Exhibit 99.1

Cenovus Energy achieves strong Q1 cash flow

Growth projects deliver 66% production increase

·Production from the Foster Creek and Christina Lake enhanced oil properties increased 66% in the first quarter of 2010 compared to the same period in 2009.

·Foster Creek achieved payout for royalty purposes in February, reflecting the project’s success.

·Cenovus’s mature conventional oil and gas properties generated about half a billion dollars in operating cash flow in excess of capital expenditures.

·The company’s hedging position was strengthened to help provide more cash flow certainty.

·Cenovus changed to reporting financial results in Canadian dollars, and to reporting production on a before royalties basis, for better comparison with its Canadian peers.

“In our first full quarter, we completed our transition to an independent company while achieving great financial and operating results,” said Brian Ferguson, President & Chief Executive Officer of Cenovus. “The year is progressing well and we are somewhat ahead of our expectations. Production ramped up at our new phases at Foster Creek and work is advancing on the next two phases at Christina Lake.

“Our conventional oil and gas properties continue to be very efficient operations and are delivering strong cash flow,” Ferguson said. “We have added to our financial strength by increasing our hedging position, giving us more certainty around cash flow. The evaluation of our opportunity rich portfolio is well under way, supported by the release of our bitumen economic contingent resources estimates last week. We are on track with our plans and look forward to continued strong performance in 2010.”

Financial & Production Summary1
(for the period ended March 31) (C$ millions, except per share amounts)	2010 Q1	2009 Q1	% change
Cash flow2 Per share diluted	721 0.96	741 0.99	-3
Operating earnings2 Per share diluted	353 0.47	414 0.55	-15
Capital investment	493	652	-24
Production (before royalties)
Foster Creek (bbls/d)	51,126	28,554	79
Christina Lake (bbls/d)	7,420	6,635	12
Foster Creek & Christina Lake Total (bbls/d)	58,546	35,189	66
Other Oil and NGLs (bbls/d)	72,003	78,870	-9
Natural gas (MMcf/d)	775	866	-11

1 Effective Jan. 1, 2010, Cenovus changed its reporting currency to Canadian dollars and started presenting production volumes on a before royalties basis.

2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory.

Calgary, Alberta (April 29, 2010) – In its first full quarter as an independent integrated oil company, Cenovus Energy Inc. (TSX, NYSE: CVE) realized strong cash flow. Its Foster Creek and Christina Lake enhanced oil properties in northeast Alberta delivered higher production and lower operating costs per barrel relative to the first quarter of 2009.

Cash flow for the quarter was approximately $721 million ($0.96 per share), down 3% from the same period in 2009, as higher oil production and prices were offset by expected lower natural gas production as well as a decrease in realized natural gas prices and lower refining margins.

Cenovus’s strategy is focused on growing its oil business, which accounts for approximately 85% of its proved plus probable reserves and 98% of its economic contingent resources. Reflecting that commitment to oil growth, production from Foster Creek increased by 79% in the first quarter of 2010 compared to the same period last year and first quarter production at Christina Lake increased by 12%.

“We maintained our momentum in this period of transition following the completion of the Encana split transaction,” Ferguson said. “I’d like to thank our employees for keeping us safely on track and for the progress we made in charting our growth strategy.”

Foster Creek achieves payout

Strong operational performance and a superior quality resource resulted in Cenovus’s Foster Creek project achieving payout for royalty purposes in the first quarter of 2010, the result of cumulative project revenue exceeding cumulative project allowable costs. After a decade in operation, production at Foster Creek has increased to average about 102,000 barrels per day (bbls/d) on a gross basis in the first quarter. As a result of reaching payout, the royalty rate increased from an average of 1.4% in the first quarter of 2009 to an average of 9.7% in the first quarter of 2010, with only a portion of the quarter reflecting the increased rate. Foster Creek is Alberta’s largest producing steam assisted gravity drainage (SAGD) project to reach payout to date.

“The achievement of payout at Foster Creek is a significant milestone that speaks to the quality of our assets and is a credit to our team,” Ferguson said. “Cenovus’s largest enhanced oil project has demonstrated top tier capital and operational efficiency. We are leading the way in implementing innovative technologies that reduce operating costs and our impact on the environment. Foster Creek’s top performance demonstrates that we have the experience and capabilities to deliver on our growth plans.”

