As filed with the Securities and Exchange Commission on May 26, 2010.

Registration No. 333-166738

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

AMENDMENT NO. 1
TO

FORM F-10

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

CENOVUS ENERGY INC.

(Exact name of Registrant as specified in its charter)

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

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

(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System, 111 Eighth Avenue, New York, New York 10011, (212) 894-8940

(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

The Commission is requested to send copies of all communications to:

Kerry D. Dyte
Cenovus Energy Inc.
4000, 421—7th Avenue S.W.
P.O. Box 766
Calgary, Alberta, Canada T2P
4K9
(403) 766-2000 John D. MacNeil Bennett Jones LLP 4500 Bankers Hall  East  855—2nd Street S. W. Calgary, AB T2P 4K7 Canada (403) 298-3100 Andrew J. Foley
Paul, Weiss, Rifkind, Wharton
& Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-
6064
(212) 373-3000

Approximate date of commencement of proposed sale to the public: 
As soon as practicable after this Registration Statement becomes effective.

Canada

(Principal jurisdiction regulating this offering)

It is proposed that this filing shall become effective (check appropriate box below):

A.	o  upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).
B.	þ  at some future date (check appropriate box below)
		1.	o  pursuant to Rule 467(b) on (          ) at (          ) (designate a time not sooner than seven calendar days after filing).
		2.	o  pursuant to Rule 467(b) on (          ) at (          ) (designate a time seven calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on (          ).
		3.	þ  pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
		4.	o   after the filing of the next amendment to this Form (if preliminary material is being filed).

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction’s shelf prospectus offering procedures, check the following box.   o

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registration Statement shall become effective as provided in Rule 467 under the Securities Act of 1933, as amended, or on such date as the Commission, acting pursuant to Section 8(a) of the Act, may determine.

PART I

INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION NOR HAS THE COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

Short Form Prospectus

New Issue May 26, 2010

Cenovus Energy Inc.

Exchange Offer for:

US$	800,000,000	4.50% Senior Notes due 2014
US$	1,300,000,000	5.70% Senior Notes due 2019
US$	1,400,000,000	6.75% Senior Notes due 2039

The exchange offer:

·The exchange offer expires at 5:00 p.m., New York City time on June 28, 2010, unless we extend the exchange offer.

·If all the conditions of the exchange offer are satisfied, we will exchange all of the 4.50% senior notes due 2014 issued on September 18, 2009 (the “Initial 2014 Notes”) that are validly tendered and not withdrawn for new 4.50% senior notes due 2014 (the “New 2014 Notes”), we will exchange all of the 5.70% senior notes due 2019 issued on September 18, 2009 (the “Initial 2019 Notes”) that are validly tendered and not withdrawn for new 5.70% senior notes due 2019 (the “New 2019 Notes”) and we will exchange all of the 6.75% senior notes due 2039 issued on September 18, 2009 (the “Initial 2039 Notes”, together with the Initial 2014 Notes and Initial 2019 Notes, the “Initial Notes”) that are validly tendered and not withdrawn for new 6.75% senior notes due 2039 (the “New 2039 Notes”, together with the New 2014 Notes and the New 2019 Notes, the “Exchange Notes”).

·You may withdraw your tender of Initial Notes at any time prior to the expiration of the exchange offer.

The Exchange Notes:

·The Exchange Notes (collectively, with the Initial Notes, the “notes”) to be issued in exchange for your Initial Notes will be substantially identical to the Initial Notes, except that, unlike your Initial Notes, the Exchange Notes will have no transfer restrictions or registration rights.

·No public market currently exists for the Initial Notes.  We do not intend to list the Exchange Notes on any securities exchange and, therefore, no active public market is anticipated for the Exchange Notes.

For a more detailed description of the Exchange Notes, see “Description of the Exchange Notes” beginning on page 60.

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Before participating in the exchange offer, please refer to the section in this prospectus entitled “Risk Factors” beginning on page 19.

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is truthful or complete.  Any representation to the contrary is a criminal offence.

We are permitted, under a multijurisdictional disclosure system adopted by the United States, to prepare this prospectus in accordance with Canadian disclosure requirements, which are different from those of the United States.  We prepare our financial statements in accordance with Canadian generally accepted accounting principles, and they are subject to Canadian auditing and auditor independence standards.  They may not be comparable to financial statements of United States companies.  See “Presentation of Financial Information”.

Owning the Exchange Notes may subject you to tax consequences both in the United States and Canada.  This prospectus may not describe these tax consequences fully.  You should read the tax discussion in this prospectus.

Your ability to enforce civil liabilities under the United States federal securities laws may be affected adversely because we are organized under the laws of Canada, most of our directors and officers and some of the experts named in this prospectus are Canadian residents, and most of our assets or the assets of our directors and officers and the experts are located outside the United States.  See “Enforceability of Civil Liabilities Against Foreign Persons”.

There is no market through which the Exchange Notes may be sold and purchasers may not be able to resell the Exchange Notes offered under this prospectus.  This may affect the pricing of the Exchange Notes in the secondary market, the transparency and availability of trading prices, the liquidity of the Exchange Notes, and the extent of issuer regulation.  See “Risk Factors”.

No underwriter has been involved in the preparation of this prospectus or performed any review of the contents of this prospectus.

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes.  The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”).  This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Initial Notes where such Initial Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities.  We have agreed that, for a period of 180 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution”.

Our registered and principal office is located at 4000, 421 – 7th Avenue S.W., Calgary, Alberta, Canada T2P 4K9.

TABLE OF CONTENTS

ABOUT THIS PROSPECTUS	1
WHERE YOU CAN FIND MORE INFORMATION	1
DOCUMENTS INCORPORATED BY REFERENCE	2
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS	3
PRESENTATION OF FINANCIAL INFORMATION	3
CURRENCY AND EXCHANGE RATE INFORMATION	4
NOTE REGARDING FORWARD-LOOKING STATEMENTS	4
NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION	5
SUMMARY	7
SUMMARY OF THE EXCHANGE OFFER	11
SUMMARY OF TERMS OF THE EXCHANGE NOTES	16
RISK FACTORS	19
CREDIT RATINGS	28
USE OF PROCEEDS	29
INTEREST COVERAGE	29
CAPITALIZATION	29
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA	29
SUMMARY OPERATING AND RESERVES INFORMATION	31
CORPORATE STRUCTURE	31
GENERAL DEVELOPMENT OF OUR BUSINESS	32

NARRATIVE DESCRIPTION OF OUR BUSINESS	35
GENERAL	43
DIRECTORS AND EXECUTIVE OFFICERS	46
DESCRIPTION OF OTHER MATERIAL INDEBTEDNESS	47
THE EXCHANGE OFFER	48
DESCRIPTION OF THE EXCHANGE NOTES	60
CERTAIN CANADIAN AND UNITED STATES INCOME TAX CONSIDERATIONS	76
PLAN OF DISTRIBUTION	80
PRIOR SALES	80
LEGAL MATTERS	81
EXPERTS	81
AUDITOR’S CONSENT	82
GLOSSARY OF TERMS	83
INDEX TO APPENDICES	F-1
CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2009	F-2
INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) FOR THE PERIOD ENDED MARCH 31, 2010	F-52
MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2009	A-1
MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE THREE MONTH PERIOD ENDED MARCH 31, 2010	B-1
RESERVES AND OTHER OIL AND GAS INFORMATION	C-1

ABOUT THIS PROSPECTUS

Except as set forth under “Description of the Exchange Notes”, and unless otherwise specified or the context otherwise requires, all references in this prospectus to “Cenovus”, “we”, “us” and “our” mean Cenovus Energy Inc. and its consolidated subsidiaries and partnerships.

In this prospectus, unless otherwise specified or the context otherwise requires, all dollar amounts in this prospectus are expressed in United States dollars, references to “dollars”, “$” or “US$” are to United States dollars and all references to “C$” are to Canadian dollars.

Unless otherwise indicated, all financial information included and incorporated by reference in this prospectus is determined using Canadian generally accepted accounting principles, referred to as “Canadian GAAP”.  Our audited consolidated financial statements for the year ended December 31, 2009, and periods prior thereto, are expressed in U.S. dollars.  All of our consolidated financial statements for periods ended subsequent to December 31, 2009 are expressed in Canadian dollars.

Unless otherwise specified, capitalized terms used in this prospectus have the meaning ascribed thereto under the heading “Glossary of Terms”.

WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form F-10 with the SEC regarding the Exchange Notes. This prospectus is part of our registration statement.  For further information about us and the Exchange Notes, you should refer to our registration statement and its exhibits. This prospectus summarizes material provisions of contracts and other documents to which we refer you. Since the prospectus may not contain all of the information that you may find important, you should review the full text of these documents. We have included copies of these documents as exhibits to our registration statement.

Information has been incorporated by reference in this prospectus from documents filed with securities commissions or similar authorities in Canada.  Copies of the documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of Cenovus Energy Inc., 421 – 7th Avenue S.W., P.O. Box 766, Calgary, Alberta, Canada T2P 0M5, telephone (403) 766-2000.  These documents are also available through the internet via SEDAR, which can be accessed at www.sedar.com.

We file with the securities commission or authority in each of the provinces and territories of Canada, annual and quarterly reports, material change reports and other information.  We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and, in accordance with the Exchange Act, we also file reports with and furnish other information to the SEC.  Under the multijurisdictional disclosure system adopted by the United States, these reports and other information (including financial information) may be prepared, in part, in accordance with the disclosure requirements of Canada, which differ from those in the United States.  You may read any document we furnish to the SEC at the SEC’s public reference room at Room 1580, 100 F Street, N.E., Washington, D.C. 20549.  You may also obtain copies of the same documents from the public reference room of the SEC at 100 F Street, N.E., Washington D.C. 20549 by paying a fee.  Please call the SEC at 1-800-SEC-0330 or contact them at www.sec.gov for further information on the public reference rooms.  Our filings are also electronically available from EDGAR, which can be accessed at www.sec.gov, as well as from commercial document retrieval services.

Anyone who receives a copy of this prospectus may obtain copies of the Indenture governing the Exchange Notes without charge by writing to our Corporate Secretary at 421 – 7th Avenue S.W., P.O. Box 766, Calgary, Alberta, Canada T2P 0M5.

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DOCUMENTS INCORPORATED BY REFERENCE

Under applicable securities laws in Canada and the United States, the Canadian securities commissions and the SEC allow us to incorporate by reference in this prospectus certain information that we file with them, which means that we can disclose important information to you by referring you to those documents. Information that is incorporated by reference is an important part of this prospectus.  We incorporate by reference the documents listed below, which were filed with the securities commissions or similar authorities in Canada under applicable securities laws in Canada:

(a)our Annual Information Form dated February 18, 2010;

(b)our audited consolidated financial statements and auditors’ report thereon for the year ended December 31, 2009;

(c)our Management’s Discussion and Analysis for the year ended December 31, 2009;

(d)our unaudited interim consolidated financial statements for the three month period ended March 31, 2010;

(e)our Management’s Discussion and Analysis for the three month period ended March 31, 2010; and

(f)our supplemental disclosure document concerning our estimated contingent resources dated May 10, 2010.

Any documents of the type required by National Instrument 44-101 Short Form Prospectus Distributions to be incorporated by reference in this prospectus, including any material change reports (excluding confidential material change reports), unaudited interim consolidated financial statements, annual consolidated  financial statements and the auditors’ report thereon, management’s discussion and analysis, information circulars, annual information forms and business acquisition reports filed by us with the securities commissions or similar authorities in Canada subsequent to the date of this prospectus and prior to the termination of the exchange offer shall be deemed to be incorporated by reference in this prospectus.  To the extent that any document or information incorporated by reference into this prospectus is included in a report that is filed with or furnished to the SEC on Form 40-F, 20-F, 10-K, 10-Q, 8-K or 6-K (or any respective successor form), such document or information shall also be deemed to be incorporated by reference as an exhibit to the registration statement of which this prospectus forms a part.

Any statement contained in this prospectus or in a document incorporated, or deemed to be incorporated by reference, in this prospectus shall be deemed to be modified or superseded, for purposes of this prospectus, to the extent that a statement contained in this prospectus or in any subsequently filed document that also is, or is deemed to be, incorporated by reference in this prospectus modifies or replaces such statement.  The making of such a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made.  Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute part of this prospectus.  The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document which it modifies or supersedes.

Upon unaudited interim consolidated financial statements and the accompanying management’s discussion and analysis being filed by us with the applicable securities regulatory authorities during the currency of this prospectus, all unaudited interim consolidated financial statements and the accompanying management’s discussion and analysis filed prior to the new unaudited interim consolidated financial statements shall be deemed no longer to be incorporated into this prospectus for purposes of distributions under this prospectus.

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ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS

We are organized under the laws of Canada and, accordingly, are governed by the applicable provincial and federal laws of Canada.  A majority of our directors and officers and certain of the experts named in this prospectus reside principally in Canada.  Because we and these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on these persons.  Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States courts, because a substantial portion of our assets and their assets are located outside the United States.  We have been advised by Bennett Jones LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the United States federal securities laws or the securities laws or “blue sky” laws of any state within the United States and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based upon the civil liability provisions of the United States federal securities laws or any such state securities laws or blue sky laws.  Therefore, it may not be possible to enforce those judgments against us, a majority of our directors and officers or certain of the experts named in this prospectus.

PRESENTATION OF FINANCIAL INFORMATION

Unless otherwise indicated, all financial information included in this prospectus is determined using Canadian GAAP, which differs from U.S. GAAP in certain material respects, and thus may not be comparable to financial statements and financial information of U.S. companies.  The notes to our audited consolidated financial statements included or incorporated by reference in this prospectus contain a discussion of the principal differences between the financial results calculated under Canadian GAAP and under U.S. GAAP.

In February 2008, the Canadian Institute of Chartered Accountants’ Accounting Standards Board confirmed that profit-oriented Canadian publicly accountable enterprises will be required to report their financial results in accordance with International Financial Reporting Standards (“IFRS”).  Accordingly, we will be required to report our results in accordance with IFRS beginning in 2011.

Our audited consolidated financial statements for the year ended December 31, 2009, and periods prior thereto, are expressed in U.S. dollars.  All of our consolidated financial statements for periods ended subsequent to December 31, 2009 are expressed in Canadian dollars.

Certain historical information contained in this prospectus has been provided by, or derived from information provided by, certain third parties, including Encana.  Although we have no knowledge that would indicate that any such information is untrue or incomplete, we assume no responsibility for the completeness or accuracy of such information or the failure by such third parties to disclose events which may have occurred or may affect the completeness or accuracy of such information, but which are unknown to us.

We commenced independent operations on December 1, 2009 following the completion of the Arrangement.  The description of our business, recent significant developments, the presentation of financial statements and other information throughout this prospectus in respect of periods prior to December 1, 2009 is based on information with respect to the Cenovus Assets as operated by Encana prior to December 1, 2009.  See “General Development of our Business – The Arrangement” for further information on the Arrangement.  Such financial information has been derived from the historical consolidated financial statements of Encana for each of the relevant periods on a carve-out basis from such historical consolidated financial statements of Encana for the relevant period and should be read in conjunction with our audited consolidated financial statements for the year ended December 31, 2009 and the carve-out consolidated financial statements in relation to Cenovus Energy for the year ended December 31, 2008 and the Management’s Discussion and Analysis thereon, each as set out in the Information Circular of Encana dated October 20, 2009 relating to an arrangement involving Cenovus Energy Inc., and the unaudited interim carve-out consolidated financial statements in relation to Cenovus Energy for the nine months ended September 30, 2009 and the Management’s Discussion and Analysis thereon which are accessible on the SEDAR profile of Encana at www.sedar.com and have been filed with the SEC and are available via EDGAR at www.sec.gov.

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

CURRENCY AND EXCHANGE RATE INFORMATION

The following table sets forth: (i) the noon day rates of exchange for the Canadian dollar, expressed in Canadian dollars per U.S. dollar, in effect at the end of the periods indicated; (ii) the average noon day exchange rates for such periods; and (iii) the high and low exchange rates during such periods, based on the rates quoted by the Bank of Canada.

Canadian Dollar per U.S. Dollar	January 1, 2010 through March 31, 2010 (C$)	2009 (C$)	2008 (C$)	2007 (C$)
Noon day rate at end of period	1.0156	1.0466	1.2246	0.9881
Average noon day rate for period	1.0401	1.1420	1.0660	1.0748
High for period	1.0734	1.3000	1.2969	1.1853
Low for period	1.0113	1.0292	0.9719	0.9170

On May 25, 2010, the rate of exchange based on the noon day rate as quoted by the Bank of Canada was C$1.0778 equals US$1.00.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and documents incorporated by reference in this prospectus contain certain forward-looking statements and information (collectively referred to as “forward-looking statements”) about our current expectations, estimates and projections about the future, based on certain assumptions made by Cenovus in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking statements are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “objective”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook” or similar expressions suggesting future outcomes or statements regarding an outlook.  All statements other than statements of historical fact contained in this prospectus and documents incorporated by reference in this prospectus are forward-looking statements, including, but not limited to, statements relating to the anticipated benefits of the Arrangement, our strategy, operating and financial information and results, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves and resources, material properties, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements as our actual results may differ materially from those expressed or implied.

Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect of our risk management program, including the impact of derivative

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financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the expected impacts of the Arrangement on our employees, operations, suppliers, business partners and stakeholders and our ability to realize the expected benefits of the Arrangement; our ability to obtain financing in the future on a stand alone basis; the historical financial information pertaining to our assets as operated by Encana prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

We caution that the foregoing list of important factors is not exhaustive.  Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements.  You should also carefully consider the matters discussed under “Risk Factors” in this prospectus and the risk factors identified in documents incorporated by reference in this prospectus.  Except as required under applicable securities laws, we undertake no obligation to update publicly or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise, or the foregoing list of factors affecting this information.

NOTE REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION

NI 51-101 imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities.  We have obtained an exemption from the Canadian securities regulatory authorities to permit us to provide disclosure in accordance with the relevant legal requirements of the SEC.  This facilitates comparability of our oil and gas disclosure with that provided by U.S. and other international issuers, given that we are active in the U.S. capital markets. Accordingly, the proved and probable reserves data and much of the other oil and gas information included in this prospectus and documents incorporated by reference in this prospectus is disclosed in accordance with U.S. disclosure requirements.  Such information, as well as the information that we anticipate disclosing in the future in reliance on such exemption, may differ from the corresponding information prepared in accordance with NI 51-101 standards.

In 2008, the SEC amended its oil and gas reporting requirements effective for Cenovus’s 2009 year end reporting.  The U.S. Financial Accounting Standards Board also amended its oil and gas reserve estimation and disclosure requirements to align with the amended SEC requirements.  The amendments included changing the price used to calculate reserves from a year-end single day price to a historical 12-month average price, permitting

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optional disclosure of probable reserves and the sensitivity of reserves to price and requiring the separate disclosure of bitumen reserves from crude oil and NGLs reserves.

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

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

The current U.S. requirements permit, but do not require, the disclosure of probable reserves information.  The SEC has defined probable reserves as those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved 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 royalty scheme which ties the bitumen royalty rate to the West Texas Intermediate reference oil price, in Canadian dollars. Since oil price is unregulated and can have significant volatility, this in turn means the royalty rate can vary significantly.  For example, our year-end 2008 proved bitumen reserves were subject to a forecasted average royalty rate of four percent, while year-end 2009 proved bitumen reserves face a forecasted average royalty rate of 16 percent.  This oil price dependent volatility can mask the impact of our development activities.  To provide more complete information on our business, in this prospectus and/or documents incorporated by reference in this prospectus, we have, in certain instances, voluntarily provided reserves and production information for both proved and probable reserves, on a before royalties basis, as well as, on an after royalties basis.

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SUMMARY

This summary may not contain all of the information that may be important to you.  The following summary is qualified in its entirety by and should be read in conjunction with the detailed information and financial statements appearing elsewhere in this prospectus.  You should read the entire prospectus closely.

Cenovus

Cenovus is an integrated oil company headquartered in Calgary, Alberta.  Our operations include enhanced oil recovery (“EOR”) properties and established crude oil and natural gas production in Alberta and Saskatchewan.  We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the split of Encana into two independent publicly traded energy companies – Cenovus and Encana.  Although we are a new company, we have operated a number of our assets for decades.

The Arrangement

The division of Encana into two highly focused and independent publicly traded energy companies was completed on November 30, 2009.  It resulted in, among other things, the establishment of our company as an independent integrated oil company anchored by stable production and cash flow from well-established crude oil and natural gas plays, integrated from crude oil production through to refined products.

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

·those assets associated with Encana’s Integrated Oil Division, which included Encana’s interests in the Foster Creek, Christina Lake, Narrows Lake and Borealis areas and the U.S. refinery interests in addition to certain of Encana’s other bitumen interests and natural gas assets located in the Athabasca area;

·those assets associated with Encana’s Canadian Plains Division, which included the majority of Encana’s legacy oil and natural gas assets in southern Alberta and Saskatchewan.  This Division included the EOR properties located at Weyburn and Pelican Lake, as well as the Southern Alberta oil and gas properties; and

·those assets associated with the foregoing businesses, including marketing, corporate and office space (including a proportionate share of The Bow office project).

Pursuant to the Pre-Arrangement Reorganization in connection with the Arrangement, Encana transferred the Cenovus Assets to Subco in exchange for, among other things, the Demand Note.

The Assumed Liabilities assumed, directly or indirectly, in connection with the Arrangement included, among others, those liabilities relating to Encana’s Integrated Oil and Canadian Plains Divisions described above.

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

In connection with the Arrangement and in order to provide ongoing liquidity, including working capital requirements, prior to the completion of the Arrangement, we obtained commitments from a syndicate of banks to make available an unsecured credit facility in the amount of C$2.5 billion.  The revolving syndicated credit facility consists of two tranches, a C$2.0 billion three-year tranche and a C$500 million 364-day tranche.  The terms of each of these facilities commenced on the Effective Date.

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On the Issue Date, a predecessor entity of Cenovus completed, in three tranches, a $3.5 billion private offering of the Initial Notes which are exempt from the registration requirements of the Securities Act under Rule 144A and Regulation S.  The net proceeds were placed into an escrow account pending the completion of the Arrangement.  Upon completion of the Arrangement, the net proceeds, together with other pre-funded amounts, were released from escrow and were applied to repay all of the amounts outstanding under the Demand Note.

Our Business

Our operations are organized into two operating divisions:

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

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

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The following maps outline the location of our assets, including our major properties and refining assets as at December 31, 2009.

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One hundred 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 a proved reserves base (our share after royalties) of approximately 719 million barrels of bitumen reserves, 232 million barrels of crude oil and NGLs reserves and 1,474 billion cubic feet of natural gas reserves.  The estimated proved reserves life index as at December 31, 2009 was approximately 14.7 years.  We also had probable reserves (our share after royalties) of approximately 403 million barrels of bitumen, 127 million barrels of crude oil and NGLs and 405 billion cubic feet of natural gas as at December 31, 2009.

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SUMMARY OF THE EXCHANGE OFFER

On the Issue Date, we sold the Initial Notes in a private placement exempt from the registration requirements of the Securities Act, and the initial purchasers of the Initial Notes then resold them in reliance on other exemptions from the registration requirements of the Securities Act.  Consequently, the Initial Notes are subject to transfer restrictions under the Securities Act.  Pursuant to the terms of the Registration Rights Agreement, we agreed, among other things, to deliver this prospectus and to keep the exchange offer open for a period of not less than 30 days after the date notice of the exchange offer is mailed to the holders of the Initial Notes and to use commercially reasonable efforts to cause the exchange offer to be completed no later than the 45th day after the exchange offer registration statement is declared effective by the SEC.

We are offering to exchange: (i) US$800,000,000 aggregate principal amount of Initial 2014 Notes for a like aggregate principal amount of our New 2014 Notes; (ii) US$1,300,000,000 aggregate principal amount of Initial 2019 Notes for a like aggregate principal amount of our New 2019 Notes; and (iii) US$1,400,000,000 aggregate principal amount of Initial 2039 Notes for a like aggregate principal amount of our New 2039 Notes.  In order to exchange your Initial 2014 Notes, and/or your Initial 2019 Notes and/or your Initial 2039 Notes, you must properly tender them and we must accept your tender.  We will exchange all outstanding Initial 2014 Notes, Initial 2019 and Initial 2039 Notes that are validly tendered and not validly withdrawn.

Exchange Offer	We are offering to exchange your Initial 2014 Notes for a like aggregate principal amount at maturity of our New 2014 Notes.
	We are offering to exchange your Initial 2019 Notes for a like aggregate principal amount at maturity of our New 2019 Notes.
	We are offering to exchange your Initial 2039 Notes for a like aggregate principal amount at maturity of our New 2039 Notes.
Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on the Expiration Date.
Conditions to the Exchange Offer	We will complete the exchange offer only if:
	•there is no change in the laws and regulations which, in our judgment or the opinion of our counsel, would reasonably be expected to impair our ability to proceed with the exchange offer;
	•there is no change in the current interpretation of the staff of the SEC which permits resales of the Exchange Notes;
	•there is no stop order issued by the SEC or any state securities authority suspending the effectiveness of the registration statement which includes this prospectus or the qualification of the Indenture for the Exchange Notes under the Trust Indenture Act of 1939 as amended (the “Trust Indenture Act”) and there are no proceedings initiated or, to our knowledge, threatened for that purpose;
	•there is no action or proceeding instituted or threatened in any court or before any governmental agency or body that, in our judgment or in the opinion of our counsel, would reasonably be expected to prohibit, prevent or otherwise impair our ability to proceed with the exchange offer; and

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	•we obtain all governmental approvals that we deem in our sole discretion necessary to complete the exchange offer.
	In addition, we will not be obligated to accept for exchange the Initial Notes of any holder that has not made to us the representations described under “The Exchange Offer – Procedures for Tendering Initial Notes – Representations Made by Tendering Holders of Initial Notes” and “Plan of Distribution”, as applicable.
	Please refer to the section in this prospectus entitled “The Exchange Offer – Conditions to the Exchange Offer”.
Procedures for Tendering Initial Notes	To participate in the exchange offer, you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your Initial Notes to be exchanged and all other documents required by the letter of transmittal, to BNY Mellon, as exchange agent, at its address indicated under “The Exchange Offer – Exchange Agent”.  In the alternative, you can tender your Initial Notes by book-entry delivery following the procedures described in this prospectus and the letter of transmittal. For more information on tendering your Initial Notes, please refer to the section in this prospectus entitled “The Exchange Offer – Procedures for Tendering Initial Notes”.
Special Procedures for Beneficial Owners	If you are a beneficial owner of Initial Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Initial Notes in the exchange offer, you should contact the registered holder promptly and instruct that person to tender on your behalf. For more information on tendering your Initial Notes, please refer to the section in this prospectus entitled “The Exchange Offer – Procedures for Tendering Initial Notes”.
Guaranteed Delivery Procedure	If you wish to tender your Initial Notes and you cannot get the required documents to BNY Mellon, as exchange agent, on time, you may tender your Initial Notes by using the guaranteed delivery procedures described under the section of this prospectus entitled “The Exchange Offer – Procedures for Tendering Initial Notes – Guaranteed Delivery Procedure”.
Withdrawal Rights	You may withdraw the tender of your Initial Notes at any time before 5:00 p.m., New York City time, on the Expiration Date.  To withdraw, you must send a written or facsimile transmission notice of withdrawal to BNY Mellon, as the exchange agent, to the address or facsimile number indicated under “The Exchange Offer – Exchange Agent” before 5:00 p.m., New York City time, on the Expiration Date of the exchange offer.

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Acceptance of Initial Notes and Delivery of Exchange Notes	If all the conditions to the completion of the exchange offer are satisfied, we will accept any and all Initial Notes that are properly tendered in the exchange offer on or before 5:00 p.m., New York City time, on the Expiration Date.  We will return any Initial Notes that we do not accept for exchange to you without expense as promptly as practicable after the Expiration Date.  We will deliver the Exchange Notes to you as promptly as practicable after the Expiration Date and the acceptance of your Initial Notes for exchange.  Please refer to the section in this prospectus entitled “The Exchange Offer – Acceptance of Initial Notes for Exchange”.
Income Tax Consequences Relating to the Exchange Offer	Subject to the assumptions and qualifications set forth herein, exchanging your Initial Notes for Exchange Notes will not be a taxable event to you for either Canadian or United States federal income tax purposes.  Please refer to the section of this prospectus entitled “Certain Canadian and United States Income Tax Considerations”.
Exchange Agent	BNY Mellon is serving as exchange agent for the purposes of the exchange offer.
Fees and Expenses	We will pay all expenses related to the exchange offer.  Please refer to the section of this prospectus entitled “The Exchange Offer – Fees and Expenses”.
Use of Proceeds	We will not receive any proceeds from the issuance of the Exchange Notes.  Please refer to the section of this prospectus entitled “Use of Proceeds”
Consequences to Holders Who Do Not Participate in the Exchange Offer	If you do not exchange your Initial Notes in accordance with the exchange offer, or if you do not properly tender your Initial Notes in the exchange offer: •you may no longer be able to obligate us to register your Initial Notes under the Securities Act;
	•you will not be able to resell, offer to resell or otherwise transfer the Initial Notes unless they are registered under the Securities Act or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act; and
	•the trading market for your Initial 2014 Notes, your Initial 2019 Notes and your Initial 2039 Notes will become more limited to the extent other holders of Initial Notes participate in the exchange offer.
	Please refer to the section of this prospectus entitled “The Exchange Offer – Your Failure to Participate in the Exchange Offer May Have Adverse Consequences”.

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	However, if: •we are not permitted to file the exchange offer registration statement; •because of any change in applicable law or in interpretations thereof by the SEC staff, we are not permitted to effect the exchange offer;
	•the exchange offer is not completed by the 410th day after the Issue Date; •any initial purchaser so requests with respect to Initial Notes held by it that are not eligible to be exchanged for Exchange Notes in the exchange offer; or •prior to the 20th day following the consummation of the exchange offer, any holder of Transfer Restricted Securities (as defined herein) notifies us that it is prohibited by law or the SEC from participating in the exchange offer or that it may not resell the Exchange Notes acquired in the exchange offer without delivering a prospectus or it is a broker-dealer and owns Exchange Notes acquired directly from us or an affiliate of ours,
	we will be required to file with the SEC a shelf registration statement to register for public resale the Transfer Restricted Securities held by any such holder within 90 days after such triggering event and use our commercially reasonable efforts to have it declared effective no later than 180 days after the trigger date, subject to the exceptions description under “The Exchange Offer – Purpose and Effect of the Exchange Offer.”
Resale of the Exchange Notes	Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties in similar transactions, we believe that a holder of the Exchange Notes may offer the Exchange Notes for resale or resell or otherwise transfer the Exchange Notes in the United States without compliance with the registration and prospectus delivery requirements of the Securities Act, unless the holder:
	•is our “affiliate” within the meaning of Rule 405 under the Securities Act; •acquired the Exchange Notes other than in the ordinary course of the holder’s business; •is participating, intends to participate, or has an arrangement or understanding with any person to participate in the distribution of the Exchange Notes; or •is a broker-dealer who purchased Initial Notes directly from us for resale under Rule 144A under the Securities Act (“Rule 144A”) or any other available exemption under the Securities Act;

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We do not intend to seek our own no-action letter from the SEC, and we cannot assure you that the SEC staff would make a similar determination as set forth in the no-action letters issued to third parties in similar transactions with respect to the Exchange Notes. If this interpretation is inapplicable and you resell or otherwise transfer any Exchange Notes without complying with the registration and prospectus delivery requirements of the Securities Act, you may incur liability under the Securities Act. We do not and will not assume or indemnify you against this liability.

Each broker-dealer that receives Exchange Notes for its own account in exchange for Initial Notes that were acquired by it as a result of market-making activities or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Notes.  Any holder of Initial Notes who:

•is our “affiliate” within the meaning of Rule 405 under the Securities Act;

•acquired the Exchange Notes other than in the ordinary course of this holder’s business;

•is participating, intends to participate, or has an arrangement or understanding with any person to participate in the distribution of the Exchange Notes; or

•is a broker-dealer who purchased Initial Notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act;

cannot rely on the position of the SEC staff expressed in the no-action letters described above and, in the absence of an exemption, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the Exchange Notes.

Please refer to the sections of this prospectus entitled “The Exchange Offer – Delivery of Prospectus”, “The Exchange Offer – Resale of the Exchange Notes” and “Plan of Distribution”.

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SUMMARY OF TERMS OF THE EXCHANGE NOTES

The summary below describes the principal terms of the Exchange Notes.  Some of the terms and conditions described below are subject to important limitations and exceptions.  You should carefully read the “Description of the Exchange Notes” section of this prospectus for a more detailed description of the Exchange Notes.

Issuer	Cenovus Energy Inc.
Exchange Notes Offered	US$800,000,000 aggregate principal amount of 4.50% senior notes due 2014, US$1,300,000,000 aggregate principal amount of 5.70% senior notes due 2019 and US$1,400,000,000 aggregate principal amount of 6.75% senior notes due 2039.  The form and terms of the Exchange Notes are the same as the form and terms of the Initial Notes except that the issuance of the Exchange Notes is registered under the Securities Act, the Exchange Notes will not bear legends restricting their transfer and the Exchange Notes will not be entitled to registration rights under the Registration Rights Agreement.  The Exchange Notes will evidence the same debt as the Initial Notes, and the Exchange Notes will be governed by the same Indenture that governed the Initial Notes.
Maturity Date	The New 2014 Notes will mature on September 15, 2014; The New 2019 Notes will mature on October 15, 2019; and The New 2039 Notes will mature on November 15, 2039.
Interest and Accrued Interest	The interest rate on each series of the Exchange Notes shall be: New 2014 Notes                        Rate:  4.50% New 2019 Notes                        Rate:  5.70% New 2039 Notes                        Rate:  6.75% Each series of the Exchange Notes will bear interest from the most recent date to which interest has been paid on the corresponding series of Initial Notes or, if no interest has been paid on the applicable series of Initial Notes, from the Issue Date.
Interest Payment Dates	We will pay interest on the New 2014 Notes semi-annually in arrears on March 15 and September 15 of each year.   We will pay interest on the New 2019 Notes semi-annually in arrears on April 15 and October 15 of each year.  We will pay interest on the New 2039 Notes semi-annually in arrears on May 15 and November 15 of each year.  We will make interest payments in U.S. dollars.

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Ratings	The Exchange Notes are rated “BBB+” by S&P, “Baa2” (Stable) by Moody’s and “A(low)” (Stable) by DBRS. Credit ratings are not recommendations to purchase, hold or sell the Exchange Notes.  Ratings are subject to revision or withdrawal at any time by the ratings agencies.  See “Credit Ratings”.
Ranking	The Exchange Notes will be our direct, unsecured and unsubordinated obligations and will rank equally and ratably with all of our existing and future unsecured and unsubordinated indebtedness.  The Exchange Notes will be structurally subordinate to all existing and future indebtedness and liabilities of any of our corporate and partnership subsidiaries.  A substantial portion of our operations is conducted through corporate and partnership subsidiaries.  In connection with the formation of Cenovus’s integrated oil business with ConocoPhillips one of our partnership subsidiaries owed, as at March 31, 2010, approximately $5.6 billion of partnership contribution payable to an entity that Cenovus and ConocoPhillips own equally.  See “Description of the Exchange Notes – Ranking”.
Certain Covenants	The Indenture contains certain covenants that, among other things, limit: ·   our ability and the ability of our restricted subsidiaries to create liens; and ·   our ability (exclusive of our corporate and partnership subsidiaries) to merge, amalgamate or consolidate with, or sell all or substantially all of our assets to, any other person, except that transactions with, or sales to, a wholly owned subsidiary are, subject to certain limitations, permitted. See “Description of the Exchange Notes – Certain Covenants”. These covenants are subject to important exceptions and qualifications which are described under the caption “Description of the Exchange Notes”.
Use of Proceeds	We will not receive any proceeds from the issuance of the Exchange Notes in exchange for the outstanding Initial Notes.  We are making this exchange offer solely to satisfy our obligations under the Registration Rights Agreement.
Risk Factors	See “Risk Factors” for a discussion of factors you should carefully consider before deciding to exchange the Initial Notes for the Exchange Notes.
Optional Redemption	We may redeem each series of Exchange Notes, in whole or in part, at our option at any time or from time to time at the applicable redemption price described in this prospectus.  See “Description of the Exchange Notes – Optional Redemption”. We may also redeem, in whole and not in part, any series of the Exchange Notes, at the redemption price described in this prospectus at any time in the event certain changes affecting Canadian or other

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	applicable withholding taxes occur.  See “Description of the Exchange Notes – Tax Redemption”.
Mandatory Redemption	We will not be required to make mandatory redemption or sinking fund payments with respect to the Exchange Notes.
Sinking Fund	None.
Absence of Public Trading Market	The Exchange Notes will be a new issue of securities for which there is currently no market.  We do not intend to apply for the Exchange Notes to be listed on any securities exchange or to arrange for any quotation system to quote them.  Accordingly, there can be no assurance that a liquid market for the Exchange Notes will develop or be maintained.  See “Risk Factors”.
Form and Denomination	Each series of the Exchange Notes will be represented by one or more fully-registered global notes (the “Global Notes”) registered in the name of a nominee of DTC.  Beneficial interests in the Global Notes will be in minimum denominations of $2,000 and any integral multiple of $1,000 in excess thereof.
Governing Law	The Indenture is, and the Exchange Notes will be, governed and construed in accordance with the laws of the State of New York.

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RISK FACTORS

You should carefully consider the following risk factors, as well as other information contained in this prospectus, before tendering your Initial Notes in the exchange offer.  If any event arises from the risk factors set forth below, our business, prospects, financial condition, results of operation or cash flows and, in some cases, our reputation could be materially adversely affected.

Risks relating to the Exchange Notes

There can be no assurance as to the liquidity of the trading market for the Exchange Notes or that a trading market for the Exchange Notes will develop.

There is no public market for the Exchange Notes and we do not intend to apply for listing of the Exchange Notes on any securities exchange.  If the Exchange Notes are traded after their initial issue, they may trade at a discount from the initial offering prices of the Initial Notes depending on prevailing interest rates, the market for similar securities and other factors, including general economic conditions and our financial condition.  There can be no assurance as to the liquidity of the trading market for the Exchange Notes or that a trading market for the Exchange Notes will develop.  Please refer to the section in this prospectus entitled “The Exchange Offer – Your Failure to Participate in the Exchange Offer May Have Adverse Consequences”.

The market for the Initial Notes may be significantly more limited after the exchange offer.

Because we anticipate that most holders of Initial Notes will elect to exchange their Initial Notes, we expect that the liquidity of the market for any Initial Notes remaining after the completion of the exchange offer may be substantially limited. Any Initial Notes tendered and exchanged in the exchange offer will reduce the aggregate principal amount of the Initial Notes outstanding. Accordingly, the liquidity of the market for any Initial Notes could be adversely affected and you may be unable to sell them. The extent of the market for the Initial Notes and the availability of price quotations would depend on a number of factors, including the number of holders of Initial Notes, the aggregate principal amount of Initial Notes remaining outstanding and the interest of securities firms in maintaining a market in the Initial Notes. An issue of securities with a smaller number of units available for trading may command a lower, and more volatile, price than would a comparable issue of securities with a larger number of units available for trading; therefore, the market price for the Initial Notes that are not exchanged may be lower and more volatile as a result of the reduction in the aggregate principal amount of the Initial Notes outstanding.  Please refer to the section in this prospectus entitled “The Exchange Offer – Your Failure to Participate in the Exchange Offer May Have Adverse Consequences”.

If you do not properly tender your Initial Notes, you will not receive Exchange Notes in the exchange offer, and you may not be able to sell your Initial Notes.

We intend to register the Exchange Notes, but not the Initial Notes, under the Securities Act.  The Initial Notes may not be offered or sold in the United States except pursuant to an exemption from the registration of the Securities Act and applicable state securities laws or pursuant to an effective registration statement.  The Initial Notes may not be offered or sold in Canada except pursuant to applicable prospectus registration exemptions.  We will issue Exchange Notes only in exchange for Initial Notes that are timely received by the exchange agent, together with all required documents, including a properly completed and duly signed letter of transmittal.  Therefore, you should allow sufficient time to ensure timely delivery of the Initial Notes, and you should carefully follow the instructions on how to tender your Initial Notes.

Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of the Initial Notes.  If you do not tender your Initial Notes or if we do not accept your Initial Notes because you did not tender your Initial Notes properly, then, after we consummate the exchange offer, you will continue to hold Initial Notes that are subject to their existing terms and transfer restrictions.  In general, you may not offer or sell the Initial Notes in the United States unless they are registered under the Securities Act or offered or

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sold in a transaction exempt from, or not subject to, the registration requirements of the Securities Act and applicable state securities laws.

Although we may in the future seek to acquire unexchanged Initial Notes in the open market or through privately negotiated transactions, through subsequent exchange offers or otherwise, we have no present plans to acquire any unexchanged Initial Notes or to file with the SEC a shelf registration statement or a prospectus with any securities regulatory authority in Canada to permit resales of any unexchanged Initial Notes. In addition, holders who do not tender their Initial Notes, except for initial purchasers or holders of Initial Notes who are prohibited by applicable law or SEC policy from participating in the exchange offer, or may not resell the Exchange Notes acquired in the exchange offer without delivering a prospectus and this prospectus is not appropriate or available for such resales by such holders, will not have any further registration rights and will not have the right to receive special interest on their Initial Notes.

Credit ratings may not reflect all risks of an investment in the Exchange Notes and may change.

Credit ratings may not reflect all risks associated with an investment in the Exchange Notes.  Any credit ratings applied to the Exchange Notes are an assessment of our ability to pay our obligations.  Consequently, real or anticipated changes in the credit ratings will generally affect the market value of the Exchange Notes.  The credit ratings, however, may not reflect the potential impact of risks related to structure, market or other factors discussed herein on the value of the Exchange Notes.  There is no assurance that any credit rating assigned to the Exchange Notes will remain in effect for any given period of time or that any rating will not be lowered or withdrawn entirely by the relevant rating agency.

Changes in interest rates may cause the market price or value of the Exchange Notes to decline.

Prevailing interest rates will affect the market price or value of the Exchange Notes.  The market price or value of the Exchange Notes may decline as prevailing interest rates for comparable debt instruments rise, and increase as prevailing interest rates for comparable debt instruments decline.

The Exchange Notes will be structurally subordinate to certain indebtedness of our corporate and partnership subsidiaries.

The Exchange Notes will be our direct, unsecured and unsubordinated obligations and will rank equally and ratably with all of our other unsecured, unsubordinated obligations.  We conduct a substantial portion of business through corporate and partnership subsidiaries.  Our obligations under the Exchange Notes will be structurally subordinate to all existing and future indebtedness and liabilities, including trade payables, of any of our corporate and partnership subsidiaries.

Certain bankruptcy and insolvency laws may impair your ability to enforce your rights or remedies under the Indenture.

Your ability and the rights of any trustee who represents the holders of the Exchange Notes to enforce your rights or remedies under the Indenture may be significantly impaired by the provisions of applicable Canadian federal bankruptcy, insolvency and other restructuring legislation or by Canadian federal or provincial receivership laws. For example, the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada) and the Winding-up and Restructuring Act (Canada) contain provisions enabling an insolvent debtor to obtain a stay of proceedings against its creditors and others and to prepare and file a proposal or a plan of arrangement and reorganization for consideration by all or some of its creditors, to be voted on by the various classes of creditors affected thereby.  Such a restructuring proposal or arrangement and reorganization, if accepted by the requisite majority of each class of affected creditors and if approved by the relevant Canadian court, would be binding on all creditors of the debtor within the affected classes, including those creditors who vote against such a proposal.  Moreover, certain provisions of the relevant Canadian insolvency legislation permit an insolvent debtor to retain possession and administration of its property in certain circumstances, subject to court oversight, even though such debtor may be in default in respect of certain of its obligations during the period that the stay of

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proceedings remains in place.  The powers of the court under Canadian bankruptcy, insolvency and restructuring legislation and Canadian federal and provincial receivership laws, and particularly under the Companies’ Creditors Arrangement Act (Canada), are exercised broadly to protect a debtor and its estate from actions taken by creditors and others.  We cannot predict whether payments under the notes would be made during any proceedings in bankruptcy, receivership, insolvency or other restructuring, whether or when you or any trustee could exercise your rights under the Indenture or whether, and to what extent, the holders of the Exchange Notes would be compensated for any delays in payment of principal, interest and costs, including fees and disbursements of any trustee.  Accordingly, if we were to become subject to such proceedings, we may cease making payments on the Exchange Notes and you and the Trustee (as defined below) may not be able to exercise your rights under the Indenture following commencement of or during such proceedings without leave of the court.

You might have difficulty enforcing your rights against us and our directors and officers.

We are currently organized under the laws of Canada and, accordingly, are governed by the applicable provincial and federal laws of Canada.  A majority of our directors and officers and certain of the experts named in this prospectus reside principally in Canada.  Because we and these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on these persons. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States courts, because a substantial portion of our and their assets are located outside the United States.  We have been advised by Bennett Jones LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based on the United States federal securities laws or the securities laws or “blue sky” laws of any state within the United States and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based on the civil liability provisions of the United States federal securities laws or any such state securities laws or blue sky laws.  Therefore, it may not be possible to enforce those judgments against us, our directors and officers or certain of the experts named in this prospectus.

Certain persons who participate in the exchange offer must deliver a prospectus in connection with resales of the Exchange Notes, failure of which subjects such persons to potential liability under the Securities Act.

In some instances described in this prospectus under “The Exchange Offer – Resale of the Exchange Notes,” you will be obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your Exchange Notes. In those cases, if you transfer any Exchange Notes without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your Exchange Notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability.

Risks relating to the Arrangement

As a result of the Arrangement, any financing that we may require will be obtained on a stand alone basis.

As a result of the Arrangement, we are independent of Encana and any financing that we may require in the future will be obtained by us on a stand alone basis.  In addition, our credit ratings are determined independently of, and without reference to, the historical or current ratings of Encana.  Differences in credit ratings affect the interest rate charged on financings, as well as the amounts of indebtedness, types of financing structures and debt markets that may be available to us.

As a result, we may not be able to secure adequate debt or equity financing or otherwise raise the capital we require on the same terms as Encana (as it existed historically or exists currently), or on desirable terms or at all.

We may be unable to make the changes necessary to operate as an independent entity and may incur greater costs.

As a result of the Arrangement, we separated from the other businesses of Encana and such separation may materially adversely affect us.  We may not be able to implement successfully the changes necessary to operate

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independently.  We may incur additional costs relating to operating independently that could materially affect our cash flow and results of operations.  We require Encana to provide us with certain services (including, but not limited to, information technology services) on a transitional basis.  We may, as a result, be dependent on such services until we are able to provide our own.

The historical financial information of our assets may not be representative of our results as an independent entity, and, therefore, may not be reliable as an indicator of our historical or future results.

Our assets were integrated within the business units of Encana for 11 of the 12 months of 2009; consequently, our financial information has been derived, in substantial part, from the consolidated financial statements and accounting records of Encana and reflect certain assumptions and allocations.  Our financial position, results of operations and cash flows could differ from those that would have resulted had we operated autonomously or as an entity independent of Encana for all of fiscal 2009.

We have a limited operating history as a stand alone entity.

We became an independent public company on November 30, 2009.  The operating history of Encana in respect of our assets cannot be regarded as our operating history.  Our ability to raise capital, satisfy our obligations and provide a return to our shareholders will be dependent upon our future performance.  We will not be able to rely on the capital resources and cash flows of Encana.  Our future operating results and performance may be materially different than those we would have achieved had we been operating as part of Encana.

Risks relating to our Business

A substantial or extended decline in crude oil, natural gas and refined products prices could have a material adverse effect on us.

Our financial performance and condition are substantially dependent on the prevailing prices of crude oil, natural gas and refined products.  Fluctuations in crude oil, natural gas and refined products prices could have an adverse effect on our operations and financial condition, the value and amount of our proved reserves and the value of our refining assets.  Prices for crude oil, natural gas and refined products fluctuate in response to changes in the supply of and demand for crude oil, natural gas and refined products, market uncertainty and a variety of additional factors beyond our control.  Crude oil prices are determined by international supply and demand.  Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil, the price of foreign imports, the availability of alternate fuel sources and weather conditions.  Natural gas prices realized by us are affected primarily by North American supply and demand, weather conditions and by prices of alternate sources of energy (including refined product and imported liquefied natural gas).  Our refined products margins are impacted by, among other things: market competitiveness, the cost of inputs and fluctuations in the supply and demand for refined products.  Any substantial or extended decline in the prices of crude oil, natural gas or refined products could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment in production at some properties or could result in unutilized long-term transportation commitments and low utilization levels at the refineries, all of which could have an adverse effect on our revenues, profitability and cash flows.

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

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We will conduct an annual assessment of the carrying value of our assets in accordance with Canadian GAAP.  If crude oil and natural gas prices decline, the carrying value of our assets could be subject to financial downward revisions and our earnings could be adversely affected.

Our ability to operate and complete projects is dependent on certain factors outside of our control.

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

Current market conditions are challenging with the global recession negatively impacting commodity prices as well as access to credit and capital markets.  These conditions impact our customers and suppliers and may alter our spending and operating plans.  There may be unexpected business impacts from this market uncertainty.

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

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

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

Certain of our operations require us to obtain certain approvals from various regulatory authorities and there can be no assurance that we will be able to obtain all necessary licenses, permits and other approvals that may be required to carry out certain exploration and development activities on our properties.  In addition, obtaining certain approvals 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 satisfaction of certain conditions, including, but not limited to, security deposit obligations, regulatory oversight of projects by third parties, habitat assessments and other commitments or obligations.  Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs, all of which could have a material adverse effect on our business, financial conditions, results of operations and cash flow.

Our crude oil and natural gas reserves data and future net revenue estimates are uncertain.

There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves, including many factors beyond our control.  The reserves data in this prospectus and the documents incorporated by reference in this prospectus represent estimates only.  In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of

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which may vary considerably from actual results.  All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved.  For those reasons, estimates of the economically recoverable bitumen, crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.  Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from such estimates and such variances could be material.

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

Our hedging activities could result in realized and unrealized losses.

The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign exchange rates.  We will monitor our exposure to such fluctuations and, where we deem it appropriate, utilize derivative financial instruments and physical delivery contracts to help mitigate the potential impact of declines in crude oil, natural gas and refined product prices, changes in interest rates and foreign exchange rates.  Under Canadian GAAP, derivative instruments that do not qualify as hedges, or are not designated as hedges, are marked-to-market with changes in fair value recognized in current period net earnings.  The utilization of derivative financial instruments may therefore introduce significant volatility into our reported net earnings.

The terms of our various hedging agreements, if any, may limit the benefit to us of commodity price increases or changes in interest rates and foreign exchange rates.  We may also suffer financial loss because of hedging arrangements if:

·we are unable to produce oil, natural gas or refined products to fulfill delivery obligations; or

·counterparties to our hedging agreements are unable to fulfill their obligations under the hedging agreements.

Our ability to secure and maintain cost effective financing for our capital and other commitments is uncertain.

The nature of our operations will require significant capital commitments; consequently, failure to achieve timely and cost effective financing could have a negative impact on our future plans.  Unpredictable financial markets and associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital markets.

Our business is subject to environmental legislation in all jurisdictions in which we operate and any changes in such legislation could negatively affect our results of operations.

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

Environmental legislation requires that wells, facility sites, refineries and other properties associated with our operations be constructed, operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of

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hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. It also imposes restrictions, liabilities and obligations in connection with the management of fresh or potable water sources that are being used, or whose use is contemplated, in connection with oil and gas operations.  Compliance with environmental legislation can require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties and failure to comply with environmental legislation may result in the imposition of fines and penalties.  Although it is not expected that the costs of complying with environmental legislation will have a material adverse effect on our financial condition or results of operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect.

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas emissions and other air pollutants and a number of legislative and regulatory measures to address greenhouse gas emissions are in various phases of review, discussion or implementation in the United States and Canada.  These include proposed federal legislation and state actions in the United States to develop statewide or regional programs, each of which could impose reductions in greenhouse gas emissions.

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

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

If we fail to acquire or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels.

Our future crude oil and natural gas reserves and production, and therefore our cash flows, are highly dependent upon our success in exploiting our current resource base and acquiring, discovering or developing additional reserves.  Without reserves additions through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are depleted.  The business of exploring for, developing or acquiring reserves is capital intensive.  To the extent cash from operating activities is insufficient and external sources of capital become limited, our ability to make the necessary capital investments to maintain and expand 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 acquire additional reserves to replace production at acceptable costs.

Our operations are subject to the risk of business interruption and casualty losses.

Our business is subject to all of the operating risks normally associated with the exploration for, development of and production of crude oil and natural gas and the operation of refining facilities.  These risks include, but are not limited to, blowouts, explosions, fire, gaseous leaks, migration of harmful substances and crude oil and refined products spills, acts of vandalism and terrorism, any of which could cause personal injury, result in damage to, or destruction of, crude oil and natural gas wells or formations or production facilities or refineries and other property, equipment and the environment, as well as interrupt operations.  In addition, all of our operations are subject to all of the 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 and development of crude oil and natural gas properties, including, among others, encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment

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failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks.

The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position.

We do not operate all of our properties and assets.

Other companies operate a portion of the assets in which we have interests.  We have limited ability to exercise influence over operations of these assets or their associated costs.  Our dependence on the operator and other working interest owners for these properties and assets and our limited ability to influence operations and associated costs could materially adversely affect our financial performance.  The success and timing of our activities on assets operated by others therefore depends upon a number of factors that are outside of our control, including: timing and amount of capital expenditures; timing and amount of operating and maintenance expenditures; the operator’s expertise and financial resources; approval of other participants; selection of technology; and risk management practices.

All of our downstream operations are operated by ConocoPhillips.  The success of our downstream operations is dependant on the ability of ConocoPhillips to successfully operate this business and maintain the operations of the refineries.

We are exposed to risks associated with the use of current technology, and the pursuit of new technology, which could negatively affect our results of operations.

Current SAGD technologies for enhanced recovery of heavy oil are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery process.  The amount of steam required in the production process can also vary and affect costs.  The performance of the reservoir can also affect the timing and levels of production using this technology.  A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our results of operations.

There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations.  The success of projects incorporating new technologies cannot be assured.

There are a number of risks particular to oil recovery operations that could have a material adverse impact on us.

