Exhibit 99.1

Cenovus increases second quarter oil sands production by 42%

Operational and financial performance on track

·Production from the Foster Creek and Christina Lake oil sands projects increased 42% in the second quarter of 2010 compared with the same period in 2009.

·Cenovus’s established conventional oil and gas properties generated about $400 million of operating cash flow in excess of capital expenditures in the second quarter.

·Second quarter cash flow remained strong and in line with company guidance, despite weaker realized natural gas prices and lower downstream operating cash flow.

·The Board approved a 10 year business plan detailing how the company expects to achieve oil sands production of 300,000 barrels per day (bbls/d) by the end of 2019, a five-fold increase from current production.

·An application was submitted to Alberta Environment and the Energy Resources Conservation Board (ERCB) for the Narrows Lake oil sands project. The ERCB approved a Grand Rapids pilot in the Greater Pelican Region.

“Our second quarter has delivered strong operational and financial results,” said Brian Ferguson, President & Chief Executive Officer of Cenovus. “We are on track to meet guidance targets we’ve established for production and cash flow for the year. We continue to take steps that are expected to lead to a doubling of the company’s net asset value within the next five years.

“We have top quality reservoirs, experienced and knowledgeable staff, a track record of being a low cost operator and a commitment to continuously advance our technologies and reduce our environmental impact,” Ferguson said. “These elements, combined with reliable cash flow from our conventional oil and gas assets and a solid dividend, are expected to deliver strong total shareholder return over the long term.”

Financial & Production Summary1
(for the period ended June 30)(C$ millions, except per share amounts)	2010Q2	2009Q2	% change	2010 6 months	20096 months	% change
Cash flow2Per share diluted	5370.71	9451.26	-43	1,2581.67	1,6862.25	-25
Operating earnings2Per share diluted	1420.19	5120.68	-72	4950.66	9261.23	-47
Capital investment	430	488	-12	923	1,140	-19
Production (before royalties)
Foster Creek (bbls/d)	51,010	34,729	47	51,067	31,658	61
Christina Lake (bbls/d)	7,716	6,530	18	7,569	6,582	15
Foster Creek & Christina Lake Total (bbls/d)	58,726	41,259	42	58,636	38,240	53
Other Oil and NGLs (bbls/d)	69,840	76,010	-8	70,915	77,434	-8
Natural gas (MMcf/d)	751	856	-12	762	861	-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. See also the Earnings Reconciliation Summary on page 9.

Calgary, Alberta (July 29, 2010) – Cenovus Energy Inc. (TSX, NYSE: CVE) continued to deliver strong production growth from its oil sands operations with a 42% production increase at Foster Creek and Christina Lake in the second quarter of 2010 compared with the same period last year. Operating performance exceeded the company’s expectations with production ahead of guidance and the company’s operating and capital expenditures below what was anticipated for half way through the year.

Cenovus’s conventional oil and natural gas properties remain a reliable source of cash flow with solid returns from modest capital expenditures. In the second quarter, these established assets delivered about $400 million of operating cash flow above the capital invested in them.

Overall cash flow for the second quarter was $537 million, in line with the company’s guidance although $408 million less compared with the same period last year. This 43% decrease was due to weaker realized natural gas prices, higher oil sands royalties and lower downstream operating cash flow.

Cenovus’s realized natural gas price in the second quarter of 2010 was $5.00 per thousand cubic feet (Mcf) compared with $8.13/Mcf in the second quarter of 2009. That resulted from a $182 million lower realized after-tax hedging gain in the second quarter of 2010 compared to the same period in 2009. Expected declines in natural gas production also had an impact on cash flow, as did higher royalty payments at Foster Creek due to the operation reaching payout in February. In the second quarter of 2010, Foster Creek royalties, net to Cenovus, were $45 million compared with $2 million in the same period of 2009.

Downstream operating cash flow was $202 million lower in the second quarter of 2010 compared with the same period of 2009. Approximately $180 million of that decrease is attributed to additional crude costs determined using first in, first out inventory valuation method. The refineries also experienced lower crude utilization in the second quarter of 2010 due to planned turnarounds and refinery optimization, which resulted in an estimated $25 million of reduced cash flow compared to the same period of 2009.

Cenovus is already one of the lowest cost oil sands producers and the company further improved in the second quarter of 2010 with non-fuel operating costs for Foster Creek and Christina Lake decreasing 14% to less than $9.00/bbl compared with the same period last year. The company’s focus on innovation is expected to reduce those costs even more over time as new technologies lead to improved efficiency and reduced expenses.

“Our focus at Cenovus is on developing the tremendous oil resource in our portfolio,” Ferguson said. “This was an exciting second quarter as we announced our 10 year business plan and set measurable goals to achieve it. We’re now taking action with regulatory applications for emerging projects, increased assessment drilling on undeveloped lands and efforts to advance timelines for expansions of existing oil operations. These steps are expected to help us achieve oil sands production of 300,000 barrels per day net to Cenovus by the end of 2019.”

Next major project submitted for regulatory approval

An application for Cenovus’s Narrows Lake project was submitted to the ERCB and Alberta Environment at the end of the second quarter. Narrows Lake is near the company’s Christina Lake operation, about 160 kilometres southeast of Fort McMurray. It is jointly owned with ConocoPhillips and is expected to be developed in two or three phases with a gross production capacity of 130,000 bbls/d and an anticipated project life of 30 years.

Cenovus Energy Inc.	2
Second Quarter 2010 Interim Report	News Release

Narrows Lake is the first commercial oil sands project application that includes the potential to use solvent aided process (SAP) along with steam assisted gravity drainage (SAGD). SAP involves the injection into the reservoir of a solvent, such as butane, along with the steam. This process increases production, improves ultimate recovery potential and lowers operating costs by reducing the amount of steam needed for each barrel of oil produced. Less steam means less natural gas is needed, which results in fewer emissions per barrel of oil as well as reduced water and land use. If the approval process proceeds as anticipated, Narrows Lake could begin producing oil in 2016.

Plans to expand production in the Greater Pelican Region

Cenovus is taking steps to increase production from its 100% owned property in the Greater Pelican Region, about 300 kilometres north of Edmonton. The company is anticipating eventual production from three separate geological formations in the region.

The existing polymer flood operation is producing more than 23,000 bbls/d of oil from the Wabiskaw formation, which is at depths of between 300 and 400 metres. Cenovus expects to increase production from this formation to 35,000 bbls/d by 2014 with moderate capital investment for additional in-fill wells and expansion of the polymer flood.

Cenovus is evaluating the best method to access oil from the Grand Rapids formation, located above the Wabiskaw formation at depths of between 220 and 270 metres. During the second quarter, ERCB approval was received to proceed with a single well pair SAGD pilot in the Grand Rapids. The test is expected to begin by the end of 2010, pending approval from Alberta Environment. A regulatory application for a commercial SAGD operation is expected to be filed by the end of 2011. The Grand Rapids project has a potential production capacity of 180,000 bbls/d. If the test and regulatory process proceed as planned, the Grand Rapids project could begin production in 2017.

A third formation, the Grosmont, is located below the Grand Rapids and Wabiskaw at depths ranging from 300 to 600 metres below ground. The Grosmont is a carbonate formation and Cenovus is assessing which production method would best enable development of this large resource before initiating a pilot.

Assessment work moving ahead on undeveloped lands

Cenovus is following through with its plan to further assess the company’s undeveloped oil sands assets with a stratigraphic well drilling program of 400 to 500 wells in each of the next five years. These assessment wells will provide reservoir data to support the next phases of development at the current operations and contribute to the regulatory review process for emerging projects. So far in 2010, Cenovus has drilled more than 200 stratigraphic wells, including those on land jointly held with ConocoPhillips. About 40 more stratigraphic wells are planned for later this year. Continued assessment work will help move a greater percentage of Cenovus’s 137 billion barrels of total bitumen initially-in-place into the discovered sub-category. An independent assessment of the company’s oil sands assets during the second quarter showed 56 billion barrels of discovered bitumen initially-in-place at the end of 2009.

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. All numbers are net to Cenovus unless otherwise stated. See the Advisory for a description of the non-GAAP measures and oil and gas definitions used in this interim report.

Cenovus Energy Inc.	3
Second Quarter 2010 Interim Report	News Release

Oil Sands Operations

(Before royalties) (Mbbls/d)	Daily Production
		2010				2009			2008
	YTD	Q2	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Foster Creek	51	51	51	38	47	40	35	29	26
Christina Lake	8	8	7	7	7	6	7	7	4
Total1	59	59	59	44	54	47	41	35	30

1 Totals may not add due to rounding.

Foster Creek and Christina Lake

Cenovus’s oil sands properties in northern Alberta represent the company’s most significant opportunity for substantial near term growth. Cenovus’s producing oil sands projects, Foster Creek and Christina Lake, use specialized methods, such as SAGD, to drill and pump the oil to the surface. The projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus continues to advance technologies in its oil sands operations that reduce the amount of water, natural gas and electricity used and minimize land disturbance.

Production

·Foster Creek produced more than 51,000 bbls/d in the second quarter of 2010, up from nearly 35,000 bbls/d during the same period last year – a 47% increase. The production growth is mainly attributed to the continued ramp up of phases D and E, which began production late in the first quarter of 2009, combined with increased production from wedge wells and well optimization. About 14% of current production at Foster Creek comes from wedge wells. These horizontal wells are drilled between existing SAGD well pairs. They reach oil that would have otherwise been stranded, which improves recovery rates by about 10% with minimal or no additional steam required. Thirteen new wedge wells are planned for Foster Creek in the second half of 2010, in addition to the 36 drilled to date, of which 31 are producing. One wedge well is now operating at Christina Lake and two more are planned for 2010.

·Production at Christina Lake increased by 18% to nearly 8,000 bbls/d in the second quarter compared with the same period in 2009. This is primarily a result of the ramp up of production from the phase B expansion in addition to well and operations optimization.

Expansions

·Construction is progressing as planned on Christina Lake phases C and D, which will each add 40,000 bbls/d of gross production capacity.

·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 next expansions at Foster Creek (phase F) and Christina Lake (phase E) are expected to proceed by as much as a year earlier than initially planned pending timely regulatory and partner approvals. First production at both phases is now anticipated in 2014.

Costs

·Operating costs at Foster Creek and Christina Lake averaged $11.17/bbl in the second quarter of 2010, an 8% decline from $12.11/bbl in the second quarter of 2009, mainly due to higher production volumes and lower workovers, repairs and maintenance.

Cenovus Energy Inc.	4
Second Quarter 2010 Interim Report	News Release

·Non-fuel operating costs for Foster Creek and Christina Lake were $8.98/bbl in the second quarter of 2010 compared with $10.48/bbl in the second quarter of 2009, a 14% decrease.

·As a result of Foster Creek reaching payout for royalty purposes in February, its average royalty rate increased to 19% in the second quarter of 2010 compared with 1.5% in the second quarter of 2009. This meant that second quarter royalties, net to Cenovus, were $45 million in 2010 compared with $2 million in 2009.

·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 second quarter. This means 2.3 barrels of steam are needed for every barrel of oil produced. A lower SOR means less natural gas is burned to create the steam, which results in fewer emissions, lower water usage and reduced costs.

Future Projects

·A joint regulatory application for the Narrows Lake project, co-owned with ConocoPhillips, was filed with the ERCB and Alberta Environment at the end of the second quarter. The application is the first to include the option of using a combination of SAGD and SAP for oil production. Narrows Lake is expected to have gross production capacity of 130,000 bbls/d. The target date for first production is 2016.

·Cenovus received ERCB approval in June for a pilot to determine whether the Grand Rapids formation can be commercially produced using SAGD. This pilot falls under the company’s existing Pelican Lake operating license and is 100% owned by Cenovus. The company anticipates Alberta Environment approval of the pilot this summer.

·Additional information is being collected to support the regulatory application that was previously filed for the Telephone Lake project in the Borealis Region.

Downstream

Cenovus’s downstream operations include the Wood River refinery in Illinois and the Borger refinery in Texas, which are jointly owned with the operator, ConocoPhillips. In addition to the 25,000 bbls/d gross coking capacity at Borger, 65,000 bbls/d gross coking capacity is being added at Wood River with the coker and refinery expansion (CORE) project to increase the total gross coking capacity at Wood River to 83,000 bbls/d. The CORE project was about 82% complete at the end of the second quarter and the total cost is expected to be within 10% of the US$3.6 billion budget (US$1.8 billion net to Cenovus). The project remains on track for a mid-2011 start up. It is anticipated this project will improve operating cash flow at Wood River by about US$200 million a year (net to Cenovus). With completion of the CORE project, Cenovus’s two refineries will have an increased ability to process a variety of crude feedstocks and produce a larger percentage of high value clean products. These refineries will have a combined capacity to process as much as 275,000 bbls/d of heavy crude oil.

·In the second quarter of 2010, the two refineries produced 398,000 bbls/d of refined products, down about 7% compared with the second quarter of 2009.

·Refinery crude utilization averaged 84% or 379,000 bbls/d of crude throughput, about 6% lower than in the same period a year ago, due to scheduled turnaround activity and refinery optimization.

·Operating cash flow for downstream operations in the second quarter of 2010 was a deficiency of $24 million, which was $202 million lower than the second quarter of 2009 mainly due to higher purchased product costs for crude oil using first in, first out inventory valuation method, as well as lower crude utilization.

Cenovus Energy Inc.	5
Second Quarter 2010 Interim Report	News Release

·The Keystone pipeline began deliveries from Alberta to Illinois at the end of the second quarter, allowing the Wood River refinery to source significant additional volumes of Canadian heavy crude oil.

Conventional Oil, Natural Gas Liquids (NGLs) and Natural Gas

(Before royalties)	Daily Production
		2010				2009			2008
	YTD	Q2	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Conventional Oil & NGLs1 (Mbbls/d)	71	70	72	77	75	80	76	79	82
Natural Gas (MMcf/d)	762	751	775	837	797	830	856	866	954

1 Includes production from Cenovus’s Senlac asset, sold in the fourth quarter of 2009, and other non-core assets, sold in the second quarter of 2010.

Cenovus has a large base of conventional oil and natural gas properties across Alberta and Saskatchewan. The oil operations include Pelican Lake (Wabiskaw formation) and Weyburn as well as production in southern Alberta and Saskatchewan. Cenovus’s natural gas properties in Alberta are established, reliable fields with efficient operations. The conventional assets are an important component of the company’s financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as a hedge against price fluctuations, because natural gas fuels the company’s oil sands and refining operations.

·Conventional oil production was about 70,000 bbls/d in the second quarter of 2010, in line with the company’s guidance. This was an 8% decrease compared with the same period last year, primarily as a result of expected natural declines and the sale of some properties, partially offset by new production in southern Alberta and southwestern Saskatchewan.

·The Lower Shaunavon oil asset in Saskatchewan is an early stage development opportunity for Cenovus. Production averaged about 460 bbls/d from nine wells during the second quarter, which was lower than expected due to weather related production restrictions. The company has commenced an additional 21 well drilling program in this area.

·The company has close to 200 prospective sections in the Bakken region of southern Saskatchewan. Development is in the early stages and Cenovus is currently evaluating the performance of a number of horizontal wells and expects to make decisions about drilling plans in the next few months.