Growth strategy under development

During the first quarter, Cenovus made substantial progress in developing a plan to grow its bitumen business. A major building block was an independent evaluation of Cenovus’s bitumen economic contingent resources, with details announced on April 22, 2010. The contingent resources numbers are in addition to Cenovus’s previously reported reserves estimates. The company is also assessing the petroleum initially in place for its bitumen and plans to provide more details about that assessment in June at its investor day events. At that time, Cenovus will also offer more information about plans for future project development and capital spending.

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Strong cash flow from conventional assets

Cenovus has a large portfolio of conventional assets that continue to generate strong cash flow to fund the growth of its northeast Alberta oil properties. During the first quarter, the company’s mature conventional oil and gas properties generated about half a billion dollars in operating cash flow in excess of capital expenditures. Cenovus continues to look for ways to optimize production from these cost efficient properties.

To help provide more predictability around cash flow, Cenovus increased its hedging position during the quarter. Approximately 70%, or 455 million cubic feet per day (MMcf/d) of its expected 2010 gas production - net of internal fuel use - is now hedged at an average NYMEX price of US$6.07/Mcf and approximately 20% of expected 2010 oil production is hedged at a WTI price of US$76.99/bbl.

IMPORTANT NOTE: Effective Jan. 1, 2010, Cenovus changed its reporting currency to Canadian dollars and started presenting production volumes on a before royalties basis, to better reflect its business and to enhance comparability to its peers. Cenovus has updated its 2010 Corporate Guidance document, available at www.cenovus.com. All numbers in this interim report are reported on a net to Cenovus basis unless otherwise stated.

Oil Growth Operations

Foster Creek and Christina Lake

Cenovus’s enhanced oil properties in northeast Alberta represent the company’s most significant opportunity for substantial growth in the near term. Cenovus’s two bitumen producing projects, Foster Creek and Christina Lake, use SAGD technology. They are operated by Cenovus and owned 50-50 with ConocoPhillips. Cenovus continues to advance technologies that reduce the amount of water, natural gas and electricity used in the SAGD process and to minimize land disturbance across its operations.

	Daily Production
(Before royalties) (Mbbls/d)	2010	2009					2008
	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Foster Creek	51	38	47	40	35	29	26
Christina Lake	7	7	7	6	7	7	4
Total1	59	44	54	47	41	35	30

1 Totals may not add due to rounding.

Production

·Foster Creek produced more than 51,000 bbls/d in the first quarter of 2010, up from nearly 29,000 bbls/d during the same period last year – a 79% increase. The production growth is mainly related to the ramp up of phases D and E, which came on production late in the first quarter of 2009. With the addition of those two phases, Foster Creek has production capacity of 120,000 bbls/d (gross).

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·About 12% of current production at Foster Creek comes from wedge wells. Fourteen new wedge wells are planned for 2010, in addition to the 36 drilled to date, of which 30 are producing. A wedge well pilot program has also been launched at the Christina Lake operation.

·Production at Christina Lake increased by about 12% in the first quarter to more than 7,000 bbls/d.

·Cenovus continues to achieve one of the best steam to oil ratios (SOR) in the industry with a combined SOR of less than 2.3 at Christina Lake and Foster Creek in the first quarter.

Costs

·Operating costs per barrel at Foster Creek and Christina Lake averaged $11.82 in the first quarter of 2010, a 28% decline from $16.33 in the first quarter of 2009, mainly due to higher production volumes and a lower level of workovers and repair and maintenance activities.

·Non-fuel operating costs for Foster Creek and Christina Lake were $8.57/bbl in the first quarter of 2010 compared to $13.02/bbl in the first quarter of 2009.

Expansions and Growth Projects

·During the quarter, Cenovus announced its plan to accelerate construction of phase D at Christina Lake, moving ahead scheduled completion by six months, with production expected to begin in mid 2013.

·The regulatory process is underway for Christina Lake phases E, F and G with approval anticipated in 2011.

·Phases F, G and H at Foster Creek continue to move through the regulatory process and approval is anticipated later this year. The three new phases are expected to add 90,000 bbls/d (gross) of production capacity by 2017.