Producing oil through enhanced recovery methods and upgrading and refining heavy oil requires high levels of investment and involves particular risks and uncertainties.  Our oil operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems.  While there are virtually no finding costs associated with bitumen resources, delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with upgrading heavy oil can entail significant capital outlays.  The costs 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.

Fluctuations in exchange rates 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 our expenses outside of the U.S. will be denominated in Canadian dollars.  Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could impact our expenses and have an adverse effect on our financial performance and condition.

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We may become subject to claims by third parties.

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

We may be adversely affected by certain terms of the Separation Agreement.

Pursuant to the Separation Agreement, Encana and Cenovus have each agreed to cooperate fully with each other and our respective counsels in the investigation, prosecution, defense and resolution of certain litigation matters, including without limitation, certain judicial actions to which Encana is a party relating to the entitlement to CBM (collectively, the "Joint Litigation").  The possible impacts and effects of such agreement are uncertain.  Our obligation to cooperate fully with Encana and its counsel in respect of the Joint Litigation and the limitation this may place on the position that Cenovus may otherwise wish to take with respect to these matters may have an adverse affect on Cenovus.  The outcome of any of the Joint Litigation matters cannot be predicted and may materially impact our financial condition or results of operations. In addition, the existence of such agreement and our obligations thereunder may have an affect on the manner in which we determine to conduct our business or operations until such time that all of the Joint Litigation is resolved.

We have certain post-Arrangement indemnification and other obligations under each of the Arrangement Agreement and Separation Agreement.

Encana and Cenovus have agreed to indemnify each other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of our indemnity, the Cenovus Businesses and the Cenovus Assets.  At the present time, we cannot determine whether we will have to indemnify Encana for any substantial obligations under the terms of the Arrangement.  We also cannot assure that if Encana has to indemnify Cenovus and our affiliates for any substantial obligations, Encana will be able to satisfy such obligations.

In connection with the Arrangement, Encana and Cenovus entered into the Arrangement Agreement which contains a number of representations, warranties and covenants, including agreement by each of the parties to indemnify and hold harmless each other against any loss suffered 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 to take any action or enter into any transaction that could adversely impact the Canadian Tax Ruling or the U.S. Tax Ruling.  With respect to Canadian income taxation, there are a variety of transactions that the parties were or are prohibited from undertaking prior to and after the implementation of the Arrangement.  One of these is that, following the Arrangement, no party is permitted to dispose of or exchange property having a fair market value greater than ten percent of the fair market value of its property, or undergo an acquisition of control where such disposition of property or control acquisition is, for Canadian tax purposes, part of the “series of transactions or events” that includes the Arrangement, except in limited circumstances.

Under the Separation Agreement: (i) we have agreed to indemnify Encana and its affiliates from and against any liabilities associated with, among other things, the Cenovus Assets and Cenovus Businesses, whether relating to the period, or arising, prior to or after the Reorganization Time; and (ii) Encana has agreed to indemnify us and our affiliates from and against any liabilities associated with, among other things, the assets owned by Encana or any affiliate of Encana and the businesses carried on by Encana or any affiliate of Encana after the Reorganization Time, whether relating to the period, or arising, prior to or after the Reorganization Time.

Any indemnification claim against us pursuant to the provisions of the Arrangement Agreement or Separation Agreement could have a material adverse effect.

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Our success is dependent on successful recruitment, retention and succession.

Our success is dependent upon our management and the quality of our personnel.  Failure to retain current employees or to attract and retain new employees with the necessary skills could have a material adverse effect on our growth and profitability.  Although the demand for personnel has recently reduced, competition for key oil and gas professionals remains high.

Our ability to operate is dependent upon a variety of information systems.

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

Other Risk Factors

A discussion of additional risks which may impact our business, prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found in our Annual Information Form dated February 18, 2010 and Management’s Discussion and Analysis for the year ended December 31, 2009 and the three month period ended March 31, 2010 included in or incorporated by reference in this prospectus and which are accessible on our SEDAR profile at www.sedar.com and on EDGAR at www.sec.gov.

CREDIT RATINGS

The Exchange Notes have been assigned a rating of “BBB+” by S&P, a rating of “Baa2”(Stable) by Moody’s and a rating of “A(low)”(Stable) by DBRS.  S&P assigns an outlook to the issuer of securities and not to individual debt instruments; S&P has assigned Cenovus a corporate credit rating of “BBB+” (Stable).

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

S&P’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated.  A rating of BBB+ by S&P is within the fourth highest of ten categories and indicates that the obligation exhibits adequate protection parameters.  However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.  The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within the major rating categories.

Moody’s long-term credit ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated.  A rating of Baa2 by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are considered medium-grade (i.e., they are subject to moderate credit risk).  Such debt securities may possess certain speculative characteristics.  The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category.  The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking in the lower end of that generic rating category.

DBRS’s long-term credit ratings are on a rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of A(low) by DBRS is within the third highest of ten categories and is assigned to debt securities considered to be of satisfactory credit quality.  Protection of interest and principal is substantial, but the degree of strength is less than that of higher rated securities.  Entities in the A category are considered to be more susceptible to adverse economic conditions and have greater cyclical

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tendencies than higher-rated securities.  The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category.

USE OF PROCEEDS

We will not receive any proceeds from the issuance of the Exchange Notes.  We are making this exchange offer solely to satisfy our obligations under the Registration Rights Agreement.

INTEREST COVERAGE

The following sets forth our interest coverage ratios calculated for the twelve month periods ended December 31, 2009, based on audited financial information, and March 31, 2010, based on unaudited financial information.  The interest coverage ratios set forth below do not purport to be indicative of the interest coverage ratios for any future periods.  The interest coverage ratios have been calculated based on information contained within the financial statements for the related periods prepared in accordance with Canadian GAAP.

Our interest requirements, after giving effect to the issue of the Initial Notes and the exchange of the Initial Notes for the Exchange Notes, amounted to US$187 million and C$223 million for the twelve months ended December 31, 2009 and March 31, 2010, respectively.  Our net earnings before interest on long-term debt and income taxes for the twelve months ended December 31, 2009 and March 31, 2010 was US$1,137 million and C$1,436 million, respectively.

	December 31, 2009	March 31, 2010
Interest coverage on long-term debt(1):
Net earnings(2)	6.1 times	6.4 times

Notes:

(1)Long-term debt includes the current portion of long-term debt.

(2)Interest coverage on long-term debt on a net earnings basis is equal to net earnings before interest on long-term debt and income taxes divided by interest expense on long-term debt.

CAPITALIZATION

Since March 31, 2010, there has been no material change in our consolidated capitalization.  As we will realize no proceeds from the exchange offer, the completion of the exchange offer will have no material change on our consolidated capitalization.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table provides Cenovus’s selected financial data as at and for the years ended December 31, 2009 and December 31, 2008 and as at and for the three month periods ended March 31, 2010 and March 31, 2009.  The financial data as at and for the years ended December 31, 2009 and 2008 has been derived from Cenovus’s audited consolidated financial statements for the corresponding period.  The financial data for the three month periods ended March 31, 2010 and 2009 has been derived from Cenovus’s unaudited consolidated financial statements for the corresponding period.

The unaudited consolidated financial statements have been prepared on the same basis as Cenovus’s audited financial statements except as described in notes to those financial statements.  Cenovus believes that the unaudited consolidated financial statements contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments).  The historical financial data for the interim period is not necessarily indicative of the results that may be expected for Cenovus’s full year of operations.  The summary consolidated financial information should be read in conjunction with the corresponding historical consolidated financial statements and related “Management’s Discussion and Analysis” included elsewhere in this prospectus.

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Cenovus’s financial statements have been prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP.  The notes to our audited consolidated financial statements for the year ended December 31, 2009 contain a discussion of the principal differences between the financial results calculated under Canadian GAAP and under U.S. GAAP.

Our audited consolidated financial statements for the year ended December 31, 2009, and periods prior thereto, are expressed in U.S. dollars.  All of our consolidated financial statements for periods ended subsequent to December 31, 2009 are expressed in Canadian dollars.

	C$ millions		US$ millions
Consolidated Statement of Earnings	Three Months Ended March 31, 2010 (unaudited)	Three Months Ended March 31, 2009 (unaudited)	Year Ended December 31, 2009	Year Ended December 31, 2008
Net revenues	3,491	2,693	10,140	16,559
Expenses
Production and mineral taxes	12	13	38	75
Transportation and selling	291	166	672	963
Operating	348	364	1,154	1,223
Purchased product	1,765	1,136	5,250	9,710
Depreciation, depletion and amortization	324	380	1,343	1,318
General and administrative	52	41	188	167
Interest, net	65	45	218	218
Accretion of asset retirement obligation	22	11	39	39
Foreign exchange (gain) loss, net	(27)	(52)	290	(250)
Other (income) loss, net	(1)	-	(2)	3
Income tax expense	115	74	302	725
Net earnings	525	515	648	2,368
Consolidated Statement of Cash Flows (in millions)
Cash from Operating Activities	820	682	3,469	2,687
Capital Expenditures	493	652	1,895	2,046
Other Financial Data
Adjusted EBITDA(1)	1,023	973	2,838	4,421

Balance Sheet (C$ millions)	March 31, 2010 (unaudited)	March 31, 2009 (unaudited)
Working capital	717	469
Total assets	22,181	21,755
Long-term debt (including current portion)	3,494	3,656
Total Shareholders’ Equity/Total Net Investment	9,901	9,608

Note:

(1)Adjusted EBITDA represents Net earnings before Income tax expense, Loss on divestitures, Foreign exchange loss, net, Accretion of asset retirement obligation, Interest, net and Depreciation, depletion and amortization. Adjusted EBITDA is not a measure that has any standardized meaning prescribed by Canadian GAAP and is considered a non-GAAP measure. Therefore, this measure may not be comparable to similar measures presented by other issuers. Adjusted EBITDA is presented in order to provide additional information regarding our liquidity and our ability to generate funds to finance our operations. Adjusted EBITDA should not be considered an alternative to net earnings, cash from operating activities or other measures of financial performance calculated in accordance with Canadian GAAP.

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The following table provides a reconciliation of adjusted EBITDA from net earnings (in millions):

	C$ millions		US$ millions
(unaudited)	Three Months ended March 31, 2010	Three Months Ended March 31, 2009	Year Ended December 31, 2009	Year Ended December 31, 2008
Net earnings	525	515	648	2,368
Add (Deduct):
Interest, net	65	45	218	218
Income tax expense	115	74	302	725
Depreciation, depletion and amortization	324	380	1,343	1,318
Accretion of asset retirement obligation	22	11	39	39
Foreign exchange (gain) loss, net	(27)	(52)	290	(250)
Other (income) loss, net	(1)	-	(2)	3
Adjusted EBITDA	1,023	973	2,838	4,421

SUMMARY OPERATING AND RESERVES INFORMATION

The following tables set forth summary operating and reserves information for the periods indicated.

	Three Months Ended March 31, 2010	Year Ended December 31, 2009	Year Ended December 31, 2008
Production, before Royalties
Crude Oil and NGLs (bbls/d)	130,549	121,838	112,803
Natural gas (MMcf/d)	775	837	954
Proved Reserves, before Royalties
Crude Oil and NGLs (MMbbls)		277	276
Natural Gas (Bcf)		1,529	1,937
Bitumen (MMbbls)		866	699

The following table summarizes the combined refineries’ key operational results for the periods indicated.

Refinery Operations(1)	Three Months Ended March 31, 2010	Year Ended December 31, 2009	Year Ended December 31, 2008
Crude Oil Capacity (Mbbls/d)	452	452	452
Crude Oil Runs (Mbbls/d)	355	394	423
Crude Utilization	79%	87%	93%
Refined Products (Mbbls/d)
Gasoline	206	223	230
Distillates	104	120	139
Other	67	74	79
Total	377	417	448

Note:

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

CORPORATE STRUCTURE

Cenovus Energy Inc. was incorporated on September 24, 2008 under the CBCA as 7050372 Canada Inc.  Pursuant to the Arrangement, 7050372 and Subco amalgamated under the CBCA on the Effective Date with the amalgamated company’s name being “Cenovus Energy Inc.”  Our executive and registered office is located at 4000, 421 – 7th Avenue S.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 further description of the Arrangement, see “General Development of Our Business – The Arrangement”.

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Intercorporate Relationships

We have the following principal subsidiaries and partnerships which have total assets that exceed ten percent of our total consolidated assets or sales and revenues which exceed ten percent of our total consolidated sales and revenues as at and for the period ended March 31, 2010:

Subsidiaries & Partnerships	Percentage Owned(1)	Jurisdiction of Incorporation, Continuance, Formation or Organization
Cenovus FCCL Ltd.	100	Alberta
FCCL Partnership	50	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 all of our subsidiaries and partnerships.  The assets and revenues of our unnamed subsidiaries and partnerships did not exceed 20 percent of our total consolidated assets or total consolidated sales and revenues as at and for the period ended March 31, 2010.

GENERAL DEVELOPMENT OF OUR BUSINESS

Cenovus is an integrated oil company headquartered in Calgary, Alberta.  Our operations include EOR properties and established crude oil and natural gas production in Alberta and Saskatchewan.  We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the split of Encana into two independent publicly traded energy companies – Cenovus and Encana. Although we are a new company, we have operated a number of our assets for decades.

The Arrangement

The division of Encana into two highly focused and independent publicly traded energy companies was completed on November 30, 2009.  It resulted in, among other things, the establishment of our company as an independent integrated oil company anchored by stable production and cash flow from well-established crude oil and natural gas plays, integrated from crude oil production through to refined products.

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

·those assets associated with Encana’s Integrated Oil Division, which included Encana’s interests in the Foster Creek, Christina Lake, Narrows Lake and Borealis areas and the U.S. refinery interests in addition to certain of Encana’s other bitumen interests and natural gas assets located in the Athabasca area;

·those assets associated with Encana’s Canadian Plains Division, which included the majority of Encana’s legacy oil and natural gas assets in southern Alberta and Saskatchewan.  This Division included the EOR properties located at Weyburn and Pelican Lake, as well as the Southern Alberta oil and gas properties; and

·those assets associated with the foregoing businesses, including marketing, corporate and office space (including a proportionate share of The Bow office project).

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Pursuant to the Pre-Arrangement Reorganization in connection with the Arrangement, Encana transferred the Cenovus Assets to Subco in exchange for, among other things, the Demand Note.

The Assumed Liabilities assumed, directly or indirectly, in connection with the Arrangement included, among others, those liabilities relating to Encana’s Integrated Oil and Canadian Plains Divisions described above.

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

In connection with the Arrangement and in order to provide ongoing liquidity, including working capital requirements, prior to the completion of the Arrangement, we obtained commitments from a syndicate of banks to make available an unsecured credit facility in the amount of C$2.5 billion.  The revolving syndicated credit facility consists of two tranches, a C$2.0 billion three-year tranche and a C$500 million 364-day tranche.  The terms of each of these facilities commenced on the Effective Date.

On the Issue Date, a predecessor entity of Cenovus completed, in three tranches, the Cenovus Note Offering.  See “Prior Sales”.  The net proceeds of the Cenovus Note Offering were placed into an escrow account pending the completion of the Arrangement.  Upon completion of the Arrangement, the net proceeds, together with other pre-funded amounts, were released from escrow and were applied to repay all of the amounts outstanding under the Demand Note.

Our Business

Our operations are organized into two operating divisions:

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

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

For financial statement reporting purposes, our operating and reportable segments are:

Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and NGLs and other related activities in Canada.  This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips, an unrelated U.S. public company, and operated by Cenovus.

Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States.  The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.

Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities.  As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates.  Eliminations relate to sales and operating revenues and purchased product between

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segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

In addition to the Arrangement, the following describes the significant events of the last three years in respect of our business:

2009

In the first quarter 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 production capacity, increasing the total production capacity of Foster Creek to approximately 120,000 barrels per day.

In the second quarter of 2009, a joint regulatory application for Foster Creek phases F, G and H was submitted to the ERCB and Alberta Environment.  Each phase is expected to increase production capacity by 30,000 barrels per day of bitumen.

In the fourth quarter of 2009, FCCL sanctioned the next phase, phase D, of expansion at Christina Lake, which is expected to increase production capacity by 40,000 barrels per day of bitumen in 2013.

In the fourth quarter of 2009, a joint regulatory application for Christina Lake phases E, F and G was submitted to the ERCB and Alberta Environment.  Each phase is expected to increase 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 added 8,000 barrels per day of production capacity, increasing the total production capacity at Christina Lake to approximately 18,000 barrels per day of bitumen.

In the third quarter of 2008, the Wood River refinery received regulatory approvals to start construction on the CORE project.  Our 50 percent share of the CORE project is expected to cost approximately $1.8 billion and is anticipated to be completed and in operation in 2011.  The expansion is expected to more than double heavy crude oil refining capacity to approximately 240,000 barrels per day and increase crude oil refining capacity by 50,000 barrels per day to approximately 356,000 barrels per day.

2007

The creation of the integrated oil business venture, consisting of upstream and downstream assets, with ConocoPhillips was completed on January 3, 2007.  It is comprised of two 50-50 operating entities, a Canadian upstream enterprise operated by Cenovus and a U.S. downstream enterprise operated by ConocoPhillips, with both ConocoPhillips and Cenovus having contributed equally valued assets and equity.  The integrated oil business provides greater certainty of execution for our Foster Creek and Christina Lake EOR projects and allows us to participate in the full value chain from crude oil production through to refined products.

In the first quarter of 2007, Foster Creek phase C expansion was commissioned.  This phase added 30,000 barrels per day of production capacity, increasing the total production capacity at Foster Creek to approximately 60,000 barrels per day of bitumen.

In the second quarter of 2007, a 25,000 barrel per day coker addition at the Borger refinery was completed. The refinery was shut down for approximately one month to complete a major planned turnaround timed to coincide with bringing the new coker online.  The refinery started up again in June 2007 and ran its first barrel of Canadian heavy oil on July 10, 2007, marking a major milestone for the refinery.

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In the third quarter of 2007, regulatory approval and sanctioning was received for the Christina Lake phase C expansion, which is expected to increase production capacity by 40,000 barrels per day of bitumen in 2011.

In the fourth quarter of 2007, a joint regulatory application for development of the Borealis property was submitted to the ERCB and Alberta Environment that would allow for the construction of a SAGD facility with production capacity of approximately 35,000 barrels per day of bitumen.

NARRATIVE DESCRIPTION OF OUR BUSINESS

One hundred 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 a proved reserves base (our share after royalties) of approximately 719 million barrels of bitumen reserves, 232 million barrels of crude oil and NGLs reserves and 1,474 billion cubic feet of natural gas reserves.  The estimated proved reserves life index as at December 31, 2009 was approximately 14.7 years.  We also had probable reserves (our share after royalties) of approximately 403 million barrels of bitumen, 127 million barrels of crude oil and NGLs and 405 billion cubic feet of natural gas as at December 31, 2009.

The following narrative describes each of our operating divisions in greater detail.

Integrated Oil Division

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

As at December 31, 2009, we held bitumen rights of approximately 1,055,000 gross acres (760,000 net acres) within the Athabasca and Cold Lake areas, as well as the exclusive rights to lease an additional 652,000 net acres on our behalf and/or our assignee’s behalf on the Cold Lake Air Weapons Range.

The following 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)Under an area of mutual interest arrangement, ConocoPhillips made an election to participate in a certain Cenovus lease acquisition through ConocoPhillips’s interest in FCCL, reducing Cenovus’s working interest share to 50 percent on January 1, 2010.

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The following table sets forth our share of daily average production figures for the periods indicated.

	Crude Oil
	and NGLs		Natural Gas		Total Production
Production (annual average)	(bbls/d)		(MMcf/d)		(BOE/d)
	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

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

	Producing Oil Wells		Producing Gas Wells		Total 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

The following describes major producing areas or activities in the Integrated Oil Division.

Integrated Oil Business

On January 3, 2007, the creation of the integrated oil business with ConocoPhillips was completed.  The integrated oil business includes Canadian upstream assets contributed by Cenovus and U.S. downstream assets contributed by ConocoPhillips.  The business is comprised of two 50-50 operating entities, a Canadian upstream entity, FCCL, operated by Cenovus and a U.S. downstream enterprise, WRB, operated by ConocoPhillips.

FCCL owns the Foster Creek and Christina Lake EOR projects.  Cenovus FCCL Ltd., our wholly-owned subsidiary, is the operating and managing partner of FCCL.  WRB owns the Wood River and Borger refineries.  ConocoPhillips held a disproportionate economic interest in the Borger refinery of 85 percent in 2007 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 our representatives and three of ConocoPhillips’s representatives, with each company holding equal voting rights.

At December 31, 2009, the combined production capacity of the Foster Creek and Christina Lake properties was approximately 138,000 barrels per day.  FCCL plans to increase production capacity to approximately 218,000 barrels of bitumen per day from the combined facilities at Foster Creek and Christina Lake with the completion of the Christina Lake phase C expansion in 2011 and phase D expansion in 2013.

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

Foster Creek

We have a 50 percent interest in Foster Creek, an EOR property which uses SAGD technology and produces from the McMurray formation.  We hold surface access rights from the Governments of Canada and

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Alberta and bitumen rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range which were granted by the Government of Alberta.  In addition, we hold exclusive rights to lease several hundred thousand acres of bitumen rights in other areas on the Cold Lake Air Weapons Range on our behalf and/or our assignee’s behalf.  In the first quarter of 2009, two new expansion phases were completed at Foster Creek adding production capacity of approximately 60,000 barrels of bitumen per day and increasing total production capacity to approximately 120,000 barrels of bitumen per day.

We continually 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 new pump designs that are expected to enable us to optimize SAGD performance by operating at lower pressures, thereby realizing lower steam-oil ratios and decreasing facility capital and operating costs.  As at December 31, 2009, electrical submersible pumps were in use on 133 wells at Foster Creek and we expect to continue to utilize this technology on new SAGD wells.

In addition, we have successfully piloted another technology at Foster Creek whereby an additional well, a wedge well, is drilled between two producing well pairs to produce bitumen that is heated by proximity to a steam chamber, but is not recoverable by the adjacent production wells.  We have received a U.S. and Canadian patent for this technology.  This technology requires no additional steam, thus it helps reduce the overall steam-oil ratio.  In 2009, we drilled 18 wedge wells (2008 – four wells).  As at December 31, 2009, there were 27 wedge wells producing.  This process is being piloted at our Christina Lake property.

We also focus on reducing our reliance on natural gas for the generation of steam used in SAGD production operations.  The Solvent Aided Process (“SAP”) is discussed under “Christina Lake” below.

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

Christina Lake

We have a 50 percent interest in a SAGD EOR project at Christina Lake which produces from the McMurray formation. During 2008, the phase B expansion was completed which increased production capacity to approximately 18,000 barrels of bitumen per day.

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

During the 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 of bitumen production capacity at Christina Lake.  We have accelerated the completion of phase D by six months and it is expected to be completed in mid-2013. Regulatory approval for this additional phase was received in 2008.

There have been several innovations to SAGD technology that have been undertaken at Christina Lake over the past several years.  One major project that started in 2009 is a new SAP pilot.  This SAP pilot utilizes a mixture of steam and solvent to enhance recovery of the bitumen by reducing the steam-oil ratio and increasing the overall recovery of the oil in place.  Business cases are currently being evaluated for the potential use of this technology in the Christina Lake and Narrows Lake development plans.

Another innovation was undertaken in 2007, whereby a remote water disposal system was utilized to successfully manage bottom water pressures and further reduce the steam-oil ratio.

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Narrows Lake

We hold a 50 percent interest in the Narrows Lake area which is located within the greater Christina Lake regional area.  We are preparing development plans and regulatory applications for a project at Narrows Lake that would include two to three phases with each phase expected to add approximately 40,000 barrels per day of bitumen production capacity.

Wood River Refinery

We have a 50 percent interest in the Wood River refinery, located in Roxana, Illinois.  As at December 31, 2009, the Wood River refinery had a processing capacity of approximately 306,000 barrels per day of crude oil.  It processes light, low-sulphur and heavy, high-sulphur crude oil that it receives from North American crude oil pipelines to produce gasoline, diesel and jet fuel, petrochemical feedstocks and asphalt.  The gasoline and diesel are transported via pipelines to markets in the upper Midwest.  Other products are transported via pipeline, truck, barge and railcar to markets in the Midwest.  In 2007, the refinery completed the construction of a proprietary sulphur removal unit that produces low-sulphur gasoline.  In September 2008, regulatory approval was received to proceed with the CORE project at Wood River which is expected to increase crude oil refining capacity by approximately 50,000 barrels per day, increase coking capacity by approximately 65,000 barrels per day, more than double heavy crude oil refining capacity to approximately 240,000 barrels per day and increase the clean transportation fuels yield by approximately ten percent to approximately 89 percent.  Capital expenditures for the CORE project are estimated at $3.6 billion ($1.8 billion net to Cenovus) and the project is scheduled to be completed in 2011.  At December 31, 2009, the CORE project was 71 percent complete, on schedule and on budget.

Borger Refinery

We have a 50 percent interest in the Borger refinery, located in Borger, Texas.  As at December 31, 2009, the Borger refinery had a processing capacity of approximately 146,000 barrels per day of crude oil and approximately 45,000 barrels per day of NGLs.  It processes mainly medium, high-sulphur and heavy, high-sulphur crude oil and NGLs that it receives from North American pipeline systems to produce gasoline, diesel and jet fuel along with NGLs and solvents.  The refined products are transported via pipelines to markets 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 was brought into service along with a new vacuum unit and revamped gas, oil and distillate hydrotreaters.  This project has enabled the refinery to process heavy oil blends, particularly Canadian heavy oil, and comply with clean fuel regulations for ultra-low sulphur diesel and low-sulphur gasoline.  The project has also enabled compliance with required reductions of sulphur dioxide and other air emissions.

The following table summarizes the combined refineries’ key operational results for the 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 and Borger refinery operations.

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Other Integrated Oil Division Properties

Borealis

We hold a 100 percent working interest in the Borealis area, which is located approximately 90 kilometres northeast of Fort McMurray.  Borealis is not included in the integrated oil business with ConocoPhillips.  Approximately 200 delineation wells have been drilled in the greater Borealis area as at December 31, 2009.  A joint application for development has been submitted to the ERCB and Alberta Environment that would allow for the construction of a SAGD facility with production capacity of approximately 35,000 barrels of bitumen per day.  We continue to evaluate the greater Borealis area in support of the development application.

Athabasca Gas

We produce natural gas from the Cold Lake Air Weapons Range and several surrounding landholdings located in northeast Alberta and hold surface access and natural gas rights for exploration, development and transportation from areas within the Cold Lake Air Weapons Range that were granted by the Governments of Canada and Alberta.  The majority of our natural gas production in the area is processed through wholly-owned and operated compression facilities.

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

Canadian Plains Division

The Canadian Plains Division encompasses crude oil development and production activities in Alberta and Saskatchewan, as well as established natural gas development and production activities in both southern and northern Alberta and southern Saskatchewan.  Three major properties are located in the Canadian Plains Division: EOR projects at Pelican Lake and Weyburn, as well as conventional oil and natural gas in Southern Alberta.  The Division also markets crude oil and natural gas, including third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

As at December 31, 2009, the Canadian Plains Division had an established land position of approximately 6.7 million gross acres (6.3 million net acres), of which approximately 4.3 million gross acres (4.1 million net acres) are developed.  The mineral rights on approximately 50 percent of the total net acreage are owned in fee title by Cenovus, which means that production is subject to a mineral tax that is generally less than the Crown royalty imposed on production from land where the government owns the mineral rights.  In 2009, the Canadian Plains Division had capital investment of approximately $478 million and drilled approximately 614 net wells.  Of our capital expenditures, 56 percent was oil focused, while 43 percent of the capital expenditure was natural gas focused.

Plans for 2010 include further EOR initiatives, continued drilling, well optimizations, well recompletions (including CBM) and investment in facility infrastructure necessary for continued development.

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The following table summarizes the landholdings for the Canadian Plains 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
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%

The following table sets forth our share of daily average production figures for the periods indicated.

Production (annual average)	Crude Oil and NGLs (bbls/d)		Natural Gas (MMcf/d)		Total Production (BOE/d)
	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

The following table summarizes the Canadian Plains Division’s interests in producing wells as at December 31, 2009.  These figures exclude wells which were capable of producing, but that were not producing, as of December 31, 2009.

Producing Wells (number of wells)	Producing Oil Wells		Producing Gas Wells		Total Producing 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 major producing areas or activities in the Canadian Plains Division.

Weyburn

We have a 62 percent working interest (50 percent economic interest) in the unitized portion of the Weyburn crude oil field in southeast Saskatchewan.  The Weyburn unit produces light and medium sour crude from the Mississippian Midale formation and covers 78 sections of land.  Cenovus is the operator and we are increasing ultimate recovery in the EOR area of the field with a CO2 miscible flood project.  As at December 31, 2009, approximately 70 percent of the approved and planned CO2 flood pattern development at the Weyburn unit was complete.  Since the inception of the project, approximately 15 million tonnes of CO2 have been injected as part of the EOR program.  We estimate that another 15 million tonnes will be injected as part of the EOR project.  The CO2 is delivered by pipeline directly to the Weyburn facility from a coal gasification project in North Dakota.

Pelican Lake

Pelican Lake produces heavy crude oil from the Cretaceous Wabiskaw formation in northeast Alberta through horizontally drilled waterflood and polymer EOR methods.  Facility infrastructure expansion in this area continued in 2009 to accommodate higher total fluid production volumes associated with its waterflood and polymer projects.  The polymer flood program was expanded by 50 injection wells during 2009.

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

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

In August 2008, we entered into an agreement with Pembina Pipeline Corporation (“Pembina”) to transport blended heavy oil from Utikuma, Alberta to Edmonton, Alberta via Pembina’s 100,000 barrels per day capacity pipeline.  This pipeline will be used to transport heavy oil from our Pelican Lake property to crude oil markets.  The parties also agreed to transport condensate, used as diluent for transporting heavy oil, from Whitecourt, Alberta to Utikuma, Alberta via a 22,000 barrel per day capacity pipeline.  The initial term of the agreement is ten years from the in-service date, which is estimated to be in mid-2011.

Southern Alberta

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

Southern Alberta – Oil Properties

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

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The following table sets forth net oil wells drilled and daily average oil production figures for the periods indicated.

Net Wells Drilled and Production (annual average)	Net Wells Drilled		Light/Medium (bbls/d)		Heavy Oil (bbls/d)
	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 – Natural Gas Properties

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

Development in this area focuses on infill drilling up to 16 wells per section, recompletions and optimization of existing wells.

The following table sets forth net gas wells drilled and daily average gas production figures for the periods indicated.

Net Wells Drilled and Production (annual average)	Net Wells Drilled		Gas Production (MMcf/d)
	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 and Langevin area lands is the Belly River Cretaceous formation where Cenovus is producing CBM.  In 2009, approximately 500 wells were recompleted which added approximately 14 million cubic feet per day of natural gas production by the end of the year.  The CBM assets are long-life and low decline and are expected to generate production for future growth in a capital efficient manner.

Suffield is one of the core areas of our Southern Alberta major property.  The Suffield area is largely made up of the Suffield Block, where operations are carried out pursuant to an agreement among Cenovus, the Government of Canada and the Province of Alberta governing surface access to CFB Suffield.  In 1999, the parties agreed to permit access to the Suffield military training area to additional operators.  Our predecessor companies, Alberta Energy Company Ltd. and Encana Corporation, have operated at CFB Suffield for over 30 years.  On October 6, 2008, pursuant to the Canadian Environmental Assessment Act, a joint review panel (“JRP”), made up of provincial and federal regulators, heard our application 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 that the proposed project could proceed provided two key pre-conditions were met: first, critical habitat assessments for certain specific species of plants and animals must be finalized by Environment Canada within the NWA; and second, the role of the Suffield Environmental Advisory Committee (“SEAC”) must be clarified by the parties to the surface access agreement, and SEAC must be resourced adequately to provide proper environmental oversight of the project.  The JRP also concluded that other mitigations and recommendations should be followed once the two key pre-conditions were met.  We are working with necessary interested parties to proceed with this project.

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Other Properties

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

We also hold interests in other conventional oil and natural gas producing properties, primarily located in east central and northern Alberta.

Crude Oil and Natural Gas Marketing

Our Marketing group is focused on enhancing the netback price of our proprietary production.  Canadian Plains divisional results include third-party purchases and sales of product to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.  The Marketing and Power group is also focused on ensuring reliable sourcing and lowest delivered cost of power at the field level.

We also seek to mitigate the market risk associated with future cash flows by entering into various risk management contracts relating to produced products.  Details of those transactions related to our various risk management positions for crude oil, natural gas and power are found in the notes to our consolidated financial statements incorporated or deemed to be incorporated by reference in this prospectus.

Crude Oil Marketing

We manage the transportation and marketing of crude oil for our upstream operating divisions.  Our objective is to sell production to achieve the best price within the constraints of a diverse sales portfolio, as well as to obtain and manage condensate supply, inventory and storage to meet diluent requirements.  During 2009, our blend volumes on behalf of FCCL were 120,894 barrels per day (2008 – 80,866 barrels per day), while our non-partnership blend volumes were 78,303 barrels per day (2008 – 86,560 barrels per day).

Natural Gas Marketing

Our natural gas is primarily marketed to industrials, other producers and energy marketing companies.  In 2009, approximately 25 percent of our sales of natural gas were directly marketed by us to industrials.  The remaining 75 percent of sales of natural gas were marketed to other producers and energy marketing companies.  Prices received by us are based primarily upon prevailing index prices for natural gas.  Prices are impacted by competing fuels in such markets and by North American regional supply and demand for natural gas.

GENERAL

Competitive Conditions

All aspects of the oil and gas industry are highly competitive and we actively compete with other companies, particularly in the following areas: (i) exploration for and development of new sources of bitumen, crude oil and natural gas reserves; (ii) reserves and property acquisitions; (iii) transportation and marketing of oil, natural gas, NGLs, diluents and electricity; (iv) supply of refinery feedstock and the market for refined products; (v) access to services and equipment to carry out exploration, development or operating activities; and (vi) attracting and retaining experienced industry personnel.  The oil and gas industry also competes with other industries that provide alternative forms of energy to consumers.  Competitive forces can lead to cost increases or result in an oversupply of oil and natural gas, both of which could have a negative impact on our financial results.

Environmental Protection

Our operations are subject to laws and regulations concerning protection of the environment, pollution and the handling and transport of hazardous materials.  These laws and regulations generally require us to remove or remedy the effect of our activities on the environment at present and former operating sites, including dismantling

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production facilities and remediating damage caused by the use or release of specified substances.  The Safety, Environment and Responsibility Committee of our Board reviews and recommends to our Board for approval environmental policies and oversees compliance with government laws and regulations.  Monitoring and reporting programs for EH&S performance in day-to-day operations, as well as inspections and assessments, have been designed to provide assurance that environmental and regulatory standards are met. Contingency plans have been put in place for a timely response to an environmental event and remediation/reclamation programs have been put in place and utilized to restore the environment.

We recognize that there is a cost associated with carbon emissions and we believe that greenhouse gas regulations and the cost of carbon at various price levels can be adequately accounted for as part of business planning.  As part of our future planning, management and the Board review the impact of a variety of carbon constrained scenarios on our strategy, with a current price range from $15 to $65 per tonne of emissions applied across a range of regulatory policy options.  A major benefit of applying a range of carbon prices at the strategic level 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 our investments across a range of scenarios.

We also examine the impact of carbon regulation on our major projects, including both our SAGD operations and refining assets.  We continue to closely monitor potential greenhouse gas legislation developments in the U.S.  Some of the climate change legislation being contemplated in the U.S. would require refiners to obtain emission allowances for emissions of greenhouse gases, including CO2 based on the carbon content of their fuels.  If this type of legislation is enacted into law, this could have a material impact on the cost structure of refined petroleum products that would be passed onto the consumer.

We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed. In 2009, expenditures beyond normal compliance with environmental regulations were not material.  We do not anticipate making material expenditures beyond amounts paid in respect of normal compliance with environmental regulations in 2010.  Based on estimates at December 31, 2009, the total anticipated undiscounted future cost of abandonment and reclamation costs to be incurred over the life of our proved reserves is estimated at approximately $5.4 billion.

Social and Environmental Policies

We have a Corporate Responsibility Policy (the ‘‘Policy’’) that applies to any activity undertaken by or on behalf of Cenovus.  The Policy has specific requirements in the areas of: (i) leadership commitment; (ii) sustainable value creation; (iii) governance and business practices; (iv) human rights; (v) labour practices; (vi) EH&S; (vii) stakeholder engagement; and (viii) socio-economic and community development.

The Policy and any revisions are approved by our executive team and our Board.  Accountability for implementation of the Policy is at the operational level within Cenovus’s business units.  Business units have established processes to evaluate risks and programs are implemented to minimize that risk.  Results related to the commitments are tied to the individual performance assessment process.

The Policy states the following with respect to the environment: (i) Cenovus will safeguard the environment and will operate in a manner consistent with recognized global industry standards in EH&S; (ii) we will strive to make efficient use of resources, to minimize our environmental footprint and to conserve habitat diversity and the plant and animal populations that may be affected by our operations; and (iii) we will strive to reduce our emissions intensity and increase our energy efficiency.

With respect to Cenovus’s relationship with the communities in which we do business, the Policy states that: (i) we engage in collaborative, consultative and partnership approaches in our community investment and programs, recognizing that no corporation is solely responsible for changing the fundamental economic, environmental and social situation in a community or country; and (ii) through our activities, Cenovus will assist in

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local capacity-building and develop mutually beneficial relationships, to make a positive difference in the communities and regions where we operate.

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

Through the Policy, Cenovus is committed to protecting the health and safety of all individuals affected by our activities, including our workforce and the public.  We will not compromise the health and safety of any individual in the conduct of our activities.  Cenovus will strive to provide a safe and healthy working environment and we expect our workers to comply with the health and safety practices established for their protection.

Some of the steps that Cenovus has taken to embed the corporate responsibility approach throughout the organization include: (i) an EH&S management system; (ii) a security program to regularly assess security threats to business operations and to manage the associated risks; (iii) corporate responsibility performance metrics to track our progress; (iv) an energy efficiency program that focuses on reducing energy use at Cenovus’s operations and supports initiatives at the community level while also incentivizing employees to reduce energy use in their homes; (v) an Investigations Practice and an Investigations Committee to review and resolve potential violations of Cenovus policies or practices and other regulations; (vi) an Integrity Helpline that provides an additional avenue for Cenovus’s stakeholders to raise their concerns as well as the corporate responsibility website which allows people to write to Cenovus about non-financial issues of concern; (vii) an internal corporate EH&S audit program that evaluates Cenovus’s compliance with the expectations and requirements of the EH&S management system; (viii) related policies and practices such as an Alcohol and Drug Policy, a Code of Business Conduct & Ethics and guidelines for correct behaviours with respect to the acceptance of gifts, conflicts of interest and the appropriate use of Cenovus equipment and technology in a manner that is consistent with leading ethical business practices; and (ix) a requirement for acknowledgement and sign-off on key policies from our Board and employees.  In addition, our Board approves such policies and is advised of significant contraventions thereof, and receives updates on trends, issues or events which could have a significant impact on Cenovus.

Employees

At December 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 service providers.

Foreign Operations

One hundred percent of our reserves, production and assets are located in North America, which limits our exposure to risks and uncertainties in countries considered politically and economically unstable.  Any of our future operations and related assets outside North America may be adversely affected by changes in governmental policy, social instability or other political or economic developments which are not within our control, including the expropriation of property, the cancellation or modification of contract rights and restrictions on repatriation of cash.

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DIRECTORS AND EXECUTIVE OFFICERS

Directors

The names, province or state and country of residence and position(s) of the persons who serve as our directors are set out below.

Name and Residence(1)	Office Held	Principal Occupation
Ralph S. Cunningham(2,4,5,7) Houston, Texas, United States	Director	President & Chief Executive Officer EPE Holdings, LLC (Midstream energy services)
Patrick D. Daniel(2,3,4,5) Calgary, Alberta, Canada	Director	President & Chief Executive Officer Enbridge Inc. (Energy delivery)
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)
Brian C. Ferguson(8) Calgary, Alberta, Canada	Director, President & Chief Executive Officer	President & Chief Executive Officer Cenovus Energy Inc.
Michael A. Grandin(2,5,9) Calgary, Alberta, Canada	Chair	Corporate Director
Valerie A.A. Nielsen(2,3,5,6) Calgary, Alberta, Canada	Director	Corporate Director
Charles M. Rampacek(5,6,7) Dallas, Texas, United States	Director	Corporate Director
Colin Taylor(3,4,5) Toronto, Ontario, Canada	Director	Corporate Director
Wayne G. Thomson(2,5,6,7) Calgary, Alberta, Canada	Director	President Enviro Valve Inc. (Private technology company)

Notes:

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

(2)Former director of Encana.

(3)Member of the Audit Committee.

(4)Member of the Human Resources and Compensation Committee.

(5)Member of the Nominating and Corporate Governance Committee.

(6)Member of the Reserves Committee.

(7)Member of the Safety, Environment and Responsibility Committee.

(8)As an officer and a non-independent director, Mr. Ferguson is not a member of any of the Committees of our Board.

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

Each of the directors was appointed as a member of our Board effective November 30, 2009 pursuant to the Arrangement and will hold office until the first annual meeting of the holders of Common Shares or until his or her successor is duly elected or appointed, unless his or her office is earlier vacated.  Additional directors may be appointed by our Board prior or subsequent to the first annual meeting of holders of Common Shares in accordance

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with our articles.  We have been granted an exemption by the TSX from being required to hold our first annual meeting of holders of Common Shares within six months of December 31, 2009.  As a result, the first annual meeting of holders of Common Shares is expected to occur in the second quarter of 2011 and, in any event, not later than May 31, 2011, at which time holders of Common Shares will vote on the election of our directors and appointment of our auditors.

Executive Officers

The following table sets forth the name and residency as of the date of this prospectus and position held by each of Cenovus’s directors and executive officers:

Name and Residence	Office Held
Brian C. Ferguson	Director, President & Chief Executive Officer
Ivor M. Ruste	Executive Vice-President & Chief Financial Officer
John K. Brannan	Executive Vice-President (President, Integrated Oil Division)
Harbir S. Chhina	Executive Vice-President, Enhanced Oil Development & New Resource Plays
Kerry D. Dyte	Executive Vice-President, General Counsel & Corporate Secretary
Judy A. Fairburn	Executive Vice-President, Environment & Strategic Planning
Sheila M. McIntosh	Executive Vice-President, Communications & Stakeholder Relations
Donald T. Swystun	Executive Vice-President (President, Canadian Plains Division)
Hayward J. Walls	Executive Vice-President, Organization & Workplace Development

Interest of Management and Others in Material Transactions

None of the directors or executive officers of Cenovus nor any person or company that is the direct or indirect owner of, or who exercises control or direction of, more than 10 percent of any class or series of Cenovus’s outstanding voting securities, of which there are none that Cenovus is aware, or any associate or affiliate of any of the foregoing persons, in each case, as at March 31, 2010, has or has had any material interest, direct or indirect, in any past transaction or any proposed transaction that has materially affected or will materially affect Cenovus.

DESCRIPTION OF OTHER MATERIAL INDEBTEDNESS

We currently have in place an unsecured credit facility in the amount of C$2.5 billion or its equivalent amount in U.S. dollars.  The revolving syndicated credit facility consists of two tranches, a C$2.0 billion 3-year tranche and a C$500 million 364-day tranche.  At March 31, 2010, no amounts were drawn under this credit facility.  We are currently in compliance with all of our financial covenants under this credit facility.

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The credit agreement governing the credit facility contains customary representations, warranties, covenants and events of default for credit facilities of this type.  Advances under the credit facility bear interest at the prevailing prime rate, U.S. base rate, bankers acceptance rate or LIBOR, plus applicable margins.

THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

On the Issue Date, we sold the Initial Notes in a private placement exempt from the registration requirements of the Securities Act, and the initial purchasers of the Initial Notes then resold them in reliance on other exemptions from the registration requirements of the Securities Act.  Consequently, the Initial Notes are subject to transfer restrictions under the Securities Act.  Pursuant to the terms of the Registration Rights Agreement, we agreed, among other things, to deliver this prospectus and to keep the exchange offer open for a period of not less than 30 days after the date notice of the exchange offer is mailed to the holders of the Initial Notes and to use commercially reasonable efforts to cause the exchange offer to be completed no later than the 45th day after the exchange offer registration statement is declared effective by the SEC (the “consummation deadline”).

Pursuant to the exchange offer, certain holders of Initial Notes that constitute Transfer Restricted Securities (as defined below) may exchange their Transfer Restricted Securities for the Exchange Notes.  To participate in the exchange offer, each holder must represent that it is not an affiliate of ours, it is not engaged in, and does not intend to engage in, and has no arrangement or understanding with any person to participate in, a distribution of the Exchange Notes, and that it is acquiring the Exchange Notes in the exchange offer in its ordinary course of business.

If you are a broker-dealer that will receive Exchange Notes for your own account in exchange for Initial Notes that were acquired as a result of market-making or other trading activities, you will be required to deliver a prospectus in connection with any resale of the Exchange Notes pursuant to applicable laws.

If:

·we are not permitted to file the exchange offer registration statement;

·because of any change in applicable law or in interpretations thereof by the SEC staff, we are not permitted to effect the exchange offer;

·the exchange offer is not completed by the 410th day after the Issue Date;

·any initial purchaser so requests with respect to Initial Notes held by it that are not eligible to be exchanged for Exchange Notes in the exchange offer; or

·prior to the 20th day following the consummation of the exchange offer, any holder of Transfer Restricted Securities notifies us that it is prohibited by law or the SEC from participating in the exchange offer or that it may not resell the Exchange Notes acquired in the exchange offer without delivering a prospectus or it is a broker-dealer and owns Exchange Notes acquired directly from us or an affiliate of ours,

Cenovus will be required to file with the SEC a shelf registration statement to register for public resale the Transfer Restricted Securities held by any such holder within 90 days after such triggering event and use their commercially reasonable efforts to have it declared effective no later than 180 days after the trigger date; provided that in no event shall Cenovus be required to file the shelf registration statement or have such registration statement declared effective prior to the applicable deadlines for the exchange offer registration statement.  Cenovus will be required to use its commercially reasonable efforts to keep the shelf registration statement effective until the earliest of (A) the time when the notes covered by the shelf registration statement are no longer restricted securities (as defined in Rule 144 under the Securities Act) or are saleable pursuant to Rule 144 without limitation and (B) the date on

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which all notes registered thereunder are disposed of in accordance therewith.  A holder who sells notes pursuant to the shelf registration statement generally will be required to be named as a selling securityholder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be required to agree in writing to be bound by the provisions of the Registration Rights Agreement which are applicable to such a holder (including certain indemnification obligations).  In addition, each holder of the notes will be required to deliver information to be used in connection with the shelf registration statement in order to have its notes included in the shelf registration statement.  We do not currently anticipate that we will register under the Securities Act any Initial Notes that remain outstanding after completion of the exchange offer.

For the purposes of the Registration Rights Agreement, “Transfer Restricted Securities” means each Initial Note until:

·the date on which such Initial Note is exchanged in the exchange offer by a person other than a broker-dealer for a freely transferable Exchange Note;

·following the exchange by a broker-dealer in the exchange offer of an Initial Note for an Exchange Note, the date on which such Exchange Note is sold to a purchaser who receives from the broker-dealer on or prior to the date of such sale a copy of the prospectus contained in the exchange offer registration statement;

·the date on which such Initial Note has been effectively registered under the Securities Act and disposed of in accordance with the shelf registration statement; or

·the date on which such Initial Note is distributed to the public pursuant to Rule 144 under the Securities Act.

The Registration Rights Agreement provides that if:

·Cenovus fails to file any registration statement required by the agreement on or prior to the applicable deadline;

·any registration statement is not declared effective on or prior to September 20, 2010;

·the exchange offer is not completed on or prior to the consummation deadline; or

·any registration statement has been declared effective but thereafter ceases to be effective or useable in connection with resales of the Transfer Restricted Securities during the periods specified in the Registration Rights Agreement (each, a “Registration Default”), then

we have agreed to pay to each holder of Transfer Restricted Securities affected thereby additional interest over and above the interest otherwise payable on the securities from and including the date on which any Registration Default shall occur to but excluding the date on which all such Registration Defaults have been cured, at a rate of 0.25% per annum for the first 90-day period immediately following the occurrence of a Registration Default, to be increased by an additional 0.25% per annum with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum additional interest rate of 0.5% per annum.  We will not be required to pay additional interest for more than one Registration Default at any given time.  All accrued additional interest shall be paid by us in the same manner and at the same time as payments of interest.

All of the Initial Notes of a particular series and the Exchange Notes issued in exchange for that series will be treated as the same series and will vote together as a single series under the Indenture.

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Under certain circumstances described in the Registration Rights Agreement, we may delay the filing of or suspend the effectiveness of or the holders’ ability to use this prospectus or a shelf registration statement, if applicable, and such delay or suspension will not alter the obligations of Cenovus to pay additional interest upon the occurrence of a Registration Default.

All references in the Indenture, in any context, to any interest or other amount payable on or with respect to the notes shall be deemed to include any additional interest pursuant to the Registration Rights Agreement.

We are conducting the exchange offer to satisfy our obligations under the Registration Rights Agreement.  If you participate in the exchange offer, you will, with limited exceptions, receive Exchange Notes that are freely tradable and not subject to additional interest or transfer restrictions.  You should read the discussion under “– Resale of the Exchange Notes” for more information regarding your ability to transfer the Exchange Notes.

The exchange offer is not being made to, nor will we accept tenders for exchange from, holders of Initial Notes in any jurisdiction in which the exchange offer or the acceptance of the exchange offer would not be in compliance with the securities laws or blue sky laws of such jurisdiction.  In addition, the Exchange Notes are not being offered for sale and may not be offered or sold, directly or indirectly in Canada, or to any resident thereof, except in accordance with the securities laws of the provinces and territories of Canada.  We are not required, and do not intend, to qualify the Exchange Notes by prospectus in Canada, and accordingly the Exchange Notes will be subject to applicable restrictions on resale in Canada.

Terms of the Exchange Offer

We are offering to exchange:

·your Initial 2014 Notes for a like aggregate principal amount at maturity of our New 2014 Notes;

·your Initial 2019 Notes for a like aggregate principal amount at maturity of our New 2019 Notes; and

·your Initial 2039 Notes for a like aggregate principal amount at maturity of our New 2039 Notes.

The Exchange Notes that we propose to issue in the exchange offer will be substantially identical to our Initial Notes except that, unlike our Initial Notes, the Exchange Notes will have no transfer restrictions or registration rights.

We will accept for exchange any and all Initial Notes that are properly tendered on or prior to 5:00 p.m., New York City time, on the Expiration Date.  We will issue $1,000 principal amount of the New 2014 Notes, New 2019 Notes or New 2039 Notes in exchange for each $1,000 principal amount of outstanding Initial 2014 Notes, Initial 2019 Notes or Initial 2039 Notes, respectively, accepted in the exchange offer.  You may tender some or all of your Initial Notes pursuant to the exchange offer; however, Initial Notes may be tendered only in minimum denominations of $2,000 and any integral multiple of $1,000 in excess thereof.

The exchange agent will act as agent for the tendering holders for the purpose of receiving the Exchange Notes from us.  If any tendered Initial Notes are not accepted for exchange because of an invalid tender or otherwise, certificates for the unaccepted Initial Notes will be returned, without expense, to the tendering holder as promptly as practicable after the Expiration Date.  Holders of the Initial Notes do not have appraisal or dissenters’ rights under the laws of the State of New York or the Indenture.  We intend to conduct the exchange offer in accordance with the applicable requirements of Canadian securities laws, the Securities Act and the Exchange Act and the rules and regulations under the Securities Act and the Exchange Act.

None of us, our directors or our management recommends that you tender or not tender your Initial Notes in the exchange offer.  In addition, no one has been authorized to make any such recommendation.  You must make your own decision whether to participate in the exchange offer and, if you choose to participate, the aggregate

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principal amount of your Initial Notes to tender, after carefully reading this prospectus and the letter of transmittal.  We urge you to consult your financial and tax advisors in making your decision on what action to take.

Expiration Date; Extensions; Amendments; Termination

The exchange offer will expire at 5:00 p.m., New York City time, on the Expiration Date.

We expressly reserve the right to delay acceptance of any Initial Notes, extend or terminate the exchange offer at any time and not accept any Initial Notes that we have not previously accepted if any of the conditions described below under “Conditions to the Exchange Offer” have not been satisfied or waived by us.  We will notify the exchange agent of any extension by oral notice promptly confirmed in writing or by written notice.  We will also notify the holders of the Initial Notes of any extension by mailing an announcement or by a press release or other public announcement communicated before 9:00 a.m., New York City time, on the next business day following the previously scheduled Expiration Date unless applicable laws require us to do otherwise.

We also expressly reserve the right to amend the terms of the exchange offer in any manner. If we make any material change, we will promptly disclose this change in a manner reasonably calculated to inform the holders of our Initial Notes of the change, including providing public announcement or giving oral or written notice to such holders.  A material change in the terms of the exchange offer could include a change in the timing of the exchange offer, a change in the exchange agent and other similar changes in the terms of the exchange offer.  If we make any material change to the exchange offer, we will disclose this change by means of a post-effective amendment to the registration statement which includes this prospectus and will distribute an amended or supplemented prospectus to each registered holder of Initial Notes.  In addition, we will extend the exchange offer for an additional five to ten business days as required by the Exchange Act, depending on the significance of the amendment or if the exchange offer would otherwise have expired during that period.  We will promptly notify the exchange agent by oral notice, promptly confirmed in writing, or written notice of any delay in acceptance, extension, termination or amendment of the exchange offer.

Procedures for Tendering Initial Notes

Proper Execution and Delivery of Letters of Transmittal

To tender your Initial Notes in the exchange offer, you must use one of the three alternative procedures described below:

(1)Regular delivery procedure: Complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal. Have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal. Mail or otherwise deliver the letter of transmittal or the facsimile together with the certificates representing the Initial Notes being tendered and any other required documents to the exchange agent on or before 5:00 p.m., New York City time, on the Expiration Date.

(2)Book-entry delivery procedure: Send a timely confirmation of a book-entry transfer of your Initial Notes into the exchange agent’s account at DTC in accordance with the procedures for book-entry transfer described under “Book-Entry Delivery Procedure” below, on or before 5:00 p.m., New York City time, on the Expiration Date.

