake in exchange for certainnon-core lands.

 

FREE CASH FLOW

 

In order to determine the funds available for financing andinvesting activities, including dividend payments, we use a non-GAAP measure ofFree Cash Flow, which is defined as Cash Flow in excess of Capital Investment,excluding acquisitions and divestitures. Cash Flow is a non-GAAP measure and isdefined under the Cash Flow section of this MD&A.

 

In 2009, our Free Cash Flow was $580million, which was $462 million lower than our Free Cash Flow of $1,042 millionin 2008(2007 - $2,061 million) primarily due to lower cash flow, partially offset byless capital investment during the year. Additional explanationsfor the decrease in total Cash Flow and Capital Investment are discussed underthe Cash Flow, Net Capital Investment and Divisional Results sections of thisMD&A.

 
| ($ millions)  | ** ** | **2009**     |      | 2008   |     | 2007  |   |
|--------------------|------------|--------------|-----------|--------|----------|-------|--------|
| Cash Flow          | ** ** | **  $** | **2,472** |   |   $ | 3,088 |   |   $ | 3,536 |   |
| Capital Investment | ** ** | **1,892**    |      | 2,046  |     | 1,475 |   |
| Free Cash Flow     | ** ** | **  $** | **580**   |   |   $ | 1,042 |   |   $ | 2,061 |   |

 

FOREIGN EXCHANGE

 

As disclosed in theBusiness Environment section of this MD&A, the average U.S./Canadian dollarexchange rate was lower in 2009 than both 2008 and 2007. The table belowsummarizes the impact of the lower foreign exchange rate on reported amountswhen compared to the prior years.

 
|                                        | ** ** | **2009** |        | 2008   |   | 2007   |   |
|---------------------------------------------|------------|----------|-------------|--------|--------|--------|--------|
| Average  U.S./Canadian Dollar Exchange Rate | ** ** | **$**    | **0.876**   |   | $      | 0.938  |   | $ | 0.930 |   |
| Dollar Change from  prior year              | ** ** | **$**    | **(0.062)** |   | $      | 0.008  |   | $ | 0.048 |   |
| Percentage change  from prior year          | ** ** | **-7%**  |        | 1%     |   | 5%     |   |
| ($ millions)                           |       |     |        |   |   |   |   |
| Increase  (decrease) in:                    |       |     |        |   |   |   |   |
| Capital Investment                          | ** ** | **$**    | **(82)**    |   | $      | (12)   |   | $ | 80 |   |
| Operating Expense                           | ** ** | **(46)** |        | 7      |   | 40     |   |
| Administrative  Expense                     | ** ** | **(9)**  |        | 1      |   | 6      |   |
| DD&A Expense                            | ** ** | **(82)** |        | 13     |   | 73     |   |

 

The U.S. to Canadiandollar exchange rate strengthened from a December 31, 2008 spot rate of$0.824 to a December 31, 2009 spot rate of $0.955. The $0.131 increaseresulted in a Foreign Currency Translation Adjustment of $2.0 billion, net oftax for 2009 which increased our Comprehensive Income.  As the U.S. to Canadian dollar exchange rateweakened from a rate of $1.007 at December 31, 2007 to $0.824 at December 31,2008 our Foreign Currency Translation Adjustment for 2008 reduced ourComprehensive Income by $2.2 billion, net of tax.

 

 

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**RESULTS OF OPERATIONS**

 

Crude Oil and NGLs Production Volumes

 
|                    | ** ** | ** **  | ** ** | **2009 vs** |   |    |   | 2008 vs |   |          |   |
|-------------------------|------------|-------------|------------|-------------|--------|---------|--------|---------|--------|---------------|--------|
| ** **              | ** ** | **2009**    |       | **2008**    |   | 2008    |   | 2007    |   | 2007     |   |
| Crude  Oil *(bbls/d)*   |       |        |       |        |   |    |   |    |   |          |   |
| Foster Creek            | ** ** | **36,654**  | ** ** | **41%**     |   | 25,947  |   | 7%      |   | 24,262   |   |
| Christina Lake          | ** ** | **6,527**   | ** ** | **54%**     |   | 4,236   |   | 66%     |   | 2,552    |   |
| Weyburn                 | ** ** | **14,948**  | ** ** | **7%**      |   | 14,031  |   | -5%     |   | 14,771   |   |
| Pelican Lake            | ** ** | **20,105**  | ** ** | **-9%**     |   | 21,975  |   | -5%     |   | 23,253   |   |
| Southern Alberta        | ** ** | **22,406**  | ** ** | **-7%**     |   | 24,153  |   | -10%    |   | 26,776   |   |
| Integrated Oil - Other  | ** ** | **2,553**   | ** ** | **-6%**     |   | 2,729   |   | 2%      |   | 2,688    |   |
| Canadian Plains - Other | ** ** | **5,405**   | ** ** | **-10%**    |   | 5,998   |   | -2%     |   | 6,139    |   |
| NGLs *(bbls/d)*         | ** ** | **1,186**   | ** ** | **-%**      |   | 1,181   |   | -6%     |   | 1,260    |   |
| ** **              | ** ** | **109,784** |       | **10%**     |   | 100,250 |   | -1%     |   | 101,701  |   |

 

Production volumes at Foster Creek and Christina Lakeincreased in 2009 as a result of the commissioning and ramp up of new expansionphases at each property, slightly offset by higher royalty rates as a result ofthe new Alberta royalty framework (effective January 1, 2009), whichreduced the production volumes. Weyburn production increased from 2008 to 2009as a result of well optimizations and lower royalties. The decrease inproduction at Pelican Lake for 2009 was a result of natural production declinesand a scheduled facility turnaround partially offset by fewer operationalissues at the facility. Crude oil production from Southern Alberta decreased in2009 compared to 2008 due to expected natural declines partially offset bylower royalty rates and production from new wells.

 

Natural Gas Production Volumes

 
|                    |       |     | ** ** | **2009 vs** | ** ** | ** ** |   | 2008 vs |   |       |   |
|-------------------------|------------|----------|------------|-------------|------------|------------|--------|---------|--------|------------|--------|
| Natural Gas *(MMcf/d)*  | ** ** | **2009** | ** ** | **2008**    |       | 2008       |   | 2007    |   | 2007  |   |
| Southern Alberta        | ** ** | **739**  | ** ** | **-8%**     |       | 800        |   | -4%     |   | 832   |   |
| Canadian Plains - Other | ** ** | **36**   | ** ** | **-14%**    |       | 42         |   | -2%     |   | 43    |   |
| Integrated Oil - Other  | ** ** | **49**   | ** ** | **-22%**    |       | 63         |   | -31%    |   | 91    |   |
|                    | ** ** | **824**  | ** ** | **-9%**     |       | 905        |   | -6%     |   | 966   |   |

 

The decline in Southern Alberta natural gas production in2009 compared to 2008 was the result of expected natural production declinesand capacity restrictions in response to the lower commodity price.  These production decreases were partiallyoffset by a slight reduction in the royalty rates as a result of decliningprices.

 

OperatingNetbacks

 
|                                          | ** ** | **2009**                                       |       | 2008                                                |   | 2007                                 |   |
|-----------------------------------------------|------------|------------------------------------------------|------------|-----------------------------------------------------|--------|--------------------------------------|--------|
|                                          | ** ** | **Liquids**                                    | ** ** | **Natural  Gas**                                    |   | Liquids                              |   | Natural  Gas |   | Liquids |   | Natural  Gas |   |
|                                          |       | ($/bbl)                                        |       | ($/Mcf)                                             |   | ($/bbl)                              |   | ($/Mcf) |   | ($/bbl) |   | ($/Mcf) |   |
| Price                                         | ** ** | **$    50.87  ** | ** ** | **$     3.60  ** |   | $   74.00   |   | $    7.76   |   | $  46.69   |   | $     6.08  |   |
| Expenses                                      | ** ** | ** **                                     | ** ** | ** **                                          |   |                                 |   |   |   |   |   |   |   |
| Production and mineral taxes                  | ** ** | **0.62  **                           | ** ** | **0.04  **                                |   | 1.08                       |   | 0.11   |   | 0.76   |   | 0.10  |   |
| Transportation and selling                    | ** ** | **1.55  **                           | ** ** | **0.14  **                                |   | 1.71                       |   | 0.24   |   | 1.72   |   | 0.27  |   |
| Operating                                     | ** ** | **10.41  **                          | ** ** | **0.76  **                                |   | 11.59                      |   | 0.84   |   | 10.27   |   | 0.74  |   |
| Netback excluding Realized Financial  Hedging | ** ** | **38.29  **                          | ** ** | **2.66  **                                |   | 59.62                      |   | 6.57   |   | 33.94   |   | 4.97  |   |
| Realized Financial Hedging Gain  (Loss)       | ** ** | **0.98  **                           | ** ** | **3.22  **                                |   | (6.07)                          |   | (0.30)  |   | (3.40)  |   | 0.75  |   |
| Netback including Realized Financial  Hedging | ** ** | **$    39.27  ** | ** ** | **$     5.88  ** |   | $   53.55   |   | $    6.27   |   | $  30.54   |   | $     5.72  |   |

 

 

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Our average netbackfor both liquids and natural gas (excluding realized financial hedging) waslower in 2009 primarily as a result of lower average prices for the year,consistent with the reduction in benchmark prices.

 

As part of ongoingefforts to maintain financial resilience and flexibility, we reduced ourpricing risk through a commodity price hedging program. In 2009, our hedgingprogram added $0.98 per bbl of liquids and $3.22 per Mcf of natural gas.Further information regarding this program can be found in the Risk Managementsection of this MD&A and the notes to the Consolidated FinancialStatements.

 

**DIVISIONAL RESULTS**

 

Our Upstream Canada segment includes the upstream activitiesof the Integrated Oil Division and the Canadian Plains Division. Our DownstreamRefining segment includes the Downstream Refining business of the IntegratedOil Division.

 

**INTEGRATED OIL DIVISION**

 

We are a 50 percent partner in an integrated North Americanoil business with ConocoPhillips that consists of an upstream and a downstreamentity.  The upstream entity includes theFoster Creek and Christina Lake oil properties in northeast Alberta, while thedownstream entity includes the Wood River and Borger refineries located inIllinois and Texas, USA, respectively.

 

FOSTER CREEK AND CHRISTINA LAKE

 

Financial Results

 
| ($ millions)                                 | ** ** | **2009**                                                       |   | 2008   |   | 2007  |   |
|---------------------------------------------------|------------|----------------------------------------------------------------|--------|--------|--------|------------|--------|
| Revenues, Net of Royalties and  excluding hedging | ** ** | **$     1,165**                       |   | $      | 1,184  |       | $      | 781  |   |
| Realized Financial Hedging Gain  (Loss)           | ** ** | **37**                                                         |   | (67)   |   | (43)  |   |
| Expenses                                          | ** ** | ** **                                                     |   |   |   |       |   |
| Transportation and selling                        | ** ** | **430**                                                        |   | 526    |   | 366   |   |
| Operating                                         | ** ** | **176**                                                        |   | 170    |   | 159   |   |
| Operating Cash Flow                               | ** ** | **$         596** |   | $      | 421    |       | $      | 213  |   |

 

Production Volumes

 
|                     | ** ** | ** ** | ** ** | **2009 vs** |   |   |   | 2008 vs  |   |         |   |
|--------------------------|------------|------------|------------|-------------|--------|--------|--------|---------------|--------|--------------|--------|
| Heavy Crude Oil (bbls/d) | ** ** | **2009**   | ** ** | **2008**    |   | 2008   |   | 2007          |   | 2007    |   |
| Foster Creek             | ** ** | **36,654** | ** ** | **41%**     |   | 25,947 |   | 7%            |   | 24,262  |   |
| Christina Lake           | ** ** | **6,527**  | ** ** | **54%**     |   | 4,236  |   | 66%           |   | 2,552   |   |
|                     | ** ** | **43,181** | ** ** | **43%**     |   | 30,183 |   | 13%           |   | 26,814  |   |

 

Revenue Variance

 
|                            |   | 2008 Revenues | ** **                          | Revenue       | ** ** | **2009 Revenues** | ** ** |
|---------------------------------|--------|---------------|-------------------------------------|---------------|------------|-------------------|------------|
|                            |   | Net of        | ** **                          | Variances in: | ** ** | **Net of**        | ** ** |
| ($ millions)               |   | Royalties     |                                | Price(1)      |       | Volume            |       | Other(2) | ** ** | **Royalties** | ** ** |
| Foster Creek and Christina Lake |   | $             | 1,117      |          | $          | (94)              |       | $ | 286 |   | $ | (107) | ** ** | **$** | **1,202  ** | ** ** |
|                                 |        |               |                                     |               |            |                   |            |  |  |  |  |  |  |  |  |  |

(1)  Includesthe impact of realized financial hedging.

(2)  Revenuedollars reported include the value of condensate sold as bitumen blend.  Condensate costs are  recorded in transportation and sellingexpense.

 

 

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Revenues, net of royalties, excluding realized financialhedging, decreased $19 million in 2009 compared to 2008 as a result of loweraverage crude oil prices offset by an increase in crude oil production of 43percent. During 2009, financial hedging activities realized a gain of $37million ($2.35 per bbl) compared to a loss of $67 million ($6.11 per bbl) in2008 (2007 – loss of $43 million; $3.88 per bbl).

 

Our average crude oil sales price decreased 20 percent to$49.71 per bbl in 2009 from $62.44 per bbl in 2008 primarily due to a 38percent decrease in average WTI prices over the year offset somewhat by thenarrowing of the WCS differential.

 

Production at Foster Creek increased 41 percent in 2009compared to 2008 as a result of production from the phase C and D/E expansions,as well as additional production from wedge wells, offset slightly by higherroyalty rates.  Production from phase C reachedcapacity of 60,000 bbls/d in the third quarter of 2008.  Production from the phase D/E expansioncommenced late in the first quarter of 2009 and ramped up throughout the year.

 

Production at Christina Lake increased 54 percent in 2009compared to 2008 as a result of higher production from the phase B expansionwhich commenced production in the second quarter of 2008 slightly offset byhigher royalty rates in 2009.

 

Transportation and selling costs are comprised mostly ofcondensate costs, as blending condensate with bitumen enables the product to betransported. During 2009, condensate volumes increased due to the higherproduction noted above, offset by a 45 percent decrease in the average price ofcondensate used for blending. This resulted in a reduction of transportationand selling costs to $430 million in 2009 from $526 million in 2008 (2007 -$366 million).

 

Operating costs in 2009 increased slightly to $176 millioncompared to $170 million in 2008 due to the significant increase in volumescombined with additional repairs and maintenance and a scheduled turnaround atChristina Lake in the fall of 2009. The increase in operating costs was offsetby lower fuel costs due to declining natural gas prices as well as highervolumes of Athabasca natural gas production being used internally at FosterCreek, requiring less fuel to be purchased in the market.

 

DOWNSTREAM REFINING

 

Financial Results

 
| ($ millions)   | ** ** | **2009**                                                                   | ** ** | 2008                                                               |   | 2007   | ** **  |
|---------------------|------------|----------------------------------------------------------------------------|------------|--------------------------------------------------------------------|--------|-------------|-------------|
| Revenues            | ** ** | **$       5,280**                       |       | $        9,011             |   | $           | 7,315  |   |
| Expenses            |       |                                                                       |       |                                                               |   |        |        |
| Operating           | ** ** | **453**                                                                    |       | 492                                                                |   | 428    |        |
| Purchased product   | ** ** | **4,517**                                                                  |       | 8,760                                                              |   | 5,813  |        |
| Operating Cash Flow | ** ** | **$           310** |       | $          (241) |   | 1,074  |        |
|                     |            |                                                                            |            |                                                                    |        |             |             |  |

 

Refinery Operations (1)

 
| ** **                     | ** ** | **2009** | ** ** | 2008 |   | 2007  | ** ** |
|--------------------------------|------------|----------|------------|------|--------|------------|------------|
| Crude oil capacity *(Mbbls/d)* | ** ** | **452**  |       | 452  |   | 452   |       |
| Crude oil runs *(Mbbls/d)*     | ** ** | **394**  |       | 423  |   | 432   |       |
| Crude utilization *(%)*        | ** ** | **87**   |       | 93   |   | 96    |       |
| Refined products *(Mbbls/d)*   | ** ** | **417**  |       | 448  |   | 457   |       |

 

(1) Represents 100% of the Wood Riverand Borger refinery operations.

 

On a 100 percent basis, our refineries have a currentcapacity of approximately 452,000 bbls/d of crude oil and 45,000 bbls/d ofNGLs, as well as processing capability to refine approximately 145,000 bbls/dof heavy crude oil (approximately 70,000 bbls/d of bitumen equivalent). Uponcompletion of the Wood River CORE project in 2011 we expect to be able torefine approximately 275,000 bbls/d (on a 100 percent basis) of heavy crude oil(approximately 150,000 bbls/d of bitumen equivalent) primarily into motorfuels.

 

 

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During 2009, our refineries operated at an average of 87percent of their capacity compared to 93 percent in 2008. Utilization was lowerin 2009 primarily due to refinery optimization based on weakened market crackspreads, increased number of turnarounds at Wood River to advance the COREproject and unplanned maintenance at both refineries.

 

Revenues have decreased 41 percent and purchased product hasdecreased 48 percent in 2009, consistent with the decrease in crude oil prices.Purchased product, consisting mainly of crude oil, represented 91 percent oftotal expenses in 2009 compared to 95 percent in 2008. Operating costs, consistingmainly of labour, utilities and supplies, decreased eight percent in 2009 dueto lower prices for electricity and fuel gas consumed at the refineries.

 

Operating Cash Flow for 2009 was $551 million higher than2008 mainly due to lower purchased product costs more than offsetting lowerrefined product sales. The increase was partially offset by lower refineryutilization.

 

INTEGRATED OIL DIVISION - OTHER PROPERTIES

 

The Integrated Oil Division also manages our 100 percentowned natural gas operations in Athabasca. For 2009, natural gas productionvolumes from Athabasca decreased to 49 MMcf/d (2008 – 63 MMcf/d; 2007 – 91MMcf/d) primarily as a result of increased usage of natural gas as a source offuel for the Foster Creek operations as well as natural declines.

 

In November 2009, we sold our Senlac heavy oil assetsfor proceeds of approximately $83 million. Prior to the divestiture, Senlacproduction was 2,553 bbls/d in 2009 compared to 2,729 bbls/d in 2008 (2007 –2,688 bbls/d).

 

INTEGRATED OIL DIVISION - CAPITAL INVESTMENT

 
| ($ millions)             | ** ** | **2009** | ** ** | 2008   |   | 2007  | ** ** |
|-------------------------------|------------|----------|------------|--------|--------|------------|------------|
| Upstream                      | ** ** | **$**    | **476**    |   | $      | 644        |       | $ | 450  |   |
| Downstream Refining           | ** ** | **907**  |       | 478    |   | 220   |       |
| Total Integrated Oil Division | ** ** | **$**    | **1,383**  |   | $      | 1,122      |       | $ | 670  |   |

 

Our Upstream capital investment in 2009 was primarilyfocused on the continued development of the next phases of the Foster Creek andChristina Lake properties. Capital investment was lower in 2009 because oflower drilling costs as we drilled fewer stratigraphic test wells at FosterCreek, Christina Lake and Borealis, combined with a lower foreign exchangerate. Our current plan is to increase production capacity at Foster Creek andChristina Lake to approximately 218,000 bbls/d of bitumen with the completionof Christina Lake phase C in 2011 and phase D in 2013.  We have chosen to accelerate completion ofChristina Lake phase D which we expect will advance start up by approximatelysix months.

 

Our Downstream Refining capital investment in 2009 continuedto focus on the CORE project at the Wood River refinery, as we significantlyincreased capital expenditures to $907 million in 2009 from $478 million in2008 (2007 - $220 million). The CORE project is expected to cost approximately$1.8 billion (net to Cenovus) and is anticipated to be completed and inoperation in 2011.  The expansion isexpected to increase crude oil refining capacity by 50,000 bbls/d to 356,000bbls/d and more than double heavy crude oil refining capacity at Wood River to240,000 bbls/d.  At December 31,2009, construction on the CORE project was approximately 71 percent completeand continued to be on schedule and within budgeted costs.

 

 

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**CANADIAN PLAINS DIVISION**

 

Crude Oil and NGLs

 

Financial Results

 
| ($ millions)                                 | ** ** | **2009** |            | 2008   |   | 2007   |   |
|---------------------------------------------------|------------|----------|-----------------|--------|--------|--------|--------|
| Revenues,  Net of Royalties and excluding hedging | ** ** | **$**    | ** 1,371** |   | $      | 2,256  |   | $ | 1,540 |   |
| Realized  Financial Hedging Gain (Loss)           | ** ** | **2**    |            | (150)  |   | (87)   |   |
| Expenses                                          |       |     |            |   |   |   |   |
| Production  and mineral taxes                     | ** ** | **24**   |            | 38     |   | 29     |   |
| Transportation  and selling                       | ** ** | **179**  |            | 321    |   | 263    |   |
| Operating                                         | ** ** | **229**  |            | 239    |   | 215    |   |
| Operating  Cash Flow                              | ** ** | **$**    | ** 941**   |   | $      | 1,508  |   | $ | 946 |   |

 

Production Volumes

 
|                            | ** ** | ** ** |       | **2009  vs** |   |   |   | 2008 vs |   |   |   |
|---------------------------------|------------|------------|------------|--------------|--------|--------|--------|---------|--------|--------|--------|
|                            | ** ** | **2009**   | ** ** | **2008**     |   | 2008   |   | 2007    |   | 2007   |   |
| Heavy Oil *(bbls/d)*            | ** ** | ** ** |       |         |   |   |   |    |   |   |   |
| Pelican  Lake                   | ** ** | **20,105** | ** ** | **-9%**      |   | 21,975 |   | -5%     |   | 23,253 |   |
| Southern  Alberta               | ** ** | **12,038** | ** ** | **-8%**      |   | 13,054 |   | -16%    |   | 15,530 |   |
| Light and  Medium Oil*(bbls/d)* | ** ** | ** ** |       |         |   |   |   |    |   |   |   |
| Weyburn                         | ** ** | **14,948** | ** ** | **7%**       |   | 14,031 |   | -5%     |   | 14,771 |   |
| Southern  Alberta               | ** ** | **10,368** | ** ** | **-7%**      |   | 11,099 |   | -1%     |   | 11,246 |   |
| Other                           | ** ** | **5,405**  | ** ** | **-10%**     |   | 5,998  |   | -2%     |   | 6,139  |   |
| NGLs *(bbls/d)*                 | ** ** | **1,186**  | ** ** | **0%**       |   | 1,181  |   | -6%     |   | 1,260  |   |

 

Revenue Variance

 
|              |   | 2008 Revenues                                                                              |   | Revenue       | ** ** | **2009  Revenues** | ** ** |
|-------------------|--------|--------------------------------------------------------------------------------------------|--------|---------------|------------|--------------------|------------|
|              |   | Net of                                                                                     |   | Variances in: | ** ** | **Net  of**        | ** ** |
| ($ millions) |   | Royalties                                                                                  |   | Price(1)      |       | Volume   |       | Other(2) | ** ** | **Royalties** | ** ** |
| Canadian  Plains  |   | $         2,106      |   | $             | (501)      |               | $          | (104) |   | $ | (128) | ** ** | **$** | **1,373** | ** ** |
|                   |        |                                                                                            |        |               |            |                    |            |  |  |  |  |  |  |  |  |

 

(1)     Includes the impact of realizedfinancial hedging.

(2)     Revenue dollars reported include thevalue of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

 

Crude oil and NGLrevenues, net of royalties, excluding realized financial hedging, decreased$885 million in 2009 compared to 2008 due to lower commodity prices andproduction volumes.

 

Theaverage crude oil sales price, excluding realized hedging, decreased 35 percentto $51.80 per bbl in 2009 from $79.09 per bbl in 2008, consistent with changes inthe benchmark WTI and WCS crude oil prices. During 2009, crude oil and NGLs realized financialhedging gains were $2million($0.10 per bbl) compared to lossesof $150million($6.02 per bbl) in 2008 (2007 – loss of $87 million; $3.32 per bbl).

 

Production volumes at Weyburn wereseven percent higher in 2009 compared to 2008 mainly due to well optimizationsand lower royalty rates partially offset by natural declines. At Pelican Lake,volumes were nine percent lower in 2009 compared to 2008 mainly due to naturaldeclines and a scheduled facility turnaround partially offset by less facilitydowntime. Southern Alberta oil production was down eight percent from 2008primarily due to expected natural declines partially offset by production fromnew wells.

 

Production and mineral taxes of $24million in 2009 decreased from $38 million in 2008 (2007 - $29 million)consistent with lower crude oil prices.

 

 

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Transportation and selling costs of$179 million in 2009 decreased from $321 million in 2008 (2007 - $263 million)due to a 39 percent decrease in theaverage price and a nine percent decrease in volume of condensate used forblending with heavy oil.

 

Operatingcosts decreased to $229 million in 2009 from $239 million in 2008 (2007 - $215million) due to a lower foreign exchange rate and lower workover activitypartially offset by higher chemical usage and electricity costs. NGLs are abyproduct obtained through the production of natural gas and thereforeoperating costs associated with the production of NGLs are included withnatural gas.

 

Natural Gas

 

Financial Results
| ($ millions)                                 | ** ** | **2009** |      | 2008   |   | 2007   |   |
|---------------------------------------------------|------------|----------|-----------|--------|--------|--------|--------|
| Revenues,  Net of Royalties and excluding hedging | ** ** | **$**    | **1,022** |   | $      | 2,392  |   | $ | 1,946 |   |
| Realized  Financial Hedging Gain (Loss)           | ** ** | **880**  |      | (91)   |   | 240    |   |
| Expenses                                          |       |     |      |   |   |   |   |
| Production  and mineral taxes                     | ** ** | **13**   |      | 36     |   | 34     |   |
| Transportation  and selling                       | ** ** | **39**   |      | 71     |   | 82     |   |
| Operating                                         | ** ** | **210**  |      | 241    |   | 221    |   |
| Operating  Cash Flow                              | ** ** | **$**    | **1,640** |   | $      | 1,953  |   | $ | 1,849 |   |

 

Production Volumes

 
|                    | ** ** | ** ** |       | **2009  vs** |   |   |   | 2008 vs |   |   |   |
|-------------------------|------------|------------|------------|--------------|--------|--------|--------|---------|--------|--------|--------|
|                    | ** ** | **2009**   | ** ** | **2008**     |   | 2008   |   | 2007    |   | 2007   |   |
| Natural Gas  *(MMcf/d)* | ** ** | ** ** |       |         |   |   |   |    |   |   |   |
| Southern  Alberta       | ** ** | **739**    | ** ** | **-8%**      |   | 800    |   | -4%     |   | 832    |   |
| Other                   | ** ** | **36**     | ** ** | **-14%**     |   | 42     |   | -2%     |   | 43     |   |
|                    | ** ** | **775**    |       |         |   | 842    |   |    |   | 875    |   |

 

Revenue Variance

 
|              |   | 2008 Revenues |   | Revenue       | ** **                                                                           | **2009  Revenues** | ** **                                                                     |
|-------------------|--------|---------------|--------|---------------|--------------------------------------------------------------------------------------|--------------------|--------------------------------------------------------------------------------|
|              |   | Net of        |   | Variances in: | ** **                                                                           | **Net  of**        | ** **                                                                     |
| ($ millions) |   | Royalties     |   | Price(1)      |                                                                                 | Volume        | ** **                                                                     | **Royalties** | ** ** |
| Canadian  Plains  |   | $             | 2,301  |          | $             (210) |               | $            (189) | ** ** | **$** | **1,902** | ** ** |
|                   |        |               |        |               |                                                                                      |                    |                                                                                |  |  |  |  |

 

 

(1) Includesthe impact of realized financial hedging.

 

Natural gas revenues, net ofroyalties, excluding realized financial hedging, decreased $1,370 million in2009 compared to 2008, primarily due to lower natural gas prices as well aslower production volumes.  Averagenatural gas prices, excluding the impact of financial hedges, decreased to$3.62 per Mcf in 2009 from $7.77 per Mcf in 2008 consistent with the reductionin the benchmark AECO price. In 2009, we realized a financial hedging gain of$880 million ($3.11 per Mcf) compared to a loss of $91 million ($0.29 per Mcf)in 2008 (2007 – gain of $240 million; $0.75 per Mcf).

 

Production volumes for SouthernAlberta decreased eight percent in 2009 compared to 2008 due to expectednatural declines and lower drilling and tie-in activity in response to lowercommodity prices partially offset by lower royalty rates.

 

Production and mineral taxes of $13million in 2009 decreased from $36 million in 2008 (2007 - $34 million)primarily as a result of lower natural gas prices and lower production volumes.

 

Transportation and selling costs of$39 million in 2009 decreased from $71 million in 2008 (2007 - $82 million) dueto lower volumes being shipped to eastern Canada and the eastern United Statesand the

 

 

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lower foreign exchange rate.

 

Operating expenses in 2009 decreasedto $210 million from $241 million in 2008 (2007 - $221 million) mostly as aresult of the lower foreign exchange rate combined with a lower level ofrepair, maintenance and workover activity.

 

Canadian Plains - Other

 

Financial Results
| ($ millions)                                 | ** ** | **2009** |                                                    | 2008   |   | 2007                                                      |   |
|---------------------------------------------------|------------|----------|---------------------------------------------------------|--------|--------|-----------------------------------------------------------|--------|
| Revenues,  Net of Royalties and excluding hedging | ** ** | **$**    | **       868**            |   | $      |      1,137                            |   | $ |      1,824 |   |
| Expenses                                          |       |     |                                                    |   |   |                                                      |   |
| Transportation  and selling                       | ** ** | **-**    |                                                    | -      |   | 10                                                        |   |
| Operating                                         | ** ** | **18**   |                                                    | 22     |   | 23                                                        |   |
| Purchased  product                                | ** ** | **832**  |                                                    | 1,101  |   | 1,751                                                     |   |
| Operating  Cash Flow                              | ** ** | **$**    | **         18** |   | $      |           14 |   | $ |           40 |   |

 

The Canadian Plains Division marketsall of our crude oil and natural gas, including third party purchases and salesof product, in order to provide operational flexibility for transportationcommitments, product quality, delivery points and customerdiversification.  The decrease in bothrevenues and purchased product expenses for 2009 compared to 2008 is consistentwith decreased average market prices during 2009.  Canadian Plains – Other also includes a smallamount of third party processing fee income.

 

Capital Investment

 

Canadian Plains capital investment in2009 was $478 million (2008 - $872 million; 2007 - $795 million). The $394million decrease from 2008 was primarily the result of management’s decision toreduce capital investment in response to lower commodity prices in 2009.  The reduction came primarily from lowernatural gas drilling, completion and tie-in activity, as well as the lower foreignexchange rate, and lower land acquisition expenditures, partially offset byhigher heavy crude oil drilling activity. Canadian Plains drilled 614 net wells in 2009 compared to 1,476 netwells in 2008 (2007 – 2,264 net wells).

 

**CORPORATE AND ELIMINATIONS**

** **

Financial Results

 
| ($ millions)                         | ** ** | **2009**      |                               | 2008      |   | 2007                                                 |   |
|-------------------------------------------|------------|---------------|------------------------------------|-----------|--------|------------------------------------------------------|--------|
| Revenues                                  | ** ** | **$**         | **     (738)** |      | $      |         576  |   | $ |        (437) |   |
| Expenses                                  |       |          |                               |      |   |                                                 |   |
| Operating                                 | ** ** | **30 **  |                               | (11)      |   | (2)                                                  |   |
| Purchased  product                        | ** ** | **(99)**      |                               | (151)     |   | (88)                                                 |   |
| Depreciation,  depletion and amortization | ** ** | **50 **  |                               | 23   |   | 45                                              |   |
| General and  administrative               | ** ** | **188 ** |                               | 167  |   | 145                                             |   |
| Interest,  net                            | ** ** | **218 ** |                               | 218  |   | 187                                             |   |
| Accretion  of asset retirement obligation | ** ** | **39 **  |                               | 39   |   | 28                                              |   |
| Foreign  exchange (gain) loss, net        | ** ** | **290 ** |                               | (250)     |   | 380                                             |   |
| (Gain) loss  on divestitures              | ** ** | **(2)**       |                               | 3    |   | 4                                               |   |
| Segment  Income (Loss)                    | ** ** | **$**         | **  (1,452)**                 |      | $      |         538  |   | $ |     (1,136) |   |

 

The Corporate and Eliminationssegment includes revenues that represent the unrealized mark-to-market gains orlosses related to derivative financial instruments used to mitigatefluctuations in commodity prices. The segment also includes inter-segmenteliminations that relate to transactions that have been recorded at transferprices based on current market prices as well as unrealized intersegmentprofits in inventory. Operating expenses primarily relate to mark-to-marketgains and losses on long-term power purchase contracts and downstream crude oilsupply positions.  Depreciation,Depletion and Amortization

 

 

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(“DD&A”) includes provisions inrespect of corporate assets, such as computer equipment, office furniture andleasehold improvements.

 

General and administrative expensesincreased $21 million in 2009 compared to 2008 primarily due to higherlong-term compensation costs as a result of the increased share price andexpenses related to the creation of Cenovus offset by a lower foreign exchangerate.

 

Interest expense in 2009 was $218million, unchanged from 2008 interest expense, of $218 million (2007 - $187million) primarily as a result of our average level of debt outstanding andinterest rates being consistent between 2008 and 2009. Our weighted averageinterest rate on outstanding debt at December 31, 2009 was 5.8 percent,compared to 5.5 percent in 2008.

 

We reported a foreign exchange lossof $290 million in 2009 compared to a gain of $250 million in 2008 (2007 – lossof $380 million), the majority of which was unrealized.  We are exposed to foreign exchange gains andlosses primarily on our U.S. dollar partnership contribution receivable and ourU.S. dollar denominated debt issued from Canada.  The strengthening of the Canadian dollarduring 2009 led to unrealized losses on our partnership contributionreceivable, which was partially offset by unrealized gains on our U.S. dollardebt.  We also reported an unrealizedforeign exchange loss of $107 million during the year relating to thetranslation of our U.S. dollar risk management assets and liabilities, comparedto an unrealized gain of $2 million in 2008 (2007 – unrealized loss of $34million).  The loss incurred in 2009 wasalso primarily due to the strengthening of the Canadian dollar during the year.

 

Depreciation, Depletionand Amortization

 

In 2009, DD&A was $1,343 million compared to $1,318 million in 2008(2007 - $1,426 million). We use full cost accounting for our upstream oil andgas activities and calculate DD&A on a country-by-country cost centrebasis. Upstream DD&A of $1,101 million in 2009 was consistent with 2008DD&A of $1,107 million (2007 - $1,222 million) as a result of a higherDD&A rate offset by a lower foreign exchange rate and slightly lowerproduction volumes. In 2009, DD&A on our Downstream Refiningassets was $192 million, which was consistent with 2008 DD&A of $188million (2007 - $159 million). DD&A in the Corporate and Eliminationssegment was $50 million for 2009 compared to $23 million for 2008 (2007 - $45million).

 

Income Tax

 

Total income tax expense in 2009 was$302 million, which was $423 million lower than 2008 mainly due to lowerearnings before income tax. Current income tax expense in 2009 was $853 millioncompared to $340 million in 2008, with the increase largely being attributableto the acceleration of income tax arising from the dissolution of EnCana’sCanadian oil and gas partnership in connection with the Arrangement, as well asthe realization of significant hedging gains in 2009. This accelerated currenttax was offset by a future tax recovery for the tax that would have been paidin 2010. Current tax expense for the three years is primarily an allocation ofEnCana’s income tax liability on a carve-out accounting basis our portion ofwhich was settled as part of the Arrangement and therefore we do not have anyincome tax payable at December 31, 2009.

 

In 2009, we had a future income taxrecovery of $551 million compared to an expense of $385 million in 2008. Thesignificant net recovery in 2009 is due to the reversal of the future tax whichoffsets the accelerated current income tax on partnership income, as notedabove, as well as 2008 unrealized mark-to-market hedging gains.

 

In 2009, our effective tax rate was31.8 percent compared to 23.4 percent in 2008. The increase is primarily due tothe provision of future income tax on unrealized foreign exchange gains as wellas a variety of rate differences.

 

Additional information regarding oureffective tax rate can be found in the notes to the Consolidated FinancialStatements. Our effective tax rate in any year is a function of therelationship between total tax expense and the amount of earnings before incometaxes for the year. The effective tax rate differs from the statutory tax rateas it takes into consideration permanent differences, adjustments for changesin tax

 

 

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rates and other tax legislation,variation in the estimate of reserves and the differences between the provisionand the actual amounts subsequently reported on the tax returns.  Permanent differences include:

·      Thenon-taxable portion of Canadian capital gains and losses;

·      Internationalfinancing; and

·      Foreignexchange (gains) losses not included in Net Earnings.

 

Tax interpretations, regulations andlegislation in the various jurisdictions in which the Company and itssubsidiaries operate are subject to change. As a result, there are usually some tax matters under review.  We believe that our provision for taxes isadequate.