·In the first quarter, Cenovus initiated public consultation for the Narrows Lake project. The company expects to file a regulatory application for Narrows Lake with Alberta’s Energy Resources Conservation Board at the end of the second quarter. The application is expected to include the possibility of using a combination of SAGD and solvent aided process (SAP) for oil production. SAP is a technological improvement applied to SAGD operations that helps maximize the amount of oil recovered and decrease emissions.

Downstream

Cenovus’s downstream operations include the Wood River refinery in Illinois and the Borger refinery in Texas, which are jointly owned with ConocoPhillips, the operator. In addition to the 25,000 bbls/d (gross) coking capacity at Borger, 65,000 bbls/d (gross) of coking capacity is being added at Wood River with the coker and refinery expansion (CORE) project to increase the total coking capacity at Wood River to 83,000 bbls/d (gross). The CORE project was approximately 77% complete as of March 31 and is expected to be in operation in mid 2011. It is anticipated that this project will improve operating cash flow at Wood River by between US$150 million and US$200 million a year (net to Cenovus). With the completion of the CORE project, Cenovus’s two refineries will be among the most complex in the United States, with the ability to process a wide variety of crude feedstocks and produce a large quantity of high value clean products. These refineries will have a combined capability to process as much as 275,000 bbls/d (gross) of heavy crude oil.

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Despite a challenging environment for refiners during the first quarter of 2010, Cenovus’s refineries performed relatively well and were supported by better than anticipated margins on asphalt at Wood River.

·In the first quarter of 2010, the refineries produced 188,500 bbls/d of refined products.

·Refinery crude utilization averaged 79% or 177,500 bbls/d crude throughput, lower than in the same period a year ago, due to weaker market conditions and scheduled turnaround activity.

·Operating cash flow for downstream operations in the first quarter of 2010 was a deficiency of $6 million, which was $79 million lower than the first quarter of 2009 due to increased crude oil feedstock costs, reduced market crack spreads and lower crude utilization.

Conventional Oil and Natural Gas

	Daily Production
(Before royalties)	2010	2009					2008
	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Conventional oil production1 (Mbbls/d)	72	77	75	80	76	79	82
Natural Gas (MMcf/d)	775	837	797	830	856	866	954

1 The production numbers reflect the sale of Cenovus’s Senlac assets in the fourth quarter of 2009.

Conventional Crude Oil and NGLs

Cenovus holds a large base of crude oil properties across Alberta and Saskatchewan. These highly efficient operations include the Pelican Lake and Weyburn enhanced oil operations as well as conventional oil production in southern Alberta. The conventional assets continue to generate operating cash flow well in excess of their ongoing capital investment requirements. Cenovus’s Weyburn operation is the world’s largest geological carbon dioxide sequestration project.

·The Lower Shaunavon oil asset in Saskatchewan is an early stage development opportunity for Cenovus. Production reached about 1,000 bbls/d during the quarter from eight new wells, before being restricted by weather and road bans.

·Cenovus has farmed out some of its fee lands in the Pekisko oil play in southern Alberta and is receiving about 1,000 bbls/d of royalty production.

·Overall conventional oil production decreased primarily as a result of expected natural declines, partially offset by new production.

·Operating costs increased 15% to $11.10/bbl in the first quarter of 2010 compared to the same period last year, mainly due to increased polymer usage, a higher level of workovers and repair and maintenance activity, as well as higher property taxes.

·A pilot project to determine whether an alkaline surfactant polymer (ASP) flood would economically enhance heavy oil recovery from conventional assets in southern Alberta was successful. The pilot is now proceeding to the commercial stage and the technology is being considered for application to other projects.

Natural Gas

Cenovus’s natural gas assets in southern Alberta are an important component of the company’s financial foundation, generating funds required for expansion in other areas of the company. The company’s

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natural gas business also acts as an economic hedge against price fluctuations, since natural gas fuels the company’s SAGD and refinery operations. Cenovus’s natural gas properties comprise established, reliable fields with efficient operations.

·Natural gas production decreased 11% to 775 MMcf/d in the first quarter of 2010 compared to the same period in 2009, due to expected natural declines as well as lower drilling and tie-in activity in response to lower natural gas prices.

·Cenovus plans to manage declines in natural gas production, targeting a long term production level of between 400 and 500 MMcf/d.