(3)Guaranteed delivery procedure: If time will not permit you to complete your tender by using the procedures described in (1) or (2) above before the Expiration Date and this procedure is available, comply with the guaranteed delivery procedures described under “Guaranteed Delivery Procedure” below.

The method of delivery of the Initial Notes, the letter of transmittal and all other required documents is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand-delivery service.  If you choose the mail, we recommend that you use registered mail, properly insured, with return receipt

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requested.  In all cases, you should allow sufficient time to assure timely delivery.  You should not send any letters of transmittal or Initial Notes to us.  You must deliver all documents to the exchange agent at its address provided below.  You may also request your broker, dealer, commercial bank, trust company or nominee to tender your Initial Notes on your behalf.

Only a holder of Initial Notes may tender Initial Notes in the exchange offer.  A holder is any person in whose name Initial Notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder.

If you are the beneficial owner of Initial Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your notes, you must contact that registered holder promptly and instruct that registered holder to tender your notes on your behalf.  If you wish to tender your Initial Notes on your own behalf, you must, before completing and executing the letter of transmittal and delivering your Initial Notes, either make appropriate arrangements to register the ownership of these notes in your name or obtain a properly completed bond power from the registered holder.  The transfer of registered ownership may take considerable time.

You must have any signatures on a letter of transmittal or a notice of withdrawal guaranteed by:

(1)a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority;

(2)a commercial bank or trust company having an office or correspondent in the United States; or

(3)an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act, unless the Initial Notes are tendered:

(a)by a registered holder or by a participant in DTC whose name appears on a security position listing as the owner, who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal and only if the Exchange Notes are being issued directly to this registered holder or deposited into this participant’s account at DTC, or

(b)for the account of a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, a commercial bank or trust company having an office or correspondent in the United States or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act.

If the letter of transmittal or any bond powers are signed by:

(1)the registered holder(s) of the Initial Notes tendered: the signature must correspond with the name(s) written on the face of the Initial Notes without alteration, enlargement or any change whatsoever.

(2)a participant in DTC: the signature must correspond with the name as it appears on the security position listing as the holder of the Initial Notes.

(3)a person other than the registered holder of any Initial Notes: these Initial Notes must be endorsed or accompanied by bond powers and a proxy that authorize this person to tender the Initial Notes on behalf of the registered holder, in satisfactory form to us as determined in our sole discretion, in each case, as the name of the registered holder or holders appears on the Initial Notes.

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(4)trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity: these persons should so indicate when signing. Unless waived by us, evidence satisfactory to us of their authority to so act must also be submitted with the letter of transmittal.

To effectively tender notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program.  DTC will then edit and verify the acceptance and send an agent’s message to the exchange agent for its acceptance.  An agent’s message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant.

Book-Entry Delivery Procedure

Any financial institution that is a participant in DTC’s systems may make book-entry deliveries of Initial Notes by causing DTC to transfer their Initial Notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. To effectively tender Initial Notes through DTC, the financial institution that is a participant in DTC will electronically transmit its acceptance through the Automatic Tender Offer Program. DTC will then edit and verify the acceptance and send an agent’s message to the exchange agent for its acceptance. An agent’s message is a message transmitted by DTC to the exchange agent stating that DTC has received an express acknowledgment from the participant in DTC tendering the Initial Notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant. The exchange agent will make a request to establish an account for the Initial Notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus.

A delivery of Initial Notes through a book-entry transfer into the exchange agent’s account at DTC will only be effective if an agent’s message or the letter of transmittal or a facsimile of the letter of transmittal with any required signature guarantees and any other required documents is transmitted to and received by the exchange agent at the address indicated below under “Exchange Agent” on or before the Expiration Date unless the guaranteed delivery procedures described below are complied with.  Delivery of documents to DTC does not constitute delivery to the exchange agent.

Guaranteed Delivery Procedure

If you are a registered holder of Initial Notes and desire to tender your notes, and (1) these notes are not immediately available, (2) time will not permit your notes or other required documents to reach the exchange agent before the Expiration Date or (3) the procedures for book-entry transfer cannot be completed on a timely basis and an agent’s message delivered, you may still tender in the exchange offer if:

(1)you tender through a member firm of a registered national securities exchange or of the Financial Industry Regulatory Authority, a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act;

(2)on or before the Expiration Date, the exchange agent receives a properly completed and duly executed letter of transmittal or facsimile of the letter of transmittal, and a notice of guaranteed delivery, substantially in the form provided by us, with your name and address as holder of the Initial Notes and the amount of notes tendered, stating that the tender is being made by that letter and notice and guaranteeing that within three New York Stock Exchange trading days after the Expiration Date, the certificates for all the Initial Notes tendered, in proper form for transfer, or a book-entry confirmation with an agent’s message, as the case may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

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(3)the certificates for all your tendered Initial Notes in proper form for transfer or a book-entry confirmation as the case may be, and all other documents required by the letter of transmittal are received by the exchange agent within three New York Stock Exchange trading days after the Expiration Date.

Representations Made by Tendering Holders of Initial Notes

By tendering, you will represent to us that, among other things:

·you are acquiring the Exchange Notes in the ordinary course of business;

·you do not have any arrangement or understanding with any person or entity to participate in the distribution of the Exchange Notes;

·if you are not a broker-dealer, but will not receive Exchange Notes for your own account, neither you nor the holder are engaged in or intend to participate in a distribution of the Exchange Notes;

·if you are a broker-dealer that will receive Exchange Notes for your own account in exchange for Initial Notes that were acquired by you as a result of market-making activities or other trading activities, you will deliver a prospectus, as required by law, in connection with any resale of the Exchange Notes (see “Plan of Distribution”); and

·you are not our “affiliate” as defined in Rule 405 of the Securities Act.

If you are our “affiliate,” as defined under Rule 405 of the Securities Act, or are engaged in or intend to engage in or have an arrangement or understanding with any person to participate in a distribution of the Exchange Notes, you will represent and warrant that you: (i) may not rely on the applicable interpretations of the staff of the SEC; and (ii) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

In addition, in tendering Initial Notes, you must warrant in the letter of transmittal or in an agent’s message that:

·you have full power and authority to tender, exchange, sell, assign and transfer Initial Notes;

·we will acquire good, marketable and unencumbered title to the tendered Initial Notes, free and clear of all liens, restrictions, charges and other encumbrances; and

·the Initial Notes tendered for exchange are not subject to any adverse claims or proxies.

You must also warrant and agree that you will, upon request, execute and deliver any additional documents deemed by us to be necessary or desirable to complete the exchange, sale, assignment and transfer of the Initial Notes.  You must also warrant that acceptance of any tendered Initial Notes by us and the issuance of Exchange Notes in exchange therefor shall constitute performance in full by us of certain of our obligations under the Registration Rights Agreement, which has been filed as an exhibit to the registration statement in connection with the exchange offer.

Acceptance of Initial Notes for Exchange

Your tender of Initial Notes will constitute an agreement between you and us governed by the terms and conditions provided in this prospectus and in the related letter of transmittal.

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We will be deemed to have received your tender as of the date when your duly signed letter of transmittal accompanied by your Initial Notes tendered, or a timely confirmation of a book-entry transfer of these notes into the exchange agent’s account at DTC with an agent’s message, or a notice of guaranteed delivery from an eligible institution is received by the exchange agent.

All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tenders will be determined by us in our sole discretion.  Our determination will be final and binding.

We reserve the absolute right to reject any and all Initial Notes not properly tendered or any Initial Notes which, if accepted, would, in our opinion or our counsel’s opinion, be unlawful.  We also reserve the absolute right to waive any conditions of the exchange offer or irregularities or defects in tender as to particular notes.  Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties.  Unless waived, any defects or irregularities in connection with tenders of Initial Notes must be cured within such time as we shall determine.  We, the exchange agent or any other person will be under no duty to give notification of defects or irregularities with respect to tenders of Initial Notes.  We and the exchange agent or any other person will incur no liability for any failure to give notification of these defects or irregularities.  Tenders of Initial Notes will not be deemed to have been made until such irregularities have been cured or waived.  The exchange agent will return without cost to their holders any Initial Notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived as promptly as practicable following the Expiration Date.

If all the conditions to the exchange offer are satisfied or waived on the Expiration Date, we will accept all Initial Notes properly tendered and will issue the Exchange Notes promptly thereafter. Please refer to the section of this prospectus entitled “Conditions to the Exchange Offer” below. For purposes of the exchange offer, Initial Notes will be deemed to have been accepted as validly tendered for exchange when, as and if we give oral or written notice of acceptance to the exchange agent.

We will issue the Exchange Notes in exchange for the Initial Notes tendered pursuant to a notice of guaranteed delivery by an eligible institution only against delivery to the exchange agent of the letter of transmittal, the tendered Initial Notes and any other required documents, or the receipt by the exchange agent of a timely confirmation of a book-entry transfer of Initial Notes into the exchange agent’s account at DTC with an agent’s message, in each case, in form satisfactory to us and the exchange agent.

If any tendered Initial Notes are not accepted for any reason provided by the terms and conditions of the exchange offer or if Initial Notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged Initial Notes will be returned without expense to the tendering holder, or, in the case of Initial Notes tendered by book-entry transfer procedures described above, will be credited to an account maintained with the book-entry transfer facility, as promptly as practicable after withdrawal, rejection of tender or the expiration or termination of the exchange offer.

By tendering into the exchange offer, you will irrevocably appoint our designees as your attorney-in-fact and proxy with full power of substitution and resubstitution to the full extent of your rights on the notes tendered.  This proxy will be considered coupled with an interest in the tendered notes.  This appointment will be effective only when, and to the extent that we accept your notes in the exchange offer.  All prior proxies on these notes will then be revoked and you will not be entitled to give any subsequent proxy.  Any proxy that you may give subsequently will not be deemed effective.  Our designees will be empowered to exercise all voting and other rights of the holders as they may deem proper at any meeting of note holders or otherwise.  The Initial Notes will be validly tendered only if we are able to exercise full voting rights on the notes, including voting at any meeting of the note holders, and full rights to consent to any action taken by the note holders.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw tenders of Initial Notes at any time before 5:00 p.m., New York City time, on the Expiration Date.

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For a withdrawal to be effective, you must send a written or facsimile transmission notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the Expiration Date at the address provided below under “Exchange Agent” and before acceptance of your tendered notes for exchange by us.

Any notice of withdrawal must:

(1)specify the name of the person having tendered the Initial Notes to be withdrawn;

(2)identify the notes to be withdrawn, including, if applicable, the registration number or numbers and total principal amount of these notes;

(3)be signed by the person having tendered the Initial Notes to be withdrawn in the same manner as the original signature on the letter of transmittal by which these notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to permit the trustee for the Initial Notes to register the transfer of these notes into the name of the person having made the original tender and withdrawing the tender;

(4)specify the name in which any of these Initial Notes are to be registered, if this name is different from that of the person having tendered the Initial Notes to be withdrawn; and

(5)if applicable because the Initial Notes have been tendered through the book-entry procedure, specify the name and number of the participant’s account at DTC to be credited, if different than that of the person having tendered the Initial Notes to be withdrawn.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of all notices of withdrawal and our determination will be final and binding on all parties.  Initial Notes that are withdrawn will be deemed not to have been validly tendered for exchange in the exchange offer.

You may re-tender properly withdrawn Initial Notes in the exchange offer by following one of the procedures described under “Procedures for Tendering Initial Notes” above at any time on or before the Expiration Date.

Determination of Validity of Tender

We will resolve in our sole discretion all questions as to the validity, form, eligibility (including time of receipt) and acceptance of any Initial Notes tendered for exchange.  Our determination of these questions and our interpretation of the terms and conditions of the exchange offer, including without limitation the letter of transmittal and its instructions, shall be final and binding on all parties.  A tender of Initial Notes is invalid until all defects and irregularities have been cured or waived.  Each holder must cure any and all defects or irregularities in connection with their tender of Initial Notes within the reasonable period of time determined by us, unless we waive these defects or irregularities.  None of us, our affiliates and assigns, the exchange agent and any other person is under any duty or obligation to give notice of any defect or irregularity with respect to any tender of the Initial Notes, and none of them shall incur any liability for failure to give any such notice.

We reserve the absolute right in our sole and absolute discretion to:

·reject any and all tenders of Initial Notes determined to be in improper form or unlawful;

·waive any condition of the exchange offer; and

·waive any condition, defect or irregularity in the tender of Initial Notes by any holder, whether or not we waive similar conditions, defects or irregularities in the case of other holders.

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The exchange agent will return without cost to their holders all Initial Notes that have been tendered for exchange and are not exchanged for any reason, as promptly as practicable after withdrawal, rejection of tender or expiration or termination of the exchange offer.

Conditions to the Exchange Offer

We will complete the exchange offer only if:

(1)there is no change in the laws and regulations which, in our judgment or in the opinion of our counsel, would reasonably be expected to impair our ability to proceed with the exchange offer;

(2)there is no change in the current interpretation of the staff of the SEC which permits resales of the Exchange Notes;

(3)there is no stop order issued by the SEC or any state securities authority suspending the effectiveness of the registration statement which includes this prospectus or the qualification of the Indenture for our Exchange Notes under the Trust Indenture Act and there are no proceedings initiated or, to our knowledge, threatened for that purpose;

(4)there is no action or proceeding instituted or threatened in any court or before any governmental agency or body that in our judgment or in the opinion of our counsel would reasonably be expected to prohibit, prevent or otherwise impair our ability to proceed with the exchange offer; and

(5)we obtain all governmental approvals that we deem in our sole discretion necessary to complete the exchange offer.

In addition, we will not be obligated to accept for exchange the Initial Notes of any holder that has not made to us:

·the representations described under “– Procedures for Tendering Initial Notes – Representations Made by Tendering Holders of Initial Notes” and “Plan of Distribution”; and

·any other representations reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the Exchange Notes under the Securities Act.

The foregoing conditions are for our sole benefit, and we may assert them regardless of the circumstances giving rise to any such condition, or we may waive the conditions, completely or partially, whenever or as many times as we may choose, in our sole discretion. Our failure at any time to exercise any of the above rights will not be a waiver of those rights, and each right will be deemed an ongoing right that may be asserted at any time. Any determination by us concerning the events described above will be final and binding upon all parties. If we determine that a waiver of conditions materially changes the exchange offer, this prospectus will be amended or supplemented, and the exchange offer extended, if appropriate, as described under “ – Expiration Date; Extensions; Amendments; Termination”.

In addition, at any time when any stop order is threatened or in effect with respect to the registration statement that includes this prospectus or with respect to the qualification of the Indenture governing the notes under the Trust Indenture Act, we will not accept for exchange any Initial Notes tendered, and no Exchange Notes will be issued in exchange for any such Initial Notes.

Each of these rights will be deemed an ongoing right which we may assert at any time and from time to time.  If we determine that we may terminate the exchange offer because any of these conditions is not satisfied, we may:

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(1)refuse to accept and return to their holders any Initial Notes that have been tendered;

(2)extend the exchange offer and retain all notes tendered before the Expiration Date, subject to the rights of the holders of these notes to withdraw their tenders; or

(3)waive any condition that has not been satisfied and accept all properly tendered notes that have not been withdrawn or otherwise amend the terms of the exchange offer in any respect as provided under the section in this prospectus entitled “Expiration Date; Extensions; Amendments; Termination”.

Accounting Treatment

We will record the Exchange Notes at the same carrying value as the Initial Notes, as reflected in our accounting records on the date of the exchange.  Accordingly, we will not recognize any gain or loss for accounting purposes.  We will expense the costs of the exchange offer.

Exchange Agent

We have appointed BNY Mellon as exchange agent for the exchange offer.  You should direct all questions and requests for assistance on the procedures for tendering and all requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows:

By mail: 101 Barclay Street

New York, New York 10286

Attention: Lesley Daley

By hand/overnight delivery: 101 Barclay Street

New York, New York 10286

Attention: Lesley Daley

Facsimile Transmission: (212) 815-5366

Confirm by Telephone: (212) 815-2719

Attention: Lesley Daley

Fees and Expenses

We will bear the expenses of soliciting tenders in the exchange offer, including fees and expenses of the exchange agent and Trustee and accounting, legal, printing and related fees and expenses.

We will not make any payments to brokers, dealers or other persons soliciting acceptances of the exchange offer.  However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonable out-of-pocket expenses in connection with the exchange offer.  We will also pay brokerage houses and other custodians, nominees and fiduciaries their reasonable out-of-pocket expenses for forwarding copies of the prospectus, letters of transmittal and related documents to the beneficial owners of the Initial Notes and for handling or forwarding tenders for exchange to their customers.

We will pay all transfer taxes, if any, applicable to the exchange of Initial Notes in accordance with the exchange offer.  However, tendering holders will pay the amount of any transfer taxes, whether imposed on the registered holder or any other persons, if:

(1)certificates representing Exchange Notes or Initial Notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the notes tendered;

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(2)tendered Initial Notes are registered in the name of any person other than the person signing the letter of transmittal; or

(3)a transfer tax is payable for any reason other than the exchange of the Initial Notes in the exchange offer.

If you do not submit satisfactory evidence of the payment of any of these taxes or of any exemption from this payment with the letter of transmittal, we will bill you directly the amount of these transfer taxes.

Your Failure to Participate in the Exchange Offer May Have Adverse Consequences

The Initial Notes were not registered under the Securities Act or under the securities laws of any state and you may not resell them, offer them for resale or otherwise transfer them unless they are subsequently registered or resold under an exemption from the registration requirements of the Securities Act and applicable state securities laws.  If you do not exchange your Initial Notes for Exchange Notes in accordance with the exchange offer, or if you do not properly tender your Initial Notes in the exchange offer, you will not be able to resell, offer to resell or otherwise transfer the Initial Notes unless they are registered under the Securities Act or unless you resell them, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.  In addition, you may no longer be able to obligate us to register the Initial Notes under the Securities Act except as described above under “–  Purpose and Effect of the Exchange Offer.”  The trading market for your Initial 2014 Notes, your Initial 2019 Notes and your Initial 2039 Notes will become more limited to the extent other holders of Initial Notes participate in the exchange offer.

Delivery of Prospectus

Each broker-dealer that receives Exchange Notes for its own account in exchange for Initial Notes, where such Initial Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes.  See “Plan of Distribution”.

Resale of the Exchange Notes

Based on interpretations by the SEC staff set forth in no-action letters issued to third parties in similar transactions, we believe that a holder of the Exchange Notes may offer the Exchange Notes for resale or resell or otherwise transfer the Exchange Notes in the United States without compliance with the registration and prospectus delivery requirements of the Securities Act, unless this holder:

·is our “affiliate” within the meaning of Rule 405 under the Securities Act;

·is a broker-dealer who purchased Initial Notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act;

·acquired the Exchange Notes other than in the ordinary course of this holder’s business; or

·is participating, intends to participate or has an arrangement or understanding with any person to participate in the distribution of the Exchange Notes.

Accordingly, holders of Initial Notes wishing to participate in the exchange offer must make the applicable representations described in “– Procedures for Tendering Initial Notes – Representations Made by Tendering Holders of Initial Notes” above.

Although we are making the exchange offer in reliance on the interpretations by the SEC staff set forth in these no-action letters, we do not intend to seek our own no-action letter from the SEC. Consequently, we cannot assure you that the SEC staff would make a similar determination with respect to the exchange offer as it did in its

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no-action letters to third parties. If this interpretation is inapplicable and you resell or otherwise transfer any Exchange Notes without complying with the registration and prospectus delivery requirements of the Securities Act, you may incur liability under the Securities Act. We do not and will not assume or indemnify you against this liability.

You may not rely on the interpretations of the SEC staff in the above-described no-action letters if you are a holder of Initial Notes who:

·is our “affiliate” as defined in Rule 405 under the Securities Act;

·does not acquire the Exchange Notes in the ordinary course of business;

·tenders in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the Exchange Notes; or

·is a broker-dealer that purchased Initial Notes from us to resell them pursuant to Rule 144A under the Securities Act or any other available exemption under the Securities Act, and in the absence of an exemption, you must comply with the registration and prospectus delivery requirements of the Securities Act or applicable Canadian securities laws in connection with any resale or other transfer of the Exchange Notes.

In addition, each broker-dealer that receives Exchange Notes for its own account in exchange for Initial Notes that were acquired by it as a result of market-making activities or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of those Exchange Notes (see “Plan of Distribution”). Under the Registration Rights Agreement, we will be required to use our commercially reasonable efforts to keep the registration statement that includes this prospectus effective to allow these participating broker-dealers and other persons, if any, with similar prospectus delivery requirements to use this prospectus in connection with the resale of the Exchange Notes for the period that, unless extended pursuant to the Registration Rights Agreement, ends on the sooner of 180 days after the effectiveness of the registration statement that includes this prospectus and the date on which participating broker-dealers are no longer required to deliver a prospectus in connection with market-making or other trading activities.

In order to comply with state securities laws, the Exchange Notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification is available and is complied with.

DESCRIPTION OF THE EXCHANGE NOTES

In this section only, “we”, “us”, “our” or “Cenovus” refer only to Cenovus, as it exists as of the date of this prospectus, without any of its subsidiaries or partnerships through which it operates or will operate.

The Initial Notes were, and the Exchange Notes will be, issued under the Indenture.  The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

The following is a summary of the material provisions of the Indenture but does not restate the Indenture in its entirety.  You can find the definitions of certain capitalized terms used in the following summary under the subheading “Certain Definitions”.  We urge you to read the Indenture because it, and not this description, defines your rights as holders of the notes.

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General

The Exchange Notes:

·will be our direct unsecured and unsubordinated obligations ranking equally and ratably in right of payment with all of our other unsecured and unsubordinated indebtedness;

·will be issued in US$3,500,000,000 aggregate principal amount comprised of: US$800,000,000 aggregate principal amount of New 2014 Notes, US$1,300,000,000 aggregate principal amount of New 2019 Notes and US$1,400,000,000 aggregate principal amount of New 2039 Notes;

·will mature on September 15, 2014, in the case of the New 2014 Notes, October 15, 2019 in the case of the New 2019 Notes and November 15, 2039 in the case of the New 2039 Notes;

·the New 2014 Notes will bear interest to be paid semi-annually in arrears on March 15 and September 15 of each year, to holders of record on March 1 or September 1, respectively, immediately preceding the applicable interest payment date.  The New 2019 Notes will bear interest to be paid semi-annually in arrears on April 15 and October 15 of each year to holders of record on April 1 or October 1, respectively, immediately preceding the applicable interest payment date.  The New 2039 Notes will bear interest to be paid semi-annually in arrears on May 15 and November 15 of each year to holders of record on May 1 or November 1, respectively, immediately preceding the applicable interest payment date; and

·will bear interest on overdue principal, and overdue interest, at the rate otherwise applicable to the notes.

Interest will be computed on the basis of a 360-day year of twelve 30-day months.  The interest period relating to an interest payment date shall be the period from but not including the preceding interest payment date to and including the relevant interest payment date.  Each series of the Exchange Notes will bear interest from the most recent date to which interest has been paid on the corresponding series of Initial Notes or, if no interest has been paid on the applicable series of Initial Notes, from the Issue Date.

Payment of the principal, premium, if any, and interest on the notes will be made in United States dollars.  The Exchange Notes will be issued in denominations of $2,000 and any integral multiple of $1,000 in excess thereof.

We may from time to time without notice to, or the consent of, the holders of the notes, create and issue additional 2014 Notes, 2019 Notes or 2039 Notes under the Indenture.  Any additional 2014 Notes, 2019 Notes or 2039 Notes issued under the Indenture will each respectively be part of the same issue as the 2014 Notes, 2019 Notes or 2039 Notes previously issued pursuant to the Cenovus Note Offering and the Exchange Notes to be issued pursuant to the exchange offer and will be treated as notes of the same respective series, including for purposes of voting status, redemptions, offers to purchase and otherwise and will rank equally and have the same terms as the notes of the same series offered hereby in all respects (or in all respects except for the original issue price, payment of interest accruing prior to the issue date of the Initial Notes of the same series, or except for the initial interest payment following the original issue date of the Initial Notes of the same series).

The Exchange Notes will not be entitled to the benefits of any sinking fund. We may issue debt securities and incur additional indebtedness other than through the exchange offer.

Ranking

The Exchange Notes will be our direct, unsecured and unsubordinated obligations and will rank equally and ratably with all of our existing and future unsecured and unsubordinated indebtedness.  The Exchange Notes will be structurally subordinate to all existing and future indebtedness and liabilities of any of our corporate and partnership subsidiaries.  A substantial portion of our operations is conducted through corporate and partnership

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subsidiaries.  In connection with the formation of Cenovus’s integrated oil business with ConocoPhillips one of our partnership subsidiaries owed, as at March 31, 2010, approximately $5.6 billion of partnership contribution payable to an entity that Cenovus and ConocoPhillips own equally.

Book-Entry System

DTC acts as securities depository for the Initial Notes and will also act as securities depository for the Exchange Notes (the “Depository”). The Exchange Notes will be issued as fully-registered securities registered in the name of Cede & Co. (DTC’s partnership nominee) or such other name as may be requested by an authorized representative of DTC. One or more fully-registered Global Notes will be issued for the Exchange Notes, in the aggregate principal amount of such issue, and will be deposited with DTC.

DTC is a limited-purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC also facilitates the post-trade settlement among direct participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between direct participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation (“DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly. The DTC Rules applicable to its participants are on file with the SEC.

Purchases of Exchange Notes under the DTC system must be made by or through direct participants, which will receive a credit for the notes on DTC’s records. The ownership interest of each actual purchaser of each note (“beneficial owner”) is in turn to be recorded on the direct and indirect participants’ records. Beneficial owners will not receive written confirmation from DTC of their purchase. Beneficial owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct or indirect participant through which the beneficial owner entered into the transaction. Transfers of ownership interests in the Global Notes are to be accomplished by entries made on the books of direct and indirect participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in the Global Notes, except in the event that use of the book-entry system for the Exchange Notes is discontinued.

The deposit of the Global Notes with DTC and their registration in the name of Cede & Co. do not effect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the Global Notes; DTC’s records reflect only the identity of the direct participants to whose accounts such securities are credited, which may or may not be the beneficial owners. The direct and indirect participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants, and by direct and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

None of DTC, Cede & Co., or any other DTC nominee will consent or vote with respect to the Global Notes unless authorized by a direct participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to us as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts the securities are credited on the record date. These participants are identified in a listing attached to the omnibus proxy.

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Principal and interest payments on the Global Notes will be made to Cede & Co., or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from us, on the applicable payment date in accordance with their respective holdings shown on DTC’s records. Payments by participants to beneficial owners will be governed by standing instructions and customary practices, as is the case with notes held for the accounts of customers in bearer form or registered in street name. These payments will be the responsibility of these participants and not of DTC or its nominee, us, the Trustee, or any other agent or party, subject to any statutory or regulatory requirements that may be in effect from time to time. Payment of principal and interest to Cede & Co., or any other nominee as may be requested by an authorized representative of DTC, is our responsibility. Disbursement of the payments to direct participants is the responsibility of DTC, and disbursement of the payments to the beneficial owners is the responsibility of the direct or indirect participants.

We will send any redemption notices to DTC. If less than all of the Exchange Notes of a series are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each direct participant in the issue to be redeemed.

The information in this section concerning DTC and DTC’s system has been obtained from sources that we believe to be reliable, but is subject to any changes to the arrangement between us and DTC and any changes to these procedures that may be instituted unilaterally by DTC.

Certificated Notes

The Depository may discontinue providing its services as depository with respect to the Exchange Notes at any time by giving reasonable notice to us and the Trustee. Under these circumstances, and in the event that a successor depository is not appointed, Exchange Notes in certificated form are required to be printed and delivered. We may decide to discontinue use of the system of book-entry transfers through the Depository (or a successor depository). In that event, notes in certificated form will be printed and delivered. If at any time the Depository ceases to be a clearing agency registered under the Exchange Act and a successor depository is not appointed by us within 90 days or if there shall have occurred and be continuing an Event of Default under the Indenture with respect to the notes and the Trustee has received a request from a beneficial holder of outstanding Exchange Notes to issue Exchange Notes in certificated form to such holder, we will issue individual Exchange Notes in certificated form in exchange for the Global Notes.

Certain Definitions

Set forth below is a summary of certain of the defined terms used in the Indenture.  The Indenture contains the full definition of all such terms.

“Adjusted Treasury Rate” means, with respect to any redemption date, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date.

“Comparable Treasury Issue” means the United States Treasury security or securities selected by the Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term of the notes to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate notes of comparable maturity to the remaining term of the notes.

“Comparable Treasury Price” means, with respect to any redemption date, (A) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (B) if fewer than four such Reference Treasury Dealer Quotations are obtained, the average of all such quotations.

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“Consolidated Net Tangible Assets” means the total amount of assets of any Person on a consolidated basis (less applicable reserves and other properly deductible items) after deducting therefrom:

·all current liabilities (excluding any indebtedness classified as a current liability and any current liabilities which are by their terms extendible or renewable at the option of the obligor thereon to a time more than 12 months after the time as of which the amount thereof is being computed);

·all goodwill, trade names, trademarks, patents and other like intangibles; and

·appropriate adjustments on account of minority interests of other persons holding shares of the Subsidiaries of such Person,

in each case, as shown on the most recent annual audited or quarterly unaudited consolidated balance sheet of such Person computed in accordance with GAAP.

“Current Assets” means assets which in the ordinary course of business are expected to be realized in cash or sold or consumed within 12 months.

“Facilities” means any drilling equipment, production equipment and platforms or mining equipment; pipelines, pumping stations and other pipeline facilities; terminals, warehouses and storage facilities; refineries and related facilities; bulk plants; production, separation, dehydration, extraction, treating and processing facilities; gasification or natural gas liquefying facilities, flares, stacks and burning towers; floatation mills, crushers and ore handling facilities; tank cars, tankers, barges, ships, trucks, automobiles, airplanes and other marine, automotive, aeronautical and other similar moveable facilities or equipment; computer systems and associated programs or office equipment; roads, airports, docks (including drydocks); reservoirs and waste disposal facilities; sewers; generating plants (including power plants) and electric lines; telephone and telegraph lines, radio and other communications facilities; townsites, housing facilities, recreation halls, stores and other related facilities; and similar facilities and equipment of or associated with any of the foregoing.

“Financial Instrument Obligations” means obligations arising under:

·interest rate swap agreements, forward rate agreements, floor, cap or collar agreements, futures or options, insurance or other similar agreements or arrangements, or any combination thereof, entered into by a Person relating to interest rates or pursuant to which the price, value or amount payable thereunder is dependent or based upon interest rates in effect from time to time or fluctuations in interest rates occurring from time to time;

·currency swap agreements, cross-currency agreements, forward agreements, floor, cap or collar agreements, futures or options, insurance or other similar agreements or arrangements, or any combination thereof, entered into by a Person relating to currency exchange rates or pursuant to which the price, value or amount payable thereunder is dependent or based upon currency exchange rates in effect from time to time or fluctuations in currency exchange rates occurring from time to time; and

·commodity swap or hedging agreements, floor, cap or collar agreements, commodity futures or options or other similar agreements or arrangements, or any combination thereof, entered into by a Person relating to one or more commodities or pursuant to which the price, value or amount payable thereunder is dependent or based upon the price of one or more commodities in effect from time to time or fluctuations in the price of one or more commodities occurring from time to time.

“GAAP” means generally accepted accounting principles in Canada which are in effect from time to time, unless the Person’s most recent audited or quarterly financial statements are not prepared in accordance with generally accepted accounting principles in Canada, in which case GAAP shall mean generally accepted accounting principles in the United States in effect from time to time.

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“Independent Investment Banker” means one of the Reference Treasury Dealers, which is appointed by the Trustee after consultation with us.

“Lien” means, with respect to any properties or assets, any mortgage or deed of trust, pledge, hypothecation, assignment, security interest, lien, charge, encumbrance, preference, priority or other security agreement or preferential arrangement of any kind or nature whatsoever on or with respect to such properties or assets (including, without limitation, any conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing).

“Non-Recourse Debt” means indebtedness to finance the creation, development, construction or acquisition of properties or assets and any increases in or extensions, renewals or refinancings of such indebtedness, provided that the recourse of the lender thereof (including any agent, trustee, receiver or other Person acting on behalf of such entity) in respect of such indebtedness is limited in all circumstances to the properties or assets created, developed, constructed or acquired in respect of which such indebtedness has been incurred and to the receivables, inventory, equipment, chattels payable, contracts, intangibles and other assets, rights or collateral connected with the properties or assets created, developed, constructed or acquired and to which such lender has recourse.

“Permitted Liens” of any Person at any particular time means:

·Liens existing as of the date of the Indenture, or arising thereafter pursuant to contractual commitments entered into prior to such date;

·Liens on Current Assets given in the ordinary course of business to any financial institution or others to secure any indebtedness payable on demand or maturing (including any right of extension or renewal) within 12 months or less from the date such indebtedness is incurred;

·Liens in connection with indebtedness, which, by its terms, is Non-Recourse Debt to us or any of our Subsidiaries;

·Liens existing on property or assets at the time of acquisition (including by way of lease) by such Person, provided that such Liens were not incurred in anticipation of such acquisition;

·Liens or obligations to incur Liens (including under indentures, trust deeds and similar instruments) on property or assets of another Person existing at the time such other Person becomes a Subsidiary of such Person, or is liquidated or merged into, or amalgamated or consolidated with, such Person or Subsidiary of such Person or at the time of the sale, lease or other disposition to such Person or Subsidiary of such Person of all or substantially all of the properties and assets of such other Person, provided that such Liens were not incurred in anticipation of such other Person becoming a Subsidiary of such Person;

·Liens upon property or assets of whatsoever nature other than Restricted Property;

·Liens upon property or facilities used in connection with, or necessarily incidental to, the purchase, sale, storage, transportation or distribution of oil or gas or the products derived from oil or gas;

·Liens arising under partnership agreements, oil and natural gas leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, master limited partnership agreements, farm-out agreements, division orders, contracts for the sale, purchase, exchange, storage, transportation, distribution, gathering or processing of Restricted Property, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts (including security in respect of take or pay or similar obligations thereunder), area of mutual interest agreements, natural gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical

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permits or agreements, which in each of the foregoing cases is customary in the oil and natural gas business, and other agreements which are customary in the oil and natural gas business, provided in all instances that such Lien is limited to the property or assets that are the subject of the relevant agreement;

·Liens on assets or property (including oil sands property) securing: (i) all or any portion of the cost of acquisition (directly or indirectly), surveying, exploration, drilling, development, extraction, operation, production, construction, alteration, repair or improvement of all or any part of such assets or property, the plugging and abandonment of wells and the decommissioning or removal of structures or facilities located thereon, and the reclamation and clean-up of such properties, facilities and interests and surrounding lands whether or not owned by us or our Restricted Subsidiaries, (ii) all or any portion of the cost of acquiring (directly or indirectly), developing, constructing, altering, improving, operating or repairing any assets or property (or improvements on such assets or property) used or to be used in connection with such assets or property, whether or not located (or located from time to time) at or on such assets or property, (iii) indebtedness incurred by us or any of our Subsidiaries to provide funds for the activities set forth in clauses (i) and (ii) above, provided such indebtedness is incurred prior to, during or within two years after the completion of acquisition, construction or such other activities referred to in clauses (i) and (ii) above, and (iv) indebtedness incurred by us or any of our Subsidiaries to refinance indebtedness incurred for the purposes set forth in clauses (i) and (ii) above. Without limiting the generality of the foregoing, costs incurred after the date hereof with respect to clauses (i) or (ii) above shall include costs incurred for all facilities relating to such assets or property, or to projects, ventures or other arrangements of which such assets or property form a part or which relate to such assets or property, which facilities shall include, without limitation, Facilities, whether or not in whole or in part located (or from time to time located) at or on such assets or property;

·Liens granted in the ordinary course of business in connection with Financial Instrument Obligations;

·Purchase Money Mortgages;

·Liens in favor of us or any of our Subsidiaries to secure indebtedness owed to us or any of our Subsidiaries; and

·any extension, renewal, alteration, refinancing, replacement, exchange or refunding (or successive extensions, renewals, alterations, refinancings, replacements, exchanges or refundings) of all or part of any Lien referred to in the foregoing clauses; provided, however, that (i) such new Lien shall be limited to all or part of the property or assets which was secured by the prior Lien plus improvements on such property or assets and (ii) the indebtedness, if any, secured by the new Lien is not increased from the amount of the indebtedness secured by the prior Lien then existing at the time of such extension, renewal, alteration, refinancing, replacement, exchange or refunding, plus an amount necessary to pay fees and expenses, including premiums, related to such extensions, renewals, alterations, refinancings, replacements, exchanges or refundings.

“Person” means any individual, corporation, partnership, limited liability company, unlimited liability company, joint venture, association, joint-stock company, trust, unincorporated organization or government or any agency or political subdivision thereof.

“Purchase Money Mortgage” of any Person means any Lien created upon any property or assets of such Person to secure or securing the whole or any part of the purchase price of such property or assets or the whole or any part of the cost of constructing or installing fixed improvements thereon or to secure or securing the repayment of money borrowed to pay the whole or any part of such purchase price or cost of any vendor’s privilege or Lien on such property or assets securing all or any part of such purchase price or cost including title retention agreements and leases in the nature of title retention agreements; provided that (i) the principal amount of money borrowed which is secured by such Lien does not exceed 100% of such purchase price or cost and any fees incurred in

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connection therewith, and (ii) such Lien does not extend to or cover any other property other than such item of property and any improvements on such item.

“Reference Treasury Dealers” means each of Barclays Capital Inc., Banc of America Securities LLC and RBC Capital Markets Corporation or their affiliates, plus two others which are primary U.S. Government securities dealers and their respective successors; provided, however, that if any of the foregoing or their affiliates shall cease to be a primary U.S. Government securities dealer in the United States (a “Primary Treasury Dealer”), we shall substitute for it another Primary Treasury Dealer.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Reference Treasury Dealer, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted by such Reference Treasury Dealers at 3:30 p.m. New York Time on the third business day preceding such redemption date.

“Restricted Property” means any oil, gas or mineral property of a primary nature located in the United States or Canada, and any facilities located in the United States or Canada directly related to the mining, processing or manufacture of hydrocarbons or minerals, or any of the constituents thereof and includes Voting Shares or other interests of a corporation or other Person which owns such property or facilities, but does not include (i) any property or facilities used in connection with or necessarily incidental to the purchase, sale, storage, transportation or distribution of Restricted Property, (ii) any property which, in the opinion of our board of directors, is not materially important to the total business conducted by us and our Subsidiaries as an entirety or (iii) any portion of a particular property which, in the opinion of our board of directors, is not materially important to the use or operation of such property.

“Restricted Subsidiary” means, on any date, any Subsidiary of ours which owns at the time Restricted Property; provided, however, such term shall not include a Subsidiary of ours if the amount of our share of Shareholders’ Equity of such Subsidiary constitutes, at the time of determination, less than 2% of our Consolidated Net Tangible Assets.

“Shareholders’ Equity” means the aggregate amount of shareholders’ equity (including but not limited to share capital, contributed surplus and retained earnings) of a Person as shown on the most recent annual audited or unaudited interim consolidated balance sheet of such Person and computed in accordance with GAAP.

“Subsidiary” of any Person means, on any date, any corporation or other Person of which Voting Shares or other interests carrying more than 50% of the voting rights attached to all outstanding Voting Shares or other interests are owned, directly or indirectly, by or for such Person or one or more Subsidiaries thereof.

“Voting Shares” means shares of any class of any corporation carrying voting rights under all circumstances, provided that, for the purposes of this definition, shares which only carry the right to vote conditionally on the happening of any event shall not be considered Voting Shares, nor shall any shares be deemed to cease to be Voting Shares solely by reason of a right to vote accruing to shares of another class or classes by reason of the happening of such an event, or solely because the right to vote may not be exercisable under the charter of the corporation.

Certain Covenants

Limitation on Liens

The Indenture provides that so long as any of the notes are outstanding and subject to the provisions of the Indenture, we will not, and will not permit any of our Restricted Subsidiaries to, create, incur, assume or otherwise have outstanding any Lien securing any indebtedness for borrowed money or interest thereon (or any liability of ours or such Restricted Subsidiaries under any guarantee or endorsement or other instrument under which we or such Restricted Subsidiaries are contingently liable, either directly or indirectly, for borrowed money or interest

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thereon), other than Permitted Liens, without also simultaneously or prior thereto securing, or causing such Restricted Subsidiaries to secure, indebtedness under the Indenture so that the notes are secured equally and ratably with or prior to such other indebtedness, except that we and our Restricted Subsidiaries may incur a Lien to secure indebtedness for borrowed money without securing the notes if, after giving effect thereto, the principal amount of indebtedness for borrowed money secured by Liens created, incurred or assumed after the date of the Indenture and otherwise prohibited by the Indenture does not exceed 10% of our Consolidated Net Tangible Assets.

Notwithstanding the foregoing, transactions such as the sale (including any forward sale) or other transfer of (i) oil, gas, minerals or other resources of a primary nature, whether in place or when produced, for a period of time until, or in an amount such that, the purchaser will realize therefrom a specified amount of money or a specified rate of return (however determined), or a specified amount of such oil, gas, minerals, or other resources of a primary nature, or (ii) any other interest in property of the character commonly referred to as a “production payment”, will not constitute a Lien and will not result in us or a Restricted Subsidiary of ours being required to secure the notes.

Consolidation, Amalgamation, Merger and Sale of Assets

We may not consolidate or amalgamate with or merge into or enter into any statutory arrangement with any other corporation, or convey, transfer or lease all or substantially all our properties and assets to any Person, unless:

·the entity formed by or continuing from such consolidation or amalgamation or into which we are merged or with which we enter into such statutory arrangement or the Person which acquires or leases all or substantially all of our properties and assets is organized and existing under the laws of the United States, any state thereof or the District of Columbia or the laws of Canada or any province or territory thereof, or, if such consolidation, amalgamation, merger, statutory arrangement or other transaction would not impair the rights of the holders of our notes, in any other country, provided that if such successor entity is organized under the laws of a jurisdiction other than the United States, any state thereof or the District of Columbia, or the laws of Canada or any province or territory thereof, the successor entity assumes our obligations under the notes and the Indenture to pay Additional Amounts (as defined herein), with the name of such successor jurisdiction being included in addition to Canada in each place that Canada appears in “–Payment of Additional Amounts” and in “Tax Redemption” below;

·the successor entity expressly assumes or assumes by operation of law all of our obligations under the notes and under the Indenture;

·immediately before and after giving effect to such transaction, no event of default, and no event which, after notice or lapse of time or both, would become an event of default, shall have happened and be continuing; and

·we or the successor entity, as the case may be, delivers to the Trustee an officer’s certificate and an opinion of counsel stating that such amalgamation, statutory arrangement, consolidation, merger, conveyance, transfer or lease and such supplemental indenture complies with the Indenture.

Notwithstanding anything in the Indenture to the contrary, we may, in addition to our right to enter into a transaction permitted by the preceding paragraph, consolidate or amalgamate with or merge into or enter into a statutory amalgamation with any direct or indirect wholly-owned Subsidiary and we may convey, transfer or lease all or substantially all of our properties and assets to any direct or indirect wholly-owned Subsidiary without complying with the provisions in the preceding paragraph in a transaction or series of transactions in which we retain all of our obligations under and in respect of all outstanding notes (a “Permitted Reorganization”) provided that on or prior to the date of the Permitted Reorganization we deliver to the Trustee an officer’s certificate confirming that, as of the date of the Permitted Reorganization:

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·substantially all of our unsubordinated and unsecured indebtedness for borrowed money which ranked pari passu with the then outstanding notes immediately prior to the proposed Permitted Reorganization will rank no better than pari passu with the notes after the Permitted Reorganization; for certainty, there is no requirement for any such other indebtedness to obtain or maintain similar ranking to the notes and such other indebtedness may be structurally subordinated or otherwise subordinated to the notes; or

·at least two of our then current credit rating agencies (or if only one credit rating agency maintains ratings in respect of the notes at such time, that one rating agency) have affirmed that the rating assigned by them to the notes shall not be downgraded as a result of the Permitted Reorganization.

If, as a result of any such transaction described in the preceding paragraphs, any of our or our Restricted Subsidiaries’ Restricted Properties become subject to a Lien, then, unless such Lien could be created pursuant to the Indenture provisions described under the “Limitation on Liens” covenant above without equally and ratably securing our notes, we, simultaneously with or prior to such transaction, will secure, or cause the applicable Restricted Subsidiary to secure, our notes to be secured equally and ratably with or prior to the indebtedness secured by such Lien.

Optional Redemption

Each series of notes will be redeemable, in whole or in part, at our option at any time or from time to time at a redemption price equal to the greater of:

·100% of the principal amount of the notes to be redeemed, and

·the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed (exclusive of interest accrued to the date of redemption) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Adjusted Treasury Rate (as defined above) plus 35 basis points in respect of each of the New 2014 Notes and New 2019 Notes and 40 basis points in respect of the New 2039 Notes,

plus accrued interest thereon to the date of redemption.

Notice of any redemption will be mailed at least 30 days but not more than 60 days before the redemption date to each holder of the notes to be redeemed.

Unless we default in payment of the redemption price, on and after the redemption date, interest will cease to accrue on the notes or the portions of the notes called for redemption.

In the case of a partial redemption of a series of notes, selection of such notes for redemption will be made pro rata, by lot or such other method as the Trustee in its sole discretion deems appropriate and just.  If any note is redeemed in part, the notice of redemption relating to such note shall state the portion of the principal amount thereof to be redeemed; provided that no note in an aggregate principal amount of $2,000 or less shall be redeemed in part.  A replacement note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original note.

Payment of Additional Amounts

All payments made by or on behalf of us under or with respect to any series of the notes will be made free and clear of and without withholding or deduction for or on account of any present or future tax, duty, levy, impost, assessment or other governmental charge (including penalties, interest and other liabilities related thereto) imposed or levied by or on behalf of the Government of Canada or any province or territory thereof or by any authority or agency therein or thereof having power to tax (hereinafter “Canadian Taxes”), unless we are required to withhold or deduct Canadian Taxes by law or by the interpretation or administration thereof.  If we are so required to withhold

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or deduct any amount for or on account of Canadian Taxes from any payment made under or with respect to the notes, of any series, we will pay to each holder of such notes as additional interest such additional amounts (“Additional Amounts”) as may be necessary so that the net amount received by each such holder (including the Additional Amounts) after such withholding or deduction (and after deducting any Canadian Taxes on such Additional Amounts) will not be less than the amount such holder would have received if such Canadian Taxes had not been withheld or deducted.  However, no Additional Amounts will be payable with respect to a payment made to a note holder (such holder, an “Excluded Holder”) in respect of the beneficial owner thereof:

·with which we do not deal at arm’s length (for the purposes of the Tax Act) at the time the amount is paid or payable;

·which is subject to such Canadian Taxes by reason of the note holder or beneficial owner thereof being a resident, domicile or national of, or engaged in business or maintaining a permanent establishment or other physical presence in or otherwise having some present or former connection with Canada or any province or territory thereof otherwise than by the mere holding of the notes or the receipt of payments thereunder; or

·which is subject to such Canadian Taxes by reason of the note holder’s failure to comply with any certification, identification, information, documentation or other reporting requirements if compliance is required by law, regulation, administrative practice or an applicable treaty as a precondition to exemption from, or a reduction in the rate of deduction or withholding of, such Canadian Taxes.

In addition, Additional Amounts will not be payable if the beneficial owner of, or Person ultimately entitled to obtain an interest in, such notes is not the sole beneficial owner of such payments, or is a fiduciary or partnership, to the extent that any beneficial owner, beneficiary or settlor with respect to such fiduciary or any partner or member of such partnership would not have been entitled to such Additional Amounts with respect to such payments had such beneficial owner, beneficiary, settlor, partner or member received directly its beneficial or distributive shares of such payments.  In addition, Additional Amounts will not be payable with respect to any Canadian Taxes which are payable otherwise than by withholding from payments of, or in respect of, principal of, or interest on, the notes.

We will also:

·make such withholding or deduction; and

·remit the full amount deducted or withheld to the relevant authority in accordance with applicable law.

We will furnish to the holders of the notes, within 60 days after the date the payment of any Canadian Taxes is due pursuant to applicable law, certified copies of tax receipts or other documents evidencing such payment by us.

We will indemnify and hold harmless each holder of notes (other than an Excluded Holder) and upon written request reimburse each such holder for the amount (excluding any Additional Amounts that have previously been paid by us with respect thereto) of:

·the payment of any Canadian Tax, together with any interest, penalties and reasonable expenses in connection therewith; and

·any Canadian Taxes imposed with respect to any reimbursement under the preceding clause, but excluding any such Canadian Taxes on such holder’s net income.

In any event, provided that we or any successor is a Canadian or U.S. entity, no Additional Amounts or indemnity amounts will be payable in excess of Additional Amounts or the indemnity amounts which would be

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required if the holder of notes and beneficial owner thereof was a resident of the United States and a qualifying person for purposes of the Canada-U.S. Income Tax Convention (1980), as amended.

Wherever in the Indenture there is mentioned, in any context, the payment of principal (and premium, if any), interest, if any, or any other amount payable under or with respect to a note, such mention shall be deemed to include mention of the payment of Additional Amounts to the extent that, in such context, Additional Amounts are, were or would be payable in respect thereof.

Tax Redemption

Each series of the notes will be subject to redemption at any time, in whole and not in part, at a redemption price equal to the principal amount thereof together with accrued and unpaid interest to the date fixed for redemption, upon the giving of a notice as described below, if:

·as a result of any change in or amendment to the laws (or any regulations or rulings promulgated thereunder) of Canada or of any political subdivision or taxing authority thereof or therein affecting taxation, or any change in official position regarding the application or interpretation of such laws, regulations or rulings (including a holding by a court of competent jurisdiction), which change or amendment is announced or becomes effective on or after the later of (i) the date hereof or (ii) if applicable, the date a party organized in a jurisdiction other than Canada or the United States becomes Cenovus’s successor, we or such successor reasonably determine that we have or will become obligated to pay, on the next succeeding date on which interest is due, Additional Amounts with respect to any note of such series as described under “–Payment of Additional Amounts”; or

·on or after the later of (i) the date hereof or (ii) if applicable, the date a party organized in a jurisdiction other than Canada or the United States becomes Cenovus’s successor, any action has been taken by any taxing authority of, or any decision has been rendered by a court of competent jurisdiction in Canada, or any political subdivision or taxing authority thereof or therein, including any of those actions specified in the paragraph immediately above, whether or not such action was taken or decision was rendered with respect to us or such successor, or any change, amendment, application or interpretation shall be officially proposed, which, in any such case, in the written opinion to us of legal counsel of recognized standing, will likely result in our or such successor becoming obligated to pay, on the next succeeding date on which interest is due, Additional Amounts with respect to the notes of such series;

and, in any such case, we, in our business judgment (or the successor’s business judgment), determine that such obligation cannot be avoided by the use of reasonable measures available to us.

In the event that we (or our successor) elect to redeem a series of the notes pursuant to the provisions set forth in the preceding paragraph, we shall deliver to the Trustee a certificate, signed by an authorized officer, stating that we are entitled to redeem such series of notes pursuant to their terms.

Notice of intention to redeem a series of the notes will be given not earlier than 60 nor later than 30 days prior to the date on which we (or our successor) would become obligated to pay such Additional Amounts were a payment in respect of the notes of such series then due.

Provision of Financial Information

We will furnish to the Trustee, within 30 days after we file them with or furnish them to the SEC, copies (which may be electronic copies) of our annual and quarterly reports and of the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) which we are required to file with or furnish to the SEC pursuant to Section 13 or 15(d) of the Exchange Act.

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In the event that we may not remain subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act or otherwise report on an annual and quarterly basis on forms provided for such annual and quarterly reporting pursuant to rules and regulations promulgated by the SEC, we will continue to furnish to the Trustee:

·within the time periods required for the filing of annual information forms and annual financial statements (or similar annual filings) by the Canadian securities regulatory authorities, the information required to be provided or incorporated by reference in an annual information form, annual financial statement or similar annual filing under the laws of Canada or any province thereof to security holders of a corporation with securities listed on the TSX, whether or not we have any of our securities listed on such exchange; and

·within the time periods required for the filing of quarterly reports by the Canadian securities regulatory authorities, the information required to be provided in quarterly reports under the laws of Canada or any province thereof to security holders of a corporation with securities listed on the TSX, whether or not we have any of our securities listed on such exchange.

Events of Default

The following are summaries of events of default under the Indenture with respect to the notes of any series:

·default in the payment of any interest on the notes of that series when it becomes due and payable, and continuance of such default for a period of 30 days;

·default in the payment of the principal of (or premium, if any, on), the notes of that series when it becomes due and payable;

·default in the performance, or breach, of any of our covenants or warranties in the Indenture in respect of the notes of that series (other than a covenant or warranty a default in the performance of which or the breach of which is specifically dealt with elsewhere in the Indenture), and continuance of such default or breach for a period of 60 days after receipt by us of written notice to us, specifying such default or breach, by the Trustee or by the holders of at least 25% in principal amount of all outstanding notes of any series affected thereby;

·if an event of default (as defined in any indenture or instrument under which we or one of our Restricted Subsidiaries has at the time of the Indenture or shall thereafter have outstanding any indebtedness for borrowed money) shall happen and be continuing, or we or any Restricted Subsidiary shall have failed to pay principal amounts with respect to such indebtedness at maturity and such event of default or failure to pay shall result in such indebtedness being declared due and payable or otherwise being accelerated, in either event so that an amount in excess of the greater of $150,000,000 and 2% of our Shareholders’ Equity shall be or become due and payable upon such declaration or otherwise accelerated prior to the date on which the same would otherwise have become due and payable (the “accelerated indebtedness”), and such acceleration shall not be rescinded or annulled, or such event of default or failure to pay under such indenture or instrument shall not be remedied or cured, whether by payment or otherwise, or waived by the holders of such accelerated indebtedness, then (i) if the accelerated indebtedness shall be as a result of an event of default which is not related to the failure to pay principal or interest on the terms, at the times, and on the conditions set out in any such indenture or instrument, it shall not be considered an event of default for purposes of the Indenture until 30 days after such indebtedness has been accelerated, or (ii) if the accelerated indebtedness shall occur as a result of such failure to pay principal or interest or as a result of an event of default which is related to the failure to pay principal or interest on the terms, at the times, and on the conditions set out in any such indenture or instrument, then (A) if such accelerated indebtedness is, by its terms, Non-Recourse Debt to us or our Restricted Subsidiaries, it shall not be considered an event of default for purposes of the Indenture; or (B) if such accelerated indebtedness is recourse to us or our Restricted Subsidiaries, any requirement in connection with such failure to pay or event of default for the

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giving of notice or the lapse of time or the happening of any further condition, event or act under such other indenture or instrument in connection with such failure to pay principal or an event of default shall be applicable together with an additional seven days before being considered an event of default for purposes of the Indenture;

·the entry of decree or order by a court having jurisdiction in the premises adjudging us a bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of us under the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada) or any other applicable insolvency law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or similar official) of us or of any substantial part of our property, or ordering the winding up or liquidation of our the affairs, and the continuance of any such decree or order unstayed and in effect for a period of 90 consecutive days; or

·the institution by us of proceedings to be adjudicated a bankrupt or insolvent, or the consent by us to the institution of bankruptcy or insolvency proceedings against us, or the filing by us of a petition or answer or consent seeking reorganization or relief under the Bankruptcy and Insolvency Act (Canada), the Companies’ Creditors Arrangement Act (Canada) or any other applicable insolvency law, or the consent by us to the filing of any such petition or to the appointment of a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of us or of any substantial part of our property, or the making by us of an assignment for the benefit of creditors, or the admission by it in writing of our inability to pay our debts generally as they become due.