 

Summary of Unrealized Mark-to-MarketGains (Losses)

 

The volatility of commodity priceshas a significant impact on our Net Earnings, and as a means of managing thisvolatility, we enter into various financial instrument agreements. Thefinancial instrument agreements were recorded at the date of the financialstatements based on mark-to-market accounting. Changes in the mark-to-marketgain or loss reflected in corporate revenues are the result of volatilitybetween periods in the forward commodity prices and changes in the balance ofunsettled contracts. The table below provides a summary of the unrealizedmark-to-market gains and losses recognized for each year. Additionalinformation regarding financial instrument agreements can be found in the notesto the Consolidated Financial Statements.

 
| ($ millions)                                    | ** ** | **2009 ** |                                         | 2008   |   | 2007   |
|------------------------------------------------------|------------|----------------|----------------------------------------------|--------|--------|--------|
| Revenues                                             |       |           |                                         |   |   |   |   |   |   |
| Crude Oil                                            | ** ** | **$**          | **       (98** | **)**  |   | $      |         212 |   |   | $ |        (161 | ) |
| Natural Gas                                          | ** ** | **(541**       | **)**                                        |   | 515    |   |   | (188 | ) |
|                                                 | ** ** | **(639**       | **)**                                        |   | 727    |   |   | (349 | ) |
| Expenses                                             | ** ** | **28**         |                                         |   | (7     | )      |   | (1 | ) |
|                                                 | ** ** | **(667**       | **)**                                        |   | 734    |   |   | (348 | ) |
| Income Tax  Expense (Recovery)                       | ** ** | **(194**       | **)**                                        |   | 215    |   |   | (104 | ) |
| Unrealized  Mark-to-Market Gains (Losses), after tax | ** ** | **$**          | **     (473**            | **)**  |   | $      |         519 |   |   | $ |        (244 | ) |

 

 

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**QUARTERLY FINANCIAL DATA**

 
| ($ millions, except per share | ** ** | **2009**                     |       | 2008                         |       |
|------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| amounts)                           | ** ** | **Q4**                       | ** ** | **Q3**                       | ** ** | **Q2** | ** ** | **Q1** |   | Q4 |   | Q3 |   | Q2 |   | Q1 |   |
| Revenues,  Net of Royalties        | ** ** | **$   2,835** | ** ** | **$   2,714** | ** ** | **$   2,429** | ** ** | **$   2,162** |   | $   3,207 |   | $   5,533 |   | $   4,381 |   | $   3,438 |   |
| Operating  Cash Flow (1)           | ** ** | **909**                      | ** ** | **1,032**                    | ** ** | **1,008** | ** ** | **746** |   | 101 |   | 1,133 |   | 1,518 |   | 1,098 |   |
| Cash Flow (1)                      | ** ** | **225**                      | ** ** | **841**                      | ** ** | **811** | ** ** | **595** |   | (174) |   | 1,123 |   | 1,228 |   | 911 |   |
| - per share  – diluted (2)    | ** ** | **0.30**                     | ** ** | **1.12**                     | ** ** | **1.08** | ** ** | **0.79** |   | (0.23) |   | 1.50 |   | 1.63 |   | 1.21 |   |
| Operating  Earnings (1)            | ** ** | **152**                      | ** ** | **382**                      | ** ** | **447** | ** ** | **331** |   | (123) |   | 611 |   | 710 |   | 431 |   |
| - per share  – diluted (2)    | ** ** | **0.20**                     | ** ** | **0.51**                     | ** ** | **0.59** | ** ** | **0.44** |   | (0.16) |   | 0.81 |   | 0.95 |   | 0.57 |   |
| Net  Earnings                      | ** ** | **24**                       | ** ** | **63**                       | ** ** | **149** | ** ** | **412** |   | 380 |   | 1,299 |   | 522 |   | 167 |   |
| - per share  – basic (2)      | ** ** | **0.03**                     | ** ** | **0.08**                     | ** ** | **0.20** | ** ** | **0.55** |   | 0.51 |   | 1.73 |   | 0.70 |   | 0.22 |   |
| - per share  – diluted (2)    | ** ** | **0.03**                     | ** ** | **0.08**                     | ** ** | **0.20** | ** ** | **0.55** |   | 0.51 |   | 1.73 |   | 0.70 |   | 0.22 |   |
| Capital  expenditures              | ** ** | **481**                      | ** ** | **471**                      | ** ** | **416** | ** ** | **524** |   | 626 |   | 469 |   | 435 |   | 516 |   |
| Free Cash  Flow (1)                | ** ** | **(256)**                    | ** ** | **370**                      | ** ** | **395** | ** ** | **71** |   | (800) |   | 654 |   | 793 |   | 395 |   |
| Cash Dividends  (3)                | ** ** | **151**                      | ** ** | **-**                        | ** ** | **-** | ** ** | **-** |   | - |   | - |   | - |   | - |   |

(1)  Non-GAAPmeasures which are defined in this MD&A.

(2)  Any per shareamounts prior to December 1, 2009 have been calculated using EnCana's commonshare balances based on the terms of the Arrangement where EnCana shareholdersreceived one common share of Cenovus and one common share of the new EnCana.

(3)  We declaredand paid a dividend of $0.20 per share in December 2009. The December dividendreflects an amount determined in connection with the Arrangement based oncarve-out earnings and cash flow.

 

Our Cash Flow in the fourth quarterof 2009 increased $399 million compared to the fourth quarter of 2008.  The main drivers for the increase in CashFlow were:

·                  The improvement of downstreamoperating cash flow in 2009 was the result of the fourth quarter in 2008 beingimpacted by a 50 percent drop in crude oil prices compared to the third quarterof 2008, resulting in a much lower inventory carrying value at December 31,2008, thereby resulting in much higher purchased product costs;

·                  Increase in the average liquids salesprice, before hedging, to $61.08 per bbl compared to $30.47 per bbl in 2008;and

·                  Increase in crude oil and NGLsproduction of 11 percent.

 

Partially offsetting the increaseswere the following:

·      An increasein current tax of $360 million on the acceleration of current tax payable,resulting in no income tax payable at December 31, 2009, due to the dissolutionof EnCana’s Canadian oil and gas partnership in connection with theArrangement;

·                  A decrease in natural gas averagesales prices, excluding hedging, of 30 percent; and

·                  A decrease in natural gas productionof 13 percent.

 

Our Net Earnings in the fourthquarter of 2009 were $24 million, which were $356 million lower than 2008. Thefactors that increased Cash Flow in the fourth quarter increased Net Earningsbut were offset by the following factors that resulted in an overall decreaseto Net Earnings:

·                  Unrealized hedging loss of $143million compared to a gain of $386 million in the fourth quarter of 2008; and

·                  Higher Operating, General andAdministrative and DD&A expenses.

 

 

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** **

**OIL AND GAS RESERVES**

** **

PROVED AND PROBABLE RESERVES AS ATDECEMBER 31

** **
| ** **       | ** ** | **Bitumen**                | ** ** | **Crude  Oil and NGLs**(1) | ** ** | **Natural  Gas**              |
|------------------|------------|----------------------------|------------|----------------------------|------------|-------------------------------|
| Constant  Prices | ** ** | **(millions  of barrels)** | ** ** | **(millions  of barrels)** | ** ** | **(billions  of cubic feet)** |
| After  Royalties | ** ** | **2009**                   |       | 2008                       |       | 2007                          | ** ** | **2009** |   | 2008 |   | 2007 | ** ** | **2009** |   | 2008 |   | 2007  |
| Proved           | ** ** | **719**                    |       | 668                        |       | 596                           | ** ** | **232** |   | 241 |   | 231 | ** ** | **1,474** |   | 1,855 |   | 2,019  |
| Probable         | ** ** | **403**                    |       | 624                        |       | 537                           | ** ** | **127** |   | 136 |   | 119 | ** ** | **405** |   | 522 |   | 569  |

(1) Crude Oil andNGLs include condensate.

 

All of our bitumen, crude oil, NGLsand natural gas reserves are located in Canada. Each year, we engage independent qualified reserves evaluators toprepare reports on 100 percent of our reserves. We have a Reserves Committee of independent members of our Board, whichreviews the qualifications and appointment of the independent qualifiedreserves evaluators.  The ReservesCommittee also reviews the procedures for providing information to theevaluators.  Our disclosure of reservesdata is prescribed by National Instrument 51-101 – Standards of Disclosure forOil and Gas Activities**(“NI 51-101”)of the Canadian Securities Administrators as amended by a Decision datedOctober 20, 2009 permitting the adoption of U.S. reporting standards, includingcompliance with the practices and procedures of the U.S. Securities andExchange Commission (“SEC”) and U.S. Financial Accounting Standards Board(“FASB”) reserves reporting requirements.

 

As of December 31, 2009, the SECrequires companies to determine their oil and gas reserves using an averageprice based upon the prior 12-month period, rather than year-end prices. TheSEC also now permits companies to disclose their probable and possible reservesin their SEC filings.

 

PROVED RESERVES RECONCILIATION

** **
| Constant  Prices after Royalties | ** ** | **Bitumen**                | ** ** | **Crude  Oil and NGLs****(1)** | ** ** | **Natural  Gas**              | ** ** |
|----------------------------------|------------|----------------------------|------------|--------------------------------|------------|-------------------------------|------------|
| As at  December 31, 2009         | ** ** | **(millions  of barrels)** | ** ** | **(millions  of barrels)**     | ** ** | **(billions  of cubic feet)** | ** ** |
| Beginning  of year               |       |                       | 668        |                           |       | 241                           |       |   | 1,855  |   |   |
| Revisions  and improved recovery |       |                       | (88        | )                              |       | 8                             |       |   | (128) |   |   |
| Extensions  and discoveries      |       |                       | 160        |                           |       | 6                             |       |   | 50 |   |   |
| Divestitures                     |       |                       | (4         | )                              |       | -                             |       |   | (2) |   |   |
| Production                       |       |                       | (17        | )                              |       | (23                           | )          |   |   | (301) |   |   |
| **End of year**                  | ** ** | ** **                 | **719**    | ** **                     | ** ** | **232**                       | ** ** | ** ** | **1,474 ** |   | ** ** |

(1) Crude Oil andNGLs includes condensate.

 

In 2009, our bitumen reserves extensions anddiscoveries were approximately 160 million barrels, primarily as a result ofChristina Lake phase D receiving approval to proceed. The increase waspartially offset by negative revisions of approximately 88 million barrelsattributed to higher royalty rates resulting from a higher WTI price. Inaddition, as a result of the new Alberta Royalty Framework, where royalties aredetermined on a sliding scale depending on the price of bitumen, when pricesare between C$55 per barrel and C$120 per barrel, pre-payout royalty ratesrange from one to nine percent of gross revenue. Once a project reaches payoutthe royalty is based on the greater of one to nine percent of a project’s grossrevenue or 25 to 40 percent of net revenue. Our crude oil and NGLs reservesdecreased by approximately four percent year over year as aggregate revisionsand improved recoveries and extensions and discoveries did not fully offset ourproduction. Our natural gas reserves negative revisions were approximately 128billion cubic feet mainly due to low natural gas prices.

 

Additional disclosure relating to ouroil and gas reserves is contained in our Annual Information Form for the yearended December 31, 2009 which can be accessed at www.sedar.com and on our website at www.cenovus.com.

 

 

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**LIQUIDITY AND CAPITAL RESOURCES**

** **
| ($ millions)                                                                   | ** ** | **2009  **                                                                               |   | 2008                                                                    |   | 2007                                                                                    |   |
|-------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------|--------|------------------------------------------------------------------------------|--------|----------------------------------------------------------------------------------------------|--------|
| Net cash  from (used in)                                                            |       |                                                                                               |   |                                                                         |   |                                                                                         |   |
| Operating  activities                                                               | ** ** | **$        3,496   **                       |   | $**        **2,687    |   | $**        **3,014                    |   |
| Investing  activities                                                               | ** ** | **(1,780)  **                                                                            |   | (1,964)                                                            |   | (1,533)                                                                            |   |
| Net cash  provided before Financing activities                                      | ** ** | **1,716   **                                                                        |   | 723                                                           |   | 1,481                                                                         |   |
| Financing  activities                                                               | ** ** | **(1,730)  **                                                                            |   | (852)                                                              |   | (1,292)                                                                            |   |
| Foreign  exchange gain (loss) on cash and cash equivalents held in foreign currency |       | **9   **                                                                            |   | (20)                                                               |   | 7                                                                             |   |
| Increase  (decrease) in cash and cash equivalents                                   | ** ** | **$             (5)  ** |   | $**         **(149)   |   | $**           **196    |   |

** **

OPERATING ACTIVITIES

 

Net cash from operating activitiesincreased to $3,496 million in 2009 compared to $2,687 million in 2008 (2007 -$3,014 million). Cash Flow was $2,472 million during 2009 compared to $3,088million in 2008.  Reasons for this changeare discussed under the Cash Flow section of this MD&A.  Cash from operating activities was alsoimpacted by net changes in other assets and liabilities and net changes innon-cash working capital, primarily from increases in inventories, accounts receivableand accrued revenues and current income taxes partially offset by increases inaccounts payable and accrued liabilities.

 

Excluding the impact of riskmanagement assets and liabilities, we had working capital of $457 million atDecember 31, 2009 compared to a working capital deficit of $191 million atDecember 31, 2008.  We anticipate that wewill continue to meet the payment terms of our suppliers.

 

INVESTINGACTIVITIES

 

Net cash used for investingactivities in 2009 decreased to $1,780 million from $1,964 million in 2008.Capital expenditures decreased in 2009 to $1,895 million compared to $2,046million in 2008.  Divestitures were $162million higher than 2008 and were substantially offset with increases in cashused for investing activities from net changes in non-cash workingcapital.  The decreased capitalexpenditures are discussed under the Net Capital Investment and DivisionalResults sections of this MD&A.

 

FINANCINGACTIVITIES

 

On September 18, 2009, a predecessorentity of Cenovus completed a private offering of senior unsecured notes for anaggregate principal amount of $3.5 billion, issued in three tranches, which areexempt from the registration requirements of the U.S. Securities Act of 1933under Rule 144A and Regulation S. The net proceeds of the private offering,along with $151 million deposited by the Company, were placed into an escrowaccount pending the completion of the Arrangement with EnCana.  Upon completion of the Arrangement, fundswere released from escrow and the proceeds of the notes were then used to paythe note payable to EnCana of $3.5 billion as part of the Arrangement. OnNovember 30, 2009, the notes became the direct, unsecured obligations ofCenovus.

 

We currently have in place anunsecured credit facility in the amount of Canadian $2.5 billion or itsequivalent amount in U.S. dollars. The revolving syndicated credit facilityconsists of two tranches, a Canadian $2.0 billion 3-year tranche and a Canadian$500 million 364-day tranche.  AtDecember 31, 2009, we had available $2.3 billion (Canadian $2.4 billion) inunused credit capacity under this facility. We are currently in compliance with all of our financial covenants underthis credit facility.

 

We declared and paid a dividend of$151 million ($0.20 per share) in December 2009.  The December dividend reflects an amountdetermined in connection with the Arrangement based on carved-out earnings andcash flows. Future dividends will be at the sole discretion of the Board andconsidered quarterly.

 

It is Cenovus’s intention to maintaininvestment grade credit ratings on our senior unsecured debt.  DBRS Limited has assigned a rating of “A(low)” with a “Stable” outlook, Standard & Poor’s Corporation has assigneda rating of BBB+ with a “Stable” outlook and Moody’s Investors Service, Inc.has assigned a rating of Baa2 with a “Stable” outlook.

 

 

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As at December 31, 2008, our currentand long-term debt represented an allocation of our proportionate share ofEnCana’s consolidated current and long-term debt. As a result, the debtallocations presented in the Consolidated Financial Statements at December 31,2008 represented intercompany balances between EnCana and Cenovus with the sameterms and conditions as EnCana’s long-term debt and in the same proportion ofCanadian and U.S. dollar denominated debt.

 

Our net cash used in financingactivities for 2009 of $1,730 million, includes $3,468 million of net proceedsfrom the private offering of the notes, as well as the repayment of the $3.5billion demand promissory note to EnCana. Subsequent to the completion of theArrangement, Cenovus made a payment to EnCana in the amount of $250 million toadjust the cash balances of both companies at November 30, 2009 to the agreedupon amounts pursuant to the Arrangement. Our debt, including current portion,was $3,493 million as at December 31, 2009 compared with $3,036 million as atDecember 31, 2008.

 

FINANCIAL METRICS

 
|                             |       | **2009**       |   | 2008       |   | 2007        |   |
|----------------------------------|------------|----------------|--------|------------|--------|------------------|--------|
| Debt to  Capitalization          | ** ** | **28%**        |   | 28%        |   | 32%         |   |
| Debt to  Adjusted EBITDA (times) | ** ** | **1.2x ** |   | 0.7x  |   | 1.0x   |   |

 

Cenovusmonitors its capital structure and short-term financing requirements using,among other things, non-GAAP financial metrics consisting of Debt toCapitalization and Debt to Adjusted EBITDA. Capitalization is a non-GAAPmeasure defined as long-term debt including current portion plus Shareholders’Equity. Trailing 12-month Adjusted EBITDA is a non-GAAP measure defined asAdjusted Earnings before Interest, Income Taxes, DD&A and foreign exchangegains/losses. These metrics are used to steward Cenovus’s capital structure.  Debt is defined as the current and long-termportions of long-term debt.

 

We target aDebt to Capitalization ratio between 30 to 40 percent and a Debt to AdjustedEBITDA between 1.0 to 2.0 times.

 

OUTSTANDING SHAREDATA

 
| (millions)                                        | ** ** | ** ** |   |   |   | **2009 **  |   |
|---------------------------------------------------|------------|------------|--------|--------|--------|-----------------|--------|
| Common  Shares issued pursuant to the Arrangement | ** ** | ** ** |   |   |   | **751.3 ** |   |
| Outstanding,  End of year                         | ** ** | ** ** |   |   |   | **751.3 ** |   |

 

Cenovus is authorized to issue anunlimited number of Common Shares (the “Common Shares”), an unlimited number offirst preferred shares and an unlimited number of second preferred shares.There were no first preferred shares or second preferred shares outstanding asat December 31, 2009.

 

Pursuant to theArrangement, each shareholder of EnCana received one new common share of EnCana(which continued to be represented by EnCana common share certificatesoutstanding prior to the Arrangement becoming effective) and one Common Shareof Cenovus for every EnCana common share held. In aggregate, 751,273,307 Common Shares were issued pursuant to theArrangement.

 

The Cenovus Employee Stock OptionPlan permits our Board, from time to time, to grant to employees of Cenovus andits subsidiaries stock options to purchase our Common Shares. Option exerciseprices approximate the market price for the Common Shares on the date the optionswere issued. As at December 31, 2009, our options are exercisable at 30 percentof the number granted after one year, an additional 30 percent of the numbergranted after two years and are fully exercisable after three years and expirefive years after the date granted. Stock options granted have an associatedTandem Share Appreciation Right (“TSAR”) attached, which gives employees theright to elect to receive a cash payment equal to the excess of the marketprice of our Common Shares over the exercise price of their stock option inexchange for surrendering their stock option. A portion of the TSARs have anadditional vesting condition which is subject to the Company attainingprescribed performance relative to key pre-determined measures. Performance TSARsthat do not vest when eligible are forfeited. The exercise of a TSAR for a

 

 

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cash payment does not result in theissuance of any additional Common Shares, thus it has no dilutive effect.

 

In accordance with the Arrangementwith EnCana, each holder of EnCana TSARs and stock options disposed of aportion of their right to Cenovus in exchange for Cenovus Replacement Units andto EnCana for EnCana Replacement Units. The terms and conditions of the CenovusReplacement Units are similar to the terms and conditions of the originalEnCana units, which are also similar, to the terms and conditions of CenovusTSARs and stock options. The original exercise price of the EnCana units wereapportioned to the Cenovus and EnCana Replacement Units based on the one-dayweighted average trading price of Cenovus’s common share price relative to thatof EnCana’s common share price on the TSX on December 2, 2009.

 

At December 31, 2009, Cenovusemployees held approximately 16 million Cenovus TSARs, of which 6 million wereexercisable.

 

At December 31, 2009 EnCana employeesheld approximately 23 million Cenovus TSARs, of which 10 million wereexercisable. EnCana is required to reimburse Cenovus in respect of cashpayments made to EnCana employees for the Cenovus TSARs held. No furtherCenovus TSARs will be granted to EnCana’s employees. Cenovus is required toreimburse EnCana in respect of cash payments made to Cenovus employees for theCenovus Replacement Units held. No further EnCana Replacement Units will begranted to Cenovus’s employees.

 

At December 31, 2009 there wereapproximately 0.2 million options without TSARs attached outstanding, all ofwhich were exercisable.

 

Cenovus employees hold Cenovus ShareAppreciation Rights, Cenovus Deferred Share Units, EnCana Tandem ShareAppreciation Rights and EnCana Share Appreciation Rights and Cenovus directorshold Cenovus Deferred Share Units for which Cenovus is responsible.  These units do not result in the issuance ofany additional Cenovus Common Shares and therefore have no dilutive effect.

 

CONTRACTUAL OBLIGATIONS ANDCOMMITMENTS(1)

 
|                                    |                                                                                                                                                                                                                                                                                                | **Expected  Payment Date**                               |       |
|-----------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|----------------------------------------------------------|------------|
| ($ millions)                       | ** **                                                                                                                                                                                                                                                                                          | **2010**                                                 | ** ** | **2011** | ** ** | **2012** | ** ** | **2013** | ** ** | **2014** | ** ** | **2015+** | ** ** | **Total** | ** ** |
| Long-Term  Debt(2)                      |                                                                                                                                                                                                                                                                                                | $         - |       | $         - |   | $      56 |   | $         - |   | $      800 |   | $    2,700 |   | $    3,556 |   |
| Partnership  Contribution Payable(2)    |                                                                                                                                                                                                                                                                                                | 325                                                      |       | 345 |   | 366 |   | 388 |   | 412 |   | 1,021 |   | 2,857 |   |
| Asset  Retirement Obligation            |                                                                                                                                                                                                                                                                                                | 68                                                       |       | 11 |   | 11 |   | 12 |   | 16 |   | 5,312 |   | 5,430 |   |
| Pipeline  Transportation                |                                                                                                                                                                                                                                                                                                | 101                                                      |       | 95 |   | 68 |   | 141 |   | 141 |   | 923 |   | 1,469 |   |
| Purchase of  Goods and Services         |                                                                                                                                                                                                                                                                                                | 98                                                       |       | 9 |   | 4 |   | 3 |   | - |   | - |   | 114 |   |
| Product  Purchases                      |                                                                                                                                                                                                                                                                                                | 26                                                       |       | 23 |   | 22 |   | 22 |   | 22 |   | 28 |   | 143 |   |
| Operating  Leases (3)                   |                                                                                                                                                                                                                                                                                                | 26                                                       |       | 27 |   | 34 |   | 72 |   | 76 |   | 1,575 |   | 1,810 |   |
| Capital  Commitments                    |                                                                                                                                                                                                                                                                                                | 105                                                      |       | 85 |   | 33 |   | - |   | - |   | - |   | 223 |   |
| Total  Payments                         |                                                                                                                                                                                                                                                                                                | $    749                             |       | $    595 |   | $    594 |   | $    638 |   | $  1,467 |   | $  11,559 |   | $  15,602 |   |
| Product  Sales                          |                                                                                                                                                                                                                                                                                                | $      46                  |       | $      48 |   | $      52 |   | $      53 |   | $       55 |   | $       119 |   | $       373 |   |
| Partnership  Contribution Receivable(2) |                                                                                                                                                                                                                                                                                                | $    330                             |       | $    347 |   | $    366 |   | $    386 |   | $     407 |   | $       998 |   | $    2,834 |   |
| (1)                                     | In addition, we have commitments  related to our risk management program (see notes to the Consolidated  Financial Statements), and an obligation to fund our defined benefit pension  and Other Post-Employment Benefit plans as disclosed in the notes to the  Consolidated Financial Statements. |
| (2)                                     | Principal component only. See notes to the Consolidated  Financial Statements.                                                                                                                                                                                                                      |
| (3)                                     | Operating leases consist of building leases.                                                                                                                                                                                                                                                        |
|                                         |                                                                                                                                                                                                                                                                                                     |                                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We have entered into variouscommitments in the normal course of operations primarily related to debt,demand charges on firm transportation agreements, capital commitments andmarketing agreements.

 

As at December 31, 2009, Cenovus remained a party tolong-term, fixed price, physical contracts for natural gas with a currentdelivery of approximately 33 MMcf/d, with varying terms and volumes through

 

 

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2017.  The totalvolume to be delivered within the terms of these contracts is 85 Bcf at aweighted average price of $4.39 per Mcf.

 

In the normal course of business, wealso lease office space for personnel who support field operations and forcorporate purposes.

 

LEGAL PROCEEDINGS

 

We are involved in various legalclaims associated with the normal course of operations and we believe we havemade adequate provisions for such claims.

 

**RISK MANAGEMENT**

** **

Our business, prospects, financialcondition, results of operations and cash flows, and in some cases ourreputation, are impacted by risks that are categorized as follows:

 

·                  Financial risks includingmarket risks (such as commodity price, foreign exchange and interest rates),credit and liquidity risks;

 

·                  Operational risks includingcapital, operating and reserves replacement risks; and

 

·                  Safety, environmental andregulatory risks.

 

We are committed to identifying andmanaging these risks in the near-term as well as on a strategic and longer termbasis at all levels in the organization in accordance with our Board approvedCorporate Risk Management Policy and risk management programs. Issuesaffecting, or with the potential to affect, our assets, operations and/orreputation, are generally of a strategic nature or emerging issues that can beidentified early and then managed, but occasionally include unforeseen issuesthat arise unexpectedly and must be managed on an urgent basis. We take aproactive approach to the identification and management of issues that canaffect our assets, operations and/or reputation and have established consistentand clear policies, procedures, guidelines and responsibilities for identifyingand managing these issues.

 

FINANCIAL RISKS

 

Financial risks are defined as therisk of loss or lost opportunity resulting from financial management and marketconditions that could have a positive or negative impact on our business.

 

We continue to implement our businessmodel which focuses on developing low-risk and low-cost long-life resourceproperties. Management has been monitoring our operational and financial riskstrategies to proactively respond to the changing economic conditions and tomitigate or reduce risk. The prudent and conservative capital budget for 2010continues to be monitored and it contains the flexibility to allow spending tobe reduced or increased as commodity prices and forecasts are revised.  Cost containment and reduction strategies arein place to help ensure our controllable costs are efficiently managed.Counterparty and credit risks are closely monitored as is our liquidity to helpensure our ability to access cost effective credit is maintained and thatsufficient cash resources are in place to fund capital expenditures. Furtherinsight into these risks and strategies is summarized below.

 

We partially mitigate our exposure tofinancial risks through the use of various financial instruments and physicalcontracts. The use of derivative instruments is governed under formal policiesand is subject to limits established in our Market Risk Mitigation Policy. As ameans of mitigating exposure to commodity price risk volatility, we haveentered into various financial instrument agreements in respect of ouroperations. The details of these instruments, including any unrealized gains orlosses, as of December 31, 2009, are disclosed in the notes to the ConsolidatedFinancial Statements.

 

Policies, practices and proceduresare in place with respect to the required documentation and approvals for theuse of derivative financial instruments and specifically tie their use, in thecase of commodities, to the mitigation of price risk to achieve targetedinvestment returns and growth objectives, while maintaining prescribedfinancial metrics.

 

 

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With respect to transactions involving our production or assets, thefinancial instruments generally used are swaps or options which are enteredinto with major financial institutions, integrated energy companies orcommodities trading institutions.

 

COMMODITY PRICE

 

Commodity price risk is defined as the uncertainties and fluctuations offuture market prices for commodities.  Topartially mitigate the commodity price risk, we enter into swaps and puts,which establish NYMEX floor prices.For crude oil, we have partiallymitigated our exposure to commodity price risk on our crude oil sales andcondensate supply with fixed price swaps. For natural gas, to partially mitigate the natural gas commodity pricerisk, the Company has entered into swaps, which fix the NYMEX prices. To helpprotect against widening natural gas price differentials in various productionareas, Cenovus has entered into basis swaps to manage the price differentialsbetween these production areas and various sales points. We have mitigated someof our exposure to electricity consumption costs, with two derivative contractswhich do not expire until December 31, 2018.

 

CREDIT

 

Credit risk is defined as the potential for loss if a counterparty in atransaction fails to meet its obligations in accordance with agreed terms.  A substantial portion of our accountsreceivable is with customers in the oil and gas industry. This credit exposureis mitigated through the use of our Board-approved credit policies governingour credit portfolio and with credit practices that limit transactionsaccording to counterparties’ credit quality and transactions that are fullycollateralized. All financial derivative agreements are with major financialinstitutions in Canada and the United States or with counterparties havinginvestment grade credit ratings.

 

LIQUIDITY

 

Liquidity risk is the risk we will not be able to meet all our financialobligations as they come due.  Liquidityrisk also includes the risk of not being able to liquidate assets in a timelymanner at a reasonable price.   We manageour liquidity risk through the active management of cash and debt by ensuringthat we have access to multiple sources of capital including: cash and cashequivalents, cash from operating activities and undrawn credit facilities.  At December 31, 2009, Cenovus hadapproximately $2.3 billion in unused credit capacity available on its committedbank credit facility.

 

FOREIGN EXCHANGE

 

Foreign exchange risk is defined as the risk of gains or losses thatcould result from changes in foreign currency exchange rates.  As we operate in North America, fluctuationsin the exchange rate between the U.S. and Canadian dollar can have a significanteffect on our reported results.

 

As a means of mitigating the exposure to fluctuations in theU.S./Canadian dollar exchange rate, we may enter into foreign exchangecontracts, in conjunction with crude oil marketing transactions. In addition,we may hedge commodity exposures in Canadian dollars. Gains or losses on thesecontracts are recognized when the difference between the average month spotrate and the rate on the date of settlement is determined. All foreign exchangeagreements are with major financial institutions in Canada and the UnitedStates or with counterparties having investment grade credit ratings.  By maintaining U.S. and Canadian operations,we have a natural hedge to some foreign exchange exposure.

 

We also have the flexibility to maintain a mix of both U.S. dollar andCanadian dollar debt, which helps to offset the exposure to the fluctuations inthe U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S.dollar denominated debt, we may enter into cross currency swaps on a portion ofour debt as a means of managing the U.S./Canadian dollar debt mix.

 

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INTEREST RATES

 

Interest rate risk is defined as the impact of changing interest rateson earnings, cash flows and valuations. Although the majority of our debtportfolio was fixed rate debt at December 31, 2009, we have theflexibility to partially mitigate our exposure to interest rate changes bymaintaining a mix of both fixed and floating rate debt through the use of ourbank credit facilities. We may also enter into interest rate swap transactionsfrom time to time as an additional means of managing the fixed/floating ratedebt portfolio mix.

 

OPERATIONAL RISKS

 

Operational risk is the risk of loss or lost opportunity resulting fromoperating and capital activities that, by their nature, could have an impact onour ability to achieve our objectives.

 

Our ability to operate, generate cash flows, complete projects and valuereserves is dependent on financial risks, including commodity prices mentionedabove, continued market demand for our products and other risk factors outsideof our control, which include:  generalbusiness and market conditions; economic recessions and financial marketturmoil; the ability to secure and maintain cost effective financing for ourcommitments; the ability to obtain necessary approvals; environmental andregulatory matters; unexpected cost increases; royalties; taxes; theavailability of drilling and other equipment; the ability to access lands;weather; the availability of processing capacity; the availability and proximityof pipeline capacity; the availability of diluents to transport crude oil;technology failures; accidents; the availability of skilled labour; andreservoir quality.

 

If we fail to acquire or find additional crude oil and natural gasreserves, our reserves and production will decline materially from theircurrent levels and, therefore, our cash flows are highly dependent uponsuccessfully exploiting current reserves and acquiring, discovering ordeveloping additional reserves.

 

To mitigate these risks, as part of the capital approval process, weevaluate projects on a fully risked basis, including geological risk andengineering risk. In addition, the asset teams undertake a process calledLookback and Learning. In this process, each asset team undertakes a thoroughreview of its previous capital program to identify key learnings, which ofteninclude operational issues that positively and negatively impacted the project’sresults. Mitigation plans are developed for the operational issues that had anegative impact on results. These mitigation plans are then incorporated intothe current year plan for the project. On an annual basis, these Lookback andLearning results are analyzed for our capital program with the results andidentified learnings shared across our company.

 

We utilize a peer review process to ensure that capital projects areappropriately risked and that knowledge is shared across our company. Peerreviews are undertaken primarily for early stage properties, although they mayoccur for any type of project.

 

When making operating and investing decisions, our business model allowsflexibility in capital allocation to optimize investments focused on strategicfit, project returns, long-term value creation, and risk mitigation.  We also mitigate operational risks through anumber of other policies, systems and processes as well as by maintaining acomprehensive insurance program in respect of our assets and operations.

 

SAFETY, ENVIRONMENTAL AND REGULATORY RISKS

 

We are engaged in relatively high risk activities of integrated enhancedoil development and natural gas production. We are committed to safety in ouroperations and with high regard for the environment and stakeholders, includingregulators.  These risks are managed byexecuting policies and standards that are designed to comply with or exceedgovernment regulations and industry standards. In addition, we maintain asystem, in respect of our assets and operation, that identifies, assesses andcontrols safety, security and environmental risk and requires regular reportingto Senior Management and our Board. The Safety, Environment and ResponsibilityCommittee of our Board provides recommended environmental policies for approvalby our Board and oversees compliance with government laws and regulations.Monitoring and reporting programs for environmental, health and safetyperformance in day-to-day operations, as well as inspections and assessments,are designed to provide assurance that environmental

 

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and regulatorystandards are met. Contingency plans are in place for a timely response to anenvironmental event and remediation/reclamation strategies are utilized torestore the environment.  In addition,security risks are managed through a security program designed to protect ourpersonnel and assets.

 

We have an Investigations Committee with the mandate to addresspotential violations of policies and practices and an Integrity Helpline thatcan be used to raise any concerns regarding operations, accounting or internalcontrol matters which includes any such matters associated with us.

 

Our operations are subject to regulation and intervention by governmentsthat can affect or prohibit the drilling, completion and tie-in of wells,production, the construction or expansion of facilities and the operation andabandonment of fields. Contract rights can be cancelled or expropriated.Changes to government regulation could impact our existing and planned projectsas well as impose a cost of compliance.

 

Regulatory and legal risks are identified by the operatingdivisions and corporate groups, and our compliance with the required laws andregulations is monitored by our legal group in respect of our assets andoperations. Our legal and environmental policy groups stay abreast of newdevelopments and changes in laws and regulations to ensure that we continue tocomply with prescribed laws and regulations. Of note in this regard, ourapproach to changes in regulations relating to climate change and royaltyframeworks is discussed below.  To partiallymitigate resource access risks, keep abreast of regulatory developments and bea responsible operator, we maintain relationships with key stakeholders andconduct other mitigation initiatives mentioned herein.

 

**CLIMATE**CHANGE

** **

Various federal, provincial andstate governments have announced intentions to regulate greenhouse gas (“GHG”)emissions and other air pollutants and a number of legislative and regulatorymeasures to address GHG emissions are in various phases of review, discussionor implementation in the United States and Canada. These include proposedfederal legislation and state actions in the United States to develop statewideor regional programs, each of which could impose reductions in GHGemissions.  While some jurisdictions haveprovided details on these regulations, it is anticipated that otherjurisdictions will announce emission reduction plans in the future.  Adverse impacts to our business ifcomprehensive GHG legislation is enacted in any jurisdiction in which weoperate, may include, among other things, increased compliance costs,permitting delays, substantial costs to generate or purchase emission creditsor allowances adding costs to the products we produce and reduced demand forcrude oil and certain refined products.

 

Beyond existing legalrequirements, the extent and magnitude of any adverse impacts of any of theseadditional programs cannot be reliably or accurately estimated at this timebecause specific legislative and regulatory requirements have not beenfinalized and uncertainty exists with respect to the additional measures beingconsidered and the time frames for compliance. We intend to continue our activity to reduce our emissions intensity andimprove our energy efficiency. We will also continue to work with governmentsto develop an approach to deal with climate change issues that protects theindustry’s competitiveness, limits the cost and administrative burden ofcompliance and supports continued investment in the sector.

 

The Alberta government has settargets for GHG emissions reductions. In March 2007, regulations wereamended to require facilities that emit more than 100,000 tonnes of GHGemissions per year to reduce their emissions intensity by 12 percent from aregulated baseline starting July 1, 2007. To comply, companies can makeoperating improvements, purchase carbon offsets (or emission performancecredits) or make a C$15 per tonne contribution to an Alberta Climate Change andEmissions Management Fund. Cenovus currently has three facilities subject tothis regulation that will report performance against their targets in March 2010and for the 2009 compliance year does not anticipate material costs.

 

The American Clean Energy andSecurity Act (the “Act”) was passed by the U.S. House of Representatives on June 26,2009 and similar measures have been contemplated by the U.S. Senate. Some ofthe climate change bills being contemplated in the U.S. would require refinersto purchase credits equivalent to the

 

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CO2 emissions from boththeir refineries and from consumer emissions. If this approach was enacted intolaw, this could have a material impact on the cost structure of refinedpetroleum products.

 

Our efforts with respect toemissions management are founded in our industry leadership in CO2 sequestration, afocus on energy efficiency and the development of technology to reduce GHGemissions.  In particular, our industryleading steam to oil ratio at Foster Creek and Christina Lake translatesdirectly into lower emissions intensity. Given the uncertainty in North American carbon legislation, our strategyfor addressing the implications of emerging carbon regulations is proactive andis composed of three principal elements:

 

1.              Manage Existing Costs

Whenregulations are implemented, a cost is placed on our emissions (or a portionthereof) and while these are not material at this stage, they are beingactively managed to ensure compliance. Factors such as effective emissions tracking attention to fuelconsumption and a focus on minimizing our steam to oil ratio help to supportand drive our focus on cost reduction.