·Operating costs for Cenovus’s conventional oil and liquids operations increased 30% to $12.80/bbl in the second quarter of 2010 compared with the same period last year, mainly due to a higher level of workover, repair and maintenance activity deferred from 2009 due to the economic uncertainty last year, increased chemical usage, higher electricity rates, as well as lower oil production. These operating costs remain within the company’s guidance range.

·Natural gas production was in line with guidance at 751 MMcf/d, a 12% decrease in the second quarter of 2010 compared with the same period in 2009. This is due to expected natural declines, weather delays and decreased production as Cenovus chose to postpone some drilling and tie-in work in 2009 in response to lower prices.

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

Cenovus Energy Inc.	6
Second Quarter 2010 Interim Report	News Release

Financial

Dividend

The Cenovus Board of Directors declared a third quarter dividend of $0.20 per share, payable on September 30, 2010, to common shareholders of record as of September 15, 2010. Based on the July 28, 2010, closing share price on the Toronto Stock Exchange of $29.97, this represents an annualized yield of about 2.7%. Declaration of dividends is at the sole discretion of the Board. Earlier this year, the Board approved a dividend reinvestment plan, which was made available to shareholders for the second quarter 2010 dividend. More information is available at www.cenovus.com.

Hedging Strategy

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

Cenovus’s hedging position at June 30, 2010, comprises:

·444 MMcf/d, or approximately 68% of expected 2010 net gas production, hedged at an average NYMEX price of US$6.12/Mcf

·29,100 bbls/d, or approximately 23% of expected 2010 oil production, hedged at an average WTI price of US$78.91/bbl and an additional 5,000 bbls/d, or approximately 4% of expected 2010 oil production, hedged at an average WTI price of C$89.65/bbl

·5,000 bbls/d of 2011 oil production hedged at an average WTI price of US$90.98/bbl and an additional 6,000 bbls/d hedged at an average WTI price of C$92.77/bbl

·351 MMcf/d of natural gas hedged for 2011 at an average NYMEX price of US$5.82/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 second quarter of 2010 were $64 million, down from $250 million in the second quarter of 2009, due to weaker 2010 natural gas average hedge prices.

In addition to 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 the natural gas Cenovus produces. This natural hedge is considered when determining the company’s financial hedging limits.

Financial Highlights

·Cash flow for the second quarter of 2010 was $537 million, down 43% from the same period in 2009, largely due to lower realized hedging gains and decreased downstream operating cash flow.

·Free cash flow was $107 million for the second quarter of 2010, $350 million lower than in the second quarter of 2009.

·Operating earnings were $142 million, or $0.19 per share, down 72% from the same period a year ago, reflecting the effects of decreased realized hedging gains and lower natural gas production, as well as increased crude oil purchased product costs, turnarounds and optimizations at the refineries. 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 Energy Inc.	7
Second Quarter 2010 Interim Report	News Release

·Cenovus’s net earnings in the second quarter were $172 million, slightly higher than the same quarter in 2009. Net earnings were impacted by an unrealized mark-to-market after-tax gain of $16 million, compared with an after-tax loss of $214 million in the second quarter of 2009, and an unrealized after-tax foreign exchange gain of $14 million, compared with an after-tax loss of $138 million in the second quarter of last year.

·Cenovus received an average realized price, including hedging, of $59.11/bbl for its oil, almost the same price as during the second quarter of last year. The average realized price, including hedging, for natural gas was $5.00/Mcf, 38% less than the second quarter of 2009, which had substantially higher hedging gains.

·Capital investment during the quarter was $430 million, a decrease of 12% compared with the second quarter of 2009, primarily due to poor weather that restricted access to Cenovus’s lands in southern Alberta and reduced downstream capital spending related to the CORE project. The downstream decrease was partially offset by increased spending on the Christina Lake expansion.

·Cenovus sold assets for proceeds of $72 million in the second quarter for a year-to-date divestiture total of $144 million. The company maintains a royalty interest in some of those properties. In addition, Cenovus recently signed a purchase and sale agreement providing for the disposition of certain non-core assets in southeastern Alberta and southwestern Saskatchewan that are currently producing approximately 37 MMcf/d of natural gas, for proceeds of $165 million before any closing adjustments. The transaction is subject to normal closing conditions and regulatory approvals and is expected to be completed in the third quarter of this year. Several other asset packages are currently being marketed and the company continues to assess its portfolio and may consider selling other non-core assets if market conditions are favourable. Small acquisitions of property were made in the second quarter to add to the company’s Narrows Lake and Wainwright oil assets.

·In June, 2010, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. A U.S. base shelf prospectus for unsecured notes in the amount of US$1.5 billion was filed in July. Each prospectus allows for the issuance, dependent on market conditions, of debt securities from time to time over a 25 month period.

·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 June 30, 2010, the company’s debt to capitalization ratio was 28% and debt to adjusted EBITDA, on a trailing 12 month basis, was 1.2 times. Both debt to capitalization and debt to adjusted EBITDA are non-GAAP measures as defined in the Advisory.

Earnings Reconciliation Summary
(for the period ended June 30) ($ millions, except per share amounts)	2010 Q2	2009 Q2	6 months 2010	6 months 2009
Net earnings Add back (losses) & deduct gains:	172	160	697	675
Unrealized mark-to-market hedging gain (loss), after-tax	16	-214	186	-150
Non-operating foreign exchange gain (loss), after-tax	14	-138	16	-101
Operating earnings1	142	512	495	926
Per share diluted	0.19	0.68	0.66	1.23

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

Cenovus Energy Inc.	8
Second Quarter 2010 Interim Report	News Release

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 Cenovus’s interim consolidated 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 views operating earnings as a better measure of performance than net earnings because the 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.

·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. Capitalization is a measure defined as debt plus shareholders’ equity. 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. Debt is defined as the current and long term portions of long term debt.

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. For further information, refer to Cenovus’s most recent Management’s Discussion and Analysis (MD&A) available at www.cenovus.com.

OIL AND GAS INFORMATION

The following estimates were prepared effective December 31, 2009 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE) and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further discussion regarding our economic contingent resources and our total bitumen initially-in-place and all subcategories thereof, see our April 22, 2010, news release and our June 16, 2010, news release, respectively, available at www.cenovus.com. Actual resources may be greater than or less than the estimates provided. All quantities expressed are best estimate. Total Bitumen Initially-In-Place (BIIP) (137 Bbbls) (equivalent to “total resources”) is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations.  It includes that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. Discovered Bitumen Initially-In-Place (56 Bbbls) (equivalent to “discovered resources”) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production.

Cenovus Energy Inc.	9
Second Quarter 2010 Interim Report	News Release

The recoverable portion of discovered bitumen initially-in-place includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the estimate. Undiscovered Bitumen Initially-In-Place (82 Bbbls) (equivalent to “undiscovered resources”) is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered.  The recoverable portion of undiscovered bitumen initially-in-place is referred to as “prospective resources,” the remainder as “unrecoverable”. There is no certainty that any portion of the estimate will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Contingent resources are quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. For Cenovus, the contingencies which must be overcome to enable the classification of bitumen contingent resources as reserves include regulatory application submission with no major issues raised, access to markets and intent to proceed by the operator and partners as evidenced by major capital expenditures planned within five years. Economic contingent resources (5.4 Bbbls) are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The IQRE used the same commodity price assumptions that were used for the 2009 reserves evaluation, which were determined in accordance with U.S. Securities and Exchange Commission requirements. The estimate of economic contingent resources has not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources.  Prospective resources (12.6 Bbbls) are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.  Prospective resources have both an associated chance of discovery and a chance of development.  Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Unrecoverable (49 Bbbls discovered; 69 Bbbls undiscovered) is that portion of discovered or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects.  A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Best estimate, when used in reference to contingent resources, is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The term “best estimate”, when used in reference to an “in-place” estimate, is not defined in COGEH; however, it was determined by the IQRE to the same 50% confidence level as was applied to previously disclosed estimates of 2P reserves and best estimate economic contingent resources.

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, our projected future value or net asset value, 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.

Cenovus Energy Inc.	10
Second Quarter 2010 Interim Report	News Release

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 752 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 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 Annual Information Form/Form 40-F and our annual and interim MD&A 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.

Cenovus Energy Inc.	11
Second Quarter 2010 Interim Report	News Release

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.

Cenovus Energy Inc.

Cenovus Energy Inc. is a Canadian, integrated oil company. It is committed to applying fresh, progressive thinking to safely and responsibly unlock energy resources the world needs. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and Saskatchewan. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. Its enterprise value is approximately $26 billion. For more information, visit www.cenovus.com.

Cenovus Energy Inc.	12
Second Quarter 2010 Interim Report	News Release

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 July 28, 2010, should be read with the unaudited Interim Consolidated Financial Statements for the period ended June 30, 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. Interim MD&As are approved by the Audit Committee of the Board of Directors of Cenovus (the “Board”), while the annual MD&A is approved by the Board.

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; Crude Oil, NGLs and Natural Gas Conversions; Currency; Abbreviations; Non-GAAP Measures; and References to Cenovus contained in the Advisory section at the end of this document.

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

INTRODUCTION AND OVERVIEW OF CENOVUS ENERGY

Cenovus is a Canadian oil company headquartered in Calgary, Alberta, which had a market capitalization of approximately $20 billion on June 30, 2010. In the second quarter of 2010, we had production of 253,733 BOE/d, 51 percent of which was crude oil and NGLs. Our operations include oil sands projects in northern Alberta, including Foster Creek and Christina Lake. These properties are located in the Athabasca region in northeast Alberta and use steam-assisted gravity drainage (“SAGD”) to extract crude oil. In southern Saskatchewan, we inject carbon dioxide (“CO2”) to enhance oil recovery at our Weyburn operation. We also have established crude oil and natural gas production in Alberta and Saskatchewan. In addition to our upstream assets, we have a 50 percent ownership 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 oil sands projects at Foster Creek and Christina Lake. We have proven our expertise and low cost oil sands development approach, while our established crude oil and natural gas production base is expected to generate reliable production and cash flows which will enable further development of our oil sands assets. In all of our operations, whether 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. Cenovus has a knowledgeable, experienced team committed to continuous innovation. 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 land position that we hold in the Athabasca region in northeast Alberta. In addition to our Foster Creek and Christina Lake oil sands projects, we currently have three emerging projects in this area: Grand Rapids, Telephone Lake and Narrows Lake.

During the second quarter of 2010, we received approval from the Energy Resources Conservation Board (“ERCB”) to begin a pilot project at our 100 percent owned Grand Rapids project, which is located within the Greater Pelican Region. We intend to commence the pilot project before the end of 2010.

We have a 100 percent working interest in the Telephone Lake property, in the Greater Borealis Region. A joint application and environmental impact assessment (“EIA”) has been submitted to the ERCB and Alberta Environment for the development of the property, including the construction of a facility with production capacity of 35,000 bbls/d.

We hold a 50 percent interest, through our interest in the FCCL Partnership, in the Narrows Lake property, which is located within the greater Christina Lake Region. In the first quarter of 2010, we initiated the regulatory approval process for Narrows Lake by filing proposed terms of reference for an EIA and began public consultation for the project. Final terms of reference were issued by Alberta Environment in the second quarter. A joint application and EIA was filed at the end of the second quarter of 2010. The project is expected to include gross production capacity of up to 130,000 bbls/d in three phases, with the first phase expected to add approximately 40,000 bbls/d.

We have a number of opportunities to deliver shareholder value, predominantly through production growth from our land position in the oil sands. Most of the oil sands resource is undeveloped. In the second quarter of 2010, we issued news releases that highlight more detailed information related to our bitumen economic contingent resources and bitumen initially-in-place enabling investors to more fully understand our inventory of oil sands assets. We also provided further information about our resources and development plans at our Investor Day presentations in June 2010. Our 10 year business plan is to grow our net oil sands production to 300,000 bbls/d by 2019. Growth is expected to be internally funded through cash flow generated from our established crude oil and natural gas production base where we also have opportunities to add production through new technologies. Our natural gas production provides a natural economic hedge for the natural gas required as a fuel source at both our upstream and downstream operations. Our refineries, which are operated by ConocoPhillips, an unrelated U.S. public company, enable us to mitigate commodity cycles by integrating our oil sands production with the sale of refined products. In addition to our strategy of growing net asset value as described here in, we will continue to pay meaningful dividends to deliver strong total shareholder return over the long term.

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

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 oil sands interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major oil sands projects: (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 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 crude oil, natural gas and natural gas liquids, 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, as well as several other emerging projects.

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

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

OVERVIEW OF THE SECOND QUARTER 2010

The specific financial and operating highlights of the second quarter of 2010 compared to the second quarter of 2009 are:

·Production from our Foster Creek and Christina Lake oil sands projects increased by 42 percent;

·Net revenues increased by 13 percent, primarily as a result of higher crude oil prices and higher crude oil production;

·Upstream Operating Cash Flow decreased by $306 million because of lower natural gas volumes and prices, offset by higher crude oil volumes and prices;

·Operating Cash Flow from Downstream Refining operations decreased by $202 million due to increased crude oil purchased product costs and reduced crude utilization as a result of planned turnarounds and refinery optimization;

·Realized financial hedging gains of $64 million, net of tax, compared to gains of $250 million, net of tax in 2009;

·Operating earnings decreased by $370 million, mostly due to lower Operating Cash Flows; and

·Declared and paid dividends of $150 million ($0.20 per share) in the second quarter of 2010.

The CORE project at Wood River continues to proceed with expected completion in mid-2011, with total costs expected to be within 10 percent of the US$3.6 billion budget (US$1.8 billion net to Cenovus). At June 30, 2010, construction on the CORE project was approximately 82 percent complete.

Work is currently progressing on the construction of Christina Lake phases C and D to assist in reaching our planned production goals. We are now targeting production from the next expansion phases at Foster Creek (phase F) and Christina Lake (phase E) to commence in 2014, one year earlier than initially planned. These accelerated planned production start dates are still pending timely regulatory and partner approvals.

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

To enable shareholders to understand our long-term growth potential, we released an independent evaluation of our bitumen economic contingent resources in April 2010 and our bitumen initially-in-place in June 2010. These evaluations, which were prepared by an independent qualified reserves evaluator, support management’s belief that Cenovus has significant long term development potential.

In order to provide financial flexibility in the future, we have recently established two debt programs by way of base shelf prospectus filings. The Canadian shelf prospectus allows us to offer, from time to time, an aggregate principal amount of up to $1.5 billion in unsecured medium term notes. The U.S. shelf prospectus allows us to offer, from time to time, an aggregate principal amount up to US$1.5 billion in unsecured notes. Each of the shelf prospectuses has a term of 25 months.