If an event of default under the Indenture occurs and is continuing with respect to the notes of any series, then and in every such case the Trustee or the holders of at least 25% in aggregate principal amount of the outstanding notes of such affected series may, subject to any subordination provisions thereof, declare the entire principal amount of all notes of that series and all accrued and unpaid interest thereon to be immediately due and payable.  However, at any time after a declaration of acceleration with respect to the notes of any series has been made, but before a judgment or decree for payment of the money due has been obtained, the holders of a majority in principal amount of the outstanding notes of that series, by written notice to us and the Trustee under certain circumstances, including the payment or deposit with the Trustee of a sum sufficient to pay all sums paid or advanced by the Trustee and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel in connection with such event of default, may rescind and annul such acceleration.

Subject to certain limitations set forth in the Indenture, the holders of a majority in principal amount of the outstanding notes of all series affected by the event of default shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the notes.

No holder of any notes of any series will have any right to institute any proceeding with respect to the Indenture, or for the appointment of a receiver or a Trustee, or for any other remedy thereunder, unless:

·such holder has previously given to the Trustee written notice of a continuing event of default with respect to the notes of that series;

·the holders of at least 25% in aggregate principal amount of the outstanding notes of that series affected by such event of default (voting as one class) have made written request, and such holder or holders have offered reasonable indemnity, to the Trustee to institute such proceeding as Trustee; and

·the Trustee has failed to institute such proceeding, and has not received from the holders of a majority in aggregate principal amount of the outstanding notes of that series affected by such event of default a direction inconsistent with such request, within 60 days after such notice, request and offer.

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However, such above-mentioned limitations do not apply to a suit instituted by the holder of a note for the enforcement of payment of the principal of or any premium or interest on such note on or after the applicable due date.

We will annually furnish to the Trustee a statement by certain of our officers as to whether or not we, to the best of their knowledge, are in compliance with all conditions and covenants of the Indenture and, if not, specifying all such known defaults.

Defeasance and Covenant Defeasance

The Indenture provides that, at our option, we will be discharged from any and all obligations in respect of the outstanding notes of any series upon irrevocable deposit with the Trustee, in trust, of money and/or government securities which will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent chartered accountants (as evidenced by an officer’s certificate delivered to the Trustee) to pay the principal of (and premium, if any, and each installment of interest, if any, on) the outstanding notes of such series (hereinafter referred to as a “defeasance”) (except with respect to the authentication, transfer, exchange or replacement of the notes or the maintenance of a place of payment and certain other obligations set forth in the Indenture). Such trust may only be established if among other things:

·we have delivered to the Trustee an opinion of counsel in the United States stating that (i) we have received from, or there has been published by, the Internal Revenue Service a ruling, or (ii) since the date of execution of the Indenture, there has been a change in the applicable U.S. federal income tax law, in either case to the effect that the holders of the outstanding notes of such series will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such defeasance had not occurred;

·we have delivered to the Trustee an opinion of counsel in Canada or a ruling from the Canada Revenue Agency (or successor agency) to the effect that the holders of the outstanding notes of such series should not recognize income, gain or loss for Canadian federal or provincial income purposes as a result of such defeasance and should be subject to Canadian federal or provincial income on the same amounts, in the same manner and at the same times as would have been the case had such defeasance not occurred (and for the purposes of such opinion, such Canadian counsel shall assume that holders of the outstanding notes of such series include holders who are not resident in Canada);

·no event of default or event that, with the passing of time or the giving of notice, or both, shall constitute an event of default shall have occurred and be continuing on the date of such deposit; and

·we are not an “insolvent person” within the meaning of the Bankruptcy and Insolvency Act (Canada) on the date of such deposit or at any time during the period ending on the 91st day following such deposit.

We may exercise our defeasance option notwithstanding our prior exercise of our covenant defeasance option described in the following paragraph if we meet the conditions described in the preceding sentence at the time we exercise the defeasance option.

The Indenture provides that, at our option, unless and until we have exercised our defeasance option described in the preceding paragraph, we may omit to comply with the “Limitation on Liens” covenant, certain aspects of the “Consolidation, Amalgamation, Merger and Sale of Assets” covenant and certain other covenants and such omission shall not be deemed to be an event of default under the Indenture and our outstanding notes upon irrevocable deposit with the Trustee, in trust, of money and/or government securities which will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent chartered accountants (as evidenced by an officer’s certificate delivered to the Trustee) to pay the principal of (and premium, if any, and each installment of interest, if any, on) the outstanding notes (hereinafter referred to as “covenant defeasance”).  If we

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exercise our covenant defeasance option, the obligations under the Indenture other than with respect to such covenants and the events of default other than with respect to such covenants shall remain in full force and effect. Such trust may only be established if, among other things:

·we have delivered to the Trustee an opinion of counsel in the United States to the effect that the holders of our outstanding notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such covenant defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such covenant defeasance had not occurred;

·we have delivered to the Trustee an opinion of counsel in Canada or a ruling from the Canada Revenue Agency to the effect that the holders of our outstanding notes will not recognize income, gain or loss for Canadian federal or provincial income or other tax purposes as a result of such covenant defeasance and will be subject to Canadian federal or provincial income and other tax on the same amounts, in the same manner and at the same times as would have been the case had such covenant defeasance not occurred (and for the purposes of such opinion, such Canadian counsel shall assume that holders of our outstanding notes include holders who are not resident in Canada);

·no event of default or event that, with the passing of time or the giving of notice, or both, shall constitute an event of default shall have occurred and be continuing on the date of such deposit; and

·we are not an “insolvent person” within the meaning of the Bankruptcy and Insolvency Act (Canada) on the date of such deposit or at any time during the period ending on the 91st day following such deposit.

Modification and Waiver

Modifications and amendments of the Indenture may be made by us and the Trustee with the consent of the holders of a majority in principal amount of the outstanding notes of a series affected by such modification or amendment (voting as one class); provided, however, that no such modification or amendment may, without the consent of the holders of all outstanding notes of such affected series:

·change the stated maturity of the principal of, or any installment of interest, if any, on any note of that series;

·reduce the principal amount of (or premium, if any, or interest, if any, on) any note of that series;

·reduce the amount of principal of a note of that series payable upon acceleration of the maturity thereof;

·change the place of payment;

·change the currency of payment of principal of (or premium, if any, or interest, if any, on) any note of that series;

·impair the right to institute suit for the enforcement of any payment on or with respect to any note of that series;

·reduce the percentage of principal amount of outstanding notes of that series, the consent of the holders of which is required for modification or amendment of the Indenture or for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults; or

·modify any provisions of the Indenture relating to the modification and amendment of the Indenture or the waiver of past defaults or covenants except as otherwise specified in the Indenture.

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The holders of a majority in principal amount of the outstanding notes of any series may on behalf of the holders of all notes of that series waive, insofar as that series is concerned, compliance by us with certain restrictive provisions of the Indenture.  The holders of a majority in principal amount of outstanding notes of any series may waive any past default under the Indenture with respect to that series, except a default in the payment of the principal of (or premium, if any) and interest, if any, on any note of that series or in respect of a provision which under the Indenture cannot be modified or amended without the consent of the holder of each outstanding note of that series.

The Indenture or the notes may be amended or supplemented, without the consent of any holder of such notes, in order to, among other things, cure any ambiguity or inconsistency or to make any change, in any case, that does not have a materially adverse effect on the rights of any holder of such notes.

Governing Law

Our notes and the Indenture are governed by and construed in accordance with the laws of the State of New York.

Enforceability of Judgments

We are currently organized under the laws of Canada and, accordingly, are governed by the applicable provincial and federal laws of Canada.  A majority of our directors and officers and certain of the experts named in this prospectus reside principally in Canada.  Because we and these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on these persons.  Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States courts, because a substantial portion of our assets and their assets are located outside the United States. We have been advised by Bennett Jones LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the United States federal securities laws and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based upon the civil liability provisions of the United States federal securities laws.  Therefore, it may not be possible to enforce those actions against us, a majority of our directors and officers or certain of the experts named in this prospectus.

CERTAIN CANADIAN AND UNITED STATES INCOME TAX CONSIDERATIONS

Certain Canadian Federal Income Tax Considerations

In the opinion of Bennett Jones LLP, our Canadian legal counsel (“Canadian Counsel”), the following is, as of the date of this prospectus, a general summary of the principal Canadian federal income tax considerations generally applicable to a holder of Initial Notes who exchanges such Initial Notes for Exchange Notes pursuant to the exchange offer and who, at all relevant times, and for the purposes of the Tax Act and any applicable income tax treaty or convention, deals with Cenovus at arm’s length, is not and is not deemed to be a resident of Canada, holds the Initial Notes and will hold the Exchange Notes as capital property, and does not use or hold and is not deemed to use or hold the Initial Notes or the Exchange Notes in connection with a business carried on in Canada (a “Non-Resident Holder”). Special rules which are not discussed in this summary may apply to a Non-Resident Holder that is an insurer carrying on business in Canada and elsewhere.

This summary is based upon the current provisions of the Tax Act, all specific proposals to amend such provisions publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date of this prospectus, and Canadian Counsel’s understanding of the current published written administrative practices of the Canada Revenue Agency. This summary is not exhaustive of all possible Canadian federal income tax consequences, and except as noted above, does not take into account or anticipate any changes in law, whether by legislative, governmental or judicial action, and does not take into account tax legislation or considerations of any province, territory or foreign jurisdiction, which may differ from the federal income tax considerations.

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This summary is of a general nature only and is not intended to be, nor should it be construed to be, legal or tax advice to any particular Non-Resident Holder, and no representation with respect to the income tax consequences to any particular Non-Resident Holder is made.

Under the Tax Act, there will be no Canadian income taxes payable by a Non-Resident Holder in respect of the exchange of the Initial Notes for the Exchange Notes.

A Non-Resident Holder will not be subject to Canadian withholding tax in respect of any amounts paid or credited by Cenovus as, on account of, in lieu of, or in satisfaction of interest on the Exchange Notes.  There are no other Canadian income taxes payable under the Tax Act in respect of the holding, redemption or disposition of the Exchange Notes or the receipt of interest, premium or penalty on the Exchange Notes by a Non-Resident Holder from Cenovus.

Certain U.S. Federal Income Tax Considerations

The following summary describes certain U.S. federal income tax consequences of the exchange of Initial Notes for Exchange Notes pursuant to the exchange offer and the ownership and disposition of Exchange Notes by U.S. Holders (as defined below).  This discussion is based on existing provisions of the Code, final and temporary Treasury Regulations promulgated thereunder (“Treasury Regulations”), administrative pronouncements or practice, judicial decisions, and interpretations of the foregoing, all as of the date hereof.  Future legislative, judicial or administrative modifications, revocations or interpretations, which may or may not be retroactive, may result in U.S. federal income tax consequences significantly different from those discussed herein.  This discussion is not binding on the IRS. No ruling has been or will be sought or obtained from the IRS with respect to any of the U.S. federal income tax consequences discussed herein. There can be no assurance that the IRS will not challenge any of the conclusions described herein or that a U.S. court will not sustain such challenge.

This discussion does not purport to deal with all aspects of U.S. federal income taxation that may be relevant to particular holders in light of their particular circumstances nor does it deal with persons that are subject to special tax rules, such as (i) banks, financial institutions or insurance companies; (ii) regulated investment companies or real estate investment trusts; (iii) brokers or dealers in securities or currencies or traders in securities that elect to apply a mark-to-market accounting method; (iv) tax-exempt organizations, qualified retirement plans, individual retirement accounts or other tax deferred accounts; (v) persons that hold an Initial Note or an Exchange Note as a part of a straddle, hedge, or conversion transaction or a synthetic security or other integrated transaction; (vi) holders whose “functional currency” is not the U.S. dollar; (vii) U.S. expatriates; and (viii) holders that are not U.S. Holders. This discussion assumes that an Initial Note and an Exchange Note are held as capital assets within the meaning of Section 1221 of the Code.  Furthermore, this discussion does not address any U.S. federal alternative minimum tax, U.S. federal estate, gift or other non-income tax, or any state, local or non-U.S. tax consequences of the exchange or the ownership or disposition of the Exchange Notes.

As used in this section, the term “U.S. Holder” means a beneficial owner of an Initial Note or an Exchange Note that is (i) a citizen or an individual resident of the United States, as determined for U.S. federal income tax purposes, (ii) a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States or any political subdivision thereof or therein, (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source or (iv) a trust (A) which is subject to the primary jurisdiction of a court within the United States and for which one or more U.S. persons have authority to control all substantial decisions or (B) which has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.

If a pass-through entity, including a partnership or other entity taxable as a partnership for U.S. federal income tax purposes, holds an Initial Note or an Exchange Note, the U.S. federal income tax treatment of an owner or partner generally will depend on the status of such owner or partner and on the activities of the pass-through entity.  A U.S. Holder that is an owner or partner of a pass-through entity holding an Initial Note or an Exchange Note is urged to consult its own tax advisor.

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Exchange of Initial Notes for Exchange Notes

The exchange of an Initial Note for an Exchange Note pursuant to the exchange offer, will not constitute a taxable exchange for U.S. federal income tax purposes.  Consequently, a U.S. Holder will not recognize any gain or loss upon the receipt of the Exchange Note pursuant to the exchange offer.  A U.S. Holder’s holding period for an Exchange Note will include the holding period for the Initial Note exchanged therefor, and such U.S. Holder’s basis in the Exchange Note immediately after the exchange will be the same as its basis in such Initial Note immediately before the exchange.

Payments of Interest

Interest on an Exchange Note will generally be includable by a U.S. Holder as ordinary income at the time the interest is paid or accrued, depending on the U.S. Holder’s method of accounting for U.S. federal income tax purposes.  In addition to interest on the Exchange Note, a U.S. Holder will be required to include in income any additional amounts paid to cover any Canadian taxes withheld from interest payments. As a result, a U.S. Holder may be required to include more interest in gross income than the amount of cash it actually receives.  For U.S. foreign tax credit purposes, interest income on an Exchange Note generally will constitute foreign source income and be considered “passive category income”.  The rules governing the U.S. foreign tax credit are complex and U.S. Holders are urged to consult their tax advisors regarding the availability of the credit under their particular circumstances.

Market Discount and Bond Premium

Market Discount.  If a U.S. Holder purchased an Initial Note for an amount that is less than its stated redemption price at maturity, the amount of the difference will be treated as market discount for U.S. federal income tax purposes.  The amount of any market discount will generally be treated as de minimis and disregarded if it is less than ¼ of 1 percent of the stated redemption price of the Initial Note, multiplied by the number of complete years to maturity.  The rules described below do not apply to a U.S. Holder that holds an Initial Note that has de minimis market discount.

If a U.S. Holder exchanges an Initial Note, with respect to which there is market discount, for an Exchange Note pursuant to the exchange offer, the market discount applicable to the Initial Note should carry over to the Exchange Note so received.  In that case, such U.S. Holder is required to treat any principal payment on, or any gain on the sale, exchange, redemption or other disposition of, an Exchange Note as ordinary income to the extent of any market discount that has not previously been included in income.  If a U.S. Holder disposes of an Exchange Note in a nontaxable transaction (other than certain specified nonrecognition transactions), such U.S. Holder will be required to include any accrued market discount as ordinary income as if the U.S. Holder had sold the Exchange Note at its then fair market value.  In addition, the U.S. Holder may be required to defer, until the maturity of the Exchange Note or its earlier disposition in a taxable transaction, the deduction of a portion of the interest expense on any indebtedness incurred or continued to purchase or carry the Initial Note or the Exchange Note received in exchange therefor.

Market discount accrues ratably during the period from the date on which the Initial Note was acquired through the maturity date of the Exchange Note (for which the Initial Note was exchanged), unless an irrevocable election to accrue market discount under a constant yield method is made.  A U.S. Holder may elect to include market discount in income currently as it accrues (either ratably or under the constant-yield method), in which case the rule described above regarding deferral of interest deductions will not apply.  If a U.S. Holder makes an election to include market discount in income currently, the adjusted basis of such U.S. Holder in an Exchange Note will be increased by any market discount included in such U.S. Holder’s income.  An election to include market discount currently will apply to all market discount obligations acquired during or after the first taxable year in which the election is made, and the election may not be revoked without the consent of the IRS.

Bond Premium.  A U.S. Holder that purchased an Initial Note for an amount in excess of its principal amount, the excess will be treated as bond premium.  If a U.S. Holder exchanges an Initial Note, with respect to

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which there is a bond premium, for an Exchange Note pursuant to the exchange offer, the bond premium will carry over to the Exchange Note so received.  In general, a U.S. Holder may elect to amortize bond premium.  This election, if made, will reduce the amount required to be included in a U.S. Holder’s income each year with respect to interest on such U.S. Holder’s Exchange Note by the amount of amortizable bond premium allocable to that year. The election, once made, is irrevocable without the consent of the IRS and applies to all taxable bonds held during the taxable year for which the election is made or subsequently acquired.  If a U.S. Holder does not make this election, the U.S. Holder will be required to include in gross income the full amount of interest on the Exchange Note in accordance with its regular method of tax accounting, and will include the premium in its tax basis for the Exchange Note for purposes of computing the amount of its gain or loss recognized on the taxable disposition of the Exchange Note.

Sale, Exchange or Retirement of the Exchange Notes

Upon the sale, exchange or retirement of an Exchange Note, a U.S. Holder generally will recognize gain or loss equal to the difference between the amount realized on such sale, exchange or retirement (reduced by any amounts attributable to accrued but unpaid interest, which will be taxable as described above under “–Payments of Interest”) and the U.S. Holder’s adjusted tax basis in the Exchange Note.  A U.S. Holder’s adjusted tax basis in an Exchange Note will be the U.S. Holder’s cost for the Initial Note increased by any accrued market discount previously included in income through the date of disposition and decreased by the amount of any amortizable bond premium previously amortized by the U.S. Holder.  Gain or loss recognized on the disposition of an Exchange Note generally will be capital gain or loss and will be long-term capital gain or loss if, at the time of such disposition, the Exchange Note is treated as having been held for more than one year.  Long-term capital gain is currently subject to tax at a reduced rate to a non-corporate U.S. Holder. The deductibility of capital losses is subject to limitations.

Any gain or loss recognized on the sale, exchange, retirement or other taxable disposition of an Exchange Note generally will be U.S. source income or loss for purposes of computing the foreign tax credit allowable to a U.S. Holder.

Backup Withholding and Information Reporting

Payments of interest on an Exchange Note made within the United States (including payments made by wire transfer from outside the United States to an account maintained in the United States) and a payment of the proceeds from the sale or other taxable disposition of an Exchange Note effected at a United States office of a broker generally will be subject to information reporting. Backup withholding, currently at the rate of 28%, will generally apply if a U.S. Holder (a) fails to furnish its correct taxpayer identification number (generally on an IRS Form W–9), (b) furnishes an incorrect taxpayer identification number, (c) is notified by the IRS that it has previously failed to report properly items subject to backup withholding, or (d) fails to certify, under penalty of perjury, that it has furnished its correct taxpayer identification number and that the IRS has not notified that it is subject to backup withholding.  If a U.S. Holder is a corporation, it may be exempted from information reporting and backup withholding requirements, provided that such U.S. Holder establishes its exemption by certifying its status on an IRS Form W–9 (or a successor form).

Backup withholding is not an additional U.S. federal income tax.  Any amounts withheld under the U.S. backup withholding rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded to the extent they exceed such liability, if the U.S. Holder furnishes required information to the IRS in a timely manner.

THE U.S. FEDERAL INCOME TAX DISCUSSION SET FORTH ABOVE IS INCLUDED FOR GENERAL INFORMATION ONLY AND MAY NOT BE APPLICABLE DEPENDING UPON YOUR PARTICULAR SITUATION. YOU SHOULD CONSULT YOUR OWN TAX ADVISOR WITH RESPECT TO THE TAX CONSEQUENCES TO YOU OF THE RECEIPT OF EXCHANGE NOTES PURSUANT TO THE EXCHANGE OFFER AND THE OWNERSHIP AND DISPOSITION OF THE EXCHANGE NOTES INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, NON-U.S. AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN U.S. OR OTHER TAX LAWS.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives Exchange Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of these Exchange Notes.  This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Initial Notes where those Initial Notes were acquired as a result of market-making activities or other trading activities.  The Company has agreed that, for a period of 180 days after the Expiration Date, it will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

We will not receive any proceeds from any sale of Exchange Notes by broker-dealers.  Exchange Notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices.  Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such Exchange Notes.  Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of Exchange Notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the Expiration Date, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal.  We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The Exchange Notes are not being offered and may not be offered or sold, directly or indirectly, in Canada or to or for the account of any resident of Canada in contravention of the securities law of any province or territory of Canada.

PRIOR SALES

Debt Securities

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

The Initial Notes are, and the Exchange Notes will be, our direct, unsecured and unsubordinated obligations and rank equally and rateably with all of our other existing and future unsecured and unsubordinated indebtedness. The Initial Notes are, and the Exchange Notes will be, structurally subordinate to all existing and future indebtedness and liabilities of any of our corporate and partnership subsidiaries.

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Trading Price and Volume of Common Shares

All of the outstanding Common Shares are 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 shares traded by month for the period from December 3, 2009 to May 25, 2010:

	TORONTO STOCK EXCHANGE						NEW YORK STOCK EXCHANGE
	Share Price Trading Range						Share Price Trading Range
	High	Low			Close	Share Volume	High	Low		Close	Share Volume
	(C$ per share)					(millions)	(US$ per share)				(millions)
2009
December(1)	27.18		24.68	26.50		59.0	25.70	23.37	25.20		24.5
2010
January	27.84		24.52	24.71		51.2	26.79	22.96	23.15		24.9
February	27.67		24.26	25.70		45.8	26.58	22.87	24.50		18.4
March	27.16		24.93	26.53		51.4	26.68	24.21	26.21		12.8
April	30.63		26.75	29.87		59.6	30.66	26.49	29.30		17.8
May 1 to 25	30.44		25.83	26.01		42.0	30.10	23.84	24.45		21.6

Note:

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

LEGAL MATTERS

Legal matters in connection with this offering will be passed upon for Cenovus by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York (concerning matters of U.S. law) and Bennett Jones LLP, Calgary, Alberta (concerning matters of Canadian law).  The partners of Paul, Weiss, Rifkind, Wharton & Garrison LLP and Bennett Jones LLP, each as a group, beneficially own, directly or indirectly, less than 1% of any class of our securities.

EXPERTS

Our independent auditors are PricewaterhouseCoopers LLP, Chartered Accountants, who have issued an independent auditors’ report dated February 17, 2010 in respect of our consolidated financial statements as at December 31, 2009 and December 31, 2008 and for each of the years in the three year period ended December 31, 2009 and Cenovus’s internal control over financial reporting as at December 31, 2009.  PricewaterhouseCoopers LLP has advised that they are independent with respect to Cenovus within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the 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 our reserves contained in this prospectus and documents incorporated by reference herein was calculated by GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd. as independent petroleum consultants.

The principals of each of GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consultants Ltd., in each case, as a group own beneficially, directly or indirectly, less than 1% of any class of our securities.

- 82 -

AUDITOR’S CONSENT

We have read the prospectus of Cenovus Energy Inc. (the “Company”) dated May 26, 2010 relating to the exchange of all of its 4.50% senior notes due 2014, 5.70% senior notes due 2019 and 6.75% senior notes due 2039, such notes being issued, in each case, by a predecessor entity of the Company on September 18, 2009. We have complied with Canadian generally accepted standards for an auditor’s involvement with offering documents.

We consent to the incorporation by reference in the above-mentioned prospectus of our report dated February 17, 2010 to shareholders of the Company on the comparative consolidated financial statements for the year ended December 31, 2009, comprising the consolidated balance sheets of the Company as at December 31, 2009 and December 31, 2008 and the consolidated statements of earnings and comprehensive income, shareholders’ equity and cash flows for each of the years in the three year period ended December 31, 2009.

Calgary, Alberta	“PricewaterhouseCoopers LLP”
May 26, 2010	Chartered Accountants

GLOSSARY OF TERMS

The following is a glossary of certain terms used in this prospectus:

“2014 Notes” means, collectively, the Initial 2014 Notes, the New 2014 Notes and any future notes of the same series that may be issued by Cenovus under the Indenture;

“2019 Notes” means, collectively, the Initial 2019 Notes, the New 2019 Notes and any future notes of the same series that may be issued by Cenovus under the Indenture;

“2039 Notes” means, collectively, the Initial 2039 Notes, the New 2039 Notes and any future notes of the same series that may be issued by Cenovus under the Indenture;

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

“Arrangement” means an arrangement under Section 192 of the CBCA involving, among others, Encana, 7050372 and Subco, which became effective on the Effective Date;

“Arrangement Agreement” means the Arrangement Agreement dated as of October 20, 2009 among Encana, 7050372 and Subco;

“Assumed Liabilities” means the liabilities assumed by Subco pursuant to the Separation Agreement and described under “General Development of Our Business – The Arrangement”;

“BNY Mellon” or the “Trustee” means The Bank of New York Mellon, a New York banking corporation;

“Board” means our board of directors;

“Canadian Tax Ruling” means the advance income tax rulings and opinions received from the Canada Revenue Agency with respect to certain aspects of the Pre-Arrangement Reorganization, the Arrangement and certain other transactions, and includes any replacements thereof and amendments and supplements thereto received 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;

“CBM” means coalbed methane;

“Cenovus Assets” means the assets transferred by Encana to Subco pursuant to the Separation Agreement and described under “General Development of Our Business – The Arrangement”;

“Cenovus Businesses” means, collectively, the Integrated Oil Division and the Canadian Plains Division of Encana as they existed prior to the Effective Date;

“Cenovus Note Offering” means the offering of the Initial Notes by Subco on the Issue Date;

“CO2” means carbon dioxide;

“Code” means the Internal Revenue Code of 1986, as amended;

“Common Shares” means the common shares in the capital of Cenovus Energy Inc.;

- 84 -

“Company” means Cenovus Energy Inc.;

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

“DBRS” means DBRS Limited;

“Demand Note” means the interest bearing demand intercompany note in the amount of $3.5 billion issued by Subco to Encana;

“Dissenting Shareholder” means a shareholder of Encana that validly exercised its dissent rights in connection with the special resolution to approve the Arrangement;

“DTC” means The Depository Trust Company;

“EDGAR” means the U.S. Electronic Data-Gathering Analysis and Retrieval system;

“Effective Date” means November 30, 2009, the date upon which the Arrangement became effective;

“EH&S” means environmental, health and safety;

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

“ERCB” means Energy Resources Conservation Board;

“Expiration Date” means June 28, 2010, or such later date to which we may extend the exchange offer;

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

“Indenture” means the indenture dated September 18, 2009 between Subco and BNY Mellon;

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

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

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

“IRS” means the United States Internal Revenue Service;

“Issue Date” means September 18, 2009;

“Moody’s” means Moody’s Investors Services, Inc.;

“New 2014 Notes” means the new 4.50% senior notes due 2014 of Cenovus to be issued in exchange for the Initial 2014 Notes in accordance with the Indenture and Registration Rights Agreement;

“New 2019 Notes” means the new 5.70% senior notes due 2019 of Cenovus to be issued in exchange for the Initial 2019 Notes in accordance with the Indenture and Registration Rights Agreement;

- 85 -

“New 2039 Notes” means the new 6.75% senior notes due 2039 of Cenovus to be issued in exchange for the Initial 20139 Notes in accordance with the Indenture and Registration Rights Agreement;

“NGLs” means natural gas liquids;

“NI 51-101” means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators;

“Pre-Arrangement Reorganization” means the reorganization mechanics effected prior to the Arrangement becoming effective;

“Reorganization Time” means the time that all or substantially all of the Cenovus Assets were transferred by Encana to Subco and the Assumed Liabilities were assumed by Subco, which was 12:10 a.m. (Calgary time) on the Effective Date;

“Registration Rights Agreement” means the registration rights agreement dated September 18, 2009 among Subco and Barclays Capital Inc., Banc of America Securities LLC and RBC Capital Markets Corporation entered into in connection with the offering of the Initial Notes;

“S&P” means Standard & Poor’s Ratings Services;

“SAGD” means steam assisted gravity drainage;

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

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

“Separation Agreement” means the separation and transition agreement dated November 30, 2009 involving, among others, Encana, 7050372 and Subco regarding the transfer of the Cenovus Assets from Encana to Subco, the assumption of the Assumed Liabilities by 7050372 and Subco and certain transitional arrangements after completion of the Arrangement, as it may be amended, modified or supplemented from time to time in accordance with its terms;

“Subco” means Cenovus Energy Inc. (formerly EnCana Finance Ltd.), a corporation continued under the CBCA, which amalgamated with 7050372 on the Effective Date with the resulting amalgamated corporation being named “Cenovus Energy Inc.”;

“Tax Act” means the Income Tax Act (Canada) and the regulations thereto, as amended;

“TSX” means the Toronto Stock Exchange;

“United States” and “U.S.” means the United States of America;

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

“U.S. Tax Ruling” means the private letter ruling received from the U.S. Internal Revenue Service confirming the U.S. federal income tax consequences of certain aspects of the Pre-Arrangement Reorganization, the Arrangement and certain other transactions, and includes any amendments and supplements thereto; and

“WRB” means WRB Refining LLC.

- 86 -

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls/d	barrels per day	MMcf	million cubic feet
Mbbls/d	thousand barrels per day	MMcf/d	million cubic feet per day
MMbbls	million barrels	Tcf	trillion cubic feet
NGLs	natural gas liquids	Bcf	billion cubic feet
BOE	barrel of oil equivalent	MMbtu	million British thermal units
MMBOE	million barrels of oil equivalent
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 prospectus and the documents incorporated by reference in this prospectus, certain natural gas volumes have been converted to BOE or MBOE on the basis of six Mcf to one bbl. BOE and MBOE may be misleading, particularly if used in isolation.  A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.

F-1

INDEX TO appendices

Consolidated Financial Statements for the year ended December 31, 2009	F-2
Interim Consolidated Financial Statements (unaudited) for the period ended March 31, 2010	F-52
Management's Discussion and Analysis for the year ended December 31, 2009	A-1
Management's Discussion and Analysis for the three month period ended March 31, 2010	B-1
Reserves and Other Oil and Gas Information.	C-1

F-2

Cenovus Energy Inc.

Consolidated Financial Statements

For the Year Ended December 31, 2009

(U.S. Dollars)

F-3

Report of Management

Management’s Responsibility for the ConsolidatedFinancial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. (“Cenovus”) are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with Canadian generally accepted accounting principles and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of three independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets with Management and the independent auditors at least on a quarterly basis to review and approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control over FinancialReporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2009. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework in Internal Control–Integrated Framework to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at that date.

PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2009 as stated in their Auditors’ Report.  PricewaterhouseCoopers LLP has provided 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.

F-4

Independent Auditors’ Report

To the Shareholders of Cenovus Energy Inc.

We have completed integrated audits of Cenovus Energy Inc.’s 2009 and 2008 consolidated financial statements and of its internal control over financial reporting as of December 31, 2009 and an audit of its 2007 consolidated financial statements. Our opinions, based on our audits, are presented below.

Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. as at December 31, 2009 and December 31, 2008, and the related consolidated statements of earnings and comprehensive income, shareholders’ equity, and cash flows for each of the years in the three year period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits 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 the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Company’s financial statements for the year ended December 31, 2007 in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as at December 31, 2009 and December 31, 2008 and the results of its operations and its cash flows 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 Financial Reporting

We have also audited Cenovus Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal

Cenovus Energy Inc.

F-5

control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009 based on criteria established in Internal Control — Integrated Framework issued by the COSO.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

Canada

February 17, 2010

Cenovus Energy Inc.

F-6

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 to Consolidated Financial Statements.

Cenovus Energy Inc.

F-7

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 to Consolidated 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.

F-8

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 Other Comprehensive Income

See accompanying Notes to Consolidated Financial Statements.

Cenovus Energy Inc.

F-9

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 to Consolidated Financial Statements.

Cenovus Energy Inc.

F-10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the development, production and marketing of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”) in Canada with refining operations in the United States.

The Company is headquartered in Calgary, Alberta and its common shares are listed on the Toronto and New York stock exchanges.  Information on the Company’s background and the basis of presentation for these financial statements are found in Note 2.

Cenovus is organized into two operating divisions:

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

·Canadian PlainsDivision, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

For financial statement reporting purposes, our operating and reportable segments are:

·Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada.  This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips, an unrelated U.S. public company, and operated by Cenovus.

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

·Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities.  As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

The operating and reportable segments shown above have been changed from those presented in prior periods to match Cenovus’s structure.  All prior periods have been restated to reflect this presentation.

The tabular financial information which follows presents the segmented information first by segment and geographic location, then by product and operating division.  Capital expenditures, goodwill, sales information and information relating to Cenovus’s major customers are summarized at the end of the note.

Cenovus Energy Inc.

F-11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

1.  DESCRIPTION OF BUSINESS AND SEGMENTED 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.

F-12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Upstream Canada Product and Divisional 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.

F-13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

1.  DESCRIPTION OF BUSINESS AND SEGMENTED 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 strategic bitumen lands in exchange for certain non-core holdings.

Goodwill Additions

There were no additions to goodwill during 2009, 2008 or 2007; changes in the goodwill balance result from changes in foreign exchange rates.

Export Sales

Sales of crude oil, natural gas and NGLs produced or purchased 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 own and purchased crude oil, natural gas and refined products for the year ended December 31, 2009, Cenovus had two customers (2008–two; 2007–two) which individually accounted for more than 10 percent of its consolidated revenues, net of royalties. Sales to these customers, major international integrated energy companies 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 began independent operations on December 1, 2009, as a result of the Arrangement involving EnCana Corporation (“EnCana”) whereby EnCana was split into two independent energy companies, one a natural gas company, EnCana and the other an integrated oil company, Cenovus.  In connection with the Arrangement, EnCana common shareholders received one share in each of the new EnCana and Cenovus in exchange for each EnCana share held.  Common shares of Cenovus began trading 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 agreements with EnCana for the use of certain technical services, the marketing of crude oil, natural gas and NGLs and office space lease arrangements.  These agreements reflect terms negotiated in anticipation of each company being stand-alone public companies, each with independent boards of directors and management teams.

Cenovus Energy Inc.

F-14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise 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 relationship with the Cenovus entities. However, subsequent to the Arrangement, EnCana is no longer a related party as defined by the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3840 – Related Party Transactions.

Basis of presentation / Carve-out financial information

The Consolidated Financial Statements for the year ended December 31, 2009 include the results for the period from January 1 to November 30, 2009 prior to the Arrangement with EnCana, in addition to the results for the period from December 1 to December 31, 2009 as described below. The consolidated financial results for the periods prior to December 1, 2009 represent the financial position, results of operations and cash flows of the businesses transferred to Cenovus on a carve-out basis.

The historical financial information prior to December 1, 2009 has been derived from the accounting records of EnCana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus on a carve-out accounting basis.

As the Company operated as part of EnCana and was not a stand-alone entity prior to November 30, 2009, the historical Consolidated Financial Statements include allocations of certain EnCana revenues, expenses, assets and liabilities, including the items described below.

The operating results of Cenovus were specifically identified based on EnCana’s divisional organization. Certain other expenses presented in the Consolidated Statement of Earnings and Comprehensive Income represent allocations and estimates of the cost of services incurred by EnCana. These allocations and estimates include unrealized 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 of Cenovus have been identified based on the divisional structure, with the most significant exceptions being property, plant and equipment (“PP&E”), income taxes payable and long-term debt.

Downstream refining, crude oil and natural gas marketing and corporate depreciation, depletion and amortization have been specifically identified based on EnCana’s existing divisional structure where possible.  Depletion related to upstream properties has been allocated to Cenovus based on the related production volumes utilizing the depletion rate calculated for EnCana’s consolidated Canadian cost centre.

Mark-to-market gains and losses resulting from derivative financial instruments entered into by EnCana have been allocated to Cenovus based on the related product volumes.

Salaries, benefits, pension, long-term incentives and other post-employment benefits costs, assets and liabilities have been allocated to Cenovus based on Management’s best estimate of how services were historically provided by existing employees.  Costs, assets and liabilities associated with retired employees remain with EnCana.

Net interest expense has been calculated primarily using the debt balance allocated to Cenovus.

Income taxes have been recorded as if Cenovus and its subsidiaries had been separate tax paying legal entities, each filing a separate tax return in its local jurisdiction.  The calculation of income taxes is based on a number of assumptions, allocations and estimates, including those used to prepare the Cenovus Carve-out Consolidated Financial Statements.  Prior to the Arrangement, Cenovus’s tax pools were allocated for the Canadian cost centre based on the fair value allocation of PP&E for carve-out purposes.

Cenovus Energy Inc.

F-15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

2.  BACKGROUND & BASIS OF PRESENTATION (continued)

PP&E related to upstream oil and gas activities are accounted for by Cenovus using the full cost method of accounting.  PP&E related to upstream oil and gas activities has been determined based on an allocation process which used the ratio of future net revenue, discounted at 10 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 the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves.

Goodwill has been allocated to Cenovus based on the properties associated with the former business combinations on which it arose.

For the purpose of preparing the Carve-out Consolidated Financial Statements, it was determined that Cenovus should maintain approximately the same Debt to Capitalization ratio as consolidated EnCana.  As a result, prior to the Arrangement, debt was allocated to Cenovus based on this ratio.  Debt is defined as the current and long-term portions of Long-term Debt.  Capitalization is not a term that has a prescribed meaning under generally accepted accounting principles (“non-GAAP”) and is a measure defined as Debt plus Shareholders’ Equity.

Management believes the assumptions underlying the Cenovus Carve-out Consolidated Financial Statements are reasonable. However, the Cenovus Consolidated Financial Statements herein may not reflect Cenovus’s financial position, results of operations, and cash flows had Cenovus been a stand-alone company during the periods presented or what Cenovus’s operations, financial position, and cash flows will be in the future.  EnCana’s direct investment in Cenovus is shown as Net Investment in place of Shareholders’ Equity because a direct ownership by shareholders in Cenovus did not exist prior to November 30, 2009.  EnCana’s investment includes the accumulated net earnings, other comprehensive income and net cash distributions to EnCana.

In the opinion of Management, the Consolidated and the historical Carve-out Consolidated Financial Statements reflect all adjustments (including normal recurring adjustments) necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in United States (U.S.) dollars. While Cenovus’s reporting currency is U.S. dollars, the functional currency is Canadian dollars. All references to US$ or $ are to U.S. dollars and references to C$ are to Canadian dollars.

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries and are presented in accordance with Canadian GAAP. Information prepared in accordance with GAAP in the United States is included in Note 21.

Investments in jointly controlled partnerships and unincorporated joint ventures carry on certain of Cenovus’s development, production and crude oil refining businesses and are accounted for using the proportionate consolidation method, whereby Cenovus’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts.

Cenovus Energy Inc.

F-16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

B) Foreign Currency Translation

The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at period end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the self-sustaining operations are included in Accumulated Other Comprehensive Income (“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 are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.

C) Measurement Uncertainty

The timely preparation of the Consolidated Financial Statements in conformity with Canadian GAAP requires that Management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and the related future cash flows are subject to measurement uncertainty, and the impact in the Consolidated Financial Statements of future periods could be material.

The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which, by their nature, are subject to measurement uncertainty.

The amount of compensation expense accrued for long-term performance-based compensation arrangements is subject to Management’s best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.

The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty.

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus operates are subject to change.  As such, income taxes are subject to measurement 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 title passes from the Company to its customer. Realized gains and losses from crude oil and natural gas commodity price risk management activities are recorded in revenue when the product is sold.

Revenues and purchased product are recorded on a gross basis when the title to product passes and the risks and rewards of ownership have been transferred. Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with the services provided as agent are recorded as the services are provided.

Cenovus Energy Inc.

F-17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Unrealized gains and losses from natural gas and crude oil commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period.

E) Production and Mineral Taxes

Costs paid to non-mineral interest owners based on production of crude oil, natural gas and NGLs are recognized when the product is 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 is delivered and the services provided.

G) Employee Benefit Plans

Accruals for obligations under the employee benefit plans and the related costs are recorded net of plan assets.

The cost of pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The accrued benefit obligation is discounted using the market interest rate on high quality corporate debt instruments as at the measurement date.

Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is done on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans.

Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plans.

H) Income Taxes

Cenovus follows the liability method of accounting for income taxes, where future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs.

Cenovus Energy Inc.

F-18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

I) Earnings Per Share Amounts

Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share amounts are calculated giving effect to the potential dilution that would occur if stock options, without tandem share appreciation rights attached, were exercised or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options without tandem share appreciation rights attached and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options without tandem share appreciation rights attached are 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 of three months or less when purchased.

K) Inventories

Product inventories, including petroleum and refined products, are valued at the lower of cost and net realizable value on a first-in,
first-out or weighted average cost basis.

L) Property, Plant and Equipment

Upstream Canada

Crude oil and natural gas properties are accounted for in accordance with the CICA guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, the exploration for, and the development of bitumen, crude oil and natural gas reserves, are capitalized 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 estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, natural gas is converted to oil on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater, in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from the costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization.

An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of:

i.  the fair value of proved and probable reserves; and

ii. the costs of unproved properties that have been subject to a separate impairment test.

Cenovus Energy Inc.

F-19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Downstream Refining

The initial acquisition costs of refinery property, plant and equipment are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use and the associated asset retirement costs. Capitalized costs are not subject to depreciation until the asset is put into use, after which they are depreciated on a straight-line basis over the estimated service lives of each component of the downstream facilities.

An impairment loss is recognized on refinery property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from expected use and eventual disposition. If the carrying amount is not recoverable, an impairment loss is measured as the amount by which the refinery asset exceeds the fair value.

Other

Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Assets under construction are not subject to depreciation until put into use.

M) Capitalization of Costs

Expenditures related to renewals or betterments that improve the 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, where applicable, on a straight-line basis over the estimated useful lives of the assets.

O) Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to the country cost centre level, referred to as a reporting unit. To assess impairment, the fair value of the reporting unit is determined and compared to 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. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.

Cenovus Energy Inc.

F-20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

P) Asset Retirement Obligation

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made.

Asset retirement obligations include those legal obligations where Cenovus will be required to retire tangible long-lived assets such as producing well sites, natural gas processing plants, and refining facilities. 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 in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.

Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.

Actual expenditures incurred are charged against the accumulated obligation.

Q) Stock-Based Compensation

Obligations for payments, cash or common shares, under Cenovus’s stock options with tandem share appreciation rights attached, share appreciation rights and deferred share units plans are accrued using the intrinsic method as compensation cost over the vesting period. Fluctuations in the price of Cenovus’s common shares change the accrued compensation cost and are recognized when they occur.

EnCana replacement share options with tandem share appreciation rights attached and share appreciation rights held by Cenovus employees are accrued using the fair value method.  The fair value is recognized as compensation cost over the vesting period. Fluctuations in the fair value of the rights change the accrued compensation cost and are recognized when they occur.

R) Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”,
“available-for-sale”, “held-to-maturity”, “loans and receivables”, or “other financial 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 net earnings. 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 “other financial liabilities” are measured at amortized cost using the effective interest method of amortization.

Cash and cash equivalents are designated as “held-for-trading” and are measured at fair value. Accounts receivable and accrued revenues and the Partnership Contribution Receivable are designated as “loans and receivables”. Accounts payable and accrued liabilities, the Partnership Contribution Payable and long-term debt are designated as “other financial liabilities”. Long-term debt transaction costs, premiums and discounts are capitalized within long-term debt and amortized using the effective interest method.

Cenovus Energy Inc.

F-21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Derivative Financial Instruments

Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to natural gas and crude oil commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Realized gains or losses from financial derivatives related to power commodity prices are recognized in operating costs as the related power costs are incurred. Unrealized gains and losses are recognized at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for speculative purposes.

Policies and procedures are in place with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated from budgeted capital programs, and in other cases to the mitigation of market price risks for specific assets and obligations. When applicable, the Company identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the strategy for undertaking the economic hedge transaction. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

S) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2009.

T) Recent Accounting Pronouncements

In February 2008, the CICA’s Accounting Standards Board confirmed that International Financial Reporting Standards (“IFRS”) will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises.  Cenovus will be required to report its results in accordance with IFRS beginning in 2011.  Cenovus has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information.  The impact of IFRS on the Consolidated Financial Statements is not reasonably determinable at this time.

In addition, there are three recent accounting pronouncements as noted below, which Cenovus will be required to adopt as of January 1, 2011.  All of these standards are converged with IFRS.

·“Business Combinations”, Section 1582, which replaces the previous Business Combinations standard.  The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings.  The adoption of this standard will impact the accounting treatment of future business combinations.

Cenovus Energy Inc.

F-22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

3.  SUMMARY OF 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.  CHANGES IN ACCOUNTING POLICIES AND PRACTICES

On January 1, 2009, Cenovus adopted the CICA Handbook Section “Goodwill and Intangible Assets”, Section 3064.  The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets.  The adoption of this standard had no material impact on the Consolidated Financial Statements.

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-going portfolio management efforts, in 2009 Cenovus received cash proceeds of $209 million 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 due to the Partnership Contribution Payable and Receivable, respectively (See Note 9).

Cenovus Energy Inc.

F-23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

7.  FOREIGN EXCHANGE (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 $107 million unrealized loss on the translation of U.S. dollar risk management assets and liabilities (2008–unrealized gain of $2 million; 2007–unrealized loss of $34 million) and a $50 million realized loss related to the timing of receipt of the $3.5 billion debt offering proceeds from escrow (see Note 13).

8.  INCOME TAXES

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 tax provision in 2009 reflects the acceleration of the income tax impact of the dissolution of a partnership during the fourth quarter in conjunction with the Arrangement with EnCana.

Total income tax expense in 2009 was $302 million, which was $423 million lower than in 2008 due to lower earnings before income tax.  Current income tax expense in 2009 was $853 million, compared to $340 million in 2008.  The increase is largely attributable to the acceleration of income tax arising from the dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement and the realization of significant hedging gains in 2009.  Current tax expense for the three years is primarily an allocation of EnCana’s income tax liability on a carve-out accounting basis and as a result, there is no income tax payable by Cenovus at the end of 2009.  For 2009, there was a recovery 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 reversal of future tax on partnership income and unrealized mark-to-market hedging gains.

Cenovus Energy Inc.

F-24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

8.  INCOME TAXES (continued)

The following table reconciles income taxes calculated at the 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 as follows:

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–$77 million) related to non-capital and net operating losses available for carry forward to reduce taxable income in future years.  These losses expire no earlier than 2028.

Cenovus Energy Inc.

F-25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

9.  PARTNERSHIP CONTRIBUTION RECEIVABLE AND PAYABLE

In connection with the Arrangement with EnCana, Cenovus acquired EnCana’s assets which are jointly controlled with ConocoPhillips. On January 2, 2007, EnCana became a 50 percent partner in an integrated, North American oil business with ConocoPhillips which consists of an upstream entity and a downstream entity. The upstream entity contribution included assets from EnCana, primarily the Foster Creek and Christina Lake properties, with a fair value of $7.5 billion and a note receivable (Partnership Contribution Receivable) contributed from ConocoPhillips of an equal amount. For the downstream entity, ConocoPhillips contributed its Wood River and Borger refineries, located in Illinois and Texas, respectively, for a fair value of $7.5 billion and EnCana contributed a note payable (Partnership Contribution Payable) of $7.5 billion.

In accordance with Canadian GAAP, these entities have been accounted for using the proportionate consolidation method with the results of operations included in the Integrated Oil Division (See Note 1).

Partnership Contribution Receivable

This note receivable bears interest at a rate of 5.3 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term Partnership Contribution Receivable shown in the Consolidated Balance Sheet represents Cenovus’s 50 percent share of this promissory note, net of 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 of 6.0 percent per annum. Equal payments of principal and interest are payable quarterly, with final payment due January 2, 2017. The current and long-term Partnership Contribution Payable amounts shown in the Consolidated Balance Sheet represents Cenovus’s 50 percent share of this promissory note, 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.

F-26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

10.  INVENTORIES (continued)

As a result of a significant decline in commodity prices in the latter half of 2008, Cenovus recorded a write-down of its product inventory by $152 million from cost to net realizable value.  At December 31, 2009, the product turnover during the current year and the improvement in commodity prices resulted in a reversal of the prior year’s write-down of $144 million.

The total amount of inventories recognized as an expense during the 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 and amortization

Upstream Canada property, plant and equipment includes internal costs directly related to exploration, development and construction activities of $103 million (2008–$96 million). Costs classified as general and administrative expenses have not been capitalized as part of the capital expenditures.

Costs in respect of significant unproved properties and major development projects are excluded from the country cost centre’s depletable base.  Downstream Refining assets not put into use are excluded from depreciable costs. At the end of the year 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 of Cenovus’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.  OTHER ASSETS

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.

F-27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

13.  LONG-TERM DEBT

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 an allocation of Cenovus’s proportionate share of EnCana’s consolidated debt as at December 31, 2008.  Long-term debt was allocated to Cenovus on the same proportion of Canadian and U.S. dollar denominated debt and with the same terms and conditions as EnCana’s long-term debt.  The effective average interest rate 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$2.5 billion or its equivalent amount in U.S. dollars.  The revolving syndicated credit facility consists of two tranches, a C$2.0 billion 3-year tranche and a C$500 million 364-day tranche.  The 3-year tranche matures in November 2012 and is extendible from time to time for a period of up to three years at the option of Cenovus and upon agreement from the lenders.  The 364-day tranche matures in November 2010 and is extendible from time to time for a period of up to 364 days at the option of Cenovus and upon agreement from the lenders.  If the facilities are not extended, the full amount of the outstanding principal will come due on the respective maturity dates.

Borrowings under both 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 the 3-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 senior unsecured notes for an aggregate principal amount of $3.5 billion, issued in three 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 offering along with $151 million deposited by the Company were placed into an escrow account pending the completion of the Arrangement with EnCana.  Upon completion of the Arrangement, funds were released from escrow and the proceeds of the notes were then used to pay the note payable to EnCana of $3.5 billion as part of the Arrangement.  On November 30, 2009, these notes became the 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.

F-28

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

13.  LONG-TERM DEBT (continued)

Cenovus has agreed to use its commercially reasonable efforts to cause a registration statement with respect to an offer to exchange the U.S. unsecured notes for a new issue of notes registered under the U.S. Securities Act to be declared effective no later than September 18, 2010.

At December 31, 2009, the Company is in compliance with all of the terms of its debt agreements.

C) Debt Discounts and Transaction Costs

During 2009, $67 million in transaction costs and discounts were recorded within long-term debt relating to the issuance of the U.S. unsecured notes and the placement of the bank credit facilities.  The costs are being amortized using the effective interest method.  For comparative purposes, the transaction costs 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 associated with the retirement of upstream oil and gas assets and downstream refining facilities 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 due to the increased estimate of costs to be incurred and the rate of discount used for the current year estimate.  The total undiscounted amount of estimated cash 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 free rate of 6.23 percent (2008–6.76 percent). Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general resources at that time.

Cenovus Energy Inc.

F-29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

15.  SHARE CAPITAL

Authorized

Cenovus is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.

Issued and Outstanding

Under the terms of the Arrangement described in Note 2, EnCana shareholders exchanged their EnCana share 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 stated capital immediately prior to the Arrangement was split based on the relative fair market values of the EnCana and Cenovus Common Shares at the time of the initial exchange.  Cenovus’s share capital amount was deducted from EnCana’s net investment with the remaining $4,902 million reclassified as Paid in Surplus. In December, Cenovus declared its share of a pre-Arrangement dividend of $0.20 per share, which was charged to Paid in Surplus.  This dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flows.

Under carve-out accounting, Owner’s Net Investment represents the accumulated net earnings of the operations and the accumulated net distributions to EnCana.  Accumulated Other Comprehensive Income (“AOCI”) includes accumulated foreign currency translation adjustments.  At the date of the 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 under stock option plans.  There were no Preferred Shares outstanding as at December 31, 2009.

Net Investment

EnCana’s net investment in the operations of Cenovus prior to the Arrangement is presented as total Net Investment in the Consolidated Financial Statements.  Total Net Investment consists of Owner’s Net Investment and AOCI.

Option Plans

Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted.

Cenovus Energy Inc.

F-30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

15.  SHARE CAPITAL (continued)

Cenovus Employee Stock Option Plan

Cenovus has stock-based compensation plans that allow employees to purchase Common Shares of the Company.  Option exercise prices approximate the market price for the Common Shares on the date the options were issued.  Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, and are fully exercisable after three years and expire five years after the original grant date.  Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted.  In addition, certain stock options granted are performance based.  The performance based stock options vest and expire under the same terms and service conditions as the underlying option, and vesting is subject to Cenovus attaining prescribed performance relative to pre-determined key measures.  All new options issued by the Company have an associated Tandem Share Appreciation Right (“TSAR”) attached to them (see Note 17).