 

2.              Respond to Price Signals

Asregulatory regimes for GHGs develop in the jurisdictions where we work,inevitably price signals begin to emerge. We have initiated an Energy Efficiency Initiative in an effort toimprove the energy efficiency of our operations.  The price of potential carbon reductionsplays a role in the economics of the projects that are implemented. In responseto the anticipated price of carbon reduction, we are also attempting, whereappropriate, to realize the associated value of our reduction projects.

 

3.              Anticipate Future Carbon Constrained Scenarios

We continueto work with governments, academics and industry leaders to develop and respondto emerging GHG regulations.  Bycontinuing to stay engaged in the debate on the most appropriate means to regulatethese emissions, we gain useful knowledge that allows us to explore differentstrategies for managing our emissions and costs.  These scenarios inform our long rangeplanning and our analyses on the implications of regulatory trends.

 

We incorporate the potential costs of carbon into future planning.Management and the Board review the impact of a variety of carbon constrainedscenarios on our strategy, with a current price range from $15 to $65 per tonneof emissions applied to a range of emissions coverage levels. A major benefitof applying a range of carbon prices at the strategic level is that it providesdirect guidance to the capital allocation process.  We also examine the impact of carbonregulation on our major projects. Although uncertainty remains regardingpotential future emissions regulation, our plan is to continue to assess andevaluate the cost of carbon relative to our investments across a range ofscenarios.

 

We recognize that there is a cost associated with carbon emissions. Weare confident that GHG regulations and the cost of carbon at various pricelevels have been adequately accounted for as part of our business planning andscenarios analysis. We believe that our development strategy is an effectiveway to develop the resource, generate shareholder returns and coordinateoverall environmental objectives with respect to carbon, air emissions, waterand land. We are committed to transparency with our stakeholders and will keepthem apprised of how these issues affect operations.

 

TRANSPARENCY AND CORPORATERESPONSIBILITY

 

We are committed to operating in a responsible manner which maintainsand enhances our reputation and credibility. A central aspect of this commitment involves engagement with our variousstakeholders, including shareholders and other investors, financialinstitutions, employees, business partners, communities, Aboriginal peoples,governments and non-governmental organizations. We will continue to discloseinformation about our business activities to our stakeholders in a timely andtransparent manner to maintain and advance our reputation as a responsibleoperator, as well as to develop trust with our stakeholders. We discloseinformation that is not only required by law and/or regulation, but alsoadditional information that management regards as important to helpstakeholders understand our activities, policies, opportunities and risks. Ourengagement with stakeholders also allows us to determine how they are eachaffected by our business. Feedback that we receive from stakeholders enables usto better identify and manage our environmental and socio-economic risks.

 

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We are reviewing our existing Corporate Responsibility (“CR”) policy toensure that it not only continues to drive our commitments, strategy andreporting, but also that it maintains alignment with our business objectivesand processes. Our reporting process will focus on improving performancethrough better data management, stakeholder engagement and continuousimprovement. Our approach in this first year is to communicate our key performanceindicators using the Cenovus website as the main reporting vehicle.

 

As our CR reporting process matures, additional indicators will bedeveloped that better reflect Cenovus’s operations and challenges. Theseindicators will be integrated into our CR reporting and will expand our onlinepresence through our website.

 

We are committed to integrating the principles of corporateresponsibility into the way we conduct our business across all of ouroperations and we recognize the importance of reporting to stakeholders in atransparent and accountable way.

 

ALBERTA’S NEW ROYALTY PROGRAMS

 

The Alberta Government’s NewRoyalty Framework (“NRF”) and Transitional Royalty Program (“TRP”) came intoeffect on January 1, 2009.  The NRF established new royalties forconventional oil, natural gas and bitumen that are linked to commodity prices,well production volumes and well depths for gas wells and oil quality for oilwells.  These new rates apply to both new and existing conventional oiland gas activities and EOR properties in Alberta.  The TRP allows for a one time option ofselecting between transitional rates and the NRF rates on new natural gas orconventional oil wells drilled between 1,000 metres to 3,500 metres in depth. The TRP rates would apply until January 1, 2014, at which time all wellswould be moved to the NRF.

 

On March 3, 2009, the Alberta Government announced an Energy IncentiveProgram that focuses on keeping drilling and service crews at work.  There are two components of this program thataffect us: the Drilling Royalty Credit and the New Well Incentive.  The Drilling Royalty Credit is a depthrelated credit for the drilling of new conventional oil and gas wells between April 1,2009 and March 31, 2011.  The NewWell Incentive provides a maximum five percent royalty rate for new gas andconventional oil wells that come on production between April 1, 2009 and March 31,2011 for a period of 12 months or 0.5 billion cubic feet equivalent (“Bcfe”)for gas wells or 50,000 barrels ofoil equivalent (“BOE”) for oil wells, whichever comes first.

 

Impacts as a result of the NRF, TRPand Energy Incentive Programs change the economics of operating in Alberta, andaccordingly, are reflected in our capital programs in respect of our assets andoperations.

 

We are committed to continuing towork with the Alberta Government during its competitive review process.

 

**ACCOUNTING POLICIES AND ESTIMATES**

 

Managementis required to make judgments, assumptions and estimates in the application ofGAAP that have a significant impact on our financial results. The basis ofpresentation for the Consolidated Financial Statements and our significantaccounting policies can be found in the notes to the Consolidated FinancialStatements.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

Thefollowing discussion outlines the accounting policies and practices involvingthe use of estimates that are critical to understanding our financial results.

 

Basis ofPresentation

 

Our results for the period from December 1 to December 31,2009 represent our operations, cash flows and financial position as astand-alone entity.

 

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Our results for the periods prior to theArrangement with EnCana, being January 1 to November 30, 2009 as wellas the years ended December 31, 2008 and 2007 have been prepared on a “carve-out”accounting basis, whereby the results have been derived from the accountingrecords of EnCana using the historical results of operations and historicalbasis of assets and liabilities of the businesses transferred to Cenovus. Thehistorical consolidated financial statements include allocations of certainEnCana expenses, assets and liabilities. In the opinion of Management, the consolidated and the historicalcarve-out consolidated financial statements reflect all adjustments necessaryfor a fair statement of the financial position and the results of operationsand cash flows in accordance with Canadian GAAP.

 

The presentation of financial statements inaccordance with Canadian GAAP requires management to make estimates and assumptionsthat affect the amounts reported in the financial statements and accompanyingnotes. Actual results could differ from those estimates. Management believesthat the assumptions underlying the historical consolidated financialstatements are reasonable.  However, aswe operated as part of EnCana and were not a stand-alone company prior to November 30,2009, the historical consolidated financial statements included herein may notnecessarily reflect our results of operations, financial position and cashflows had we been a stand-alone company during the periods presented.

 

Full Cost Accounting

 

Crude oiland natural gas properties are accounted for in accordance with the CanadianInstitute of Chartered Accountants (“CICA”) guideline on full cost accountingin the oil and gas industry. Under this method, all costs, including internalcosts and asset retirement costs, directly associated with the acquisition of,exploration for, and the development of crude oil and natural gas reserves, arecapitalized on a country-by-country cost centre basis and costs associated withproduction are expensed. The capitalized costs, including estimated futuredevelopment costs, are depreciated, depleted and amortized using theunit-of-production method based on estimated proved reserves. Reservesestimates can have a significant impact on earnings, as they are a keycomponent in the calculation of DD&A. A downward revision in reservesestimate could result in a higher DD&A charge to earnings. In addition, ifnet capitalized costs are determined to be in excess of the calculated ceiling,which is based largely on reserves estimates (see asset impairment discussionbelow), the excess must be written off as an expense charged against earnings.In the event of a property divestiture, proceeds are normally deducted from thefull cost pool without recognition of a gain or loss unless there is a changein the DD&A rate of 20 percent or greater.

 

Oil and Gas Reserves

 

All of ouroil and gas reserves are evaluated and reported on by independent qualifiedreserves evaluators. The estimation of reserves is a subjective process.Forecasts are based on engineering data, projected future rates of production,estimated commodity price forecasts and the timing of future expenditures, allof which are subject to numerous uncertainties and various interpretations.Reserves estimates can be revised upward or downward based on the results offuture drilling, testing, production levels and economics of recovery based oncash flow forecasts.

 

Asset Impairments

 

Under fullcost accounting, a ceiling test is performed to ensure that unamortizedcapitalized costs in each cost centre do not exceed their fair value. Animpairment loss is recognized in Net Earnings when the carrying amount of acost centre is not recoverable and the carrying amount of the cost centreexceeds its fair value. The carrying amount of the cost centre is notrecoverable if the carrying amount exceeds the sum of the undiscounted cashflows from proved reserves. If the sum of the cash flows is less than thecarrying amount, the impairment loss is limited to an amount by which thecarrying amount exceeds the sum of:

i)      the fair value of proved and probablereserves; and

ii)     the costs of unproved properties that havebeen subject to a separate impairment test.

 

Animpairment loss is recognized on downstream refining property, plant andequipment when the carrying amount is not recoverable and exceeds its fairvalue. The carrying amount is not recoverable if the carrying amount exceedsthe sum of the undiscounted cash flows from expected use and eventual

 

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disposition.If the carrying amount is not recoverable, an impairment loss is measured asthe amount by which the refinery asset exceeds the discounted future cash flowsfrom the refinery asset.

 

Ourproperty, plant and equipment has been assessed for impairment as at December 31,2009 and it has been determined that no write-down was required under CanadianGAAP.

 

Asset Retirement Obligations

 

The fairvalue of estimated asset retirement obligations is recognized in theConsolidated Balance Sheet when incurred and a reasonable estimate of fairvalue can be made. Asset retirement obligations are legal obligationsassociated with the requirement to retire tangible long-lived assets such asproducing well sites, crude oil and natural gas processing plants and refiningfacilities.  The asset retirement cost,equal to the initially estimated fair value of the asset retirement obligation,is capitalized as part of the cost of the related long-lived asset. Changes inthe estimated obligation resulting from revisions to estimated timing or amountof undiscounted cash flows are recognized as a change in the asset retirementobligation and the related asset retirement cost. Increases in the assetretirement obligation resulting from the passage of time are recorded asaccretion of asset retirement obligation in the Consolidated Statement ofEarnings.  Amounts recorded for assetretirement obligations are based on estimates of reserves and on retirementcosts, which will not be incurred for several years. Actual expendituresincurred are charged against the accumulated obligation.

 

Goodwill

 

Goodwill,which represents the excess of purchase price over fair value of net assetsacquired, is assessed for impairment at least annually. Goodwill and all otherassets and liabilities have been allocated to the country cost centre level,referred to as reporting units.  Toassess impairment, the fair value of each reporting unit is determined and comparedto the book value of the reporting unit. If the fair value of the reporting unit is less than the book value,then a second test is performed to determine the amount of the impairment. Theamount of the impairment is determined by deducting the fair value of thereporting unit’s assets and liabilities from the fair value of the reportingunit to determine the implied fair value of Goodwill and comparing that amountto the book value of the reporting unit’s Goodwill.  Any excess of the book value of Goodwill overthe implied fair value of Goodwill is the impairment amount.

 

Our Goodwillhas been assessed for impairment as at December 31, 2009 and it has beendetermined that no write-down was required.

 

Income Taxes

 

Income taxesare accounted for using the liability method. Under this method, future incometaxes are estimated and recorded for the effect of any difference between theaccounting and income tax basis of an asset or liability, using thesubstantively enacted income tax rates. Accumulated future income tax balancesare adjusted to reflect changes in income tax rates that are substantivelyenacted with the adjustment being recognized in Net Earnings in the period thatthe change occurs.

 

Taxinterpretations, regulations and legislation in the various jurisdictions inwhich we (and our subsidiaries) operate are subject to change. As such, incometaxes are subject to measurement uncertainty.

 

Derivative Financial Instruments

 

We may usederivative financial instruments to manage exposure to market risks relating tocommodity prices, foreign currency exchange rates and interest rates.  Derivative financial instruments are not usedfor speculative purposes.

 

We enter into financial transactions to help reduce exposureto price fluctuations with respect to commodity purchase and sale transactionsto achieve targeted investment returns and growth objectives,

 

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while maintaining prescribed financial metrics.  These transactions generally are swaps,collars or options and are generally entered into with major financialinstitutions or commodities trading institutions.

 

We may alsouse derivative financial instruments, such as interest rate swap agreements, tomanage the fixed and floating interest rate mix of our total debt portfolio andrelated overall cost of borrowing. Interest rate swap agreements involve theperiodic exchange of payments, without the exchange of the normal principalamount upon which the payments are based, and are recorded as an adjustment ofinterest expense on the hedged debt instrument.

 

We may alsopurchase foreign exchange forward contracts to hedge anticipated sales tocustomers in the United States. Foreign exchange translation gains and losseson these instruments are recognized as an adjustment of the revenues when thesale is recorded.

 

Derivativeinstruments that do not qualify as hedges, or are not designated as hedges, arerecorded using the mark-to-market method of accounting whereby instruments arerecorded in the Consolidated Balance Sheet as either an asset or liability withchanges in fair value recognized in Net Earnings. Realized gains or losses fromfinancial derivatives related to crude oil and natural gas prices arerecognized in revenues as the related sales occur. Unrealized gains and lossesare recognized in revenues at the end of each respective reporting period. Theestimate of fair value of all derivative instruments is based on quoted marketprices or, in their absence, third-party market indications and forecasts.  The estimated fair value of financial assetsand liabilities, by their very nature, is subject to measurement uncertainty.

 

In 2009, weelected not to designate any of our price risk management activities asaccounting hedges and, accordingly, accounted for all derivatives using themark-to-market accounting method. Mark-to-market gains and losses resulting from derivative financialinstruments entered into by EnCana have been allocated to Cenovus based on therelated product volumes.

 

We also haveobligations for payments (to employees of Cenovus) under the share appreciationrights, stock options with TSARs attached, performance share appreciationrights, and performance TSARs of EnCana. The financial liability for thisobligation is accrued using the fair value method, and therefore fluctuationsin the fair value of the rights will affect the accrued compensation expensethat is recognized. The fair value of the obligation fluctuates, as it is basedon assumptions for risk-free discount rate, dividend yield, as well as thevolatility of our Cenovus share price.

 

Pensions and Other Post-EmploymentBenefits

 

Accruals forthe obligations under the employee benefit plans and the related costs arerecorded net of plan assets.

 

The cost ofpensions and other post-employment benefits is actuarially determined using theprojected benefit method based on length of service, and reflects Management’sbest estimate of expected plan investment performance, salary escalation,retirement ages of employees and expected future health care costs. Theexpected return on plan assets is based on the fair value of those assets. Theaccrued benefit obligation is discounted using the market interest rate on highquality corporate debt instruments as at the measurement date.

 

Pensionexpense for the defined benefit pension plan includes the cost of pensionbenefits earned during the current year, the interest cost on pensionobligations, the expected return on pension plan assets, the amortization ofthe net transitional obligation, the amortization of adjustments arising frompension plan amendments and the amortization of the excess of the net actuarialgain or loss over 10 percent of the greater of the benefit obligation and thefair value of plan assets. The amortization period covers the expected averageremaining service lives of employees covered by the plans.

 

Pensionexpense for the defined contribution pension plans is recorded as the benefitsare earned by the employees covered by the plan.

 

Pension andother post-employment benefits costs, assets and liabilities have beenallocated to us based on Management’s best estimate of how services werehistorically provided by existing employees. Costs,

 

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assets andliabilities associated with retired employees remain with EnCana.  Where service amounts are provided by anindividual to both EnCana and Cenovus, those costs including salaries,benefits, pension and long-term incentives have been allocated equally betweenEnCana and Cenovus.

 

Performance TSARs and PerformanceSARs

 

These plansprovide for a range of payouts, based on key predetermined performancemeasures. The cost of these plans is expensed based on expected payouts.  However, the amounts to be paid, if any, mayvary from the current estimate.  Furtherdetails on these plans are disclosed in the notes to our Consolidated FinancialStatements.

 

NEW ACCOUNTINGSTANDARDS ADOPTED

 

On January 1,2009, we adopted the CICA Handbook Section 3064 “Goodwill and IntangibleAssets”. The adoption of this standard has had no material impact on ourConsolidated Financial Statements. Additional information on the effects of the implementation of the newstandard can be found in the notes to the Consolidated Financial Statements.

 

RECENT ACCOUNTING PRONOUNCEMENTS

 

As of January 1,2011, we will be required to adopt the following CICA Handbook sections whichhave been converged with International Financial Reporting Standards (“IFRS”):

 

BusinessCombinations

 

“BusinessCombinations”, Section 1582, replaces the previous business combinationsstandard.  The standard requires assetsand liabilities acquired in a business combination, contingent considerationand certain acquired contingencies to be measured at their fair values as ofthe date of acquisition.  In addition,acquisition-related and restructuring costs are to be recognized separatelyfrom the business combination and included in the statement of earnings.  The adoption of this standard will impact theaccounting treatment of future business combinations.

 

ConsolidatedFinancial Statements

 

“ConsolidatedFinancial Statements”, Section 1601, which together with Section 1602below, replace the former consolidated financial statements standard.  Section 1601 establishes therequirements for the preparation of consolidated financial statements.  The adoption of this standard should not havea material impact on our Consolidated Financial Statements.

 

Non-controllingInterests

 

“Non-controllingInterests”, Section 1602, establishes the accounting for a non-controllinginterest in a subsidiary in consolidated financial statements subsequent to abusiness combination.  The standardrequires a non-controlling interest in a subsidiary to be classified as aseparate component of equity.  Inaddition, Net Earnings and components of other comprehensive income areattributed to both the parent and non-controlling interest.  The adoption of this standard should not havea material impact on our Consolidated Financial Statements.

 

INTERNATIONALFINANCIAL REPORTING STANDARDS

 

In 2011, IFRS will replace Canadian GAAP for profit-orientedCanadian publicly accountable enterprises. We will be required to report ourresults in accordance with IFRS beginning with the 3 month period ending March 31,2011.

 

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Our IFRS Transition Plan

 

We have developed a changeover plan to complete thetransition to IFRS by January 1, 2011, including the preparation ofrequired comparative information for 2010. The key elements of our changeoverplan include:

·                   Determineappropriate changes to accounting policies and required amendments to financialdisclosures;

·                   Identify andimplement changes in associated processes and information systems;

·                   Comply with internalcontrol requirements;

·                   Communicatecollateral impacts to internal business groups; and

·                   Educate and traininternal and external stakeholders.

 

IFRS Accounting Policies

 

We have completed our analysis of accounting policyalternatives and determined the areas that will be most significantly affectedby the adoption of IFRS. The areas identified as being significant have thegreatest potential impact to our financial statements or the greatest risk interms of complexity to implement. The most significant areas continue toinclude:

·                   Upstream Property,Plant and Equipment (“PP&E”), including

                 Transition on date of adoption ofIFRS

                 Pre-exploration costs

                 Exploration and Evaluation costs

                 DD&A

                 Gains and losses on divestitures

·                   Impairment testing

·                   Asset retirementobligation

·                   Stock-based compensation

·                   Income taxes

 

Upstream PP&E

 

Upstream PP&E will be one of the most significant areasimpacted by the adoption of IFRS.  UnderCanadian GAAP, we follow the CICA’s guideline on full cost accounting, whileIFRS has no equivalent guideline. In order to facilitate the transition to IFRSby full cost accounting companies, the International Accounting Standards Board(“IASB”) released additional exemptions for first-time adopters of IFRS in July 2009.  Included in the amendments is an exemptionwhich permits full cost accounting companies to allocate their existingupstream PP&E net book value (full cost pool) over reserves to the unit ofaccount level upon transition to IFRS. We expect to adopt this exemption using the fair value of reserves as anallocation method. Without this exemption, we would have been required toretrospectively determine the carrying amount of oil and gas assets at the dateof transition, or use the fair value or revaluation amount as our new deemedcost under IFRS.  By using the exemption,the net book value of our upstream PP&E at the date of transition to IFRSwill be the same as it was under Canadian GAAP, subject to any potential IFRSimpairments that are recognized at the date of transition.

 

In moving to IFRS, we will be required to adopt differentaccounting policies for pre-exploration activities, exploration and evaluationcosts, DD&A and the accounting for gains and losses on divestitures ofproperties.

 

Pre-exploration costs are costs incurred before the Companyobtains the legal right to explore an area. Under Canadian GAAP, these costsare capitalized, while under IFRS, these costs must be expensed. At this time,we do not anticipate that this accounting policy difference will have asignificant impact on our Consolidated Financial Statements.

 

During the exploration and evaluation phase (“E&E”), wecapitalize costs incurred for these projects under Canadian GAAP. Under IFRS,we have the alternative to either continue capitalizing these costs untiltechnical feasibility and commercial viability of the project has beendetermined, or expensing these costs as incurred. At this time, our IFRSaccounting policy in relation to E&E activities has not been finalized.

 

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Under Canadian GAAP, we calculate our DD&A rate at thecountry cost centre level. Under IFRS, this rate will be calculated at a lowerunit of account level. At this time, we have not finalized our policy in thisregard, and therefore the impact of this difference in accounting policy is notreasonably determinable.

 

Full cost accounting under Canadian GAAP requires that gainsor losses on divestitures of properties are only recognized when the disposalwould affect our DD&A rate by 20 percent or more. Under IFRS, there is nosuch exemption, and therefore we will be required to recognize all gains andlosses on property divestitures. At this time, the impact of this difference inaccounting policy is not reasonably determinable.

 

As a result of the additional exemption released by theIASB, we anticipate that all changes to our Upstream PP&E accountingpolicies will be adopted prospectively.

 

Impairment Testing

 

For the first step of all of our impairment tests (Upstream,Downstream, Goodwill) under Canadian GAAP, future cash flows are notdiscounted. Under IFRS, the future cash flows are discounted. In addition, forupstream PP&E, impairment testing is currently performed at the countrycost centre level, while under IFRS, it will be performed at a lower level,referred to as a cash-generating unit. We expect to adopt these changes inaccounting policy prospectively. At this time, the impact of accounting policydifferences related to impairment testing is not reasonably determinable.

 

Asset Retirement Obligation

 

Under Canadian GAAP, the discount rate used to estimate theliability is not updated to current market discount rates, while under IFRS,the rate is updated each reporting period. We expect to adopt this change inaccounting policy prospectively. We do not anticipate that this accountingpolicy difference will have a significant impact on our consolidated financialstatements.

 

Stock-based Compensation

 

Under Canadian GAAP, obligations for cash payments understock-based compensation plans are accrued using the intrinsic method, whileunder IFRS, these obligations must be accounted for using the fair valuemethod. While the carrying value each reporting period will be different underIFRS, the cumulative expense recognized over the life of the instrument underboth methods will be the same. We expect to adopt this change in accountingpolicy prospectively. At this time, the impact of this difference is notreasonably determinable.

 

Income Tax

 

In transitioning to IFRS, the carrying amount of our taxbalances will be directly impacted by the tax effects resulting from changesrequired by the above IFRS accounting policy differences. Therefore, at thistime the income tax impacts of our differences are not reasonably determinable.

 

Changes to IFRS AccountingStandards

 

Our analysis of accounting policy differences specificallyconsiders the current IFRS standards that are in effect. We will continue tomonitor any new or amended accounting standards that are issued by the IASB,including assessing any impact of the new joint ventures standard that the IASBexpects to publish in the first quarter of 2010.

 

Preparation of the IFRS OpeningBalance Sheet

 

We expect to commence working on the determination of ourIFRS opening balance sheet in the first quarter of 2010.

 

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Information Systems

 

We have completed the design of process and system changesthat we expect will be required. We have performed preliminary testing of thechanges and expect to finalize our testing in the first half of 2010. We planto fully implement the system changes by June 30, 2010.

 

Internal Controls Over FinancialReporting

 

We are in the process of updating our internal controlsdocumentation, and we do not anticipate that the transition to IFRS will have asignificant impact on either our internal controls over financial reporting, orour disclosure controls and procedures.

 

Education and Training

 

All of the individuals that are involved in our financialreporting under Canadian GAAP have been engaged and involved in the IFRStransition project since 2008, and will continue to be involved in our IFRStransition throughout 2010 and 2011. Other individuals affected by the changefrom Canadian GAAP to IFRS will be educated and trained during 2010 as weidentify and calculate the specific dollar value of differences arising fromthe changes to our accounting policies.

 

Impacts to our Business

 

We are not expectingthat the adoption of IFRS in 2011 will have a significant impact or influenceon our business activities, operations or strategies.

 

**OUTLOOK**

 

Our long term objective is to focus on building net assetvalue and generating an attractive total shareholder return through thefollowing strategies:
| · | Visible material growth in enhanced oil resource  development, particularly with expansions at our Foster Creek and Christina  Lake SAGD bitumen operations. We also have an extensive inventory of emerging  bitumen plays; |
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| · | Leadership in low-cost SAGD development; enabled by  technology and continued respect for our employee’s safety, our stakeholders  and the environment;                                                                 |
| · | Internally funded growth through free cash flow from our  established crude oil and natural gas assets; and                                                                                                                  |
| · | Maintaining a lower risk profile through natural gas and  downstream integration as well as hedging execution.                                                                                                               |

 

We believeglobal oil demand will continue to increase. However, commodity pricevolatility, environmental regulations, government intervention and competitivepressures within our industry are the key hurdles that need to be effectivelymanaged to enable our growth. Additional detail regarding the impact of thesefactors on our 2009 results is discussed in the Risk Management section of thisMD&A. WTI and light-heavy differentials are likely to be relatively strongfor the foreseeable future. Offsetting this is a relatively weak price outlookfor natural gas and refining margins.

 

We expectour 2010 capital investment program to be funded from Cash Flow. Our crude oiland natural gas assets in Alberta and Saskatchewan will be key to providingfree cash flow to enable our bitumen growth. We have chosen to acceleratecompletion of Christina Lake phase D which we expect will advance start up byapproximately six months.

 

As part of ongoingefforts to maintain financial resilience and flexibility, Cenovus has takensteps to reduce pricing risk through a commodity hedging program. While we havebenefitted from this strategy in 2009 and 2008, we cannot ensure that we willcontinue to derive such benefits in the future.

 

One of thefactors that will affect our future results will be our effective royaltyrates. Based on current market pricing, we expect that the Foster Creek projectwill reach payout during 2010.  Once theproject

 

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reachespayout the applicable monthly royalty will be based on the greater of 1-9percent of the project’s gross revenue or 25-40 percent of the net revenue. Theactual royalty rate that is payable within these ranges is determined based onthe WTI U.S. dollar price of crude oil, translated into Canadian dollars.

 

Asa new entity, the Company will continue to develop strategy with respect tocapital investment and returns to shareholders. Future dividends will be at thesole discretion of the Board and considered quarterly.

 

**ADVISORY**

 

FORWARD-LOOKINGSTATEMENTS

 

In the interest ofproviding Cenovus shareholders and potential investors with informationregarding the Company and its subsidiaries, including Management’s assessmentof Cenovus’s and its subsidiaries’ future plans and operations, certainstatements contained in this document constitute forward-looking statements orinformation (collectively referred to herein as “forward-looking statements”)within the meaning of the “safe harbour” provisions of applicable securitieslegislation. Forward-looking statements are typically identified by words suchas “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”or similar words suggesting future outcomes or statements regarding an outlook.Forward-looking statements in this document include, but are not limited to,statements with respect to: projections relating to the adequacy of ourprovision for taxes; the effect of our policies and programs to reduce safety,environmental and regulatory risks, including climate change; our estimate ofthe cost of carbon; the potential impact of the Alberta Royalty Framework, NRF,TRP and Energy Incentive Programs; projections and plans with respect to growthof natural gas production from unconventional properties and enhanced oilresources including with respect to the Foster Creek and Christina Lakeproperties, the CORE project and planned expansions of our downstream heavy oilprocessing capacity and the capital costs and expected timing of the same; ourability to meet consumer demand; projections relating to the volatility ofcrude oil prices in 2010 and beyond and the reasons therefor; commodity prices,including the WTI and light-heavy differentials; our projected capitalinvestment levels for 2010, the flexibility of capital spending plans and thesource of funding therefor; the effect of our risk management program,including the impact of derivative financial instruments and our access tovarious sources of capital; the adequacy of provisions made for legalproceedings against us; the impact of the changes and proposed changes in lawsand regulations, including greenhouse gas, carbon and climate changeinitiatives on our operations and operating costs; our ability to realize theexpected benefits of the Arrangement; potential dividends; our expected futureattributes, business plan and operational focus; our ability to fund our 2010capital program; the effect of our risk mitigation policies, systems, processesand insurance program; our expectations for future Debt to Capitalization andDebt to Adjusted EBITDA ratios; the expected impact and timing of variousaccounting pronouncements, rule changes and standards on us and ourConsolidated Financial Statements; and projections relating to global oildemand, prices for natural gas and refining margins. Readers are cautioned notto place undue reliance on forward-looking statements, as there can be noassurance that the plans, intentions or expectations upon which they are basedwill occur. By their nature, forward-looking statements involve numerousassumptions, known and unknown risks and uncertainties, both general andspecific, that contribute to the possibility that the predictions, forecasts,projections and other forward-looking statements will not occur, which may causeour actual performance and financial results in future periods to differmaterially from any estimates or projections of future performance or resultsexpressed or implied by such forward-looking statements. These risks anduncertainties include, among other things: volatility of and assumptionsregarding oil and gas prices; assumptions based upon our current guidance;fluctuations in currency and interest rates; product supply and demand; marketcompetition; risks inherent in our and our subsidiaries’ marketing operations,including credit risks; imprecision of reserves estimates and estimates ofrecoverable quantities of oil, bitumen, natural gas and liquids from propertiesand other sources not currently classified as proved; our and our subsidiaries’ability to replace and expand oil and gas reserves; the ability of ourselvesand ConocoPhillips to successfully manage and operate the North Americanintegrated heavy oil business and the ability of the parties to obtainnecessary regulatory approvals; refining and marketing margins; potentialdisruption or unexpected technical difficulties in developing new products andmanufacturing processes; potential failure of new products to achieveacceptance in the market; unexpected cost increases or technical difficultiesin constructing or modifying manufacturing or refining facilities; unexpecteddifficulties in manufacturing, transporting or refining synthetic crude oil;risks associated with

 

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technology and theapplication thereof to our business; our ability to generate sufficient cashflow from operations to meet our current and future obligations; our ability toaccess external sources of debt and equity capital; the timing and the costs ofwell and pipeline construction; our and our subsidiaries’ ability to secureadequate product transportation; changes in royalty, tax, environmental,greenhouse gas, carbon and other laws or regulations or the interpretations ofsuch laws or regulations; political and economic conditions in the countries inwhich we and our subsidiaries operate; the risk of war, terrorist threats,hostilities, civil insurrection and instability affecting countries in which weand our subsidiaries operate; risks associated with existing and potentialfuture lawsuits and regulatory actions made against us and our subsidiaries; thefinancing plans and initiatives that may be undertaken by us, thecapitalization and adequacy thereof for us, the expected impacts of theArrangement on our employees, operations, suppliers, business partners andstakeholders, our ability to obtain financing in the future on a stand alonebasis, that the historical financial information pertaining to our assets asoperated by EnCana prior to November 30, 2009 may not be representative ofour results as an independent entity, that we have a limited operating history,as a separate entity, and other risks and uncertainties described from time totime in the reports and filings we have made with securities regulatoryauthorities. Statements relating to “reserves” are deemed to be forward-lookingstatements, as they involve the implied assessment, based on certain estimatesand assumptions that the resources and reserves described exist in thequantities predicted or estimated, and can be profitably produced in thefuture. Although we believe that the expectations represented by suchforward-looking statements are reasonable, there can be no assurance that suchexpectations will prove to be correct. Readers are cautioned that the foregoinglist of important factors is not exhaustive. Furthermore, the forward-lookingstatements contained in this document are made as of the date of this document,and except as required by law, we do not undertake any obligation to updatepublicly or to revise any of the included forward-looking statements, whetheras a result of new information, future events or otherwise. The forward-lookingstatements contained in this document are expressly qualified by thiscautionary statement.

 

We previouslydisclosed and updated guidance relating to anticipated results for 2009. Therewere no material differences between (a) our actual cash flow, capitalinvestment and operating costs in 2009 and (b) the amounts forecast in ourmost recently disclosed guidance (dated December 1, 2009). Explanationsfor any changes contained in any updated guidance, from guidance previouslydisclosed, were provided in the news release issued by Cenovus at the time theguidance was updated.

 

Our forward-lookinginformation respecting anticipated 2010 cash flow, operating cash flow andpre-tax cash flow is based upon achieving average 2010 production ofapproximately 105,000 bbls/d to 111,500 bbls/d of crude oil and liquids and 720MMcf/d to 740 MMcf/d of natural gas, average commodity prices for 2010 of a WTIprice of $65 per bbl to $85 per bbl and a WCS price of $54 per bbl to $71 perbbl for oil, a NYMEX price of $5.50 per Mcf to $6.15 per Mcf and AECO price of$5.15 per GJ to $5.70 per GJ for natural gas, an average U.S./Canadian dollarforeign exchange rate of $0.85 to $0.96 US$/CDN$, an average Chicago 3-2-1 crackspread for 2010 of $7.50 per bbl to $9.50 per bbl for refining margins, and anaverage number of outstanding shares of approximately 750 million. Assumptionsrelating to forward-looking statements generally include our currentexpectations and projections made by the Company in light of, and generallyconsistent with, its historical experience and its perception of historicaltrends, as well as expectations regarding rates of advancement and innovation,generally consistent with and informed by its past experience, all of which aresubject to the risk factors identified elsewhere in this document.

 

We are required todisclose events and circumstances that occurred during the period to which thisMD&A relates that are reasonably likely to cause actual results to differmaterially from material forward-looking statements for a period that is notyet complete that we have previously disclosed to the public and the expecteddifferences thereto. Such disclosure can be found in our news release dated February 11,2010 which is available on www.sedar.com.

 

OILAND GAS INFORMATION

 

Our disclosure ofreserves data and other oil and gas information is made in reliance on anexemption granted to us by Canadian securities regulatory authorities thatpermits us to provide such disclosure in accordance with U.S. disclosurerequirements. The information provided by us may differ from the correspondinginformation prepared in accordance with Canadian disclosure standards under NI51-101.

 

38
| Cenovus  Energy Inc. |   | Management’s Discussion and Analysis (prepared in US$) |
|----------------------|--------|-------------------------------------------------------------|

 

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The reservesquantities disclosed by us represent net proved and probable reservescalculated using the standards contained in Regulation S-X of the U.S.Securities & Exchange Commission. Further information about thedifferences between the U.S. requirements and the NI 51-101 requirements is setforth under the heading “Note Regarding Reserves Data and Other Oil and GasInformation” in our Annual Information Form for the year ended December 31,2009.

 

CRUDEOIL, NGLs AND NATURAL GAS CONVERSIONS

 

In this document,certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”)on the basis of one barrel to six thousand cubic feet. BOE may be misleading,particularly if used in isolation. A conversion ratio of one bbl to six Mcf isbased on an energy equivalency conversion method primarily applicable at theburner tip and does not necessarily represent value equivalency at the wellhead.

 

CURRENCY

 

All informationincluded in this document and the Consolidated Financial Statements andcomparative information is shown on a U.S. dollar, after royalties basis unlessotherwise noted.

 

NON-GAAPMEASURES

 

Certain measures inthis document do not have any standardized meaning as prescribed by CanadianGAAP such as Cash Flow, Operating Cash Flow, Free Cash Flow, OperatingEarnings, Adjusted EBITDA, Debt and Capitalization and therefore are considerednon-GAAP measures. Therefore, these measures may not be comparable to similarmeasures presented by other issuers. These measures have been described andpresented in this document in order to provide shareholders and potentialinvestors with additional information regarding our liquidity and our abilityto generate funds to finance our operations. Management’s use of these measureshas been disclosed further in this document as these measures are discussed andpresented.

 

REFERENCESTO CENOVUS

 

For convenience,references in this document to “Cenovus”, “we”, “us”, “our” and “its” may,where applicable, refer only to or include any relevant direct and indirectsubsidiary corporations and partnerships (“Subsidiaries”) of Cenovus, and theassets, activities and initiatives of such Subsidiaries.

 

Additional information regarding Cenovus Energy Inc. can be accessedunder our public filings, including our Annual Information Form for theyear ended December 31, 2009, found at www.sedar.com and on ourwebsite at www.cenovus.com.

 

39
| Cenovus  Energy Inc. |   | Management’s Discussion and Analysis (prepared in US$) |
|----------------------|--------|-------------------------------------------------------------|

 

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Cenovus Energy Inc.

 

 

 

Consolidated Financial Statements

 

 

For the Year Ended December 31, 2009

 

 

 

(U.S. Dollars)

 

 

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Report of Management

 

***Management’sResponsibility for the Consolidated**********Financial Statements***

 

The accompanying Consolidated Financial Statements ofCenovus Energy Inc. (“Cenovus”) are the responsibility of Management. TheConsolidated Financial Statements have been prepared by Management in UnitedStates dollars in accordance with Canadian generally accepted accountingprinciples and include certain estimates that reflect Management’s bestjudgments.

 

The Board of Directors has approved the informationcontained in the Consolidated Financial Statements. The Board of Directorsfulfills its responsibility regarding the financial statements mainly throughits Audit Committee which is made up of three independent directors. The AuditCommittee has a written mandate that complies with the current requirements ofCanadian securities legislation and the United States *Sarbanes-Oxley Act of 2002*and voluntarilycomplies, in principle, with the Audit Committee guidelines of the New YorkStock Exchange. The Audit Committee meets with Management and the independentauditors at least on a quarterly basis to review and approve interimConsolidated Financial Statements and Management’s Discussion and Analysisprior to their release as well as annually to review the annual ConsolidatedFinancial Statements and Management’s Discussion and Analysis and recommendtheir approval to the Board of Directors.