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:

(Average benchmark	Six Months Ended June 30		Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
prices)	2010	2009	2010	2010	2009	2009	2009	2009	2008	2008	2008
Crude Oil Prices (US $/bbl)
West Texas Intermediate (“WTI”)	78.46	51.68	78.05	78.88	76.13	68.24	59.79	43.31	59.08	118.22	123.80
Western Canada Select (“WCS”)	66.89	43.50	63.96	69.84	64.01	58.06	52.37	34.38	39.95	100.22	102.18
Differential – WTI/WCS	11.57	8.18	14.09	9.04	12.12	10.18	7.42	8.93	19.13	18.00	21.62
WCS as percent of WTI	85%	84%	82%	89%	84%	85%	88%	79%	68%	85%	83%
Refining Margin 3-2-1 Crack Spreads (1) (US $/bbl)
Chicago	8.86	10.35	11.60	6.11	5.00	8.48	10.95	9.75	6.31	17.29	13.60
Midwest Combined (Group 3)	9.10	9.39	11.38	6.82	5.52	8.06	9.16	9.62	6.00	14.38	13.47
Natural Gas Prices
AECO ($/GJ)	4.36	4.40	3.66	5.08	4.01	2.87	3.47	5.34	6.43	8.76	8.86
NYMEX (US $/MMBtu)	4.69	4.19	4.09	5.30	4.17	3.39	3.50	4.89	6.94	10.24	10.93
Basis Differential AECO/ NYMEX (US $/MMBtu)	0.25	0.37	0.32	0.19	0.19	0.67	0.39	0.35	1.10	1.28	1.71
Foreign Exchange
Average US/Canadian dollar Exchange Rate	0.967	0.829	0.973	0.961	0.947	0.911	0.857	0.803	0.825	0.961	0.990

(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 second quarter of 2010 saw large swings in the price of WTI. In early April the WTI spot price closed as high as US$86.84 per bbl but, impacted by the instability in global financial markets, deteriorated to a low of US$68.01 per bbl in late May before closing the quarter at US$75.63 per bbl. WTI averaged US$78.05 per bbl in the second quarter of 2010, consistent with the first quarter and approximately 31 percent higher than the same period in 2009. The average WTI price for the six months ended June 30, 2010 was approximately 52 percent higher than the same period in 2009, reflecting increased global crude oil demand, mainly from developing countries, and the effects of substantial cuts in OPEC production from 2008 which has resulted in decreased global inventory in 2010 when compared to 2009 levels.

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

WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. This blended heavy oil is usually traded at a discount to the light oil benchmark, WTI. The discount to WTI in the first two quarters of 2010 averaged US$11.57 per bbl which is wider than the same period last year. However, as a percentage of WTI, WCS remained consistent as the wider differential was offset by an increase in WTI prices. On a percentage basis, the differential in the second quarter of 2010 declined to recent historic average levels when compared with the previous quarter, attributable to the improvement in lighter crude oil demand, weak demand for heavy fuel oil in Asia and lower U.S. coker utilization due to poor economics. Compounding this global weakness was increased planned refinery maintenance in PADD II (Midwest U.S.) and increased unplanned upgrader outages in western Canada.

As shown in the table above, benchmark U.S. refining crack spreads improved in the second quarter of 2010 compared to the prior quarter as late May marks the beginning of summer driving season in North America, which historically has resulted in higher demand and higher prices for gasoline. Crack spreads for the second quarter of 2010 have improved compared to the same period in 2009 with the increase in consumer demand for refined products partly due to the improved economy in the United States. Consumer demand for refined products in the United States still remains below pre-recession levels.

In the second quarter of 2010, NYMEX natural gas prices improved over the second quarter of 2009 primarily due to the anticipation of hotter-than-normal summer weather and forecasts of an active hurricane season. Natural gas volumes in storage have decreased from the same period in 2009 but still remain well above the 5-year average.

During 2010, the Canadian dollar strengthened relative to the U.S. dollar, which increased the average exchange rate to 0.967 for the six months ended June 30, 2010 compared to 0.829 for the same period in 2009.

Our risk mitigation strategy has helped reduce our exposure to commodity price volatility. Realized hedging gains, after tax, in the second quarter were $64 million (year to date - $81 million). Further information regarding our hedging program can be found in the notes to the Interim Consolidated Financial Statements. Also, further information regarding the sensitivity of our 2010 financial results to changes in various benchmark prices can be found in our 2010 Corporate Guidance document which can be found on our website, www.cenovus.com.

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. 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.

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

SELECTED CONSOLIDATED FINANCIAL RESULTS

(millions of Canadian dollars, except per	Six Months Ended June 30		Q2	Q1	Q4		Q3	Q2	Q1	Q4		Q3	Q2
share amounts)	2010	2009	2010	2010	2009		2009	2009	2009	2008		2008	2008
Net Revenues	6,686	5,511	3,195	3,491	3,005		3,001	2,818	2,693	3,946		5,753	4,424
Operating Cash Flow (1)	1,503	2,101	665	838	954		1,134	1,173	928	121		1,176	1,535
Cash Flow (1)	1,258	1,686	537	721	235		924	945	741	(209	)	1,161	1,244
- per share – diluted (2)	1.67	2.25	0.71	0.96	0.31		1.23	1.26	0.99	(0.28	)	1.54	1.66
Operating Earnings (1)	495	926	142	353	169		427	512	414	(159	)	623	722
- per share – diluted (2)	0.66	1.23	0.19	0.47	0.23		0.57	0.68	0.55	(0.21	)	0.82	0.96
Net Earnings	697	675	172	525	42		101	160	515	490		1,341	528
- per share – basic (2)	0.93	0.90	0.23	0.70	0.06		0.13	0.21	0.69	0.65		1.79	0.71
- per share – diluted (2)	0.93	0.90	0.23	0.70	0.06		0.13	0.21	0.69	0.65		1.78	0.71
Capital Investment	923	1,140	430	493	507		515	488	652	760		487	438
Free Cash Flow (1)	335	546	107	228	(272	)	409	457	89	(969	)	674	806
Cash Dividends (3)	300	-	150	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 each of the first and second quarters of 2010 and US$0.20 per share in the fourth quarter of 2009. The fourth quarter 2009 dividend reflected an amount determined in connection with the Arrangement based on carve-out earnings and cash flow.

NET REVENUES VARIANCE

(millions of Canadian dollars)		Three months ended				Six months ended
Net Revenues for the Periods Ended June 30, 2009			$	2,818			$	5,511
Increase (decrease) due to:
Upstream Canada	Price		28				364
	Realized hedging		(268		)		(543		)
	Volume		27				45
	Royalties		(70		)		(138		)
	Other (1)		278				573
Downstream Refining			84				448
Corporate	Unrealized hedging		314				450
	Other		(16		)		(24		)
Net Revenues for the Periods Ended June 30, 2010			$	3,195			$	6,686

(1) Revenue dollars reported include the value of condensate sold as bitumen or heavy oil blend. Condensate costs are recorded in transportation and selling expense.

Net Revenues increased in the second quarter of 2010 and the six months ended June 30, 2010, primarily because of higher crude oil production volumes and prices partially offset by lower natural gas volumes and realized prices and higher royalties. Downstream Refining Net Revenues increased due to higher refined product prices partially offset by reduced volumes. Net Revenues also include unrealized hedge gains which increased in the second quarter and year over year. Further information and explanations regarding our Net Revenues can be found in the Divisional Results and Corporate and Eliminations sections of this MD&A.

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

OPERATING CASH FLOW

	Three Months Ended June 30						Six Months Ended June 30
(millions of Canadian dollars)		2010			2009			2010			2009
Crude Oil and NGLs
Foster Creek and Christina Lake		$	176		$	162		$	391		$	233
Canadian Plains		234			275			543			454
Natural Gas		268			555			582			1,149
Other Upstream Operations		11			3			17			14
		689			995			1,533			1,850
Downstream Refining		(24		)	178			(30		)	251
Operating Cash Flow		$	665		$	1,173		$	1,503		$	2,101

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. It 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. Operating Cash Flow excludes unrealized hedging gains and losses which are included in the Corporate and Eliminations segment.

Three Months Ended June 30, 2010 compared to 2009

While we have seen increases in our Net Revenues in the three and six month periods in 2010, as shown above, Operating Cash Flows from our Upstream Canada segment decreased by $306 million in the second quarter of 2010 as a result of lower netbacks for natural gas resulting from decreased production and realized natural gas prices and lower netbacks for crude oil resulting from increased production volume and prices offset by higher royalties. Operating Cash Flows from our Downstream Refining segment decreased $202 million mainly due to increased crude oil purchased product costs and reduced crude utilization as a result of planned turnarounds and refinery optimization. Details of the components that explain this decrease can be found in the Divisional Results section of this MD&A.

Cenovus Energy Inc.	19
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2010 compared to 2009

Operating Cash Flows for the six months ended June 30, 2010 decreased by $598 million. Upstream Canada decreased $317 million because of lower netbacks for natural gas resulting from decreased realized natural gas prices and production offset by higher netbacks for crude oil resulting from increased prices and production offset by higher royalties. Operating Cash Flows for Downstream Refining decreased $281 million due to increased crude oil purchased product costs and reduced crude utilization as a result of planned turnarounds and refinery optimization. Details of the components that explain this decrease 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 June 30							Six Months Ended June 30
(millions of Canadian dollars)		2010			2009				2010			2009
Cash From Operating Activities		$	471		$	793			$	1,291		$	1,475
(Add back) deduct:
Net change in other assets and liabilities		(13		)	(6		)		(28		)	(9		)
Net change in non-cash working capital		(53		)	(146		)		61			(202		)
Cash Flow		$	537		$	945			$	1,258		$	1,686

Three Months Ended June 30, 2010 compared to 2009

In the second quarter of 2010 Cash Flow decreased $408 million primarily due to:

·A 38 percent decrease in the realized average natural gas price, including the impact of hedges, to $5.00 per Mcf compared to $8.13 per Mcf;

·A decrease in operating cash flow from downstream operations of $202 million;

·An increase in Royalties of $70 million primarily as a result of Foster Creek achieving royalty payout and higher crude oil prices;

·Natural gas production declined 12 percent;

·Higher crude oil and NGLs operating costs consistent with the increase in production; and

·An increase in General and administrative and net interest expenses of $16 million.

Cenovus Energy Inc.	20
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

The decreases in our second quarter 2010 Cash Flow were offset by:

·A $136 million decrease in current income tax expense primarily due to lower realized hedging gains and lower earnings from our downstream operations; and

·A 10 percent increase in our crude oil and NGLs production volumes.

Six Months Ended June 30, 2010 compared to 2009

Cash Flow for the six months ended June 30, 2010 decreased $428 million mainly due to:

·A 37 percent decrease in the realized average natural gas price, including the impact of hedges, to $5.40 per Mcf compared to $8.52 per Mcf;

·A decrease in operating cash flow from downstream operations of $281 million;

·An increase in Royalties of $138 million, primarily as a result of Foster Creek achieving payout and higher crude oil prices;

·Natural gas production declined 11 percent;

·Higher crude oil and NGLs operating costs consistent with the increase in production; and

·An increase in General and administrative and net interest expenses of $47 million.

The Cash Flow decreases above were offset by:

·A 24 percent increase in the realized average liquids selling price, including the impact of hedges, to $63.53 per bbl compared to $51.35 per bbl;

·Current income tax expense decreased $219 million primarily due to lower realized hedging gains and lower earnings from our downstream operations; and

·A 12 percent increase in our crude oil and NGLs production volumes.

OPERATING EARNINGS

(millions of Canadian dollars)	Three Months Ended June 30						Six Months Ended June 30
		2010		2009				2010		2009
Net Earnings, as reported		$	172	$	160			$	697	$	675
(Add back) deduct:
Unrealized mark-to-market accounting gain (loss), after-tax (1)		16		(214		)		186		(150		)
Non-operating foreign exchange gain (loss), after-tax (2)		14		(138		)		16		(101		)
Operating Earnings		$	142	$	512			$	495	$	926

(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.

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 non-operating foreign exchange 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.

The declines in our Operating Earnings for the three and six months ended June 30, 2010 compared to 2009 were consistent with the decreases to our Operating Cash Flow and Cash Flow, details of which can be found above.

Cenovus Energy Inc.	21
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

NET EARNINGS VARIANCE

(millions of Canadian dollars)	Three Months Ended				Six Months Ended
Net Earnings for the Periods Ended June 30, 2009		$	160			$	675
Increase (decrease) due to:
Net revenues		377				1,175
Expenses:
Transportation and selling		(107		)		(232		)
Purchased product		(463		)		(1,092		)
Other expenses (1)		89				40
Depreciation, depletion and amortization		57				113
Income taxes		59				18
Net Earnings for the Periods Ended June 30, 2010		$	172			$	697

(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 second quarter of 2010 increased by $12 million compared to the second quarter of 2009. The items identified above that reduced our Cash Flow in the second quarter also reduced our Net Earnings. There were other significant factors that increased our second quarter 2010 Net Earnings including:

·Unrealized mark-to-market gain, after-tax, of $16 million, compared to a $214 million loss, after-tax, in the second quarter of 2009;

·Unrealized foreign exchange loss of $31 million in the second quarter of 2010 compared to a loss in the second quarter of 2009 of $160 million;

·A decrease of $57 million in Depreciation, depletion and amortization (“DD&A”); and

·Future income tax recovery, excluding the impact of the unrealized financial hedging gains, in the second quarter of 2010 of $10 million, compared to a future income tax expense of $2 million in 2009.

For the six months ended June 30, 2010 Net Earnings increased by $22 million when compared to the same period in 2009. The items previously discussed that reduced our Cash Flow for the six months ended June 30, 2010 also reduced our Net Earnings. There were other significant factors that impacted our 2010 Net Earnings including:

·Unrealized mark-to market gain, after-tax of $186 million compared to a loss, after-tax of $150 million in 2009;

·DD&A expense decrease of $113 million;

·Unrealized foreign exchange gain of $1 million for year to date 2010 compared to a loss of $107 million in 2009; and

·Future income tax expense, excluding the impact of the unrealized financial hedging gains, of $23 million, compared to a future income tax recovery of $44 million in 2009.

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. Overall our hedging program has had a positive effect on Net Earnings. The following information has been provided in order to provide information that is more comparable between periods:

	Three Months Ended June 30						Six Months Ended June 30
(millions of Canadian dollars)		2010		2009				2010		2009
Unrealized Mark-to-Market Gains (Losses), after-tax (1)		$	16	$	(214	)		$	186	$	(150	)
Realized Hedging Gains (Losses), after-tax (2)		64		250				81		448
Hedging Impacts in Net Earnings		$	80	$	36			$	267	$	298

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

NET CAPITAL INVESTMENT

	Three Months Ended June 30							Six Months Ended June 30
(millions of Canadian dollars)		2010			2009				2010			2009
Integrated Oil - Upstream		$	147		$	122			$	298		$	277
Canadian Plains		102			99				241			334
Downstream Refining		168			265				370			517
Other		13			2				14			12
Capital Investment		430			488				923			1,140
Acquisitions		47			1				47			1
Divestitures		(72		)	(3		)		(144		)	(3		)
Net Capital Investment		$	405		$	486			$	826		$	1,138

Capital investment for both the three and six months ended June 30, 2010 were primarily focused on the continued development of our Integrated Oil – Upstream oil sands projects and Canadian Plains oil properties, 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 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

We continued with our planned program to divest of non-core assets in the second quarter of 2010 and sold certain Canadian Plains producing properties for net proceeds of $67 million while at the same time retaining our royalty interest in the area.

Acquisitions of $47 million in the second quarter of 2010 included the purchase of an interest in three sections of undeveloped land at Narrows Lake. Subsequent to June 30, 2010, we reached an agreement to transfer these lands to the FCCL Partnership. Other acquisitions during the second quarter included the purchase of undeveloped land and producing properties in our Canadian Plains Division.