·Coalbed methane (CBM) projects in southern Alberta are outperforming company expectations, with production reaching about 22 MMcf/d at the end of the first quarter. CBM is a new and developing opportunity for Cenovus, offsetting expected declines in natural gas production from shallow gas wells and demonstrating low finding and development costs and low operating costs. Cenovus has more than 7,000 potential CBM well locations identified in southern Alberta.

Financial

Dividend

The Cenovus Board of Directors has declared a quarterly dividend of $0.20 per share, payable on June 30, 2010, to common shareholders of record as of June 15, 2010. Based on the April 28, 2010, closing share price on the Toronto Stock Exchange of $28.59, this represents an annualized yield of about 2.8%. Declaration of dividends is at the sole discretion of the Board of Directors.

The Board of Directors has approved a dividend reinvestment plan, which Cenovus expects to establish and make available to shareholders for the second quarter 2010 dividend. More information will soon be available on Cenovus’s website, www.cenovus.com.

Risk Management Strategy

The risk management policy helps Cenovus to achieve more predictability around cash flow and safeguard its capital program. The policy allows Cenovus to hedge up to 75% of its net current year expected natural gas production, net of internal fuel use, and up to 50% and 25%, respectively, in the following two years. The policy allows for fixed price hedges of as much as 50% of net liquids production in the current year and 25% of net liquids production for each of the following two years.

Cenovus’s hedging position at March 31, 2010, comprises:

·455 MMcf/d, or approximately 70% of expected 2010 net gas production, hedged at an average NYMEX price of US$6.07/Mcf

·24,600 bbls/d, or approximately 20% of expected 2010 oil production, hedged at a WTI price of US$76.99/bbl

·263 MMcf/d of natural gas hedged for 2011 at an average NYMEX price of US$5.90/Mcf

·60 MMcf/d of natural gas hedged for 2012 at an average NYMEX price of US$6.49/Mcf

Cenovus’s realized after tax hedging gains for the first quarter of 2010 were $17 million, down from $198 million in the first quarter of 2009, due to lower hedge prices being realized on natural gas.

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In addition to its financial hedges, Cenovus benefits from a natural hedge with its gas production. About 100 MMcf/d of natural gas is consumed at the company’s SAGD and refinery operations, which is offset by natural gas that Cenovus produces. This natural hedge is considered when determining the company’s financial hedging limits.

Financial Highlights

·Operating earnings were $353 million, or $0.47 per share, down 15% from the same period a year ago, reflecting the effects of decreased realized hedging gains and lower natural gas prices and production, as well as lower refining margins.

·Cenovus’s net earnings in the first quarter were $525 million, similar to the same quarter in 2009. Net earnings were impacted by an unrealized mark-to-market after tax gain of $170 million, compared to an after tax gain of $64 million in the first quarter of 2009, and an unrealized after tax foreign exchange gain of $2 million, compared to an after tax gain of $37 million last year. Cenovus’s management views operating earnings, a non-GAAP measure defined in the Advisory, as a better measure of performance than net earnings because non-operating unrealized gains and losses are removed from operating earnings.

·Cenovus received an average realized price of $68.09/bbl for its oil, 58% higher than the first quarter of last year, and $5.80/Mcf for its natural gas, 35% less than the first quarter of 2009, including hedging gains and losses.

·Capital spending during the quarter was $493 million, a decrease of 24% compared to the first quarter of 2009, primarily due to weather related delays in both downstream and upstream operations. Much of the capital spending that was delayed in the first quarter is expected to proceed later in the year.

·Free cash flow was $228 million, $139 million higher than in the first quarter of 2009.

·Cenovus’s divestiture program continues with first quarter proceeds of $72 million from the sale of land at the Narrows Lake property to the partnership Cenovus has with ConocoPhillips. Another $70 million worth of assets are expected to be sold in the second quarter. Several other asset packages are currently being marketed. Cenovus is planning $1 billion in divestitures over the next two years if market conditions are favourable.

·Cenovus targets a debt to capitalization ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of between 1.0 and 2.0 times. At March 31, 2010, the company’s debt to capitalization ratio was 26% and debt to adjusted EBITDA, on a trailing 12 month basis, was 1.0 times.