 

***Management’sAssessment of Internal Control over Financial**********Reporting***

 

Management is also responsible for establishing andmaintaining adequate internal control over financial reporting. The internalcontrol system was designed to provide reasonable assurance to Managementregarding the preparation and presentation of the Consolidated FinancialStatements.

 

Internal control systems, no matter how well designed, haveinherent limitations. Therefore, even those systems determined to be effectivecan provide only reasonable assurance with respect to financial statementpreparation and presentation. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

 

Management has assessed the design and effectiveness ofinternal control over financial reporting as at December 31, 2009. Inmaking its assessment, Management has used the Committee of SponsoringOrganizations of the Treadway Commission (“COSO”) framework in Internal Control–IntegratedFramework to evaluate the design and effectiveness of internal control overfinancial reporting. Based on our evaluation, Management has concluded thatinternal control over financial reporting was effective as at that date.

 

PricewaterhouseCoopers LLP, an independent firm of CharteredAccountants, was appointed to audit and provide independent opinions on boththe Consolidated Financial Statements and internal control over financialreporting as at December 31, 2009 as stated in their Auditors’Report.  PricewaterhouseCoopers LLP hasprovided such opinions.

 

 

 
| /s/ Brian C. Ferguson   |       | /s/ Ivor M. Ruste                   |
|-------------------------|------------|-------------------------------------|
| **Brian C. Ferguson**   | ** ** | **Ivor M. Ruste**                   |
| President &    |       | Executive Vice-President & |
| Chief Executive Officer |       | Chief Financial Officer             |
| Cenovus Energy Inc.     |       | Cenovus Energy Inc.                 |
|                    |       |                                |
| February 17, 2010  |       |                                |

 

 
| Cenovus Energy Inc. | 2 |   |
|---------------------|---|--------|

 

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| Independent Auditors’ Report |
|-----------------------------------|

 

**To the Shareholders of Cenovus EnergyInc.**

 

We have completed integrated audits of Cenovus Energy Inc.’s2009 and 2008 consolidated financial statements and of its internal controlover financial reporting as of December 31, 2009 and an audit of its 2007consolidated financial statements. Our opinions, based on our audits, arepresented below.

 

**Consolidated Financial Statements**

 

We have audited theaccompanying consolidated balance sheets of Cenovus Energy Inc. as at December 31,2009 and December 31, 2008, and the related consolidated statements ofearnings and comprehensive income, shareholders’ equity, and cash flows foreach of the years in the three year period ended December 31, 2009. Thesefinancial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

We conducted ouraudits of the Company’s financial statements as at December 31, 2009 and December 31,2008 and for each of the years in the two year period ended December 31,2009 in accordance with Canadian generally accepted auditing standards and thestandards of the Public Company Accounting Oversight Board (United States). Weconducted our audit of the Company’s financial statements for the year ended December 31,2007 in accordance with Canadian generally accepted auditing standards. Thosestandards require that we plan and perform an audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit of financial statements includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statements.A financial statement audit also includes assessing the accounting principlesused and significant estimates made by management, and evaluating the overallfinancial statement presentation. We believe that our audits provide areasonable basis for our opinion.

 

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of the Company as at December 31,2009 and December 31, 2008 and the results of its operations and its cashflows for each of the years in the three year period ended December 31,2009 in accordance with Canadian generally accepted accounting principles.

 

**Internal Control over FinancialReporting**

 

We have also audited Cenovus Energy Inc.’s internal controlover financial reporting as of December 31, 2009, based on criteriaestablished in *Internal Control - IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (“COSO”). The Company’s management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting, included in theaccompanying Management’s Assessment of Internal Control over FinancialReporting. Our responsibility is to express an opinion on the effectiveness ofthe Company’s internal control over financial reporting based on our audit.

 

We conducted our audit of internal control over financialreporting in accordance with the standards of the Public Company AccountingOversight Board (United States). Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects. An audit of internal control over financial reporting includesobtaining an understanding of internal control over financial reporting,assessing the risk that a material weakness exists, testing and evaluating thedesign and operating effectiveness of internal control based on the assessedrisk, and performing such other procedures as we consider necessary in thecircumstances. We believe that our audit provides a reasonable basis for ouropinion.

 

A company’s internal control over financial reporting is aprocess designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies andprocedures that (i) pertain to the 

 

 
| Cenovus Energy Inc. | 3 |   |
|---------------------|---|--------|

 

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maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assetsof the company; (ii) provide reasonable assurance that transactions arerecorded as necessary to permit preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts andexpenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (iii) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have amaterial effect on the financial statements.

 

Because of its inherent limitations, internal control overfinancial reporting may not prevent or detect misstatements. Also, projectionsof any evaluation of effectiveness to future periods are subject to the riskthat controls may become inadequate because of changes in conditions, or thatthe degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, the Company maintained, in all materialrespects, effective internal control over financial reporting as of December 31,2009 based on criteria established in Internal Control — Integrated Frameworkissued by the COSO.

 

 

 
| **/s/ PricewaterhouseCoopers LLP** |
|------------------------------------|
| **PricewaterhouseCoopers LLP**     |
| Chartered Accountants              |
| Calgary, Alberta                   |
| Canada                             |
|                               |
| February 17, 2010             |

 

 
| Cenovus Energy Inc. | 4 |   |
|---------------------|---|--------|

 

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| CONSOLIDATED STATEMENT OF EARNINGS AND   COMPREHENSIVE INCOME |
|---------------------------------------------------------------|

 
| For the years ended December 31, (US$ millions, except per  share amounts) | ** ** | ** **  | ** ** | **2009**   |   | 2008   |   | 2007   |   |
|--------------------------------------------------------------------------------------|------------|-------------|------------|------------|--------|--------|--------|--------|--------|
|                                                                                 | ** ** | ** **  |       |       |   |   |   |   |   |
| Revenues,  Net of Royalties                                                          | * *   | *(Note 1)*  | ** ** | **10,140** |   | 16,559 |   | 13,406 |   |
| Expenses                                                                             | * *   | *(Note 1)*  | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes                                                         |       |        | ** ** | **38**     |   | 75     |   | 63     |   |
| Transportation and selling                                                           |       |        | ** ** | **672**    |   | 963    |   | 756    |   |
| Operating                                                                            |       |        | ** ** | **1,154**  |   | 1,223  |   | 1,114  |   |
| Purchased product                                                                    |       |        | ** ** | **5,250**  |   | 9,710  |   | 7,476  |   |
| Depreciation, depletion and  amortization                                            |       |        | ** ** | **1,343**  |   | 1,318  |   | 1,426  |   |
| General and administrative                                                           |       |        | ** ** | **188**    |   | 167    |   | 145    |   |
| Interest, net                                                                        | * *   | *(Note 6)*  | ** ** | **218**    |   | 218    |   | 187    |   |
| Accretion of asset retirement  obligation                                            | * *   | *(Note 14)* | ** ** | **39**     |   | 39     |   | 28     |   |
| Foreign exchange (gain) loss, net                                                    | * *   | *(Note 7)*  | ** ** | **290**    |   | (250   | )      | 380    |   |
| Other (income) loss, net                                                             | * *   | * *    | ** ** | **(2**     | **)**  | 3      |   | 4      |   |
|                                                                                 | ** ** | ** **  | ** ** | **9,190**  |   | 13,466 |   | 11,579 |   |
| Earnings  Before Income Tax                                                          |       |        | ** ** | **950**    |   | 3,093  |   | 1,827  |   |
| Income tax expense                                                                   | * *   | *(Note 8)*  | ** ** | **302**    |   | 725    |   | 423    |   |
| Net  Earnings                                                                        |       |        | ** ** | **648**    |   | 2,368  |   | 1,404  |   |
| Other  Comprehensive Income, Net of Tax                                              |       |        | ** ** | ** ** |   |   |   |   |   |
| Foreign  Currency Translation Adjustment                                             |       |        | ** ** | **1,979**  |   | (2,246 | )      | 1,265  |   |
| Comprehensive  Income                                                                |       |        | ** ** | **2,627**  |   | 122    |   | 2,669  |   |
|                                                                                 | ** ** | ** **  |       |       |   |   |   |   |   |
| Net  Earnings per Common Share                                                       | * *   | *(Note 19)* | ** ** | ** ** |   |   |   |   |   |
| Basic                                                                                |       |        | ** ** | **0.86**   |   | 3.16   |   | 1.86   |   |
| Diluted                                                                              |       |        | ** ** | **0.86**   |   | 3.15   |   | 1.84   |   |

 

 

*See accompanying Notes toConsolidated Financial**Statements.*

 

 
| Cenovus Energy Inc. | 5 |   |
|---------------------|---|--------|

 

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CONSOLIDATED BALANCE SHEET

 

| As at December 31, (US$ millions)             | ** ** | ** **      |       | **2009**   |   | 2008   |   |
|---------------------------------------------------------|------------|-----------------|------------|------------|--------|--------|--------|
|                                                    | ** ** | ** **      |       |       |   |   |   |
| Assets                                                  |       |            | ** ** | ** ** |   |   |   |
| Current Assets                                          |       |            | ** ** | ** ** |   |   |   |
| Cash and cash equivalents                               |       |            | ** ** | **148**    |   | 153    |   |
| Accounts receivable and accrued  revenues               |       |            | ** ** | **874**    |   | 598    |   |
| Income tax receivable                                   | * *   | * *        | ** ** | **38**     |   | -      |   |
| Current portion of Partnership  Contribution Receivable | * *   | *(Note 9)*      | ** ** | **330**    |   | 313    |   |
| Risk management                                         | * *   | *(Note 18)*     | ** ** | **58**     |   | 681    |   |
| Inventories                                             | * *   | *(Note 10)*     | ** ** | **836**    |   | 503    |   |
|                                                    | ** ** | ** **      |       | **2,284**  |   | 2,248  |   |
| Property, Plant and Equipment, net                      | * *   | *(Notes 1, 11)* | ** ** | **14,537** |   | 12,260 |   |
| Partnership Contribution Receivable                     | * *   | *(Note 9)*      | ** ** | **2,504**  |   | 2,834  |   |
| Risk Management                                         | * *   | *(Note 18)*     | ** ** | **1**      |   | 38     |   |
| Other Assets                                            | * *   | *(Note 12)*     | ** ** | **131**    |   | 150    |   |
| Goodwill                                                | * *   | *(Note 1)*      | ** ** | **1,095**  |   | 936    |   |
|                                                    | ** ** | ** **      |       | **20,552** |   | 18,466 |   |
|                                                    | ** ** | ** **      |       |       |   |   |   |
| Liabilities  and Shareholders’ Equity              |       |            | ** ** | ** ** |   |   |   |
| Current Liabilities                                     |       |            | ** ** | ** ** |   |   |   |
| Accounts payable and accrued  liabilities               |       |            | ** ** | **1,444**  |   | 1,114  |   |
| Income tax payable                                      |       |            | ** ** | **-**      |   | 254    |   |
| Current portion of Partnership  Contribution Payable    | * *   | *(Note 9)*      | ** ** | **325**    |   | 306    |   |
| Risk management                                         | * *   | *(Note 18)*     | ** ** | **67**     |   | 40     |   |
| Current portion of long-term debt                       | * *   | *(Note 13)*     | ** ** | **-**      |   | 84     |   |
|                                                    | ** ** | ** **      |       | **1,836**  |   | 1,798  |   |
| Long-Term Debt                                          | * *   | *(Note 13)*     | ** ** | **3,493**  |   | 2,952  |   |
| Partnership Contribution Payable                        | * *   | *(Note 9)*      | ** ** | **2,532**  |   | 2,857  |   |
| Risk Management                                         | * *   | *(Note 18)*     | ** ** | **4**      |   | -      |   |
| Asset Retirement Obligation                             | * *   | *(Note 14)*     | ** ** | **1,096**  |   | 648    |   |
| Other Liabilities                                       |       |            | ** ** | **54**     |   | 52     |   |
| Future Income Taxes                                     | * *   | *(Note 8)*      | ** ** | **2,357**  |   | 2,411  |   |
|                                                    | ** ** | ** **      |       | **11,372** |   | 10,718 |   |
| Commitments and Contingencies                           | * *   | *(Note 20)*     | ** ** | ** ** |   |   |   |
| Shareholders’ Equity                               | * *   | *(Note 15)*     | ** ** | **9,180**  |   | 7,748  |   |
|                                                    | ** ** | ** **      |       | **20,552** |   | 18,466 |   |

 

*See accompanying Notes toConsolidated Financial**Statements.*

 

Approved by the Board

 
| /s/ Michael A. Grandin |       | /s/ Patrick D. Daniel |
|------------------------|------------|-----------------------|
| **Michael A. Grandin** | ** ** | **Patrick D. Daniel** |
| Director               |       | Director              |
| Cenovus Energy Inc.    |       | Cenovus Energy Inc.   |

 

 
| Cenovus Energy Inc. | 6 |   |
|---------------------|---|--------|

 

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| CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY |
|-----------------------------------------------------|

 
| (US$ millions)                                                                                     |       | Share  Capital*(Note 15)* |       | Paid in  Surplus*(Note 15)* |       | Retained   Earnings |       | AOCI*     |       | Owner’s  Net  Investment | Total      |
|---------------------------------------------------------------------------------------------------------|------------|---------------------------|------------|-----------------------------|------------|---------------------|------------|-----------|------------|-------------------------------|------------|
|                                                                                                    |       |                      |       |                        |       |                |       |      |       |                          |       |   |   |   |
| **Balance as of December 31, 2006**                                                                |       | -                         |       | -                           |       | -                   |       | 1,169     |       | 6,145                         |       | 7,314 |   |   |
| Net  earnings                                                                                           |       | -                         |       | -                           |       | -                   |       | -         |       | 1,404                         |       | 1,404 |   |   |
| Net  distribution to owner                                                                              |       | -                         |       | -                           |       | -                   |       | -         |       | (1,976                        | )          | (1,976 | ) |   |
| Other  comprehensive income (loss)                                                                      |       | -                         |       | -                           |       | -                   |       | 1,265     |       | -                             |       | 1,265 |   |   |
| **Balance as of December 31, 2007**                                                                |       | -                         |       | -                           |       | -                   |       | 2,434     |       | 5,573                         |       | 8,007 |   |   |
| Net  earnings                                                                                           |       | -                         |       | -                           |       | -                   |       | -         |       | 2,368                         |       | 2,368 |   |   |
| Net  distribution to owner                                                                              |       | -                         |       | -                           |       | -                   |       | -         |       | (381                          | )          | (381 | ) |   |
| Other  comprehensive income (loss)                                                                      |       | -                         |       | -                           |       | -                   |       | (2,246    | )          | -                             |       | (2,246 | ) |   |
| **Balance as of December 31, 2008**                                                                |       | -                         |       | -                           |       | -                   |       | 188       |       | 7,560                         |       | 7,748 |   |   |
| Net  earnings                                                                                           |       | -                         |       | -                           |       | -                   |       | -         |       | 609                           |       | 609 |   |   |
| Net  distribution to owner                                                                              |       | -                         |       | -                           |       | -                   |       | -         |       | (1,045                        | )          | (1,045 | ) |   |
| Other  comprehensive income (loss)                                                                      |       | -                         |       | -                           |       | -                   |       | 1,908     |       | -                             |       | 1,908 |   |   |
| **Owner’s Net Investment at Arrangement date – November 30, 2009**                       |       | -                         |       | -                           |       | -                   |       | 2,096     |       | 7,124                         |       | 9,220 |   |   |
| Issuance  of common stock in connection with the Arrangement                                            |       | 2,222                     |       | -                           |       | -                   |       | -         |       | (2,222                        | )          | - |   |   |
| Reclassification  of owner’s net investment to paid in surplus in connection with the  Arrangement |       | -                         |       | 4,902                       |       | -                   |       | -         |       | (4,902                        | )          | - |   |   |
| Net  earnings – December 1 to December 31                                                |       | -                         |       | -                           |       | 39                  |       | -         |       | -                             |       | 39 |   |   |
| Dividends  on common shares                                                                             |       | -                         |       | (151                        | )          | -                   |       | -         |       | -                             |       | (151 | ) |   |
| Common  shares issued under option plans                                                                |       | 1                         |       | -                           |       | -                   |       | -         |       | -                             |       | 1 |   |   |
| Other  comprehensive income (loss)                                                                      |       | -                         |       | -                           |       | -                   |       | 71        |       | -                             |       | 71 |   |   |
| **Balance as of December 31, 2009**                                                                | ** ** | **2,223**                 | ** ** | **4,751**                   | ** ** | **39**              | ** ** | **2,167** | ** ** | **-**                         | ** ** | **9,180** | ** ** | ** ** |

 

*Accumulated OtherComprehensive Income

 

*See accompanying Notes toConsolidated Financial**Statements.*

 

 
| Cenovus Energy Inc. | 7 |   |
|---------------------|---|--------|

 

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| CONSOLIDATED STATEMENT OF CASH FLOWS |
|--------------------------------------|

 
| For the years ended December 31,  (US$ millions)                          | ** ** | ** **  | ** ** | **2009**   |   | 2008   |   | 2007   | ** ** |
|-------------------------------------------------------------------------------------|------------|-------------|------------|------------|--------|--------|--------|--------|------------|
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Operating  Activities                                                               |       |        | ** ** | ** ** |   |   |   |   |       |   |
| Net earnings                                                                        |       |        | ** ** | **648**    |   | 2,368  |   | 1,404  |       |   |
| Depreciation, depletion and  amortization                                           |       |        | ** ** | **1,343**  |   | 1,318  |   | 1,426  |       |   |
| Future income taxes                                                                 | * *   | *(Note 8)*  | ** ** | **(551**   | **)**  | 385    |   | (182   | )          |   |
| Unrealized (gain) loss on risk  management                                          | * *   | *(Note 18)* | ** ** | **667**    |   | (734   | )      | 348    |       |   |
| Unrealized foreign exchange (gain)  loss                                            |       |        | ** ** | **313**    |   | (259   | )      | 383    |       |   |
| Accretion of asset retirement  obligation                                           | * *   | *(Note 14)* | ** ** | **39**     |   | 39     |   | 28     |       |   |
| Other                                                                               |       |        | ** ** | **13**     |   | (29    | )      | 129    |       |   |
| Net change in other assets and  liabilities                                         |       |        | ** ** | **(23**    | **)**  | (89    | )      | (48    | )          |   |
| Net change in non-cash working  capital                                             |       |        | ** ** | **1,047**  |   | (312   | )      | (474   | )          |   |
| Cash From Operating Activities                                                      |       |        | ** ** | **3,496**  |   | 2,687  |   | 3,014  |       |   |
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Investing  Activities                                                               |       |        | ** ** | ** ** |   |   |   |   |       |   |
| Capital expenditures                                                                | * *   | *(Note 1)*  | ** ** | **(1,895** | **)**  | (2,046 | )      | (1,489 | )          |   |
| Proceeds from divestitures                                                          | * *   | *(Note 5)*  | ** ** | **209**    |   | 47     |   | -      |       |   |
| Net change in other assets                                                          |       |        | ** ** | **(18**    | **)**  | (48    | )      | (34    | )          |   |
| Net change in non-cash working  capital                                             |       |        | ** ** | **(76**    | **)**  | 83     |   | (10    | )          |   |
| Cash (Used in) Investing Activities                                                 |       |        | ** ** | **(1,780** | **)**  | (1,964 | )      | (1,533 | )          |   |
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Net Cash Provided before Financing  Activities                                      |       |        | ** ** | **1,716**  |   | 723    |   | 1,481  |       |   |
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Financing  Activities                                                               |       |        | ** ** | ** ** |   |   |   |   |       |   |
| Net issuance (repayment) of  revolving long-term debt                               |       |        | ** ** | **(304**   | **)**  | (503   | )      | (148   | )          |   |
| Issuance of long-term debt                                                          |       |        | ** ** | **173**    |   | 268    |   | 931    |       |   |
| Repayment of long-term debt                                                         |       |        | ** ** | **(88**    | **)**  | (236   | )      | (99    | )          |   |
| Issuance of U.S. Unsecured Notes                                                    | * *   | *(Note 13)* | ** ** | **3,468**  |   | -      |   | -      |       |   |
| Payment of note payable to EnCana                                                   | * *   | *(Note 13)* | ** ** | **(3,500** | **)**  | -      |   | -      |       |   |
| Payment of transition account  payable to EnCana                                    |       |        | ** ** | **(250**   | **)**  | -      |   | -      |       |   |
| Net financing transactions with  EnCana                                             |       |        | ** ** | **(1,045** | **)**  | (381   | )      | (1,976 | )          |   |
| Issuance of common shares                                                           |       |        | ** ** | **1**      |   | -      |   | -      |       |   |
| Dividends on common shares                                                          |       |        | ** ** | **(151**   | **)**  | -      |   | -      |       |   |
| Other                                                                               |       |        | ** ** | **(34**    | **)**  | -      |   | -      |       |   |
| Cash (Used in) Financing Activities                                                 |       |        | ** ** | **(1,730** | **)**  | (852   | )      | (1,292 | )          |   |
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Foreign  Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency |       |        | ** ** | **9**      |   | (20    | )      | 7      |       |   |
| Increase  (Decrease) in Cash and Cash Equivalents                                   |       |        | ** ** | **(5**     | **)**  | (149   | )      | 196    |       |   |
| Cash and  Cash Equivalents, Beginning of Year                                       |       |        | ** ** | **153**    |   | 302    |   | 106    |       |   |
| Cash and  Cash Equivalents, End of Year                                             |       |        | ** ** | **148**    |   | 153    |   | 302    |       |   |
|                                                                                | ** ** | ** **  |       |       |   |   |   |   |       |   |
| Supplemental Cash Flow Information                                                  | * *   | *(Note 19)* | ** ** | ** ** |   |   |   |   |       |   |

 

 

*See accompanying Notes toConsolidated Financial**Statements.*

 

 
| Cenovus Energy Inc. | 8 |   |
|---------------------|---|--------|

 

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Table of Contents

** **

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES**

 

Cenovus Energy Inc. (“Cenovus” or the “Company”) is in thebusiness of the development, production and marketing of bitumen, crude oil,natural gas and natural gas liquids (“NGLs”) in Canada with refining operationsin the United States.

 

The Company is headquartered in Calgary, Alberta and itscommon shares are listed on the Toronto and New York stock exchanges.  Information on the Company’s background andthe basis of presentation for these financial statements are found in Note 2.

 

Cenovus is organized into two operating divisions:

 

·                  **IntegratedOil**Division, whichincludes all of the assets within the upstream and downstream integrated oilbusiness with our joint venture partner, as well as other bitumen interests andthe Athabasca natural gas assets. The Integrated Oil Division has assets inboth Canada and the U.S. including two major enhanced oil recovery properties: (i) FosterCreek; and (ii) Christina Lake; as well as two refineries: (i) WoodRiver; and (ii) Borger.

 

·                **CanadianPlains**Division, whichcontains established crude oil and natural gas development assets in Albertaand Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn;and (ii) Pelican Lake; as well as the Southern Alberta oil and gasproperties. The division also markets Cenovus’s crude oil and natural gas, aswell as third-party purchases and sales of product that provide operationalflexibility for transportation commitments, product type, delivery points andcustomer diversification.

 

For financial statement reporting purposes, our operatingand reportable segments are:

 

·                  **Upstream Canada,**which includes Cenovus’s development and production of bitumen, crudeoil, natural gas and natural gas liquids (“NGLs”), and other related activitiesin Canada.  This includes the FosterCreek and Christina Lake operations which are jointly owned with ConocoPhillips, anunrelated U.S. public company, andoperated by Cenovus.

 

·                  **Downstream Refining,** which is focused on the refining of crude oil into petroleum andchemical products at two refineries located in the United States. Therefineries are jointly owned with ConocoPhillips and operated byConocoPhillips.

 

·                  **Corporate andEliminations,**which primarilyincludes unrealized gains or losses recorded on derivative financialinstruments as well as other Cenovus-wide costs for general and administrativeand financing activities.  As financialinstruments are settled, realized gains and losses are recorded in theoperating segment to which the derivative instrument relates. Eliminationsrelate to sales and operating revenues and purchased product between segmentsrecorded at transfer prices based on current market prices and to unrealizedintersegment profits in inventory.

 

The operating and reportable segments shown above have beenchanged from those presented in prior periods to match Cenovus’sstructure.  All prior periods have beenrestated to reflect this presentation.

 

The tabular financial information which follows presents thesegmented information first by segment and geographic location, then by productand operating division.  Capitalexpenditures, goodwill, sales information and information relating to Cenovus’smajor customers are summarized at the end of the note.

 

 
| Cenovus Energy Inc. | 9 |   |
|---------------------|---|--------|

 

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Table of Contents

** **

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

** **

** **

**1.  DESCRIPTION OF BUSINESS ANDSEGMENTED DISCLOSURES (continued)**

 

**Results of Operations**

 

**Segment and Geographic Information**

 
|                                                       | ** ** | Upstream Canada | ** ** | ** ** | Downstream Refining |       |
|------------------------------------------------------------|------------|-----------------|------------|------------|---------------------|------------|
| For the years ended December 31,  (US$ millions) | ** ** | **2009**        |       | 2008       |                | 2007       | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                                       |       |            |       |       |                |       |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties                                | ** ** | **5,598**       |       | 6,972      |                | 6,528      | ** ** | ** ** | **5,280** |   | 9,011 |   | 7,315 |   |
| Expenses                                                   | ** ** | ** **      |       |       |                |       | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes                               | ** ** | **38**          |       | 75         |                | 63         | ** ** | ** ** | **-** |   | - |   | - |   |
| Transportation and selling                                 | ** ** | **672**         |       | 963        |                | 756        | ** ** | ** ** | **-** |   | - |   | - |   |
| Operating                                                  | ** ** | **671**         |       | 742        |                | 688        | ** ** | ** ** | **453** |   | 492 |   | 428 |   |
| Purchased product                                          | ** ** | **832**         |       | 1,101      |                | 1,751      | ** ** | ** ** | **4,517** |   | 8,760 |   | 5,813 |   |
| Operating cash flow                                        | ** ** | **3,385**       |       | 4,091      |                | 3,270      | ** ** | ** ** | **310** |   | (241 | ) | 1,074 |   |
| Depreciation, depletion and  amortization                  | ** ** | **1,101**       |       | 1,107      |                | 1,222      | ** ** | ** ** | **192** |   | 188 |   | 159 |   |
| Segment  Income (Loss)                                     | ** ** | **2,284**       |       | 2,984      |                | 2,048      | ** ** | ** ** | **118** |   | (429 | ) | 915 |   |
| ** **                                                 |       |            |       |       | ** **          | ** ** |   |   |   |   |   |   |   |   |
| Property,  Plant & Equipment                      | ** ** | **9,660**       |       | 8,148      |                | 9,574      | ** ** | ** ** | **4,767** |   | 4,032 |   | 3,706 |   |
| Goodwill                                                   | ** ** | **1,095**       |       | 936        |                | 1,159      | ** ** | ** ** | **-** |   | - |   | - |   |
| Total  Assets                                              | ** ** | **14,481**      |       | 12,863     |                | 15,569     | ** ** | ** ** | **5,660** |   | 4,637 |   | 4,887 |   |

 
|                                                       | ** ** | Corporate and Eliminations | ** ** | ** ** | Consolidated |       |
|------------------------------------------------------------|------------|----------------------------|------------|------------|--------------|------------|
| For the years ended December 31,  (US$ millions) | ** ** | **2009**                   |       | 2008       |         | 2007       | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                                       |       |                       |       |       |         |       |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties                                | ** ** | **(738**                   | **)**      | 576        |         | (437       | ) | ** ** | **10,140** |   | 16,559 |   | 13,406 |   |
| Expenses                                                   | ** ** | ** **                 |       |       |         |       | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes                               | ** ** | **-**                      |       | -          |         | -          | ** ** | ** ** | **38** |   | 75 |   | 63 |   |
| Transportation and selling                                 | ** ** | **-**                      |       | -          |         | -          | ** ** | ** ** | **672** |   | 963 |   | 756 |   |
| Operating                                                  | ** ** | **30**                     |       | (11        | )            | (2         | ) | ** ** | **1,154** |   | 1,223 |   | 1,114 |   |
| Purchased product                                          | ** ** | **(99**                    | **)**      | (151       | )            | (88        | ) | ** ** | **5,250** |   | 9,710 |   | 7,476 |   |
|                                                       | ** ** | **(669**                   | **)**      | 738        |         | (347       | ) | ** ** | **3,026** |   | 4,588 |   | 3,997 |   |
| Depreciation, depletion and  amortization                  | ** ** | **50**                     |       | 23         |         | 45         | ** ** | ** ** | **1,343** |   | 1,318 |   | 1,426 |   |
| Segment  Income (Loss)                                     | ** ** | **(719**                   | **)**      | 715        |         | (392       | ) | ** ** | **1,683** |   | 3,270 |   | 2,571 |   |
| General and Administrative                                 | ** ** | **188**                    |       | 167        |         | 145        | ** ** | ** ** | **188** |   | 167 |   | 145 |   |
| Interest, net                                              | ** ** | **218**                    |       | 218        |         | 187        | ** ** | ** ** | **218** |   | 218 |   | 187 |   |
| Accretion of asset retirement  obligation                  | ** ** | **39**                     |       | 39         |         | 28         | ** ** | ** ** | **39** |   | 39 |   | 28 |   |
| Foreign exchange (gain) loss, net                          | ** ** | **290**                    |       | (250       | )            | 380        | ** ** | ** ** | **290** |   | (250 | ) | 380 |   |
| Other (income) loss, net                                   | ** ** | **(2**                     | **)**      | 3          |         | 4          | ** ** | ** ** | **(2** | **)** | 3 |   | 4 |   |
| ** **                                                 |       | **733**                    |       | 177        |         | 744        |   |   | **733** |   | 177 |   | 744 |   |
| Earnings  Before Income Tax                                | ** ** | ** **                 |       |       |         |       | ** ** | ** ** | **950** |   | 3,093 |   | 1,827 |   |
| Income tax expense                                         | ** ** | ** **                 |       |       |         |       | ** ** | ** ** | **302** |   | 725 |   | 423 |   |
| Net  Earnings (Loss)                                       | ** ** | ** **                 |       |       |         |       | ** ** | ** ** | **648** |   | 2,368 |   | 1,404 |   |
| ** **                                                 |       |                       |       |       | ** **   | ** ** |   |   |   |   |   |   |   |   |
| Property,  Plant & Equipment                      | ** ** | **110**                    |       | 80         |         | 104        | ** ** | ** ** | **14,537** |   | 12,260 |   | 13,384 |   |
| Goodwill                                                   | ** ** | **-**                      |       | -          |         | -          | ** ** | ** ** | **1,095** |   | 936 |   | 1,159 |   |
| Total  Assets                                              | ** ** | **411**                    |       | 966        |         | 531        | ** ** | ** ** | **20,552** |   | 18,466 |   | 20,987 |   |

 

 
| Cenovus Energy Inc. | 10 |   |
|---------------------|----|--------|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**1.  DESCRIPTION OF BUSINESS ANDSEGMENTED DISCLOSURES (continued)**

 

**Upstream Canada Product andDivisional Information**

 
| (US$ millions)                   |       | Crude Oil & NGLs |   |
|---------------------------------------|------------|---------------------------|--------|
|                                  |       | Integrated Oil            |   | Canadian Plains |   | Total |   |
| For the years ended December 31, | ** ** | **2009  **      |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                  |       |                      |   |   |   |   |   |   |   |   |   | ** ** | ** ** |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties           | ** ** | **1,202**                 |   | 1,117 |   | 738 | ** ** | ** ** | **1,373** |   | 2,106 |   | 1,453 | ** ** | ** ** | **2,575** |   | 3,223 |   | 2,191 |   |
| Expenses                              | ** ** | ** **                |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes          | ** ** | **-**                     |   | - |   | - | ** ** | ** ** | **24** |   | 38 |   | 29 | ** ** | ** ** | **24** |   | 38 |   | 29 |   |
| Transportation and selling            | ** ** | **430**                   |   | 526 |   | 366 | ** ** | ** ** | **179** |   | 321 |   | 263 | ** ** | ** ** | **609** |   | 847 |   | 629 |   |
| Operating                             | ** ** | **176**                   |   | 170 |   | 159 | ** ** | ** ** | **229** |   | 239 |   | 215 | ** ** | ** ** | **405** |   | 409 |   | 374 |   |
| Purchased product                     | ** ** | **-**                     |   | - |   | - | ** ** | ** ** | **-** |   | - |   | - | ** ** | ** ** | **-** |   | - |   | - |   |
| Operating Cash Flow                   | ** ** | **596**                   |   | 421 |   | 213 | ** ** | ** ** | **941** |   | 1,508 |   | 946 | ** ** | ** ** | **1,537** |   | 1,929 |   | 1,159 |   |

 
| (US$ millions)                   |       | Natural Gas    |   |
|---------------------------------------|------------|----------------|--------|
|                                  |       | Integrated Oil |   | Canadian Plains |   | Total |   |
| For the years ended December 31, | ** ** | **2009**       |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                  |       |           |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties           | ** ** | **180**        |   | 192 |   | 252 | ** ** | ** ** | **1,902** |   | 2,301 |   | 2,186 | ** ** | ** ** | **2,082** |   | 2,493 |   | 2,438 |   |
| Expenses                              | ** ** | ** **     |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes          | ** ** | **-**          |   | - |   | - | ** ** | ** ** | **13** |   | 36 |   | 34 | ** ** | ** ** | **13** |   | 36 |   | 34 |   |
| Transportation and selling            | ** ** | **2**          |   | 7 |   | 12 | ** ** | ** ** | **39** |   | 71 |   | 82 | ** ** | ** ** | **41** |   | 78 |   | 94 |   |
| Operating                             | ** ** | **20**         |   | 39 |   | 40 | ** ** | ** ** | **210** |   | 241 |   | 221 | ** ** | ** ** | **230** |   | 280 |   | 261 |   |
| Purchased product                     | ** ** | **-**          |   | - |   | - | ** ** | ** ** | **-** |   | - |   | - | ** ** | ** ** | **-** |   | - |   | - |   |
| Operating Cash Flow                   | ** ** | **158**        |   | 146 |   | 200 | ** ** | ** ** | **1,640** |   | 1,953 |   | 1,849 | ** ** | ** ** | **1,798** |   | 2,099 |   | 2,049 |   |

 
| (US$ millions)                   |       | Other          |   |
|---------------------------------------|------------|----------------|--------|
|                                  |       | Integrated Oil |   | Canadian Plains |   | Total |   |
| For the years ended December 31, | ** ** | **2009**       |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                  |       |           |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties           | ** ** | **73**         |   | 119 |   | 75 | ** ** | ** ** | **868** |   | 1,137 |   | 1,824 | ** ** | ** ** | **941** |   | 1,256 |   | 1,899 |   |
| Expenses                              | ** ** | ** **     |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes          | ** ** | **1**          |   | 1 |   | - | ** ** | ** ** | **-** |   | - |   | - | ** ** | ** ** | **1** |   | 1 |   | - |   |
| Transportation and selling            | ** ** | **22**         |   | 38 |   | 23 | ** ** | ** ** | **-** |   | - |   | 10 | ** ** | ** ** | **22** |   | 38 |   | 33 |   |
| Operating                             | ** ** | **18**         |   | 31 |   | 30 | ** ** | ** ** | **18** |   | 22 |   | 23 | ** ** | ** ** | **36** |   | 53 |   | 53 |   |
| Purchased product                     | ** ** | **-**          |   | - |   | - | ** ** | ** ** | **832** |   | 1,101 |   | 1,751 | ** ** | ** ** | **832** |   | 1,101 |   | 1,751 |   |
| Operating Cash Flow                   | ** ** | **32**         |   | 49 |   | 22 | ** ** | ** ** | **18** |   | 14 |   | 40 | ** ** | ** ** | **50** |   | 63 |   | 62 |   |

 
| (US$ millions)                   |       | Total Upstream Canada |   |
|---------------------------------------|------------|-----------------------|--------|
|                                  |       | Integrated Oil        |   | Canadian Plains |   | Total |   |
| For the years ended December 31, | ** ** | **2009**              |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 | ** ** | ** ** | **2009** |   | 2008 |   | 2007 |   |
|                                  |       |                  |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenues,  Net of Royalties           | ** ** | **1,455**             |   | 1,428 |   | 1,065 | ** ** | ** ** | **4,143** |   | 5,544 |   | 5,463 | ** ** | ** ** | **5,598** |   | 6,972 |   | 6,528 |   |
| Expenses                              | ** ** | ** **            |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   | ** ** | ** ** | ** ** |   |   |   |   |   |
| Production and mineral taxes          | ** ** | **1**                 |   | 1 |   | - | ** ** | ** ** | **37** |   | 74 |   | 63 | ** ** | ** ** | **38** |   | 75 |   | 63 |   |
| Transportation and selling            | ** ** | **454**               |   | 571 |   | 401 | ** ** | ** ** | **218** |   | 392 |   | 355 | ** ** | ** ** | **672** |   | 963 |   | 756 |   |
| Operating                             | ** ** | **214**               |   | 240 |   | 229 | ** ** | ** ** | **457** |   | 502 |   | 459 | ** ** | ** ** | **671** |   | 742 |   | 688 |   |
| Purchased product                     | ** ** | **-**                 |   | - |   | - | ** ** | ** ** | **832** |   | 1,101 |   | 1,751 | ** ** | ** ** | **832** |   | 1,101 |   | 1,751 |   |
| Operating Cash Flow                   | ** ** | **786**               |   | 616 |   | 435 | ** ** | ** ** | **2,599** |   | 3,475 |   | 2,835 | ** ** | ** ** | **3,385** |   | 4,091 |   | 3,270 |   |

 

 
| Cenovus Energy Inc. | 11 |   |
|---------------------|----|--------|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**1.  DESCRIPTION OF BUSINESS ANDSEGMENTED DISCLOSURES (continued)**

 

**Capital Expenditures**

 
| For the years ended December 31,  (US$ millions) | ** ** | **2009**   |   | 2008   |   | 2007   |   |
|------------------------------------------------------------|------------|------------|--------|--------|--------|--------|--------|
|                                                       | ** ** | ** ** |   |   |   |   |   |
| Integrated Oil                                             | ** ** | **476**    |   | 644    |   | 450    |   |
| Canadian Plains                                            | ** ** | **478**    |   | 872    |   | 795    |   |
| Upstream Canada                                            | ** ** | **954**    |   | 1,516  |   | 1,245  |   |
| Downstream Refining                                        | ** ** | **907**    |   | 478    |   | 220    |   |
| Corporate                                                  | ** ** | **31**     |   | 52     |   | 10     |   |
| ** **                                                 |       | **1,892**  |   | 2,046  |   | 1,475  |   |
| Acquisition Capital                                        | ** ** | ** ** |   |   |   |   |   |
| Integrated Oil                                             | ** ** | **-**      |   | -      |   | 14     |   |
| Canadian Plains                                            | ** ** | **3**      |   | -      |   | -      |   |
| Total                                                      | ** ** | **1,895**  |   | 2,046  |   | 1,489  |   |

 

In addition to the above, in 2009 we acquired strategicbitumen lands in exchange for certain non-core holdings.