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 and reduced our working interest in Narrows Lake 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.

	Three months ended June 30					Six months ended June 30
(millions of Canadian dollars)		2010		2009			2010		2009
Cash Flow		$	537	$	945		$	1,258	$	1,686
Capital Investment		430		488			923		1,140
Free Cash Flow		$	107	$	457		$	335	$	546

Cenovus Energy Inc.	23
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

In the second quarter of 2010, Free Cash Flow was $350 million lower than the same period in 2009, while for the first six months of 2010, Free Cash Flow decreased by $211 million. Explanations for the decrease in Cash Flow and Capital Investment are discussed under the Cash Flow, Net Capital Investment and Divisional Results sections of this MD&A.

RESULTS OF OPERATIONS

Crude Oil and NGLs Production Volumes

	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
(bbls/d)	2010	2010	2009	2009	2009	2009	2008	2008	2008
Crude Oil
Foster Creek	51,010	51,126	47,017	40,367	34,729	28,554	29,241	27,289	21,244
Christina Lake	7,716	7,420	7,319	6,305	6,530	6,635	6,170	4,620	3,670
Weyburn	18,043	17,722	18,536	18,354	18,368	18,028	17,408	17,634	17,178
Pelican Lake	23,319	23,565	23,804	25,671	23,989	26,029	24,975	27,826	27,306
Southern Alberta	22,458	23,790	23,729	23,895	24,089	25,404	25,509	25,654	27,041
Canadian Plains – Other	4,854	5,770	5,506	5,573	5,806	5,862	6,090	6,166	6,470
Integrated Oil – Senlac	-	-	2,221	5,080	2,574	2,334	2,623	3,135	3,281
NGLs	1,166	1,156	1,183	1,242	1,184	1,213	1,158	1,167	1,204
	128,566	130,549	129,315	126,487	117,269	114,059	113,174	113,491	107,394

When compared to the same periods in 2009, overall crude oil and NGLs production increased 10 percent in the second quarter and 12 percent year to date to 129,551 bbls/d. Quarterly production volumes increased 47 percent at Foster Creek (year to date – 61 percent) and 18 percent at Christina Lake (year to date – 15 percent). These increases were partially offset by declines at our other properties, as well as the sale of certain non-core properties in the second quarter of 2010 and our Senlac property in the fourth quarter of 2009. Further detail on the changes in our production between the periods can be found in the Divisional Results section of this MD&A.

Natural Gas Production Volumes

	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
(MMcf/d)	2010	2010	2009	2009	2009	2009	2008	2008	2008
Southern Alberta	676	699	719	741	761	777	803	815	838
Canadian Plains – Other	32	34	34	37	41	39	40	44	48
Integrated Oil – Other	43	42	44	52	54	50	62	88	99
	751	775	797	830	856	866	905	947	985

When compared to the same periods in 2009, overall natural gas production decreased 12 percent in the second quarter and 11 percent year to date to 762 MMcf/d. Quarterly production volumes declined 11 percent in Southern Alberta (year to date – 11 percent) compared to the same quarter of 2009. The production decline was the result of expected natural production declines, as well as the cumulative impact of lower capital spending on natural gas drilling and tie-in activity throughout 2009 and weather related delays in the first half of 2010. Further detail on our year to date production can be found in the Divisional Results section of this MD&A.

Cenovus Energy Inc.	24
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Operating Netbacks - Quarter

	Three Months Ended June 30
	2010						2009
	Liquids			Natural Gas			Liquids		Natural Gas
	($/bbl)			($/Mcf)			($/bbl)		($/Mcf)
Price	$	59.50		$	3.78		$	57.81	$	3.80
Royalties	9.93			0.07			5.14		0.01
Production and mineral taxes	0.71			(0.04		)	0.61		0.07
Transportation and selling	1.94			0.15			1.98		0.16
Operating expenses	12.07			0.94			10.61		0.83
Netback excluding Realized Financial Hedging	34.85			2.66			39.47		2.73
Realized Financial Hedging Gain (Loss)	(0.40		)	1.22			1.54		4.33
Netback including Realized Financial Hedging	$	34.45		$	3.88		$	41.01	$	7.06

Our 2010 second quarter average netback for liquids, excluding realized financial hedging, decreased by $4.62 per bbl. The decrease was mostly related to higher royalties and partly due to higher operating expenses. Our average netback for natural gas, excluding realized financial hedging, was consistent with 2009.

Operating Netbacks – Year to Date

	Six Months Ended June 30
	2010					2009
	Liquids			Natural Gas		Liquids		Natural Gas
	($/bbl)			($/Mcf)		($/bbl)		($/Mcf)
Price	$	64.11		$	4.53	$	48.97	$	4.64
Royalties	9.37			0.11		4.11		0.08
Production and mineral taxes	0.65			0.02		0.77		0.06
Transportation and selling	1.87			0.18		1.84		0.17
Operating expenses	11.75			0.94		11.13		0.88
Netback excluding Realized Financial Hedging	40.47			3.28		31.12		3.45
Realized Financial Hedging Gain (Loss)	(0.58		)	0.87		2.38		3.88
Netback including Realized Financial Hedging	$	39.89		$	4.15	$	33.50	$	7.33

In the first six months of 2010, our average netback for liquids, excluding realized financial hedging, increased by $9.35 per bbl primarily due to an increase in prices partially offset by higher royalties. Our average netback for natural gas, excluding realized financial hedges, was consistent with 2009.

Further discussions of operating results are contained in the Divisional Results section of this MD&A.

As part of ongoing efforts to maintain financial resilience and flexibility, we reduced our pricing risk through a commodity price hedging program. Further information regarding this program can be found in the notes to the Interim Consolidated Financial Statements.

Cenovus Energy Inc.	25
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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, Christina Lake and Narrows Lake oil sands projects in northeast Alberta, while the downstream entity includes the Wood River and Borger refineries located in Illinois and Texas, USA, respectively.

Highlights of the second quarter include significant increases in production at both Foster Creek and Christina Lake, as well as significant progress related to the development of our other oil sands projects.

FOSTER CREEK AND CHRISTINA LAKE

Financial Results

	Three Months Ended June 30					Six Months Ended June 30
(millions of Canadian dollars)	2010		2009			2010		2009
Revenues	$	510	$	309		$	1,030	$	485
Deduct (add)
Realized financial hedging (gain) loss	3		(16		)	8		(45		)
Royalties	46		2			73		3
Net revenues	461		323			949		527
Expenses
Transportation and selling	224		116			437		199
Operating	61		45			121		95
Operating Cash Flow	$	176	$	162		$	391	$	233

Production Volumes

	Three Months Ended June 30			Six Months Ended June 30
Crude oil (bbls/d)	2010	2010 vs2009	2009	2010	2010 vs 2009	2009
Foster Creek	51,010	47%	34,729	51,067	61%	31,658
Christina Lake	7,716	18%	6,530	7,569	15%	6,582
	58,726	42%	41,259	58,636	53%	38,240

Cenovus Energy Inc.	26
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Production Volumes by Quarter

Net Revenues Variance

Three Months Ended June 30, 2010 compared to 2009

	Three Months Ended June 30, 2009	Net Revenue Variances in:				Three Months Ended June 30, 2010
(millions of Canadian dollars)	Net Revenues	Price(1)	Volume	Royalties	Other(2)	Net Revenues
Foster Creek and Christina Lake	$       323	(19)	94	(44)	107	$         461

(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.

In the second quarter the average crude oil sales price, excluding realized financial hedges, of $54.78 per bbl was consistent with the 2009 price of $54.88 per bbl. Although the price of WCS in 2010 was higher than 2009, it was offset by a shift in condensate prices trading at a premium to WTI in the second quarter of 2010 compared to a discount in the same quarter of 2009. In the second quarter of 2010, financial hedging activities resulted in a realized loss of $3 million ($0.47 per bbl) compared to a gain of $16 million ($4.41 per bbl) in the second quarter of 2009.

Production at Foster Creek increased 47 percent in the second quarter of 2010 compared to 2009 as a result of the ramp up of production from the phase D and E expansions combined with well optimizations and increased production from wedge wells. Second quarter production at Christina Lake increased 18 percent compared to 2009 as a result of the ramp up of production from the phase B expansion and well optimizations.

Royalties in the second quarter of 2010 increased by $44 million compared to the same period in 2009 as Foster Creek achieved royalty payout status in the first quarter of 2010 and higher WTI prices resulted in higher royalty rates. Further information regarding the financial impact of achieving royalty payout status can be found in our MD&A for the three months ended March 31, 2010. For the second quarter of 2010, the effective royalty rate for Foster Creek was 19.0 percent compared to 1.5 percent in the second quarter of 2009. For Christina Lake, the royalty rate was 4.4 percent in the second quarter of 2010 compared to 1.6 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 second quarter of 2010, our condensate volumes increased directly due to the higher production volumes. Our condensate costs were also higher due to a 33 percent increase in the average cost of condensate. This resulted in transportation and selling costs increasing to $224 million in the second quarter of 2010 from $116 million in the second quarter of 2009.

Operating costs increased to $61 million in the second quarter of 2010 compared to $45 million in 2009 due to an increase in purchased fuel volumes, as well as higher chemical costs and increased field personnel as a result of higher production.

Cenovus Energy Inc.	27
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2010 compared to 2009

	Six Months Ended June 30, 2009		Net Revenue Variances in:				Six Months Ended June 30, 2010
(millions of Canadian dollars)	Net Revenues		Price(1)	Volume	Royalties	Other(2)	Net Revenues
Foster Creek and Christina Lake		$       527	90	170	(70)	232	$         949

(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.

In the first six months our average crude oil sales price, excluding realized financial hedges, increased 30 percent to $58.83 per bbl compared to the same period in 2009 consistent with the price of WCS increasing year over year. Financial hedging activities for the first half of 2010 resulted in a realized loss of $8 million ($0.72 per bbl) compared to a gain of $45 million ($6.76 per bbl) in 2009.

Foster Creek production increased 61 percent for the six months ended June 30, 2010 compared to 2009 primarily as a result of the phase D and E expansions which commenced production late in the first quarter of 2009 combined with well optimizations and increased production from wedge wells. The 15 percent increase in production at Christina Lake for the first six months of 2010 compared to 2009 was a result of the ramp up of production from the phase B expansion and well optimizations.

Year to date royalties increased by $70 million compared to the same period in 2009 with Foster Creek achieving royalty payout status in the first quarter of 2010 along with a higher WTI price resulting in higher royalty rates. In the first half of 2010, the effective royalty rate for Foster Creek was 14.5 percent (2009 - 1.4 percent) and for Christina Lake was 4.2 percent (2009 – 1.3 percent).

Transportation and selling costs comprised mostly of condensate costs, which increased to $437 million in the first six months of 2010, as the volume of condensate required increased due to the higher production noted above and the average cost of condensate increased 42 percent.

Operating costs for the first six months of 2010 increased to $121 million compared to $95 million for the same period in 2009 due to increased purchased fuel volumes, as well as higher chemical costs and increased field personnel as a result of higher production.

DOWNSTREAM REFINING

Financial Results

	Three Months Ended June 30					Six Months Ended June 30
(millions of Canadian dollars)	2010			2009		2010			2009
Revenues	$	1,610		$	1,526	$	3,128		$	2,680
Expenses
Operating	110			129		249			276
Purchased product	1,524			1,219		2,909			2,153
Operating Cash Flow	$	(24	)	$	178	$	(30	)	$	251

Cenovus Energy Inc.	28
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Refinery Operations (1)

	Three Months Ended June 30		Six Months Ended June 30
	2010	2009	2010	2009
Crude oil capacity (Mbbls/d)	452	452	452	452
Crude oil runs (Mbbls/d)	379	404	367	401
Crude utilization (%)	84	89	81	89
Refined products (Mbbls/d)	398	428	388	425

(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 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 second quarter of 2010, our refineries operated at an average of 84 percent (year to date – 81 percent) of their capacity compared to 89 percent in the second quarter of 2009 (year to date – 89 percent). Utilization is lower in 2010 primarily due to planned turnarounds at the Wood River and Borger refineries and refinery optimization.

Market prices for refined products increased in the second quarter of 2010, which were partially offset by reduced volumes as a result of planned turnarounds in the quarter resulting in a six percent increase in Revenues between periods. Revenues for the six months ended June 30, 2010 compared to 2009 increased by 17 percent driven by increased refined product pricing consistent with increases in the benchmark prices. Purchased product costs, which are determined on a first-in, first-out basis, increased 25 percent in the second quarter of 2010 and year to date 35 percent compared to the same periods in 2009. Purchased product, consisting mainly of crude oil, represented 93 percent of total expenses in the second quarter of 2010 compared to 90 percent in the second quarter of 2009 and 92 percent of total expenses for the first six months of 2010 compared to 89 percent in 2009.

Operating costs, consisting mainly of labour, utilities and supplies, decreased 15 percent in the second quarter of 2010 and decreased by 10 percent for the six months ended June 30, 2010 due to the strengthening of the average Canadian dollar exchange rates in the periods offset by costs related to the turnarounds at both refineries and higher prices for utilities consumed at the refineries.

Operating Cash Flow for the second quarter of 2010 was $202 million lower than the second 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 planned turnarounds at both Wood River and Borger and lower refinery utilization. 2010 year to date Operating Cash Flow decreased by $281 million mainly due to the same factors that affected the change between second quarters.

INTEGRATED OIL DIVISION - OTHER PROPERTIES

The Integrated Oil Division also manages our 100 percent owned natural gas operations in Athabasca. Primarily as a result of natural declines, our production from Athabasca in the second quarter of 2010, decreased to 43 MMcf/d (2009 – 54 MMcf/d) and for the first six months of 2010 decreased to 42 MMcf/d (2009 – 52 MMcf/d). In the fourth quarter of 2009, we sold our Senlac heavy oil assets. Senlac production in the second quarter of 2009 was 2,574 bbls/d and for the first six months of 2009 was 2,455 bbls/d.

Cenovus Energy Inc.	29
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

INTEGRATED OIL DIVISION - CAPITAL INVESTMENT

	Three Months Ended June 30				Six Months Ended June 30
(millions of Canadian dollars)	2010		2009		2010		2009
Upstream
Foster Creek	$	52	$	59	$	109	$	124
Christina Lake	84		49		147		105
Other	11		14		42		48
	147		122		298		277
Downstream Refining
Wood River	140		239		321		470
Borger	28		26		49		47
	168		265		370		517
Total Integrated Oil Division	$	315	$	387	$	668	$	794

Our Upstream capital investment in 2010 was primarily focused on the continued development of the next phases of the Foster Creek and Christina Lake projects. 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 second quarter and year to date is lower than 2009 as we await regulatory approvals for the next phases of expansion. The majority of Foster Creek spending is related to drilling stratigraphic test wells, debottlenecking aspects of the plant and spending in preparation for the next phase of expansion.

At Christina Lake, capital investment was higher in both the second quarter and year to date 2010 compared to 2009 due to increased pad drilling related to the phase C expansion and drilling stratigraphic test wells.

We have chosen to accelerate completion of Christina Lake phase D by approximately six months. Pending timely regulatory and partner approvals, completion of Foster Creek phase F and Christina Lake phase E is planned to be accelerated by up to 12 months.