Earnings Reconciliation Summary
(for the period ended March 31) ($ millions, except per share amounts)	2010 Q1	2009 Q1
Net earnings Add back (losses) & deduct gains:	525	515
Unrealized mark-to-market hedging gain (loss), after-tax	170	64
Non-operating foreign exchange gain (loss), after-tax	2	37
Operating earnings1	353	414
Per share diluted	0.47	0.55

1Operating earnings is a non-GAAP measure as defined in the Advisory.

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Cenovus Energy Inc.

Cenovus Energy is a leading integrated oil company headquartered in Calgary, Alberta, with an enterprise value of approximately $25 billion. The company’s operations include its growing enhanced oil projects and established natural gas and crude oil production in Alberta and Saskatchewan as well as ownership in two high quality refineries in Illinois and Texas. Cenovus is respectful of the environment and communities where it operates and is committed to applying fresh, progressive thinking to the development of energy resources the world needs. Cenovus shares, which trade under the symbol CVE, are listed on the Toronto and New York stock exchanges. For more information, go to www.cenovus.com.

ADVISORY

NON-GAAP MEASURES

This interim report contains references to non-GAAP measures as follows:

·Operating Cash Flow is 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.

·Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital from continuing operations, both of which are defined on the Consolidated Statement of Cash Flows, in this interim report and interim financial statements.

·Operating earnings show net earnings excluding non-operating items such as the after-tax impacts of a gain/loss on discontinuance, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, the after-tax foreign exchange gain/loss on settlement of intercompany transactions, future income tax on foreign exchange related to U.S. dollar intercompany debt recognized for tax purposes only and the effect of changes in statutory income tax rates. Management believes that these excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.

·Free cash flow is defined as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.

·Capitalization is a measure defined as debt plus shareholders’ equity. Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength.

·Adjusted EBITDA is defined as net earnings from continuing operations before gains or losses on divestitures, income taxes, foreign exchange gains or losses, interest net, accretion of asset retirement obligation, and depreciation, depletion and amortization.

These measures have been described and presented in this interim report in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations.

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OIL AND GAS INFORMATION

Our disclosure of annual reserves data is made in accordance with U.S. disclosure requirements pursuant to an exemption from the Canadian securities administrators. As a result, the information provided by Cenovus may differ from corresponding information prepared in accordance with National Instrument 51-101 (“NI 51-101”). 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 Cenovus’s Annual Information Form, available at www.cenovus.com or www.sedar.com.

Our disclosure of economic contingent resources is based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further information regarding our economic contingent resources estimates and the associated COGEH definitions, see our April 22, 2010 news release available at www.cenovus.com.

FORWARD-LOOKING INFORMATION

This interim report 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 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 and information as our actual results may differ materially from those expressed or implied.

Our forward-looking information respecting anticipated 2010 cash flow and operating 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 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

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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 plan of arrangement with Encana Corporation (“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 Corporation 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 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.

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.

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Management’s Discussion and Analysis

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.

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

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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. 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.

Cenovus Energy Inc.	12
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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 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.

Cenovus Energy Inc.	13
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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 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.

Cenovus Energy Inc.	14
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

Cenovus Energy Inc.	15
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

Cenovus Energy Inc.	16
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

Cenovus Energy Inc.	17
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

Cenovus Energy Inc.	18
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.	19
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.	20
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.	21
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.	22
First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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.

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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

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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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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First Quarter 2010 Interim Report	Management’s Discussion and Analysis

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).

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First Quarter 2010 Interim Report	Consolidated Financial Statements

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).

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First Quarter 2010 Interim Report	Consolidated Financial Statements

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).

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First Quarter 2010 Interim Report	Consolidated Financial Statements

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).

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First Quarter 2010 Interim Report	Consolidated Financial Statements

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.