 

**Goodwill Additions**

 

There were no additions togoodwill during 2009, 2008 or 2007; changes in the goodwill balance result fromchanges in foreign exchange rates.

 

**Export Sales**

 

Sales of crude oil, natural gas and NGLs produced orpurchased in Canada delivered to customers outside of Canada were $544 million(2008–$1,296 million; 2007–$943 million).

 

**Major Customers**

 

In connection with the marketing and sale of Cenovus’s ownand purchased crude oil, natural gas and refined products for the year ended December 31,2009, Cenovus had two customers (2008–two; 2007–two) which individuallyaccounted for more than 10 percent of its consolidated revenues, netof royalties. Sales to these customers, major international integrated energycompanies with an investment grade credit rating, were approximately$5,658 million (2008–$8,979 million; 2007–$6,916 million).

 

 

**2. BACKGROUND & BASIS OF PRESENTATION**

 

Cenovus was created on November 30, 2009 and beganindependent operations on December 1, 2009, as a result of the Arrangementinvolving EnCana Corporation (“EnCana”) whereby EnCana was split into twoindependent energy companies, one a natural gas company, EnCana and the otheran integrated oil company, Cenovus.  Inconnection with the Arrangement, EnCana common shareholders received one sharein each of the new EnCana and Cenovus in exchange for each EnCana shareheld.  Common shares of Cenovus begantrading on a “when issued” basis on the Toronto (“TSX”) and New York (“NYSE”)stock exchanges on November 2, 2009. Regular trading of the Cenovus shares began on the TSX on December 3,2009 and on the NYSE on December 9, 2009.

 

Cenovus has entered into various transitional agreementswith EnCana for the use of certain technical services, the marketing of crudeoil, natural gas and NGLs and office space lease arrangements.  These agreements reflect terms negotiated inanticipation of each company being stand-alone public companies, each withindependent boards of directors and management teams.

 

 
| Cenovus Energy Inc. | 12 |   |
|---------------------|----|--------|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**2. BACKGROUND & BASIS OF PRESENTATION (continued)**

 

Accordingly, up until the completion of the Arrangement,EnCana was considered a related party due to its parent-subsidiary relationshipwith the Cenovus entities. However, subsequent to the Arrangement, EnCana is nolonger a related party as defined by the Canadian Institute of CharteredAccountants (“CICA”) Handbook Section 3840 – Related Party Transactions.

 

***Basisof presentation / Carve-out financial information***

 

The ConsolidatedFinancial Statements for the year ended December 31, 2009 include theresults for the period from January 1 to November 30, 2009 prior tothe Arrangement with EnCana, in addition to the results for the period from December 1to December 31, 2009 as described below. The consolidated financialresults for the periods prior to December 1, 2009 represent the financialposition, results of operations and cash flows of the businesses transferred toCenovus on a carve-out basis.

 

The historicalfinancial information prior to December 1, 2009 has been derived from theaccounting records of EnCana using the historical results of operations andhistorical basis of assets and liabilities of the businesses transferred toCenovus on a carve-out accounting basis.

 

As the Companyoperated as part of EnCana and was not a stand-alone entity prior to November 30,2009, the historical Consolidated Financial Statements include allocations ofcertain EnCana revenues, expenses, assets and liabilities, including the itemsdescribed below.

 

The operatingresults of Cenovus were specifically identified based on EnCana’s divisionalorganization. Certain other expenses presented in the Consolidated Statement ofEarnings and Comprehensive Income represent allocations and estimates of thecost of services incurred by EnCana. These allocations and estimates includeunrealized mark-to-market gains and losses, general and administrative costs,net interest, foreign exchange gains and losses and income tax expenses.  The majority of the assets and liabilities ofCenovus have been identified based on the divisional structure, with the mostsignificant exceptions being property, plant and equipment (“PP&E”), incometaxes payable and long-term debt.

 

Downstream refining,crude oil and natural gas marketing and corporate depreciation, depletion andamortization have been specifically identified based on EnCana’s existingdivisional structure where possible. Depletion related to upstream properties has been allocated to Cenovusbased on the related production volumes utilizing the depletion rate calculatedfor EnCana’s consolidated Canadian cost centre.

 

Mark-to-market gainsand losses resulting from derivative financial instruments entered into byEnCana have been allocated to Cenovus based on the related product volumes.

 

Salaries, benefits,pension, long-term incentives and other post-employment benefits costs, assetsand liabilities have been allocated to Cenovus based on Management’s bestestimate of how services were historically provided by existing employees.  Costs, assets and liabilities associated withretired employees remain with EnCana.

 

Net interest expensehas been calculated primarily using the debt balance allocated to Cenovus.

 

Income taxes havebeen recorded as if Cenovus and its subsidiaries had been separate tax payinglegal entities, each filing a separate tax return in its localjurisdiction.  The calculation of incometaxes is based on a number of assumptions, allocations and estimates, includingthose used to prepare the Cenovus Carve-out Consolidated Financial Statements.  Prior to the Arrangement, Cenovus’s tax poolswere allocated for the Canadian cost centre based on the fair value allocationof PP&E for carve-out purposes.

 

 
| Cenovus Energy Inc. | 13 |   |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**2. BACKGROUND & BASIS OF PRESENTATION (continued)**

 

PP&E related toupstream oil and gas activities are accounted for by Cenovus using the fullcost method of accounting.  PP&Erelated to upstream oil and gas activities has been determined based on anallocation process which used the ratio of future net revenue, discounted at10 percent, of the respective divisions to the future net revenue,discounted at 10 percent, of all proved properties in Canada at December 31,2008 and December 31, 2007, respectively. Future net revenue is theestimated net amount to be received with respect to development and productionof crude oil and natural gas reserves.

 

Goodwill has beenallocated to Cenovus based on the properties associated with the formerbusiness combinations on which it arose.

 

For the purpose ofpreparing the Carve-out Consolidated Financial Statements, it was determinedthat Cenovus should maintain approximately the same Debt to Capitalizationratio as consolidated EnCana.  As aresult, prior to the Arrangement, debt was allocated to Cenovus based on thisratio.* *Debtis defined as the current and long-term portions of Long-term Debt.  Capitalization is not a term that has aprescribed meaning under generally accepted accounting principles (“non-GAAP”)and is a measure defined as Debt plus Shareholders’ Equity.

 

Management believesthe assumptions underlying the Cenovus Carve-out Consolidated FinancialStatements are reasonable. However, the Cenovus Consolidated FinancialStatements herein may not reflect Cenovus’s financial position, results of operations,and cash flows had Cenovus been a stand-alone company during the periodspresented or what Cenovus’s operations, financial position, and cash flows willbe in the future.  EnCana’s directinvestment in Cenovus is shown as Net Investment in place of Shareholders’Equity because a direct ownership by shareholders in Cenovus did not existprior to November 30, 2009.  EnCana’sinvestment includes the accumulated net earnings, other comprehensive incomeand net cash distributions to EnCana.

 

In the opinion ofManagement, the Consolidated and the historical Carve-out ConsolidatedFinancial Statements reflect all adjustments (including normal recurringadjustments) necessary for a fair statement of the financial position and theresults of operations and cash flows in accordance with Canadian generallyaccepted accounting principles (“Canadian GAAP”).

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES**

 

In these Consolidated Financial Statements, unless otherwiseindicated, all dollars are expressed in United States (U.S.) dollars. WhileCenovus’s reporting currency is U.S. dollars, the functional currency isCanadian dollars. All references to US$ or $ are to U.S. dollars and referencesto C$ are to Canadian dollars.

 

**A****) ****Principles of Consolidation**

 

The Consolidated Financial Statements include the accountsof Cenovus and its subsidiaries and are presented in accordance with CanadianGAAP. Information prepared in accordance with GAAP in the United States isincluded in Note 21.

 

Investments in jointly controlled partnerships andunincorporated joint ventures carry on certain of Cenovus’s development,production and crude oil refining businesses and are accounted for using theproportionate consolidation method, whereby Cenovus’s proportionate share ofrevenues, expenses, assets and liabilities are included in the accounts.

 

 
| Cenovus Energy Inc. | 14 |   |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

**B****) ****Foreign Currency Translation**

 

The accounts of self-sustaining operations are translatedusing the current rate method, whereby assets and liabilities are translated atperiod end exchange rates, while revenues and expenses are translated usingaverage rates over the period. Translation gains and losses relating to theself-sustaining operations are included in Accumulated Other ComprehensiveIncome (“AOCI”) as a separate component of Shareholders’ Equity. As at December 31,2009, AOCI is comprised solely of foreign currency translation adjustments.

 

Monetary assets and liabilities of Cenovus that aredenominated in foreign currencies are translated into its functional currencyat the rates of exchange in effect at the period end date. Any gains or lossesare recorded in the Consolidated Statement of Earnings.

 

**C****) ****Measurement Uncertainty**

 

The timely preparation of the Consolidated FinancialStatements in conformity with Canadian GAAP requires that Management makeestimates and assumptions and use judgment regarding the reported amounts ofassets and liabilities and disclosures of contingent assets and liabilities atthe date of the Consolidated Financial Statements and the reported amounts ofrevenues and expenses during the period. Such estimates primarily relate tounsettled transactions and events as of the date of the Consolidated FinancialStatements. Accordingly, actual results may differ from estimated amounts asfuture confirming events occur.

 

Amounts recorded for depreciation, depletion andamortization, asset retirement costs and obligations and amounts used forceiling test and impairment calculations are based on estimates of crude oiland natural gas reserves and future costs required to develop those reserves.By their nature, these estimates of reserves, including the estimates of futureprices and costs, and the related future cash flows are subject to measurementuncertainty, and the impact in the Consolidated Financial Statements of futureperiods could be material.

 

The values of pension assets and obligations and the amountof pension costs charged to net earnings depend on certain actuarial andeconomic assumptions which, by their nature, are subject to measurementuncertainty.

 

The amount of compensation expense accrued for long-termperformance-based compensation arrangements is subject to Management’s bestestimate of whether or not the performance criteria will be met and what theultimate payout will be.

 

The estimated fair value of financial assets andliabilities, by their very nature, are subject to measurement uncertainty.

 

Tax interpretations, regulations and legislation in thevarious jurisdictions in which Cenovus operates are subject to change.  As such, income taxes are subject tomeasurement uncertainty.

 

**D****) ****Revenue Recognition**

 

Revenues associated with the sales of Cenovus’s crude oil,natural gas, NGLs and petroleum and refined products are recognized when titlepasses from the Company to its customer. Realized gains and losses from crudeoil and natural gas commodity price risk management activities are recorded inrevenue when the product is sold.

 

Revenues and purchased product are recorded on a gross basiswhen the title to product passes and the risks and rewards of ownership havebeen transferred. Purchases and sales of products that are entered into incontemplation of each other with the same counterparty are recorded on a netbasis. Revenues associated with the services provided as agent are recorded asthe services are provided.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

Unrealized gains and losses from natural gas and crude oilcommodity price risk management activities are recorded as revenue based on therelated mark-to-market calculations at the end of the respective period.

 

**E****) ****Production and Mineral Taxes**

 

Costs paid to non-mineral interest owners based onproduction of crude oil, natural gas and NGLs are recognized when the productis produced.

 

**F****) ****Transportation and Selling Costs**

 

Costs paid for the transportation and selling of crude oil,natural gas and NGLs, including diluent, are recognized when the product isdelivered and the services provided.

 

**G****) ****Employee Benefit Plans**

 

Accruals for obligations under the employee benefit plansand the related costs are recorded net of plan assets.

 

The cost of pensions and other post-employment benefits isactuarially determined using the projected benefit method based on length ofservice, and reflects Management’s best estimate of expected plan investmentperformance, salary escalation, retirement ages of employees and expectedfuture health care costs. The expected return on plan assets is based on thefair value of those assets. The accrued benefit obligation is discounted usingthe market interest rate on high quality corporate debt instruments as at themeasurement date.

 

Pension expense for the defined benefit pension planincludes the cost of pension benefits earned during the current year, theinterest cost on pension obligations, the expected return on pension planassets, the amortization of the net transitional obligation, the amortizationof adjustments arising from pension plan amendments and the amortization of theexcess of the net actuarial gain or loss over 10 percent of the greater ofthe benefit obligation and the fair value of plan assets. Amortization is done ona straight-line basis over a period covering the expected average remainingservice lives of employees covered by the plans.

 

Pension expense for the defined contribution pension plansis recorded as the benefits are earned by the employees covered by the plans.

 

**H****) ****Income Taxes**

 

Cenovus follows the liability method of accounting forincome taxes, where future income taxes are recorded for the effect of anydifference between the accounting and income tax basis of an asset orliability, using the substantively enacted income tax rates. Accumulated futureincome tax balances are adjusted to reflect changes in income tax rates thatare substantively enacted with the adjustment being recognized in net earningsin the period that the change occurs.

 

 
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** **

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

** **

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

**I****) Earnings Per ShareAmounts**

 

Basic net earnings per common share is computed by dividingthe net earnings by the weighted average number of common shares outstandingduring the period. Diluted net earnings per share amounts are calculated givingeffect to the potential dilution that would occur if stock options, withouttandem share appreciation rights attached, were exercised or other contracts toissue common shares were exercised or converted to common shares. The treasurystock method is used to determine the dilutive effect of stock options withouttandem share appreciation rights attached and other dilutive instruments. Thetreasury stock method assumes that proceeds received from the exercise ofin-the-money stock options without tandem share appreciation rights attachedare used to repurchase common shares at the average market price.

 

**J)****Cash and Cash Equivalents**

 

Cash and cash equivalents include short-term investments,such as money market deposits or similar type instruments, with a maturity ofthree months or less when purchased.

 

**K) ****Inventories**

 

Product inventories, including petroleum and refinedproducts, are valued at the lower of cost and net realizable value on afirst-in,first-out or weighted average cost basis.

 

**L) ****Property, Plant and Equipment**

 

**Upstream****Canada**

 

Crude oil and natural gas properties are accounted for inaccordance with the CICA guideline on full cost accounting in the oil and gasindustry. Under this method, all costs, including internal costs and assetretirement costs, directly associated with the acquisition of, the explorationfor, and the development of bitumen, crude oil and natural gas reserves, arecapitalized on a country-by-country cost centre basis.

 

Costs accumulated within each cost centre are depreciated,depleted and amortized using the unit-of-production method based on estimatedproved reserves determined using estimated future prices and costs. For purposesof this calculation, natural gas is converted to oil on an energy equivalentbasis. Capitalized costs subject to depletion include estimated future costs tobe incurred in developing proved reserves. Proceeds from the divestiture ofproperties are normally deducted from the full cost pool without recognition ofgain or loss unless that deduction would result in a change to the rate ofdepreciation, depletion and amortization of 20 percent or greater, inwhich case a gain or loss is recorded. Costs of major development projects andcosts of acquiring and evaluating significant unproved properties are excluded,on a cost centre basis, from the costs subject to depletion until it isdetermined whether or not proved reserves are attributable to the properties,or impairment has occurred. Costs that have been impaired are included in thecosts subject to depreciation, depletion and amortization.

 

An impairment loss is recognized in net earnings when thecarrying amount of a cost centre is not recoverable and the carrying amount ofthe cost centre exceeds its fair value. The carrying amount of the cost centreis not recoverable if the carrying amount exceeds the sum of the undiscountedcash flows from proved reserves. If the sum of the cash flows is less than the carryingamount, the impairment loss is limited to the amount by which the carryingamount exceeds the sum of:

 

i.  the fair value ofproved and probable reserves; and

ii. the costs of unprovedproperties that have been subject to a separate impairment test.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31,2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

**Downstream Refining**

 

The initial acquisition costs of refinery property, plantand equipment are capitalized when incurred. Costs include the cost ofconstructing or otherwise acquiring the equipment or facilities, the cost ofinstalling the asset and making it ready for its intended use and theassociated asset retirement costs. Capitalized costs are not subject todepreciation until the asset is put into use, after which they are depreciatedon a straight-line basis over the estimated service lives of each component ofthe downstream facilities.

 

An impairment loss is recognized on refinery property, plantand equipment when the carrying amount is not recoverable and exceeds its fairvalue. The carrying amount is not recoverable if the carrying amount exceedsthe sum of the undiscounted cash flows from expected use and eventualdisposition. If the carrying amount is not recoverable, an impairment loss ismeasured as the amount by which the refinery asset exceeds the fair value.

 

**Other**

 

Costs associated with office furniture, fixtures, leaseholdimprovements, information technology and aircraft are carried at cost anddepreciated on a straight-line basis over the estimated service lives of theassets, which range from three to 25 years. Assets under construction arenot subject to depreciation until put into use.

 

**M) ****Capitalization of Costs**

 

Expenditures related to renewals or betterments that improvethe productive capacity or extend the life of an asset are capitalized.Maintenance and repairs are expensed as incurred.

 

**N****) ****Amortization of Other Assets**

 

Items included in Other Assets are amortized, whereapplicable, on a straight-line basis over the estimated useful lives of theassets.

 

**O) ****Goodwill**

 

Goodwill, which represents the excess of purchase price overfair value of net assets acquired, is assessed for impairment at leastannually. Goodwill and all other assets and liabilities have been allocated tothe country cost centre level, referred to as a reporting unit. To assessimpairment, the fair value of the reporting unit is determined and compared tothe book value of the reporting unit. If the fair value of the reporting unitis less than the book value, then a second test is performed to determine theamount of the impairment. The amount of the impairment is determined bydeducting the fair value of the reporting unit’s assets and liabilities fromthe fair value of the reporting unit to determine the implied fair value ofgoodwill and comparing that amount to the book value of the reporting unit’sgoodwill. Any excess of the book value of goodwill over the implied fair valueof goodwill is the impairment amount.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

**P) ****Asset Retirement Obligation**

 

The fair value of estimated asset retirement obligations isrecognized in the Consolidated Balance Sheet when incurred and a reasonableestimate of fair value can be made.

 

Asset retirement obligations include those legal obligationswhere Cenovus will be required to retire tangible long-lived assets such asproducing well sites, natural gas processing plants, and refining facilities.The asset retirement cost, equal to the initially estimated fair value of theasset retirement obligation, is capitalized as part of the cost of the relatedlong-lived asset. Changes in the estimated obligation resulting from revisionsto estimated timing or amount of undiscounted cash flows are recognized as achange in the asset retirement obligation and the related asset retirementcost.

 

Amortization of asset retirement costs are included indepreciation, depletion and amortization in the Consolidated Statement ofEarnings. Increases in the asset retirement obligation resulting from thepassage of time are recorded as accretion of asset retirement obligation in theConsolidated Statement of Earnings.

 

Actual expenditures incurred are charged against the accumulatedobligation.

 

**Q) ****Stock-Based Compensation**

 

Obligations for payments, cash or common shares, underCenovus’s stock options with tandem share appreciation rights attached, shareappreciation rights and deferred share units plans are accrued using theintrinsic method as compensation cost over the vesting period. Fluctuations inthe price of Cenovus’s common shares change the accrued compensation cost andare recognized when they occur.

 

EnCana replacement share options with tandem shareappreciation rights attached and share appreciation rights held by Cenovusemployees are accrued using the fair value method.  The fair value is recognized as compensationcost over the vesting period. Fluctuations in the fair value of the rightschange the accrued compensation cost and are recognized when they occur.

 

**R) ****Financial Instruments**

 

Financial instruments are measured at fair value on initialrecognition of the instrument, except for certain related party transactions.Measurement in subsequent periods depends on whether the financial instrumenthas been classified as “held-for-trading”,“available-for-sale”, “held-to-maturity”, “loans and receivables”, or “otherfinancial liabilities” as defined by the accounting standard.

 

Financial assets and financial liabilities “held-for-trading”are measured at fair value with changes in those fair values recognized in netearnings. Financial assets “available-for-sale” are measured at fair value,with changes in those fair values recognized in Other Comprehensive Income (“OCI”).Financial assets “held-to-maturity”, “loans and receivables” and “otherfinancial liabilities” are measured at amortized cost using the effectiveinterest method of amortization.

 

Cash and cash equivalents are designated as “held-for-trading”and are measured at fair value. Accounts receivable and accrued revenues andthe Partnership Contribution Receivable are designated as “loans andreceivables”. Accounts payable and accrued liabilities, the PartnershipContribution Payable and long-term debt are designated as “other financialliabilities”. Long-term debt transaction costs, premiums and discounts arecapitalized within long-term debt and amortized using the effective interestmethod.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unlessotherwise indicated*

*For the year ended December 31,2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 

**Derivative Financial Instruments**

 

Risk management assets and liabilities are derivativefinancial instruments classified as “held-for-trading” unless designated forhedge accounting. Derivative instruments that do not qualify as hedges, or arenot designated as hedges, are recorded using mark-to-market accounting wherebyinstruments are recorded in the Consolidated Balance Sheet as either an assetor liability with changes in fair value recognized in net earnings. Realizedgains or losses from financial derivatives related to natural gas and crude oilcommodity prices are recognized in natural gas and crude oil revenues as therelated sales occur. Realized gains or losses from financial derivatives relatedto power commodity prices are recognized in operating costs as the relatedpower costs are incurred. Unrealized gains and losses are recognized at the endof each respective reporting period. The estimated fair value of all derivativeinstruments is based on quoted market prices or, in their absence, third-partymarket indications and forecasts.

 

Derivative financial instruments are used to manage economicexposure to market risks relating to commodity prices, foreign currencyexchange rates and interest rates. Derivative financial instruments are notused for speculative purposes.

 

Policies and procedures are in place with respect to therequired documentation and approvals for the use of derivative financialinstruments and specifically ties their use, in the case of commodities, to themitigation of market price risk associated with cash flows expected to begenerated from budgeted capital programs, and in other cases to the mitigationof market price risks for specific assets and obligations. When applicable, theCompany identifies relationships between financial instruments and anticipatedtransactions, as well as its risk management objective and the strategy forundertaking the economic hedge transaction. Where specific financialinstruments are executed, the Company assesses, both at the time of purchaseand on an ongoing basis, whether the financial instrument used in theparticular transaction is effective in offsetting changes in fair values orcash flows of the transaction.

 

**S) Reclassification**

 

Certain information provided forprior years has been reclassified to conform to the presentation adopted in2009.

 

**T) Recent AccountingPronouncements**

 

In February 2008, the CICA’s Accounting Standards Boardconfirmed that International Financial Reporting Standards (“IFRS”) willreplace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountableenterprises.  Cenovus will be required toreport its results in accordance with IFRS beginning in 2011.  Cenovus has developed a changeover plan tocomplete the transition to IFRS by January 1, 2011, including thepreparation of required comparative information.  The impact of IFRS on the ConsolidatedFinancial Statements is not reasonably determinable at this time.

 

In addition, there are three recent accountingpronouncements as noted below, which Cenovus will be required to adopt as of January 1,2011.  All of these standards areconverged with IFRS.

 

·         “Business Combinations”, Section 1582,which replaces the previous Business Combinations standard.  The standard requires assets and liabilitiesacquired in a business combination, contingent consideration and certainacquired contingencies to be measured at their fair values as of the date ofacquisition.  In addition,acquisition-related and restructuring costs are to be recognized separatelyfrom the business combination and included in the Statement of Earnings.  The adoption of this standard will impact theaccounting treatment of future business combinations.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**3.  SUMMARYOF SIGNIFICANT ACCOUNTING POLICIES (continued)**

 
| · | “Consolidated Financial Statements”,  Section 1601, which together with Section 1602 below, replace the  former consolidated financial statement standard. Section 1601  establishes the requirements for the preparation of consolidated financial  statements. The adoption of this standard should not have a material impact  on Cenovus’s Consolidated Financial Statements.                                                                                                                                                                    |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
| · | “Non-controlling Interests”,  Section 1602, which establishes the accounting for a non-controlling  interest in a subsidiary in consolidated financial statements subsequent to a  business combination. The standard requires a non-controlling interest to be  classified as a separate component of equity. In addition, net earnings, and  components of other comprehensive income are attributed to both the parent  and non-controlling interest. The adoption of this standard should not have a  material impact on the Consolidated Financial Statements. |

 

 

**4.  CHANGESIN ACCOUNTING POLICIES AND PRACTICES**

 

On January 1, 2009, Cenovus adopted the CICA Handbook Section “Goodwilland Intangible Assets”, Section 3064. The new standard replaces the previous goodwill and intangible assetstandard and revises the requirement for recognition, measurement, presentationand disclosure of intangible assets.  Theadoption of this standard had no material impact on the Consolidated FinancialStatements.

 

 

**5. DIVESTITURES**

 
| For the years ended December 31,  (US$ millions) | ** ** | **2009** |   | 2008   |   | 2007   |   |
|------------------------------------------------------------|------------|----------|--------|--------|--------|--------|--------|
|                                                       |       |     |   |   |   |   |   |
| Integrated Oil                                             | ** ** | **83**   |   | 8      |   | -      |   |
| Canadian Plains                                            | ** ** | **123**  |   | 39     |   | -      |   |
| Corporate                                                  | ** ** | **3**    |   | -      |   | -      |   |
| Canada                                                     | ** ** | **209**  |   | 47     |   | -      |   |

 

As part of on-goingportfolio management efforts, in 2009 Cenovus received cash proceeds of $209million related to the divestiture of certain oil and gas assets.

 

 

**6. INTEREST, NET**

 
| For the years ended December 31,  (US$ millions) | ** ** | **2009** |   | 2008   |   | 2007   |   |
|------------------------------------------------------------|------------|----------|--------|--------|--------|--------|--------|
|                                                       |       |     |   |   |   |   |   |
| Interest Expense–Long-Term Debt                       | ** ** | **187**  |   | 194    |   | 185    |   |
| Interest Expense–Other                                | ** ** | **194**  |   | 213    |   | 225    |   |
| Interest Income                                            | ** ** | **(163** | **)**  | (189   | )      | (223   | )      |
|                                                       | ** ** | **218**  |   | 218    |   | 187    |   |

 

Interest Expense–Other and Interest Income are primarily dueto the Partnership Contribution Payable and Receivable, respectively (See Note9).

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**7.  FOREIGNEXCHANGE (GAIN) LOSS, NET**

 
| For the years ended December 31, (US$ millions)                          | ** ** | **2009** |   | 2008   |   | 2007   |   |
|------------------------------------------------------------------------------------|------------|----------|--------|--------|--------|--------|--------|
|                                                                               |       |     |   |   |   |   |   |
| Unrealized Foreign Exchange (Gain) Loss on:                                        |       |     |   |   |   |   |   |
| Translation of U.S. dollar debt  issued from Canada                                | ** ** | **(357** | **)**  | 351    |   | (268   | )      |
| Translation of U.S. dollar  Partnership Contribution Receivable issued from Canada | ** ** | **478**  |   | (608   | )      | 617    |   |
| Other Foreign Exchange (Gain) Loss                                                 | ** ** | **169**  |   | 7      |   | 31     |   |
|                                                                               | ** ** | **290**  |   | (250   | )      | 380    |   |

 

Other foreign exchange (gain) loss in 2009 includes a $107million unrealized loss on the translation of U.S. dollar risk managementassets and liabilities (2008–unrealized gain of $2 million; 2007–unrealizedloss of $34 million) and a $50 million realized loss related to the timing ofreceipt of the $3.5 billion debt offering proceeds from escrow (see Note 13).

 

 

**8.  INCOMETAXES**

 

The provision for income taxes is as follows:

 
| For the years ended December 31, (US$ millions) | ** ** | **2009** |   | 2008   |   | 2007   |   |
|-----------------------------------------------------------|------------|----------|--------|--------|--------|--------|--------|
|                                                      |       |     |   |   |   |   |   |
| Current                                                   |       |     |   |   |   |   |   |
| Canada                                                    | ** ** | **896**  |   | 362    |   | 432    |   |
| United States                                             | ** ** | **(43**  | **)**  | (22    | )      | 173    |   |
| Total Current Tax                                         | ** ** | **853**  |   | 340    |   | 605    |   |
| Future Tax                                                | ** ** | **(551** | **)**  | 385    |   | (182   | )      |
|                                                      | ** ** | **302**  |   | 725    |   | 423    |   |

 

The income taxprovision in 2009 reflects the acceleration of the income tax impact of thedissolution of a partnership during the fourth quarter in conjunction with theArrangement with EnCana.

 

Total income taxexpense in 2009 was $302 million, which was $423 million lower than in 2008 dueto lower earnings before income tax. Current income tax expense in 2009 was $853 million, compared to $340million in 2008.  The increase is largelyattributable to the acceleration of income tax arising from the dissolution ofEnCana’s Canadian oil and gas partnership in connection with the Arrangementand the realization of significant hedging gains in 2009.  Current tax expense for the three years isprimarily an allocation of EnCana’s income tax liability on a carve-outaccounting basis and as a result, there is no income tax payable by Cenovus atthe end of 2009.  For 2009, there was arecovery of future income tax expense of $551 million compared to an expense of$385 million in 2008. The significant net recovery was due to the 2009 reversalof future tax on partnership income and unrealized mark-to-market hedginggains.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**8.  INCOMETAXES (continued)**

 

The following table reconciles income taxes calculated atthe Canadian statutory rate with the recorded income taxes:

 
| For the years ended December 31, (US$ millions)     |       | **2009**      |   | 2008   |   | 2007   |   |
|---------------------------------------------------------------|------------|---------------|--------|--------|--------|--------|--------|
|                                                          | ** ** | ** **    |   |   |   |   |   |
| Earnings Before Income Tax                                    | ** ** | **950**       |   | 3,093  |   | 1,827  |   |
| Canadian Statutory Rate                                       | ** ** | **29.2****%** |   | 29.7%  |   | 32.3%  |   |
| Expected Income Tax                                           | ** ** | **277**       |   | 917    |   | 590    |   |
| Effect on Taxes Resulting from:                               |       |          |   |   |   |   |   |
| Statutory and other rate  differences                         | ** ** | **(4**        | **)**  | (79    | )      | 17     |   |
| Effect of tax rate changes                                    | ** ** | **-**         |   | -      |   | (147   | )      |
| Effect of legislative changes                                 | ** ** | **-**         |   | -      |   | (76    | )      |
| Non-taxable downstream partnership  (income) loss             | ** ** | **6**         |   | 6      |   | (70    | )      |
| International financing                                       | ** ** | **(118**      | **)**  | (127   | )      | -      |   |
| Foreign exchange (gains) losses not  included in net earnings | ** ** | **67**        |   | 11     |   | -      |   |
| Non-taxable capital (gains) losses                            | ** ** | **11**        |   | (50    | )      | 45     |   |
| Other                                                         | ** ** | **63**        |   | 47     |   | 64     |   |
|                                                          | ** ** | **302**       |   | 725    |   | 423    |   |
| Effective Tax Rate                                            | ** ** | **31.8****%** |   | 23.4%  |   | 23.2%  |   |

 

The net future income tax liability is comprised of:

 
| As at December 31, (US$ millions)            | ** ** | **2009**   |   | 2008   |   |
|--------------------------------------------------------|------------|------------|--------|--------|--------|
|                                                   | ** ** | ** ** |   |   |   |
| Future Tax Liabilities                                 |       |       |   |   |   |
| Property, plant and equipment in  excess of tax values | ** ** | **2,535**  |   | 1,810  |   |
| Timing of partnership items                            | ** ** | **9**      |   | 470    |   |
| Risk management                                        | ** ** | **16**     |   | 185    |   |
| Other                                                  | ** ** | **59**     |   | -      |   |
| Future Tax Assets                                      |       |       |   |   |   |
| Non-capital and net capital losses  carried forward    | ** ** | **(231**   | **)**  | (19    | )      |
| Risk management                                        | ** ** | **(31**    | **)**  | -      |   |
| Other                                                  | ** ** | **-**      |   | (35    | )      |
| Net Future Income Tax Liability                        | ** ** | **2,357**  |   | 2,411  |   |

 

The approximate amounts of tax pools available are asfollows:

 
| As at December 31, (US$ millions) | ** ** | **2009**  |   | 2008   |   |
|---------------------------------------------|------------|-----------|--------|--------|--------|
|                                        |       |      |   |   |   |
| Canada                                      | ** ** | **3,543** |   | 4,092  |   |
| United States                               | ** ** | **2,489** |   | 1,805  |   |
|                                        | ** ** | **6,032** |   | 5,897  |   |

 

Included in the above tax pools are $731 million (2008–$77million) related to non-capital and net operating losses available for carryforward to reduce taxable income in future years.  These losses expire no earlier than 2028.

 

 
| Cenovus Energy Inc. | 23 |
|---------------------|----|

 

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**9. PARTNERSHIP CONTRIBUTION RECEIVABLE AND PAYABLE**

 

In connection with the Arrangement with EnCana, Cenovusacquired EnCana’s assets which are jointly controlled with ConocoPhillips. On January 2,2007, EnCana became a 50 percent partner in an integrated, North Americanoil business with ConocoPhillips which consists of an upstream entity and adownstream entity. The upstream entity contribution included assets fromEnCana, primarily the Foster Creek and Christina Lake properties, with a fairvalue of $7.5 billion and a note receivable (Partnership ContributionReceivable) contributed from ConocoPhillips of an equal amount. For thedownstream entity, ConocoPhillips contributed its Wood River and Borgerrefineries, located in Illinois and Texas, respectively, for a fair value of$7.5 billion and EnCana contributed a note payable (PartnershipContribution Payable) of $7.5 billion.

 

In accordance with Canadian GAAP, these entities have beenaccounted for using the proportionate consolidation method with the results ofoperations included in the Integrated Oil Division (See Note 1).

 

**Partnership Contribution Receivable**

 

This note receivable bears interest at a rate of5.3 percent per annum. Equal payments of principal and interest arepayable quarterly, with final payment due January 2, 2017. The current andlong-term Partnership Contribution Receivable shown in the Consolidated BalanceSheet represents Cenovus’s 50 percent share of this promissory note, netof payments to date.

 

**Mandatory Receipts**

 
| (US$ millions)                 |   | 2010   |   | 2011   |   | 2012   |   | 2013   |   | 2014   |   | Thereafter | ** ** | **Total** | ** ** |
|-------------------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|------------|------------|-----------|------------|
|                                |   |   |   |   |   |   |   |   |   |   |   |       |       |      |       |
| Partnership Contribution Receivable |   | 330    |   | 347    |   | 366    |   | 386    |   | 407    |   | 998        | ** ** | **2,834** | ** ** |

 

**Partnership Contribution Payable**

 

This note payable bears interest at a rate of6.0 percent per annum. Equal payments of principal and interest arepayable quarterly, with final payment due January 2, 2017. The current andlong-term Partnership Contribution Payable amounts shown in the ConsolidatedBalance Sheet represents Cenovus’s 50 percent share of this promissorynote, net of payments to date.

 

**Mandatory Payments**

 
| (US$ millions)              |   | 2010   |   | 2011   |   | 2012   |   | 2013   |   | 2014   |   | Thereafter | ** ** | **Total** | ** ** |
|----------------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|------------|------------|-----------|------------|
|                             |   |   |   |   |   |   |   |   |   |   |   |       |       |      |       |
| Partnership Contribution Payable |   | 325    |   | 345    |   | 366    |   | 388    |   | 412    |   | 1,021      | ** ** | **2,857** | ** ** |

 

 

**10. INVENTORIES**

** **
| As at December 31, (US$ millions) | ** ** | **2009** |   | 2008   |   |
|---------------------------------------------|------------|----------|--------|--------|--------|
|                                        |       |     |   |   |   |
| Product                                     |       |     |   |   |   |
| Upstream Canada                             | ** ** | **255**  |   | 165    |   |
| Downstream Refining                         | ** ** | **563**  |   | 323    |   |
| Parts and Supplies                          | ** ** | **18**   |   | 15     |   |
|                                        | ** ** | **836**  |   | 503    |   |

 

 
| Cenovus Energy Inc. | 24 |
|---------------------|----|

 

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**10. INVENTORIES (continued)**

 

As a result of a significant decline in commodity prices inthe latter half of 2008, Cenovus recorded a write-down of its product inventoryby $152 million from cost to net realizable value.  At December 31, 2009, the productturnover during the current year and the improvement in commodity pricesresulted in a reversal of the prior year’s write-down of $144 million.

 

The total amount of inventories recognized as an expense duringthe year was $4,442 million (2008–$8,749 million; 2007–$5,752 million).