Cenovus Replacement Tandem Share Appreciation Rights (“Cenovus Replacement TSARs”) Held By EnCana Employees

Under the terms of the Arrangement, each original EnCana TSAR was replaced with one EnCana Replacement TSAR and one Cenovus Replacement TSAR with terms and conditions similar to the original EnCana TSAR.  EnCana is required to reimburse Cenovus in respect of cash payments made by Cenovus to EnCana’s employees when these employees exercise a Cenovus Replacement TSAR and therefore, no compensation expense is recognized.  No further Cenovus Replacement TSARs will be granted to EnCana employees.

EnCana employees can choose to exercise the Cenovus Replacement TSAR in exchange for a Cenovus common share or for cash.  Cenovus has recorded a liability in the Consolidated Balance Sheet for Cenovus Replacement TSARs held by EnCana employees using the fair value method, with an offsetting account receivable from EnCana.  The fair value of each Cenovus Replacement TSAR held by EnCana employees was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:

	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 tables summarize information related to the Cenovus Replacement TSARs held by EnCana employees:

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.

F-31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

15.  SHARE CAPITAL (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.  CAPITAL STRUCTURE

Cenovus’s capital structure is comprised of Shareholders’ Equity plus Long-Term Debt.  Cenovus’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Debt is defined as the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable.

Cenovus targets a Debt to Capitalization ratio of between 30 and 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 and 2.0 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	1.2x		0.7x		1.0x

Cenovus Energy Inc.

F-32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

16.  CAPITAL STRUCTURE (continued)

It is Cenovus’s intention to maintain an investment grade rating to ensure it has continuous access to capital and the financial flexibility to fund its capital programs, meet its financial obligations and finance potential acquisitions.  Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle.  To manage the capital structure, Cenovus may adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facility or repay existing debt.

Cenovus’s capital structure, objectives and targets have remained unchanged over the periods presented.  At December 31, 2009, Cenovus is in compliance with all of the terms of its debt agreements.

17.  COMPENSATION PLANS

Cenovus has in place a number of programs whereby employees may be granted the following share-based long-term incentives:

·Tandem Share Appreciation Rights (“TSARs”)

All options to purchase Common Shares issued under the Cenovus Employee Stock Option Plan, with the exception of a limited number of Cenovus Replacement Options, as described in Note 15, have an associated TSAR attached to them whereby the option holder has the right to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right in lieu of exercising the option. The TSARs vest and expire under the same terms and conditions as the underlying option.  Certain of the TSARs (“Performance TSARS”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited.

·Share Appreciation Rights (“SARs”)

Share Appreciation Rights (“SARs”) entitle the employee to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right. SARs are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the original grant date.  Certain of the SARs (“Performance SARs”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance SARs that do not vest when eligible are forfeited.

In accordance with the Arrangement with EnCana described in Note 2, each Cenovus employee holding an original EnCana long-term incentive unit of the same nature transferred their right to Cenovus in exchange for a Cenovus Replacement Unit and to EnCana for an EnCana Replacement Unit. The terms and conditions of the Cenovus and EnCana Replacement Units are similar to the terms and conditions of the original EnCana unit. The original exercise price of the EnCana unit was apportioned to the Cenovus and EnCana Replacement Units based on the one day weighted average trading price of Cenovus’s common share price relative to that of EnCana’s common share price on the TSX on December 2, 2009.  Cenovus is required to reimburse EnCana in respect of cash payments made by EnCana to Cenovus employees for the EnCana Replacement Units they hold. No further EnCana Replacement Units will be granted to Cenovus employees.

All of these share-based long-term incentive programs have similar vesting provisions as the Cenovus stock option plan.  Cenovus Units and Cenovus Replacement Units are measured against the Cenovus common share price and EnCana Replacement Units are measured against the EnCana common share price.

Cenovus Energy Inc.

F-33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

17.  COMPENSATION PLANS (continued)

The Company has recorded a liability in the Consolidated Balance Sheet for EnCana Replacement Units held by the Company’s employees using the fair value method.  The fair value of each EnCana Replacement Unit granted is estimated using the Black-Scholes-Merton model with weighted average 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 tables summarize the information related to the TSARs held by Cenovus employees:

As at December 31, 2009
	TotalNumber ofTSARs		Performance TSARs	WeightedAverage 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 related to TSARs.

B) Share Appreciation Rights

The following tables summarize 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.

F-34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 tables summarize information related to the EnCana Replacement 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		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 the EnCana Replacement TSARs.

D) EnCana Replacement Share Appreciation Rights

The following tables summarize information related to the EnCana Replacement SARs held by Cenovus employees:

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.

F-35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 EnCana Replacement SARs.

E) Deferred Share Units (“DSUs”)

Cenovus has in place a program whereby directors, officers and employees are issued Deferred Share Units (“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 percent of their annual bonus award into DSUs.  DSUs vest immediately, can be redeemed in accordance with terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

Pursuant to the terms of the Arrangement, EnCana DSUs credited to directors, officers and employees of Cenovus were exchanged for Cenovus DSUs.  The fair value of the Cenovus DSUs credited to each holder was based on the fair market value of Cenovus Common Shares relative to EnCana common shares prior to the effective date 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-Based Compensation Costs

Included in the financial information prior to the Arrangement, the Company recorded compensation 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

Cenovus Energy Inc.

F-36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

17.  COMPENSATION PLANS (continued)

G) Pensions and Other Post-Employment Benefits

The Company sponsors defined benefit and defined contribution plans, providing pension and other post-employment benefits (“OPEB”) to its employees.

The Company is required to file an actuarial valuation of its pension plans with the provincial 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 the Arrangement, the liabilities and assets related to Cenovus employees, as determined by actuarial consultants, transferred to the Cenovus Pension Plans effective November 30, 2009. The 2009 Pension and OPEB amounts reflect activity since the effective date.

The 2008 Pension and OPEB amounts represent Cenovus’s proportionate share of EnCana’s pension plans related to active employees. The going concern liabilities and assets related to retirees prior to the Arrangement remained with EnCana.

Information related to defined benefit pension and other post-employment benefit plans, based on actuarial 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	)

Cenovus Energy Inc.

F-37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

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 OPEB plans are funded on an as required basis.

The weighted average assumptions 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 average remaining service period of the active employees covered by the defined benefit pension plan is 4 years.  The average remaining service period of the active employees covered by the OPEB plan is 11 years.

Assumed health care cost 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 care cost trend rates have an effect on the amounts reported for the OPEB plans.  A one percentage point change in assumed health 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’s pension 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 of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The objective of the asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense.  The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The Supplemental Pension Plan is funded through a retirement compensation arrangement and is subject to the applicable Canada Revenue Agency regulations.

Cenovus Energy Inc.

F-38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

17.  COMPENSATION PLANS (continued)

The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.

The Company’s contributions to the pension plans are subject to the results of the actuarial valuation and direction by the Human Resources and Compensation Committee of the Board.

Estimated future payment 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 are comprised of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the Partnership Contribution Receivable and Payable, risk management assets and liabilities, and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows.  The information contained within Note 18 is based on carve-out information for the periods prior to December 1, 2009.

A) Fair Value of Financial Assets and Liabilities

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments.

The fair values of the Partnership Contribution Receivable and Partnership Contribution Payable approximate their carrying amount due to the specific non-tradeable nature of these instruments in relation to the creation of the integrated oil business venture.

Risk management assets and liabilities are recorded at their estimated fair value based on mark-to-market accounting, using quoted market prices or, in their absence, third-party market indications and forecasts.

Long-term debt is carried at amortized cost.  The estimated fair values of long-term borrowings have been determined based on market information.

Cenovus Energy Inc.

F-39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

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 and Liabilities

Under the terms of the Arrangement with EnCana, the risk management positions at November 30, 2009 were allocated to Cenovus based upon Cenovus’s proportion of the related volumes covered by the contracts. To effect the allocation, Cenovus entered into a contract with EnCana with the same terms and conditions as between EnCana and the third parties to the existing contracts. All positions entered into after the Arrangement have been negotiated 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 Management Positions

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

Cenovus Energy Inc.

F-40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

18.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Net Fair Value Methodologies Used to Calculate Unrealized Risk ManagementPositions

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 contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

Net Fair Value of Commodity Price Positions 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 ongoing operations to market the Company’s production.

**Cenovus has entered into swaps to protect against widening natural gas price differentials between production areas in Canada and various sales points.  These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX.

Earnings Impact of Realized and Unrealized Gains (Losses) on RiskManagement Positions

	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	)

Cenovus Energy Inc.

F-41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

18.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Reconciliation of Unrealized Risk Management 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 fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, Management believes 10 percent volatility is a reasonable measure. Fluctuations in commodity prices could have resulted 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 with Financial Assets and Liabilities

Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.  The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.  The Company’s policy is not to use derivative financial instruments for speculative purposes.

Crude Oil – The Company has partially mitigated its exposure to the commodity price risk on its crude oil sales and condensate supply with fixed price swaps.

Natural Gas – To partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into swaps to manage the price differentials between these production areas and various sales points.

Power – The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs.

Cenovus Energy Inc.

F-42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

18.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality. All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks.  As at December 31, 2009, over 98 percent (2008–95 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties.

At December 31, 2009, Cenovus had two counterparties (2008–two counterparties) whose net settlement position individually account for more than 15 percent of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty.  The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the Partnership Contribution Receivable is the total carrying value. The current concentration of this credit risk resides with EnCana and a AAA rated counterparty. Cenovus’s exposure to EnCana is expected to reduce substantially by the end of the first quarter 2010 as Cenovus begins to market its own physical gas to the market. Cenovus’s exposure to its counterparties is acceptable and within Credit Policy tolerances.

Liquidity Risk

Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due.  Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.  Cenovus manages its liquidity through the active management of cash and debt.  As disclosed in Note 16, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including:  cash and cash equivalents, cash from operating activities and undrawn credit facilities.  At December 31, 2009, Cenovus had approximately $2.3 billion in unused credit capacity available on its committed bank credit facility.

It is Cenovus’s intention to maintain investment grade credit 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 outlined in 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, including current portion.

Cenovus Energy Inc.

F-43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

18.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Included in Cenovus’s long-term debt obligations of $3,493 million at December 31, 2009, are $56 million in principal obligations related to prime rate and LIBOR based loans.  These amounts are fully supported by the Company’s revolving syndicated credit facility, which have no repayment requirements within the next year.  All outstanding amounts related to the prime rate and LIBOR based loans were drawn on the 3-year tranche of the revolving syndicated credit facility.  Based on the current maturity dates of the 3-year tranche, these amounts are included in cash outflows for the period disclosed as “1-3 Years.”   Further information on Long-Term Debt is included in Note 13.

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. Cenovus’s functional currency is Canadian dollars; however, the Company reports its results in U.S. dollars, unless otherwise indicated.  As the effects of foreign exchange fluctuations are embedded in the Company’s results, the total effect of foreign exchange fluctuations is not separately identifiable.

As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar Partnership Contribution Receivable issued from Canada.  At December 31, 2009, Cenovus had $3,525 million 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 Contribution Receivable ($3,147 million at December 31, 2008).  A $0.01 change in the U.S. to Canadian dollar exchange 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 interest rates that may affect the earnings, cash flows and valuations.  Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed 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 in interest rates on floating rate debt amounts to nil (December 31, 2008–$4 million; 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 the Arrangement, the per share amounts disclosed above are based on EnCana’s common shares.

Cenovus Energy Inc.

F-44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

19.  SUPPLEMENTARY INFORMATION (continued)

B) Supplementary Cash Flow Information

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 as a 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 to certain 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 commitments related to its risk management program are disclosed in Note 18.

Contingencies

Legal Proceedings

Cenovus is involved in various legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions for such legal claims.

Cenovus Energy Inc.

F-45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

20.  COMMITMENTS AND CONTINGENCIES (continued)

Asset Retirement

Cenovus is responsible for the retirement of long-lived assets related to its oil and gas properties, refining facilities and Midstream facilities at the end of their useful lives. Cenovus has recognized a liability of $1,096 million based on current legislation and estimated costs. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax interpretations, regulations and legislation in the various jurisdictions that Cenovus operates in are continually changing. As a result, there are usually some tax matters under review. Management believes that the provision for taxes is adequate.

21.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING

The Cenovus Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”) which, in most respects, conform to accounting principles generally accepted in the United States (“U.S. GAAP”). The significant differences between Canadian GAAP and U.S. GAAP are described in this note.  The most notable differences are:

·full cost accounting;

·pensions and other post-employment benefits;

·liability-based stock compensation plans;

·income taxes;

·other comprehensive income;

·joint venture accounting; and

·inventories.

RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO 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.

F-46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

CONSOLIDATED STATEMENT OF EARNINGS AND COMPREHENSIVE 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.

F-47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 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 ensure the unamortized capitalized costs in each cost centre do not exceed the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of estimated value of future production from proved reserves using oil and gas prices at the balance sheet date, less related unescalated estimated future development and production costs, plus unimpaired unproved property costs. For 2009, depletion charges under U.S. GAAP were also calculated by reference to proved reserves estimated using an average price for the prior 12-month period.  For 2008 and 2007, depletion charges under U.S. GAAP were calculated by reference to proved reserves estimated using oil and gas prices at the balance sheet date.

Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecast pricing and future development and production costs to determine whether impairment exists. The impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAP are also calculated by reference to proved reserves estimated using estimated future prices and costs.

At December 31, 2008, Cenovus’s capitalized costs of oil and gas properties in Canada exceeded the full cost ceiling resulting in a
non-cash U.S. GAAP write-down of $60 million charged to DD&A (2007–nil). Additional depletion was also recorded in 2006, and certain prior years, as a result of the ceiling test difference between Canadian GAAP and U.S. GAAP. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.

The U.S. GAAP adjustment for the difference in depletion calculations results in an impact to DD&A charges and foreign currency 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.

F-48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

21.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

B) Property, Plant and Equipment Allocation

Net property, plant and equipment related to Canadian upstream oil and gas activities have been allocated for U.S. GAAP carve-out purposes using the same methodology as the carve-out allocation for Canadian GAAP purposes.

The balances related to Canadian upstream operations have been allocated between Cenovus and EnCana in accordance with the CICA Handbook Accounting Guideline ACG-16, based on the ratio of future net revenue, discounted at 10 percent, of the properties carved out to the discounted future net revenue of all proved properties in Canada using the reserve reports dated December 31, 2008 and December 31, 2007.  Future net revenue is the estimated net amount to be received with respect to development and production of crude oil and natural gas reserves, the value of which has been determined by independent reserve evaluators.

C) Compensation Plans

i)  Pensions and Other Post-Employment Benefits

Under U.S. GAAP, ASC 715-30, “Compensation – Retirement Benefits”, requires Cenovus to recognize the over-funded or
under-funded status of defined benefit and post-employment plans on the balance sheet as an asset or liability and to recognize changes in the funded status through Other Comprehensive Income. Canadian GAAP does not require Cenovus to recognize the funded status of these plans on its balance sheet.

ii)  Liability-Based Stock Compensation Plans

Under Canadian GAAP, obligations for liability-based stock compensation plans are recorded using the intrinsic-value method of accounting. For U.S. GAAP purposes, Cenovus adopted ASC 718, “Compensation – Stock Compensation” for the year ended December 31, 2006 using the modified-prospective approach. Under ASC 718, liability-based stock compensation plans, including tandem share appreciation rights, performance tandem share appreciation rights, share appreciation rights, performance share appreciation rights and deferred share units, are required to be re-measured at fair value at each reporting period up until the settlement date.

To the extent compensation cost relates to employees directly involved in crude oil and natural gas development activities, certain amounts are capitalized to property, plant and equipment. Amounts not capitalized 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 million increase)

·Other liabilities increased by $1.6 million (2008–$0.2 million decrease)

·Other comprehensive income–nil (2008–$3.0 million increase)

·Operating expenses decreased by $3.8 million (2008–$11.6 million increase)

·Administrative expenses decreased by $7.9 million (2008–$14.5 million increase)

·Depreciation, depletion and amortization expenses decreased by $1.6 million (2008–$3.8 million increase)

Cenovus Energy Inc.

F-49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

21.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

D) Income Taxes

U.S. GAAP uses enacted tax rates and legislative changes to calculate current and deferred income taxes, whereas Canadian GAAP uses substantively enacted tax rates and legislative changes. In 2007, a Canadian tax legislative change was substantively enacted for Canadian GAAP; however, this tax legislative change was not considered enacted for U.S. GAAP by December 31, 2007 and 2008. This tax legislative change is still not considered enacted. Accordingly, there was no difference in 2009 (2008–nil; 2007–increase to income tax expense of $76 million) for U.S. GAAP.

The remaining differences resulted from the deferred income tax adjustments included in the Reconciliation of Net Earnings under Canadian GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.

In 2009, Cenovus incurred losses in one of its subsidiary company which were recognized and included in calculating future income taxes for Canadian GAAP purposes on the basis that the tax legislative changes noted above were substantially enacted. For U.S. GAAP, these losses can not be recognized as 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 the statutory 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.

F-50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

21.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

E) Other Comprehensive Income

ASC 715-30 requires a change in the funded status of defined benefit and post-employment plans to be recognized on the balance sheet and changes 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, as required, the transitional amount of $12 million, net of tax was booked directly to Accumulated Other Comprehensive Income.

The foreign currency translation adjustment includes the effect of the accumulated U.S. GAAP differences.

F) Joint Venture with ConocoPhillips

Under Canadian GAAP, the Integrated Oil operations that are jointly controlled are proportionately consolidated. U.S. GAAP requires the Downstream Refining operations included in the Integrated Oil Division be accounted for using the equity method. However, under an accommodation of the U.S. Securities and Exchange Commission, accounting for jointly controlled investments does not require reconciliation from Canadian to U.S. GAAP if the joint venture is jointly controlled by all parties having an equity interest in the entity, which is the case for the Downstream Refining operations. Equity accounting for the Downstream Refining operations would have no impact on Cenovus’s net earnings or retained earnings. As required, the following disclosures are provided for the Downstream Refining operations of the 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.

F-51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in US$ millions, unless otherwise indicated

For the year ended December 31, 2009

21.  UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (continued)

G) Inventories

For Canadian GAAP purposes, for the year ended December 31, 2009, the Company recorded an increase in inventory values resulting from a subsequent improvement in commodity prices following a write-down of product inventory.  Under U.S. GAAP, this increase 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 Accounting Pronouncements

During the year, Cenovus adopted the following pronouncements for U.S. GAAP purposes:

·ASC 805-10, “Business Combinations,” which is a revised standard and requires assets and liabilities acquired in a business combination, contingent consideration, and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  Acquisition-related and restructuring costs are recognized separately from the business combination.  This standard was adopted prospectively as of January 1, 2009.  The adoption of this standard had no material impact on Cenovus’s U.S. GAAP accounting treatment of business combinations entered into after January 1, 2009.

·ASC 810-10 “Consolidation,” which requires a non-controlling interest in a subsidiary to be classified as a separate component of equity.  The standard also changes the way the U.S. GAAP consolidated statement of earnings is presented by requiring net earnings to include the amounts attributable to both the parent and the non-controlling interest and to disclose these respective amounts.  This standard was adopted as of January 1, 2009.  The adoption of this standard had no material impact on Cenovus’s Consolidated Financial Statements.

·In June 2009, the U.S. Financial Accounting Standards Board (“FASB”) issued the Accounting Standards Update (ASU) 2009-01, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.”  This update establishes the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. generally accepted accounting principles effective for financial statements issued for interim and annual periods ending after September 15, 2009.  The Codification did not change existing requirements under U.S. GAAP and as a result, did not impact Cenovus’s Consolidated Financial Statements.

·The U.S. Securities Exchange Commission’s project, “Modernization of Oil and Gas Reporting” and FASB’s Accounting Standards Update 2010-03 “Oil and Gas Reserve Estimation and Disclosures,” which include provisions that permit the use of new technologies to establish proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.  Additionally, oil and gas reserves are now reported using an average price based upon the prior 12-month period rather than year-end prices.  The new rules and standards were adopted prospectively by Cenovus on December 31, 2009 and affected the reserve estimate used in the calculation of the ceiling test for U.S. GAAP.  There was no effect on the ceiling test for the change in rules and standards noted above for 2009.   In addition, the FASB standard affected the amounts reported in the Supplementary Oil and Gas Information Topic 932 as discussed in that supplementary information.

Cenovus Energy Inc.

F-52

Cenovus Energy Inc.

Interim Consolidated Financial Statements (unaudited)

For the Period Ended March 31, 2010

(Canadian Dollars)

F-53

CONSOLIDATED STATEMENT OF EARNINGS AND
COMPREHENSIVE INCOME (unaudited)

For the period ended March 31,		Three Months Ended
(C$ millions, except per share amounts)		2010		2009
Gross Revenues	(Note 1)	3,602		2,736
Less: Royalties		111		43
Net Revenues		3,491		2,693
Expenses	(Note 1)
Production and mineral taxes		12		13
Transportation and selling		291		166
Operating		348		364
Purchased product		1,765		1,136
Depreciation, depletion and amortization		324		380
General and administrative		52		41
Interest, net	(Note 7)	65		45
Accretion of asset retirement obligation	(Note 13)	22		11
Foreign exchange (gain) loss, net	(Note 8)	(27	)	(52	)
Other (income) loss, net		(1	)	-
		2,851		2,104
Earnings Before Income Tax		640		589
Income tax expense	(Note 9)	115		74
Net Earnings		525		515
Other Comprehensive Income, Net of Tax
Foreign Currency Translation Adjustment		(88	)	87
Comprehensive Income		437		602
Net Earnings per Common Share	(Note 18)
Basic		0.70		0.69
Diluted		0.70		0.69

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-54

CONSOLIDATED BALANCE SHEET(unaudited)

As at (C$ millions)		March 31, 2010	December 31, 2009
Assets
Current Assets
Cash and cash equivalents		397	155
Accounts receivable and accrued revenues		1,108	978
Income tax receivable		7	40
Current portion of Partnership Contribution Receivable	(Note 11)	339	345
Risk management	(Note 17)	246	60
Inventories	(Note 10)	845	875
		2,942	2,453
Property, Plant and Equipment, net	(Note 1)	15,171	15,214
Partnership Contribution Receivable	(Note 11)	2,457	2,621
Risk Management	(Note 17)	51	1
Other Assets		414	320
Goodwill	(Note 1)	1,146	1,146
		22,181	21,755
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		1,823	1,574
Current portion of Partnership Contribution Payable	(Note 11)	335	340
Risk management	(Note 17)	67	70
		2,225	1,984
Long-Term Debt	(Note 12)	3,494	3,656
Partnership Contribution Payable	(Note 11)	2,486	2,650
Risk Management	(Note 17)	6	4
Asset Retirement Obligation	(Note 13)	1,165	1,147
Other Liabilities		335	239
Future Income Taxes		2,569	2,467
		12,280	12,147
Shareholders’ Equity	(Note 14)	9,901	9,608
		22,181	21,755

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-55

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
(unaudited)

(C$ millions)	Share Capital (Note 14)	Paid in Surplus (Note 14)	Retained Earnings		AOCI*		Owner’s Net Investment		Total
Balance as of December 31, 2008	-	-	-		224		9,264		9,488
Net earnings	-	-	-		-		515		515
Net distribution to owner	-	-	-		-		(129	)	(129	)
Other comprehensive income (loss)	-	-	-		87		-		87
Balance as of March 31, 2009	-	-	-		311		9,650		9,961
Balance as of December 31, 2009	3,681	5,896	45		(14	)	-		9,608
Net earnings	-	-	525		-		-		525
Common shares issued under option plans	6	-	-		-		-		6
Dividends on common shares	-	-	(150	)	-		-		(150	)
Other comprehensive income (loss)	-	-	-		(88	)	-		(88	)
Balance as of March 31, 2010	3,687	5,896	420		(102	)	-		9,901

*Accumulated Other Comprehensive Income

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-56

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

		Three Months Ended
For the period ended March 31, (C$ millions)		2010		2009
Operating Activities
Net earnings		525		515
Depreciation, depletion and amortization		324		380
Future income taxes	(Note 9)	100		(24	)
Unrealized (gain) loss on risk management	(Note 17)	(237	)	(86	)
Unrealized foreign exchange (gain) loss		(32	)	(53	)
Accretion of asset retirement obligation	(Note 13)	22		11
Other		19		(2	)
Net change in other assets and liabilities		(15	)	(3	)
Net change in non-cash working capital		114		(56	)
Cash From Operating Activities		820		682
Investing Activities
Capital expenditures	(Note 1)	(493	)	(652	)
Proceeds from divestitures	(Note 6)	72		-
Net change in investments and other		2		1
Net change in non-cash working capital		47		(67	)
Cash (Used in) Investing Activities		(372	)	(718	)
Net Cash Provided (Used) before Financing Activities		448		(36	)
Financing Activities
Net issuance (repayment) of revolving long-term debt		(58	)	240
Net financing transactions with Encana		-		(129	)
Issuance of common shares		5		-
Dividends on common shares		(150	)	-
Cash From (Used in) Financing Activities		(203	)	111
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(3	)	(2	)
Increase (Decrease) in Cash and Cash Equivalents		242		73
Cash and Cash Equivalents, Beginning of Period		155		188
Cash and Cash Equivalents, End of Period		397		261

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the development, production and marketing of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”) in Canada with refining operations in the United States.

The Company is headquartered in Calgary, Alberta and its common shares are listed on the Toronto and New York stock exchanges.  Information on the Company’s background and the basis of presentation for these financial statements are found in Note 2.

Cenovus is organized into two operating divisions:

·	Integrated OilDivision, which includes all of the assets within the upstream and downstream integrated oil business with the Company’s joint venture partner, as well as other bitumen interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major enhanced oil recovery properties: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries: (i) Wood River; and (ii) Borger.
·	Canadian PlainsDivision, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.
For financial statement reporting purposes, the Company’s operating and reportable segments are:
·	Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada. This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips, an unrelated U.S. public company, and operated by Cenovus.
·	Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.
·	Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

The tabular financial information which follows presents the segmented information first by segment and geographic location, then by product and operating division.  Capital expenditures and goodwill information are summarized at the end of the note.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Results of Operations

Segment and Geographic Information (For the three months ended March 31)

	Upstream Canada				Downstream Refining
(C$ millions)	2010		2009		2010		2009
Gross Revenues	1,867		1,493		1,518		1,154
Less: Royalties	111		43		-		-
Net Revenues	1,756		1,450		1,518		1,154
Expenses
Production and mineral taxes	12		13		-		-
Transportation and selling	291		166		-		-
Operating	205		198		139		147
Purchased product	404		218		1,385		934
Operating Cash Flow	844		855		(6	)	73
Depreciation, depletion and amortization	265		304		51		63
Segment Income (Loss)	579		551		(57	)	10
As at (C$ millions)	March 31, 2010		December 31, 2009		March 31, 2010		December 31,  2009
Property, Plant & Equipment	10,068		10,109		4,993		4,989
Goodwill	1,146		1,146		-		-
Total Assets	15,172		15,218		6,155		6,107
	Corporate and Eliminations				Consolidated
(C$ millions)	2010		2009		2010		2009
Gross Revenues	217		89		3,602		2,736
Less: Royalties	-		-		111		43
Net Revenues	217		89		3,491		2,693
Expenses
Production and mineral taxes	-		-		12		13
Transportation and selling	-		-		291		166
Operating	4		19		348		364
Purchased product	(24	)	(16	)	1,765		1,136
	237		86		1,075		1,014
Depreciation, depletion and amortization	8		13		324		380
Segment Income (Loss)	229		73		751		634
General and administrative	52		41		52		41
Interest, net	65		45		65		45
Accretion of asset retirement obligation	22		11		22		11
Foreign exchange (gain) loss, net	(27	)	(52	)	(27	)	(52	)
Other (income) loss, net	(1	)	-		(1	)	-
	111		45		111		45
Earnings Before Income Tax					640		589
Income tax expense					115		74
Net Earnings					525		515
As at (C$ millions)	March 31, 2010		December 31, 2009		March 31, 2010		December 31,  2009
Property, Plant & Equipment	110		116		15,171		15,214
Goodwill	-		-		1,146		1,146
Total Assets	854		430		22,181		21,755

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Upstream Canada Product and Divisional Information

(For the three months ended March 31)

			Crude Oil & NGLs
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	515	205	526	343	1,041	548
Less: Royalties	27	1	74	29	101	30
Net Revenues	488	204	452	314	940	518
Expenses
Production and mineral taxes	-	-	7	9	7	9
Transportation and selling	213	83	64	63	277	146
Operating	60	50	72	63	132	113
Purchased product	-	-	-	-	-	-
Operating Cash Flow	215	71	309	179	524	250
			Natural Gas
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	27	41	382	656	409	697
Less: Royalties	4	4	6	8	10	12
Net Revenues	23	37	376	648	399	685
Expenses
Production and mineral taxes	-	-	5	4	5	4
Transportation and selling	-	1	14	13	14	14
Operating	7	9	59	64	66	73
Purchased product	-	-	-	-	-	-
Operating Cash Flow	16	27	298	567	314	594
			Other
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	2	17	415	231	417	248
Less: Royalties	-	1	-	-	-	1
Net Revenues	2	16	415	231	417	247
Expenses
Production and mineral taxes	-	-	-	-	-	-
Transportation and selling	-	6	-	-	-	6
Operating	2	7	5	5	7	12
Purchased product	-	-	404	218	404	218
Operating Cash Flow	-	3	6	8	6	11
			Total Upstream
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	544	263	1,323	1,230	1,867	1,493
Less: Royalties	31	6	80	37	111	43
Net Revenues	513	257	1,243	1,193	1,756	1,450
Expenses
Production and mineral taxes	-	-	12	13	12	13
Transportation and selling	213	90	78	76	291	166
Operating	69	66	136	132	205	198
Purchased product	-	-	404	218	404	218
Operating Cash Flow	231	101	613	754	844	855

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Capital Expenditures

	Three Months Ended
For the period ended March 31, (C$ millions)	2010	2009
Integrated Oil	151	155
Canadian Plains	139	235
Upstream Canada	290	390
Downstream Refining	202	252
Corporate	1	10
Total	493	652

Goodwill Additions

There were no additions to goodwill during 2010 or 2009.

2.  BACKGROUND & BASIS OF PRESENTATION

Cenovus was created on November 30, 2009 and began independent operations on December 1, 2009, as a result of the plan of arrangement (“Arrangement”) involving Encana Corporation (“Encana”) whereby Encana was split into two independent energy companies, one a natural gas company, Encana and the other an integrated oil company, Cenovus.  In connection with the Arrangement, Encana common shareholders received one share in each of the new Encana and Cenovus in exchange for each Encana share held.  Common shares of Cenovus began trading on a “when issued” basis on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges on November 2, 2009.  Regular trading of Cenovus shares began on the TSX on December 3, 2009 and on the NYSE on December 9, 2009.

Basis of presentation / Carve-out financial information for comparative periods

These interim Consolidated Financial Statements have been presented in accordance with Canadian generally accepted accounting principles (“GAAP”) and have been prepared following the same accounting policies and methods of computation as the Cenovus annual audited Consolidated Financial Statements for the year ended December 31, 2009, except as outlined in Notes 3 and 4.  The disclosures provided below are incremental to those included with the Cenovus annual audited Consolidated Financial Statements.  Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the Cenovus annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2009.

Since the Company was created on November 30, 2009 and began independent operations on December 1, 2009, the comparative information provided in these interim Consolidated Financial Statements represent the financial position, results of operations and cash flows of the businesses transferred to Cenovus on a carve-out basis.  Management believes the assumptions underlying the Cenovus Carve-out Consolidated Financial Statements for prior period comparatives are reasonable. However, these comparative amounts may not reflect Cenovus’s financial position, results of operations, and cash flows had Cenovus been a stand-alone company during the comparative periods presented.  For additional information regarding the carve-out process, readers should refer to Cenovus’s annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2009.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

3.CHANGE IN REPORTING CURRENCY

Upon the creation of the Company on November 30, 2009 as a result of the Arrangement, Cenovus reported its results in U.S. dollars for the preparation of its December 31, 2009 financial statements as this was the reporting currency used by Encana.  Effective January 1, 2010, the Company changed its reporting currency to Canadian dollars.  The change in reporting currency is to better reflect the business of Cenovus, and it allows for increased comparability to the Company’s peers.  In implementing this change, the Company has followed the requirements of the Canadian Institute of Chartered Accountants (“CICA”) Emerging Issues Committee (“EIC”) Abstract 130 (“EIC-130”), “Translation Method When the Reporting Currency Differs from the Measurement Currency or there is a Change in the Reporting Currency.”

With the change in reporting currency, all comparative financial information being presented has been restated from U.S. dollars to Canadian dollars to reflect the Company’s financial statements as if they had been historically reported in Canadian dollars.

4.  CHANGES IN ACCOUNTING POLICIES AND PRACTICES

Business Combinations

On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582, “Business Combinations,” which replaces CICA Handbook Section 1581 of the same name.  The new standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings.  The adoption of this standard did not impact the Company’s interim Consolidated Financial Statements for the period ended March 31, 2010.  However, the adoption of this new standard will impact the accounting treatment of future business combinations.

Consolidated Financial Statements and Non-controlling Interests

In conjunction with the early adoption of CICA Handbook Section 1582, the Company was also required to early adopt CICA Handbook Sections 1601, “Consolidated Financial Statements” and 1602, “Non-controlling Interests” effective January 1, 2010.  These sections replace the former consolidated financial statement standard, CICA Handbook Section 1600, “Consolidated Financial Statements.”  Section 1601 establishes the requirements for the preparation of the consolidated financial statements and Section 1602 establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination.  Section 1602 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 early adoption of these standards did not have a material impact on the Company’s interim Consolidated Financial Statements for the period ended March 31, 2010.  These standards along with CICA Handbook section 1582 above are converged with International Financial Reporting Standards (see Note 5).

Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2010.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

5.  RECENT ACCOUNTING PRONOUNCEMENTS

In February 2008, the CICA’s Accounting Standards Board confirmed that International Financial Reporting Standards (“IFRS”) will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises.  Cenovus will be required to report its results in accordance with IFRS beginning in 2011.  Cenovus has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information.  The impact of IFRS on the interim Consolidated Financial Statements is not reasonably determinable at this time.

6.  DIVESTITURES

For the period ended March 31, 2010, total proceeds received on the sale of assets were $72 million (2009–nil).

7.  INTEREST, NET

	Three Months Ended
For the period ended March 31, (C$ millions)	2010		2009
Interest Expense—Long-Term Debt	58		46
Interest Expense—Other	45		55
Interest Income	(38	)	(56	)
	65		45

Interest Expense – Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively.

8.  FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended
For the period ended March 31, (C$ millions)	2010		2009
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada	(108	)	67
Translation of U.S. dollar Partnership Contribution Receivable issued from Canada	76		(109	)
Realized and Other Foreign Exchange (Gain) Loss	5		(10	)
	(27	)	(52	)

9.  INCOME TAXES

The provision for income taxes is as follows:

	Three Months Ended
For the period ended March 31, (C$ millions)	2010	2009
Current
Canada	15	88
United States	-	10
Total Current Tax	15	98
Future	100	(24	)
	115	74

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

10.  INVENTORIES

As at (C$ millions)	March 31, 2010	December 31, 2009
Product
Upstream Canada	277	267
Downstream Refining	549	589
Parts and Supplies	19	19
	845	875

11.  PARTNERSHIP CONTRIBUTION RECEIVABLE AND PAYABLE

In relation to the creation and activities of the integrated oil business venture with ConocoPhillips, the following represent Cenovus’s 50 percent share of amounts receivable and payable:

Partnership Contribution Receivable

As at (C$ millions)	March 31, 2010	December 31, 2009
Current	339	345
Long-term	2,457	2,621
	2,796	2,966

Partnership Contribution Payable

As at (C$ millions)	March 31, 2010	December 31, 2009
Current	335	340
Long-term	2,486	2,650
	2,821	2,990

In addition to the Partnership Contribution Receivable and Payable, other assets and other liabilities include equal amounts for interest bearing member loans, with no fixed repayment terms, related to the funding of refining operating and capital requirements.  At March 31, 2010 these amounts were $279 million (December 31, 2009—$183 million).

12.  LONG-TERM DEBT

As at (C$ millions)	March 31, 2010		December 31, 2009
Canadian Dollar Denominated Debt
Bank credit facilities	-		32
U.S. Dollar Denominated Debt
Bank credit facilities	-		26
Unsecured notes	3,555		3,663
	3,555		3,689
Total Debt Principal	3,555		3,721
Debt Discounts and Transaction Costs	(61	)	(65	)
Current Portion of Long-Term Debt	-		-
	3,494		3,656

At March 31, 2010, Cenovus is in compliance with all of the terms of its debt agreements.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

13.  ASSET RETIREMENT OBLIGATION

The aggregate carrying amount of the obligation associated with the retirement of upstream oil and gas assets and downstream refining facilities is as follows:

As at (C$ millions)	March 31, 2010		December 31, 2009
Asset Retirement Obligation, Beginning of Period	1,147		793
Liabilities Incurred	12		6
Liabilities Settled	(10	)	(38	)
Liabilities Divested	-		(10	)
Change in Estimated Future Cash Outflows	(5	)	357
Accretion Expense	22		45
Foreign Currency Translation	(1	)	(6	)
Asset Retirement Obligation, End of Period	1,165		1,147

14.  SHARE CAPITAL

Authorized

Cenovus is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.

Issued and Outstanding

As at March 31, 2010
	Number of Common Shares (millions)	Amount ($ millions)
Outstanding, Beginning of Period	751.3	3,681
Common Shares Issued under Option Plans	0.4	6
Outstanding, End of Period	751.7	3,687

To determine Cenovus’s share capital amount, Encana’s stated capital immediately prior to the Arrangement was split based on the relative fair market values of the Encana and Cenovus Common Shares at the time of the initial exchange.  Cenovus’s share capital amount was deducted from Encana’s net investment with the remaining $6,055 million reclassified as Paid in Surplus.

At March 31, 2010, there were 22 million Common Shares available for future issuance under stock option plans.  There were no Preferred Shares outstanding as at March 31, 2010.

Net Investment

For comparative periods, Encana’s net investment in the operations of Cenovus prior to the Arrangement is presented as total Net Investment in the interim Consolidated Financial Statements.  Total Net Investment consists of Owner’s Net Investment and AOCI.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

14.  SHARE CAPITAL (continued)

Option Plans

Cenovus Employee Stock Option Plan

Cenovus has stock-based compensation plans that allow employees to purchase Common Shares of the Company.  Option exercise prices approximate the market price for the Common Shares on the date the options were issued.  Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, and are fully exercisable after three years.  Options granted prior to February 17, 2010 expire after five years while options granted on February 17, 2010 or later expire after seven years.  In addition, certain stock options granted are performance based.  The performance based stock options vest and expire under the same terms and service conditions as the underlying option, and vesting is subject to Cenovus attaining prescribed performance relative to pre-determined key measures.  All options issued by the Company have an associated Tandem Share Appreciation Right (“TSAR”) attached to them (see Note 16).

Cenovus Replacement Tandem Share Appreciation Rights (“Cenovus Replacement TSARs”) Held By Encana Employees

Under the terms of the Arrangement, each original Encana TSAR was replaced with one Encana Replacement TSAR and one Cenovus Replacement TSAR with terms and conditions similar to the original Encana TSAR.  Encana is required to reimburse Cenovus in respect of cash payments made by Cenovus to Encana’s employees when these employees exercise a Cenovus Replacement TSAR and therefore, no compensation expense is recognized.  No further Cenovus Replacement TSARs will be granted to Encana employees.

Encana employees can choose to exercise the Cenovus Replacement TSAR in exchange for a Cenovus common share or for cash.  Cenovus has recorded a liability in the Consolidated Balance Sheet for Cenovus Replacement TSARs held by Encana employees using the fair value method, with an offsetting accounts receivable from Encana.  The fair value of each Cenovus Replacement TSAR held by Encana employees was estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:

	2010
Risk Free Rate	1.56	%
Dividend Yield	3.16	%
Volatility	26.34	%
Cenovus’s Closing Common Share Price at March 31, 2010	C$26.53

The following tables summarize information related to the Cenovus Replacement TSARs held by Encana employees:

As at March 31, 2010
	TotalNumber ofTSARs		Performance TSARs		WeightedAverageExercisePrice (C$)
Outstanding, Beginning of Period	22,945,337		10,462,643		27.14
Exercised – SARs	(1,112,435	)	(8,049	)	18.72
Exercised – Options	(83,812	)	(171	)	18.66
Forfeited	(971,360	)	(876,905	)	28.35
Outstanding, End of Period	20,777,730		9,577,518		27.57
Exercisable, End of Period	13,805,966		5,284,426		26.95

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

14.  SHARE CAPITAL (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	14,480	-	0.09	19.28	14,480	-	19.28
20.00 to 24.99	3,859,211	-	0.88	22.95	3,844,966	-	22.95
25.00 to 29.99	11,408,907	6,645,198	2.88	26.50	6,973,503	3,777,892	26.61
30.00 to 34.99	5,304,032	2,932,320	2.83	32.82	2,910,542	1,506,534	32.81
35.00 to 39.99	109,450	-	3.17	37.14	37,980	-	37.08
40.00 to 44.99	80,150	-	3.19	42.76	24,045	-	42.76
45.00 to 49.99	1,500	-	3.14	45.56	450	-	45.56
	20,777,730	9,577,518	2.50	27.57	13,805,966	5,284,426	26.95

15.  CAPITAL STRUCTURE

Cenovus’s capital structure is comprised of Shareholders’ Equity plus Long-Term Debt.  Cenovus’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Debt is defined as the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable.

Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent.

As at (C$ millions)	March 31, 2010		December 31, 2009
Debt	3,494		3,656
Shareholders’ Equity	9,901		9,608
Total Capitalization	13,395		13,264
Debt to Capitalization ratio	26%		28%
Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and 2.0 times.
As at (C$ millions)	March 31, 2010		December 31, 2009
Debt	3,494		3,656
Net Earnings	828		818
Add (deduct):
Interest, net	264		244
Income tax expense	385		344
Depreciation, depletion and amortization	1,471		1,527
Accretion of asset retirement obligation	56		45
Foreign exchange (gain) loss, net	329		304
Other (income) loss, net	(3	)	(2	)
Adjusted EBITDA	3,330		3,280
Debt to Adjusted EBITDA*	1.0x		1.1x

* Calculated on a trailing 12-month basis

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

15.  CAPITAL STRUCTURE (continued)

It is Cenovus’s intention to maintain an investment grade rating to ensure it has continuous access to capital and the financial flexibility to fund its capital programs, meet its financial obligations and finance potential acquisitions.  Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle.  To manage the capital structure, Cenovus may adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facility or repay existing debt.

Cenovus’s capital structure, objectives and targets have remained unchanged over the periods presented.  At March 31, 2010, Cenovus is in compliance with all of the terms of its debt agreements.

16.  COMPENSATION PLANS

Cenovus has in place programs whereby employees may be granted the following share-based long-term incentives:

·Tandem Share Appreciation Rights (“TSARs”)

Tandem Share Appreciation Rights (“TSARs”) are options to purchase Common Shares issued under the Cenovus Employee Stock Option Plan whereby the option holder has the right to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right in lieu of exercising the option. The TSARs vest and expire under the same terms and conditions as the underlying option.  Certain of the TSARs (“Performance TSARs”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited.

·Share Appreciation Rights (“SARs”)

Share Appreciation Rights (“SARs”) entitle the employee to receive a cash payment equal to the excess of the market price of Cenovus’s Common Shares at the time of exercise over the exercise price of the right. SARs are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the original grant date.  Certain of the SARs (“Performance SARs”) have an additional vesting requirement which is subject to the achievement of prescribed performance relative to key pre-determined measures. Performance SARs that do not vest when eligible are forfeited.

In accordance with the Arrangement described in Note 2, each Cenovus employee holding an original Encana long-term incentive unit of the same nature disposed of their right to Cenovus in exchange for a Cenovus Replacement unit and to Encana for an Encana Replacement unit. The terms and conditions of the Cenovus and Encana Replacement units are similar to the terms and conditions of the original Encana unit. The original exercise price of the Encana unit was apportioned to the Cenovus and Encana Replacement units based on the one day volume weighted average trading price of Cenovus’s common share price relative to that of Encana’s common share price on the TSX on December 2, 2009.  Cenovus is required to reimburse Encana in respect of cash payments made by Encana to Cenovus employees for the Encana Replacement units they hold. No further Encana Replacement units will be granted to Cenovus employees.

All of these share-based long-term incentive programs have similar vesting provisions as the Cenovus stock option plan.  Cenovus units and Cenovus Replacement Units are measured against the Cenovus common share price and Encana Replacement Units are measured against the Encana common share price.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

16.  COMPENSATION PLANS (continued)

The Company has recorded a liability in the Consolidated Balance Sheet for Encana Replacement Units held by the Company’s employees using the fair value method.  The fair value of each Encana Replacement Unit granted is estimated using the Black-Scholes-Merton model with weighted average assumptions as follows:

	2010
Risk Free Rate	1.61	%
Dividend Yield	2.63	%
Volatility	27.43	%
Encana’s Common Share Price	C$32.00

A) Tandem Share Appreciation Rights

The following tables summarize the information related to the TSARs held by Cenovus employees:

As at March 31, 2010
	TotalNumber ofTSARs		Performance TSARs		WeightedAverage ExercisePrice (C$)
TSARs – Outstanding, Beginning of Period	16,454,727		8,053,074		27.52
Granted	5,564,485		-		26.32
Exercised – SARs	(553,593	)	(618	)	18.44
Exercised – Options	(123,205	)	-		18.34
Forfeited	(586,601	)	(580,121	)	28.47
Outstanding, End of Period	20,755,813		7,472,335		27.47
Exercisable, End of Period	9,193,069		3,821,509		27.37

	Outstanding TSARs				Exercisable TSARs
Range of Exercise Price (C$)	TotalNumber ofTSARs	Performance TSARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	TotalNumber of TSARs	Performance TSARs	Weighted AverageExercisePrice (C$)
15.00 to 19.99	9,840	-	0.11	19.36	9,840	-	19.36
20.00 to 24.99	2,277,484	-	0.93	22.95	2,238,679	-	22.94
25.00 to 29.99	14,035,991	4,992,012	4.58	26.40	4,563,283	2,540,810	26.58
30.00 to 34.99	4,234,298	2,480,323	2.86	32.89	2,312,132	1,280,699	32.89
35.00 to 39.99	124,350	-	3.20	37.14	46,980	-	36.88
40.00 to 44.99	71,850	-	3.21	43.31	21,555	-	43.31
45.00 to 49.99	2,000	-	3.14	45.56	600	-	45.56
	20,755,813	7,472,335	3.81	27.47	9,193,069	3,821,509	27.37

For the period ended March 31, 2010, Cenovus has not recorded any significant compensation costs related to TSARs.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

16.  COMPENSATION PLANS (continued)

B) Share Appreciation Rights

The following tables summarize the information related to the SARs held by Cenovus employees:

As at March 31, 2010
	TotalNumber ofSARs		PerformanceSARs		WeightedAverageExercisePrice (C$)
SARs – Outstanding, Beginning of Period	44,657		23,932		29.38
Forfeited	(3,271	)	(2,646	)	29.28
Outstanding, End of Period	41,386		21,286		29.38
Exercisable, End of Period	15,326		8,246		30.47

	Outstanding SARs				Exercisable SARs
Range of Exercise Price (C$)	TotalNumber of SARs	PerformanceSARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	Total Number of SARs	Performance SARs	WeightedAverageExercisePrice (C$)
25.00 to 29.99	24,128	10,528	3.89	26.83	5,868	2,688	26.47
30.00 to 34.99	17,258	10,758	2.87	32.96	9,458	5,558	32.96
	41,386	21,286	3.47	29.38	15,326	8,246	30.47

For the period ended March 31, 2010, Cenovus has not recorded any significant compensation costs related to the SARs.

C) Encana Replacement Tandem Share Appreciation Rights

The following tables summarize information related to the Encana Replacement TSARs held by Cenovus employees:

As at March 31, 2010
	TotalNumber ofTSARs		Performance TSARs		WeightedAverageExercisePrice (C$)
Replacement TSARs – Outstanding, Beginning of Period	16,356,660		8,051,692		30.46
Exercised – SARs	(665,281	)	(22,601	)	21.34
Exercised – Options	(79,920	)	(45	)	20.78
Forfeited	(588,131	)	(579,461	)	31.43
Outstanding, End of Period	15,023,328		7,449,585		30.87
Exercisable, End of Period	9,091,923		3,798,271		30.29

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

16.  COMPENSATION PLANS (continued)

	Outstanding Encana Replacement TSARs				Exercisable Encana Replacement TSARs
Range of Exercise Price (C$)	TotalNumber of TSARs	Performance TSARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	TotalNumber ofTSARs	Performance TSARs	Weighted Average Exercise Price (C$)
20.00 to 24.99	27,090	-	1.09	22.63	21,490	-	22.53
25.00 to 29.99	10,285,010	4,969,277	2.65	28.37	6,500,955	2,517,753	27.99
30.00 to 34.99	406,650	-	2.18	32.30	260,420	-	32.13
35.00 to 39.99	4,157,528	2,480,308	2.88	36.47	2,263,518	1,280,518	36.46
40.00 to 44.99	74,200	-	3.25	42.28	23,685	-	42.21
45.00 to 49.99	70,850	-	3.21	47.94	21,255	-	47.94
50.00 to 54.99	2,000	-	3.14	50.39	600	-	50.39
	15,023,328	7,449,585	2.70	30.87	9,091,923	3,798,271	30.29

For the period ended March 31, 2010, the Company recorded a reduction of compensation costs of $13 million related to the Encana Replacement TSARs.

D) Encana Replacement Share Appreciation Rights

The following tables summarize information related to the Encana Replacement SARs held by Cenovus employees:

As at March 31, 2010
	TotalNumber ofSARs		Performance TSARs		Weighted AverageExercisePrice (C$)
Encana Replacement SARs – Outstanding, Beginning of Period	44,657		23,932		32.48
Cancelled/Forfeited	(3,271	)	(2,646	)	32.37
Outstanding, End of Period	41,386		21,286		32.49
Exercisable, End of Period	15,326		8,246		33.69

	Outstanding Encana Replacement SARs				Exercisable Encana Replacement SARs
Range of Exercise Price (C$)	TotalNumber of TSARs	Performance TSARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	TotalNumber ofSARs	Performance TSARs	Weighted AverageExercisePrice (C$)
25.00 to 29.99	21,128	10,528	3.84	29.25	5,868	2,688	29.26
30.00 to 34.99	3,000	-	4.21	32.55	-	-	-
35.00 to 39.99	17,258	10,758	2.87	36.44	9,458	5,558	36.44
	41,386	21,286	3.47	32.49	15,326	8,246	33.69

For the period ended March 31, 2010, the Company has not recorded any significant compensation costs related to the Encana Replacement SARs.

E) Deferred Share Units (“DSUs”)

Cenovus has in place a program whereby directors, officers and employees may receive Deferred Share Units (“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 percent of their annual bonus award into DSUs.  DSUs vest immediately, can be redeemed in accordance with terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

16.  COMPENSATION PLANS (continued)

Pursuant to the terms of the Arrangement, Encana DSUs credited to directors, officers and employees of Cenovus were exchanged for Cenovus DSUs.  The fair value of the Cenovus DSUs credited to each holder was based on the fair market value of Cenovus Common Shares relative to Encana common shares prior to the effective date of the Arrangement.

The following table summarizes information related to the DSUs held by Cenovus employees and Directors:

As at March 31, 2010
	Outstanding DSUs
Outstanding, Beginning of Period	768,103
Granted	61,345
Granted from Annual Bonus Awards	81,117
Units in Lieu of Dividends	6,935
Outstanding, End of Period	917,500

For the period ended March 31, 2010, the Company has recorded $2 million in compensation costs related to DSUs.

F) Performance Share Units (“PSUs”)

In 2010, the Company granted Performance Share Units (“PSUs”) to certain employees. PSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30% after year one, 30% after year two and 40% after year three, multiplied by a performance multiplier for each year. The multiplier is based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The following table summarizes information related to the PSUs held by Cenovus employees:

As at March 31, 2010
	Outstanding PSUs
Outstanding, Beginning of Period	-
Granted	1,251,995
Cancelled	(781	)
Units in Lieu of Dividends	9,550
Outstanding, End of Period	1,260,764

For the period ended March 31, 2010, the Company recorded $2 million in compensation costs related to the PSUs.

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Cenovus’s consolidated financial assets and liabilities are comprised of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the Partnership Contribution Receivable and Payable and member loans, risk management assets and liabilities, and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

A) Fair Value of Financial Assets and Liabilities

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments.

The fair values of the Partnership Contribution Receivable and Payable and member loans approximate their carrying amount due to the specific non-tradeable nature of these instruments in relation to the creation of the integrated oil business venture.

Risk management assets and liabilities are recorded at their estimated fair value based on mark-to-market accounting, using quoted market prices or, in their absence, third-party market indications and forecasts.

Long-term debt is carried at amortized cost.  The estimated fair values of long-term borrowings have been determined based on market information.

The fair value of financial assets and liabilities, including current portions thereof were as follows:

As at (C$ millions)	March 31, 2010		December 31, 2009
	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial Assets
Held-for-trading:
Cash and cash equivalents	397	397	155	155
Risk management assets	297	297	61	61
Loans and Receivables:
Accounts receivable and accrued revenues	1,108	1,108	978	978
Partnership Contribution Receivable	2,796	2,796	2,966	2,966
Member loans receivable	279	279	183	183
Financial Liabilities
Held-for-trading:
Risk management liabilities	73	73	74	74
Other Financial Liabilities:
Accounts payable and accrued liabilities	1,823	1,823	1,574	1,574
Long-term debt	3,494	3,762	3,656	3,964
Partnership Contribution Payable	2,821	2,821	2,990	2,990
Member loans payable	279	279	183	183

B) Risk Management Assets and Liabilities

For comparative purposes, under the terms of the Arrangement, the risk management positions at November 30, 2009 were allocated to Cenovus based upon Cenovus’s proportion of the related volumes covered by the contracts. To effect the allocation, Cenovus entered into a contract with Encana with the same terms and conditions as between Encana and the third parties to the existing contracts. All positions entered into after the Arrangement have been negotiated between Cenovus and third parties.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Net Risk Management Position

As at (C$ millions)	March 31, 2010	December 31, 2009
Risk Management
Current asset	246	60
Long-term asset	51	1
	297	61
Risk Management
Current liability	67	70
Long-term liability	6	4
	73	74
Net Risk Management Asset (Liability)	224	(13	)

Of the $224 million net risk management asset balance at March 31, 2010, an asset of $143 million relates to the contract with Encana.