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First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	46
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	47
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	48
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	49
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	50
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	51
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	52
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	53
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	54
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	55
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	56
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	57
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	58
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	59
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	60
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	61
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	62
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	63
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	64
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

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.	65
First Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

(C$ millions, except per share amounts)		2010		2009
		Q1		Year		Q4		Q3		Q2		Q1
Gross Revenues		3,602		11,790		3,103		3,080		2,871		2,736
Less: Royalties		111		273		98		79		53		43
Net Revenues		3,491		11,517		3,005		3,001		2,818		2,693
Operating Cash Flow
Crude Oil and Natural Gas Liquids
Foster Creek and Christina Lake		215		663		232		198		162		71
Canadian Plains		309		1,057		289		314		275		179
Natural Gas		314		2,061		412		500		555		594
Other Upstream Operations		6		50		9		27		3		11
		844		3,831		942		1,039		995		855
Downstream		(6	)	358		12		95		178		73
Operating Cash Flow		838		4,189		954		1,134		1,173		928
Cash Flow Information
Cash from Operating Activities		820		3,039		150		1,414		793		682
Deduct (Add back):
Net change in other assets and liabilities		(15	)	(26	)	(14	)	(3	)	(6	)	(3	)
Net change in non-cash working capital		114		220		(71	)	493		(146	)	(56	)
Cash Flow (1)		721		2,845		235		924		945		741
Per share	- Basic	0.96		3.79		0.31		1.23		1.26		0.99
	- Diluted	0.96		3.79		0.31		1.23		1.26		0.99
Operating Earnings (2)		353		1,522		169		427		512		414
Per share	- Diluted	0.47		2.03		0.23		0.57		0.68		0.55
Net Earnings		525		818		42		101		160		515
Per share	- Basic	0.70		1.09		0.06		0.13		0.21		0.69
	- Diluted	0.70		1.09		0.06		0.13		0.21		0.69
Effective Tax Rates using
Net Earnings		18.0	%	29.6	%
Operating Earnings, excluding divestitures		6.1	%	25.0	%
Canadian Statutory Rate		28.2	%	29.2	%
Foreign Exchange Rates (US$ per C$1)
Average		0.961		0.876		0.947		0.911		0.857		0.803
Period end		0.985		0.956		0.956		0.933		0.860		0.794

(1)

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, both of which are defined on the Consolidated Statement of Cash Flows.

(2)

Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gain/loss 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, 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.

	2010	2009
Financial Metrics
Debt to Capitalization (1)	26%	28%
Debt to Adjusted EBITDA (1, 2)	1.0x	1.1x
Return on Capital Employed (1, 2)	7%	8%
Return on Common Equity (2)	8%	8%

(1)	Calculated using Debt defined as the current and long-term portions of Long-Term Debt.
(2)	Calculated on a trailing twelve-month basis.

Common Share Information	2010	December
	Q1	2009
Common Shares Outstanding (millions) (1)
Period end	751.7	751.3
Average - Basic	751.5	751.0
Average - Diluted	751.7	751.4
Price Range ($ per share)
TSX - C$
High	27.84	27.18
Low	24.26	24.68
Close	26.53	26.50
NYSE - US$
High	26.79	25.70
Low	22.87	23.37
Close	26.21	25.20
Dividends Paid (2)	C$0.20	US$0.20
Share Volume Traded (millions)	204.5	83.5

(1)	Cenovus Common Shares were issued under the terms of the arrangement on November 30, 2009 and began trading on December 3, 2009 (TSX) and December 9, 2009 (NYSE).
(2)	Dividend paid in December reflects an amount determined in connection with the Arrangement with Encana Corporation based on carve-out earnings and cash flows.

Cenovus Energy Inc.	66
First Quarter 2010 Interim Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

Net Capital Investment (C$ millions)	2010		2009
	Q1		Year		Q4		Q3	Q2		Q1
Capital Investment
Upstream Canada
Foster Creek	57		262		76		62	59		65
Christina Lake	63		224		66		53	49		56
Canadian Plains	139		553		115		104	99		235
Other	31		57		5		4	14		34
	290		1,096		262		223	221		390
Downstream Refining	202		1,032		224		291	265		252
Corporate	1		34		21		1	2		10
Capital Investment	493		2,162		507		515	488		652
Acquisitions	-		148		146		1	1		-
Divestitures	(72	)	(367	)	(366	)	2	(3	)	-
Net Acquisition and Divestiture Activity	(72	)	(219	)	(220	)	3	(2	)	-
Net Capital Investment	421		1,943		287		518	486		652