 

 

**11. PROPERTY, PLANT AND EQUIPMENT, NET**

** **
| As at December 31, (US$ millions) | ** ** | **    2009**           |       |                                        |    2008        |                                  |
|---------------------------------------------|------------|--------------------------------------------|------------|---------------------------------------------|-------------------------------|---------------------------------------|
|                                        | ** ** | **    Accumulated**    |       |                                        |    Accumulated |                                  |
| ** **                                  | ** ** | **     ****Cost** | ** ** | **     DD&A*** | ** **                    | **     Net** |   |   |      Cost |   |     DD&A* |   |      Net |   |
|                                        | ** ** | ** **                                 |       |                                        |                          |                                  |   |   |   |   |   |   |   |   |
| Upstream Canada                             | ** ** | **20,626**                                 | ** ** | **(10,966**                                 | **)**                         | **9,660**                             |   |   | 16,638 |   | (8,490 | ) | 8,148 |   |
| Downstream Refining                         | ** ** | **5,256**                                  | ** ** | **(489**                                    | **)**                         | **4,767**                             |   |   | 4,347 |   | (315 | ) | 4,032 |   |
| Corporate and Eliminations                  | ** ** | **373**                                    | ** ** | **(263**                                    | **)**                         | **110**                               |   |   | 190 |   | (110 | ) | 80 |   |
|                                        | ** ** | **26,255**                                 | ** ** | **(11,718**                                 | **)**                         | **14,537**                            |   |   | 21,175 |   | (8,915 | ) | 12,260 |   |

 

*  Depreciation, depletion andamortization

 

Upstream Canada property, plant and equipment includesinternal costs directly related to exploration, development and constructionactivities of $103 million (2008–$96 million). Costs classified asgeneral and administrative expenses have not been capitalized as part of thecapital expenditures.

 

Costs in respect of significant unproved properties andmajor development projects are excluded from the country cost centre’sdepletable base.  Downstream Refiningassets not put into use are excluded from depreciable costs. At the end of theyear these costs were:

 
| As at December 31, (US$ millions) | ** ** | **2009**  |   | 2008   |   | 2007   |   |
|---------------------------------------------|------------|-----------|--------|--------|--------|--------|--------|
|                                        |       |      |   |   |   |   |   |
| Upstream Canada                             | ** ** | **615**   |   | 227    |   | 223    |   |
| Downstream Refining                         | ** ** | **1,305** |   | 488    |   | 139    |   |
|                                        | ** ** | **1,920** |   | 715    |   | 362    |   |

 

The Canadian prices used in the ceiling test evaluation ofCenovus’s crude oil and natural gas reserves at December 31, 2009 were:

 
| ** **                      |   | 2010   |   | 2011   |   | 2012   |   | 2013   |   | 2014   |   | Cumulative  % Change to 2021 |   |
|---------------------------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|------------------------------|--------|
|                            |   |   |   |   |   |   |   |   |   |   |   |                         |   |
| Crude Oil (C$/barrel)           |   | 59.82  |   | 62.61  |   | 65.57  |   | 60.79  |   | 59.93  |   | (10)%                        |   |
| Natural Gas Liquids (C$/barrel) |   | 65.72  |   | 65.93  |   | 66.14  |   | 67.03  |   | 66.32  |   | 1%                           |   |
| Natural Gas (C$/Mcf)            |   | 5.31   |   | 6.21   |   | 6.09   |   | 5.88   |   | 5.86   |   | -%                           |   |

 

 

**12.  OTHERASSETS**

** **
| As at December 31, (US$ millions) | ** ** | **2009** |   | 2008   |   |
|---------------------------------------------|------------|----------|--------|--------|--------|
|                                        |       |     |   |   |   |
| Deferred Asset–Downstream Refining     | ** ** | **116**  |   | 134    |   |
| Deferred Pension Plan and Savings Plan      | ** ** | **9**    |   | 8      |   |
| Other                                       | ** ** | **6**    |   | 8      |   |
|                                        | ** ** | **131**  |   | 150    |   |

 

 
| Cenovus Energy Inc. | 25 |
|---------------------|----|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**13.  LONG-TERMDEBT**

** **
| As at December 31, (US$ millions) |       | Note       | ** ** | **2009**  |   | 2008   |   |
|---------------------------------------------|------------|------------|------------|-----------|--------|--------|--------|
|                                        | ** ** |       |       |      |   |   |   |
| Canadian Dollar Denominated Debt            |       |       |       |      |   |   |   |
| Bank credit facilities                      |       | A          | ** ** | **31**    |   |   |   |
| U.S. Dollar Denominated Debt                | ** ** |       |       |      |   |   |   |
| Bank credit facilities                      |       | A          | ** ** | **25**    |   |   |   |
| Unsecured notes                             |       | B          | ** ** | **3,500** |   |   |   |
|                                        | ** ** |       |       | **3,525** |   |   |   |
| Total Debt Principal                        | ** ** |       |       | **3,556** |   |   |   |
|                                        | ** ** |       |       |      |   |   |   |
| Debt Discounts and Transaction Costs        |       | C          | ** ** | **(63**   | **)**  |   |   |
| Current Portion of Long-Term Debt           |       | D          | ** ** | **-**     |   |   |   |
|                                        | ** ** | ** ** |       | **3,493** |   | 2,952  |   |

 

Long-term debt at December 31, 2008 represents anallocation of Cenovus’s proportionate share of EnCana’s consolidated debt as atDecember 31, 2008.  Long-term debtwas allocated to Cenovus on the same proportion of Canadian and U.S. dollardenominated debt and with the same terms and conditions as EnCana’s long-termdebt.  The effective average interestrate for long-term debt in 2009 was 5.7 percent (2008–5.5 percent).

 

**A) Bank Credit Facilities**

 

At December 31,2009, Cenovus had in place an unsecured credit facility in the amount of C$2.5billion or its equivalent amount in U.S. dollars.  The revolving syndicated credit facilityconsists of two tranches, a C$2.0 billion 3-year tranche and a C$500 million364-day tranche.  The 3-year tranchematures in November 2012 and is extendible from time to time for a periodof up to three years at the option of Cenovus and upon agreement from thelenders.  The 364-day tranche matures in November 2010and is extendible from time to time for a period of up to 364 days at theoption of Cenovus and upon agreement from the lenders.  If the facilities are not extended, the fullamount of the outstanding principal will come due on the respective maturitydates.

 

Borrowings underboth tranches are available by way of Bankers Acceptances, LIBOR based loans,prime rate loans or U.S. base rate loans. Bank credit outstanding at December 31, 2009 was drawn on the3-year tranche and included prime rate and LIBOR based loans of $56 million.

 

**B) U.S. Unsecured Notes**

 

On September 18,2009, a predecessor entity of Cenovus completed a private offering of seniorunsecured notes for an aggregate principal amount of $3.5 billion, issued inthree tranches, which are exempt from the registration requirements of the U.S.Securities Act of 1933 under Rule 144A and Regulation S.  The net proceeds of the private offeringalong with $151 million deposited by the Company were placed into an escrowaccount pending the completion of the Arrangement with EnCana.  Upon completion of the Arrangement, fundswere released from escrow and the proceeds of the notes were then used to paythe note payable to EnCana of $3.5 billion as part of the Arrangement.  On November 30, 2009, these notes becamethe direct, unsecured obligations of Cenovus.

 
| (US$ millions)               | ** ** | **2009**  | ** ** |
|-----------------------------------|------------|-----------|------------|
|                              | ** ** |      | ** ** |
| 4.50% due September 15, 2014 | ** ** | **800**   | ** ** |
| 5.70% due October 15, 2019   | ** ** | **1,300** | ** ** |
| 6.75% due November 15, 2039  | ** ** | **1,400** | ** ** |
|                              | ** ** | **3,500** | ** ** |

 

 
| Cenovus Energy Inc. | 26 |
|---------------------|----|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**13.  LONG-TERM DEBT (continued)**

 

Cenovushas agreed to use its commercially reasonable efforts to cause a registrationstatement with respect to an offer to exchange the U.S. unsecured notes for anew issue of notes registered under the U.S. Securities Act to be declaredeffective no later than September 18, 2010.

 

AtDecember 31, 2009, the Company is in compliance with all of the terms ofits debt agreements.

 

**C) Debt Discounts and Transaction Costs**

 

During 2009, $67million in transaction costs and discounts were recorded within long-term debtrelating to the issuance of the U.S. unsecured notes and the placement of thebank credit facilities.  The costs arebeing amortized using the effective interest method.  For comparative purposes, the transactioncosts and discounts allocated to Cenovus for 2008 were $2 million.

 

**D) Mandatory Debt Payments**

** **
| ($ millions) |   | C$ Principal  

Amount   |   | US$ Principal  

Amount   |   | Total US$  

Equivalent   |   |
|-------------------|--------|---------------------------------------------------|--------|----------------------------------------------------|--------|-----------------------------------------------|--------|
|              |   |                                              |   |                                               |   |                                          |   |
| 2010              |   | -                                                 |   | -                                                  |   | -                                             |   |
| 2011              |   | -                                                 |   | -                                                  |   | -                                             |   |
| 2012              |   | 32                                                |   | 25                                                 |   | 56                                            |   |
| 2013              |   | -                                                 |   | -                                                  |   | -                                             |   |
| 2014              |   | -                                                 |   | 800                                                |   | 800                                           |   |
| Thereafter        |   | -                                                 |   | 2,700                                              |   | 2,700                                         |   |
|              |   | 32                                                |   | 3,525                                              |   | 3,556                                         |   |

 

 

**14.  ASSET RETIREMENT OBLIGATION**

 

The aggregate carrying amount of the obligation associatedwith the retirement of upstream oil and gas assets and downstream refiningfacilities is as follows:

 
| As at December 31, (US$ millions)    |       | **2009**   |   | 2008   |   |
|------------------------------------------------|------------|------------|--------|--------|--------|
|                                           | ** ** | ** ** |   |   |   |
| Asset Retirement Obligation, Beginning of Year | ** ** | **648**    |   | 703    |   |
| Liabilities Incurred                           | ** ** | **5**      |   | 20     |   |
| Liabilities Settled                            | ** ** | **(33**    | **)**  | (49    | )      |
| Liabilities Divested                           | ** ** | **(9**     | **)**  | (1     | )      |
| Change in Estimated Future Cash Flows          | ** ** | **342**    |   | 69     |   |
| Accretion Expense                              | ** ** | **39**     |   | 39     |   |
| Foreign Currency Translation                   | ** ** | **104**    |   | (133   | )      |
| Asset Retirement Obligation, End of Year       | ** ** | **1,096**  |   | 648    |   |

 

The change estimated future cash flows in 2009 is dueto the increased estimate of costs to be incurred and the rate ofdiscount used for the current year estimate.  The total undiscounted amount of estimatedcash flows required to settle the obligation is $5,430 million (2008–$3,189 million),which has been discounted using a weighted average credit-adjusted risk freerate of 6.23 percent (2008–6.76 percent). Most of these obligationsare not expected to be paid for several years, or decades, in the future andwill be funded from general resources at that time.

 

 
| Cenovus Energy Inc. | 27 |
|---------------------|----|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**15.  SHARECAPITAL**

 

**Authorized**

 

Cenovus isauthorized to issue an unlimited number of Common Shares, an unlimited numberof First Preferred Shares and an unlimited number of Second Preferred Shares.

 

**Issued and Outstanding**

 

Under the terms ofthe Arrangement described in Note 2, EnCana shareholders exchanged their EnCanashare for one new EnCana Common Share and one Cenovus Common Share.

 
| As at December 31, 2009                     | ** ** | ** **                                              | ** ** | ** ** | ** **                      | ** ** |
|--------------------------------------------------|------------|---------------------------------------------------------|------------|------------|---------------------------------|------------|
|                                             | ** ** | ** **

**Number of  Common  Shares****(millions)** | ** ** | ** ** | **Amount****($ millions)** | ** ** |
| ** **                                       | ** ** | ** **                                              | ** ** | ** ** | ** **                      | ** ** |
| Common Shares Issued Pursuant to the Arrangement | ** ** | **751.3**                                               | ** ** | ** ** | **2,222**                       | ** ** |
| Common Shares Issued under Option Plans          | ** ** | **-**                                                   | ** ** | ** ** | **1**                           | ** ** |
| Outstanding, End of Year                         | ** ** | **751.3**                                               | ** ** | ** ** | **2,223**                       | ** ** |

 

To determine Cenovus’s share capital amount, EnCana’s statedcapital immediately prior to the Arrangement was split based on the relativefair market values of the EnCana and Cenovus Common Shares at the time of theinitial exchange.  Cenovus’s sharecapital amount was deducted from EnCana’s net investment with the remaining$4,902 million reclassified as Paid in Surplus. In December, Cenovus declaredits share of a pre-Arrangement dividend of $0.20 per share, which was chargedto Paid in Surplus.  This dividendreflects an amount determined in connection with the Arrangement based oncarve-out earnings and cash flows.

 

Under carve-out accounting, Owner’s Net Investmentrepresents the accumulated net earnings of the operations and the accumulatednet distributions to EnCana.  AccumulatedOther Comprehensive Income (“AOCI”) includes accumulated foreign currencytranslation adjustments.  At the date ofthe Arrangement, EnCana’s net investment in Cenovus was $7,124 million.

 

At December 31,2009, there were 24 million Common Shares available for future issuance understock option plans.  There were noPreferred Shares outstanding as at December 31, 2009.

 

**Net Investment**

 

EnCana’s net investment in the operations of Cenovus priorto the Arrangement is presented as total Net Investment in the ConsolidatedFinancial Statements.  Total NetInvestment consists of Owner’s Net Investment and AOCI.

 

**Option Plans**

 

Options grantedunder the plans are generally fully exercisable after three years and expirefive years after the date granted.

 

 
| Cenovus Energy Inc. | 28 |
|---------------------|----|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**15.  SHARECAPITAL (continued)**

 

*Cenovus Employee Stock Option Plan*

 

Cenovus hasstock-based compensation plans that allow employees to purchase Common Sharesof the Company.  Option exercise pricesapproximate the market price for the Common Shares on the date the options wereissued.  Options granted are exercisableat 30 percent of the number granted after one year, an additional 30 percent ofthe number granted after two years, and are fully exercisable after three yearsand expire five years after the original grant date.  Options granted under predecessor and/orrelated company replacement plans expire up to 10 years from the date theoptions were granted.  In addition,certain stock options granted are performance based.  The performancebased stock options vest and expire under the same terms and service conditionsas the underlying option, and vesting is subject to Cenovus attainingprescribed performance relative to pre-determined key measures.  All new options issued by the Company have anassociated Tandem Share Appreciation Right (“TSAR”) attached to them (see Note17).

 

*Cenovus Replacement Tandem Share Appreciation Rights (“CenovusReplacement TSARs”) Held By EnCana Employees*

 

Under the terms ofthe Arrangement, each original EnCana TSAR was replaced with one EnCanaReplacement TSAR and one Cenovus Replacement TSAR with terms and conditionssimilar to the original EnCana TSAR. EnCana is required to reimburse Cenovus in respect of cash payments madeby Cenovus to EnCana’s employees when these employees exercise a CenovusReplacement TSAR and therefore, no compensation expense is recognized.  No further Cenovus Replacement TSARs will begranted to EnCana employees.

 

EnCana employees canchoose to exercise the Cenovus Replacement TSAR in exchange for a Cenovuscommon share or for cash.  Cenovus hasrecorded a liability in the Consolidated Balance Sheet for Cenovus ReplacementTSARs held by EnCana employees using the fair value method, with an offsettingaccount receivable from EnCana.  The fairvalue of each Cenovus Replacement TSAR held by EnCana employees was estimatedusing the Black-Scholes-Merton model with weighted average assumptions asfollows:

 
|                                                                 |       | **2009**    |       |
|----------------------------------------------------------------------|------------|-------------|------------|
|                                                                 | ** ** | ** **  | ** ** |
| Risk Free Rate                                                       | ** ** | **1.46**    | **%**      |
| Dividend Yield                                                       | ** ** | **3.16**    | **%**      |
| Volatility                                                           | ** ** | **34.18**   | **%**      |
| Cenovus’s Closing Common Share  Price at December 31, 2009 | ** ** | **C$26.50** | ** ** |

 

The following tablessummarize information related to the Cenovus Replacement TSARs held by EnCanaemployees:

 
| As at December 31, 2009                          | ** ** | ** **                 | ** ** | ** **             | ** ** | ** ** | ** **                                        | ** ** |
|-------------------------------------------------------|------------|----------------------------|------------|------------------------|------------|------------|---------------------------------------------------|------------|
|                                                  | ** ** | **Total Number of  TSARs** | ** ** | **Performance  TSARs** | ** ** | ** ** | **Weighted****Average****Exercise****Price (C$)** | ** ** |
|                                                  | ** ** | ** **                 | ** ** | ** **             | ** ** | ** ** | ** **                                        | ** ** |
| Replacement TSARs – Pursuant to the  Arrangement | ** ** | **23,047,704**             | ** ** | **10,491,119**         | ** ** | ** ** | **27.14**                                         | ** ** |
| Exercised – SARs                                 | ** ** | **(29,840**                | **)**      | **-**                  | ** ** | ** ** | **18.57**                                         | ** ** |
| Exercised – Options                              | ** ** | **(1,206**                 | **)**      | **-**                  | ** ** | ** ** | **16.77**                                         | ** ** |
| Forfeited                                             | ** ** | **(71,321**                | **)**      | **(28,476**            | **)**      | ** ** | **29.50**                                         | ** ** |
| Outstanding, End of  December 31, 2009           | ** ** | **22,945,337**             | ** ** | **10,462,643**         | ** ** | ** ** | **27.14**                                         | ** ** |
| Exercisable, End of  December 31, 2009           | ** ** | **9,972,272**              | ** ** | **2,236,641**          | ** ** | ** ** | **25.29**                                         | ** ** |

 

 
| Cenovus Energy Inc. | 29 |
|---------------------|----|

 

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Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**15.  SHARECAPITAL (continued)**

 
|                           |       | **Outstanding TSARs**         | ** ** | ** **             | **Exercisable TSARS** |                                                        |
|--------------------------------|------------|-------------------------------|------------|------------------------|-----------------------|-------------------------------------------------------------|
| Range of Exercise   Price (C$) | ** ** | **Total****Number of  TSARs** | ** ** | **Performance  TSARs** | ** **            | **Weighted  Average  Remaining  Contractual  Life (years)** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** | ** ** | **Total****Number of  TSARs** | ** ** | **Performance  TSARs** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                           | ** ** | ** **                    | ** ** | ** **             | ** **            | ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 15.00 to 19.99                 | ** ** | **1,097,538**                 | ** ** | **-**                  | ** **            | **0.13**                                                    | ** ** | **18.21** | ** ** | ** ** | **1,097,538** | ** ** | **-** | ** ** | **18.21** | ** ** |
| 20.00 to 24.99                 | ** ** | **3,965,161**                 | ** ** | **-**                  | ** **            | **1.13**                                                    | ** ** | **22.95** | ** ** | ** ** | **3,948,676** | ** ** | **-** | ** ** | **22.94** | ** ** |
| 25.00 to 29.99                 | ** ** | **12,096,882**                | ** ** | **7,280,249**          | ** **            | **3.12**                                                    | ** ** | **26.50** | ** ** | ** ** | **3,340,019** | ** ** | **1,563,747** | ** ** | **26.75** | ** ** |
| 30.00 to 34.99                 | ** ** | **5,593,956**                 | ** ** | **3,182,394**          | ** **            | **3.08**                                                    | ** ** | **32.83** | ** ** | ** ** | **1,528,499** | ** ** | **672,894** | ** ** | **32.68** | ** ** |
| 35.00 to 39.99                 | ** ** | **109,450**                   | ** ** | **-**                  | ** **            | **3.41**                                                    | ** ** | **37.14** | ** ** | ** ** | **32,835** | ** ** | **-** | ** ** | **37.14** | ** ** |
| 40.00 to 44.99                 | ** ** | **80,850**                    | ** ** | **-**                  | ** **            | **3.44**                                                    | ** ** | **42.77** | ** ** | ** ** | **24,255** | ** ** | **-** | ** ** | **42.77** | ** ** |
| 45.00 to 49.99                 | ** ** | **1,500**                     | ** ** | **-**                  | ** **            | **3.39**                                                    | ** ** | **45.56** | ** ** | ** ** | **450** | ** ** | **-** | ** ** | **45.56** | ** ** |
|                           | ** ** | **22,945,337**                | ** ** | **10,462,643**         | ** **            | **2.62**                                                    | ** ** | **27.14** | ** ** | ** ** | **9,972,272** | ** ** | **2,236,641** | ** ** | **25.29** | ** ** |

 

 

**16.  CAPITALSTRUCTURE**

 

Cenovus’s capital structure is comprised of Shareholders’Equity plus Long-Term Debt.  Cenovus’sobjectives when managing its capital structure are to maintain financialflexibility, preserve access to capital markets, ensure its ability to financeinternally generated growth and to fund potential acquisitions whilemaintaining the ability to meet the Company’s financial obligations as theycome due.

 

Cenovus monitors its capital structure and short-termfinancing requirements using, among other things, non-GAAP financial metricsconsisting of Debt to Capitalization and Debt to Adjusted Earnings BeforeInterest, Taxes, Depreciation and Amortization (“EBITDA”). These metrics areused to steward Cenovus’s overall debt position as measures of Cenovus’soverall financial strength. Debt is defined as the current and long-termportions of long-term debt excluding any amounts with respect to thePartnership Contribution Payable or Receivable.

 

Cenovus targets a Debt to Capitalization ratio of between 30and 40 percent.

 
| As at December 31, (US$ millions) |       | **2009**    |   | 2008   |   |
|---------------------------------------------|------------|-------------|--------|--------|--------|
| Debt                                        | ** ** | **3,493**   |   | 3,036  |   |
| Shareholders’ Equity                   | ** ** | **9,180**   |   | 7,748  |   |
| Total Capitalization                        | ** ** | **12,673**  |   | 10,784 |   |
| Debt to Capitalization  ratio               | ** ** | **28****%** |   | 28%    |   |

 

Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and2.0 times.

 
| As at December 31, (US$ millions) |       | **2009**     |   | 2008   |   | 2007   |   |
|---------------------------------------------|------------|--------------|--------|--------|--------|--------|--------|
| Debt                                        | ** ** | **3,493**    |   | 3,036  |   | 3,690  |   |
|                                        | ** ** | ** **   |   |   |   |   |   |
| Net Earnings                                | ** ** | **648**      |   | 2,368  |   | 1,404  |   |
| Add (deduct):                               |       |         |   |   |   |   |   |
| Interest, net                               | ** ** | **218**      |   | 218    |   | 187    |   |
| Income tax expense                          | ** ** | **302**      |   | 725    |   | 423    |   |
| Depreciation, depletion and  amortization   | ** ** | **1,343**    |   | 1,318  |   | 1,426  |   |
| Accretion of asset retirement  obligation   | ** ** | **39**       |   | 39     |   | 28     |   |
| Foreign exchange (gain) loss, net           | ** ** | **290**      |   | (250   | )      | 380    |   |
| Other (income) loss, net                    | ** ** | **(2**       | **)**  | 3      |   | 4      |   |
| Adjusted EBITDA                             | ** ** | **2,838**    |   | 4,421  |   | 3,852  |   |
| Debt to Adjusted EBITDA                     | ** ** | **1.2****x** |   | 0.7x   |   | 1.0x   |   |

 

 
| Cenovus Energy Inc. | 30 |
|---------------------|----|

 

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$ millions,unless otherwise indicated*

*For the year ended December 31,2009*

 

 

**16.  CAPITALSTRUCTURE (continued)**

 

It is Cenovus’s intention to maintain an investment graderating to ensure it has continuous access to capital and the financialflexibility to fund its capital programs, meet its financial obligations andfinance potential acquisitions.  Cenovuswill maintain a high level of capital discipline and manage its capitalstructure to ensure sufficient liquidity through all stages of the economiccycle.  To manage the capital structure,Cenovus may adjust capital and operating spending, adjust dividends paid toshareholders, purchase shares for cancellation pursuant to normal course issuerbids, issue new shares, issue new debt, draw down on its credit facility orrepay existing debt.

 

Cenovus’s capital structure, objectives and targets haveremained unchanged over the periods presented. At December 31, 2009, Cenovus is in compliance with all of theterms of its debt agreements.

 

 

**17. COMPENSATION PLANS**

 

Cenovus has in placea number of programs whereby employees may be granted the following share-basedlong-term incentives:

 

·                   **Tandem Share Appreciation Rights (“TSARs”)**

Alloptions to purchase Common Shares issued under the Cenovus Employee StockOption Plan, with the exception of a limited number of Cenovus ReplacementOptions, as described in Note 15, have an associated TSAR attached to themwhereby the option holder has the right to receive a cash payment equal to theexcess of the market price of Cenovus’s Common Shares at the time of exerciseover the exercise price of the right in lieu of exercising the option. TheTSARs vest and expire under the same terms and conditions as the underlyingoption.  Certain of the TSARs (“PerformanceTSARS”) have an additional vesting requirement which is subject to theachievement of prescribed performance relative to key pre-determined measures.Performance TSARs that do not vest when eligible are forfeited.

 

·                   **Share Appreciation Rights (“SARs”)**

ShareAppreciation Rights (“SARs”) entitle the employee to receive a cash paymentequal to the excess of the market price of Cenovus’s Common Shares at the timeof exercise over the exercise price of the right. SARs are exercisable at 30percent of the number granted after one year, an additional 30 percent of thenumber granted after two years and are fully exercisable after three years andexpire five years after the original grant date.  Certain of the SARs (“Performance SARs”) havean additional vesting requirement which is subject to the achievement ofprescribed performance relative to key pre-determined measures. PerformanceSARs that do not vest when eligible are forfeited.

 

In accordance withthe Arrangement with EnCana described in Note 2, each Cenovus employee holdingan original EnCana long-term incentive unit of the same nature transferredtheir right to Cenovus in exchange for a Cenovus Replacement Unit and to EnCanafor an EnCana Replacement Unit. The terms and conditions of the Cenovus andEnCana Replacement Units are similar to the terms and conditions of theoriginal EnCana unit. The original exercise price of the EnCana unit wasapportioned to the Cenovus and EnCana Replacement Units based on the one dayweighted average trading price of Cenovus’s common share price relative to thatof EnCana’s common share price on the TSX on December 2, 2009.  Cenovus is required to reimburse EnCana inrespect of cash payments made by EnCana to Cenovus employees for the EnCanaReplacement Units they hold. No further EnCana Replacement Units will begranted to Cenovus employees.

 

All of these share-based long-term incentive programs havesimilar vesting provisions as the Cenovus stock option plan.  Cenovus Units and Cenovus Replacement Unitsare measured against the Cenovus common share price and EnCana ReplacementUnits are measured against the EnCana common share price.

 

 
| Cenovus Energy Inc. | 31

  |
|---------------------|------------|

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$ millions,unless otherwise indicated*

*For the year ended December 31,2009*

 

 

**17. COMPENSATION PLANS (continued)**

 

The Company hasrecorded a liability in the Consolidated Balance Sheet for EnCana ReplacementUnits held by the Company’s employees using the fair value method.  The fair value of each EnCana ReplacementUnit granted is estimated using the Black-Scholes-Merton model with weightedaverage assumptions as follows:

 
| ** **                                                          | ** ** | **2009 ** |
|---------------------------------------------------------------------|------------|----------------|
|                                                                | ** ** | ** **     | ** ** |
| Risk Free Rate                                                      | ** ** | **1.46**       | **%** |
| Dividend Yield                                                      | ** ** | **2.45**       | **%** |
| Volatility                                                          | ** ** | **26.17**      | **%** |
| EnCana’s Closing Common Share Price at  December 31, 2009 | ** ** | **C$34.11**    | ** ** |

 

**A) Tandem Share Appreciation Rights**

 

The following tablessummarize the information related to the TSARs held by Cenovus employees:

 
| As at December 31,  2009                         | ** ** | ** **                               | ** ** | ** **             | ** ** | ** ** | ** **                                        | ** ** |
|--------------------------------------------------|------------|------------------------------------------|------------|------------------------|------------|------------|---------------------------------------------------|------------|
|                                             | ** ** | **Total********Number  of********TSARs** |       | **Performance  TSARs** |       |       | **Weighted********Average  Exercise  Price (C$)** | ** ** |
| Replacement TSARs –  November 30, 2009 | ** ** | **16,431,032**                           | ** ** | **8,053,074**          | ** ** | ** ** | **27.51**                                         | ** ** |
| Granted                                          | ** ** | **67,500**                               | ** ** | **-**                  | ** ** | ** ** | **25.66**                                         | ** ** |
| Exercised – SARs                            | ** ** | **(12,755**                              | **)**      | **-**                  | ** ** | ** ** | **18.43**                                         | ** ** |
| Exercised – Options                         | ** ** | **(31,050**                              | **)**      | **-**                  | ** ** | ** ** | **18.13**                                         | ** ** |
| Outstanding, End of  December 31, 2009      | ** ** | **16,454,727**                           | ** ** | **8,053,074**          | ** ** | ** ** | **27.52**                                         | ** ** |
| Exercisable, End of  December 31, 2009      | ** ** | **6,107,015**                            | ** ** | **1,526,893**          | ** ** | ** ** | **25.68**                                         | ** ** |

 
|                           | ** ** | **Outstanding TSARs**         | ** ** | ** **             | **Exercisable TSARs** | ** **                                                  |
|--------------------------------|------------|-------------------------------|------------|------------------------|-----------------------|-------------------------------------------------------------|
| Range of Exercise   Price (C$) | ** ** | **Total****Number of  TSARs** | ** ** | **Performance  TSARs** | ** **            | **Weighted  Average  Remaining  Contractual  Life (years)** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** | ** ** | **Total  Number of  TSARs** | ** ** | **Performance  TSARs** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                           | ** ** | ** **                    | ** ** | ** **             | ** **            | ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 15.00 to 19.99                 | ** ** | **661,202**                   | ** ** | **-**                  | ** **            | **0.13**                                                    | ** ** | **18.25** | ** ** | ** ** | **661,202** | ** ** | **-** | ** ** | **18.25** | ** ** |
| 20.00 to 24.99                 | ** ** | **2,298,334**                 | ** ** | **-**                  | ** **            | **1.17**                                                    | ** ** | **22.94** | ** ** | ** ** | **2,261,029** | ** ** | **-** | ** ** | **22.94** | ** ** |
| 25.00 to 29.99                 | ** ** | **8,878,174**                 | ** ** | **5,390,982**          | ** **            | **3.33**                                                    | ** ** | **26.46** | ** ** | ** ** | **1,988,135** | ** ** | **964,003** | ** ** | **26.76** | ** ** |
| 30.00 to 34.99                 | ** ** | **4,418,817**                 | ** ** | **2,662,092**          | ** **            | **3.11**                                                    | ** ** | **32.90** | ** ** | ** ** | **1,137,189** | ** ** | **562,890** | ** ** | **32.82** | ** ** |
| 35.00 to 39.99                 | ** ** | **124,350**                   | ** ** | **-**                  | ** **            | **3.45**                                                    | ** ** | **37.14** | ** ** | ** ** | **37,305** | ** ** | **-** | ** ** | **37.14** | ** ** |
| 40.00 to 44.99                 | ** ** | **71,850**                    | ** ** | **-**                  | ** **            | **3.45**                                                    | ** ** | **43.31** | ** ** | ** ** | **21,555** | ** ** | **-** | ** ** | **43.31** | ** ** |
| 45.00 to 49.99                 | ** ** | **2,000**                     | ** ** | **-**                  | ** **            | **3.39**                                                    | ** ** | **45.56** | ** ** | ** ** | **600** | ** ** | **-** | ** ** | **45.56** | ** ** |
|                           | ** ** | **16,454,727**                | ** ** | **8,053,074**          | ** **            | **2.84**                                                    | ** ** | **27.52** | ** ** | ** ** | **6,107,015** | ** ** | **1,526,893** | ** ** | **25.68** | ** ** |

 

For the year ended December 31,2009, Cenovus recorded a reduction of compensation cost of $4 million relatedto TSARs.

 

**B) Share Appreciation Rights**

 

The following tablessummarize the information related to the SARs held by Cenovus employees:

 
| As at December 31,  2009                       | ** ** | ** **                   | ** ** | ** **            | ** ** | ** ** | ** **                                        | ** ** |
|------------------------------------------------|------------|------------------------------|------------|-----------------------|------------|------------|---------------------------------------------------|------------|
|                                           | ** ** | **Total  Number of****SARs** | ** ** | **Performance  SARs** | ** ** | ** ** | **Weighted****Average****Exercise****Price (C$)** | ** ** |
|                                           | ** ** | ** **                   | ** ** | ** **            | ** ** | ** ** | ** **                                        | ** ** |
| Replacement SARs – November 30, 2009 | ** ** | **44,657**                   | ** ** | **23,932**            | ** ** | ** ** | **29.38**                                         | ** ** |
| Outstanding, December 31, 2009            | ** ** | **44,657**                   | ** ** | **23,932**            | ** ** | ** ** | **29.38**                                         | ** ** |
| Exercisable, December 31, 2009            | ** ** | **4,557**                    | ** ** | **2,532**             | ** ** | ** ** | **32.96**                                         | ** ** |

 

 
| Cenovus Energy Inc. | 32

  |
|---------------------|------------|

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$ millions,unless otherwise indicated*

*For the year ended December 31,2009*

 

 

**17. COMPENSATION PLANS (continued)**

 
|                          | ** ** | ** **                   | ** ** | **Outstanding SARs**  | ** ** | ** **                                                  | ** ** | ** **                                  | **Exercisable SARs** | ** ** |
|-------------------------------|------------|------------------------------|------------|-----------------------|------------|-------------------------------------------------------------|------------|---------------------------------------------|----------------------|------------|
| Range of Exercise  Price (C$) | ** ** | **Total****Number of  SARs** | ** ** | **Performance  SARs** | ** ** | **Weighted  Average  Remaining  Contractual  Life (years)** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** **           | ** ** | **Total  Number of  SARs** | ** ** | **Performance  SARs** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                          | ** ** | ** **                   | ** ** | ** **            | ** ** | ** **                                                  | ** ** | ** **                                  | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 25.00 to 29.99                | ** ** | **25,925**                   | ** ** | **11,950**            | ** ** | **4.13**                                                    | ** ** | **26.79**                                   | ** **           | ** ** | **-** | ** ** | **-** | ** ** | **-** | ** ** |
| 30.00 to 34.99                | ** ** | **18,732**                   | ** ** | **11,982**            | ** ** | **3.12**                                                    | ** ** | **32.96**                                   | ** **           | ** ** | **4,557** | ** ** | **2,532** | ** ** | **32.96** | ** ** |
|                          | ** ** | **44,657**                   | ** ** | **23,932**            | ** ** | **3.71**                                                    | ** ** | **29.38**                                   | ** **           | ** ** | **4,557** | ** ** | **2,532** | ** ** | **32.96** | ** ** |

 

For the year ended December 31,2009, Cenovus has not recorded any compensation costs related to the SARs.

 

**C) EnCana Replacement Tandem Share Appreciation Rights**

 

The following tablessummarize information related to the EnCana Replacement TSARs held by Cenovusemployees:

 
| As at December 31,  2009                         | ** ** | ** **                                               | ** ** | ** **             | ** ** | ** ** | ** **                                  | ** ** |
|--------------------------------------------------|------------|----------------------------------------------------------|------------|------------------------|------------|------------|---------------------------------------------|------------|
|                                             | ** ** | **Total Number of  TSARs     ** | ** ** | **Performance  TSARs** | ** ** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                                             | ** ** | ** **                                               | ** ** | ** **             | ** ** | ** ** | ** **                                  | ** ** |
| Replacement TSARs –  November 30, 2009 | ** ** | **16,431,032**                                           | ** ** | **8,053,074**          | ** ** | ** ** | **30.41**                                   | ** ** |
| Exercised – SARs                            | ** ** | **(73,322**                                              | **)**      | **(1,382**             | **)**      | ** ** | **20.67**                                   | ** ** |
| Exercised – Options                         | ** ** | **(1,050**                                               | **)**      | **-**                  | ** ** | ** ** | **17.96**                                   | ** ** |
| Outstanding, End of  December 31, 2009      | ** ** | **16,356,660**                                           | ** ** | **8,051,692**          | ** ** | ** ** | **30.46**                                   | ** ** |
| Exercisable, End of  December 31, 2009      | ** ** | **6,076,448**                                            | ** ** | **1,525,511**          | ** ** | ** ** | **28.43**                                   | ** ** |

 
|                           | ** ** | **Outstanding EnCana Replacement TSARs** | **Exercisable EnCana Replacement TSARs** | ** **             |
|--------------------------------|------------|------------------------------------------|------------------------------------------|------------------------|
| Range of Exercise   Price (C$) | ** ** | **Total****Number of  TSARs**            | ** **                               | **Performance  TSARs** | ** ** | **Weighted  Average  Remaining  Contractual  Life (years)** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** | ** ** | **Total  Number of  TSARs** | ** ** | **Performance  TSARs** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                           | ** ** | ** **                               | ** **                               | ** **             | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 15.00 to 19.99                 | ** ** | **2,960**                                | ** **                               | **-**                  | ** ** | **0.08** | ** ** | **19.08** | ** ** | ** ** | **2,960** | ** ** | **-** | ** ** | **19.08** | ** ** |
| 20.00 to 24.99                 | ** ** | **652,542**                              | ** **                               | **-**                  | ** ** | **0.18** | ** ** | **20.27** | ** ** | ** ** | **646,942** | ** ** | **-** | ** ** | **20.25** | ** ** |
| 25.00 to 29.99                 | ** ** | **10,800,826**                           | ** **                               | **5,389,600**          | ** ** | **2.89** | ** ** | **28.39** | ** ** | ** ** | **4,035,672** | ** ** | **962,621** | ** ** | **27.17** | ** ** |
| 30.00 to 34.99                 | ** ** | **411,720**                              | ** **                               | **-**                  | ** ** | **2.41** | ** ** | **32.29** | ** ** | ** ** | **264,565** | ** ** | **-** | ** ** | **32.09** | ** ** |
| 35.00 to 39.99                 | ** ** | **4,341,562**                            | ** **                               | **2,662,092**          | ** ** | **3.12** | ** ** | **36.47** | ** ** | ** ** | **1,082,194** | ** ** | **562,890** | ** ** | **36.46** | ** ** |
| 40.00 to 44.99                 | ** ** | **74,200**                               | ** **                               | **-**                  | ** ** | **3.49** | ** ** | **42.28** | ** ** | ** ** | **22,260** | ** ** | **-** | ** ** | **42.28** | ** ** |
| 45.00 to 49.99                 | ** ** | **70,850**                               | ** **                               | **-**                  | ** ** | **3.45** | ** ** | **47.94** | ** ** | ** ** | **21,255** | ** ** | **-** | ** ** | **47.94** | ** ** |
| 50.00 to 54.99                 | ** ** | **2,000**                                | ** **                               | **-**                  | ** ** | **3.39** | ** ** | **50.39** | ** ** | ** ** | **600** | ** ** | **-** | ** ** | **50.39** | ** ** |
|                           | ** ** | **16,356,660**                           | ** **                               | **8,051,692**          | ** ** | **2.84** | ** ** | **30.46** | ** ** | ** ** | **6,076,448** | ** ** | **1,525,511** | ** ** | **28.43** | ** ** |

 

For the year ended December 31,2009, the Company recorded compensation costs of $55 million related to theEnCana Replacement TSARs.