The stratigraphic test wells drilled at Foster Creek and Christina Lake are to support the next phases of expansion while wells drilled at Narrows Lake, Telephone Lake and other emerging projects have been drilled to assess the quality of our projects and to support regulatory applications for project approval. The following table summarizes the net stratigraphic wells drilled for the first six months of each year:

	Six Months Ended June 30
	2010	2009
Foster Creek	35	33
Christina Lake	12	14
Narrows Lake	18	-
Telephone Lake	26	-
Other Emerging Projects	7	-
	98	47

Other capital investment in 2010 mainly relates to drilling of stratigraphic test wells and regulatory advancement of our new emerging oil sand plays.  In 2009, other capital investment was focused on the continued development of the Athabasca gas and Senlac oil properties.

Cenovus Energy Inc.	30
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Our Downstream Refining capital investment in 2010 continued to focus on the CORE project at the Wood River refinery. For 2010, of the $321 million capital expenditures at Wood River, $262 million were related to the CORE project. At June 30, 2010, the CORE project is approximately 82 percent complete and is anticipated to be completed and in operation mid-year 2011, with total costs expected to be within 10 percent of the US$3.6 billion budget (US$1.8 billion net to Cenovus). 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 balance of the Wood River and Borger capital investment was related to refining reliability and maintenance projects, clean fuels and other emission reduction environmental initiatives.

CANADIAN PLAINS DIVISION

Crude Oil and NGLs

Financial Results

	Three Months Ended June 30		Six Months Ended June 30
(millions of Canadian dollars)	2010	2009	2010	2009
Revenues	$            454	$         445	$       984	$          785
Deduct (add)
Realized financial hedging (gain) loss	2	-	6	(3	)
Royalties	72	48	146	77
Net revenues	380	397	832	711
Expenses
Production and mineral taxes	8	7	15	16
Transportation and selling	56	51	120	114
Operating	82	64	154	127
Operating Cash Flow	$            234	$         275	$       543	$          454

Production Volumes

	Three Months Ended June 30			Six Months Ended June 30
(bbls/d)	2010	2010 vs 2009	2009	2010	2010 vs 2009	2009
Heavy Oil
Pelican Lake	23,319	-3%	23,989	23,441	-6%	25,004
Southern Alberta	12,253	-10%	13,654	12,769	-11%	14,320
Light and Medium Oil
Weyburn	18,043	-2%	18,368	17,883	-2%	18,199
Southern Alberta	10,205	-2%	10,435	10,352	-1%	10,456
Other	4,854	-16%	5,806	5,309	-8%	5,801
NGLs	1,166	-2%	1,184	1,161	-3%	1,199
	69,840	-5%	73,436	70,915	-5%	74,979

Cenovus Energy Inc.	31
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Net Revenues Variance

Three Months Ended June 30, 2010 compared to 2009

(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 seven percent to $63.53 per bbl in the second quarter from $59.42 per bbl in 2009 consistent with increases in the benchmark prices. During the second quarter, realized financial hedging losses were $2 million ($0.34 per bbl) compared to a gain of less than $1 million for 2009 ($0.04 per bbl).

Production volumes at Weyburn were two percent lower in the second quarter compared to 2009 as volume reductions due to maintenance downtime offset volume increases from well optimization and injection programs. At Pelican Lake, volumes were three percent lower in the second quarter mainly due to expected natural declines offset by the increase in production due to less maintenance downtime in 2010. Southern Alberta oil production was down seven percent when compared to the same period in the prior year primarily due to expected natural declines and production downtime resulting from weather. Other production volumes were lower primarily because of the divestiture of certain non-core properties, which prior to their divestiture had production of 441 bbls/d in the second quarter of 2010 (2009 – 2,060 bbls/d), partially offset by new production in the Lower Shaunavon area of Saskatchewan.

Royalties in the second quarter of $72 million were $24 million higher than the same period in 2009 as a result of higher commodity prices, as well as higher royalty rates arising from the higher commodity prices. The effective crude oil royalty rate in the second quarter of 2010 was 17.6 percent (2009 – 13.0 percent).

Production and mineral taxes in the second quarter were consistent with the second quarter of 2009.

Transportation and selling costs in the second quarter increased by $5 million as the 24 percent increase in the average cost of condensate was partially offset by a 12 percent decrease in the volume of condensate used for blending with heavy oil.

Operating costs increased to $82 million in the second quarter from $64 million in the second quarter of 2009 as a result of increased workover and repair and maintenance activity, higher electricity rates and increased chemical usage at Pelican Lake. NGLs are a byproduct obtained through the production of natural gas and therefore operating costs associated with the production of NGLs are included with natural gas.

Cenovus Energy Inc.	32
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2010 compared to 2009

(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.

For the first six months the average crude oil and NGLs sales price, excluding realized hedging, increased 34 percent to $68.44 per bbl compared to the same period in 2009, consistent with increases in the benchmark prices. During the first half of 2010, realized financial hedging losses were $6 million ($0.47 per bbl) compared to a gain of $3 million ($0.24 per bbl) in the first six months of 2009.

Production for the first half of 2010 was lower than the same period in 2009 due to expected natural declines, production downtime due to weather and operational challenges in Southern Alberta. Partially offsetting these reductions were increased production from both well optimizations at Weyburn and from new wells in Southern Alberta and the Lower Shaunavon area of Saskatchewan. Non-core properties were divested in the second quarter of 2010, which prior to their divestiture had year to date production of 895 bbls/d (2009 – 1,825 bbls/d).

Royalties for the six months of $146 million were $69 million higher than the same period in 2009 as a result of higher commodity prices, as well as higher royalty rates arising from the higher commodity prices, which resulted in the effective royalty rate for the period increasing to 17.0 percent from 11.9 percent for the same period in 2009.

Production and mineral taxes were consistent with the same period in 2009.

Transportation and selling costs in the first half of 2010 increased by $6 million compared to the same period in 2009 as a 26 percent increase in the average cost of condensate was offset by a 16 percent decrease in the volume of condensate used for blending with heavy oil.

2010 year to date Operating costs increased to $154 million from $127 million in 2009 as result of increased workover and repair and maintenance activity, higher chemical usage at Pelican Lake, increased electricity prices and indirect costs.

Cenovus Energy Inc.	33
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Natural Gas

Financial Results

	Three Months Ended June 30							Six Months Ended June 30
(millions of Canadian dollars)		2010			2009				2010			2009
Revenues		$	247		$	275			$	595		$	678
Deduct (add)
Realized financial hedging (gain) loss		(76		)	(283		)		(110		)	(536		)
Royalties		3			3				9			11
Net revenues		320			555				696			1,203
Expenses
Production and mineral taxes		(2		)	6				3			10
Transportation and selling		10			12				24			25
Operating		60			60				119			124
Operating Cash Flow		$	252		$	477			$	550		$	1,044

Production Volumes

	Three Months Ended June 30			Six Months Ended June 30
Natural Gas (MMcf/d)	2010	2010 vs 2009	2009	2010	2010 vs 2009	2009
Southern Alberta	676	-11%	761	688	-11%	769
Other	32	-22%	41	32	-20%	40
	708	-12%	802	720	-11%	809

The increase in the average natural gas price, excluding realized financial hedges, to $3.84 per Mcf in the second quarter from $3.77 per Mcf in the second quarter of 2009 was consistent with the increase in the benchmark AECO price. In the quarter, our realized financial hedging gain of $76 million ($1.17 per Mcf) was $207 million lower than our gain of $283 million ($3.88 per Mcf) for the same period in 2009 as a result of our settled fixed price contract prices of $6.18 per Mcf for the period 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.

In the first six months the average natural gas price, excluding realized financial hedges, decreased by $0.07 per Mcf when compared to the same period in 2009, which was consistent with the reduction in the benchmark AECO price. Our realized financial gain in 2010 was $110 million ($0.84 per Mcf), a significant decrease from our 2009 gain of $536 million ($3.66 per Mcf). The change in our settled fixed price contracts, as discussed above, resulted in the decrease in realized hedging gains. For details of the specific pricing on our hedging program, see the notes to our Interim Consolidated Financial statements.

Cenovus Energy Inc.	34
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Net Revenues Variance

Three Months Ended June 30, 2010 Compared to 2009

(1) Includes the impact of realized financial hedging.

Production volumes for Southern Alberta decreased 11 percent in the second quarter of 2010 compared to the same period in 2009 due to expected natural declines, the cumulative effect of lower drilling and tie-in activity throughout 2009 in response to low commodity prices, and weather related drilling and completion delays in the first half of 2010. The decrease was offset by increased production from our coal bed methane (“CBM”) properties and production from wells that were drilled in 2009 and tied-in during 2010.

Royalties in the second quarter were consistent with 2009. The effective royalty rate for the second quarter of 2010 was 1.0 percent (2009 – 1.3 percent).

Production and mineral taxes decreased by $8 million in the second quarter compared to 2009 primarily as a result of lower prices and volumes in 2010 and the true up of 2009 estimated amounts in 2010.

Transportation and selling costs in the second quarter were consistent with the same period in 2009.

Operating expenses in the second quarter were consistent with 2009 as higher electricity prices and workover activity were offset by lower salaries and lower repair and maintenance costs.

Cenovus Energy Inc.	35
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2010 Compared to 2009

(1) Includes the impact of realized financial hedging.

Southern Alberta production volumes decreased 11 percent year over year at June 30, due to expected natural declines, the cumulative impact of lower drilling and tie-in activity throughout 2009 in response to low commodity prices and weather related drilling and completion delays in 2010. The decrease was offset by increases in CBM production and production from wells drilled in 2009 that were tied-in during 2010.

Decreased Royalties for the period were the result of lower volumes. The average royalty rate for the six month period ended June 30, 2010 was 1.5 percent (2009 – 1.6 percent).

Production and mineral taxes in the first six months of 2010 were $7 million lower than 2009 due to lower price and volumes in 2010 and the true up of 2009 estimated amounts in 2010.

Transportation and selling costs for the six months ended June 30, 2010 were consistent with 2009.

Operating expenses for the period decreased four percent to $119 million mainly as a result of a lower level of repair and maintenance activity.

Canadian Plains - Other

Financial Results

	Three Months Ended June 30					Six Months Ended June 30
(millions of Canadian dollars)		2010		2009			2010		2009
Revenues		$	415	$	236		$	830	$	467
Expenses
Operating		7		6			12		11
Purchased product		402		228			806		446
Operating Cash Flow		$	6	$	2		$	12	$	10

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 increase in both revenues and purchased product expenses for the three and six month periods ended June 30, 2010 is largely the result of increased volumes for both crude oil and natural gas, and higher crude oil prices. Canadian Plains – Other also includes a small amount of third party processing fee income.

Cenovus Energy Inc.	36
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Capital Investment

Canadian Plains capital investment in the second quarter of 2010 was $102 million (2009 - $99 million) and for the six months ended June 30, 2010 was $241 million (2009 - $334 million). The $93 million decrease from year to date 2009 was primarily the result of winter weather, an early spring thaw and continued poor weather conditions throughout the second quarter which resulted in the deferral of some planned investment from the first half of 2010 to later in the year.

The Canadian Plains Division drilled 16 net wells (2009 – 56 net wells) in the second quarter of 2010. For the six months, we drilled 137 net wells (2009 – 430 net wells). Fewer wells were drilled in 2010 as poor weather conditions restricted access to our leases.

For the six months ended June 30, 2010, approximately 81 percent of our capital investment was on our crude oil properties (2009 - 42 percent) and primarily included capital maintenance and polymer injection investment in the Greater Pelican Region, drilling and facility work at Weyburn and drilling in the Lower Shaunavon area of Saskatchewan and Bakken new development projects. Our investment included 54 net oil development wells (2009 - 28 net oil development wells) and six net oil exploration wells, as well as 78 gas development wells (2009 - 402 wells). We also performed 409 well recompletions (2009 - 410 recompletions) which are mostly for CBM. In addition, 33 stratigraphic test wells were drilled in the Grand Rapids project in the Greater Pelican Region (2009 – 18 wells) to further our understanding of the reservoir existing on our leases.

CORPORATE AND ELIMINATIONS

Financial Results

	Three Months Ended June 30							Six Months Ended June 30
(millions of Canadian dollars)		2010			2009				2010			2009
Revenues		$	(18	)	$	(316	)		$	199		$	(227	)
Expenses
Operating		(3		)	3				1			22
Purchased product		(38		)	(22		)		(62		)	(38		)
Depreciation, depletion and amortization		12			12				20			25
Segment Income (Loss)			11			(309	)			240			(236	)

The Corporate and Eliminations segment includes revenues that represent the unrealized mark-to-market gains and 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.

Cenovus Energy Inc.	37
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative and financing activities made up of the following:

	Three Months Ended June 30				Six Months Ended June 30
(millions of Canadian dollars)	2010		2009		2010		2009
General and administrative	$	59	$	52	$	111	$	93
Interest, net	66		57		131		102
Accretion of asset retirement obligation	18		12		40		23
Foreign exchange (gain) loss, net	28		143		1		91
(Gain) loss on divestitures	9		-		8		-
	$	180	$	264	$	291	$	309

Our General and administrative expenses increased $7 million in the second quarter of 2010 compared to the same period of 2009 (year to date – increase of $18 million), primarily because of higher salaries and benefits as we move to implement our 10 year strategic plan and complete the transition to a new independent company.

Net interest in the second quarter of 2010 was $66 million, which was $9 million higher than the second quarter of 2009 (year to date – increase of $29 million). Both the second quarter and year to date increases are primarily the 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 comparative periods in 2009. Also, the second quarter includes $4 million (year to date $8 million) of financing cost amortization related to the setup of our debt financing programs. Our weighted average interest rate on outstanding debt at June 30, 2010 was 5.6 percent compared to 5.5 percent at June 30, 2009.

In the second quarter of 2010 we reported a foreign exchange loss of $28 million compared to a loss of $143 million in 2009, the majority of which was unrealized. The weakening of the Canadian dollar during the second quarter of 2010 led to an unrealized loss on our U.S. dollar debt, which was partially offset by an unrealized gain on our U.S. dollar partnership contribution receivable. For the six months ended June 30, 2010 we recognized a foreign exchange loss of $1 million (2009 - loss of $91 million).

Cenovus Energy Inc.	38
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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 period. Additional information regarding financial instrument agreements can be found in the notes to the Interim Consolidated Financial Statements.

	Three Months Ended June 30						Six Months Ended June 30
(millions of Canadian dollars)	2010			2009			2010		2009
Revenues
Crude Oil	$	118		$	(17	)	$	116	$	(48	)
Natural Gas	(98		)	(277		)	145		(141		)
	20			(294		)	261		(189		)
Expenses	(2		)	3			2		22
	22			(297		)	259		(211		)
Income Tax Expense (Recovery)	6			(83		)	73		(61		)
Unrealized Mark-to-Market Gains (Losses), after-tax	$	16		$	(214	)	$	186	$	(150	)

DEPRECIATION, DEPLETION and AMORTIZATION

In the second quarter of 2010, DD&A was $325 million (2009 - $382 million) and for the six month period ended June 30, 2010 was $649 million (2009 - $762 million). We use full cost accounting for our upstream oil and gas activities and calculate DD&A on a country-by-country cost centre basis. Upstream DD&A in the second quarter of 2010 of $264 million (2009 - $316 million) and year to date of $529 million (2009 - $620 million) were lower primarily as a result of a lower DD&A rate partially offset by increased production volumes. Our Downstream Refining assets DD&A in the second quarter of 2010 was $49 million (2009 - $54 million) and 2010 year to date was $100 million (2009 - $117 million). Decreases to our Downstream DD&A were primarily due to a strengthening of the Canadian dollar average exchange rate.