Summary of Unrealized Risk Management Positions

As at (C$ millions)	March 31, 2010				December 31, 2009
	Risk Management				Risk Management
	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Natural Gas	294	-	294		53	-	53
Crude Oil	3	61	(58	)	8	66	(58	)
Power	-	12	(12	)	-	8	(8	)
Total Fair Value	297	73	224		61	74	(13	)

Net Fair Value Methodologies Used to Calculate Unrealized Risk ManagementPositions

As at (C$ millions)	March 31, 2010		December 31, 2009
Prices actively quoted	245		6
Prices sourced from observable data or market corroboration	(21	)	(19	)
Total Fair Value	224		(13	)

Prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Net Fair Value of Commodity Price Positions at March 31, 2010

As at March 31, 2010 (C$ millions)	Notional Volumes	Term	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
WTI NYMEX Fixed Price	24,600 bbls/d	2010	US$76.99/bbl	(55	)
Other Financial Positions *				(3	)
Crude Oil Fair Value Position				(58	)
Natural Gas Contracts
Fixed Price Contracts	455 MMcf/d	2010	US$6.07/Mcf	233
NYMEX Fixed Price	263 MMcf/d	2011	US$5.90/Mcf	55
NYMEX Fixed Price	60 MMcf/d	2012-2013	US$6.49/Mcf	15
NYMEX Fixed Price
Basis Contracts **
Canada		2010		(3	)
Canada		2011-2013		(6	)
Natural Gas Fair Value Position				294
Power Purchase Contracts
Power Fair Value Position				(12	)

*	Other financial positions are part of ongoing operations to market the Company’s production.
**	Cenovus has entered into swaps to protect against widening natural gas price differentials between production areas in Canada and various sales points. These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX.

Earnings Impact of Realized and Unrealized Gains (Losses) on RiskManagement Positions

	Realized Gain (Loss)
	Three Months Ended
For the period ended March 31, (C$ millions)	2010		2009
Gross Revenues	28		303
Less: Royalties	-		-
Net Revenues	28		303
Operating Expenses and Other	(3	)	(31	)
Gain (Loss) on Risk Management	25		272
	Unrealized Gain (Loss)
	Three Months Ended
For the period ended March 31, (C$ millions)	2010		2009
Gross Revenues	241		105
Less: Royalties	-		-
Net Revenues	241		105
Operating Expenses and Other	(4	)	(19	)
Gain (Loss) on Risk Management	237		86

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Reconciliation of Unrealized Risk Management Positions from January 1 to March 31,

(C$ millions)			2010		2009
	Fair Value		Total Unrealized Gain (Loss)		Total Unrealized Gain (Loss)
Fair Value of Contracts, Beginning of Period	(13	)
Change in Fair Value of Contracts in Place at Beginning of Period and Contracts Entered into During the Period	262		262		358
Fair Value of Contracts Realized During the Period	(25	)	(25	)	(272	)
Fair Value of Contracts, End of Period	224		237		86

Commodity Price Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, Management believes 10 percent volatility is a reasonable measure. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting net earnings as at March 31, 2010 as follows:

(C$ millions)	10% Price Increase		10% Price Decrease
Natural gas price	(118	)	118
Crude oil price	(63	)	63
Power price	2		(2	)

C) Risks Associated with Financial Assets and Liabilities

Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.  The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.  The Company’s policy is not to use derivative financial instruments for speculative purposes.

Crude Oil – The Company has partially mitigated its exposure to the commodity price risk on its crude oil sales and condensate supply with fixed price swaps.

Natural Gas – To partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into swaps to manage the price differentials between these production areas and various sales points.

Power – The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

F-76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company’s credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality. All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks.  As at March 31, 2010, over 97 percent (December 31, 2009--98 percent) of Cenovus’s accounts receivable and financial derivative credit exposures are with investment grade counterparties.

At March 31, 2010, Cenovus had four counterparties whose net settlement position individually account for more than 10 percent (December 31, 2009–three counterparties, including Encana) of the fair value of the outstanding in-the-money net financial and physical contracts by counterparty.  The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the Partnership Contribution Receivable and the member loans receivable is the total carrying value. The current concentration of this credit risk resides with Encana and A rated or higher counterparties. Cenovus’s exposure to its counterparties is acceptable and within Credit Policy tolerances.

Liquidity Risk

Liquidity risk is the risk that Cenovus will not be able to meet all of its financial obligations as they become due.  Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.  Cenovus manages its liquidity through the active management of cash and debt.  As disclosed in Note 15, Cenovus targets a Debt to Capitalization ratio of between 30 and 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash flow from operating activities and undrawn credit facilities.  At March 31, 2010, no amounts were drawn on Cenovus’s committed bank credit facility.

It is Cenovus’s intention to maintain investment grade credit ratings on its senior unsecured debt.  DBRS Limited 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 outlined in the table below:

	Less than 1 Year	1 - 3 Years	4 - 5 Years	Thereafter	Total
Accounts Payable and Accrued Liabilities	1,823	-	-	-	1,823
Risk Management Liabilities	67	6	-	-	73
Long-Term Debt*	229	415	1,210	5,518	7,372
Partnership Contribution Payable*	496	993	993	993	3,475
Member Loans Payable	-	279	-	-	279

*  Principal and interest, including current portion

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended March 31, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results. Cenovus’s functional currency and reporting currency is Canadian dollars.  All amounts are reported in Canadian dollars, unless otherwise indicated.

As disclosed in Note 8, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar Partnership Contribution Receivable issued from Canada.  At March 31, 2010, Cenovus had US$3,500 million in U.S. dollar debt issued from Canada (US$3,525 million at December 31, 2009) and US$2,753 million related to the U.S. dollar Partnership Contribution Receivable (US$2,834 million at December 31, 2009).  A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $7 million change in foreign exchange (gain) loss at March 31, 2010 (2009–$13 million).

Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect the earnings, cash flows and valuations.  Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.

At March 31, 2010, one hundred percent of the Company’s debt is fixed-rate debt and as a result, for each one percent change in interest rates on floating rate debt there would be no impact on net earnings (2009–$6 million).

18.  PER SHARE AMOUNTS

For the period ended March 31,	Three Months Ended
	2010	2009
Weighted Average Common Shares Outstanding – Basic	751.5	750.5
Effect of Dilutive Securities	0.2	0.9
Weighted Average Common Shares Outstanding – Diluted	751.7	751.4

Since Cenovus’s shares were issued pursuant to the Arrangement with Encana to create the Company, the per share amounts disclosed for the comparative period are based on Encana’s common shares.

19.  CONTINGENCIES

Legal Proceedings

Cenovus is involved in various legal claims associated with the normal course of operations.  Cenovus believes it has made adequate provisions for such legal claims.

Cenovus Energy Inc.	First quarter report
	for the period ended March 31, 2010

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Cenovus Energy Inc.

Management’s Discussion 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 the audited Cenovus Energy Inc. Consolidated Financial Statements for the year ended December 31, 2009 (the “Consolidated Financial Statements”) as well as EnCana Corporation’s (“EnCana”) Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. (the “Information Circular”) dated October 20, 2009. Readers should also read the “Forward-Looking Statements” legal advisory contained at the end of this document and such similar legal advisories contained in the Information Circular.

Management is responsible for preparing the MD&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 have been prepared in United States (“U.S.”) dollars, except where another currency has been indicated, and in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). Production and reserves volumes are presented on an after royalties basis consistent with U.S. protocol reporting.  This document is dated February 17, 2010.

Readers can find the definition of certain terms used in this document in the disclosure regarding Oil and Gas Information and Currency, Non-GAAP Measures and References to Cenovus contained in the Advisory section located at the end of this document, and such similar advisories set out in the Information Circular.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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INTRODUCTION AND OVERVIEW OF CENOVUS ENERGY

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Our operations include enhanced oil recovery (“EOR”) properties and established crude oil and natural gas production in Alberta and Saskatchewan. We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the Arrangement with EnCana Corporation which created two independent publicly traded energy companies – Cenovus and EnCana (the “Arrangement”). Although we are a new company, we have operated a number of assets for decades.

Our operations include our technology-driven EOR properties, coupled with established crude oil and natural gas production in Alberta and Saskatchewan.  Three of our four enhanced oil properties (Foster Creek, Christina Lake and Pelican Lake) are located in the Athabasca region in northeast Alberta. The fourth, the Weyburn carbon dioxide (“CO2”) sequestration EOR project, is located in southeastern Saskatchewan. We also have a 50 percent ownership interest in two refineries in Illinois and Texas, USA, enabling us to capture the full value from crude oil production through to refined products such as gasoline, diesel and jet fuel.

Our operational focus over the next five years will be to increase production predominantly from our steam-assisted gravity drainage (“SAGD”) operations at Foster Creek and Christina Lake. We have proven our expertise and low cost EOR development approach. Our established crude oil and natural gas production base is expected to generate stable production and cash flows which will enable further development of our core bitumen assets. In all our operations, whether bitumen, crude oil or natural gas, technology plays a key role in extracting the resource, increasing the amount recovered, reducing costs and improving the way we extract the resources. One of our most significant ongoing objectives is to advance technologies that reduce the amount of water, steam, natural gas and electricity consumed in our operations and to minimize surface land disturbance.

Our future lies in developing the vast land position we hold in the Athabasca region in northeast Alberta. In addition to our Foster Creek and Christina Lake properties, we currently have two emerging properties in this area: Borealis and Narrows Lake. A joint application to the Energy Resources Conservation Board and Alberta Environment for the development of Borealis has been submitted for the construction of a SAGD facility with production capacity of 35,000 barrels (“bbls”) of bitumen per day. We hold a 50 percent interest in the Narrows Lake play, through our interest in the FCCL Partnership, which is located within the greater Christina Lake regional area.  We are preparing development plans and regulatory applications for a project at Narrows Lake that would include two to three phases with each phase expected to add approximately 40,000 barrels per day (“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 currently expected to assist in meeting consumer demand for decades to come. Growth at these enhanced oil operations is expected to be internally funded through cash flow generated from our established crude oil and natural gas production base. Our natural gas production also provides a natural economic hedge for the natural gas required as a fuel source at our upstream and downstream operations. Our low-cost refineries operated by ConocoPhillips, an unrelated U.S. public company, enable us to integrate our bitumen production with the sale of refined products.

OUR BUSINESS STRUCTURE

Our operations are organized into two operating divisions:

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

·Canadian PlainsDivision, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn; and

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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(ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

For financial statement reporting purposes, our operating and reportable segments are:

·Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada.  This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips and operated by Cenovus.

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

·Corporate and Eliminations, which mainly includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities.  As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

OVERVIEW OF 2009

This past year was highlighted by a number of significant factors that had major influences on our activities and financial results. The most significant factor was the global credit 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 arrange a committed Canadian $2.5 billion bank credit facility and successfully raise $3.5 billion in unsecured notes. This allowed us to move forward with the Arrangement, and on November 25, 2009, over 99 percent of the votes cast by EnCana shareholders were in favour of our creation. The global recession also impacted commodity prices which were depressed for most of 2009; however we 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 the markets uncertainty, we increased focus on cost control and discipline in 2009 through our “10 percent challenge” initiative. Through this focus on cost reduction, we identified opportunities to reduce operating costs and adjust and redirect our capital program. Our reduction of capital expenditures was partly responsible for the nine percent decrease in natural gas production; and although we did reduce spending on our oil projects as well, our average daily production grew 10 percent, with Foster Creek and Christina Lake production increasing 43 percent. Consistent with our long-term strategy to develop our integrated oil business, we continued with our development work at both Foster Creek and Christina Lake, as well as the Coker and Refinery Expansion (“CORE”) project at the Wood River refinery.

As part of the creation 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 which otherwise would have been paid in 2010 had the dissolution not occurred.  This cash tax significantly reduced our Cash Flow for the fourth quarter of 2009. Also, we were part of EnCana for 11 months of the year, and therefore our reported results for 2009 may not be typical of the results that we will achieve in future years as a stand-alone entity.

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In addition to the above, 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.

OUR BUSINESS ENVIRONMENT

Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and foreign 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 of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel.

After reaching record highs in July of 2008, the price of WTI decreased over the remainder 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 bbl on signs of an economic recovery and production discipline by OPEC. Consistent with the increase in WTI, WCS increased 103 percent from December 31, 2008 to December 31, 2009. During 2009, the average differential between WTI and WCS narrowed to less than $10 per bbl for the year as WCS averaged 84 percent of WTI.

During 2009, U.S. refining crack spreads reflected lower consumer demand, in response to the depressed economy. This reduction in U.S. demand occurred during an overall increase in global refinery capacity.

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2009 was the second consecutive annual decline in the consumption of refined products in the United States which resulted in lower prices for refined products and narrowing crack spreads.

Throughout 2009, natural gas prices in North America declined due to a combination of low demand in response to economic conditions and an increase in supply as new prolific shale gas plays began production and associated drilling commitments were completed. The result was above average volumes in storage during 2009 which decreased the price for natural gas.  Cold weather during the latter part of 2009, particularly in the eastern United States, helped the AECO price at December 31, 2009 increase from earlier lows of $2.56 per Mcf to $5.25 per Mcf but still remained below last year’s year end level.

Our risk mitigation strategy has reduced our exposure to commodity price volatility through our hedging program. Further information regarding this program can be found in the Risk Management section of this MD&A and the notes to the Consolidated Financial Statements.

ANNUAL FINANCIAL INFORMATION

The Consolidated Financial Statements include the results for the period from January 1 to 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 the historical results of operations and historical basis of assets and liabilities of the businesses subsequently transferred to Cenovus on a carve-out accounting basis. Further details are provided in the notes to the Consolidated Financial Statements.

SELECTED ANNUAL CONSOLIDATED FINANCIAL 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 defined within this MD&A.

(2)Any per share amounts prior to December 1, 2009 have been calculated using EnCana’s common share balances based on the terms of the Arrangement where EnCana shareholders received one common 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 connection with the Arrangement based on carve-out earnings and cash flow.

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REVENUE VARIANCE

($ 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 of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

Total Revenues, Net of Royalties decreased $6,419 million in 2009 compared to 2008 primarily as a result of lower average commodity prices, consistent with decreased benchmark prices 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 Flow is a non-GAAP measure defined as Revenue, Net of Royalties less production and mineral taxes, transportation and selling, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between periods.

In total, Operating Cash Flow from our Upstream and Downstream segments decreased by $155 million. Detail of the components that explain changes to Operating Cash Flow from 2008 can be found in the Divisional Results section of this MD&A.

CASH FLOW

Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.  Cash Flow is commonly used in the oil and gas industry to assist in measuring the ability to finance capital programs 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

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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Our Cash Flow decreased to $2,472 million in 2009, a decrease of $616 million from 2008 ($3,088 million). The decrease was the result of:

·Decrease in the average natural gas price, excluding financial hedging, of $4.16 per Mcf or 54 percent from 2008;

·Decrease in the average liquids selling price, excluding financial hedging, of $23.13 per bbl, or 31 percent, from 2008;

·Current tax increased $513 million primarily due to accelerated income tax as a result of the dissolution of a partnership as part of the Arrangement; and

·Decline of nine percent in our production of natural gas.

The decreases in our 2009 Cash Flow were offset by:

·Realized financial hedging gains of $692 million, after tax, compared to realized hedging losses of $213 million, after tax, in 2008;

·An improvement in our operating cash flow from downstream operations of $551 million;

·A decrease in our transportation and selling and operating expenses of $360 million; and

·10 percent increase in our crude oil and NGLs production volumes compared to 2008.

Our Cash Flow in 2008 of $3,088 million was lower than 2007 Cash Flow of $3,536 million by $448 million, primarily due to:

·Operating cash flows from downstream operations decreased $1,315 million primarily due to weaker refining margins and higher purchased product costs;

·Realized financial crude oil, natural gas and other commodity hedging losses of $213 million after-tax in 2008, compared to gains of $97 million after-tax in 2007;

·Natural gas production volumes in 2008 decreased six percent compared to 2007; and

·Increases in transportation and selling, operating, interest and general and administrative expenses.

The decreases in our 2008 Cash Flow were offset by:

·Higher average natural gas prices, excluding financial hedges, of $7.76 per Mcf in 2008 compared to $6.08 per Mcf in 2007; and

·Higher average liquids prices, excluding financial hedges of $74.00 per bbl in 2008 compared to $46.69 per bbl in 2007.

OPERATING EARNINGS

($ 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-market accounting 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 the final settlement of hedge positions.

(2)After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax realized foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt.

Operating Earnings is a non-GAAP measure defined as Net Earnings excluding non-operating items including the after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments, after-tax gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.

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We believe that these non-operating items reduce the comparability of our underlying financial performance between periods. The above reconciliation of Operating Earnings has been prepared to provide information that is more comparable between periods. The items identified above that affected our Cash Flow and below that affected our Net Earnings also impacted our Operating Earnings.

NET EARNINGS

Net Earnings in 2009 of $648 million were $1,720 million lower compared to 2008.  The items identified above that affected our 2009 Cash Flow also impacted Net Earnings. Other significant factors that reduced our 2009 Net Earnings included an unrealized mark-to-market loss of $667 million, compared to a $734 million gain in 2008 and unrealized foreign exchange loss of $313 million in 2009 compared to a gain in 2008 of $259 million.  These reductions to Net Earnings and the increased current tax, which impacted Cash Flow, were offset by a recovery of future income tax in 2009 of $551 million, compared to a future income tax expense of $385 million in 2008.

Our Net Earnings in 2008 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 Cash Flow also impacted Net Earnings. Other significant factors that increased our 2008 Net Earnings included an unrealized mark-to-market gain, after-tax, of $519 million, compared to a $244 million loss in 2007, non-operating foreign exchange gains of $220 million, after-tax, in 2008 compared to losses of $301 million after-tax in 2007 as well as a $108 million decrease in depreciation, depletion and amortization.

As a means of managing the volatility of commodity prices, we enter into various financial instrument agreements. Changes in the mark-to-market gain or loss on these agreements affect our Net Earnings and are the result of volatility in the forward commodity prices and changes in the balance of unsettled contracts. Our 2009 and 2008 Net Earnings benefitted overall from this program, while in 2007, we reported a reduction in Net Earnings from our hedging program. The following information has been provided in order to provide information that is more comparable 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 in Corporate financial results.  Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Eliminations section of this MD&A.

(2)Included in Divisional financial results.

NET CAPITAL INVESTMENT

($ 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

Capital investment in 2009 was primarily focused on the continued development of our EOR properties (Foster Creek, Christina Lake, Pelican Lake and Weyburn) and the expansion of our downstream heavy oil refining capacity. During 2009, part of the reduction in our capital investment reflected our internal “10 percent challenge”, 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 Divisional Results section of this MD&A.

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Acquisitions and Divestitures

In 2009, acquisition and divestiture activity resulted in net proceeds of $206 million from various divestitures, including the sale of the Senlac heavy oil assets, a farm-out transaction and one minor acquisition.

Our acquisitions and divestitures in 2009 also included a property swap under the terms of which we acquired strategic bitumen lands at Narrows Lake in exchange for certain non-core lands.

FREE CASH FLOW

In order to determine the funds available for financing and investing activities, including dividend payments, we use a non-GAAP measure of Free 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 is defined under the Cash Flow section of this MD&A.

In 2009, our Free Cash Flow was $580 million, which was $462 million lower than our Free Cash Flow of $1,042 million in 2008 (2007 - $2,061 million) primarily due to lower cash flow, partially offset by less capital investment during the year. Additional explanations for the decrease in total Cash Flow and Capital Investment are discussed under the Cash Flow, Net Capital Investment and Divisional Results sections of this MD&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 the Business Environment section of this MD&A, the average U.S./Canadian dollar exchange rate was lower in 2009 than both 2008 and 2007. The table below summarizes the impact of the lower foreign exchange rate on reported amounts when 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 Canadian dollar 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 increase resulted in a Foreign Currency Translation Adjustment of $2.0 billion, net of tax for 2009 which increased our Comprehensive Income.  As the U.S. to Canadian dollar exchange rate weakened 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 our Comprehensive Income by $2.2 billion, net of tax.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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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 Lake increased in 2009 as a result of the commissioning and ramp up of new expansion phases at each property, slightly offset by higher royalty rates as a result of the new Alberta royalty framework (effective January 1, 2009), which reduced the production volumes. Weyburn production increased from 2008 to 2009 as a result of well optimizations and lower royalties. The decrease in production at Pelican Lake for 2009 was a result of natural production declines and a scheduled facility turnaround partially offset by fewer operational issues at the facility. Crude oil production from Southern Alberta decreased in 2009 compared to 2008 due to expected natural declines partially offset by lower 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 in 2009 compared to 2008 was the result of expected natural production declines and capacity restrictions in response to the lower commodity price.  These production decreases were partially offset by a slight reduction in the royalty rates as a result of declining prices.

Operating Netbacks

	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

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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Our average netback for both liquids and natural gas (excluding realized financial hedging) was lower in 2009 primarily as a result of lower average prices for the year, consistent with the reduction in benchmark prices.

As part of ongoing efforts to maintain financial resilience and flexibility, we reduced our pricing risk through a commodity price hedging program. In 2009, our hedging program 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 Management section of this MD&A and the notes to the Consolidated Financial Statements.

DIVISIONAL RESULTS

Our Upstream Canada segment includes the upstream activities of the Integrated Oil Division and the Canadian Plains Division. Our Downstream Refining segment includes the Downstream Refining business of the Integrated Oil Division.

INTEGRATED OIL DIVISION

We are a 50 percent partner in an integrated North American oil business with ConocoPhillips that consists of an upstream and a downstream entity.  The upstream entity includes the Foster Creek and Christina Lake oil properties in northeast Alberta, while the downstream entity includes the Wood River and Borger refineries located in Illinois 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)  Includes the impact of realized financial hedging.

(2)  Revenue dollars reported include the value of condensate sold as bitumen blend.  Condensate costs are  recorded in transportation and selling expense.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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Revenues, net of royalties, excluding realized financial hedging, decreased $19 million in 2009 compared to 2008 as a result of lower average crude oil prices offset by an increase in crude oil production of 43 percent. During 2009, financial hedging activities realized a gain of $37 million ($2.35 per bbl) compared to a loss of $67 million ($6.11 per bbl) in 2008 (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 38 percent decrease in average WTI prices over the year offset somewhat by the narrowing of the WCS differential.

Production at Foster Creek increased 41 percent in 2009 compared 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 higher royalty rates.  Production from phase C reached capacity of 60,000 bbls/d in the third quarter of 2008.  Production from the phase D/E expansion commenced late in the first quarter of 2009 and ramped up throughout the year.

Production at Christina Lake increased 54 percent in 2009 compared to 2008 as a result of higher production from the phase B expansion which commenced production in the second quarter of 2008 slightly offset by higher royalty rates in 2009.

Transportation and selling costs are comprised mostly of condensate costs, as blending condensate with bitumen enables the product to be transported. During 2009, condensate volumes increased due to the higher production noted above, offset by a 45 percent decrease in the average price of condensate used for blending. This resulted in a reduction of transportation and selling costs to $430 million in 2009 from $526 million in 2008 (2007 - $366 million).

Operating costs in 2009 increased slightly to $176 million compared to $170 million in 2008 due to the significant increase in volumes combined with additional repairs and maintenance and a scheduled turnaround at Christina Lake in the fall of 2009. The increase in operating costs was offset by lower fuel costs due to declining natural gas prices as well as higher volumes of Athabasca natural gas production being used internally at Foster Creek, 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 River and Borger refinery operations.

On a 100 percent basis, our refineries have a current capacity of approximately 452,000 bbls/d of crude oil and 45,000 bbls/d of NGLs, as well as processing capability to refine approximately 145,000 bbls/d of heavy crude oil (approximately 70,000 bbls/d of bitumen equivalent). Upon completion of the Wood River CORE project in 2011 we expect to be able to refine approximately 275,000 bbls/d (on a 100 percent basis) of heavy crude oil (approximately 150,000 bbls/d of bitumen equivalent) primarily into motor fuels.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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During 2009, our refineries operated at an average of 87 percent of their capacity compared to 93 percent in 2008. Utilization was lower in 2009 primarily due to refinery optimization based on weakened market crack spreads, increased number of turnarounds at Wood River to advance the CORE project and unplanned maintenance at both refineries.

Revenues have decreased 41 percent and purchased product has decreased 48 percent in 2009, consistent with the decrease in crude oil prices. Purchased product, consisting mainly of crude oil, represented 91 percent of total expenses in 2009 compared to 95 percent in 2008. Operating costs, consisting mainly of labour, utilities and supplies, decreased eight percent in 2009 due to lower prices for electricity and fuel gas consumed at the refineries.

Operating Cash Flow for 2009 was $551 million higher than 2008 mainly due to lower purchased product costs more than offsetting lower refined product sales. The increase was partially offset by lower refinery utilization.

INTEGRATED OIL DIVISION - OTHER PROPERTIES

The Integrated Oil Division also manages our 100 percent owned natural gas operations in Athabasca. For 2009, natural gas production volumes from Athabasca decreased to 49 MMcf/d (2008 – 63 MMcf/d; 2007 – 91 MMcf/d) primarily as a result of increased usage of natural gas as a source of fuel for the Foster Creek operations as well as natural declines.

In November 2009, we sold our Senlac heavy oil assets for proceeds of approximately $83 million. Prior to the divestiture, Senlac production 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 primarily focused on the continued development of the next phases of the Foster Creek and Christina Lake properties. Capital investment was lower in 2009 because of lower drilling costs as we drilled fewer stratigraphic test wells at Foster Creek, Christina Lake and Borealis, combined with a lower foreign exchange rate. Our current plan is to increase production capacity at Foster Creek and Christina Lake to approximately 218,000 bbls/d of bitumen with the completion of Christina Lake phase C in 2011 and phase D in 2013.  We have chosen to accelerate completion of Christina Lake phase D which we expect will advance start up by approximately six months.

Our Downstream Refining capital investment in 2009 continued to focus on the CORE project at the Wood River refinery, as we significantly increased capital expenditures to $907 million in 2009 from $478 million in 2008 (2007 - $220 million). The CORE project is expected to cost approximately $1.8 billion (net to Cenovus) and is anticipated to be completed and in operation in 2011.  The expansion is expected to increase crude oil refining capacity by 50,000 bbls/d to 356,000 bbls/d and more than double heavy crude oil refining capacity at Wood River to 240,000 bbls/d.  At December 31, 2009, construction on the CORE project was approximately 71 percent complete and continued to be on schedule and within budgeted costs.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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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 realized financial hedging.

(2)Revenue dollars reported include the value of condensate sold as heavy oil blend.  Condensate costs are recorded in transportation and selling expense.

Crude oil and NGL revenues, net of royalties, excluding realized financial hedging, decreased $885 million in 2009 compared to 2008 due to lower commodity prices and production volumes.

The average crude oil sales price, excluding realized hedging, decreased 35 percent to $51.80 per bbl in 2009 from $79.09 per bbl in 2008, consistent with changes in the benchmark WTI and WCS crude oil prices. During 2009, crude oil and NGLs realized financial hedging gains were $2 million ($0.10 per bbl) compared to losses of $150 million ($6.02 per bbl) in 2008 (2007 – loss of $87 million; $3.32 per bbl).

Production volumes at Weyburn were seven percent higher in 2009 compared to 2008 mainly due to well optimizations and lower royalty rates partially offset by natural declines. At Pelican Lake, volumes were nine percent lower in 2009 compared to 2008 mainly due to natural declines and a scheduled facility turnaround partially offset by less facility downtime. Southern Alberta oil production was down eight percent from 2008 primarily due to expected natural declines partially offset by production from new wells.

Production and mineral taxes of $24 million in 2009 decreased from $38 million in 2008 (2007 - $29 million) consistent with lower crude oil prices.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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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 the average price and a nine percent decrease in volume of condensate used for blending with heavy oil.

Operating costs decreased to $229 million in 2009 from $239 million in 2008 (2007 - $215 million) due to a lower foreign exchange rate and lower workover activity partially offset by higher chemical usage and electricity costs. NGLs are a byproduct obtained through the production of natural gas and therefore operating costs associated with the production of NGLs are included with natural 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) Includes the impact of realized financial hedging.

Natural gas revenues, net of royalties, excluding realized financial hedging, decreased $1,370 million in 2009 compared to 2008, primarily due to lower natural gas prices as well as lower production volumes.  Average natural 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 reduction in 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 Southern Alberta decreased eight percent in 2009 compared to 2008 due to expected natural declines and lower drilling and tie-in activity in response to lower commodity prices partially offset by lower royalty rates.

Production and mineral taxes of $13 million 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) due to lower volumes being shipped to eastern Canada and the eastern United States and the

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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lower foreign exchange rate.

Operating expenses in 2009 decreased to $210 million from $241 million in 2008 (2007 - $221 million) mostly as a result of the lower foreign exchange rate combined with a lower level of repair, 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 markets all of our crude oil and natural gas, including third party purchases and sales of product, in order to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.  The decrease in both revenues and purchased product expenses for 2009 compared to 2008 is consistent with decreased average market prices during 2009.  Canadian Plains – Other also includes a small amount of third party processing fee income.

Capital Investment

Canadian Plains capital investment in 2009 was $478 million (2008 - $872 million; 2007 - $795 million). The $394 million decrease from 2008 was primarily the result of management’s decision to reduce capital investment in response to lower commodity prices in 2009.  The reduction came primarily from lower natural gas drilling, completion and tie-in activity, as well as the lower foreign exchange rate, and lower land acquisition expenditures, partially offset by higher heavy crude oil drilling activity.  Canadian Plains drilled 614 net wells in 2009 compared to 1,476 net wells 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 Eliminations segment includes revenues that represent the unrealized mark-to-market gains or losses related to derivative financial instruments used to mitigate fluctuations in commodity prices. The segment also includes inter-segment eliminations that relate to transactions that have been recorded at transfer prices based on current market prices as well as unrealized intersegment profits in inventory. Operating expenses primarily relate to mark-to-market gains and losses on long-term power purchase contracts and downstream crude oil supply positions.  Depreciation, Depletion and Amortization

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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(“DD&A”) includes provisions in respect of corporate assets, such as computer equipment, office furniture and leasehold improvements.

General and administrative expenses increased $21 million in 2009 compared to 2008 primarily due to higher long-term compensation costs as a result of the increased share price and expenses related to the creation of Cenovus offset by a lower foreign exchange rate.

Interest expense in 2009 was $218 million, unchanged from 2008 interest expense, of $218 million (2007 - $187 million) primarily as a result of our average level of debt outstanding and interest rates being consistent between 2008 and 2009. Our weighted average interest rate on outstanding debt at December 31, 2009 was 5.8 percent, compared to 5.5 percent in 2008.

We reported a foreign exchange loss of $290 million in 2009 compared to a gain of $250 million in 2008 (2007 – loss of $380 million), the majority of which was unrealized.  We are exposed to foreign exchange gains and losses primarily on our U.S. dollar partnership contribution receivable and our U.S. dollar denominated debt issued from Canada.  The strengthening of the Canadian dollar during 2009 led to unrealized losses on our partnership contribution receivable, which was partially offset by unrealized gains on our U.S. dollar debt.  We also reported an unrealized foreign exchange loss of $107 million during the year relating to the translation of our U.S. dollar risk management assets and liabilities, compared to an unrealized gain of $2 million in 2008 (2007 – unrealized loss of $34 million).  The loss incurred in 2009 was also primarily due to the strengthening of the Canadian dollar during the year.

Depreciation, Depletion and 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 and gas activities and calculate DD&A on a country-by-country cost centre basis. Upstream DD&A of $1,101 million in 2009 was consistent with 2008 DD&A of $1,107 million (2007 - $1,222 million) as a result of a higher DD&A rate offset by a lower foreign exchange rate and slightly lower production volumes. In 2009, DD&A on our Downstream Refining assets was $192 million, which was consistent with 2008 DD&A of $188 million (2007 - $159 million). DD&A in the Corporate and Eliminations segment was $50 million for 2009 compared to $23 million for 2008 (2007 - $45 million).

Income Tax

Total income tax expense in 2009 was $302 million, which was $423 million lower than 2008 mainly due to lower earnings before income tax. Current income tax expense in 2009 was $853 million compared to $340 million in 2008, with the increase largely being attributable to the acceleration of income tax arising from the dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement, as well as the realization of significant hedging gains in 2009. This accelerated current tax was offset by a future tax recovery for the tax that would have been paid in 2010. Current tax expense for the three years is primarily an allocation of EnCana’s income tax liability on a carve-out accounting basis our portion of which was settled as part of the Arrangement and therefore we do not have any income tax payable at December 31, 2009.

In 2009, we had a future income tax recovery of $551 million compared to an expense of $385 million in 2008. The significant net recovery in 2009 is due to the reversal of the future tax which offsets the accelerated current income tax on partnership income, as noted above, as well as 2008 unrealized mark-to-market hedging gains.

In 2009, our effective tax rate was 31.8 percent compared to 23.4 percent in 2008. The increase is primarily due to the provision of future income tax on unrealized foreign exchange gains as well as a variety of rate differences.

Additional information regarding our effective tax rate can be found in the notes to the Consolidated Financial Statements. Our effective tax rate in any year is a function of the relationship between total tax expense and the amount of earnings before income taxes for the year. The effective tax rate differs from the statutory tax rate as it takes into consideration permanent differences, adjustments for changes in tax

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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rates and other tax legislation, variation in the estimate of reserves and the differences between the provision and the actual amounts subsequently reported on the tax returns.  Permanent differences include:

·      The non-taxable portion of Canadian capital gains and losses;

·      International financing; and

·      Foreign exchange (gains) losses not included in Net Earnings.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change.  As a result, there are usually some tax matters under review.  We believe that our provision for taxes is adequate.

Summary of Unrealized Mark-to-Market Gains (Losses)

The volatility of commodity prices has a significant impact on our Net Earnings, and as a means of managing this volatility, we enter into various financial instrument agreements. The financial instrument agreements were recorded at the date of the financial statements based on mark-to-market accounting. Changes in the mark-to-market gain or loss reflected in corporate revenues are the result of volatility between periods in the forward commodity prices and changes in the balance of unsettled contracts. The table below provides a summary of the unrealized mark-to-market gains and losses recognized for each year. Additional information regarding financial instrument agreements can be found in the notes to 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	)

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in US$)

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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-GAAP measures which are defined in this MD&A.

(2)Any per share amounts prior to December 1, 2009 have been calculated using EnCana's common share balances based on the terms of the Arrangement where EnCana shareholders received one common 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 connection with the Arrangement based on carve-out earnings and cash flow.

Our Cash Flow in the fourth quarter of 2009 increased $399 million compared to the fourth quarter of 2008.  The main drivers for the increase in Cash Flow were:

·The improvement of downstream operating cash flow in 2009 was the result of the fourth quarter in 2008 being impacted by a 50 percent drop in crude oil prices compared to the third quarter of 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 sales price, before hedging, to $61.08 per bbl compared to $30.47 per bbl in 2008; and

·Increase in crude oil and NGLs production of 11 percent.

Partially offsetting the increases were the following:

·An increase in 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 dissolution of EnCana’s Canadian oil and gas partnership in connection with the Arrangement;

·A decrease in natural gas average sales prices, excluding hedging, of 30 percent; and

·A decrease in natural gas production of 13 percent.

Our Net Earnings in the fourth quarter of 2009 were $24 million, which were $356 million lower than 2008. The factors that increased Cash Flow in the fourth quarter increased Net Earnings but were offset by the following factors that resulted in an overall decrease to Net Earnings:

·Unrealized hedging loss of $143 million compared to a gain of $386 million in the fourth quarter of 2008; and

·Higher Operating, General and Administrative and DD&A expenses.

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OIL AND GAS RESERVES

PROVED AND PROBABLE RESERVES AS AT DECEMBER 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 and NGLs include condensate.

All of our bitumen, crude oil, NGLs and natural gas reserves are located in Canada.  Each year, we engage independent qualified reserves evaluators to prepare reports on 100 percent of our reserves.  We have a Reserves Committee of independent members of our Board, which reviews the qualifications and appointment of the independent qualified reserves evaluators.  The Reserves Committee also reviews the procedures for providing information to the evaluators.  Our disclosure of reserves data is prescribed by National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators as amended by a Decision dated October 20, 2009 permitting the adoption of U.S. reporting standards, including compliance with the practices and procedures of the U.S. Securities and Exchange Commission (“SEC”) and U.S. Financial Accounting Standards Board (“FASB”) reserves reporting requirements.

As of December 31, 2009, the SEC requires companies to determine their oil and gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The SEC also now permits companies to disclose their probable and possible reserves in 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 and NGLs includes condensate.

In 2009, our bitumen reserves extensions and discoveries were approximately 160 million barrels, primarily as a result of Christina Lake phase D receiving approval to proceed. The increase was partially offset by negative revisions of approximately 88 million barrels attributed to higher royalty rates resulting from a higher WTI price. In addition, as a result of the new Alberta Royalty Framework, where royalties are determined on a sliding scale depending on the price 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. Once a project reaches payout the royalty is based on the greater of one to nine percent of a project’s gross revenue or 25 to 40 percent of net revenue. Our crude oil and NGLs reserves decreased by approximately four percent year over year as aggregate revisions and improved recoveries and extensions and discoveries did not fully offset our production. Our natural gas reserves negative revisions were approximately 128 billion cubic feet mainly due to low natural gas prices.

Additional disclosure relating to our oil and gas reserves is contained in our Annual Information Form for the year ended 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 activities increased 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 $3,088 million in 2008.  Reasons for this change are discussed under the Cash Flow section of this MD&A.  Cash from operating activities was also impacted by net changes in other assets and liabilities and net changes in non-cash working capital, primarily from increases in inventories, accounts receivable and accrued revenues and current income taxes partially offset by increases in accounts payable and accrued liabilities.

Excluding the impact of risk management assets and liabilities, we had working capital of $457 million at December 31, 2009 compared to a working capital deficit of $191 million at December 31, 2008.  We anticipate that we will continue to meet the payment terms of our suppliers.

INVESTING ACTIVITIES

Net cash used for investing activities in 2009 decreased to $1,780 million from $1,964 million in 2008. Capital expenditures decreased in 2009 to $1,895 million compared to $2,046 million in 2008.  Divestitures were $162 million higher than 2008 and were substantially offset with increases in cash used for investing activities from net changes in non-cash working capital.  The decreased capital expenditures are discussed under the Net Capital Investment and Divisional Results sections of this MD&A.

FINANCING ACTIVITIES

On September 18, 2009, a predecessor entity of Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3.5 billion, issued in three 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 offering, along with $151 million deposited by the Company, were placed into an escrow account pending the completion of the Arrangement with EnCana.  Upon completion of the Arrangement, funds were released from escrow and the proceeds of the notes were then used to pay the note payable to EnCana of $3.5 billion as part of the Arrangement. On November 30, 2009, the notes became the direct, unsecured obligations of Cenovus.

We currently have in place an unsecured credit facility in the amount of Canadian $2.5 billion or its equivalent amount in U.S. dollars. The revolving syndicated credit facility consists of two tranches, a Canadian $2.0 billion 3-year tranche and a Canadian $500 million 364-day tranche.  At December 31, 2009, we had available $2.3 billion (Canadian $2.4 billion) in unused credit capacity under this facility.  We are currently in compliance with all of our financial covenants under this credit facility.

We declared and paid a dividend of $151 million ($0.20 per share) in December 2009.  The December dividend reflects an amount determined in connection with the Arrangement based on carved-out earnings and cash flows. Future dividends will be at the sole discretion of the Board and considered quarterly.

It is Cenovus’s intention to maintain investment 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 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.

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As at December 31, 2008, our current and long-term debt represented an allocation of our proportionate share of EnCana’s consolidated current and long-term debt. As a result, the debt allocations presented in the Consolidated Financial Statements at December 31, 2008 represented intercompany balances between EnCana and Cenovus with the same terms and conditions as EnCana’s long-term debt and in the same proportion of Canadian and U.S. dollar denominated debt.

Our net cash used in financing activities for 2009 of $1,730 million, includes $3,468 million of net proceeds from the private offering of the notes, as well as the repayment of the $3.5 billion demand promissory note to EnCana. Subsequent to the completion of the Arrangement, Cenovus made a payment to EnCana in the amount of $250 million to adjust the cash balances of both companies at November 30, 2009 to the agreed upon 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 at December 31, 2008.

FINANCIAL METRICS

	2009	2008	2007
Debt to Capitalization	28%	28%	32%
Debt to Adjusted EBITDA (times)	1.2x	0.7x	1.0x

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. Capitalization is a non-GAAP measure defined as long-term debt including current portion plus Shareholders’ Equity. Trailing 12-month Adjusted EBITDA is a non-GAAP measure defined as Adjusted Earnings before Interest, Income Taxes, DD&A and foreign exchange gains/losses. These metrics are used to steward Cenovus’s capital structure.  Debt is defined as the current and long-term portions of long-term debt.

We target a Debt to Capitalization ratio between 30 to 40 percent and a Debt to Adjusted EBITDA between 1.0 to 2.0 times.

OUTSTANDING SHARE DATA

(millions)	2009
Common Shares issued pursuant to the Arrangement	751.3
Outstanding, End of year	751.3

Cenovus is authorized to issue an unlimited number of Common Shares (the “Common Shares”), an unlimited number of first preferred shares and an unlimited number of second preferred shares. There were no first preferred shares or second preferred shares outstanding as at December 31, 2009.

Pursuant to the Arrangement, each shareholder of EnCana received one new common share of EnCana (which continued to be represented by EnCana common share certificates outstanding prior to the Arrangement becoming effective) and one Common Share of Cenovus for every EnCana common share held.  In aggregate, 751,273,307 Common Shares were issued pursuant to the Arrangement.

The Cenovus Employee Stock Option Plan permits our Board, from time to time, to grant to employees of Cenovus and its subsidiaries stock options to purchase our Common Shares. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. As at December 31, 2009, our options are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years and expire five years after the date granted. Stock options granted have an associated Tandem Share Appreciation Right (“TSAR”) attached, which gives employees the right to elect to receive a cash payment equal to the excess of the market price of our Common Shares over the exercise price of their stock option in exchange for surrendering their stock option. A portion of the TSARs have an additional vesting condition which is subject to the Company attaining prescribed performance relative to key pre-determined measures. Performance TSARs that do not vest when eligible are forfeited. The exercise of a TSAR for a

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cash payment does not result in the issuance of any additional Common Shares, thus it has no dilutive effect.

In accordance with the Arrangement with EnCana, each holder of EnCana TSARs and stock options disposed of a portion of their right to Cenovus in exchange for Cenovus Replacement Units and to EnCana for EnCana Replacement Units. The terms and conditions of the Cenovus Replacement Units are similar to the terms and conditions of the original EnCana units, which are also similar, to the terms and conditions of Cenovus TSARs and stock options. The original exercise price of the EnCana units were apportioned to the Cenovus and EnCana Replacement Units based on the one-day weighted average trading price of Cenovus’s common share price relative to that of EnCana’s common share price on the TSX on December 2, 2009.

At December 31, 2009, Cenovus employees held approximately 16 million Cenovus TSARs, of which 6 million were exercisable.

At December 31, 2009 EnCana employees held approximately 23 million Cenovus TSARs, of which 10 million were exercisable. EnCana is required to reimburse Cenovus in respect of cash payments made to EnCana employees for the Cenovus TSARs held. No further Cenovus TSARs will be granted to EnCana’s employees. Cenovus is required to reimburse EnCana in respect of cash payments made to Cenovus employees for the Cenovus Replacement Units held. No further EnCana Replacement Units will be granted to Cenovus’s employees.

At December 31, 2009 there were approximately 0.2 million options without TSARs attached outstanding, all of which were exercisable.

Cenovus employees hold Cenovus Share Appreciation Rights, Cenovus Deferred Share Units, EnCana Tandem Share Appreciation Rights and EnCana Share Appreciation Rights and Cenovus directors hold Cenovus Deferred Share Units for which Cenovus is responsible.  These units do not result in the issuance of any additional Cenovus Common Shares and therefore have no dilutive effect.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS(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 various commitments in the normal course of operations primarily related to debt, demand charges on firm transportation agreements, capital commitments and marketing agreements.

As at December 31, 2009, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas with a current delivery of approximately 33 MMcf/d, with varying terms and volumes through

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2017.  The total volume to be delivered within the terms of these contracts is 85 Bcf at a weighted average price of $4.39 per Mcf.

In the normal course of business, we also lease office space for personnel who support field operations and for corporate purposes.

LEGAL PROCEEDINGS

We are involved in various legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims.

RISK MANAGEMENT

Our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, are impacted by risks that are categorized as follows:

·Financial risks including market risks (such as commodity price, foreign exchange and interest rates), credit and liquidity risks;

·Operational risks including capital, operating and reserves replacement risks; and

·Safety, environmental and regulatory risks.

We are committed to identifying and managing these risks in the near-term as well as on a strategic and longer term basis at all levels in the organization in accordance with our Board approved Corporate Risk Management Policy and risk management programs. Issues affecting, or with the potential to affect, our assets, operations and/or reputation, are generally of a strategic nature or emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. We take a proactive approach to the identification and management of issues that can affect our assets, operations and/or reputation and have established consistent and clear policies, procedures, guidelines and responsibilities for identifying and managing these issues.

FINANCIAL RISKS

Financial risks are defined as the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on our business.

We continue to implement our business model which focuses on developing low-risk and low-cost long-life resource properties. Management has been monitoring our operational and financial risk strategies to proactively respond to the changing economic conditions and to mitigate or reduce risk. The prudent and conservative capital budget for 2010 continues to be monitored and it contains the flexibility to allow spending to be reduced or increased as commodity prices and forecasts are revised.  Cost containment and reduction strategies are in place to help ensure our controllable costs are efficiently managed. Counterparty and credit risks are closely monitored as is our liquidity to help ensure our ability to access cost effective credit is maintained and that sufficient cash resources are in place to fund capital expenditures. Further insight into these risks and strategies is summarized below.

We partially mitigate our exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies and is subject to limits established in our Market Risk Mitigation Policy. As a means of mitigating exposure to commodity price risk volatility, we have entered into various financial instrument agreements in respect of our operations. The details of these instruments, including any unrealized gains or losses, as of December 31, 2009, are disclosed in the notes to the Consolidated Financial Statements.

Policies, practices and procedures are in place with respect to the required documentation and approvals for the use of derivative financial instruments and specifically tie their use, in the case of commodities, to the mitigation of price risk to achieve targeted investment returns and growth objectives, while maintaining prescribed financial metrics.

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With respect to transactions involving our production or assets, the financial instruments generally used are swaps or options which are entered into with major financial institutions, integrated energy companies or commodities trading institutions.

COMMODITY PRICE

Commodity price risk is defined as the uncertainties and fluctuations of future market prices for commodities.  To partially mitigate the commodity price risk, we enter into swaps and puts, which establish NYMEX floor prices.For crude oil, we have partially mitigated our exposure to commodity price risk on our crude oil sales and condensate supply with fixed price swaps.  For natural gas, to partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, Cenovus has entered into basis swaps to manage the price differentials between these production areas and various sales points. We have mitigated some of our exposure to electricity consumption costs, with two derivative contracts which do not expire until December 31, 2018.

CREDIT

Credit risk is defined as the potential for loss if a counterparty in a transaction fails to meet its obligations in accordance with agreed terms.  A substantial portion of our accounts receivable is with customers in the oil and gas industry. This credit exposure is mitigated through the use of our Board-approved credit policies governing our credit portfolio and with credit practices that limit transactions according to counterparties’ credit quality and transactions that are fully collateralized. All financial derivative agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.

LIQUIDITY

Liquidity risk is the risk we will not be able to meet all our financial obligations as they come due.  Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to multiple sources of capital including: cash and cash equivalents, cash from operating activities and undrawn credit facilities.  At December 31, 2009, Cenovus had approximately $2.3 billion in unused credit capacity available on its committed bank credit facility.

FOREIGN EXCHANGE

Foreign exchange risk is defined as the risk of gains or losses that could result from changes in foreign currency exchange rates.  As we operate in North America, fluctuations in the exchange rate between the U.S. and Canadian dollar can have a significant effect on our reported results.

As a means of mitigating the exposure to fluctuations in the U.S./Canadian dollar exchange rate, we may enter into foreign exchange contracts, in conjunction with crude oil marketing transactions. In addition, we may hedge commodity exposures in Canadian dollars. Gains or losses on these contracts are recognized when the difference between the average month spot rate and the rate on the date of settlement is determined. All foreign exchange agreements are with major financial institutions in Canada and the United States 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 and Canadian dollar debt, which helps to offset the exposure to the fluctuations in the 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 of our 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 rates on earnings, cash flows and valuations. Although the majority of our debt portfolio was fixed rate debt at December 31, 2009, we have the flexibility to partially mitigate our exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of our bank credit facilities. We may also enter into interest rate swap transactions from time to time as an additional means of managing the fixed/floating rate debt portfolio mix.

OPERATIONAL RISKS

Operational risk is the risk of loss or lost opportunity resulting from operating and capital activities that, by their nature, could have an impact on our ability to achieve our objectives.

Our ability to operate, generate cash flows, complete projects and value reserves is dependent on financial risks, including commodity prices mentioned above, continued market demand for our products and other risk factors outside of our control, which include:  general business and market conditions; economic recessions and financial market turmoil; the ability to secure and maintain cost effective financing for our commitments; the ability to obtain necessary approvals; environmental and regulatory matters; unexpected cost increases; royalties; taxes; the availability of drilling and other equipment; the ability to access lands; weather; the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of diluents to transport crude oil; technology failures; accidents; the availability of skilled labour; and reservoir quality.

If we fail to acquire or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels and, therefore, our cash flows are highly dependent upon successfully exploiting current reserves and acquiring, discovering or developing additional reserves.

To mitigate these risks, as part of the capital approval process, we evaluate projects on a fully risked basis, including geological risk and engineering risk. In addition, the asset teams undertake a process called Lookback and Learning. In this process, each asset team undertakes a thorough review of its previous capital program to identify key learnings, which often include operational issues that positively and negatively impacted the project’s results. Mitigation plans are developed for the operational issues that had a negative impact on results. These mitigation plans are then incorporated into the current year plan for the project. On an annual basis, these Lookback and Learning results are analyzed for our capital program with the results and identified learnings shared across our company.

We utilize a peer review process to ensure that capital projects are appropriately risked and that knowledge is shared across our company. Peer reviews are undertaken primarily for early stage properties, although they may occur for any type of project.

When making operating and investing decisions, our business model allows flexibility in capital allocation to optimize investments focused on strategic fit, project returns, long-term value creation, and risk mitigation.  We also mitigate operational risks through a number of other policies, systems and processes as well as by maintaining a comprehensive insurance program in respect of our assets and operations.

SAFETY, ENVIRONMENTAL AND REGULATORY RISKS

We are engaged in relatively high risk activities of integrated enhanced oil development and natural gas production. We are committed to safety in our operations and with high regard for the environment and stakeholders, including regulators.  These risks are managed by executing policies and standards that are designed to comply with or exceed government regulations and industry standards. In addition, we maintain a system, in respect of our assets and operation, that identifies, assesses and controls safety, security and environmental risk and requires regular reporting to Senior Management and our Board. The Safety, Environment and Responsibility Committee of our Board provides recommended environmental policies for approval by our Board and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental

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and regulatory standards are met. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation strategies are utilized to restore the environment.  In addition, security risks are managed through a security program designed to protect our personnel and assets.

We have an Investigations Committee with the mandate to address potential violations of policies and practices and an Integrity Helpline that can be used to raise any concerns regarding operations, accounting or internal control matters which includes any such matters associated with us.

Our operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact our existing and planned projects as well as impose a cost of compliance.

Regulatory and legal risks are identified by the operating divisions and corporate groups, and our compliance with the required laws and regulations is monitored by our legal group in respect of our assets and operations. Our legal and environmental policy groups stay abreast of new developments and changes in laws and regulations to ensure that we continue to comply with prescribed laws and regulations. Of note in this regard, our approach to changes in regulations relating to climate change and royalty frameworks is discussed below.  To partially mitigate resource access risks, keep abreast of regulatory developments and be a responsible operator, we maintain relationships with key stakeholders and conduct other mitigation initiatives mentioned herein.

CLIMATE CHANGE

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (“GHG”) emissions and other air pollutants and a number of legislative and regulatory measures to address GHG emissions are in various phases of review, discussion or implementation in the United States and Canada. These include proposed federal legislation and state actions in the United States to develop statewide or regional programs, each of which could impose reductions in GHG emissions.  While some jurisdictions have provided details on these regulations, it is anticipated that other jurisdictions will announce emission reduction plans in the future.  Adverse impacts to our business if comprehensive GHG legislation is enacted in any jurisdiction in which we operate, may include, among other things, increased compliance costs, permitting delays, substantial costs to generate or purchase emission credits or allowances adding costs to the products we produce and reduced demand for crude oil and certain refined products.

Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance.  We intend to continue our activity to reduce our emissions intensity and improve our energy efficiency. We will also continue to work with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.

The Alberta government has set targets for GHG emissions reductions. In March 2007, regulations were amended to require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. To comply, companies can make operating improvements, purchase carbon offsets (or emission performance credits) or make a C$15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. Cenovus currently has three facilities subject to this regulation that will report performance against their targets in March 2010 and for the 2009 compliance year does not anticipate material costs.

The American Clean Energy and Security 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 of the climate change bills being contemplated in the U.S. would require refiners to purchase credits equivalent to the

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CO2 emissions from both their refineries and from consumer emissions. If this approach was enacted into law, this could have a material impact on the cost structure of refined petroleum products.

Our efforts with respect to emissions management are founded in our industry leadership in CO2 sequestration, a focus on energy efficiency and the development of technology to reduce GHG emissions.  In particular, our industry leading steam to oil ratio at Foster Creek and Christina Lake translates directly into lower emissions intensity.  Given the uncertainty in North American carbon legislation, our strategy for addressing the implications of emerging carbon regulations is proactive and is composed of three principal elements:

1.Manage Existing Costs

When regulations are implemented, a cost is placed on our emissions (or a portion thereof) and while these are not material at this stage, they are being actively managed to ensure compliance.  Factors such as effective emissions tracking attention to fuel consumption and a focus on minimizing our steam to oil ratio help to support and drive our focus on cost reduction.

2.Respond to Price Signals

As regulatory 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 to improve the energy efficiency of our operations.  The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon reduction, we are also attempting, where appropriate, to realize the associated value of our reduction projects.