 

**D) EnCana Replacement Share Appreciation Rights**

The following tablessummarize information related to the EnCana Replacement SARs held by Cenovusemployees:

 
| As at December 31, 2009                               | ** ** | ** **                 | ** ** | ** **             | ** ** | ** ** | ** **                                  | ** ** |
|-------------------------------------------------------|------------|----------------------------|------------|------------------------|------------|------------|---------------------------------------------|------------|
|                                                  | ** ** | **Total  Number of  SARs** | ** ** | **Performance  TSARs** | ** ** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                                                  | ** ** | ** **                 | ** ** | ** **             | ** ** | ** ** | ** **                                  | ** ** |
| EnCana Replacement SARs – November 30, 2009 | ** ** | **44,657 **           | ** ** | **23,932**             | ** ** | ** ** | **32.48 **                             | ** ** |
| Outstanding, End of December 31, 2009            | ** ** | **44,657 **           | ** ** | **23,932**             | ** ** | ** ** | **32.48 **                             | ** ** |
| Exercisable, End of December 31, 2009            | ** ** | **4,557 **            | ** ** | **2,532**              | ** ** | ** ** | **36.44 **                             | ** ** |

 

 
| Cenovus Energy Inc. | 33

  |
|---------------------|------------|

----

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$ millions,unless otherwise indicated*

*For the year ended December 31,2009*

 

 

**17.  COMPENSATION PLANS(continued)**

 
|                           | ** ** | **    Outstanding EnCana Replacement SARs** | ** ** | ** **            | **   Exercisable EnCana Replacement SARs** | ** **                                                  |
|--------------------------------|------------|-----------------------------------------------------------------|------------|-----------------------|-----------------------------------------------------------|-------------------------------------------------------------|
| Range of Exercise   Price (C$) | ** ** | **Total****Number of  SARs**                                    | ** ** | **Performance  SARs** | ** **                                                | **Weighted  Average  Remaining  Contractual  Life (years)** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** | ** ** | **Total  Number of  SARs** | ** ** | **Performance  SARs** | ** ** | **Weighted  Average  Exercise  Price (C$)** | ** ** |
|                           | ** ** | ** **                                                      | ** ** | ** **            | ** **                                                | ** **                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| 25.00 to 29.99                 | ** ** | **22,925**                                                      | ** ** | **11,950**            | ** **                                                | **4.09**                                                    | ** ** | **29.23** | ** ** | ** ** | **-** | ** ** | **-** | ** ** | **-** | ** ** |
| 30.00 to 34.99                 | ** ** | **3,000**                                                       | ** ** | **-**                 | ** **                                                | **4.45**                                                    | ** ** | **32.55** | ** ** | ** ** | **-** | ** ** | **-** | ** ** | **-** | ** ** |
| 35.00 to 39.99                 | ** ** | **18,732**                                                      | ** ** | **11,982**            | ** **                                                | **3.12**                                                    | ** ** | **36.44** | ** ** | ** ** | **4,557** | ** ** | **2,532** | ** ** | **36.44** | ** ** |
|                           | ** ** | **44,657**                                                      | ** ** | **23,932**            | ** **                                                | **3.71**                                                    | ** ** | **32.48** | ** ** | ** ** | **4,557** | ** ** | **2,532** | ** ** | **36.44** | ** ** |

 

For the year ended December 31,2009, the Company has not recorded any compensation costs related to the EnCanaReplacement SARs.

 

**E) Deferred Share Units (“DSUs”)**

 

Cenovus has in placea program whereby directors, officers and employees are issued Deferred ShareUnits (“DSUs”), which are equivalent in value to a common share of the Company.Commencing in 2009, employees had the option to convert either 25 or 50 percentof their annual bonus award into DSUs. DSUs vest immediately, can be redeemed in accordance with terms of theagreement and expire on December 15 of the calendar year following theyear of cessation of directorship or employment.

 

Pursuant to the terms of the Arrangement, EnCana DSUscredited to directors, officers and employees of Cenovus were exchanged forCenovus DSUs.  The fair value of theCenovus DSUs credited to each holder was based on the fair market value ofCenovus Common Shares relative to EnCana common shares prior to the effectivedate of the Arrangement.

 
| As at December 31, 2009                    | ** ** | ** **            | ** ** |
|--------------------------------------------|------------|-----------------------|------------|
|                                       | ** ** | ** **            | ** ** |
|                                       | ** ** | ** **            | ** ** |
|                                       | ** ** | **Outstanding  DSUs** | ** ** |
|                                       | ** ** | ** **            | ** ** |
| Outstanding, November 30, 2009        | ** ** | **762,011**           | ** ** |
| Units in Lieu of Dividends                 | ** ** | **6,092**             | ** ** |
| Outstanding, End of December 31, 2009 | ** ** | **768,103**           | ** ** |

 

For the year ended December 31,2009, the Company has not recorded any compensation costs related to DSUs.

 

**F) EnCana Pre-Arrangement Stock-BasedCompensation Costs**

 

Included in thefinancial information prior to the Arrangement, the Company recordedcompensation costs for the following EnCana plans:

 
| (US$ millions) | ** ** | **2009**   |   | 2008   |   | 2007   |   |
|---------------------|------------|------------|--------|--------|--------|--------|--------|
|                | ** ** | ** ** |   |   |   |   |   |
| EnCana TSARs        | ** ** | **4**      |   | (9     | )      | 83     |   |
| EnCana SARs         | ** ** | **1**      |   | -      |   | -      |   |
| EnCana DSUs         | ** ** | **2**      |   | 1      |   | 7      |   |
| EnCana PSUs         | ** ** | **-**      |   | -      |   | 16     |   |

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**17. COMPENSATION PLANS (continued)**

 

**G) Pensions and OtherPost-Employment Benefits**

 

The Company sponsorsdefined benefit and defined contribution plans, providing pension and otherpost-employment benefits (“OPEB”) to its employees.

 

The Company isrequired to file an actuarial valuation of its pension plans with theprovincial regulator at least every three years. An actuarial valuation as at November 30,2009 will be filed during the first half of 2010.

 

Pursuant to theArrangement, the liabilities and assets related to Cenovus employees, asdetermined by actuarial consultants, transferred to the Cenovus Pension Planseffective November 30, 2009. The 2009 Pension and OPEB amounts reflectactivity since the effective date.

 

The 2008 Pension andOPEB amounts represent Cenovus’s proportionate share of EnCana’s pension plansrelated to active employees. The going concern liabilities and assets relatedto retirees prior to the Arrangement remained with EnCana.

 

Information relatedto defined benefit pension and other post-employment benefit plans, based onactuarial estimations as at December 31, 2009 is as follows:

 

*Accrued Benefit Obligation*

 
|                                                    | ** ** | Pension Benefits | ** ** | ** ** | OPEB       |       |
|---------------------------------------------------------|------------|------------------|------------|------------|------------|------------|
| As at December 31, (US$ millions)             | ** ** | **2009**         | ** ** | 2008       | ** ** | ** ** | **2009** |   | 2008 |   |
|                                                    | ** ** |             | ** ** | ** ** |       |       |   |   |   |   |
| Accrued Benefit Obligation Pursuant  to the Arrangement | ** ** | **50**           |       |       | ** ** | ** ** | **11** |   |   |   |
| Current service cost                                    | ** ** | **-**            |       |       | ** ** | ** ** | **-** |   |   |   |
| Interest cost                                           | ** ** | **-**            |       |       | ** ** | ** ** | **-** |   |   |   |
| Benefits paid                                           | ** ** | **-**            |       |       | ** ** | ** ** | **-** |   |   |   |
| Actuarial (gain) loss                                   | ** ** | **3**            |       |       | ** ** | ** ** | **-** |   |   |   |
| Foreign exchange (gain) loss                            | ** ** | **1**            |       |       | ** ** | ** ** | **-** |   |   |   |
| Accrued Benefit Obligation, End of  Year                | ** ** | **54**           |       | 36         | ** ** | ** ** | **11** |   | 7 |   |

 

*Plan Assets*

 
|                                                   | ** ** | Pension Benefits | ** ** | ** ** | OPEB       |       |
|--------------------------------------------------------|------------|------------------|------------|------------|------------|------------|
| As at December 31, (US$ millions)                 | ** ** | **2009**         | ** ** | 2008       | ** ** | ** ** | **2009** |   | 2008 |   |
|                                                   | ** ** |             | ** ** | ** ** |       |       |   |   |   |   |
| Fair Value of Plan Assets Pursuant to the  Arrangement | ** ** | **50**           |       |       | ** ** | ** ** | **-** |   |   |   |
| Actuarial gain (loss) on return of  plan assets        | ** ** | **1**            |       |       | ** ** | ** ** | - |   |   |   |
| Employer contributions                                 | ** ** | **-**            |       |       | ** ** | ** ** | - |   |   |   |
| Benefits paid                                          | ** ** | **-**            |       |       | ** ** | ** ** | - |   |   |   |
| Foreign exchange (gain) loss                           | ** ** | **1**            |       |       | ** ** | ** ** | - |   |   |   |
| Fair Value of Plan Assets, End of Year                 | ** ** | **52**           |       | 32         | ** ** | ** ** | **-** |   | - |   |

 

*Accrued Benefit Asset (Liability)*

 
|                                                           | ** ** | Pension Benefits | ** ** | ** ** | OPEB       |       |
|----------------------------------------------------------------|------------|------------------|------------|------------|------------|------------|
| As at December 31, (US$ millions)                         | ** ** | **2009**         | ** ** | 2008       | ** ** | ** ** | **2009** |   | 2008 |   |
|                                                           | ** ** |             | ** ** | ** ** |       |       |   |   |   |   |
| Funded Status–Plan Assets (less) than Benefit  Obligation | ** ** | **(2**           | **)**      |       | ** ** | ** ** | **(11** | **)** |   |   |
| Amounts Not Recognized:                                        | ** ** | ** **       |       |       | ** ** | ** ** | ** ** |   |   |   |
| Unamortized net actuarial (gain)  loss                         | ** ** | **14**           |       |       | ** ** | ** ** | **(1** | **)** |   |   |
| Unamortized past service cost                                  | ** ** | **-**            |       |       | ** ** | ** ** | **1** |   |   |   |
| Accrued Benefit Asset (Liability)                              | ** ** | **12**           |       | 6          | ** ** | ** ** | **(11** | **)** | (6 | ) |

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**17.  COMPENSATION PLANS(continued)**

 
|                                   | ** ** | Pension Benefits | ** ** | ** ** | OPEB       |       |
|----------------------------------------|------------|------------------|------------|------------|------------|------------|
| As at December 31, (US$ millions) | ** ** | **2009**         | ** ** | 2008       | ** ** | ** ** | **2009** |   | 2008 |   |
|                                   | ** ** |             | ** ** | ** ** |       |       |   |   |   |   |
| Prepaid Benefit Cost                   | ** ** | **12**           |       |       | ** ** | ** ** | -  |   |   |   |
| Accrued Benefit Cost                   | ** ** | **-**            |       |       | ** ** | ** ** | **(11)** |   |   |   |
| Net Amount Recognized                  | ** ** | **12**           |       | 6          | ** ** | ** ** | **(11)** |   | (6) |   |

 

The Company’s OPEBplans are funded on an as required basis.

 

The weighted averageassumptions used to determine benefit obligations are as follows:

 
| As at December 31,       | ** ** | **2009 ** | ** ** | 2008        |       |       | **2009 ** |   | 2008   |   |
|-------------------------------|------------|----------------|------------|-------------|------------|------------|----------------|--------|--------|--------|
|                          | ** ** | ** **     |       |        | ** ** | ** ** | ** **     |   |   |   |
| Discount Rate                 | ** ** | **6.00%**      |       | 6.25%  | ** ** | ** ** | **6.00%**      |   | 6.25%  |   |
| Rate of Compensation Increase | ** ** | **4.05%**      |       | 4.16%  | ** ** | ** ** | **5.77%**      |   | 6.00%  |   |

 

The averageremaining service period of the active employees covered by the defined benefitpension plan is 4 years.  The averageremaining service period of the active employees covered by the OPEB plan is 11years.

 

Assumed health carecost trend rates are as follows:

 
| As at December 31,                                                      | ** ** | **2009**                   |   | 2008                   |   |
|------------------------------------------------------------------------------|------------|----------------------------|--------|------------------------|--------|
|                                                                         |       |                       |   |                   |   |
| Health Care Cost Trend Rate for  Next Year                                   | ** ** | **10.00%**                 |   | 9.50%                  |   |
| Rate that the Trend Rate Gradually  Trends To                                | ** ** | **5.00%**                  |   | 5.00%                  |   |
| Year that the Trend Rate Reaches  the Rate which it is Expected to Remain At | ** ** | **2020   ** |   | 2017    |   |

 

Assumed health carecost trend rates have an effect on the amounts reported for the OPEB plans.  A one percentage point change in assumedhealth care cost trend rates would have the following effects:

 
| (US$ millions)                           | ** ** | One Percentage Point  Increase |   | One Percentage Point  Decrease |   |
|-----------------------------------------------|------------|--------------------------------|--------|--------------------------------|--------|
|                                          | ** ** |                           |   |                           |   |
| Effect on Post-Retirement Benefit  Obligation | ** ** | 1                              |   | (1                             | )      |

 

The Company’spension plan asset allocations are as follows:

 
|                  |   | Normal |       | Range      | ** ** | **As at  December 31,  2009** |   | As at  December 31,  2008 |   | Rate of  Return |   |
|-----------------------|--------|--------|------------|------------|------------|------------------------------------|--------|--------------------------------|--------|-----------------|--------|
|                  |   |   | ** ** |       |       |                               |   |                           |   |            |   |
| Domestic Equity       |   | 35     |       | 25-45      | ** ** | **39**                             |   | 34                             |   |            |   |
| Foreign Equity        |   | 30     |       | 20-40      | ** ** | **23**                             |   | 25                             |   |            |   |
| Bonds                 |   | 30     |       | 20-40      | ** ** | **29**                             |   | 33                             |   |            |   |
| Real Estate and Other |   | 5      |       | 0-20       | ** ** | **9**                              |   | 8                              |   |            |   |
| Total                 |   | 100    |       | ** ** | ** ** | **100**                            |   | 100                            |   | 6.75%           |   |

 

The expected rate ofreturn on plan assets is based on historical and projected rates of return foreach asset class in the plan investment portfolio. The objective of the assetallocation policy is to manage the funded status of the plan at an appropriatelevel of risk, giving consideration to the security of the assets and thepotential volatility of market returns and the resulting effect on bothcontribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from acomposite benchmark comprised of passive investments in appropriate marketindices. The Supplemental Pension Plan is funded through a retirementcompensation arrangement and is subject to the applicable Canada Revenue Agencyregulations.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**17.  COMPENSATION PLANS(continued)**

 

The asset allocationstructure is subject to diversification requirements and constraints whichreduce risk by limiting exposure to individual equity investment, credit ratingcategories and foreign currency exposure.

 

The Company’scontributions to the pension plans are subject to the results of the actuarialvaluation and direction by the Human Resources and Compensation Committee ofthe Board.

 

Estimated futurepayment of pension and other benefits are as follows:

 
| (US$ millions) |   | Pension Benefits |   | OPEB   |   |
|---------------------|--------|------------------|--------|--------|--------|
|                |   |             |   |   |   |
| 2010                |   | 1                |   | -      |   |
| 2011                |   | 1                |   | -      |   |
| 2012                |   | 2                |   | -      |   |
| 2013                |   | 2                |   | 1      |   |
| 2014                |   | 3                |   | 1      |   |
| 2015 – 2019    |   | 20               |   | 6      |   |
| Total               |   | 29               |   | 8      |   |

 

 

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT**

 

Cenovus’s consolidated financial assets and liabilities arecomprised of cash and cash equivalents, accounts receivable and accruedrevenues, accounts payable and accrued liabilities, the PartnershipContribution Receivable and Payable, risk management assets and liabilities,and long-term debt. Risk management assets and liabilities arise from the useof derivative financial instruments. Fair values of financial assets andliabilities, summarized information related to risk management positions, anddiscussion of risks associated with financial assets and liabilities arepresented as follows.  The informationcontained within Note 18 is based on carve-out information for the periodsprior to December 1, 2009.

 

**A) Fair Value of FinancialAssets and Liabilities**

 

The fair values of cash and cash equivalents, accountsreceivable and accrued revenues, and accounts payable and accrued liabilitiesapproximate their carrying amount due to the short-term maturity of thoseinstruments.

 

The fair values of the Partnership Contribution Receivableand Partnership Contribution Payable approximate their carrying amount due tothe specific non-tradeable nature of these instruments in relation to thecreation of the integrated oil business venture.

 

Risk management assets and liabilities are recorded at theirestimated fair value based on mark-to-market accounting, using quoted marketprices or, in their absence, third-party market indications and forecasts.

 

Long-term debt is carried at amortized cost.  The estimated fair values of long-termborrowings have been determined based on market information.

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)**

 

The fair value of financial assets and liabilities,including current portions thereof were as follows:

 
| As at December 31, (US$ millions)    |       | **   2009** |       |       |    2008 |   |
|-------------------------------------------|------------|----------------------------|------------|------------|------------------------|--------|
| ** **                                | ** ** | **Carrying**               | ** ** | **Fair**   |                   |   | Carrying |   | Fair |   |
| ** **                                | ** ** | **Amount**                 | ** ** | **Value**  |                   |   | Amount |   | Value |   |
| Financial Assets                          | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Held-for-trading:                         | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Cash and cash equivalents                 | ** ** | **148**                    | ** ** | **148**    |                   |   | 153 |   | 153 |   |
| Risk management assets                    | ** ** | **59**                     | ** ** | **59**     |                   |   | 719 |   | 719 |   |
| Loans and Receivables:                    | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Accounts receivable and accrued  revenues | ** ** | **874**                    | ** ** | **874**    |                   |   | 598 |   | 598 |   |
| Partnership Contribution Receivable       | ** ** | **2,834**                  | ** ** | **2,834**  |                   |   | 3,147 |   | 3,147 |   |
| Financial Liabilities                     | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Held-for-trading:                         | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Risk management liabilities               | ** ** | **71**                     | ** ** | **71**     |                   |   | 40 |   | 40 |   |
| Other Financial Liabilities:              | ** ** | ** **                 | ** ** | ** ** |                   |   |   |   |   |   |
| Accounts payable and accrued  liabilities | ** ** | **1,444**                  | ** ** | **1,444**  |                   |   | 1,114 |   | 1,114 |   |
| Long-term debt                            | ** ** | **3,493**                  | ** ** | **3,788**  |                   |   | 3,036 |   | 3,036 |   |
| Partnership Contribution Payable          | ** ** | **2,857**                  | ** ** | **2,857**  |                   |   | 3,163 |   | 3,163 |   |

 

**B) Risk Management Assets andLiabilities**

 

Under the terms of the Arrangementwith EnCana, the risk management positions at November 30, 2009 were allocatedto Cenovus based upon Cenovus’s proportion of the related volumes covered bythe contracts. To effect the allocation, Cenovus entered into a contract withEnCana ****with thesame terms and conditions as between EnCana and the third parties to the existingcontracts. All positions entered into after the Arrangement have beennegotiated between Cenovus and third parties.****

 

**Net Risk Management Position**

 
| As at December 31, (US$ millions) | ** ** | **2009**     |   | 2008   |   |
|---------------------------------------------|------------|--------------|--------|--------|--------|
|                                        | ** ** |         |   |   |   |
| Risk Management                             |       |         |   |   |   |
| Current asset                               | ** ** | ** 58** |   | 681    |   |
| Long-term asset                             | ** ** | **1**        |   | 38     |   |
|                                        | ** ** | **59**       |   | 719    |   |
| Risk Management                             | ** ** |         |   |   |   |
| Current liability                           | ** ** | **67**       |   | 40     |   |
| Long-term liability                         | ** ** | **4**        |   | -      |   |
|                                        | ** ** | **71**       |   | 40     |   |
| Net Risk Management Asset  (Liability)      | ** ** | **(12**      | **)**  | 679    |   |

 

Of the $12 million net risk management liability balance at December 31,2009, a liability of $14 million relates to the contract with EnCana.

 

**Summary of Unrealized Risk ManagementPositions**

 
| As at December 31, (US$ millions) | ** ** | **   2009**            |       |          | 2008            |                      |
|----------------------------------------|------------|---------------------------------------|------------|---------------|-----------------|---------------------------|
| ** **                             | ** ** | **   Risk Management** |       |          | Risk Management |                      |
| ** **                             | ** ** | **Asset**                             | ** ** | **Liability** |            | **Net   ** |   |   | Asset**** |   | Liability |   | Net |   |
|                                   | ** ** | ** **                            |       |          |            |                      |   |   |   |   |   |   |   |   |
| Commodity Prices                       |       |                                  |       |          |            |                      |   |   |   |   |   |   |   |   |
| Natural Gas                            | ** ** | **51**                                | ** ** | **-**         | ** **      | ** 51**              |   |   | 618 |   | - |   | 618 |   |
| Crude Oil                              | ** ** | **8**                                 | ** ** | **63**        | ** **      | **(55**                   | **)** |   | 92 |   | 40 |   | 52 |   |
| Power                                  | ** ** | **-**                                 | ** ** | **8**         | ** **      | ** (8**              | **)** |   | 9 |   | - |   | 9 |   |
| Total Fair Value                       | ** ** | **59**                                | ** ** | **71**        | ** **      | **(12**                   | **)** |   | 719 |   | 40 |   | 679 |   |

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)**

 

**Net Fair Value Methodologies Used toCalculate Unrealized Risk Management********Positions**

 
| As at December 31, (US$ millions)                  | ** ** | **2009  ** |   | 2008   |   |
|--------------------------------------------------------------|------------|----------------------|--------|------------------|--------|
|                                                         | ** ** | ** **           |   |             |   |
| Prices actively quoted                                       | ** ** | **7**                |   | 521              |   |
| Prices sourced from observable data  or market corroboration | ** ** | **(19**              | **)**  | 158              |   |
| Total Fair Value                                             | ** ** | **(12**              | **)**  | 679              |   |

 

Prices actively quoted refers to the fair value of contractsvalued using quoted prices in an active market. Prices sourced from observabledata or market corroboration refers to the fair value of contracts valued inpart using active quotes and in part using observable, market-corroborateddata.

 

**Net Fair Value of Commodity PricePositions at December 31,********2009**

 
|  (US$ millions)       |   | Notional Volumes |   | Term     |       | Average Price | ** ** | **Fair   Value** | ** ** |
|---------------------------------|--------|------------------|--------|------------------------------|------------|---------------|------------|------------------|------------|
|                            |   |             |   |                         |       |          | ** ** | ** **       | ** ** |
| **Crude  Oil Contracts**        |   |             |   |                         |       |          | ** ** | ** **       | ** ** |
| Fixed  Price Contracts          |   |             |   |                         |       |          | ** ** | ** **       | ** ** |
| WTI NYMEX  Fixed Price          |   | 24,600 bbls/d    |   | 2010     |       | 76.99 US$/bbl | ** ** | **(47**          | **)**      |
| Other  Financial Positions *    |   |             |   |                         |       |          | ** ** | **(8**           | **)**      |
| Crude Oil  Fair Value Position  |   |             |   |                         |       |          | ** ** | **(55**          | **)**      |
|                            |   |             |   |                         |       |          | ** ** | ** **       | ** ** |
| **Natural  Gas Contracts**      |   |             |   | ** **                   | ** ** | ** **    | ** ** | ** **       | ** ** |
| Fixed Price Contracts           |   |             |   | ** **                   | ** ** | ** **    | ** ** | ** **       | ** ** |
| NYMEX Fixed Price               |   | 437 MMcf/d  |   | 2010     |       | 6.08 US$/Mcf  | ** ** | **52**           | ** ** |
| NYMEX Fixed Price               |   | 56 MMcf/d   |   | 2011     |       | 6.75 US$/Mcf  | ** ** | **10**           | ** ** |
|                            |   |             |   | ** **                   | ** ** | ** **    | ** ** | ** **       | ** ** |
| Basis Contracts**               |   |             |   | ** **                   | ** ** | ** **    | ** ** | ** **       | ** ** |
| Canada                          |   | 28 MMcf/d   |   | 2010     |       |          | ** ** | **(2**           | **)**      |
| Canada                          |   |             |   | 2011-2013                    |       |          | ** ** | **(9**           | **)**      |
| Natural Gas Fair Value Position |   |             |   |                         |       |          | ** ** | **51**           | ** ** |
|                            |   |             |   |                         |       |          | ** ** | ** **       | ** ** |
| **Power  Purchase Contracts**   |   |             |   | ** **                   | ** ** | ** **    | ** ** | ** **       | ** ** |
| Power Fair Value Position       |   |             |   |                         |       |          | ** ** | **(8**           | **)**      |

 

*  Other financial positions are part of ongoingoperations to market the Company’s production.

**Cenovus hasentered into swaps to protect against widening natural gas price differentialsbetween production areas in Canada and various sales points.  These basis swaps are priced using both fixedprices and basis prices determined as a percentage of NYMEX.

 

**Earnings Impact of Realized and UnrealizedGains (Losses) on Risk********ManagementPositions**

 
|                                                       |       | Realized Gain (Loss) |   |
|------------------------------------------------------------|------------|----------------------|--------|
| For the years ended December 31,  (US$ millions) | ** ** | **2009**             |   | 2008 |   | 2007 |   |
|                                                       | ** ** | ** **           |   |   |   |   |   |
| Revenues, Net of Royalties                                 | ** ** | **1,005**            |   | (323 | ) | 136 |   |
| Operating Expenses and Other                               | ** ** | **(32**              | **)**  | 24 |   | 3 |   |
| Gain (Loss) on Risk Management                             | ** ** | **973**              |   | (299 | ) | 139 |   |

 
|                                                       |       | Unrealized Gain (Loss) |       |
|------------------------------------------------------------|------------|------------------------|------------|
| For the years ended December 31,  (US$ millions) | ** ** | **2009**               |       | 2008 |   | 2007 |   |
|                                                       | ** ** | ** **             | ** ** |   |   |   |   |
| Revenues, Net of Royalties                                 | ** ** | **(639**               | **)**      | 727 |   | (349 | ) |
| Operating Expenses and Other                               | ** ** | **(28**                | **)**      | 7 |   | 1 |   |
| Gain (Loss) on Risk Management                             | ** ** | **(667**               | **)**      | 734 |   | (348 | ) |

 

 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

*All amounts in US$ millions, unless otherwiseindicated*

*For the year ended December 31, 2009*

 

 

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)**

 

**Reconciliation of Unrealized RiskManagement Positions**

 
| For the years ended December 31, (US$ millions)                                                        | ** ** | **  2009** |       |            | 2008   |   |        | 2007   |   |
|-------------------------------------------------------------------------------------------------------------|------------|----------------------|------------|-----------------|--------|--------|-------------|--------|--------|
| ** **                                                                                                  | ** ** | ** **           |       | **Total**       |   |   | Total       |   |   | Total |   |
| ** **                                                                                                  | ** ** | **Fair**             | ** ** | **Unrealized**  |   |   | Unrealized  |   |   | Unrealized |   |
| ** **                                                                                                  | ** ** | **Value**            | ** ** | **Gain (Loss)** |   |   | Gain (Loss) |   |   | Gain (Loss) |   |
|                                                                                                        | ** ** | ** **           |       |            |   |   |        |   |   |   |   |
| Fair Value of Contracts, Beginning of Year                                                                  | ** ** | **653**              |       |            |   |   |        |   |   |   |   |
| Change in Fair Value of Contracts  in Place at Beginning of Year and Contracts Entered into During the Year | ** ** | **306**              | ** ** | **306**         |   |   | 435         |   |   | (215 | ) |
| Other                                                                                                       | ** ** | **-**                | ** ** | **-**           |   |   | -           |   |   | 6 |   |
| Foreign Exchange Gain (Loss) on Canadian Dollar  Contracts                                                  | ** ** | **2**                | ** ** | **-**           |   |   | -           |   |   | - |   |
| Fair Value of Contracts Realized During the Year                                                            | ** ** | **(973**             | **)**      | **(973**        | **)**  |   | 299         |   |   | (139 | ) |
| Fair Value of Contracts, End of Year                                                                        | ** ** | **(12**              | **)**      | **(667**        | **)**  |   | 734         |   |   | (348 | ) |

 

**Commodity Price Sensitivities**

 

The following table summarizes the sensitivity of the fairvalue of Cenovus’s risk management positions to fluctuations in commodityprices, with all other variables held constant. When assessing the potentialimpact of these commodity price changes, Management believes 10 percentvolatility is a reasonable measure. Fluctuations in commodity prices could haveresulted in unrealized gains (losses) impacting net earnings as at December 31,2009 as follows:

 
| ** **          | ** ** | **10% Price** | ** ** | **10% Price** | ** ** |
|---------------------|------------|---------------|------------|---------------|------------|
| (US$ millions) | ** ** | **Increase**  | ** ** | **Decrease**  | ** ** |
| ** **          | ** ** | ** **    | ** ** | ** **    | ** ** | ** ** | ** ** |
| Natural gas price   | ** ** | **(102**      | **)**      | ** **    | **102**    | ** ** | ** ** |
| Crude oil price     | ** ** | **(82**       | **)**      | ** **    | **82**     | ** ** | ** ** |
| Power price         | ** ** | **5**         | ** ** | ** **    | **(5**     | **)** | ** ** |

 

**C) Risks Associated withFinancial Assets and Liabilities**

 

**Commodity Price Risk**

 

Commodity price risk arises from the effect thatfluctuations of future commodity prices may have on the fair value or futurecash flows of financial assets and liabilities. To partially mitigate exposureto commodity price risk, the Company has entered into various financialderivative instruments.  The use of thesederivative instruments is governed under formal policies and is subject tolimits established by the Board of Directors. The Company’s policy is not to use derivative financial instruments forspeculative purposes.

 

Crude Oil – The Company has partially mitigated its exposureto the commodity price risk on its crude oil sales and condensate supply withfixed price swaps.

 

Natural Gas – To partially mitigate the natural gascommodity price risk, the Company has entered into swaps, which fix the NYMEXprices. To help protect against widening natural gas price differentials invarious production areas, Cenovus has entered into swaps to manage the pricedifferentials between these production areas and various sales points.

 

Power – The Company has in place two Canadian dollardenominated derivative contracts, which commenced January 1, 2007 for aperiod of 11 years, to manage its electricity consumption costs.

 

 
| Cenovus Energy Inc. | 40

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|---------------------|------------|

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)**

 

**Credit Risk**

 

Credit risk arises from the potential that the Company mayincur a loss if a counterparty to a financial instrument fails to meet itsobligation in accordance with agreed terms. This credit risk exposure is mitigatedthrough the use of Board-approved credit policies governing the Company’scredit portfolio and with credit practices that limit transactions according tocounterparties’ credit quality. All foreign currency agreements are with majorfinancial institutions in Canada and the United States or with counterpartieshaving investment grade credit ratings. A substantial portion of Cenovus’saccounts receivable are with customers in the oil and gas industry and aresubject to normal industry credit risks.  As at December 31, 2009, over 98 percent(2008–95 percent) of Cenovus’s accounts receivable and financial derivativecredit exposures are with investment grade counterparties.

 

At December 31, 2009, Cenovus had two counterparties(2008–two counterparties) whose net settlement position individually accountfor more than 15 percent of the fair value of the outstanding in-the-money netfinancial and physical contracts by counterparty.  The maximum credit risk exposure associatedwith accounts receivable and accrued revenues, risk management assets and thePartnership Contribution Receivable is the total carrying value. The currentconcentration of this credit risk resides with EnCana and a AAA ratedcounterparty. Cenovus’s exposure to EnCana is expected to reduce substantiallyby the end of the first quarter 2010 as Cenovus begins to market its ownphysical gas to the market. Cenovus’s exposure to its counterparties isacceptable and within Credit Policy tolerances.

 

**Liquidity Risk**

 

Liquidity risk is the risk that Cenovus will not be able tomeet all of its financial obligations as they become due.  Liquidity risk also includes the risk of notbeing able to liquidate assets in a timely manner at a reasonable price.  Cenovus manages its liquidity through theactive management of cash and debt.  Asdisclosed in Note 16, Cenovus targets a Debt to Capitalization ratio between 30and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times tomanage the Company’s overall debt position.

 

Cenovus manages its liquidity risk by ensuring that it hasaccess to multiple sources of capital including:  cash and cash equivalents, cash fromoperating activities and undrawn credit facilities.  At December 31, 2009, Cenovus hadapproximately $2.3 billion in unused credit capacity available on its committedbank credit facility.

 

It is Cenovus’s intention to maintain investment gradecredit ratings on its senior unsecured debt. DBRS Limited (“DBRS”) has assigned a rating of A (low) with a “Stable”outlook, Standard and Poor’s Corporation has assigned a rating of BBB+ with a “Stable”outlook and Moody’s Investors Service Inc. has assigned a rating of Baa2 with a“Stable” outlook.

 

Cash outflows relating to financial liabilities are outlinedin the table below:

** **
| (US$ millions)                      | ** ** | Less than  1 Year        |   | 1 - 3 Years |   | 4 - 5 Years |   | Thereafter  |       | **Total** |       |
|------------------------------------------|------------|-------------------------------|--------|------------------|--------|------------------|--------|-------------|------------|-----------|------------|
| Accounts Payable and Accrued Liabilities |       | 1,444     |   | -                |   | -           |   | -      | ** ** | **1,444** | ** ** |
| Risk Management Liabilities              |       | 67        |   | 4                |   | -           |   | -      | ** ** | **71**    | ** ** |
| Long-Term Debt*                          |       | 227       |   | 468              |   | 1,209       |   | 5,433  | ** ** | **7,337** | ** ** |
| Partnership Contribution Payable*        |       | 489       |   | 978              |   | 978         |   | 1,099  | ** ** | **3,544** | ** ** |

 

*          Principal and interest, includingcurrent portion.

 

 
| Cenovus Energy Inc. | 41 |
|---------------------|----|

 

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** **

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

** **

** **

**18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)**

 

Included in Cenovus’s long-termdebt obligations of $3,493 million at December 31, 2009, are $56 millionin principal obligations related to prime rate and LIBOR based loans.  These amounts are fully supported by theCompany’s revolving syndicated credit facility, which have no repaymentrequirements within the next year.  Alloutstanding amounts related to the prime rate and LIBOR based loans were drawnon the 3-year tranche of the revolving syndicated credit facility.  Based on the current maturity dates of the3-year tranche, these amounts are included in cash outflows for the perioddisclosed as “1-3 Years.”   Furtherinformation on Long-Term Debt is included in Note 13.

 

**Foreign Exchange Risk**

 

Foreign exchange risk arises from changes in foreignexchange rates that may affect the fair value or future cash flows of Cenovus’sfinancial assets or liabilities. As Cenovus operates in North America,fluctuations in the exchange rate between the U.S./Canadian dollar can have asignificant effect on reported results. Cenovus’s functional currency isCanadian dollars; however, the Company reports its results in U.S. dollars,unless otherwise indicated.  As theeffects of foreign exchange fluctuations are embedded in the Company’s results,the total effect of foreign exchange fluctuations is not separatelyidentifiable.

 

As disclosed in Note 7, Cenovus’s foreign exchange (gain)loss primarily includes unrealized foreign exchange gains and losses on thetranslation of the U.S. dollar debt issued from Canada and the translation ofthe U.S. dollar Partnership Contribution Receivable issued from Canada.  At December 31, 2009, Cenovus had $3,525million in U.S. dollar debt issued from Canada ($1,804 million at December 31,2008) and $2,834 million related to the U.S. dollar Partnership ContributionReceivable ($3,147 million at December 31, 2008).  A $0.01 change in the U.S. to Canadian dollarexchange rate would have resulted in a $7 million change in foreign exchange(gain) loss at December 31, 2009 (2008-$11 million).