INCOME TAX

The second quarter income tax expense of $11 million was $59 million lower than the same period in 2009. Current income tax expense in the second quarter of 2010 was $15 million compared to $151 million in the second quarter of 2009, and future tax recovery was $4 million compared to a recovery of $81 million for 2009.

Year to date at June 30, 2010 our income tax expense of $126 million was $18 million lower than the same period in 2009. Current income tax expense for the period was $30 million (2009 - $249 million). Future tax expense for 2010 was $96 million compared to a recovery of $105 million for the period in 2009.

When comparing the 2010 and 2009 second quarter and year to date amounts, our current tax expense declined and our future tax expense increased primarily due to claims from tax pools that we received as a result of the Arrangement.

Our effective tax rate for the second quarter of 2010 was 6.0 percent (year to date - 15.3 percent) compared to 30.4 percent in 2009 (year to date – 17.6 percent). The decreases for the quarter and six months ended are primarily due to two factors: the impact of permanent differences on lower overall earnings before income taxes in the quarter, as well as the recognition of the tax benefit arising from a loss in our U.S. entities in 2010 compared to earnings in 2009.

It should be noted that for second quarter and year to date 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.

Cenovus Energy Inc.	39
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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

· Taxable 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. We believe that our provision for taxes is adequate.

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended June 30						Six Months Ended June 30
(millions of Canadian dollars)	2010			2009			2010			2009
Net cash from (used in)
Operating activities	$	471		$	793		$	1,291		$	1,475
Investing activities	(468		)	(532		)	(840		)	(1,250		)
Net cash provided (used) before Financing activities	3			261			451			225
Financing activities	16			(392		)	(187		)	(281		)
Foreign exchange gain (loss) on cash and cash equivalents held in foreign currency	(7		)	(3		)	(10		)	(5		)
Increase (decrease) in cash and cash equivalents	$	12		$	(134	)	$	254		$	(61	)

OPERATING ACTIVITIES

Net cash from operating activities decreased $322 million in the second quarter compared to 2009 and decreased $184 million in the six months compared to 2009. Cash Flow was $537 million during the second quarter compared to $945 million for the same period in 2009 and $1,258 million for the first six months (2009 - $1,686 million). 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.

Excluding the impact of risk management assets and liabilities, we had working capital of $708 million at June 30, 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 for the three months ended June 30, 2010 decreased to $468 million from $532 million for the same period in 2009. Year to date net cash used in investing of $840 million was a decrease of $410 million from the same period in 2009. Capital expenditures decreased in the second quarter to $477 million compared to $489 million in 2009 while year to date capital expenditures decreased by $171 million to $970 million compared to 2009. Total divestiture proceeds in 2010 of $144 million include $72 million which occurred in the second quarter. The net change in non-cash working capital decreased cash by $63 million in the second quarter of 2010 (2009 – $59 million) and decreased cash by $16 million in the first six months of 2010 (2009 – $126 million). The decreased capital expenditures are discussed under the Net Capital Investment and Divisional Results sections of this MD&A.

Cenovus Energy Inc.	40
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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, that expires November 30, 2012, and a $500 million 364-day tranche, that expires November 29, 2010. At June 30, 2010, Cenovus had $2.3 billion in unused credit capacity on this facility. Included in Cenovus’s long-term debt obligations of $3,821 million at June 30, 2010, are $165 million in principal obligations related to the issuance of commercial paper. These amounts are fully backstopped by the Company’s 3-year tranche of the revolving syndicated credit facility, which has no repayment requirements within the next year. We are currently in compliance with all of our financial covenants under this credit facility.

On May 26, 2010, the Company filed a prospectus to exchange up to US$800 million aggregate principal amount of 4.50 percent Senior Notes due 2014, up to US$1,300 million aggregate principal amount of 5.70 percent Senior Notes due 2019 and up to US$1,400 million aggregate principal amount of 6.75 percent Senior Notes due 2039 registered under the U.S. Securities Act of 1933, as amended, for any and all of its outstanding 4.50 percent notes, 5.70 percent notes and 6.75 percent notes, which were issued on September 18, 2009, in a transaction exempt from registration. The exchange offer was launched on May 28, 2010, was extended on June 28, 2010 and expired on June 30, 2010. All of the 4.50 percent notes and 6.75 percent notes and substantially all of the 5.70 percent notes were exchanged in accordance with the terms of the exchange offer.

On June 24, 2010, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other foreign currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates will be determined at the date of issue. At June 30, 2010, $1.5 billion of the shelf remains unutilized. The Canadian shelf prospectus expires in July 2012.

On July 7, 2010, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$1.5 billion. The U.S. shelf prospectus allows for the issuance of debt securities in U.S. dollars or other foreign currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates will be determined at the date of issue. The shelf prospectus expires in August 2012.

In the first and second quarters of 2010 Cenovus declared and paid a dividend of $0.20 per share. Dividend payments for the first six months of 2010 totaled $300 million. Dividends are at the sole discretion of the Board and considered quarterly.

Net cash generated from financing activities for the second quarter of 2010 was $16 million compared to $392 million used in 2009. For the six months ended June 30, 2010, $187 million of cash was used in financing activities (2009 - $281 million). Our debt, including current portion, was $3,821 million as at June 30, 2010 compared with $3,656 million as at December 31, 2009.

FINANCIAL METRICS

	June 30, 2010	December 31, 2009
Debt to Capitalization	28%	28%
Debt to Adjusted EBITDA (times)	1.2x	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. Debt is defined as the current and long-term portions of long-term debt. These metrics are used to steward Cenovus’s capital structure.

Cenovus Energy Inc.	41
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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. Additional information regarding our capital structure can be found in the notes to the Interim Consolidated Financial Statements.

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. As at June 30, 2010 there were 751.8 million common shares outstanding and no first preferred shares or second preferred shares outstanding.

During the second quarter of 2010, the Board approved a dividend reinvestment plan (“DRIP”), which permits holders of common shares to automatically reinvest all or any portion of the cash dividends paid on their common shares in additional common shares. At the discretion of the Company, the additional common shares may be issued from treasury at an average market price or purchased on the market at prevailing market rates. For the period ended June 30, 2010, no common shares were issued from Treasury to meet our DRIP requirements. 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 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.

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.

Cenovus Energy Inc.	42
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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 which may add costs to the products we produce and reduce 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. A fulsome assessment of these regulations, our corporate strategy and performance is provided in our MD&A for the year ended December 31, 2009 and our response to the Carbon Disclosure Project can be found on our website. We will continue to provide quarterly updates to that information.

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner and we recognize the importance of reporting to stakeholders in a transparent and accountable way. We disclose not only information that’s required by law and regulation, but also which more broadly describes activities, policies, opportunities and risk.

We are reviewing our existing Corporate Responsibility (“CR”) policy to ensure that it continues to drive our commitments, strategy and reporting, and also enables alignment with our business objectives and processes. Our future CR reporting activities will be guided by this policy and will focus on improving performance by continuing to track, measure and monitor our CR performance indicators.

In July 2010, updates to the CR section of our website were made. As part of these updates we have included the “Corporate Responsibility 2009 Performance Measures” which provides information on our CR performance in 2009 on a number of measures.

As our CR reporting process matures, 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.

Cenovus Energy Inc.	43
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

ALBERTA’S ROYALTY/REGULATORY FRAMEWORK

On March 11, 2010, the Alberta government outlined changes to the Alberta royalty structure which included:

·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, but is now permanently in place;

·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.

On May 27, 2010, the Alberta Government released further updates to the royalty structure.  The update was primarily focused on supporting deep basin gas drilling and improving the economics of unconventional gas plays, as well as horizontal oil and gas drilling. The changes detailed in this release will be effective January 1, 2011, for all wells drilled, excluding oil sands, after May 1, 2010. Impacts of the release include:

·A maximum royalty rate of five percent for all products produced from horizontal oil or horizontal non-oil sands wells, with volume and production month limits set according to the depth of the well. Horizontal oil and non-oil sands wells are defined by the ERCB;

·Wells defined as horizontal natural gas wells by the ERCB will have a maximum five percent royalty rate on all production for a period of 18 producing months or 500 MMcf of gas equivalent production;

·CBM wells that produce exclusively from areas defined by the ERCB as coal will have a maximum royalty rate of five percent on all products produced in the first 36 months with a production limit of 750 MMcf of gas equivalent; and

·The Natural Gas Deep Drilling program was made permanent and was modified and simplified. Modifications include the reduction of the minimum well depth to 2,000 metres; elimination of well target, spacing and pool boundary restrictions; all lateral wells qualify for credits; increased credits between 3,500 and 5,000 metres; and removal of maximum well depth.

Updates to the royalty curves for conventional oil and natural gas were included in the May 2010 release. The effective date of the new curves is January 1, 2011.

For Cenovus, the main impact of the royalty changes will be a positive improvement to the economics of our oil drilling program for certain properties in Canadian Plains and any future shale oil developments in Alberta.

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 was released in the second quarter of 2010 with the final report expected before the end of this year.

ACCOUNTING POLICIES AND ESTIMATES

Basis of Presentation

Our results for the six month period from January 1 to June 30, 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.

Cenovus Energy Inc.	44
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Our results for the periods prior to the Arrangement, being January 1 to November 30, 2009, have been prepared on a “carve-out” accounting basis, whereby the results have been derived from the accounting records of Encana using the historical results of operations and historical basis of assets and liabilities of the businesses transferred to Cenovus. The historical consolidated financial statements include allocations of certain Encana expenses, assets and liabilities.  In the opinion of Management, the consolidated and the historical carve-out consolidated financial statements reflect all adjustments necessary for a fair statement of the financial position and the results of operations and cash flows in accordance with Canadian GAAP.

The presentation of financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Management believes that the assumptions underlying the historical consolidated financial statements are reasonable. However, as we operated as part of Encana and were not a stand-alone company prior to November 30, 2009, the historical consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows had we been a stand-alone company during the periods presented.

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 June 30, 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 June 30, 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.

The IFRS accounting policies that we expect to use have not changed from those described in our MD&A for the three months ended March 31, 2010 and the year ended December 31, 2009. 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, including the new joint ventures standard that is expected to be published later in 2010.

Cenovus Energy Inc.	45
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Implementation of the process and system changes required for IFRS have been completed, and are currently being used to prepare and record our draft IFRS transactions and balances.

We are currently working on a draft of our IFRS opening balance sheet, and expect to begin drafting our 2010 quarterly IFRS financial results in the third quarter of 2010. We have also started drafting our IFRS financial statements for the three month period ending March 31, 2011 as well as for the year ending December 31, 2011.

We have completed updating our internal controls documentation related to the IFRS opening balance sheet and we are currently updating our documentation related to the monthly IFRS adjustments, including controls related to the completeness of the adjustments. We intend to update documentation related to external financial reporting processes, including disclosure controls and procedures, in the fourth quarter of 2010.

In terms of financial literacy, we began formal IFRS education sessions across Cenovus during the second quarter of 2010. The education sessions include an overview to IFRS which is being presented to a broad range of employees across the company. Other sessions include a detailed IFRS accounting policies and work practices session which is focused on employees in the finance and financial reporting areas of the company. Our education efforts will continue for the remainder of 2010 and into 2011.

The education of our external stakeholders is expected to continue throughout 2010 and into 2011, as we finalize our IFRS opening balance sheet and calculate the 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 oil sands production, primarily through expansions at our Foster Creek and Christina Lake properties. We also have an extensive inventory of emerging oil sands projects, and we have a working interest of 100 percent in many of these projects;

·Continue the development of our resources in multiple phases using a manufacturing like approach to benefit from repeatable and scalable processes and low costs;

·Leadership in low-cost oil sands development; enabled by technology and continued respect for the health and safety of our employees, emphasis on industry leading environmental performance and meaningful dialogue with our stakeholders;

·Internally funded growth through free cash flow generation from our established crude oil and natural gas assets;

·Maintaining a lower risk profile through natural gas and downstream integration as well as hedging execution; and

·Maintain a meaningful dividend.

We believe global oil demand will continue to increase which should allow for modest increases in WTI prices while we are expecting the light-heavy differential to remain relatively strong compared to historical trends for the foreseeable future. Offsetting this is a relatively weak price outlook for natural gas and refining margins. The key hurdles that need to be effectively managed to enable our growth are commodity price volatility, environmental regulations, government project approvals and competitive pressures within our industry. 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.

We expect our 2010 capital investment program to be funded from Cash Flow. We also have a plan to divest of certain non-core assets and to date have received proceeds of $144 million. Our conventional crude oil and natural gas assets in Alberta and Saskatchewan are key to providing free cash flow to enable oil sands growth. Our ten year business plan outlines how Cenovus expects to reach net oil sands production of 300,000 bbls/d by the end of 2019. We are planning continued expansions at Foster Creek and Christina Lake, as well as new projects at Grand Rapids, Telephone Lake and Narrows Lake in order to achieve this.

Cenovus Energy Inc.	46
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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 2009 and 2010, we cannot ensure that we will continue to derive such benefits in the future.

We will continue to develop our 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, our projected future value or net asset value, 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, 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$; and 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 752 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 as proved; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the expected impacts of the Arrangement on our employees, operations, suppliers, business partners and stakeholders and our ability to realize the expected benefits of the Arrangement; our ability to obtain financing in the future on a stand alone basis; the historical financial information pertaining to our assets as operated by Encana prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. Readers are cautioned that the foregoing list is not exhaustive.

Cenovus Energy Inc.	47
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

Many of these risk factors are discussed in further detail throughout this MD&A and in our 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 represent net proved and probable reserves calculated using the standards contained in Regulation S-X of the U.S. Securities & Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading “Note Regarding Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2009.

CRUDE OIL, NGLs AND NATURAL GAS CONVERSIONS

In this document, certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of one barrel to six thousand cubic feet. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head.

Cenovus Energy Inc.	48
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

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. 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.

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 found on our website at www.cenovus.com.