Operating Statistics - Before Royalties

Upstream Production Volumes	2010	2009
	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Heavy Oil
Foster Creek	51,126	37,725	47,017	40,367	34,729	28,554
Christina Lake	7,420	6,698	7,319	6,305	6,530	6,635
Integrated Oil - Other	-	3,057	2,221	5,080	2,574	2,334
Canadian Plains	36,856	38,668	37,057	38,989	37,643	41,023
Light and Medium Oil
Canadian Plains	33,991	34,484	34,518	34,504	34,609	34,300
Natural Gas Liquids (1)
Canadian Plains	1,156	1,206	1,183	1,242	1,184	1,213
Total Crude Oil and Natural Gas Liquids	130,549	121,838	129,315	126,487	117,269	114,059
Natural Gas (MMcf/d)
Integrated Oil - Other	42	50	44	52	54	50
Canadian Plains	733	787	753	778	802	816
Total Natural Gas Production	775	837	797	830	856	866

(1) Natural gas liquids include condensate volumes.

Average Royalty Rates

(excluding impact of realized financial hedging)	2010	2009
	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil - Foster Creek	9.7%	2.7%	3.9%	3.0%	1.5%	1.4%
Crude Oil - Christina Lake	4.0%	2.3%	3.6%	2.9%	1.6%	1.0%
Crude Oil - Pelican Lake/Weyburn	19.6%	19.4%	22.8%	19.9%	19.2%	15.7%
Crude Oil - Other	10.9%	7.8%	8.4%	9.0%	6.1%	5.4%
Natural Gas	2.8%	1.5%	3.9%	0.5%	-0.9%	2.8%
Natural Gas Liquids	2.1%	1.6%	1.6%	2.1%	1.9%	1.0%

Downstream Refining	2010	2009
	Q1	Year	Q4	Q3	Q2	Q1
Refinery Operations (1)
Crude oil capacity (Mbbls/d)	452	452	452	452	452	452
Crude oil runs (Mbbls/d)	355	394	348	425	404	398
Crude utilization (%)	79%	87%	77%	94%	89%	88%
Refined products (Mbbls/d)	377	417	370	451	428	421

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

Cenovus Energy Inc.	67
First Quarter 2010 Interim Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results