3.Anticipate Future Carbon Constrained Scenarios

We continue to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations.  By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, we gain useful knowledge that allows us to explore different strategies for managing our emissions and costs.  These scenarios inform our long range planning 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 constrained scenarios on our strategy, with a current price range from $15 to $65 per tonne of emissions applied to a range of emissions coverage levels. A major benefit of applying a range of carbon prices at the strategic level is that it provides direct guidance to the capital allocation process.  We also examine the impact of carbon regulation on our major projects. Although uncertainty remains regarding potential future emissions regulation, our plan is to continue to assess and evaluate the cost of carbon relative to our investments across a range of scenarios.

We recognize that there is a cost associated with carbon emissions. We are confident that GHG regulations and the cost of carbon at various price levels have been adequately accounted for as part of our business planning and scenarios analysis. We believe that our development strategy is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. We are committed to transparency with our stakeholders and will keep them apprised of how these issues affect operations.

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner which maintains and enhances our reputation and credibility.  A central aspect of this commitment involves engagement with our various stakeholders, including shareholders and other investors, financial institutions, employees, business partners, communities, Aboriginal peoples, governments and non-governmental organizations. We will continue to disclose information about our business activities to our stakeholders in a timely and transparent manner to maintain and advance our reputation as a responsible operator, as well as to develop trust with our stakeholders. We disclose information that is not only required by law and/or regulation, but also additional information that management regards as important to help stakeholders understand our activities, policies, opportunities and risks. Our engagement with stakeholders also allows us to determine how they are each affected by our business. Feedback that we receive from stakeholders enables us to better identify and manage our environmental and socio-economic risks.

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We are reviewing our existing Corporate Responsibility (“CR”) policy to ensure that it not only continues to drive our commitments, strategy and reporting, but also that it maintains alignment with our business objectives and processes. Our reporting process will focus on improving performance through better data management, stakeholder engagement and continuous improvement. Our approach in this first year is to communicate our key performance indicators using the Cenovus website as the main reporting vehicle.

As our CR reporting process matures, additional indicators will be developed that better reflect Cenovus’s operations and challenges. These indicators will be integrated into our CR reporting and will expand our online presence through our website.

We are committed to integrating the principles of corporate responsibility into the way we conduct our business across all of our operations and we recognize the importance of reporting to stakeholders in a transparent and accountable way.

ALBERTA’S NEW ROYALTY PROGRAMS

The Alberta Government’s New Royalty Framework (“NRF”) and Transitional Royalty Program (“TRP”) came into effect on January 1, 2009.  The NRF established new royalties for conventional oil, natural gas and bitumen that are linked to commodity prices, well production volumes and well depths for gas wells and oil quality for oil wells.  These new rates apply to both new and existing conventional oil and gas activities and EOR properties in Alberta.  The TRP allows for a one time option of selecting between transitional rates and the NRF rates on new natural gas or conventional 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 wells would be moved to the NRF.

On March 3, 2009, the Alberta Government announced an Energy Incentive Program that focuses on keeping drilling and service crews at work.  There are two components of this program that affect us: the Drilling Royalty Credit and the New Well Incentive.  The Drilling Royalty Credit is a depth related credit for the drilling of new conventional oil and gas wells between April 1, 2009 and March 31, 2011.  The New Well Incentive provides a maximum five percent royalty rate for new gas and conventional 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 of oil equivalent (“BOE”) for oil wells, whichever comes first.

Impacts as a result of the NRF, TRP and Energy Incentive Programs change the economics of operating in Alberta, and accordingly, are reflected in our capital programs in respect of our assets and operations.

We are committed to continuing to work with the Alberta Government during its competitive review process.

ACCOUNTING POLICIES AND ESTIMATES

Management is required to make judgments, assumptions and estimates in the application of GAAP that have a significant impact on our financial results. The basis of presentation for the Consolidated Financial Statements and our significant accounting policies can be found in the notes to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to understanding our financial results.

Basis of Presentation

Our results for the period from December 1 to December 31, 2009 represent our operations, cash flows and financial position as a stand-alone entity.

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Our results for the periods prior to the Arrangement with EnCana, being January 1 to November 30, 2009 as well as 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 accounting records of EnCana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. The historical consolidated financial statements include allocations of certain EnCana expenses, assets and liabilities.  In the opinion of Management, the consolidated and the historical carve-out consolidated financial statements reflect all adjustments necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian GAAP.

The presentation of financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the assumptions underlying the historical consolidated financial statements are reasonable.  However, as we 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 not necessarily reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

Full Cost Accounting

Crude oil and natural gas properties are accounted for in accordance with the Canadian Institute of Chartered Accountants (“CICA”) guideline on full cost accounting in the oil and gas industry. Under this method, all costs, including internal costs and asset retirement costs, directly associated with the acquisition of, exploration for, and the development of crude oil and natural gas reserves, are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs, including estimated future development costs, are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. Reserves estimates can have a significant impact on earnings, as they are a key component in the calculation of DD&A. A downward revision in reserves estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserves estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property divestiture, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent or greater.

Oil and Gas Reserves

All of our oil and gas reserves are evaluated and reported on by independent qualified reserves 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, all of which are subject to numerous uncertainties and various interpretations. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

Asset Impairments

Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. An impairment loss is recognized in Net Earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of:

i)      the fair value of proved and probable reserves; and

ii)     the costs of unproved properties that have been subject to a separate impairment test.

An impairment loss is recognized on downstream refining property, plant and equipment when the carrying amount is not recoverable and exceeds its fair value. The carrying amount is not recoverable if the carrying amount exceeds the 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 as the amount by which the refinery asset exceeds the discounted future cash flows from the refinery asset.

Our property, 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 Canadian GAAP.

Asset Retirement Obligations

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made. Asset retirement obligations are legal obligations associated with the requirement to retire tangible long-lived assets such as producing well sites, crude oil and natural gas processing plants and refining facilities.  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 in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.  Amounts recorded for asset retirement obligations are based on estimates of reserves and on retirement costs, which will not be incurred for several years. Actual expenditures incurred are charged against the accumulated obligation.

Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to the country cost centre level, referred to as reporting units.  To assess impairment, the fair value of each reporting unit is determined and compared to 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. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of Goodwill and comparing that amount to the book value of the reporting unit’s Goodwill.  Any excess of the book value of Goodwill over the implied fair value of Goodwill is the impairment amount.

Our Goodwill has been assessed for impairment as at December 31, 2009 and it has been determined that no write-down was required.

Income Taxes

Income taxes are accounted for using the liability method. Under this method, future income taxes are estimated and recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in Net Earnings in the period that the change occurs.

Tax interpretations, regulations and legislation in the various jurisdictions in which we (and our subsidiaries) operate are subject to change. As such, income taxes are subject to measurement uncertainty.

Derivative Financial Instruments

We may use derivative financial instruments to manage exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates.  Derivative financial instruments are not used for speculative purposes.

We enter into financial transactions to help reduce exposure to price fluctuations with respect to commodity purchase and sale transactions to 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 financial institutions or commodities trading institutions.

We may also use derivative financial instruments, such as interest rate swap agreements, to manage the fixed and floating interest rate mix of our total debt portfolio and related overall cost of borrowing. Interest rate swap agreements involve the periodic exchange of payments, without the exchange of the normal principal amount upon which the payments are based, and are recorded as an adjustment of interest expense on the hedged debt instrument.

We may also purchase foreign exchange forward contracts to hedge anticipated sales to customers in the United States. Foreign exchange translation gains and losses on these instruments are recognized as an adjustment of the revenues when the sale is recorded.

Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in Net Earnings. Realized gains or losses from financial derivatives related to crude oil and natural gas prices are recognized in revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.  The estimated fair value of financial assets and liabilities, by their very nature, is subject to measurement uncertainty.

In 2009, we elected not to designate any of our price risk management activities as accounting hedges and, accordingly, accounted for all derivatives using the mark-to-market accounting method.  Mark-to-market gains and losses resulting from derivative financial instruments entered into by EnCana have been allocated to Cenovus based on the related product volumes.

We also have obligations for payments (to employees of Cenovus) under the share appreciation rights, stock options with TSARs attached, performance share appreciation rights, and performance TSARs of EnCana. The financial liability for this obligation is accrued using the fair value method, and therefore fluctuations in the fair value of the rights will affect the accrued compensation expense that is recognized. The fair value of the obligation fluctuates, as it is based on assumptions for risk-free discount rate, dividend yield, as well as the volatility of our Cenovus share price.

Pensions and Other Post-Employment Benefits

Accruals for the obligations under the employee benefit plans and the related costs are recorded net of plan assets.

The cost of pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The accrued benefit obligation is discounted using the market interest rate on high quality corporate debt instruments as at the measurement date.

Pension expense for the defined benefit pension plan includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. The amortization period covers the expected average remaining service lives of employees covered by the plans.

Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plan.

Pension and other post-employment benefits costs, assets and liabilities have been allocated to us based on Management’s best estimate of how services were historically provided by existing employees.  Costs,

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assets and liabilities associated with retired employees remain with EnCana.  Where service amounts are provided by an individual to both EnCana and Cenovus, those costs including salaries, benefits, pension and long-term incentives have been allocated equally between EnCana and Cenovus.

Performance TSARs and Performance SARs

These plans provide for a range of payouts, based on key predetermined performance measures. The cost of these plans is expensed based on expected payouts.  However, the amounts to be paid, if any, may vary from the current estimate.  Further details on these plans are disclosed in the notes to our Consolidated Financial Statements.

NEW ACCOUNTING STANDARDS ADOPTED

On January 1, 2009, we adopted the CICA Handbook Section 3064 “Goodwill and Intangible Assets”. The adoption of this standard has had no material impact on our Consolidated Financial Statements.  Additional information on the effects of the implementation of the new standard 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 which have been converged with International Financial Reporting Standards (“IFRS”):

Business Combinations

“Business Combinations”, Section 1582, replaces the previous business combinations standard.  The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings.  The adoption of this standard will impact the accounting treatment of future business combinations.

Consolidated Financial Statements

“Consolidated Financial Statements”, Section 1601, which together with Section 1602 below, replace the former consolidated financial statements 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 our Consolidated Financial Statements.

Non-controlling Interests

“Non-controlling Interests”, Section 1602, 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 in a subsidiary 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 our Consolidated Financial Statements.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

In 2011, IFRS will replace Canadian GAAP for profit-oriented Canadian publicly accountable enterprises. We will be required to report our results 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 the transition to IFRS by January 1, 2011, including the preparation of required comparative information for 2010. The key elements of our changeover plan include:

·Determine appropriate changes to accounting policies and required amendments to financial disclosures;

·Identify and implement changes in associated processes and information systems;

·Comply with internal control requirements;

·Communicate collateral impacts to internal business groups; and

·Educate and train internal and external stakeholders.

IFRS Accounting Policies

We have completed our analysis of accounting policy alternatives and determined the areas that will be most significantly affected by the adoption of IFRS. The areas identified as being significant have the greatest potential impact to our financial statements or the greatest risk in terms of complexity to implement. The most significant areas continue to include:

·Upstream Property, Plant and Equipment (“PP&E”), including

Transition on date of adoption of IFRS

Pre-exploration costs

Exploration and Evaluation costs

DD&A

Gains and losses on divestitures

·Impairment testing

·Asset retirement obligation

·Stock-based compensation

·Income taxes

Upstream PP&E

Upstream PP&E will be one of the most significant areas impacted by the adoption of IFRS.  Under Canadian GAAP, we follow the CICA’s guideline on full cost accounting, while IFRS has no equivalent guideline. In order to facilitate the transition to IFRS by 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 exemption which permits full cost accounting companies to allocate their existing upstream PP&E net book value (full cost pool) over reserves to the unit of account level upon transition to IFRS.  We expect to adopt this exemption using the fair value of reserves as an allocation method. Without this exemption, we would have been required to retrospectively determine the carrying amount of oil and gas assets at the date of transition, or use the fair value or revaluation amount as our new deemed cost under IFRS.  By using the exemption, the net book value of our upstream PP&E at the date of transition to IFRS will be the same as it was under Canadian GAAP, subject to any potential IFRS impairments that are recognized at the date of transition.

In moving to IFRS, we will be required to adopt different accounting policies for pre-exploration activities, exploration and evaluation costs, DD&A and the accounting for gains and losses on divestitures of properties.

Pre-exploration costs are costs incurred before the Company obtains the legal right to explore an area. Under Canadian GAAP, these costs are capitalized, while under IFRS, these costs must be expensed. At this time, we do not anticipate that this accounting policy difference will have a significant impact on our Consolidated Financial Statements.

During the exploration and evaluation phase (“E&E”), we capitalize costs incurred for these projects under Canadian GAAP. Under IFRS, we have the alternative to either continue capitalizing these costs until technical feasibility and commercial viability of the project has been determined, or expensing these costs as incurred. At this time, our IFRS accounting 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 the country cost centre level. Under IFRS, this rate will be calculated at a lower unit of account level. At this time, we have not finalized our policy in this regard, and therefore the impact of this difference in accounting policy is not reasonably determinable.

Full cost accounting under Canadian GAAP requires that gains or losses on divestitures of properties are only recognized when the disposal would affect our DD&A rate by 20 percent or more. Under IFRS, there is no such exemption, and therefore we will be required to recognize all gains and losses on property divestitures. At this time, the impact of this difference in accounting policy is not reasonably determinable.

As a result of the additional exemption released by the IASB, we anticipate that all changes to our Upstream PP&E accounting policies 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 not discounted. Under IFRS, the future cash flows are discounted. In addition, for upstream PP&E, impairment testing is currently performed at the country cost 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 in accounting policy prospectively. At this time, the impact of accounting policy differences related to impairment testing is not reasonably determinable.

Asset Retirement Obligation

Under Canadian GAAP, the discount rate used to estimate the liability is not updated to current market discount rates, while under IFRS, the rate is updated each reporting period. We expect to adopt this change in accounting policy prospectively. We do not anticipate that this accounting policy difference will have a significant impact on our consolidated financial statements.

Stock-based Compensation

Under Canadian GAAP, obligations for cash payments under stock-based compensation plans are accrued using the intrinsic method, while under IFRS, these obligations must be accounted for using the fair value method. While the carrying value each reporting period will be different under IFRS, the cumulative expense recognized over the life of the instrument under both methods will be the same. We expect to adopt this change in accounting policy prospectively. At this time, the impact of this difference is not reasonably determinable.

Income Tax

In transitioning to IFRS, the carrying amount of our tax balances will be directly impacted by the tax effects resulting from changes required by the above IFRS accounting policy differences. Therefore, at this time the income tax impacts of our differences are not reasonably determinable.

Changes to IFRS Accounting Standards

Our analysis of accounting policy differences specifically considers the current IFRS standards that are in effect. We will continue to monitor any new or amended accounting standards that are issued by the IASB, including assessing any impact of the new joint ventures standard that the IASB expects to publish in the first quarter of 2010.

Preparation of the IFRS Opening Balance Sheet

We expect to commence working on the determination of our IFRS opening balance sheet in the first quarter of 2010.

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Information Systems

We have completed the design of process and system changes that we expect will be required. We have performed preliminary testing of the changes and expect to finalize our testing in the first half of 2010. We plan to fully implement the system changes by June 30, 2010.

Internal Controls Over Financial Reporting

We are in the process of updating our internal controls documentation, and we do not anticipate that the transition to IFRS will have a significant impact on either our internal controls over financial reporting, or our disclosure controls and procedures.

Education and Training

All of the individuals that are involved in our financial reporting under Canadian GAAP have been engaged and involved in the IFRS transition project since 2008, and will continue to be involved in our IFRS transition throughout 2010 and 2011. Other individuals affected by the change from Canadian GAAP to IFRS will be educated and trained during 2010 as we identify and calculate the specific dollar value of differences arising from the changes to our accounting policies.

Impacts to our Business

We are not expecting that the adoption of IFRS in 2011 will have a significant impact or influence on our business activities, operations or strategies.

OUTLOOK

Our long term objective is to focus on building net asset value and generating an attractive total shareholder return through the following 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;

· 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 believe global oil demand will continue to increase. However, commodity price volatility, environmental regulations, government intervention and competitive pressures within our industry are the key hurdles that need to be effectively managed to enable our growth. Additional detail regarding the impact of these factors on our 2009 results is discussed in the Risk Management section of this MD&A. WTI and light-heavy differentials are likely to be relatively strong for the foreseeable future. Offsetting this is a relatively weak price outlook for natural gas and refining margins.

We expect our 2010 capital investment program to be funded from Cash Flow. Our crude oil and natural gas assets in Alberta and Saskatchewan will be key to providing free cash flow to enable our bitumen growth. We have chosen to accelerate completion of Christina Lake phase D which we expect will advance start up by approximately six months.

As part of ongoing efforts to maintain financial resilience and flexibility, Cenovus has taken steps to reduce pricing risk through a commodity hedging program. While we have benefitted from this strategy in 2009 and 2008, we cannot ensure that we will continue to derive such benefits in the future.

One of the factors that will affect our future results will be our effective royalty rates. Based on current market pricing, we expect that the Foster Creek project will reach payout during 2010.  Once the project

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reaches payout the applicable monthly royalty will be based on the greater of 1-9 percent of the project’s gross revenue or 25-40 percent of the net revenue. The actual royalty rate that is payable within these ranges is determined based on the WTI U.S. dollar price of crude oil, translated into Canadian dollars.

As a new entity, the Company will continue to develop strategy with respect to capital investment and returns to shareholders. Future dividends will be at the sole discretion of the Board and considered quarterly.

ADVISORY

FORWARD-LOOKING STATEMENTS

In the interest of providing Cenovus shareholders and potential investors with information regarding the Company and its subsidiaries, including Management’s assessment of Cenovus’s and its subsidiaries’ future plans and operations, certain statements contained in this document constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “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 our provision for taxes; the effect of our policies and programs to reduce safety, environmental and regulatory risks, including climate change; our estimate of the cost of carbon; the potential impact of the Alberta Royalty Framework, NRF, TRP and Energy Incentive Programs; projections and plans with respect to growth of natural gas production from unconventional properties and enhanced oil resources including with respect to the Foster Creek and Christina Lake properties, the CORE project and planned expansions of our downstream heavy oil processing capacity and the capital costs and expected timing of the same; our ability to meet consumer demand; projections relating to the volatility of crude oil prices in 2010 and beyond and the reasons therefor; commodity prices, including the WTI and light-heavy differentials; our projected capital investment levels for 2010, the flexibility of capital spending plans and the source of funding therefor; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; the adequacy of provisions made for legal proceedings against us; the impact of the changes and proposed changes in laws and regulations, including greenhouse gas, carbon and climate change initiatives on our operations and operating costs; our ability to realize the expected benefits of the Arrangement; potential dividends; our expected future attributes, business plan and operational focus; our ability to fund our 2010 capital program; the effect of our risk mitigation policies, systems, processes and insurance program; our expectations for future Debt to Capitalization and Debt to Adjusted EBITDA ratios; the expected impact and timing of various accounting pronouncements, rule changes and standards on us and our Consolidated Financial Statements; and projections relating to global oil demand, prices for natural gas and refining margins. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions based upon our current guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in our and our subsidiaries’ marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our and our subsidiaries’ ability to replace and expand oil and gas reserves; the ability of ourselves and ConocoPhillips to successfully manage and operate the North American integrated heavy oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with

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technology and the application thereof to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our and our subsidiaries’ ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which we and our subsidiaries operate; the risk of war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we and our subsidiaries operate; risks associated with existing and potential future lawsuits and regulatory actions made against us and our subsidiaries; the financing plans and initiatives that may be undertaken by us, the capitalization and adequacy thereof for us, the expected impacts of the Arrangement on our employees, operations, suppliers, business partners and stakeholders, our ability to obtain financing in the future on a stand alone basis, that the historical financial information pertaining to our assets as operated by EnCana prior to November 30, 2009 may not be representative of our results as an independent entity, that we have a limited operating history, as a separate entity, and other risks and uncertainties described from time to time in the reports and filings we have made with securities regulatory authorities. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements 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 update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

We previously disclosed and updated guidance relating to anticipated results for 2009. There were no material differences between (a) our actual cash flow, capital investment and operating costs in 2009 and (b) the amounts forecast in our most recently disclosed guidance (dated December 1, 2009). Explanations for any changes contained in any updated guidance, from guidance previously disclosed, were provided in the news release issued by Cenovus at the time the guidance was updated.

Our forward-looking information respecting anticipated 2010 cash flow, operating cash flow and pre-tax cash flow is based upon achieving average 2010 production of approximately 105,000 bbls/d to 111,500 bbls/d of crude oil and liquids and 720 MMcf/d to 740 MMcf/d of natural gas, average commodity prices for 2010 of a WTI price of $65 per bbl to $85 per bbl and a WCS price of $54 per bbl to $71 per bbl 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 dollar foreign exchange rate of $0.85 to $0.96 US$/CDN$, an average Chicago 3-2-1 crack spread for 2010 of $7.50 per bbl to $9.50 per bbl for refining margins, and an average number of outstanding shares of approximately 750 million. Assumptions relating to forward-looking statements generally include our current expectations and projections made by the Company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this document.

We are required to disclose events and circumstances that occurred during the period to which this MD&A relates that are reasonably likely to cause actual results to differ materially from material forward-looking statements for a period that is not yet complete that we have previously disclosed to the public and the expected differences thereto. Such disclosure can be found in our news release dated February 11, 2010 which is available on www.sedar.com.

OIL AND GAS INFORMATION

Our disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to us by Canadian securities regulatory authorities that permits us to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by us may differ from the corresponding information prepared in accordance with Canadian disclosure standards under NI 51-101.

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The reserves quantities disclosed by us represent net proved and probable reserves calculated using the standards contained in Regulation S-X of the U.S. Securities & Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2009.

CRUDE OIL, 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 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head.

CURRENCY

All information included in this document and the Consolidated Financial Statements and comparative information is shown on a U.S. dollar, after royalties basis unless otherwise noted.

NON-GAAP MEASURES

Certain measures in this document do not have any standardized meaning as prescribed by Canadian GAAP such as Cash Flow, Operating Cash Flow, Free Cash Flow, Operating Earnings, Adjusted EBITDA, Debt and Capitalization and therefore are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding our liquidity and our ability to generate funds to finance our operations. Management’s use of these measures has been disclosed further in this document as these measures are discussed and presented.

REFERENCES TO 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 indirect subsidiary corporations and partnerships (“Subsidiaries”) of Cenovus, and the assets, activities and initiatives of such Subsidiaries.

Additional information regarding Cenovus Energy Inc. can be accessed under our public filings, including our Annual Information Form for the year ended December 31, 2009, found at www.sedar.com and on our website at www.cenovus.com.

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Cenovus Energy Inc.

Management’s Discussion and Analysis

For the Period Ended March 31, 2010

(Canadian Dollars)

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“Cenovus”, “we”, “our”, “us” or “the Company”), dated April 28, 2010, should be read with the unaudited Interim Consolidated Financial Statements for the period ended March 31, 2010 (“Interim Consolidated Financial Statements”), as well as the audited Consolidated Financial Statements for the year ended December 31, 2009 (the “Consolidated Financial Statements”) and Encana Corporation’s (“Encana”) Information Circular Relating to an Arrangement Involving Cenovus Energy Inc. (the “Information Circular”) dated October 20, 2009. This MD&A contains forward looking information based on our current expectations and projections. For information on the material factors and assumptions underlying our forward looking information, see the Advisory at the end of this document.

Management is responsible for preparing the MD&A, while the Audit Committee of the Board of Directors of Cenovus (the “Board”) reviews and approves the MD&A.

The Interim Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). Production volumes are presented on a before royalties basis.

Readers can find the definition of certain terms used in this document in the disclosure regarding Oil and Gas Information, Currency, Abbreviations, Non-GAAP Measures and References to Cenovus contained in the Advisory section at the end of this document.

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INTRODUCTION AND OVERVIEW OF CENOVUS ENERGY

Cenovus is an integrated oil company headquartered in Calgary, Alberta. Our operations include enhanced oil recovery (“EOR”) properties and established crude oil and natural gas production in Alberta and Saskatchewan. We also have ownership interests in two refineries in Illinois and Texas, USA.

We began independent operations on December 1, 2009 following the Arrangement with Encana which created two independent publicly traded energy companies – Cenovus and Encana (the “Arrangement”). Although we are a new company, we have operated a number of assets for decades.

Our operations include our technology-driven EOR properties, coupled with established crude oil and natural gas production in Alberta and Saskatchewan. Three of our four enhanced oil properties (Foster Creek, Christina Lake and Pelican Lake) are located in the Athabasca region in northeast Alberta. The fourth, the Weyburn carbon dioxide (“CO2”) sequestration EOR project, is located in southeastern Saskatchewan. We also have a 50 percent ownership interest in two refineries in Illinois and Texas, USA, enabling us to capture the full value from crude oil production through to refined products such as gasoline, diesel and jet fuel.

Our operational focus over the next five years will be to increase production predominantly from our steam-assisted gravity drainage (“SAGD”) operations at Foster Creek and Christina Lake. We have proven our expertise and low cost EOR development approach. Our established crude oil and natural gas production base is expected to generate stable production and cash flows which will enable further development of our bitumen assets. In all of our operations, whether bitumen, crude oil or natural gas, technology plays a key role in extracting the resource, increasing the amount recovered, reducing costs and improving the way we extract the resources. One of our most significant ongoing objectives is to advance technologies that reduce the amount of water, steam, natural gas and electricity consumed in our operations and to minimize surface land disturbance.

Our future lies in developing the vast land position we hold in the Athabasca region in northeast Alberta. In addition to our Foster Creek and Christina Lake properties, we currently have two emerging properties in this area: Borealis and Narrows Lake. A joint application to the Energy Resources Conservation Board and Alberta Environment for the development of Borealis has been submitted for the construction of a SAGD facility with production capacity of 35,000 bbls/d of bitumen. We hold a 50 percent interest in the Narrows Lake property, through our interest in the FCCL Partnership, which is located within the greater Christina Lake regional area. In the first quarter of 2010, we initiated the regulatory approval process by filing proposed terms of reference for an environmental impact assessment and began public consultation for the Narrows Lake project. The project is expected to include up to three phases, with the first phase expected to add approximately 40,000 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 is expected to assist in meeting consumer demand for decades to come. We have recently issued a news release that highlights more detailed information related to our contingent resources that enables investors to more fully understand our vast inventory of bitumen assets. Growth at these enhanced oil operations is expected to be internally funded through cash flow generated from our established crude oil and natural gas production base. Our natural gas production also provides a natural economic hedge for the natural gas required as a fuel source at both our upstream and downstream operations. Our refineries operated by ConocoPhillips, an unrelated U.S. public company, also enable us to integrate our bitumen production with the sale of refined products.

OUR BUSINESS STRUCTURE

Our operations are organized into two operating divisions:

·Integrated OilDivision, which includes all of the assets within the upstream and downstream integrated oil business with our joint venture partner, as well as other bitumen interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S.

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including two major enhanced oil recovery properties: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries: (i) Wood River; and (ii) Borger.

·Canadian PlainsDivision, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major enhanced oil recovery properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

For financial statement reporting purposes, our operating and reportable segments are:

·Upstream Canada, which includes Cenovus’s development and production of bitumen, crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada. This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips and operated by Cenovus.

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

·Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

OVERVIEW OF THE FIRST QUARTER 2010

The first quarter of 2010 was our first full quarter operating as an independent company. During the quarter, we achieved strong financial and operating performance. The specific financial and operating highlights of the first quarter of 2010 compared to the first quarter of 2009 are:

·Production from our Foster Creek and Christina Lake enhanced oil recovery properties increased 66 percent;

·Net revenues increased by 30 percent, primarily as a result of higher crude oil prices and increased crude oil production;

·Upstream Operating Cash Flow decreased by $11 million because of lower natural gas prices and production volumes offset by increased crude oil volumes and prices;

·Operating Cash Flow from Downstream Refining operations decreased by $79 million on lower refining margins;

·Realized financial hedging gains of $17 million, net of tax compared to gains of $198 million, net of tax in 2009;

·Operating earnings decreased by $61 million due to lower operating cash flows;

·Construction on the CORE project at the Wood River refinery progressed to approximately 77 percent complete at March 31, 2010; and

·Declared and paid dividends of $150 million ($0.20 per share).

Also, during the quarter, our Foster Creek property achieved project payout. Project payout is achieved when the cumulative project revenue exceeds the cumulative project allowable costs. As a result, Foster Creek’s effective royalty rate increased from 1.4 percent in the first quarter of 2009 to 9.7 percent for the same period in 2010. Post-payout royalty is based on the greater of one to nine percent of the project’s annual gross revenue or 25 to 40 percent of the annual net revenue. For royalty calculations, a project’s gross revenue is defined as total project revenue less transportation and condensate costs while a project’s net revenue is defined as gross revenue less operating and capital costs. Within the given royalty rate ranges, the royalty rate applied to gross or net revenue is determined based on the WTI U.S. dollar price per barrel of crude oil, translated into Canadian dollars.

In February, the acceleration of construction of phase D at Christina Lake was approved. Under this plan, the completion of phase D has been advanced by approximately six months with production expected to

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begin in 2013. We expect that our share of capital expenditures for 2010 related to the phase D expansion will total approximately $100 million including approximately $25 million related to the acceleration.

We have announced our intention to move ahead with the development of Narrows Lake which may use a combination of SAGD and Solvent Aided Process (“SAP”). SAP is a technological improvement applied to our SAGD operations that helps maximize the amount of oil recovered. It takes the benefit of injecting steam in the SAGD process and combines it with solvents, such as butane, to help bring the oil to the surface. A small amount of spending in 2010 will be focused on advancing regulatory requirements.

OUR BUSINESS ENVIRONMENT

Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and foreign exchange rates to assist in understanding our financial results:

	2010	2009				2008
(Average benchmark prices)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Crude Oil Prices (US$/bbl)
West Texas Intermediate (WTI)	78.88	76.13	68.24	59.79	43.31	59.08	118.22	123.80	97.82
Western Canadian Select (WCS)	69.84	64.01	58.06	52.37	34.38	39.95	100.22	102.18	76.37
Differential - WTI/WCS	9.04	12.12	10.18	7.42	8.93	19.13	18.00	21.62	21.45
WCS as % of WTI	89%	84%	85%	88%	79%	68%	85%	83%	78%
Refining Margin 3-2-1 Crack Spreads (1) (US$/bbl)
Chicago	6.11	5.00	8.48	10.95	9.75	6.31	17.29	13.60	7.69
Midwest Combined (Group 3)	6.82	5.52	8.06	9.16	9.62	6.00	14.38	13.47	10.26
Natural Gas Prices
AECO (C$/GJ)	5.08	4.01	2.87	3.47	5.34	6.43	8.76	8.86	6.76
NYMEX (US$/MMBtu)	5.30	4.17	3.39	3.50	4.89	6.94	10.24	10.93	8.03
Basis Differential – AECO/NYMEX (US$/MMBtu)	0.19	0.19	0.67	0.39	0.35	1.10	1.28	1.71	0.84
Foreign Exchange
Average U.S./Cdn Dollar Exchange Rate	0.961	0.947	0.911	0.857	0.803	0.825	0.961	0.990	0.996

(1)  3-2-1 Crack Spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of gasoline and one barrel of ultra low sulphur diesel.

The first quarter of 2010 saw continued economic growth in Asia and other developing regions, which created higher demand and higher market prices for crude oil. WTI improved from its December 31, 2009 closing price of US$79.36 to a March 31, 2010 closing price of US$83.45, its highest level in nearly 18 months. The price of WCS also increased with the differential between WTI and WCS staying consistent at around US$10 per bbl for both the first quarter of 2010 and 2009. WCS prices as a percentage of WTI are trading at very high levels compared to historic averages as a result of continued global expansion of coking capacity while facing reductions in heavy oil supply.  Supply reductions are due to OPEC production cuts, which disproportionately target heavy crudes and declining Mexican heavy crude production.

When compared to the fourth quarter of 2009, U.S. refining crack spreads improved in the first quarter of 2010 as consumer demand for refined products began to recover with the economy. Crack spreads for the first quarter of 2010 were lower compared to the same period in 2009 as the cost of crude oil feedstock increased substantially between the quarters. This increase was not fully reflected in the price for refined products due to continued erosion in U.S. product demand while new refining capacity continued to grow.

In the first quarter of 2010, NYMEX natural gas prices improved over both the fourth and first quarter of 2009 due to improved demand and falling supply. Despite these improvements, end-of-winter storage

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volumes were still 175 Bcf above the 5-year average but roughly 125 Bcf below last year and the end of the fourth quarter.

Our risk mitigation strategy has helped reduce our exposure to commodity price volatility. Further information regarding this program can be found in the notes to the Interim Consolidated Financial Statements.

FINANCIAL INFORMATION

In our financial reporting to shareholders for the year ended December 31, 2009, we used U.S. dollars as our reporting currency and reported production on an after royalties basis, consistent with U.S. protocol. Effective January 1, 2010, we changed our reporting currency to Canadian dollars and our reporting of production to a before royalties basis. This change in reporting currency and protocol was made to better reflect our business, and allows for increased comparability to our peers. With the change in reporting currency and protocol, all comparative information has been restated from U.S. dollars to Canadian dollars and production from after royalties to before royalties.

For more information we have released the following documents prepared in Canadian dollars on our website: (i) 2009 Consolidated Financial Statements; (ii) Select Interim and Annual Carve-out Consolidated Financial Information for the Interim and Annual Periods Ended 2009 and 2008; (iii) 2009 Supplemental Information; and (iv) 2009 Management’s Discussion and Analysis.

SELECTED CONSOLIDATED FINANCIAL RESULTS

	2010	2009						2008
	Q1		Q4		Q3	Q2	Q1		Q4		Q3	Q2	Q1
(millions of Canadian dollars, except per share amounts)
Net Revenues	3,491		3,005		3,001	2,818	2,693		3,946		5,753	4,424	3,447
Operating Cash Flow (1)	838		954		1,134	1,173	928		121		1,176	1,535	1,101
Cash Flow (1)	721		235		924	945	741		(209	)	1,161	1,244	919
- per share – diluted (2)	0.96		0.31		1.23	1.26	0.99		(0.28	)	1.54	1.66	1.22
Operating Earnings (1)	353		169		427	512	414		(159	)	623	722	434
- per share – diluted (2)	0.47		0.23		0.57	0.68	0.55		(0.21	)	0.82	0.96	0.58
Net Earnings	525		42		101	160	515		490		1,341	528	167
- per share – basic (2)	0.70		0.06		0.13	0.21	0.69		0.65		1.79	0.71	0.22
- per share – diluted (2)	0.70		0.06		0.13	0.21	0.69		0.65		1.78	0.71	0.22
Capital Investment	493		507		515	488	652		760		487	438	519
Free Cash Flow (1)	228		(272	)	409	457	89		(969	)	674	806	400
Cash Dividends (3)	150		159		-	-	-		-		-	-	-

(1)  Non-GAAP measures which are defined within this MD&A.

(2)  Any per share amounts prior to December 1, 2009 have been calculated using Encana’s common share balances based on the terms of the Arrangement where Encana shareholders received one common share of Cenovus and one common share of the new Encana.

(3)  We declared and paid a dividend of $0.20 per share in March 2010 and US$0.20 per share in December 2009. The December 2009 dividend reflects an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.

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NET REVENUES VARIANCE

(millions of Canadian dollars)
Net Revenues for the Three Months Ended March 31, 2009		$	2,693
Increase (decrease) due to:
Upstream Canada	Price	339
	Realized hedging	(275		)
	Volume	15
	Royalties	(68		)
	Other (1)	295
Downstream Refining		364
Corporate	Unrealized hedging	136
	Other	(8		)
Net Revenues for the Three Months Ended March 31, 2010		$	3,491

(1) Revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

Net revenues increased $798 million in the first quarter of 2010 compared to the first quarter of 2009, primarily as a result of higher average crude oil prices, consistent with higher benchmark prices in the first quarter of 2010, better downstream refined product sales prices and increased production from Foster Creek and Christina Lake. These increases were offset by decreased natural gas prices and production.

OPERATING CASH FLOW

Three Months Ended March 31,
(millions of Canadian dollars)	2010			2009
Crude Oil and NGLs
Foster Creek and Christina Lake	$	215		$	71
Canadian Plains	309			179
Natural Gas	314			594
Other Upstream Operations	6			11
	844			855
Downstream Refining	(6		)	73
Operating Cash Flow	$	838		$	928

Operating Cash Flow is a non-GAAP measure defined as net revenues less production and mineral taxes, transportation and selling, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between periods.

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In total, Operating Cash Flow from our Upstream Canada and Downstream Refining segments decreased by $90 million. Details of the components that explain changes to Operating Cash Flow in the first quarter of 2010 from the first quarter of 2009 can be found in the Divisional Results section of this MD&A.

CASH FLOW

Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.  Cash Flow is commonly used in the oil and gas industry to assist in measuring the ability to finance capital programs and meet financial obligations.

Three Months Ended March 31,
(millions of Canadian dollars)	2010			2009
Cash From Operating Activities	$	820		$	682
(Add back) deduct:
Net change in other assets and liabilities	(15		)	(3		)
Net change in non-cash working capital	114			(56		)
Cash Flow	$	721		$	741

In the first quarter of 2010 we generated Cash Flow of $721 million compared to $741 million for the same period in 2009. The decrease was the result of:

·Realized average natural gas price of $5.80 per Mcf in the first quarter 2010, which was down from the first quarter of 2009 by approximately 35 percent;

·A decrease in operating cash flow from downstream operations of $79 million;

·Increase in royalties of $68 million primarily as a result of Foster Creek achieving payout as well as higher crude oil prices;

·Natural gas production declined 11 percent; and

·An increase in general and administrative and net interest expenses of $31 million.

The decreases in our first quarter 2010 Cash Flow were offset by:

·Realized average liquids selling price of $68.07 per bbl which was 59 percent higher than the first quarter of 2009;

·Current tax decreased $83 million primarily due to decreased realized hedging gains and lower earnings from our downstream operations; and

·14 percent increase in our crude oil and NGLs production volumes compared to the same period in 2009.

OPERATING EARNINGS

Three Months Ended March 31,
(millions of Canadian dollars)	2010		2009
Net Earnings, as reported	$	525	$	515
Add back (losses) and deduct gains:
Unrealized mark-to-market accounting gain (loss), after tax (1)	170		64
Non-operating foreign exchange gain (loss), after-tax (2)	2		37
Operating Earnings	$	353	$	414

(1)  The unrealized mark-to-market accounting gains (losses), after-tax includes the reversal of unrealized gains (losses) recognized in prior periods.

(2)  After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, after-tax realized foreign exchange gains (losses) on settlement of intercompany transactions and future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt.

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Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gains or losses on discontinuance, after-tax effect of unrealized mark-to-market accounting gains (losses) on derivative instruments, after-tax gains (losses) on translation of U.S. dollar denominated Notes issued from Canada and the partnership contribution receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.

We believe that these non-operating items reduce the comparability of our underlying financial performance between periods. The above reconciliation of Operating Earnings has been prepared to provide information that is more comparable between periods. The items identified above that affected our Cash Flow and below that affected our Net Earnings also impacted our Operating Earnings.

NET EARNINGS VARIANCE

(millions of Canadian dollars)
Net Earnings for the Three months Ended March 31, 2009	$	515
Increase (decrease) due to:
Net revenues	798
Expenses:
Transportation and selling	(125		)
Purchased product	(629		)
Other expenses (1)	(49		)
Depreciation, depletion and amortization	56
Income taxes	(41		)
Net Earnings for the Three Months Ended March 31, 2010	$	525

(1)  Includes net expenses for Production and Mineral Taxes, Operating, General and Administrative, Interest, net, Accretion of asset retirement obligation, Foreign exchange (gain) loss and Other (income) loss, net.

Net Earnings in the first quarter of 2010 of $525 million increased by $10 million compared to the first quarter of 2009. The items identified above that affected our Cash Flow in the first quarter also impacted Net Earnings. Other significant factors that increased our first quarter 2010 Net Earnings include an unrealized mark-to-market gain, after tax, of $170 million, compared to a $64 million gain, after tax, in the first quarter of 2009 and a $56 million decrease in Depreciation, depletion and amortization (“DD&A”) expense in the first quarter of 2010 compared to the same period in 2009. These increases to Net Earnings were offset by future income tax expense, excluding the impact of the unrealized financial hedging gains, in the first quarter of 2010 of $33 million, compared to a future income tax recovery of $46 million for the same period in 2009 and an unrealized foreign exchange gain of $32 million in the first quarter of 2010 compared to a gain in the first quarter of 2009 of $53 million.

As a means of managing the volatility of commodity prices, we enter into various financial instrument agreements. Changes in the mark-to-market gain or loss on these agreements affect our Net Earnings and are the result of volatility in the forward commodity prices and changes in the balance of unsettled contracts. The first quarter of both 2010 and 2009 benefitted overall from our hedging program. The following information has been provided in order to provide information that is more comparable between periods:

Three Months Ended March 31,
(millions of Canadian dollars)	2010		2009
Unrealized Mark-to-Market Gains (Losses), after-tax (1)	$	170	$	64
Realized Hedging Gains (Losses), after-tax (2)	17		198
Hedging Impacts in Net Earnings	$	187	$	262

(1)  Included in Corporate and Eliminations financial results. Further detail on unrealized mark-to-market gains (losses) can be found in the Corporate and Eliminations section of this MD&A.

(2)  Included in Divisional financial results.

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NET CAPITAL INVESTMENT

Three Months Ended March 31,
(millions of Canadian dollars)	2010			2009
Integrated Oil - Upstream	$	151		$	155
Canadian Plains	139			235
Downstream Refining	202			252
Other	1			10
Capital Investment	493			652
Divestitures	(72		)	-
Net Capital Investment	$	421		$	652

Upstream capital investment in the first quarter of 2010 was primarily focused on the continued development of our EOR properties (Foster Creek, Christina Lake, Pelican Lake and Weyburn), including the drilling of stratigraphic wells to support the next phases of our expansion activities. Downstream capital investment is primarily related to the expansion of our heavy oil refining capacity. Capital investment for the first quarter of 2010 and 2009 was funded by Cash Flow. Further information regarding our capital investment can be found in the Divisional Results section of this MD&A.

Acquisitions and Divestitures

In the first quarter of 2010, Cenovus sold certain wholly owned lands at the Narrows Lake property to the FCCL Partnership resulting in net proceeds of $72 million. Our working interest in Narrows Lake has been reduced to 50 percent.

FREE CASH FLOW

In order to determine the funds available for financing and investing activities, including dividend payments, we use a non-GAAP measure of Free 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 is defined under the Cash Flow section of this MD&A.

In the first quarter of 2010, our Free Cash Flow was $228 million, which was $139 million higher than our Free Cash Flow of $89 million for the same period in 2009 primarily due to decreased capital investment offset slightly by lower cash flow. Additional explanations for the decrease in total Cash Flow and Capital Investment are discussed under the Cash Flow, Net Capital Investment and Divisional Results sections of this MD&A.

Three months ended March 31,
(millions of Canadian dollars)	2010		2009
Cash Flow	$	721	$	741
Capital Investment		493		652
Free Cash Flow	$	228	$	89

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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RESULTS OF OPERATIONS

Crude Oil and NGLs Production Volumes

	2010	2009				2008
(bbls/d)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Crude Oil
Foster Creek	51,126	47,017	40,367	34,729	28,554	29,241	27,289	21,244	27,062
Christina Lake	7,420	7,319	6,305	6,530	6,635	6,170	4,620	3,670	2,630
Weyburn	17,722	18,536	18,354	18,368	18,028	17,408	17,634	17,178	17,985
Pelican Lake	23,565	23,804	25,671	23,989	26,029	24,975	27,826	27,306	29,211
Southern Alberta	23,790	23,729	23,895	24,089	25,404	25,509	25,654	27,041	28,348
Canadian Plains – Other	5,770	5,506	5,573	5,806	5,862	6,090	6,166	6,470	6,760
Integrated Oil – Senlac	-	2,221	5,080	2,574	2,334	2,623	3,135	3,281	3,861
NGLs	1,156	1,183	1,242	1,184	1,213	1,158	1,167	1,204	1,283
	130,549	129,315	126,487	117,269	114,059	113,174	113,491	107,394	117,140

Production volumes at Foster Creek and Christina Lake increased in the first quarter of 2010 compared to 2009 primarily as a result of the ramp up of new expansion phases and well optimizations. Weyburn production decreased slightly from the first quarter of 2009 to 2010 as a result of expected natural declines exceeding increases from well optimization programs. The decrease in production at Pelican Lake for the first quarter of 2010 compared to 2009 was a result of expected natural declines and treating problems. Crude oil production from Southern Alberta decreased in the first quarter of 2010 compared to 2009 due to expected natural declines and production downtime partially offset by increased production from new wells. In the fourth quarter of 2009, we sold our Senlac heavy oil assets.

Natural Gas Production Volumes

	2010	2009				2008
(MMcf/d)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Southern Alberta	699	719	741	761	777	803	815	838	843
Canadian Plains – Other	34	34	37	41	39	40	44	48	43
Integrated Oil – Other	42	44	52	54	50	62	88	99	90
	775	797	830	856	866	905	947	985	976

The decline in Southern Alberta natural gas production in the first quarter of 2010 compared to the first quarter of 2009 was the result of expected natural production declines, the effect of lower capital spending on natural gas drilling and tie-in activity throughout 2009 as well as weather related drilling delays in the first quarter of 2010.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Operating Netbacks

	Three Months Ended March 31,
	2010			2009
	Liquids		Natural Gas	Liquids	Natural Gas
	($/bbl)		($/Mcf)	($/bbl)	($/Mcf)
Price	$      68.85		$    5.27	$    39.45	$      5.47
Royalties	8.78		0.14	3.00	0.15
Production and mineral taxes	0.59		0.07	0.94	0.05
Transportation and selling	1.83		0.21	1.69	0.18
Operating expenses	11.42		0.94	11.69	0.94
Netback excluding Realized Financial Hedging	46.23		3.91	22.13	4.15
Realized Financial Hedging Gain (Loss)	(0.78	)	0.53	3.29	3.43
Netback including Realized Financial Hedging	$      45.45		$    4.44	$    25.42	$      7.58

When compared to the first quarter of 2009, our 2010 first quarter average netback for liquids, excluding realized financial hedging, increased by $24.10 per bbl while our netback for natural gas, excluding realized financial hedging, was lower by $0.24 per Mcf. These movements were consistent with the changes in the benchmark prices between the quarters.

As part of ongoing efforts to maintain financial resilience and flexibility, we reduced our pricing risk through a commodity price hedging program. In the first quarter of 2010, our hedging program reduced our liquids netback by $0.78 per bbl while our natural gas hedging added $0.53 per Mcf. Further information regarding this program can be found in the notes to the Interim Consolidated Financial Statements.

DIVISIONAL RESULTS

Our Upstream Canada segment includes the upstream activities of the Integrated Oil Division and the Canadian Plains Division. Our Downstream Refining segment includes the Downstream Refining business of the Integrated Oil Division.

INTEGRATED OIL DIVISION

We are a 50 percent partner in an integrated North American oil business with ConocoPhillips that consists of an upstream and a downstream entity. The upstream entity includes the Foster Creek and Christina Lake oil properties in northeast Alberta, while the downstream entity includes the Wood River and Borger refineries located in Illinois and Texas, USA, respectively.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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FOSTER CREEK AND CHRISTINA LAKE

Financial Results

	Three months ended March 31,
(millions of Canadian dollars)	2010	2009
Revenues	$      520	$      176
Deduct (add)
Realized financial hedging (gain) loss	5	(29	)
Royalties	27	1
Net revenues	488	204
Expenses
Transportation and selling	213	83
Operating	60	50
Operating Cash Flow	$      215	$      71

Production Volumes

	Three Months Ended March 31,
Heavy Crude Oil (bbls/d)	2010	2010 vs 2009	2009
Foster Creek	51,126	79%	28,554
Christina Lake	7,420	12%	6,635
	58,546	66%	35,189

Production Volumes by Quarter

Net Revenues Variance

	Three Months Ended March 31,					Three Months Ended March
	2009	Revenue Variances in:				31, 2010
(millions of Canadian dollars)	Revenues, Net of Royalties	Price(1)	Volume	Royalties	Other(2)	Revenues, Net of Royalties
Foster Creek and Christina Lake	$             204	117	68	(26)	125	$               488

(1)   Includes the impact of realized financial hedging.

(2)   Revenue dollars reported include the value of condensate sold as bitumen blend. Condensate costs are recorded in transportation and selling expense.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Our average crude oil sales price, excluding realized financial hedges, increased 90 percent to $63.19 per bbl in the first quarter of 2010 from $33.26 per bbl in the first quarter of 2009 primarily due to the price of WCS more than doubling year over year. During the first quarter of 2010, financial hedging activities resulted in a realized loss of $5 million ($0.99 per bbl) compared to a gain of $29 million ($9.65 per bbl) in the first quarter of 2009.

Production at Foster Creek increased 79 percent in the first quarter of 2010 compared to the same period in 2009 as the first quarter of 2010 included production from the phase D/E expansion which commenced production late in the first quarter of 2009, combined with well optimizations and increased production from wedge wells.

Production at Christina Lake increased 12 percent in the first quarter of 2010 compared to the first quarter of 2009 as a result of the ramp up of production from the phase B expansion and well optimizations.

Royalties in the first quarter of 2010 increased by $26 million compared to the same period in 2009 with Foster Creek achieving royalty payout status in the first quarter of 2010 and increased WTI prices resulting in higher royalty rates. For the first quarter of 2010, the average royalty rate for Foster Creek was 9.7 percent compared to 1.4 percent in the first quarter of 2009. For Christina Lake, the royalty rate was 4.0 percent in the first quarter of 2010 compared to 1.0 percent for the same period in 2009.

Transportation and selling costs are comprised mostly of condensate costs, as blending condensate with bitumen enables the product to be transported. In the first quarter of 2010, our condensate volumes increased directly due to the higher production noted above. Our condensate costs were also higher due to a 55 percent increase in the average price of condensate. This resulted in transportation and selling costs increasing to $213 million in the first quarter of 2010 from $83 million in the first quarter of 2009.

In the first quarter of 2010, operating costs increased to $60 million compared to $50 million in the first quarter of 2009 due to increased purchased fuel volumes and chemical costs as a result of the higher production.

DOWNSTREAM REFINING

Financial Results

	Three Months Ended March 31			,
(millions of Canadian dollars)	2010		2009
Revenues	$         1,518		$         1,154
Expenses
Operating	139		147
Purchased product	1,385		934
Operating Cash Flow	$               (6	)	$               73

Refinery Operations (1)

	Three Months Ended March 31		,
	2010	2009
Crude oil capacity (Mbbls/d)	452	452
Crude oil runs (Mbbls/d)	355	398
Crude utilization (%)	79	88
Refined products (Mbbls/d)	377	421

(1) Represents 100% of the Wood River and Borger refinery operations.

On a 100 percent basis, our refineries have a current capacity of approximately 452,000 bbls/d of crude oil and 45,000 bbls/d of NGLs, including processing capability to refine approximately 145,000 bbls/d of

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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heavy crude oil. Upon completion of the Wood River coker and refinery expansion project (“CORE”) in 2011 we expect to be able to refine approximately 275,000 bbls/d (on a 100 percent basis) of heavy crude oil (approximately 150,000 bbls/d of bitumen equivalent) primarily into motor fuels.

In the first quarter of 2010, our refineries operated at an average of 79 percent of their capacity compared to 88 percent in the same period in 2009. Utilization was lower in the first quarter of 2010 primarily due to a turnaround at the Wood River refinery and refinery optimization as a result of weaker market crack spreads.

Revenues increased 32 percent and purchased product costs increased 48 percent in the first quarter of 2010 compared to the same period of 2009, consistent with the increase in crude oil prices. Purchased product, consisting mainly of crude oil, represented 91 percent of total expenses in the first quarter of 2010 compared to 86 percent in the first quarter of 2009.

Operating costs, consisting mainly of labour, utilities and supplies, decreased five percent in 2010 due to a strengthened average Canadian dollar exchange rate offset by higher prices for electricity and fuel gas consumed at the refineries.

Operating Cash Flow for the first quarter of 2010 was $79 million lower than the first quarter of 2009 mainly due to increased crude oil purchased product costs more than offsetting higher refined product sales prices. The decrease in Operating Cash Flow also reflected the impact of the lower refinery utilization.

INTEGRATED OIL DIVISION - OTHER PROPERTIES

The Integrated Oil Division also manages our 100 percent owned natural gas operations in Athabasca. For the first quarter of 2010, natural gas production volumes from Athabasca decreased to 42 MMcf/d (2009 – 50 MMcf/d) primarily as a result of natural declines.

In the fourth quarter of 2009, we sold our Senlac heavy oil assets. Senlac production in the first quarter of 2009 was 2,334 bbls/d.

INTEGRATED OIL DIVISION - CAPITAL INVESTMENT

	Three Months Ended March 31,
(millions of Canadian dollars)	2010	2009
Upstream
Foster Creek	$           57	$           65
Christina Lake	63	56
Other	31	34
	151	155
Downstream Refining
Wood River	180	231
Borger	22	21
	202	252
Total Integrated Oil Division	$          353	$          407

Our Upstream capital investment in the first quarter of 2010 was primarily focused on the continued development of the next phases of the Foster Creek and Christina Lake properties. Our current plan is to increase production capacity at Foster Creek and Christina Lake to approximately 218,000 bbls/d of bitumen with the completion of Christina Lake phase C in 2011 and phase D in 2013. Foster Creek capital investment in the first quarter of 2010 is slightly lower as we await regulatory approvals for the next phases of expansion.  The majority of Foster Creek spending is related to maintenance capital and drilling of SAGD well pairs and stratigraphic test wells. At Christina Lake capital investment was higher in the first quarter of 2010 with increased spending on the phase C expansion and drilling of more SAGD well pairs and stratigraphic test wells. We have chosen to accelerate completion of Christina Lake phase D which we expect will advance start up by approximately six months.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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During the first quarter of 2010, 97 net stratigraphic test wells were drilled compared to 47 wells for the same period in 2009.  The stratigraphic test wells drilled at Foster Creek and Christina Lake (2010 - 53 net wells; 2009 - 47 net wells) are to support the next phases of expansion while the wells drilled at Narrows Lake, Borealis and emerging plays (2010 - 44 net wells; 2009 - none) are drilled to assess the quality of bitumen assets and to support regulatory applications for project approval.