Cenovus Energy Inc.	49
Second Quarter 2010 Interim Report	Management’s Discussion and Analysis

CONSOLIDATED STATEMENT OF EARNINGS AND
COMPREHENSIVE INCOME (unaudited)

For the period ended June 30,		Three Months Ended			Six Months Ended
(C$ millions, except per share amounts)		2010	2009		2010	2009
Gross Revenues	(Note 1)	3,318	2,871		6,920	5,607
Less: Royalties		123	53		234	96
Net Revenues		3,195	2,818		6,686	5,511
Expenses	(Note 1)
Production and mineral taxes		6	13		18	26
Transportation and selling		291	184		582	350
Operating		322	320		670	684
Purchased product		1,888	1,425		3,653	2,561
Depreciation, depletion and amortization		325	382		649	762
General and administrative		59	52		111	93
Interest, net	(Note 7)	66	57		131	102
Accretion of asset retirement obligation	(Note 13)	18	12		40	23
Foreign exchange (gain) loss, net	(Note 8)	28	143		1	91
Other (income) loss, net		9	-		8	-
		3,012	2,588		5,863	4,692
Earnings Before Income Tax		183	230		823	819
Income tax expense	(Note 9)	11	70		126	144
Net Earnings		172	160		697	675
Other Comprehensive Income, Net of Tax
Foreign Currency Translation Adjustment		129	(104	)	41	(17	)
Comprehensive Income		301	56		738	658
Net Earnings per Common Share	(Note 18)
Basic		0.23	0.21		0.93	0.90
Diluted		0.23	0.21		0.93	0.90

See accompanying Notes to Interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	50
Second Quarter 2010 Interim Report	Consolidated Financial Statements

CONSOLIDATED BALANCE SHEET (unaudited)

As at (C$ millions)		June 30, 2010	December 31, 2009
Assets
Current Assets
Cash and cash equivalents		409	155
Accounts receivable and accrued revenues		1,063	978
Income tax receivable		34	40
Current portion of Partnership Contribution Receivable	(Note 11)	359	345
Risk management	(Note 17)	196	60
Inventories	(Note 10)	809	875
		2,870	2,453
Property, Plant and Equipment, net	(Note 1)	15,469	15,214
Partnership Contribution Receivable	(Note 11)	2,475	2,621
Risk Management	(Note 17)	62	1
Other Assets		427	320
Goodwill	(Note 1)	1,146	1,146
		22,449	21,755
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		1,547	1,574
Income tax payable		64	-
Current portion of Partnership Contribution Payable	(Note 11)	355	340
Risk management	(Note 17)	8	70
		1,974	1,984
Long-Term Debt	(Note 12)	3,821	3,656
Partnership Contribution Payable	(Note 11)	2,506	2,650
Risk Management	(Note 17)	4	4
Asset Retirement Obligation	(Note 13)	1,175	1,147
Other Liabilities		353	239
Future Income Taxes		2,561	2,467
		12,394	12,147
Shareholders’ Equity		10,055	9,608
		22,449	21,755

See accompanying Notes to Interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	51
Second Quarter 2010 Interim Report	Consolidated Financial Statements

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (unaudited)

(C$ millions)	Share Capital (Note 14)	Paid in Surplus	Retained Earnings		AOCI*		Owner’s Net Investment (Note 14)		Total
Balance as of December 31, 2008	-	-	-		224		9,264		9,488
Net earnings	-	-	-		-		675		675
Net distribution to owner	-	-	-		-		(322	)	(322	)
Other comprehensive income (loss)	-	-	-		(17	)	-		(17	)
Balance as of June 30, 2009	-	-	-		207		9,617		9,824
Balance as of December 31, 2009	3,681	5,896	45		(14	)	-		9,608
Net earnings	-	-	697		-		-		697
Common shares issued under option plans	9	-	-		-		-		9
Dividends on common shares	-	-	(300	)	-		-		(300	)
Other comprehensive income (loss)	-	-	-		41		-		41
Balance as of June 30, 2010	3,690	5,896	442		27		-		10,055

*Accumulated Other Comprehensive Income

See accompanying Notes to Interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	52
Second Quarter 2010 Interim Report	Consolidated Financial Statements

CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited)

		Three Months Ended				Six Months Ended
For the period ended June 30, (C$ millions)		2010		2009		2010		2009
Operating Activities
Net earnings		172		160		697		675
Depreciation, depletion and amortization		325		382		649		762
Future income taxes	(Note 9)	(4	)	(81	)	96		(105	)
Unrealized (gain) loss on risk management	(Note 17)	(22	)	297		(259	)	211
Unrealized foreign exchange (gain) loss	(Note 8)	31		160		(1	)	107
Accretion of asset retirement obligation	(Note 13)	18		12		40		23
Other		17		15		36		13
Net change in other assets and liabilities		(13	)	(6	)	(28	)	(9	)
Net change in non-cash working capital		(53	)	(146	)	61		(202	)
Cash From Operating Activities		471		793		1,291		1,475
Investing Activities
Capital expenditures	(Note 1)	(477	)	(489	)	(970	)	(1,141	)
Proceeds from divestitures	(Note 6)	72		3		144		3
Net change in investments and other		-		13		2		14
Net change in non-cash working capital		(63	)	(59	)	(16	)	(126	)
Cash (Used in) Investing Activities		(468	)	(532	)	(840	)	(1,250	)
Net Cash Provided (Used) before Financing Activities		3		261		451		225
Financing Activities
Net issuance (repayment) of revolving long-term debt		164		(403	)	106		(163	)
Net financing transactions with Encana		-		(193	)	-		(322	)
Issuance of long-term debt		-		204		-		204
Issuance of common shares		2		-		7		-
Dividends on common shares		(150	)	-		(300	)	-
Cash From (Used in) Financing Activities		16		(392	)	(187	)	(281	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(7	)	(3	)	(10	)	(5	)
Increase (Decrease) in Cash and Cash Equivalents		12		(134	)	254		(61	)
Cash and Cash Equivalents, Beginning of Period		397		261		155		188
Cash and Cash Equivalents, End of Period		409		127		409		127

See accompanying Notes to Interim Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	53
Second Quarter 2010 Interim Report	Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 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 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 oil sands interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major oil sands projects: (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 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 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, as well as several other emerging projects.
	·	Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.
	·	Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.

The tabular financial information which follows presents the segmented information first by segment and geographic location, then by product and operating division.  Capital expenditures and goodwill information are summarized at the end of the note.

Cenovus Energy Inc.	54
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Results of Operations

Segment and Geographic Information (For the three months ended June 30)

	Upstream Canada		Downstream Refining
(C$ millions)	2010	2009	2010		2009
Gross Revenues	1,726	1,661	1,610		1,526
Less: Royalties	123	53	-		-
Net Revenues	1,603	1,608	1,610		1,526
Expenses
Production and mineral taxes	6	13	-		-
Transportation and selling	291	184	-		-
Operating	215	188	110		129
Purchased product	402	228	1,524		1,219
Operating Cash Flow	689	995	(24	)	178
Depreciation, depletion and amortization	264	316	49		54
Segment Income (Loss)	425	679	(73	)	124

	Corporate and Eliminations				Consolidated
(C$ millions)	2010		2009		2010	2009
Gross Revenues	(18	)	(316	)	3,318	2,871
Less: Royalties	-		-		123	53
Net Revenues	(18	)	(316	)	3,195	2,818
Expenses
Production and mineral taxes	-		-		6	13
Transportation and selling	-		-		291	184
Operating	(3	)	3		322	320
Purchased product	(38	)	(22	)	1,888	1,425
	23		(297	)	688	876
Depreciation, depletion and amortization	12		12		325	382
Segment Income (Loss)	11		(309	)	363	494
General and administrative	59		52		59	52
Interest, net	66		57		66	57
Accretion of asset retirement obligation	18		12		18	12
Foreign exchange (gain) loss, net	28		143		28	143
Other (income) loss, net	9		-		9	-
	180		264		180	264
Earnings Before Income Tax					183	230
Income tax expense					11	70
Net Earnings					172	160

Cenovus Energy Inc.	55
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Upstream Canada Product and Divisional Information

(For the three months ended June 30)

				Crude Oil & NGLs
	Integrated Oil			Canadian Plains			Total
(C$ millions)	2010	2009		2010		2009	2010		2009
Gross Revenues	507	325		452		445	959		770
Less: Royalties	46	2		72		48	118		50
Net Revenues	461	323		380		397	841		720
Expenses
Production and mineral taxes	-	-		8		7	8		7
Transportation and selling	224	116		56		51	280		167
Operating	61	45		82		64	143		109
Purchased product	-	-		-		-	-		-
Operating Cash Flow	176	162		234		275	410		437
				Natural Gas
	Integrated Oil			Canadian Plains			Total
(C$ millions)	2010	2009		2010		2009	2010		2009
Gross Revenues	23	79		323		558	346		637
Less: Royalties	2	(4	)	3		3	5		(1	)
Net Revenues	21	83		320		555	341		638
Expenses
Production and mineral taxes	-	-		(2	)	6	(2	)	6
Transportation and selling	1	-		10		12	11		12
Operating	4	5		60		60	64		65
Purchased product	-	-		-		-	-		-
Operating Cash Flow	16	78		252		477	268		555
				Other
	Integrated Oil			Canadian Plains			Total
(C$ millions)	2010	2009		2010		2009	2010		2009
Gross Revenues	6	18		415		236	421		254
Less: Royalties	-	4		-		-	-		4
Net Revenues	6	14		415		236	421		250
Expenses
Production and mineral taxes	-	-		-		-	-		-
Transportation and selling	-	5		-		-	-		5
Operating	1	8		7		6	8		14
Purchased product	-	-		402		228	402		228
Operating Cash Flow	5	1		6		2	11		3
				Total Upstream
	Integrated Oil			Canadian Plains			Total
(C$ millions)	2010	2009		2010		2009	2010		2009
Gross Revenues	536	422		1,190		1,239	1,726		1,661
Less: Royalties	48	2		75		51	123		53
Net Revenues	488	420		1,115		1,188	1,603		1,608
Expenses
Production and mineral taxes	-	-		6		13	6		13
Transportation and selling	225	121		66		63	291		184
Operating	66	58		149		130	215		188
Purchased product	-	-		402		228	402		228
Operating Cash Flow	197	241		492		754	689		995

Cenovus Energy Inc.	56
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Results of Operations

Segment and Geographic Information (For the six months ended June 30)

	Upstream Canada		Downstream Refining
(C$ millions)	2010	2009	2010		2009
Gross Revenues	3,593	3,154	3,128		2,680
Less: Royalties	234	96	-		-
Net Revenues	3,359	3,058	3,128		2,680
Expenses
Production and mineral taxes	18	26	-		-
Transportation and selling	582	350	-		-
Operating	420	386	249		276
Purchased product	806	446	2,909		2,153
Operating Cash Flow	1,533	1,850	(30	)	251
Depreciation, depletion and amortization	529	620	100		117
Segment Income (Loss)	1,004	1,230	(130	)	134
As at (C$ millions)	June 30, 2010	December 31, 2009	June 30, 2010		December 31,  2009
Property, Plant & Equipment	10,014	10,109	5,342		4,989
Goodwill	1,146	1,146	-		-
Total Assets	14,980	15,218	6,558		6,107

	Corporate and Eliminations				Consolidated
(C$ millions)	2010		2009		2010	2009
Gross Revenues	199		(227	)	6,920	5,607
Less: Royalties	-		-		234	96
Net Revenues	199		(227	)	6,686	5,511
Expenses
Production and mineral taxes	-		-		18	26
Transportation and selling	-		-		582	350
Operating	1		22		670	684
Purchased product	(62	)	(38	)	3,653	2,561
	260		(211	)	1,763	1,890
Depreciation, depletion and amortization	20		25		649	762
Segment Income (Loss)	240		(236	)	1,114	1,128
General and administrative	111		93		111	93
Interest, net	131		102		131	102
Accretion of asset retirement obligation	40		23		40	23
Foreign exchange (gain) loss, net	1		91		1	91
Other (income) loss, net	8		-		8	-
	291		309		291	309
Earnings Before Income Tax					823	819
Income tax expense					126	144
Net Earnings					697	675
As at (C$ millions)	June 30, 2010		December 31, 2009		June 30, 2010	December 31,  2009
Property, Plant & Equipment	113		116		15,469	15,214
Goodwill	-		-		1,146	1,146
Total Assets	911		430		22,449	21,755

Cenovus Energy Inc.	57
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS(unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Upstream Canada Product and Divisional Information

(For the six months ended June 30)

			Crude Oil & NGLs
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	1,022	530	978	788	2,000	1,318
Less: Royalties	73	3	146	77	219	80
Net Revenues	949	527	832	711	1,781	1,238
Expenses
Production and mineral taxes	-	-	15	16	15	16
Transportation and selling	437	199	120	114	557	313
Operating	121	95	154	127	275	222
Purchased product	-	-	-	-	-	-
Operating Cash Flow	391	233	543	454	934	687
			Natural Gas
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	50	120	705	1,214	755	1,334
Less: Royalties	6	-	9	11	15	11
Net Revenues	44	120	696	1,203	740	1,323
Expenses
Production and mineral taxes	-	-	3	10	3	10
Transportation and selling	1	1	24	25	25	26
Operating	11	14	119	124	130	138
Purchased product	-	-	-	-	-	-
Operating Cash Flow	32	105	550	1,044	582	1,149
			Other
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	8	35	830	467	838	502
Less: Royalties	-	5	-	-	-	5
Net Revenues	8	30	830	467	838	497
Expenses
Production and mineral taxes	-	-	-	-	-	-
Transportation and selling	-	11	-	-	-	11
Operating	3	15	12	11	15	26
Purchased product	-	-	806	446	806	446
Operating Cash Flow	5	4	12	10	17	14
			Total Upstream
	Integrated Oil		Canadian Plains		Total
(C$ millions)	2010	2009	2010	2009	2010	2009
Gross Revenues	1,080	685	2,513	2,469	3,593	3,154
Less: Royalties	79	8	155	88	234	96
Net Revenues	1,001	677	2,358	2,381	3,359	3,058
Expenses
Production and mineral taxes	-	-	18	26	18	26
Transportation and selling	438	211	144	139	582	350
Operating	135	124	285	262	420	386
Purchased product	-	-	806	446	806	446
Operating Cash Flow	428	342	1,105	1,508	1,533	1,850

Cenovus Energy Inc.	58
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

1.  DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)

Capital Expenditures

	Three Months Ended		Six Months Ended
For the period ended June 30, (C$ millions)	2010	2009	2010	2009
Integrated Oil	147	122	298	277
Canadian Plains	102	99	241	334
Upstream Canada	249	221	539	611
Downstream Refining	168	265	370	517
Corporate	13	2	14	12
	430	488	923	1,140
Acquisition Capital
Integrated Oil	18	-	18	-
Canadian Plains	16	1	16	1
Corporate	13	-	13	-
Total	477	489	970	1,141

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.

Cenovus Energy Inc.	59
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

2.  BACKGROUND & BASIS OF PRESENTATION (continued)

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.

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 June 30, 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 June 30, 2010.  These standards along with CICA Handbook section 1582 above are converged with International Financial Reporting Standards (see Note 5).

Cenovus Energy Inc.	60
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

4.  CHANGES IN ACCOUNTING POLICIES AND PRACTICES (continued)

Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in 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 six months ended June 30, 2010, total proceeds received from the divestiture of assets were $144 million (2009–$3 million).