(C$, excluding impact of realized financial hedging)	2010	2009
	Q1	Year		Q4	Q3		Q2	Q1
Crude Oil - Heavy - Foster Creek ($/bbl)
Price (1)	63.33	55.55		63.60	62.20		54.43	33.44
Royalties	5.76	1.42		2.31	1.85		0.66	0.22
Transportation and selling	2.33	2.51		1.71	2.50		3.45	2.69
Operating	11.11	11.87		10.43	10.85		11.81	15.91
Netback	44.13	39.75		49.15	47.00		38.51	14.62
Crude Oil - Heavy - Christina Lake ($/bbl)
Price (2)	62.27	53.45		57.07	64.85		57.32	32.44
Royalties	2.28	1.24		2.04	1.72		0.83	0.23
Transportation and selling	4.47	3.09		0.96	5.36		2.83	3.38
Operating	16.41	16.31		18.06	15.31		13.69	18.21
Netback	39.11	32.81		36.01	42.46		39.97	10.62
Crude Oil - Heavy - Canadian Plains ($/bbl)
Price (3)	69.40	55.00		62.00	63.01		56.09	38.76
Royalties	13.85	9.23		11.29	11.54		8.62	5.42
Production and mineral taxes	0.09	(0.01	)	0.02	(0.01	)	0.02	(0.07	)
Transportation and selling	1.51	1.08		0.71	0.99		1.35	1.24
Operating	11.08	9.28		11.68	7.82		9.49	8.30
Netback	42.87	35.42		38.30	42.67		36.61	23.87
Crude Oil - Heavy - Total ($/bbl)
Price (4)	65.64	55.14		62.46	62.67		55.55	36.15
Royalties	8.66	5.20		6.02	6.42		4.85	3.03
Production and mineral taxes	0.04	0.03		0.03	0.05		0.05	(0.04	)
Transportation and selling	2.18	1.90		1.27	2.05		2.39	1.98
Operating	11.53	11.03		11.45	9.60		11.09	12.19
Netback	43.23	36.98		43.69	44.55		37.17	18.99
Light and Medium Oil - Canadian Plains ($/bbl)
Price	77.71	62.36		71.25	67.53		63.59	46.57
Royalties	9.37	6.82		10.88	7.30		5.98	3.02
Production and mineral taxes	2.12	2.20		1.55	2.20		1.94	3.14
Transportation and selling	0.85	0.89		0.63	0.74		1.07	1.12
Operating	11.51	10.18		9.93	9.98		9.83	11.01
Netback	53.86	42.27		48.26	47.31		44.77	28.28
Crude Oil - Total ($/bbl)
Price	68.87	57.22		64.85	64.00		57.95	39.40
Royalties	8.85	5.67		7.34	6.66		5.18	3.03
Production and mineral taxes	0.59	0.65		0.44	0.64		0.62	0.95
Transportation and selling	1.83	1.61		1.10	1.69		2.00	1.71
Operating	11.52	10.78		11.04	9.70		10.72	11.82
Netback	46.08	38.51		44.93	45.31		39.43	21.89
Natural Gas Liquids - Canadian Plains ($/bbl)
Price	67.42	49.08		59.06	49.17		44.65	43.42
Royalties	1.39	0.81		0.96	1.00		0.82	0.46
Netback	66.03	48.27		58.10	48.17		43.83	42.96
Total Liquids ($/bbl)
Price	68.85	57.14		64.79	63.85		57.81	39.45
Royalties	8.78	5.62		7.28	6.60		5.14	3.00
Production and mineral taxes	0.59	0.65		0.44	0.63		0.61	0.94
Transportation and selling	1.83	1.60		1.09	1.67		1.98	1.69
Operating	11.42	10.67		10.94	9.61		10.61	11.69
Netback	46.23	38.60		45.04	45.34		39.47	22.13
Total Natural Gas(5) ($/Mcf)
Price	5.27	4.15		4.17	3.14		3.80	5.47
Royalties	0.14	0.08		0.16	0.02		0.01	0.15
Production and mineral taxes	0.07	0.05		0.03	0.04		0.07	0.05
Transportation and selling	0.21	0.15		0.12	0.16		0.16	0.18
Operating	0.94	0.86		0.81	0.84		0.83	0.94
Netback	3.91	3.01		3.05	2.08		2.73	4.15
Total ($/BOE)
Price	50.16	39.88		44.54	40.43		38.65	35.71
Royalties	4.81	2.87		4.05	3.22		2.35	1.81
Production and mineral taxes	0.52	0.46		0.30	0.43		0.52	0.58
Transportation and selling	1.53	1.24		0.91	1.29		1.41	1.34
Operating(6)	8.53	7.71		7.85	7.24		7.52	8.27
Netback	34.77	27.60		31.43	28.25		26.85	23.71

(1)	The Foster Creek heavy oil price for 2010 has been reduced by the cost of condensate purchases ($39.05/bbl) which are blended with the heavy oil.
(2)	The Christina Lake heavy oil price for 2010 has been reduced by the cost of condensate purchases ($41.01/bbl) which are blended with the heavy oil.
(3)	The Canadian Plains heavy oil price for 2010 has been reduced by the cost of condensate purchases of ($17.00/bbl) which are blended with the heavy oil.
(4)	The total heavy oil price for 2010 has been reduced by the cost of condensate purchases of ($30.53/bbl) which are blended with the heavy oil.
(5)	Natural gas - Total includes natural gas from the Athabasca property.
(6)	2010 year-to-date operating costs include costs related to long-term incentives cost recovery of $0.11/BOE (2009 - cost recovery of $0.16/BOE).

Impact of Realized Financial Hedging
Liquids ($/bbl)	(0.78	)	1.10	(0.05	)	(0.01	)	1.54	3.29
Natural Gas ($/Mcf)	0.53		3.63	2.27		4.41		4.33	3.43
Total ($/BOE)	1.20		12.16	6.92		13.77		14.91	13.06

Cenovus Energy Inc.	68
First Quarter 2010 Interim Report	Supplemental Information

Cenovus Energy Inc.

421 – 7 Ave SW

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-8231

Cenovus Communications & Stakeholder Relations

Investor contacts:	Media contact:
Paul Gagne	Rhona DelFrari
Vice-President, Investor Relations	Manager, Media Relations
403-766-4737	403-766-4740
paul.gagne@cenovus.com	rhona.delfrari@cenovus.com
Susan Grey
Manager, Investor Relations
403-766-4751
susan.grey@cenovus.com
James Fann
Analyst, Investor Relations
403-766-6700
james.fann@cenovus.com

www.cenovus.com