Our Downstream Refining capital investment in the first quarter of 2010 continued to focus on the CORE project at the Wood River refinery. Of the $180 million capital expenditures at Wood River, $155 million was related to the CORE project. The CORE project is approximately 77 percent complete and is anticipated to be completed and in operation mid-year 2011. The expansion is expected to increase crude oil refining capacity by 50,000 bbls/d to 356,000 bbls/d and more than double heavy crude oil refining capacity at Wood River to 240,000 bbls/d. The remainder of the Wood River and Borger capital expenditures in the first quarter of 2010 were related to capital maintenance and environmental projects.

CANADIAN PLAINS DIVISION

Crude Oil and NGLs

Financial Results

	Three Months Ended March 31,
(millions of Canadian dollars)	2010	2009
Revenues	$         530	$         340
Deduct (add)
Realized financial hedging (gain) loss	4	(3	)
Royalties	74	29
Net revenues	452	314
Expenses
Production and mineral taxes	7	9
Transportation and selling	64	63
Operating	72	63
Operating Cash Flow	$         309	$         179

Production Volumes

	Three Months Ended March 31,
(bbls/d)	2010	2010 vs 2009	2009
Heavy Oil
Pelican Lake	23,565	-9%	26,029
Southern Alberta	13,291	-11%	14,994
Light and Medium Oil
Weyburn	17,722	-2%	18,028
Southern Alberta	10,499	1%	10,410
Other	5,770	-2%	5,862
NGLs	1,156	-5%	1,213
	72,003	-6%	76,536

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Net Revenues Variance

(1) Includes the impact of realized financial hedging.

(2) Revenue dollars reported include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and selling expense.

The average crude oil and NGLs sales price, excluding realized hedging, increased 73 percent to $73.30 per bbl in the first quarter of 2010 from $42.41 per bbl in the first quarter of 2009, consistent with changes in the benchmark crude oil prices. During the first quarter of 2010, crude oil realized financial hedging losses were $4 million ($0.61 per bbl) compared to gains of $3 million ($0.45 per bbl) in the first quarter of 2009.

Production volumes at Weyburn were two percent lower in the first quarter of 2010 compared to the first quarter of 2009 as expected natural declines exceeded volume increases from well optimization programs. At Pelican Lake, volumes were nine percent lower in the first quarter of 2010 compared to the same period in 2009 mainly due to expected natural declines and treating problems. Southern Alberta oil production was down six percent when compared to the same period in the prior year primarily due to expected natural declines and production downtime, partially offset by increased production from new wells.

Royalties in the first quarter of 2010 of $74 million were $45 million higher than the same period in 2009 as a result of higher sales prices. The average crude oil royalty rate in the first quarter of 2010 was 16.6 percent (2009 - 10.5 percent).

Production and mineral taxes in the first quarter of 2010 were consistent with the first quarter of 2009.

Transportation and selling costs in the first quarter of 2010 were consistent with the same period in 2009 as the 27 percent increase in the average price of condensate was offset by a 20 percent decrease in the volume of condensate used for blending with heavy oil.

Operating costs increased to $72 million in the first quarter of 2010 from $63 million in the first quarter of 2009 as result of higher chemical usage, increased repairs and maintenance and workover costs, which were partially offset by lower electricity prices. NGLs are a byproduct obtained through the production of natural gas and therefore operating costs associated with the production of NGLs are included with natural gas.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Natural Gas

Financial Results

	Three Months Ended March 31,
(millions of Canadian dollars)	2010		2009
Revenues	$         348		$         403
Deduct (add)
Realized financial hedging (gain) loss	(34	)	(253	)
Royalties	6		8
Net revenues	376		648
Expenses
Production and mineral taxes	5		4
Transportation and selling	14		13
Operating	59		64
Operating Cash Flow	$         298		$         567

Production Volumes

	Three Months Ended March 31,
(MMcf/d)	2010	2010 vs 2009	2009
Natural Gas
Southern Alberta	699	-10%	777
Other	34	-13%	39
	733	-10%	816

Net Revenues Variance

(1) Includes the impact of realized financial hedging.

The decrease in the average natural gas price, excluding realized financial hedges, to $5.28 per Mcf in the first quarter of 2010 from $5.50 per Mcf in the first quarter of 2009 was consistent with the reduction in the benchmark AECO price. For the first three months of 2010, our realized financial hedging gain of $34 million ($0.52 per Mcf) was $219 million lower than our gain of $253 million ($3.44 per Mcf) for the same period in 2009. The decrease in our realized hedging gains is the result of our settled fixed price contract prices of $6.18 per Mcf in the first quarter of 2010 being approximately $3.00 per Mcf lower than the same period in 2009. For details of the specific pricing on our hedging program, see the notes to our Interim Consolidated Financial statements.

Production volumes for Southern Alberta decreased 10 percent in the first quarter of 2010 compared to the same period in 2009 due to expected natural declines, lower drilling and tie-in activity throughout 2009 in response to low commodity prices and weather related drilling and completion delays in the first quarter of 2010.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Royalties for the first quarter of 2010 decreased by $2 million on lower volumes. The average royalty rate for the first quarter of 2010 was 1.8 percent (2009 – 2.0 percent).

Production and mineral taxes and transportation and selling costs in the first quarter of 2010 were consistent with the same period in 2009.

Operating expenses in the first quarter of 2010 decreased to $59 million from $64 million in the first quarter of 2009 mostly as a result of a lower level of repairs and maintenance and workovers, as well as lower salaries and lower prices for electricity.

Canadian Plains - Other

Financial Results

	Three Months Ended March 31,
(millions of Canadian dollars)	2010	2009
Revenues	$         415	$         231
Expenses
Operating	5	5
Purchased product	404	218
Operating Cash Flow	$             6	$             8

The Canadian Plains Division markets all of our crude oil and natural gas, including third party purchases and sales of product, in order to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification. The significant increase in both revenues and purchased product expenses for the first three months of 2010 compared to 2009 is largely the result of increased volumes and higher crude oil prices. Canadian Plains – Other also includes a small amount of third party processing fee income.

Capital Investment

Canadian Plains capital investment in the first quarter of 2010 was $139 million (2009 - $235 million). The $96 million decrease from the first quarter of 2009 was primarily the result of management’s decision to reduce capital investment in natural gas assets in response to lower commodity prices. In addition, winter weather and an early spring thaw resulted in the deferral of some planned investment to later in 2010. The Canadian Plains Division drilled 122 net production wells in the first quarter of 2010 compared to 375 net production wells in the same period in 2009. To further develop the Pelican Lake Grand Rapids region, we drilled 31 stratigraphic wells (2009 – 17 stratigraphic wells) in the first three months of 2010.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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CORPORATE AND ELIMINATIONS

Financial Results

	Three Months Ended March 31,
(millions of Canadian dollars)	2010			2009
Revenues	$	217		$	89
Expenses
Operating	4			19
Purchased product	(24		)	(16		)
Depreciation, depletion and amortization	8			13
General and administrative	52			41
Interest, net	65			45
Accretion of asset retirement obligation	22			11
Foreign exchange (gain) loss, net	(27		)	(52		)
(Gain) loss on divestitures	(1		)	-
Segment Income (Loss)	$	118		$	28

The Corporate and Eliminations segment includes revenues that represent the unrealized mark-to-market gains or losses related to derivative financial instruments used to mitigate fluctuations in commodity prices. The segment also includes inter-segment eliminations that relate to transactions that have been recorded at transfer prices based on current market prices as well as unrealized intersegment profits in inventory. Operating expenses primarily relate to mark-to-market gains and losses on long-term power purchase contracts and downstream crude oil supply positions. DD&A includes provisions in respect of corporate assets, such as computer equipment, office furniture and leasehold improvements.

Our General and administrative expenses increased $11 million in the first quarter of 2010 compared to the same period of 2009 primarily because of higher salaries and benefits related to being an independent company.

Net interest in the first quarter of 2010 was $65 million, which was $20 million higher than the first quarter of 2009.  The increase is primarily a result of a higher average interest rate and higher average outstanding debt in 2010 compared to the proportionate share of Encana’s debt allocated to Cenovus for the first quarter of 2009, as well as the amortization of $4 million of financing costs during the first quarter of 2010 related to the setup of our debt financing programs. Our weighted average interest rate on outstanding debt at March 31, 2010 was 5.8 percent compared to 5.2 percent at March 31, 2009.

We reported a foreign exchange gain of $27 million in the first quarter of 2010 compared to a gain of $52 million in the first quarter of 2009, the majority of which was unrealized.  The strengthening of the Canadian dollar during the first quarter of 2010 led to an unrealized gain on our U.S. dollar debt, which was partially offset by an unrealized loss on our U.S. dollar partnership contribution receivable.

Depreciation, Depletion and Amortization

In the first quarter of 2010, DD&A was $324 million compared to $380 million in the first quarter of 2009. We use full cost accounting for our upstream oil and gas activities and calculate DD&A on a country-by-country cost centre basis. Upstream DD&A of $265 million for the first quarter of 2010 was $39 million lower than the 2009 first quarter DD&A of $304 million, primarily as a result of a lower DD&A rate partially offset by increased production volumes. In the first quarter of 2010, DD&A on our Downstream Refining assets was $51 million, which was $12 million lower than the first quarter of 2009 DD&A of $63 million, primarily due to a strengthening of the Canadian dollar average exchange rate.

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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Income Tax

The total 2010 first quarter income tax expense was $115 million, which was $41 million higher than the same period in 2009. Current income tax expense in the first quarter of 2010 was $15 million compared to $98 million in the first quarter of 2009, and future tax expense was $100 million compared to a recovery of $24 million for 2009.

When comparing the first quarter of 2010 to 2009, our current tax expense declined and our future tax expense increased primarily due to our ability to accelerate certain tax deductions that we received as a result of the Arrangement.

For the three months ended March 31, 2010, our effective tax rate was 18.0 percent compared to 12.6 percent for the same period in 2009. The increase is primarily due to an increase in unrealized foreign exchange gains and a reduction in international financing costs.

It should be noted that the first quarter 2009 income tax expense was calculated as if Cenovus and its subsidiaries had been separate tax paying legal entities, each filing a separate tax return in its local jurisdiction, and that the calculation was based on a number of assumptions, allocations and estimates.

Our effective tax rate in any year is a function of the relationship between total tax expense and the amount of earnings before income taxes for the year. The effective tax rate differs from the statutory tax rate as it takes into consideration permanent differences, adjustments for changes in tax rates and other tax legislation, variation in the estimate of reserves and the differences between the provision and the actual amounts subsequently reported on the tax returns. Permanent differences include:

·      The non-taxable portion of Canadian capital gains and losses;

·      International financing; and

·      Foreign exchange (gains) losses not included in Net Earnings.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change.  As a result, there are usually some tax matters under review.  We believe that our provision for taxes is adequate.

Summary of Unrealized Mark-to-Market Gains (Losses)

The volatility of commodity prices has a significant impact on our Net Earnings, and as a means of managing this volatility, we enter into various financial instrument agreements. The financial instrument agreements were recorded at the date of the financial statements based on mark-to-market accounting. Changes in the mark-to-market gain or loss reflected in corporate revenues are the result of volatility between periods in the forward commodity prices and changes in the balance of unsettled contracts. The table below provides a summary of the unrealized mark-to-market gains and losses recognized for each year. Additional information regarding financial instrument agreements can be found in the notes to the Interim Consolidated Financial Statements.

	Three Months Ended March 31,
(millions of Canadian dollars)	2010		2009
Revenues
Crude Oil	$            (2	)	$           (31	)
Natural Gas	243		136
	241		105
Expenses	4		19
	237		86
Income Tax Expense (Recovery)	67		22
Unrealized Mark-to-Market Gains (Losses), after tax	$          170		$            64

Cenovus Energy Inc. Management’s Discussion and Analysis (prepared in Canadian Dollars)

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LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended March 31,
(millions of Canadian dollars)	2010			2009
Net cash from (used in)
Operating activities	$	820		$	682
Investing activities	(372		)	(718		)
Net cash provided (used) before Financing activities	448			(36		)
Financing activities	(203		)	111
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency	(3		)	(2		)
Increase (decrease) in cash and cash equivalents	$	242		$	73

OPERATING ACTIVITIES

Net cash from operating activities increased to $820 million in the first quarter of 2010 compared to $682 million in the first quarter of 2009. Cash Flow was $721 million during the first quarter of 2010 compared to $741 million for the same period in 2009. Reasons for this change are discussed under the Cash Flow section of this MD&A. Cash from operating activities was also impacted by net changes in other assets and liabilities and net changes in non-cash working capital, primarily from increases in accounts payable and accrued liabilities, decreased inventories and current income taxes receivable partially offset by increases in accounts receivable and accrued revenues.

Excluding the impact of risk management assets and liabilities, we had working capital of $538 million at March 31, 2010 compared to working capital of $479 million at December 31, 2009. We anticipate that we will continue to meet the payment terms of our suppliers.

INVESTING ACTIVITIES

Net cash used for investing activities in the first three months of 2010 decreased to $372 million from $718 million for the same period in 2009. Capital expenditures decreased in the first quarter of 2010 to $493 million compared to $652 million in the first quarter of 2009. The first quarter of 2010 also included a divestiture for proceeds of $72 million. The net change in non-cash working capital increased cash by $114 million in the first quarter of 2010 compared to the same period in 2009. The decreased capital expenditures are discussed under the Net Capital Investment and Divisional Results sections of this MD&A.

FINANCING ACTIVITIES

We currently have in place an unsecured credit facility in the amount of $2.5 billion or its equivalent amount in U.S. dollars. The revolving syndicated credit facility consists of two tranches, a $2.0 billion 3-year tranche and a $500 million 364-day tranche. At March 31, 2010, no amounts were drawn on the credit facility. We are currently in compliance with all of our financial covenants under this credit facility.

We declared and paid dividends of $150 million ($0.20 per share) in the first quarter of 2010. Dividends are at the sole discretion of the Board and considered quarterly.

Net cash used in financing activities for the first quarter of 2010 was $203 million. Our debt, including current portion, was $3,494 million as at March 31, 2010 compared with $3,656 million as at December 31, 2009.

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FINANCIAL METRICS

	March 31,	December 31,
	2010	2009
Debt to Capitalization	26%	28%
Debt to Adjusted EBITDA (times)	1.0x	1.1x

Cenovus monitors its capital structure and short-term financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. Capitalization is a non-GAAP measure defined as long-term debt including current portion plus Shareholders’ Equity. Trailing 12-month Adjusted EBITDA is a non-GAAP measure defined as Adjusted Earnings before Interest, Income Taxes, DD&A, Accretion of asset retirement obligations and foreign exchange gains/losses. These metrics are used to steward Cenovus’s capital structure.  Debt is defined as the current and long-term portions of long-term debt.

We target a Debt to Capitalization ratio of between 30 to 40 percent and a Debt to Adjusted EBITDA of between 1.0 to 2.0 times.

OUTSTANDING SHARE DATA

Cenovus is authorized to issue an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. There were no first preferred shares or second preferred shares outstanding as at March 31, 2010. As at March 31, 2010, 751.7 million common shares were outstanding.

During the first quarter of 2010, Cenovus issued 1.3 million Performance Share Units (“PSUs”) to its employees. PSUs are whole share units and entitle the employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible for payment is determined over three years based on the units granted multiplied by 30 percent after year one, 30 percent after year two and 40 percent after year three, multiplied by a performance multiplier for each year. The multiplier is based on the Company achieving key pre-determined performance measures including the recycle ratio. The recycle ratio is calculated as the ratio of our Netback compared to our Finding & Development Costs. We believe that the recycle ratio is the key measure of total “value added”, as it measures our ability to generate operating cash flow in excess of the costs of adding reserves. PSUs vest after three years.

Further information can be found in the notes to the Interim Consolidated Financial Statements.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Cenovus has entered into various commitments in the normal course of operations primarily related to debt, demand charges on firm transportation agreements, building leases, capital commitments and marketing agreements. The Company’s long-term debt of $3,494 million at March 31, 2010 did not include any obligations on the unsecured credit facilities as there was nothing outstanding under this facility. The Company expects its 2010 commitments to be funded from Cash Flow.

LEGAL PROCEEDINGS

We are involved in various legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims.

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RISK MANAGEMENT

Our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, are impacted by risks that are categorized as follows:

·Financial risks including market risks (such as commodity price, foreign exchange and interest rates), credit and liquidity risks;

·Operational risks including capital, operating and reserves replacement risks; and

·Safety, environmental and regulatory risks.

We are committed to identifying and managing these risks in the near-term as well as on a strategic and longer term basis at all levels in the organization in accordance with our Board approved Corporate Risk Management Policy and risk management programs. Issues affecting, or with the potential to affect, our assets, operations and/or reputation, are generally of a strategic nature or emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. We take a proactive approach to the identification and management of issues that can affect our assets, operations and/or reputation and have established consistent and clear policies, procedures, guidelines and responsibilities for identifying and managing these issues.

For a description of risk factors that may affect our performance, see the Advisory section at the end of this document.

CLIMATE CHANGE

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (“GHG”) emissions and other air pollutants and a number of legislative and regulatory measures to address GHG emissions are in various phases of review, discussion or implementation in the United States and Canada. These include proposed federal legislation and state actions in the United States to develop statewide or regional programs, each of which could impose reductions in GHG emissions.  While some jurisdictions have provided details on these regulations, it is anticipated that other jurisdictions will announce emission reduction plans in the future.  Adverse impacts to our business if comprehensive GHG legislation is enacted in any jurisdiction in which we operate may include, among other things, increased compliance costs, permitting delays, substantial costs to generate or purchase emission credits or allowances adding costs to the products we produce and reduced demand for crude oil and certain refined products.

Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any of these additional programs cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for compliance.  We intend to continue our activity to reduce our emissions intensity and improve our energy efficiency. We will also continue to work with governments to develop an approach to deal with climate change issues that protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector.

The Alberta government has set targets for GHG emissions reductions. In March 2007, regulations were amended to require facilities that emit more than 100,000 tonnes of GHG emissions per year to reduce their emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. To comply, companies can make operating improvements, purchase carbon offsets (or emission performance credits) or make a C$15 per tonne contribution to an Alberta Climate Change and Emissions Management Fund. We currently have three facilities subject to this regulation and have reported performance against our targets in March 2010. For the 2009 compliance year, we did not incur material costs in this regard.

The American Clean Energy and Security 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 of the climate change bills being contemplated in the U.S. would require refiners to purchase credits equivalent to the CO2 emissions

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from both their refineries and from consumer emissions. If this approach was enacted into law, it could have a material impact on the cost structure of refined petroleum products.

Our efforts with respect to emissions management are founded in our industry leadership in CO2 sequestration, a focus on energy efficiency and the development of technology to reduce GHG emissions.  In particular, our industry leading steam to oil ratio at Foster Creek and Christina Lake translates directly into lower emissions intensity.  Given the uncertainty in North American carbon legislation, our strategy for addressing the implications of emerging carbon regulations is proactive and is composed of three principal elements:

1.Manage Existing Costs

When regulations are implemented, a cost is placed on our emissions (or a portion thereof) and while these are not material at this stage, they are being actively managed to ensure compliance.  Factors such as effective emissions tracking, attention to fuel consumption and a focus on minimizing our steam to oil ratio help to support and drive our focus on cost reduction.

2.Respond to Price Signals

As regulatory 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 to improve the energy efficiency of our operations.  The price of potential carbon reductions plays a role in the economics of the projects that are implemented. In response to the anticipated price of carbon reduction, we are also attempting, where appropriate, to realize the associated value of our reduction projects.

3.Anticipate Future Carbon Constrained Scenarios

We continue to work with governments, academics and industry leaders to develop and respond to emerging GHG regulations.  By continuing to stay engaged in the debate on the most appropriate means to regulate these emissions, we gain useful knowledge that allows us to explore different strategies for managing our emissions and costs.  These scenarios inform our long range planning 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 constrained scenarios on our strategy, with a current price range from $15 to $65 per tonne of emissions applied to a range of emissions coverage levels. A major benefit of applying a range of carbon prices at the strategic level is that it provides direct guidance to the capital allocation process.  We also examine the impact of carbon regulation on our major projects. Although uncertainty remains regarding potential future emissions regulation, our plan is to continue to assess and evaluate the cost of carbon relative to our investments across a range of scenarios.

We recognize that there is a cost associated with carbon emissions. We are confident that GHG regulations and the cost of carbon at various price levels have been adequately accounted for as part of our business planning and scenarios analysis. We believe that our development strategy is an effective way to develop the resource, generate shareholder returns and coordinate overall environmental objectives with respect to carbon, air emissions, water and land. We are committed to transparency with our stakeholders and will keep them apprised of how these issues affect operations.

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner which maintains and enhances our reputation and credibility.  A central aspect of this commitment involves engagement with our various stakeholders, including shareholders and other investors, financial institutions, employees, business partners, communities, Aboriginal peoples, governments and non-governmental organizations. We will continue to disclose information about our business activities to our stakeholders in a timely and transparent manner to maintain and advance our reputation as a responsible operator, as well as to develop trust with our stakeholders. We disclose information that is not only required by law and/or regulation, but also additional information that management regards as important to help stakeholders understand our activities, policies, opportunities and risks. Our engagement with stakeholders also allows us to determine how they are each affected by our business. Feedback that we receive from stakeholders enables us to better identify and manage our environmental and socio-economic risks.

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We are continuing to review our existing Corporate Responsibility (“CR”) policy to ensure that it not only continues to drive our commitments, strategy and reporting, but also that it maintains alignment with our business objectives and processes. Our reporting process will focus on improving performance through better data management, stakeholder engagement and continuous improvement. Our approach in this first year is to communicate our key performance indicators using the Cenovus website as the main reporting vehicle.

As our CR reporting process matures, additional indicators will be developed that better reflect Cenovus’s operations and challenges. These indicators will be integrated into our CR reporting and will expand our online presence through our website.

We are committed to integrating the principles of corporate responsibility into the way we conduct our business across all of our operations and we recognize the importance of reporting to stakeholders in a transparent and accountable way.

ALBERTA’S ROYALTY/REGULATORY FRAMEWORK

On March 11, 2010, the Alberta government released its “Energizing Investment” report which outlined changes to the Alberta royalty structure and include:

· A five percent maximum royalty rate on new gas and conventional oil wells for a period of 12 months or 0.5 billion cubic feet equivalent for gas wells or 50,000 barrels of oil equivalent for oil wells, whichever comes first. The five percent royalty rate was originally created with the New Well Incentive under the Energy Incentive Program that was released on March 3, 2009 and was set to expire on March 31, 2011;

· The maximum royalty rate for conventional oil will decrease to 40 percent from 50 percent and the maximum natural gas royalty rate will decrease to 36 percent from 50 percent; and

· Effective January 1, 2011 no additional wells will be allowed under the Transitional Royalty Program (“TRP”) that went into effect on January 1, 2009. The TRP allows for a one time option of selecting transitional royalty rates on new natural gas or conventional oil wells drilled between 1,000 to 3,500 meters in depth. Any wells that are elected under the TRP can continue to use this program until December 31, 2013.

We are encouraged by the tone of the message and the early information that has been released by the Alberta government. The impact of the proposed new royalty framework on our financial results will be better understood once the updated royalty curves are released, which are expected in the second quarter of 2010. The effective date of the changes is January 1, 2011.

The Government of Alberta has also formed the “Task Force on Regulatory Enhancement” with a mandate to perform a comprehensive review of Alberta’s regulatory system for resource development. By working with the oil and gas industry and other stakeholders, the task force has been asked to look for efficiencies and ensure Alberta’s competitive balance while maintaining environmental conservation and stewardship. A progress report is due to be released in the second quarter of 2010.

ACCOUNTING POLICIES AND ESTIMATES

Basis of Presentation

Our results for the three month period from January 1 to March 31, 2010 and the one month period from December 1 to December 31, 2009 represent our operations, cash flows and financial position as a stand-alone entity.

Our results for the periods prior to the Arrangement, being January 1 to November 30, 2009 as well as 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 accounting records of Encana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. The historical consolidated financial statements include allocations of certain Encana expenses, assets and

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liabilities.  In the opinion of Management, the consolidated and the historical carve-out consolidated financial statements reflect all adjustments necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian GAAP.

The presentation of financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the assumptions underlying the historical consolidated financial statements are reasonable.  However, as we 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 not necessarily reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

Further information can be found in the notes to the Interim Consolidated Financial Statements.

NEW ACCOUNTING STANDARDS ADOPTED

On January 1, 2010, Cenovus early adopted CICA Handbook Section 1582, “Business Combinations,” which replaces CICA Handbook Section 1581 of the same name.  The new standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition.  In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the Statement of Earnings.  The adoption of this standard did not impact the Company’s Interim Consolidated Financial Statements for the period ended March 31, 2010.  However, the adoption of this new standard will impact the accounting treatment of future business combinations.

In conjunction with the early adoption of CICA Handbook Section 1582, the Company was also required to early adopt CICA Handbook Sections 1601, “Consolidated Financial Statements” and 1602, “Non-controlling Interests” effective January 1, 2010.  These sections replace the former consolidated financial statement standard, CICA Handbook Section 1600, “Consolidated Financial Statements.”  Section 1601 establishes the requirements for the preparation of the consolidated financial statements and Section 1602 establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination.  Section 1602 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 early adoption of these standards did not have a material impact on the Company’s Interim Consolidated Financial Statements for the period ended March 31, 2010.

These standards are converged with International Financial Reporting Standards (“IFRS”).

RECENT ACCOUNTING PRONOUNCEMENTS

There are no pending Canadian GAAP accounting pronouncements, other than the requirement to adopt IFRS in 2011, as discussed below.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

We will be required to report our results in accordance with IFRS beginning with the three month period ending March 31, 2011. We continue to be on schedule with our IFRS transition activities, and expect that the adoption of IFRS in 2011 will not have a significant impact or influence on our business, operations or strategies.

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The IFRS accounting policies that we expect to use have not changed from those described in our MD&A for the year ended December 31, 2009, except for the following updates:

·For exploration and evaluation (“E&E”) activities, we expect that our policy will be to continue capitalizing these costs until technical feasibility and commercial viability of the project has been determined; and

·For purposes of DD&A, we now expect that our unit of account level will be an “area” level for calculating our DD&A expense each reporting period.

We are continuing to monitor any new or amended IFRSs issued by the International Accounting Standards Board that could affect our choice of accounting policies, such as the new joint ventures standard that is expected to be published later in 2010.

We have completed the design of process and system changes that will be required to report under IFRS, and will finalize our testing and fully implement the following system changes by June 30, 2010:

·A new module for E&E activities that separately tracks our evaluation expenditures; and

·Dual GAAP ledger — which will record the journal entries needed to revise our Canadian GAAP balances to IFRS during 2010.

We are currently preparing our IFRS opening balance sheet and considering the specific optional exemptions within IFRS 1, “First-time Adoption of International Financial Reporting Standards”. The most significant exemption that we expect to elect will be to measure our E&E assets at the amount determined under Canadian GAAP, and allocate the remaining net book value of our PP&E full cost pool (excluding E&E) to our IFRS areas using the fair value of reserves as an allocation method.

We are currently preparing internal controls documentation related to the preparation of the IFRS opening balance sheet, including controls related to the completeness of the adjustments.

In terms of education and financial reporting expertise, our transition plan incorporates the tasks that are necessary to establish appropriate IFRS knowledge at all levels of our business. We have been working with our key finance and operational staff since 2009, and will continue to do so throughout 2010 and 2011. Our IFRS education activities have also included an IFRS awareness session with our Board and Audit Committee in 2009, which included the timeline for implementation, the implications of IFRS standards to our business and an overview of the potential impact to the financial statements. We will continue to provide updates to the Audit Committee each quarter throughout 2010 and 2011. The education of our external stakeholders is expected to continue throughout 2010, as we finalize our IFRS accounting policies, determine our IFRS opening balance sheet, as well as calculate the significant quarterly adjustments from Canadian GAAP to IFRS.

OUTLOOK

Our long term objective is to focus on building net asset value and generating an attractive total shareholder return through the following strategies:

·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;

·Leadership in low-cost SAGD development; enabled by technology and continued respect for our employees’ 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 believe global oil demand will continue to increase. WTI and light-heavy differentials are likely to be relatively strong for the foreseeable future. Offsetting this is a relatively weak price outlook for natural gas and refining margins. However, commodity price volatility, environmental regulations, government intervention and competitive pressures within our industry are the key hurdles that need to be effectively managed to enable our growth. Additional detail regarding the impact of these factors on our 2010 results is discussed in the Risk Management section of this MD&A and in our Annual Information Form for the year ended December 31, 2009.

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We expect our 2010 capital investment program to be funded from Cash Flow. Our crude oil and natural gas assets in Alberta and Saskatchewan will be key to providing free cash flow to enable our bitumen growth.

As part of ongoing efforts to maintain financial resilience and flexibility, Cenovus has taken steps to reduce pricing risk through a commodity hedging program. While we have benefitted from this strategy in both the first quarter of 2010 and 2009, we cannot ensure that we will continue to derive such benefits in the future.

As a relatively new entity, the Company will continue to develop strategy with respect to capital investment and returns to shareholders. Future dividends will be at the sole discretion of the Board and considered quarterly.

ADVISORY

FORWARD-LOOKING INFORMATION

This MD&A contains certain forward-looking statements and information about our current expectations, estimates and projections about the future, based on certain assumptions made by the Company in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking statements and information are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “objective”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook” or similar expressions suggesting future outcomes or statements regarding an outlook, including statements about our strategy, operating and financial results, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves, material properties, resources, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements and information as our actual results may differ materially from those expressed or implied.

Our forward-looking information respecting anticipated 2010 cash flow, operating cash flow and pre-tax cash flow is based on the following assumptions: achieving average 2010 production of approximately 120,200 bbls/d to 129,700 bbls/d of crude oil and liquids and 740 MMcf/d to 760 MMcf/d of natural gas; average commodity prices for 2010 of a WTI price of US$65 per bbl to US$85 per bbl and a WCS price of US$54 per bbl to US$71 per bbl for oil, a NYMEX price of US$5.50 per Mcf to US$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 dollar foreign exchange rate of $0.85 to $0.96 US$/CDN$; an average Chicago 3-2-1 crack spread for 2010 of US$7.50 per bbl to US$9.50 per bbl for refining margins; and an average number of outstanding shares of approximately 751 million.

Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our and our marketing operations, including credit risks; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to replace and expand oil and gas reserves; the

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ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the expected impacts of the Arrangement on our employees, operations, suppliers, business partners and stakeholders and our ability to realize the expected benefits of the Arrangement; our ability to obtain financing in the future on a stand alone basis; the historical financial information pertaining to our assets as operated by Encana prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. Readers are cautioned that the foregoing list is not exhaustive.

Many of these risk factors are discussed in further detail throughout this MD&A and in our 2009 Annual Information Form/Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2009, each as filed with Canadian securities regulatory authorities at www.sedar.com and the U.S. Securities and Exchange Commission at www.sec.gov, and available at www.cenovus.com. Readers are also referred to similar legal advisories contained in the Information Circular.

The forward-looking statements and information contained in this document, including the assumptions, risks and uncertainties underlying such statements, are made as of the date of this document and, except as required by law, we do not undertake any obligation to update publicly or to revise any of such information, whether as a result of new information, future events or otherwise. The forward-looking statements and information contained in this document are expressly qualified by this cautionary statement.

OIL AND GAS INFORMATION

Our disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to us by Canadian securities regulatory authorities that permits us to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by us may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (“NI 51-101”).

The reserves quantities disclosed by us represent net proved and probable reserves calculated using the standards contained in Regulation S-X of the U.S. Securities & Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2009.

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CRUDE OIL, 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 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head.

CURRENCY

All information included in this document and the Interim Consolidated Financial Statements and comparative information is shown on a Canadian dollar, before royalties basis unless otherwise noted.

ABBREVIATIONS

The following is a summary of the abbreviations that have been used in this document:

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

NON-GAAP MEASURES

Certain measures in this document do not have any standardized meaning as prescribed by Canadian GAAP such as Cash Flow, Operating Cash Flow, Free Cash Flow, Operating Earnings, Adjusted EBITDA, Debt and Capitalization and therefore are considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding our liquidity and our ability to generate funds to finance our operations. Management’s use of these measures has been disclosed further in this document as these measures are discussed and presented.

REFERENCES TO 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 indirect subsidiary corporations and partnerships (“Subsidiaries”) of Cenovus, and the assets, activities and initiatives of such Subsidiaries.

Additional information regarding Cenovus Energy Inc. can be accessed under our public filings found at www.sedar.com and on our website at www.cenovus.com.

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Reserves and Other

Oil and Gas Information

We retain independent qualified reserves evaluators ("IQREs") to evaluate and prepare reports on 100 percent of our bitumen, crude oil, NGLs and natural gas reserves annually.  These evaluators are McDaniel & Associates Consultants Ltd. and GLJ Petroleum Consultants Ltd.  The following reserves information is derived from the reserves reports prepared for us by each of these companies.

We have a Reserves Committee (as defined herein) of independent Board members which reviews the qualifications and appointment of the IQREs.  The Reserves Committee also reviews the procedures for providing information to the evaluators.

Our Vice-President, Strategic Planning and Reserves Governance and two other staff under this individual's direction oversee the preparation of the reserves estimates by the IQREs.  Currently, this internal staff of two professional engineers have combined relevant experience of over 65 years.  The Vice-President and other engineering staff are all members of the appropriate provincial professional associations and are members of various industry associations such as the Society of Petroleum Engineers.

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

There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves.  See "Risk Factors – Risks relating to our Business – Our crude oil and natural gas reserves data and future net revenue estimates are uncertain".  Classifications of reserves as proved or probable are only attempts to define the degree of uncertainty associated with the estimates.  In addition, whereas proved reserves are those reserves that can be estimated with reasonable certainty to be economically producible, probable reserves are those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.  Therefore, probable reserves estimates, by definition, have a higher degree of uncertainty than proved reserves.

Reserves Quantities Information

Revised reserves disclosure requirements issued by the SEC at the end of 2008 require separate disclosure of our bitumen reserves from our crude oil and NGLs reserves.  The following information in this prospectus reflects this separation for each of the years presented.

The majority of our bitumen reserves will be recovered and produced using SAGD technology.  SAGD involves injecting steam into horizontal wells drilled into the bitumen formation and recovering heated bitumen from producing wells located below the injection wells.  This technique has a surface footprint comparable to conventional oil production.  We have no bitumen reserves that require mining techniques to recover the bitumen.

Total Proved Reserves After Royalties

In 2009, bitumen reserves increased by approximately eight percent, largely as a result of Christina Lake phase D receiving approval to proceed.  The increase was partially offset by reductions attributed to higher royalty bitumen rates resulting from a higher WTI price. In addition, as a result of the new Alberta Royalty Framework, where royalties are determined on a sliding scale depending on the price 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.  Once a project reaches payout, the royalty is based on the greater of one to nine percent of a project's gross revenue or 25 to 40 percent of net revenue.  The actual royalty rate that is payable within these ranges is determined based on the WTI U.S. dollar price of crude oil, translated into Canadian dollars.  In 2008, bitumen reserves increased by approximately 12 percent, largely due to lower royalties resulting from a lower WTI price.  In 2007, bitumen reserves decreased by approximately 26 percent, as a consequence of 50 percent of the Foster Creek and Christina

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Lake reserves being contributed into the integrated oil business with ConocoPhillips.  The subsequent approval of Christina Lake phase C and other minor additions and revisions in the year restored 52 percent of the contributed reserves.

In 2009, crude oil and NGLs reserves decreased by approximately four percent as aggregate additions and revisions were insufficient to replace production.  During 2008, crude oil and NGLs reserves increased by approximately four percent as reserve additions exceeded production and negative revisions.  During 2007, crude oil and NGLs reserves decreased approximately four percent as reserves additions were more than offset by production.

In 2009, natural gas reserves decreased by approximately 21 percent as production and negative revisions to undeveloped reserves due to low gas prices, exceeded additions and positive revisions.  Natural gas reserves during 2008 decreased by approximately eight percent, with positive revisions and additions insufficient to offset production.  In 2007, natural gas reserves decreased by approximately nine percent, as positive revisions and additions only replaced approximately 46 percent of production.

Impact of SEC Modernization of Oil and Gas Reporting Requirements

SEC reporting requirements have changed with respect to prices used to estimate reserves and in the definition of proved oil and gas reserves.  Our IQREs have determined that no changes to reserves have occurred as a result of the definition changes. However, the changes 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 (average 2009 prices) as compared to the old pricing rules (price on December 31, 2009): bitumen reserves are higher by 28 million barrels and oil and NGLs reserves are higher by seven million barrels, both as a result of lower royalty rates, and natural gas reserves are lower by 156 billion cubic feet as a result of low gas prices.

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Net Proved Reserves (Share After 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	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

	Bitumen (millions of barrels)	Crude Oil and Natural Gas Liquids (millions of barrels)	Natural Gas (billions of cubic feet)
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, after deduction of estimated royalties and including royalty interests.

(b)"Proved" oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations.

(c)"Proved Developed" reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)"Proved Undeveloped" reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

Supplemental Reserves Disclosure

The volatility of our net bitumen reserves and the net oil reserves at Pelican Lake due to the linkage of royalty rates to the WTI oil reference price has led Cenovus to conclude that it would facilitate comprehension 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.  This will provide a clearer understanding of the outcome of our reserves development activities.

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Total Proved Reserves Before Royalties

In 2009, bitumen reserves increased by approximately 24 percent, as a result of the approval of Christina Lake phase D.  In 2008, bitumen reserves were unchanged, as minor revisions offset production in the year.  In 2007, bitumen reserves decreased by approximately 22 percent, as a consequence of 50 percent of the Foster Creek and Christina Lake reserves being contributed into the integrated oil business effective January 2, 2007.  The subsequent approval of Christina Lake phase C and other minor additions and revisions in the year restored approximately 57 percent of the contributed reserves.

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

In 2009, natural gas reserves decreased by approximately 21 percent as production and negative revisions to undeveloped reserves due to low gas prices exceeded additions and positive revisions.  Natural gas reserves during 2008 decreased by approximately nine percent, with positive revisions and additions insufficient to offset production.  In 2007, natural gas reserves decreased by approximately nine percent, as positive revisions and additions only replaced approximately 43 percent of production.

Impact of SEC Modernization of Oil and Gas Reporting Requirements

SEC reporting requirements have changed with respect to prices used to estimate reserves and in the definition of proved oil and gas reserves.  Our IQREs have determined that no changes to reserves have occurred as a result of the definition changes.  However, the changes 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 (average 2009 prices) as compared to the old pricing rules (price on December 31, 2009): bitumen reserves are unchanged, oil and NGLs reserves are slightly down by one million barrels and natural gas reserves are lower by 164 billion cubic feet as a result of low gas prices.

C-5

Company Share Proved Reserves Before 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 reserves attributable to the Cenovus Assets, before deduction of estimated royalties, but including royalty interests.

(b)"Proved" oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations.

(c)"Proved Developed" reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(d)"Proved Undeveloped" reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

Optional Disclosure of Probable Reserves

In addition to providing total proved reserves results, both before and after royalties, we are also providing information on our probable reserves.  Probable reserves are those additional reserves quantities of bitumen, crude oil, natural gas and NGLs that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered.

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

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Total Probable Reserves After Royalties

At the end of 2009, probable bitumen reserves were 403 million barrels, or approximately 35 percent less than the previous year, due to the reclassification of Christina Lake phase D to proved reserves from probable reserves.  In 2008, bitumen reserves were 624 million barrels, an increase of approximately 16 percent.  In 2007, bitumen reserves were 537 million barrels.

At the end of 2009, probable crude oil and NGLs reserves were 127 million barrels, a decrease of approximately seven percent.  In 2008, crude oil and NGLs reserves were 136 million barrels, an increase of approximately 14 percent. In 2007, crude oil and NGLs reserves were 119 million barrels.

At the end of 2009, probable natural gas reserves were 405 billion cubic feet, a decrease of approximately 22 percent.  Natural gas reserves in 2008 were 522 billion cubic feet, a decrease of approximately eight percent.  In 2007, natural gas reserves were 569 billion cubic feet.

Net Probable Reserves (Share After 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 to the Cenovus Assets, after deduction of estimated royalties, but including royalty interests.

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

(c)"Probable Developed" reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

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

Supplemental Reserves Disclosure

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

Probable Reserves Before Royalties

At the end of 2009, probable bitumen reserves were 479 million barrels, or approximately 25 percent less than the previous year, due to the reclassification of Christina Lake phase D to proved reserves from probable reserves.  In 2008, bitumen reserves were 637 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 reserves were 156 million barrels, a decrease of approximately one percent.  In 2008, crude oil and NGLs reserves were 158 million barrels, an increase of approximately five percent.  In 2007, crude oil and NGLs reserves were 150 million barrels.

C-7

At the end of 2009, probable natural gas reserves were 436 billion cubic feet, a decrease of approximately 23 percent.  Natural gas reserves in 2008 were 566 billion cubic feet, a decrease of approximately eight percent.  In 2007, natural gas reserves were 618 billion cubic feet.

Company Share Probable Reserves Before 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 reserves attributable to the Cenovus Assets, before deduction of estimated royalties, but including royalty interests.

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

(c)"Probable Developed" reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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

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

Development of Proved Undeveloped Reserves

Bitumen

At the end of 2009, we had proved undeveloped bitumen reserves of 611 million barrels after royalties, or approximately 85 percent of our total proved bitumen reserves.  Our existing reserves will be recovered using SAGD.  Typical SAGD project development involves installing a steam generation facility, at a cost much greater than drilling a production/injection well pair, and drilling sufficient SAGD wells to fully utilize the available steam.

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

The forecast production of Cenovus's proved bitumen reserves extends over 40 years, based on existing facilities. Production of the current proved developed portion is estimated to last ten years.

Oil

We have a significant CO2 EOR project at Weyburn and a significant waterflood/polymer flood EOR project at Pelican Lake.  These projects occur in large, well-developed reservoirs, where undeveloped reserves are not necessarily defined by the absence of drilling, but by improved recovery associated with development of the EOR schemes.  Extending both EOR schemes requires intensive capital investment in infrastructure development and will occur over many years.

C-8

At Weyburn, investment in proved undeveloped reserves is projected to continue for well over 30 years, with drilling of supplementary wells taking place over the next six years and CO2 flood advancement continuing many years beyond that.  At Pelican Lake, investment in proved undeveloped reserves is projected to continue for over 20 years, with a combination of infill drilling and polymer flood advancement.

Material Changes to Proved Undeveloped Reserves

The approval of Christina Lake phase D added approximately 160 million barrels of proved undeveloped bitumen reserves in 2009.  Natural gas reserves were reduced by approximately 108 billion cubic feet due to low gas prices.

Development Progress

In 2009, approximately $240 million was spent to convert 17 million barrels of bitumen, eight million barrels of oil and 41 billion cubic feet of natural gas from proved undeveloped to proved developed reserve status.

Aging of Proved Undeveloped Reserves

The only current proved undeveloped reserves that have remained undeveloped for five years or more are located in the Pelican Lake EOR project.  Limited polymer flooding to date has provided positive indications for broader application throughout the reservoir.

Commodity Prices for Reserves Evaluation

To estimate Cenovus's reserves, the IQREs 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 prices be determined by using the average of the first day of the month price for each of the 12 months preceding the effective date of the evaluation.  The 2008 reference 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 information prepared by us in accordance with the U.S. Financial Accounting Standards Board's ASC 932-10, "Extractive Activities - Oil and Gas".

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

In calculating the standardized measure of discounted future net cash flows for 2009, 12-month average price and cost assumptions were applied to our annual future production from proved reserves to determine cash inflows.  For the 2008 and 2007 calculations of standardized measure of discounted future net cash flows, the prices were based on the year-end price for each of the respective years.  Future production and development costs are based on average price assumptions and assume the continuation of existing economic, operating and regulatory conditions.  Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations.  The discount was computed by application of a ten percent discount factor to the future net cash flows.  The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by the IQREs in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year-end and to account for asset retirement obligations and future income taxes.

C-9

We caution that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of our oil and gas properties, nor the future net cash flows expected to be generated from such properties.  The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations.  The prescribed discount rate of ten percent may not appropriately reflect future interest rates.  The computation also excludes values attributable to the marketing of our proprietary production and third-party purchases and sales of product.

Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	2009	2008		2007
	($ millions)
Future cash inflows	48,006		31,626		57,706
Less future:
Production costs	16,757		15,001		17,345

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

Changes in Standardized Measure of Discounted Future Net Cash Flows

Relating to Proved Oil and Gas Reserves

	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

C-10

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 are located within Canada.

Capitalized Costs

	2009	2008	2007
	($ millions)
Proved oil and gas properties	19,975	16,423	19,105

	2009	2008	2007
	($ millions)
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

Production Volumes and Per-Unit Results

Production Volumes

The following tables summarize our net daily production volumes, after royalties, on a quarterly basis for the periods indicated.

C-11

	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)Senlac property sold November 2009.

(2)Natural gas 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

	Production Volumes - 2008
	Year	Q4	Q3	Q2	Q1
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)Natural gas 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)Natural gas liquids include condensate volumes.

Per-Unit Results

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

C-12

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

C-13

	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 Foster Creek price for 2008 includes the impact of the write-down of condensate inventories to net realizable value (2008 - $4.68/bbl; Q4 2008 - $12.53/bbl; Q3 2008 - $3.59/bbl).

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

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

C-14

	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 quarter operating costs include a prior year under accrual of operating costs of approximately $1.75/bbl for Foster Creek and $2.53/bbl for Christina Lake.

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

C-15

The following tables show the impact of our realized financial hedging on per-unit results.

	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

Drilling Activity

The following tables summarize our gross participation and net 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 in which we will have an interest.

(2)"Net" wells are the number of wells obtained by aggregating 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.

C-16

In addition to the above tables, we drilled stratigraphic test wells during the year ended December 31, 2009, with the Integrated Oil Division having drilled 79 gross wells (40 net wells) and the Canadian Plains Division having drilled 22 gross wells (22 net wells).

Location of Wells(1)(2)

The following table summarizes our interests in producing wells, including wells mechanically 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 also has varying royalty interests in 9,450 natural gas wells and 4,229 crude oil wells which are producing or capable of producing.

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

Interest in Material Properties(1)

The following table summarizes our developed, undeveloped and 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 acres under lease or sublease, reserving to us, royalties or other interests.

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

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

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

C-17

Capital Expenditures, Acquisitions and Divestitures

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

The following table summarizes our net capital investment for 2009 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

Delivery Commitments

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

PART II

INFORMATION NOT REQUIRED TO BE DELIVERED TO
OFFEREES OR PURCHASERS

Indemnification of Directors and Officers.

Under the Canada Business Corporations Act (the “CBCA”), Cenovus Energy Inc. may indemnify a present or former director or officer of Cenovus Energy Inc. or another individual who acts or acted at Cenovus Energy Inc.’s request as a director or officer, or an individual acting in a similar capacity, of another entity, against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by the individual in respect of any civil, criminal, administrative, investigative or other proceeding in which the individual is involved because of that association with Cenovus Energy Inc. or other entity. Cenovus Energy Inc. may not indemnify an individual unless the individual acted honestly and in good faith with a view to the best interests of Cenovus Energy Inc., or, as the case may be, to the best interests of the other entity for which the individual acted as director or officer or in a similar capacity at Cenovus Energy Inc.’s request and in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the individual had reasonable grounds for believing that the individual’s conduct was lawful. The indemnification may be made in connection with a derivative action only with court approval. The aforementioned individuals are entitled to indemnification from Cenovus Energy Inc. as a matter of right if they were not judged by the court or other competent authority to have committed any fault or omitted to do anything that the individual ought to have done and acted in accordance with conditions set out above. Cenovus Energy Inc. may advance moneys to the individual for the costs, charges and expenses of a proceeding; however, the individual shall repay the moneys if the individual does not fulfill the conditions set out above.

The by-laws of Cenovus Energy Inc. provide that, subject to the limitations contained in the CBCA, Cenovus Energy Inc. shall indemnify a director or officer, a former director or officer, or a person who acts or acted at Cenovus Energy Inc.’s request as a director or officer, or an individual acting in a similar capacity, of another entity, against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by the individual in respect of any civil, criminal, administrative, investigative or other proceeding in which the individual is involved because of that association with the Corporation or other entity, if he acted honestly and in good faith with a view to the best interests of the corporation, or, as the case may be to the best interests of the other entity for which the individual acted as director or officer or in a similar capacity at the Corporation’s request and in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the individual had reasonable grounds for believing that the individual’s conduct was lawful.

The by-laws of Cenovus Energy Inc. provide that Cenovus Energy Inc. may, subject to the limitations contained in the CBCA, purchase, maintain or participate in insurance for the benefit of any director, officer, or certain other persons, as the Board may from time to time determine.

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, may be permitted to directors, officers or persons controlling Cenovus Energy Inc.  pursuant to the foregoing provisions, Cenovus Energy Inc. has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933, as amended, and is therefore unenforceable.

II-1

EXHIBITS

Exhibit No.	Description
2.1*	Registration Rights Agreement, dated September 18, 2009, between Cenovus Energy Inc. and the Initial Purchasers named therein.
4.1*	Annual Information Form of Cenovus Energy Inc. for the year ended December 31, 2009, dated February 18, 2010 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.2*	Audited Consolidated Financial Statements of Cenovus Energy Inc. for the year ended December 31, 2009 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.3*	Management’s Discussion and Analysis of Cenovus Energy Inc. for the year ended December 31, 2009 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.4*	Unaudited Interim Financial Statements of Cenovus Energy Inc. for the three month period ended March 31, 2010 (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on April 29, 2010) (File No. 1-34513).
4.5*	Management's Discussion and Analysis of Cenovus Energy Inc. for the three month period ended March 31, 2010 (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on April 29, 2010) (File No. 1-34513).
4.6*	Supplemental Disclosure Document of Cenovus Energy Inc. (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on May 10, 2010) (File No. 1-34513).
5.1	Consent of PricewaterhouseCoopers LLP.
5.2*	Consent of McDaniel & Associates Consultants Ltd.
5.3*	Consent of GLJ Petroleum Consultants Ltd.
5.4*	Consent of Bennett Jones LLP.
6.1*	Powers of Attorney.
7.1*	Indenture, dated September 18, 2009, between Cenovus Energy Inc. and The Bank of New York Mellon (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on December 14, 2009) (File No.1-34513).
7.2*	Form T-1 Statement of Eligibility of The Bank of New York Mellon to act as trustee under the Indenture.
99.1*	Form of Letter of Transmittal.
99.2*	Form of Notice of Guaranteed Delivery.

*Previously filed or incorporated by reference herein.

II-2

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1.    Undertaking.

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to this Form F-10 or to transactions in such securities.

Item 2.    Consent to Service of Process.

(a) Concurrently with the initial filing of this Registration Statement, the Registrant filed with the Commission a written irrevocable consent and power of attorney on Form F-X.

(b) Any change to the name or address of the Registrant’s agent for service shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of this Registration Statement.

III-1

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-10 and has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Country of Canada, on this 26th day of May, 2010.

CENOVUS ENERGY INC.
By:	/s/ Brian C. Ferguson
	Name:	Brian C. Ferguson
	Title:	President & Chief Financial Officer
By:	/s/ Kerry D. Dyte
	Name:	Kerry D. Dyte
	Title:	Executive Vice-President, General Counsel & Corporate Secretary

Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment No. 1 to the Registration Statement has been signed below by or on behalf of the following persons in the capacities indicated on May 26, 2010.

Signature		Title
*
Brian C. Ferguson		President & Chief Executive Officer and Director (Principal Executive Officer)
*
Ivor M. Ruste		Executive Vice-President & Chief Financial Officer (Principal Financial Officer)
*
Michael A. Grandin		Chair of the Board of Directors
*
Ralph S. Cunningham		Director
*
Patrick D. Daniel		Director
Ian W. Delaney		Director
*
Valerie A.A. Nielsen		Director
*
Charles M. Rampacek		Director
*
Colin Taylor		Director
*
Wayne G. Thomson		Director
*By	/s/ Kerry D. Dyte
	Kerry D. Dyte
	Attorney-in-Fact

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AUTHORIZED REPRESENTATIVE

Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, as amended, the Authorized Representative has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, solely in its capacity as the duly authorized representative of the Registrant in the United States, on this 26th day of May, 2010.

CENOVUS US REFINERIES, LLC
By:	/s/ John K. Brannan
	Name:	John K. Brannan
	Title:	President

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EXHIBITS

Exhibit No.	Description
2.1*	Registration Rights Agreement, dated September 18, 2009, between Cenovus Energy Inc. and the Initial Purchasers named therein.
4.1*	Annual Information Form of Cenovus Energy Inc. for the year ended December 31, 2009, dated February 18, 2010 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.2*	Audited Consolidated Financial Statements of Cenovus Energy Inc. for the year ended December 31, 2009 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.3*	Management’s Discussion and Analysis of Cenovus Energy Inc. for the year ended December 31, 2009 (incorporated by reference to the Form 40-F of Cenovus Energy Inc. filed with the Securities and Exchange Commission on February 18, 2010) (File No.  1-34513).
4.4*	Unaudited Interim Financial Statements of Cenovus Energy Inc. for the three month period ended March 31, 2010 (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on April 29, 2010) (File No. 1-34513).
4.5*	Management’s Discussion and Analysis  of Cenovus Energy Inc. for the three month period ended March 31, 2010 (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on April 29, 2010) (File No. 1-34513).
4.6*	Supplemental Disclosure Document of Cenovus Energy Inc. (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on May 10, 2010) (File No. 1-34513).
5.1	Consent of PricewaterhouseCoopers LLP.
5.2*	Consent of McDaniel & Associates Consultants Ltd.
5.3*	Consent of GLJ Petroleum Consultants Ltd.
5.4*	Consent of Bennett Jones LLP.
6.1*	Powers of Attorney.
7.1*	Indenture, dated September 18, 2009, between Cenovus Energy Inc. and The Bank of New York Mellon (incorporated by reference to the Form 6-K of Cenovus Energy Inc. filed with the Securities and Exchange Commission on December 14, 2009) (File No.1-34513).
7.2*	Form T-1 Statement of Eligibility of The Bank of New York Mellon to act as trustee under the Indenture.
99.1*	Form of Letter of Transmittal.
99.2*	Form of Notice of Guaranteed Delivery.

*Previously filed or incorporated by reference herein.

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