 

**Interest Rate Risk**

 

Interest rate risk arises from changes in market interestrates that may affect the earnings, cash flows and valuations.  Cenovus has the flexibility to partiallymitigate its exposure to interest rate changes by maintaining a mix of bothfixed and floating rate debt.

 

At December 31,2009, the majority of the Company’s debt is fixed-rate debt and as a result,the increase or decrease in net earnings for each one percent change ininterest rates on floating rate debt amounts to nil (December 31, 2008–$4million; 2007–$5 million).

 

 

**19. SUPPLEMENTARY INFORMATION**

 

**A) Per Share Amounts**

 
| For the years ended  December 31, (millions)         |       | **2009**   |   | 2008   |   | 2007   |   |
|-----------------------------------------------------------|------------|------------|--------|--------|--------|--------|--------|
|                                                      | ** ** | ** ** |   |   |   |   |   |
| Weighted Average Common Shares Outstanding – Basic   | ** ** | **751.0**  |   | 750.1  |   | 756.8  |   |
| Effect of Stock Options and Other Dilutive Securities     | ** ** | **0.4**    |   | 1.7    |   | 7.8    |   |
| Weighted Average Common Shares Outstanding – Diluted | ** ** | **751.4**  |   | 751.8  |   | 764.6  |   |

 

Since Cenovus’s shares were issued pursuant to theArrangement, the per share amounts disclosed above are based on EnCana’s commonshares.

 

 
| Cenovus Energy Inc. | 42 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**19. SUPPLEMENTARY INFORMATION (continued)**

 

**B) Supplementary Cash FlowInformation**

 
| For the years ended  December 31, (US$ millions) |       | **2009**   |   | 2008   |   | 2007            |   |
|-------------------------------------------------------|------------|------------|--------|--------|--------|-----------------|--------|
|                                                  | ** ** | ** ** |   |   |   |            |   |
|   Interest Paid                                  | ** ** | **376**    |   | 395    |   | 408   |   |
|   Income Taxes Paid                              | ** ** | **1,145**  |   | 508    |   | 536   |   |

 

Income taxes paid in 2009 includes amounts paid to EnCana asa result of the dissolution of a partnership as part of the Arrangement.

 

 

**20. COMMITMENTS AND CONTINGENCIES**

 

**Commitments**

 

As part of normal operations, the Company has committed tocertain amounts over the next five years and thereafter as follows:

 
| (US$ millions)                |   | 2010   |   | 2011      |   | 2012      |   | 2013   |   | 2014   |   | Thereafter |   | Total  |   |
|------------------------------------|--------|--------|--------|-----------|--------|-----------|--------|--------|--------|--------|--------|------------|--------|--------|--------|
|                               |   |   |   |      |   |      |   |   |   |   |   |       |   |   |   |
| Operating Leases (Building Leases) |   | 26     |   | 27   |   | 34   |   | 72     |   | 76     |   | 1,575      |   | 1,810  |   |
| Pipeline Transportation            |   | 101    |   | 95   |   | 68   |   | 141    |   | 141    |   | 923        |   | 1,469  |   |
| Purchases of Goods and Services    |   | 98     |   | 9    |   | 4    |   | 3      |   | -      |   | -          |   | 114    |   |
| Capital Commitments                |   | 105    |   | 85   |   | 33   |   | -      |   | -      |   | -          |   | 223    |   |
| Product Purchases                  |   | 26     |   | 23   |   | 22   |   | 22     |   | 22     |   | 28         |   | 143    |   |
| Total Payments                     |   | 356    |   | 239  |   | 161  |   | 238    |   | 239    |   | 2,526      |   | 3,759  |   |
| Product Sales                      |   | 46     |   | 48   |   | 52   |   | 53     |   | 55     |   | 119        |   | 373    |   |

 

In addition to the above, Cenovus’s share of commitmentsrelated to its risk management program are disclosed in Note 18.

 

**Contingencies**

 

**Legal Proceedings**

 

Cenovus is involved in various legal claims associated withthe normal course of operations. Cenovus believes it has made adequateprovisions for such legal claims.

 

 
| Cenovus Energy Inc. | 43 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**20. COMMITMENTS AND CONTINGENCIES (continued)**

 

**Asset Retirement**

 

Cenovus is responsible for the retirement of long-livedassets related to its oil and gas properties, refining facilities and Midstreamfacilities at the end of their useful lives. Cenovus has recognized a liabilityof $1,096 million based on current legislation and estimated costs. Actualcosts may differ from those estimated due to changes in legislation and changesin costs.

 

**Income Tax Matters**

 

The tax interpretations, regulations and legislation in thevarious jurisdictions that Cenovus operates in are continually changing. As aresult, there are usually some tax matters under review. Management believesthat the provision for taxes is adequate.

 

 

**21.  UNITEDSTATES ACCOUNTING PRINCIPLES AND REPORTING**

 

The Cenovus Consolidated Financial Statements have beenprepared in accordance with accounting principles generally accepted in Canada(“Canadian GAAP”) which, in most respects, conform to accounting principlesgenerally accepted in the United States (“U.S. GAAP”). The significantdifferences between Canadian GAAP and U.S. GAAP are described in thisnote.  The most notable differences are:

 

·                  full cost accounting;

·                  pensions and otherpost-employment benefits;

·                  liability-basedstock compensation plans;

·                  income taxes;

·                  other comprehensiveincome;

·                  joint ventureaccounting; and

·                  inventories.

 

 

**RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAPTO U.S. GAAP**

 
| For the years ended  December 31, (US$ millions) |       | Note 21    | ** ** | **2009**   |   | 2008      |   | 2007   |   |
|------------------------------------------------------------|------------|------------|------------|------------|--------|-----------|--------|--------|--------|
|                                                       | ** ** | ** ** |       | ** ** |   |      |   |   |   |
| Net Earnings–Canadian GAAP                            | ** ** | ** ** |       | **648**    |   | 2,368     |   | 1,404  |   |
| Increase (Decrease) in Net Earnings Under U.S. GAAP:       |       |       |       | ** ** |   |      |   |   |   |
| Revenues, net of royalties                                 | ** ** | ** ** |       | **-**      |   | -         |   | (5     | )      |
| Expenses                                                   | ** ** | ** ** |       | ** ** |   |      |   |   |   |
|    Operating                                     | * *   | *C ii)*    | ** ** | **4**      |   | (12       | )      | 1      |   |
|    Depreciation, depletion and  amortization     | * *   | *A, C ii)* | ** ** | **209**    |   | 29        |   | 148    |   |
|    General and administrative                    | * *   | *C ii)*    | ** ** | **8**      |   | (14       | )      | 1      |   |
|    Stock-based compensation–options         | ** ** | ** ** |       | **-**      |   | 1         |   | (3     | )      |
|    Income tax expense                            |       | D          | ** ** | **(184**   | **)**  | (32       | )      | (87    | )      |
| Net Earnings–U.S. GAAP                                | ** ** | ** ** |       | **685**    |   | **2,340** |   | 1,459  |   |

 

 
| Cenovus Energy Inc. | 44 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**CONSOLIDATED STATEMENT OF EARNINGS ANDCOMPREHENSIVE INCOME – U.S. GAAP**

 
| For the years ended  December 31, (US$ millions) |     | Note 21    |       | **2009**   |       | 2008   |   | 2007   |   |
|------------------------------------------------------------|----------|------------|------------|------------|------------|--------|--------|--------|--------|
|                                                       | * * | * *   | ** ** | ** ** |       |   |   |   |   |
| Revenues, Net of Royalties                                 |     |       | ** ** | **10,140** | ** ** | 16,559 |   | 13,401 |   |
| Expenses                                                   |     |       |       | ** ** | ** ** |   |   |   |   |
| Production and mineral taxes                               |     |       | ** ** | **38**     | ** ** | 75     |   | 63     |   |
| Transportation and selling                                 |     |       | ** ** | **672**    | ** ** | 963    |   | 756    |   |
| Operating                                                  | * * | *C ii)*    | ** ** | **1,150**  | ** ** | 1,235  |   | 1,113  |   |
| Purchased product                                          |     |       | ** ** | **5,250**  | ** ** | 9,710  |   | 7,476  |   |
| Depreciation, depletion and amortization                   | * * | *A, C ii)* | ** ** | **1,134**  | ** ** | 1,289  |   | 1,278  |   |
| General and Administrative                                 | * * | *C ii)*    | ** ** | **180**    | ** ** | 181    |   | 144    |   |
| Interest, net                                              |     |       | ** ** | **218**    | ** ** | 218    |   | 187    |   |
| Accretion of asset retirement obligation                   |     |       | ** ** | **39**     | ** ** | 39     |   | 28     |   |
| Foreign exchange (gain) loss, net                          |     |       | ** ** | **290**    | ** ** | (250   | )      | 380    |   |
| Stock-based compensation–options                      |     |       | ** ** | **-**      | ** ** | (1     | )      | 3      |   |
| Other (gain) loss, net                                     |     |       | ** ** | **(2**     | **)**      | 3      |   | 4      |   |
| Earnings Before Income Tax                                 |     |       | ** ** | **1,171**  | ** ** | 3,097  |   | 1,969  |   |
| Income tax expense                                         |     | D          | ** ** | **486**    | ** ** | 757    |   | 510    |   |
| Net Earnings–U.S. GAAP                                |     |       | ** ** | **685**    | ** ** | 2,340  |   | 1,459  |   |
|                                                       |     |       | ** ** | ** ** | ** ** |   |   |   |   |
| Other Comprehensive Income, Net of Tax                     |     |       | ** ** | ** ** | ** ** |   |   |   |   |
| Foreign Currency  Translation Adjustment                   |     |       | ** ** | **1,872**  | ** ** | (2,075 | )      | 1,133  |   |
| Compensation Plans                                         |     |       | ** ** | **31**     | ** ** | (8     | )      | -      |   |
| Comprehensive Income                                       |     |       | ** ** | **2,588**  | ** ** | 257    |   | 2,592  |   |

 

**CONDENSED CONSOLIDATED BALANCE SHEET – U.S. GAAP**

 
|                                                                                                                                   |       |             |       | ** 2009** |       | 2008          |       |
|----------------------------------------------------------------------------------------------------------------------------------------|------------|------------------|------------|----------------|------------|---------------|------------|
| As at  December 31, (US$ millions)                                                                                           |       | Note 21          |       | **As Reporte** | **d**      | **U.S. GAAP** |       | As Reported |   | U.S. GAAP |   |
| ** **                                                                                                                             | ** ** | ** **       | ** ** | ** **     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Assets                                                                                                                                 |       |             | ** ** | ** **     | ** ** | ** **    |       |   |   |   |   |
| Current Assets                                                                                                                         | * *   | *G*              | ** ** | **2,284**      | ** ** | **2,284**     |       | 2,248 |   | 2,248 |   |
| Property, Plant and Equipment                                                                                                          | * *   | *A, C ii)*       |       |           |       |          |       |   |   |   |   |
| (includes unproved properties and major  development projects of $1,921 and $715 as of December 31, 2009 and  2008, respectively) |       |             | ** ** | **26,255**     | ** ** | **26,237**    |       | 21,175 |   | 21,182 |   |
| Accumulated Depreciation, Depletion and Amortization                                                                                   |       |             | ** ** | **(11,718**    | **)**      | **(12,523**   | **)**      | (8,915 | ) | (9,798 | ) |
| Property, Plant and Equipment, net                                                                                                     |       |             | ** ** | **14,537**     | ** ** | **13,714**    |       | 12,260 |   | 11,384 |   |
| (Full Cost Method for Oil and Gas Activities)                                                                                          |       |             |       |           |       |          |       |   |   |   |   |
| Other Assets                                                                                                                           | * *   | *C i)*           | ** ** | **131**        | ** ** | **138**       |       | 150 |   | 133 |   |
| Partnership Contribution Receivable                                                                                                    |       |             | ** ** | **2,504**      | ** ** | **2,504**     |       | 2,834 |   | 2,834 |   |
| Risk Management                                                                                                                        |       |             | ** ** | **1**          | ** ** | **1**         |       | 38 |   | 38 |   |
| Goodwill                                                                                                                               |       |             | ** ** | **1,095**      | ** ** | **1,095**     |       | 936 |   | 936 |   |
|                                                                                                                                   |       |             | ** ** | **20,552**     | ** ** | **19,736**    |       | 18,466 |   | 17,573 |   |
| Liabilities and Net Investment                                                                                                         | ** ** | ** **       | ** ** | ** **     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current Liabilities                                                                                                                    | * *   | *C i), C ii), D* | ** ** | **1,836**      | ** ** | **1,937**     |       | 1,798 |   | 1,918 |   |
| Long-Term Debt                                                                                                                         |       |             | ** ** | **3,493**      | ** ** | **3,493**     |       | 2,952 |   | 2,952 |   |
| Other Liabilities                                                                                                                      | * *   | *C i), C ii)*    | ** ** | **54**         | ** ** | **55**        |       | 52 |   | 65 |   |
| Partnership Contribution Payable                                                                                                       |       |             | ** ** | **2,532**      | ** ** | **2,532**     |       | 2,857 |   | 2,857 |   |
| Risk Management                                                                                                                        |       |             | ** ** | **4**          | ** ** | **4**         |       | - |   | - |   |
| Asset Retirement Obligation                                                                                                            |       |             | ** ** | **1,096**      | ** ** | **1,096**     |       | 648 |   | 648 |   |
| Deferred Income Taxes                                                                                                                  |       | D                | ** ** | **2,357**      | ** ** | **2,187**     |       | 2,411 |   | 2,093 |   |
|                                                                                                                                   |       |             | ** ** | **11,372**     | ** ** | **11,304**    |       | 10,718 |   | 10,533 |   |
| Shareholders’ Equity                                                                                                              | * *   | *E*              | ** ** | **9,180**      | ** ** | **8,432**     |       | 7,748 |   | 7,040 |   |
|                                                                                                                                   |       |             | ** ** | **20,552**     | ** ** | **19,736**    |       | 18,466 |   | 17,573 |   |

 

 
| Cenovus Energy Inc. | 45 |
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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS –U.S. GAAP**

 
| For the years ended  December 31, (US$ millions) |       | **2009**   |   | 2008   |   | 2007   |   |
|------------------------------------------------------------|------------|------------|--------|--------|--------|--------|--------|
| ** **                                                 | ** ** | ** ** |   |   |   |   |   |
| Operating Activities                                       |       |       |   |   |   |   |   |
| Net earnings                                               | ** ** | **685**    |   | 2,340  |   | 1,459  |   |
| Depreciation, depletion and amortization                   | ** ** | **1,134**  |   | 1,289  |   | 1,278  |   |
| Deferred income taxes                                      | ** ** | **(371**   | **)**  | 416    |   | (168   | )      |
| Unrealized (gain) loss on risk management                  | ** ** | **667**    |   | (734   | )      | 353    |   |
| Unrealized foreign exchange (gain) loss                    | ** ** | **313**    |   | (259   | )      | 383    |   |
| Accretion of asset retirement obligation                   | ** ** | **39**     |   | 39     |   | 28     |   |
| Other (income) loss, net                                   | ** ** | **1**      |   | (2     | )      | 124    |   |
| Net change in other assets and liabilities                 | ** ** | **(23**    | **)**  | (89    | )      | (48    | )      |
| Net change in non-cash working capital                     | ** ** | **1,051**  |   | (316   | )      | (417   | )      |
| Cash From Operating Activities                             | ** ** | **3,496**  |   | 2,684  |   | 2,992  |   |
| Cash (Used in) Investing Activities                        | ** ** | **(1,780** | **)**  | (1,964 | )      | (1,533 | )      |
| Net Cash Provided before Financing  Activities             | ** ** | **1,716**  |   | 720    |   | 1,459  |   |
| Cash From (Used in) Financing Activities                   | ** ** | **(1,730** | **)**  | (849   | )      | (1,270 | )      |

 

**Notes:**

 

**A) Full Cost Accounting**

 

Under U.S. GAAP, a ceiling test is applied to ensurethe unamortized capitalized costs in each cost centre do not exceed the sum,net of applicable income taxes, of the present value, discounted at10 percent, of the estimated future net revenues calculated on the basisof estimated value of future production from proved reserves using oil and gasprices at the balance sheet date, less related unescalated estimated futuredevelopment and production costs, plus unimpaired unproved property costs. For2009, depletion charges under U.S. GAAP were also calculated by reference toproved reserves estimated using an average price for the prior 12-monthperiod.  For 2008 and 2007, depletioncharges under U.S. GAAP were calculated by reference to proved reservesestimated using oil and gas prices at the balance sheet date.

 

Under Canadian GAAP, a similar ceiling test calculation isperformed with the exception that cash flows from proved reserves areundiscounted and utilize forecast pricing and future development and productioncosts to determine whether impairment exists. The impairment amount is measuredusing the fair value of proved and probable reserves. Depletion charges underCanadian GAAP are also calculated by reference to proved reserves estimatedusing estimated future prices and costs.

 

At December 31, 2008, Cenovus’s capitalized costs ofoil and gas properties in Canada exceeded the full cost ceiling resulting in anon-cash U.S. GAAP write-down of $60 million charged to DD&A(2007–nil). Additional depletion was also recorded in 2006, and certain prioryears, as a result of the ceiling test difference between Canadian GAAP andU.S. GAAP. As a result, the depletion base of unamortized capitalizedcosts is less for U.S. GAAP purposes.

 

The U.S. GAAP adjustment for the difference indepletion calculations results in an impact to DD&A charges and foreigncurrency translation adjustment of $207.8 million decrease and$13.9 million increase respectively (2008–$92.4 million decrease and$8.5 million decrease; 2007–$147.8 million decrease and$8.9 million increase).

 

 
| Cenovus Energy Inc. | 46 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**21.  UNITEDSTATES ACCOUNTING PRINCIPLES AND REPORTING (continued)**

 

**B) Property, Plant and EquipmentAllocation**

 

Net property, plant and equipmentrelated to Canadian upstream oil and gas activities have been allocated forU.S. GAAP carve-out purposes using the same methodology as the carve-outallocation for Canadian GAAP purposes.

 

The balances related to Canadianupstream operations have been allocated between Cenovus and EnCana inaccordance with the CICA Handbook Accounting Guideline ACG-16, based on theratio of future net revenue, discounted at 10 percent, of the properties carvedout to the discounted future net revenue of all proved properties in Canadausing the reserve reports dated December 31, 2008 and December 31,2007.  Future net revenue is theestimated net amount to be received with respect to development and productionof crude oil and natural gas reserves, the value of which has been determinedby independent reserve evaluators.

 

**C) Compensation Plans**

 

i) Pensions and Other Post-Employment Benefits

 

Under U.S. GAAP, ASC 715-30, *“Compensation*– *Retirement Benefits*”, requires Cenovusto recognize the over-funded orunder-funded status of defined benefit and post-employment plans on the balancesheet as an asset or liability and to recognize changes in the funded statusthrough Other Comprehensive Income. Canadian GAAP does not require Cenovus torecognize the funded status of these plans on its balance sheet.

 

ii) Liability-Based Stock Compensation Plans

 

Under Canadian GAAP, obligations for liability-based stock compensationplans are recorded using the intrinsic-value method of accounting. ForU.S. GAAP purposes, Cenovus adopted ASC 718, *“Compensation– Stock Compensation*” for the year ended December 31, 2006using the modified-prospective approach. Under ASC 718, liability-based stockcompensation plans, including tandem share appreciation rights, performancetandem share appreciation rights, share appreciation rights, performance shareappreciation rights and deferred share units, are required to be re-measured atfair value at each reporting period up until the settlement date.

 

To the extent compensation cost relates to employeesdirectly involved in crude oil and natural gas development activities, certainamounts are capitalized to property, plant and equipment. Amounts notcapitalized are recognized as administrative expenses or operating expenses.The current period adjustments have the following impact:

 

·   Net property, plant and equipment decreased by$24.2 million (2008–$14.6 million increase)

·   Current liabilities decreased by $39.5 million (2008–$41.4 millionincrease)

·   Other liabilities increased by $1.6 million (2008–$0.2 milliondecrease)

·   Other comprehensive income–nil (2008–$3.0 millionincrease)

·   Operating expenses decreased by $3.8 million (2008–$11.6 millionincrease)

·   Administrative expenses decreased by $7.9 million (2008–$14.5 millionincrease)

·   Depreciation, depletion and amortization expenses decreasedby $1.6 million (2008–$3.8 million increase)

 

 
| Cenovus Energy Inc. | 47 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**21.  UNITEDSTATES ACCOUNTING PRINCIPLES AND REPORTING (continued)**

 

**D) Income Taxes**

 

U.S. GAAP uses enacted tax rates and legislativechanges to calculate current and deferred income taxes, whereas Canadian GAAPuses substantively enacted tax rates and legislative changes. In 2007, aCanadian tax legislative change was substantively enacted for Canadian GAAP;however, this tax legislative change was not considered enacted forU.S. GAAP by December 31, 2007 and 2008. This tax legislative change isstill not considered enacted. Accordingly, there was no difference in 2009(2008–nil; 2007–increase to income tax expense of $76 million) forU.S. GAAP.

 

The remaining differences resulted from the deferred incometax adjustments included in the Reconciliation of Net Earnings under CanadianGAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include theeffect of such rate differences, if any, as well as the tax effect of the otherreconciling items noted.

 

In 2009, Cenovus incurred losses in one of its subsidiarycompany which were recognized and included in calculating future income taxesfor Canadian GAAP purposes on the basis that the tax legislative changes notedabove were substantially enacted. For U.S. GAAP, these losses can not be recognizedas the tax legislative changes have not been enacted by December 31, 2009.The income tax expense has been increased by $124.0 million (2008 and 2007–nil)to record the difference between Canadian and U.S. GAAP.

 

The following table provides a reconciliation of thestatutory rate to the actual tax rate:

 
| For the years Ended  December 31, (US$ millions)   |       | **2009**   |   | 2008   |   | 2007   |   |
|--------------------------------------------------------------|------------|------------|--------|--------|--------|--------|--------|
|                                                         | ** ** | ** ** |   |   |   |   |   |
| Net Earnings Before Income Tax–U.S. GAAP                | ** ** | **1,171**  |   | 3,097  |   | 1,969  |   |
| Canadian Statutory Rate                                      | ** ** | **29.2**   | **%**  | 29.7   | %      | 32.3   | %      |
| Expected Income Tax                                          | ** ** | **342**    |   | 919    |   | 636    |   |
| Effect on Taxes Resulting from:                              |       |       |   |   |   |   |   |
| Statutory and other rate differences                         | ** ** | **(9**     | **)**  | (79    | )      | 17     |   |
| Effect of tax rate changes                                   | ** ** | **-**      |   | -      |   | (147   | )      |
| Non-taxable downstream partnership income                    | ** ** | **6**      |   | 6      |   | (70    | )      |
| International financing                                      | ** ** | **(118**   | **)**  | (127   | )      | -      |   |
| Foreign exchange (gains) losses not included in net earnings | ** ** | **67**     |   | 11     |   | -      |   |
| Non-taxable capital (gains) losses                           | ** ** | **11**     |   | (50    | )      | 45     |   |
| Unrecognized non-capital losses                              | ** ** | **124**    |   | -      |   | -      |   |
| Other                                                        | ** ** | **63**     |   | 77     |   | 29     |   |
| Income Tax–U.S. GAAP                                    | ** ** | **486**    |   | 757    |   | 510    |   |
| Effective Tax Rate                                           | ** ** | **41.5**   | **%**  | 24.4   | %      | 25.9   | %      |

 

The net deferred income tax liability is comprised of:

 
| As at  December 31, (US$ millions)          |       | **2009**   | ** ** | 2008   |   |
|-------------------------------------------------------|------------|------------|------------|--------|--------|
|                                                  | ** ** | ** ** | ** ** |   |   |
| Deferred Tax Liabilities                              |       | ** ** | ** ** |   |   |
| Property, plant and equipment in excess of tax values | ** ** | **2,224**  | ** ** | 1,737  |   |
| Timing of partnership items                           | ** ** | **9**      | ** ** | 470    |   |
| Risk management                                       | ** ** | **16**     | ** ** | -      |   |
| Other                                                 | ** ** | **75**     | ** ** | 185    |   |
| Deferred Tax Assets                                   |       | ** ** | ** ** |   |   |
| Non-capital and net operating losses carried forward  | ** ** | **(106**   | **)**      | (19    | )      |
| Other                                                 | ** ** | **(31**    | **)**      | (280   | )      |
| Net Deferred Income Tax Liability                     | ** ** | **2,187**  | ** ** | 2,093  |   |

 

 
| Cenovus Energy Inc. | 48 |
|---------------------|----|

 

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NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

 

 

**21.  UNITEDSTATES ACCOUNTING PRINCIPLES AND REPORTING (continued)**

 

**E) Other Comprehensive Income**

 

ASC 715-30 requires a change in the funded status of definedbenefit and post-employment plans to be recognized on the balance sheet andchanges in the funded status through comprehensive income. In 2009, a gain of$30.9 million, net of tax was recognized in other comprehensive income(2008–loss of $7.5 million) as noted in D i). On adoption of ASC 715-30, asrequired, the transitional amount of $12 million, net of tax was bookeddirectly to Accumulated Other Comprehensive Income.

 

The foreign currency translation adjustment includes theeffect of the accumulated U.S. GAAP differences.

 

**F) Joint Venture withConocoPhillips**

 

Under Canadian GAAP, the Integrated Oil operations that arejointly controlled are proportionately consolidated. U.S. GAAP requiresthe Downstream Refining operations included in the Integrated Oil Division beaccounted for using the equity method. However, under an accommodation of theU.S. Securities and Exchange Commission, accounting for jointly controlledinvestments does not require reconciliation from Canadian to U.S. GAAP ifthe joint venture is jointly controlled by all parties having an equityinterest in the entity, which is the case for the Downstream Refiningoperations. Equity accounting for the Downstream Refining operations would haveno impact on Cenovus’s net earnings or retained earnings. As required, thefollowing disclosures are provided for the Downstream Refining operations ofthe joint venture.

 
| Consolidated  Statement of Earnings                       |       | ** ** | ** ** |   |   |
|-----------------------------------------------------------|------------|------------|------------|--------|--------|
|                                                      |       | ** ** | ** ** |   |   |
| For the year ended  December 31, (US$ millions) |       | **2009**   | ** ** | 2008   |   |
|                                                      |       | ** ** | ** ** |   |   |
| Operating Cash Flow (See Note 1)                     | ** ** | **310**    | ** ** | (241   | )      |
| Depreciation, depletion and amortization                  | ** ** | **(192**   | **)**      | (188   | )      |
| Other                                                     | ** ** | **(11**    | **)**      | 19     |   |
| Net Earnings (Loss)                                       | ** ** | **107**    | ** ** | (410   | )      |

 
| Consolidated Balance  Sheet                  |       | ** ** | ** ** |   |   |
|----------------------------------------------|------------|------------|------------|--------|--------|
|                                         |       | ** ** | ** ** |   |   |
| As at  December 31, (US$ millions) |       | **2009**   | ** ** | 2008   |   |
|                                         |       | ** ** | ** ** |   |   |
| Current Assets                               | ** ** | **771**    | ** ** | 321    |   |
| Long-term Assets                             | ** ** | **4,872**  | ** ** | 4,157  |   |
| Current Liabilities                          | ** ** | **489**    | ** ** | 422    |   |
| Long-term Liabilities                        | ** ** | **391**    | ** ** | 35     |   |

 
| Consolidated Statement of Cash Flows                      |       |     |   |   |   |
|-----------------------------------------------------------|------------|----------|--------|--------|--------|
|                                                      |       |     |   |   |   |
| For the year ended  December 31, (US$ millions) |       | **2009** |   | 2008   |   |
|                                                      |       |     |   |   |   |
| Cash From/(Used in)  Operating Activities                 | ** ** | **(54**  | **)**  | 118    |   |
| Cash (Used in)  Investing Activities                      | ** ** | **(905** | **)**  | (519   | )      |

 

 
| Cenovus Energy Inc. | 49 |
|---------------------|----|

 

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** **

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

*All amounts in US$millions, unless otherwise indicated*

*For the year endedDecember 31, 2009*

** **

** **

**21.  UNITEDSTATES ACCOUNTING PRINCIPLES AND REPORTING (continued)**

 

**G) Inventories**

 

For Canadian GAAP purposes, forthe year ended December 31, 2009, the Company recorded****an increase in inventory values resultingfrom a subsequent improvement in commodity prices following a write-down ofproduct inventory.  Under U.S. GAAP, thisincrease in inventory value is not permitted. Since the majority of the impaired inventory was sold during the year,the impact to net earnings for this reconciling difference was immaterial.

 

**H) Recent AccountingPronouncements**

 

Duringthe year, Cenovus adopted the following pronouncements for U.S. GAAP purposes:

·                  ASC 805-10, *“Business Combinations,”*which is a revised standard and requiresassets and liabilities acquired in a business combination, contingentconsideration, and certain acquired contingencies to be measured at their fairvalues as of the date of acquisition. Acquisition-related and restructuring costs are recognized separatelyfrom the business combination.  This standard was adopted prospectively asof January 1, 2009.  The adoption ofthis standard had no material impact on Cenovus’s U.S. GAAP accountingtreatment of business combinations entered into after January 1, 2009.

·                  ASC 810-10 *“Consolidation,”*which requires a non-controlling interest in a subsidiary to beclassified as a separate component of equity. The standard also changes the way the U.S. GAAP consolidated statementof earnings is presented by requiring net earnings to include the amountsattributable to both the parent and the non-controlling interest and todisclose these respective amounts.  Thisstandard was adopted as of January 1, 2009.  The adoption of this standard had no materialimpact on Cenovus’s Consolidated Financial Statements.

·                  In June 2009,the U.S. Financial Accounting Standards Board (“FASB”) issued the AccountingStandards Update (ASU) 2009-01, *“The FASB AccountingStandards Codification and the Hierarchy of Generally Accepted AccountingPrinciples.” *This updateestablishes the FASB Accounting Standards Codification (“Codification”) as thesource of authoritative U.S. generally accepted accounting principles effectivefor financial statements issued for interim and annual periods ending after September 15,2009.  The Codification did not changeexisting requirements under U.S. GAAP and as a result, did not impact Cenovus’sConsolidated Financial Statements.

·                  The U.S. Securities ExchangeCommission’s project, “*Modernization of Oiland Gas Reporting”*and**FASB’s Accounting Standards Update2010-03 “*Oil and Gas Reserve Estimation andDisclosures,”* which include provisions that permit the use ofnew technologies to establish proved reserves if those technologies have beendemonstrated empirically to lead to reliable conclusions about reservesvolumes.  Additionally, oil and gasreserves are now reported using an average price based upon the prior 12-monthperiod rather than year-end prices.  Thenew rules and standards were adopted prospectively by Cenovus on December 31,2009 and affected the reserve estimate used in the calculation of the ceilingtest for U.S. GAAP.  There was no effecton the ceiling test for the change in rules and standards noted above for2009.   In addition, the FASB standardaffected the amounts reported in the Supplementary Oil and Gas InformationTopic 932 as discussed in that supplementary information.

 

 
| Cenovus Energy Inc. | 50 |
|---------------------|----|

 

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**ADDITIONAL DISCLOSURE**

 

**Certificationsand 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, 2009, 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 under the Exchange Act is (i) recorded,  processed, summarized and reported within the time periods specified in the  Securities and Exchange Commission’s (the “Commission”) rules and forms  and (ii) accumulated and communicated to the registrant’s management,  including its principal executive and principal financial officers, or  persons performing similar functions, 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)    | Management’s Annual Report on Internal Control Over Financial  Reporting.  The  required disclosure is included in the “Management Report” that accompanies  the registrant’s Consolidated Financial Statements for the fiscal year ended  December 31, 2009, filed as part of this Annual Report on  Form 40-F.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (d)    | Attestation Report of the Registered Public Accounting Firm.  The required disclosure is included in the  “Auditors’ Report” that accompanies the registrant’s Consolidated Financial  Statements for the fiscal year ended December 31, 2009, filed as part of  this Annual Report on Form 40-F.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (e)    | Changes in Internal Control Over Financial Reporting.  During the fiscal year ended  December 31, 2009, there was no change in the registrant’s internal  control over financial reporting that has materially affected, or is  reasonably likely to materially affect, the registrant’s internal control  over financial reporting.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |

 

 

**NoticesPursuant to Regulation BTR.**

 

None.

 

**AuditCommittee Financial Expert.**

 

Theregistrant’s board of directors has determined that Colin Taylor, a member ofthe registrant’s audit committee, qualifies as an “audit committee financialexpert” (as such term is defined in Form 40-F), and is “independent” asthat term is defined in the rules of the New York Stock Exchange.

 

**Code ofEthics.**

 

Theregistrant has adopted a “code of ethics” (as that term is defined in Form 40-F),entitled the “Code of Business Conduct & Ethics”, that applies to allof its employees, including its principal executive officer, principalfinancial officer, principal accounting officer or controller, and personsperforming similar functions.

 

TheCode of Business Conduct & Ethics is available for viewing on theregistrant’s website at www.cenovus.com, and is available in print to anyperson without charge, upon request. Requests for copies of the Code of Business Conduct & Ethicsshould be made by contacting: Kerry D. Dyte, Executive Vice-President, GeneralCounsel & Corporate Secretary, Cenovus Energy Inc., 4000, 421-7thAvenue S.W., Calgary, Alberta, Canada T2P 4K9. Alternatively, requests for a copy of the Code of Business Conduct &Ethics may be made by contacting the registrant’s Corporate SecretarialDepartment at (403) 766-2000 (Fax: (403) 766-7600).

 

 

40-F-4

 

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Sincethe adoption of the Code of Business Conduct & Ethics, there have notbeen any waivers, including implicit waivers, granted from any provision of theCode of Business Conduct & Ethics.

 

**PrincipalAccountant Fees and Services.**

 

Therequired disclosure is included under the heading “Audit Committee—ExternalAuditor Service Fees” in the registrant’s Annual Information Form for thefiscal year ended December 31, 2009, filed as part of this Annual Reporton Form 40-F.

 

**Pre-ApprovalPolicies and Procedures.**

 

Therequired disclosure is included under the heading “Audit CommitteeInformation—Pre-Approval Policies and Procedures” in the registrant’s AnnualInformation Form for the fiscal year ended December 31, 2009, filedas part of this Annual Report on Form 40-F.

 

**Off-BalanceSheet Arrangements.**

 

Theregistrant does not have any off-balance sheet arrangements that have or arereasonably likely to have a current or future effect on its financialcondition, changes in financial condition, revenues or expenses, results ofoperations, liquidity, capital expenditures or capital resources that is materialto investors.

 

**TabularDisclosure of Contractual Obligations.**

 

Therequired disclosure is included under the heading “Contractual Obligations andContingencies” in the registrant’s Management’s Discussion and Analysis for thefiscal year ended December 31, 2009, filed as part of this Annual Reporton Form 40-F.

 

**Identificationof the Audit Committee.**

 

Theregistrant has a separately-designated standing audit committee established inaccordance with Section 3(a)(58)(A) of the Exchange Act.  The members of the audit committee are:  Patrick D. Daniel, Valerie A. A. Nielsen,Colin Taylor and Michael A. Grandin (ex-officio).

 

 

40-F-5

 

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**UNDERTAKING****ANDCONSENT TO SERVICE OF PROCESS**

 

**A. Undertaking**

 

The registrant undertakes to make available, in personor by telephone, representatives to respond to inquiries made by the Commissionstaff, and to furnish promptly, when requested to do so by the Commissionstaff, 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-Farises; or transactions in said securities.

 

**B. Consent to Service of Process**

 

(1)           The registrant has previously filed a Form F-Xin connection with the class of securities in relation to which the obligationto file this report arises.

 

(2)           Any change to the name or address of theagent for service of process of the registrant shall be communicated promptlyto the Commission by an amendment to the Form F-X referencing the filenumber of the registrant.

 

 

40-F-6

 

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**SIGNATURES**

 

Pursuant to the requirements of the Exchange Act,the Registrant certifies that it meets all of the requirements for filing on Form 40-Fand has duly caused this registration statement to be signed on its behalf bythe undersigned, thereunto duly authorized.

 

 
| Date:   February 18, 2010 | **CENOVUS  ENERGY INC.** |              |
|------------------------------------------|--------------------------|-------------------|
|                                     |                     |              |   |   |
|                                     |                     |              |   |   |
|                                     | By:                      | /s/ Ivor M. Ruste |   |
|                                     |                     | Name:             | Ivor M. Ruste |   |
|                                     |                     | Title:            | Executive Vice-President & Chief Financial  Officer |   |

 

 

40-F-7

 

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**EXHIBIT INDEX**

 
| **Exhibits** | ** ** | **Documents**                                                                                                                   |
|--------------|------------|---------------------------------------------------------------------------------------------------------------------------------|
|         |       |                                                                                                                            |
| 99.1         |       | Certification of Chief Executive Officer pursuant to  Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
|         |       |                                                                                                                            |
| 99.2         |       | Certification of Chief Financial Officer pursuant to  Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 |
|         |       |                                                                                                                            |
| 99.3         |       | Certification of Chief Executive Officer pursuant to  18 U.S.C. Section 1350                                          |
|         |       |                                                                                                                            |
| 99.4         |       | Certification of Chief Financial Officer pursuant to  18 U.S.C. Section 1350                                          |
|         |       |                                                                                                                            |
| 99.5         |       | Consent of PricewaterhouseCoopers LLP                                                                                           |
|         |       |                                                                                                                            |
| 99.6         |       | Consent of McDaniel & Associates  Consultants Ltd.                                                                     |
|         |       |                                                                                                                            |
| 99.7         |       | Consent of GLJ Petroleum Consultants Ltd.                                                                                       |

 

 

40-F-8

 

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