7.  INTEREST, NET

	Three Months Ended				Six Months Ended
For the period ended June 30, (C$ millions)	2010		2009		2010		2009
Interest Expense–Long-Term Debt	57		51		115		97
Interest Expense–Other	46		53		91		108
Interest Income	(37	)	(47	)	(75	)	(103	)
	66		57		131		102

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				Six Months Ended
For the period ended June 30, (C$ millions)	2010		2009		2010		2009
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar debt issued from Canada	158		(185	)	50		(118	)
Translation of U.S. dollar Partnership Contribution Receivable issued from Canada	(132	)	295		(56	)	186
Other	5		50		5		39
Unrealized Foreign Exchange (Gain) Loss	31		160		(1	)	107
Realized Foreign Exchange (Gain) Loss	(3	)	(17	)	2		(16	)
	28		143		1		91

Cenovus Energy Inc.	61
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

9.  INCOME TAXES

The provision for income taxes is as follows:

	Three Months Ended				Six Months Ended
For the period ended June 30, (C$ millions)	2010		2009		2010	2009
Current
Canada	15		169		30	257
United States	-		(18	)	-	(8	)
Total Current Tax	15		151		30	249
Future	(4	)	(81	)	96	(105	)
	11		70		126	144

10.  INVENTORIES

As at (C$ millions)	June 30, 2010	December 31, 2009
Product
Upstream Canada	182	267
Downstream Refining	606	589
Parts and Supplies	21	19
	809	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)	June 30, 2010	December 31, 2009
Current	359	345
Long-term	2,475	2,621
	2,834	2,966

Partnership Contribution Payable

As at (C$ millions)	June 30, 2010	December 31, 2009
Current	355	340
Long-term	2,506	2,650
	2,861	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 June 30, 2010 these amounts were $292 million (December 31, 2009–$183 million).

Cenovus Energy Inc.	62
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

12.  LONG-TERM DEBT

As at (C$ millions)	June 30, 2010		December 31, 2009
Canadian Dollar Denominated Debt
Revolving term debt*	85		32
U.S. Dollar Denominated Debt
Revolving term debt*	80		26
Unsecured notes	3,712		3,663
	3,792		3,689
Total Debt Principal	3,877		3,721
Debt Discounts and Transaction Costs	(56	)	(65	)
Current Portion of Long-Term Debt	-		-
	3,821		3,656

*  Revolving term debt includes commercial paper, bankers’ acceptances, Libor loans, prime rate loans and U.S. base rate loans.

Included in Cenovus’s long-term debt obligations of $3,821 million at June 30, 2010, are $165 million in principal obligations related to the issuance of commercial paper.  These amounts are fully backstopped by the Company’s 3-year tranche of the revolving syndicated credit facility, which expires in November 2012 and has no repayment requirements within the next year.

At June 30, 2010, Cenovus is in compliance with all of the terms of its debt agreements.

On May 26, 2010, the Company filed a prospectus to exchange up to US$800 million aggregate principal amount of 4.50% Senior Notes due 2014, up to US$1,300 million aggregate principal amount of 5.70% Senior Notes due 2019 and up to US$1,400 million aggregate principal amount of 6.75% Senior Notes due 2039 registered under the U.S. Securities Act of 1933, as amended, for any and all of its outstanding 4.50% notes, 5.70% notes and 6.75% notes, which were issued on September 18, 2009 in a transaction exempt from registration. The exchange offer was launched on May 28, 2010, was extended on June 28, 2010 and expired on June 30, 2010. All of the 4.50% notes and 6.75% notes and substantially all of the 5.70% notes were exchanged in accordance with the terms of the exchange offer.

On June 24, 2010, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion.  The Canadian shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other foreign currencies from time to time in one or more offerings.  Terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates will be determined at the date of issue.  At June 30, 2010, $1.5 billion of the shelf remains unutilized.  The shelf prospectus expires in July 2012.

On July 7, 2010, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$1.5 billion. The U.S. shelf prospectus allows for the issuance of debt securities in U.S. dollars or other foreign currencies from time to time in one or more offerings.  Terms of the notes, including, but not limited to, interest at either fixed or floating rates and expiry dates will be determined at the date of issue.  The shelf prospectus expires in August 2012.

Cenovus Energy Inc.	63
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 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)	June 30, 2010		December 31, 2009
Asset Retirement Obligation, Beginning of Year	1,147		793
Liabilities Incurred	24		6
Liabilities Settled	(17	)	(38	)
Liabilities Divested	(13	)	(10	)
Change in Estimated Future Cash Outflows	(6	)	357
Accretion Expense	40		45
Foreign Currency Translation	-		(6	)
Asset Retirement Obligation, End of Period	1,175		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 June 30, 2010
	Number of Common Shares (millions)	Amount ($ millions)
Outstanding, Beginning of Year	751.3	3,681
Common Shares Issued under Option Plans	0.5	9
Outstanding, End of Period	751.8	3,690

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 June 30, 2010, there were 23 million Common Shares available for future issuance under stock option plans.  There were no Preferred Shares outstanding as at June 30, 2010.

On April 21, 2010, the Company established a dividend reinvestment plan (“DRIP”).  Under the DRIP, holders of Common Shares may reinvest all or a portion of the cash dividends payable on their Common Shares in additional Common Shares. At the discretion of the Company, the additional Common Shares may be issued from treasury at an average market price or purchased on the market at prevailing market rates.  For the purpose of the Common Shares issued from treasury, the average market price will be calculated as 100% of the volume weighted average price of the Common Shares traded on the TSX or the NYSE during the last five trading days preceding the relevant dividend payment date.  At the discretion of the board of directors of Cenovus, the treasury shares may be issued at a discount to the average market price but the discount may not exceed five percent. As at June 30, 2010, there was approximately 1.9% participation rate in the Plan and additional common shares were purchased on the market to satisfy DRIP requirements.

Cenovus Energy Inc.	64
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

14.  SHARE CAPITAL (continued)

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.

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	1.60	%
Dividend Yield	2.92	%
Volatility	28.21	%
Cenovus’s Closing Common Share Price at June 30, 2010	C$27.40

Cenovus Energy Inc.	65
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

14.  SHARE CAPITAL (continued)

The following tables summarize information related to the Cenovus Replacement TSARs held by Encana employees:

As at June 30, 2010
	Total Number of TSARs		Performance TSARs		Weighted Average Exercise Price (C$)
Outstanding, Beginning of Year	22,945,337		10,462,643		27.14
Exercised – SARs	(2,034,873	)	(214,794	)	21.39
Exercised – Options	(101,762	)	(171	)	19.18
Forfeited	(1,158,079	)	(975,648	)	28.55
Outstanding, End of Period	19,650,623		9,272,030		27.70
Exercisable, End of Period	12,938,857		5,056,893		27.15

	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$)
20.00 to 24.99	3,353,946	-	0.64	22.95	3,340,401	-	22.95
25.00 to 29.99	10,886,466	6,379,381	2.65	26.50	6,584,780	3,567,665	26.62
30.00 to 34.99	5,226,111	2,892,649	2.58	32.82	2,926,751	1,489,228	32.79
35.00 to 39.99	104,450	-	2.91	37.17	49,635	-	37.32
40.00 to 44.99	78,150	-	2.95	42.81	36,390	-	42.71
45.00 to 49.99	1,500	-	2.89	45.56	900	-	45.56
	19,650,623	9,272,030	2.29	27.70	12,938,857	5,056,893	27.15

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)	June 30, 2010		December 31, 2009
Debt	3,821		3,656
Shareholders’ Equity	10,055		9,608
Total Capitalization	13,876		13,264
Debt to Capitalization ratio	28	%	28	%

Cenovus Energy Inc.	66
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

15.  CAPITAL STRUCTURE (continued)

Cenovus targets a Debt to Adjusted EBITDA of between 1.0 and 2.0 times.

As at (C$ millions)	June 30, 2010	December 31, 2009
Debt	3,821	3,656
Net Earnings	840	818
Add (deduct):
Interest, net	273	244
Income tax expense	326	344
Depreciation, depletion and amortization	1,414	1,527
Accretion of asset retirement obligation	62	45
Foreign exchange (gain) loss, net	214	304
Other (income) loss, net	6	(2	)
Adjusted EBITDA	3,135	3,280
Debt to Adjusted EBITDA*	1.2x	1.1x

* Calculated on a trailing 12-month basis

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 June 30, 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.

Cenovus Energy Inc.	67
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

16.  COMPENSATION PLANS (continued)

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.

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	1.60%
Dividend Yield	2.55%
Volatility	28.40%
Encana’s Common Share Price	C$32.50

A) Tandem Share Appreciation Rights

The following tables summarize the information related to the TSARs held by Cenovus employees:

As at June 30, 2010
	Total Number of TSARs		Performance TSARs		Weighted Average Exercise Price (C$)
TSARs – Outstanding, Beginning of Year	16,454,727		8,053,074		27.52
Granted	5,721,785		-		26.38
Exercised – SARs	(752,747	)	(52,367	)	20.02
Exercised – Options	(220,896	)	(13,787	)	20.74
Forfeited	(648,027	)	(604,566	)	28.52
Outstanding, End of Period	20,554,842		7,382,354		27.52
Exercisable, End of Period	8,946,087		3,749,074		27.51

	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$)
20.00 to 24.99	2,105,220	-	0.70	22.95	2,066,865	-	22.94
25.00 to 29.99	14,029,356	4,913,888	4.37	26.43	4,466,631	2,474,238	26.59
30.00 to 34.99	4,223,066	2,468,466	2.62	32.89	2,321,556	1,274,836	32.88
35.00 to 39.99	124,350	-	2.95	37.14	54,060	-	37.03
40.00 to 44.99	70,850	-	2.96	43.28	35,775	-	43.25
45.00 to 49.99	2,000	-	2.89	45.56	1,200	-	45.56
	20,554,842	7,382,354	3.62	27.52	8,946,087	3,749,074	27.51

For the six months ended June 30, 2010, Cenovus has recorded $11 million in compensation costs related to TSARs.

Cenovus Energy Inc.	68
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 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 June 30, 2010
	Total Number of SARs		Performance SARs		Weighted Average Exercise Price (C$)
SARs – Outstanding, Beginning of Year	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	16,226		8,246		30.42

	Outstanding SARs				Exercisable SARs
Range of Exercise Price (C$)	Total Number of SARs	Performance SARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	Total Number of SARs	Performance SARs	Weighted Average Exercise Price (C$)
25.00 to 29.99	24,128	10,528	3.64	26.83	6,768	2,688	26.86
30.00 to 34.99	17,258	10,758	2.63	32.96	9,458	5,558	32.96
	41,386	21,286	3.22	29.38	16,226	8,246	30.42

For the six months ended June 30, 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 June 30, 2010
	Total Number of TSARs		Performance TSARs		Weighted Average Exercise Price (C$)
Replacement TSARs – Outstanding, Beginning of Year	16,356,660		8,051,692		30.46
Exercised – SARs	(1,181,346	)	(112,832	)	23.64
Exercised – Options	(91,320	)	(45	)	21.31
Forfeited	(649,495	)	(612,600	)	31.53
Outstanding, End of Period	14,434,499		7,326,215		31.02
Exercisable, End of Period	8,614,954		3,700,835		30.56

	Outstanding Encana Replacement TSARs				Exercisable Encana Replacement TSARs
Range of Exercise Price (C$)	Total Number of TSARs	Performance TSARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	Total Number of TSARs	Performance TSARs	Weighted Average Exercise Price (C$)
20.00 to 24.99	7,650	-	3.26	23.05	2,050	-	23.11
25.00 to 29.99	9,762,041	4,860,412	2.46	28.46	6,007,921	2,426,562	28.10
30.00 to 34.99	385,110	-	1.95	32.39	280,150	-	32.29
35.00 to 39.99	4,133,648	2,465,803	2.63	36.47	2,257,393	1,274,273	36.46
40.00 to 44.99	74,200	-	3.00	42.28	31,065	-	42.19
45.00 to 49.99	69,850	-	2.96	47.92	35,175	-	47.88
50.00 to 54.99	2,000	-	2.89	50.39	1,200	-	50.39
	14,434,499	7,326,215	2.50	31.02	8,614,954	3,700,835	30.56

For the six months ended June 30, 2010, the Company has recorded a reduction of compensation costs of $4 million related to the Encana Replacement TSARs.

Cenovus Energy Inc.	69
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

16.  COMPENSATION PLANS (continued)

D) Encana Replacement Share Appreciation Rights

The following tables summarize information related to the Encana Replacement SARs held by Cenovus employees:

As at June 30, 2010
	Total Number of SARs		Performance SARs		Weighted Average Exercise Price (C$)
Encana Replacement SARs – Outstanding, Beginning of Year	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	16,226		8,246		33.63

	Outstanding Encana Replacement SARs				Exercisable Encana Replacement SARs
Range of Exercise Price (C$)	Total Number of SARs	Performance SARs	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price (C$)	Total Number of SARs	Performance SARs	Weighted Average Exercise Price (C$)
25.00 to 29.99	21,128	10,528	3.59	29.25	5,868	2,688	29.26
30.00 to 34.99	3,000	-	3.96	32.55	900	-	32.55
35.00 to 39.99	17,258	10,758	2.63	36.44	9,458	5,558	36.44
	41,386	21,286	3.22	32.49	16,226	8,246	33.63

For the six months ended June 30, 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.

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 June 30, 2010
	Outstanding DSUs
Outstanding, Beginning of Year	768,103
Granted	62,545
Granted from Annual Bonus Awards	81,117
Units in Lieu of Dividends	13,765
Outstanding, End of Period	925,530

For the six months ended June 30, 2010, the Company has recorded $3 million in compensation costs related to DSUs.

Cenovus Energy Inc.	70
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

16.  COMPENSATION PLANS (continued)

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 June 30, 2010
	Outstanding PSUs
Outstanding, Beginning of Year	-
Granted	1,251,995
Cancelled	(15,410	)
Units in Lieu of Dividends	18,910
Outstanding, End of Period	1,255,495

For the six months ended June 30, 2010, the Company has recorded $7 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.

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.

Cenovus Energy Inc.	71
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

The fair value of financial assets and liabilities, including current portions thereof were as follows:

As at (C$ millions)	June 30, 2010		December 31, 2009
	Carrying	Fair	Carrying	Fair
	Amount	Value	Amount	Value
Financial Assets
Held-for-trading:
Cash and cash equivalents	409	409	155	155
Risk management assets	258	258	61	61
Loans and Receivables:
Accounts receivable and accrued revenues	1,063	1,063	978	978
Partnership Contribution Receivable	2,834	2,834	2,966	2,966
Member loans receivable	292	292	183	183
Financial Liabilities
Held-for-trading:
Risk management liabilities	12	12	74	74
Other Financial Liabilities:
Accounts payable and accrued liabilities	1,547	1,547	1,574	1,574
Long-term debt	3,821	4,286	3,656	3,964
Partnership Contribution Payable	2,861	2,861	2,990	2,990
Member loans payable	292	292	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.

Net Risk Management Position

As at (C$ millions)	June 30, 2010	December 31, 2009
Risk Management
Current asset	196	60
Long-term asset	62	1
	258	61
Risk Management
Current liability	8	70
Long-term liability	4	4
	12	74
Net Risk Management Asset (Liability)	246	(13)

Of the $246 million net risk management asset balance at June 30, 2010, an asset of $108 million relates to the contract with Encana.

Summary of Unrealized Risk Management Positions

As at (C$ millions)	June 30, 2010			December 31, 2009
	Risk Management			Risk Management
	Asset	Liability	Net	Asset	Liability	Net
Commodity Prices
Natural Gas	199	-	199	53	-	53
Crude Oil	59	3	56	8	66	(58)
Power	-	9	(9)	-	8	(8)
Total Fair Value	258	12	246	61	74	(13)

Cenovus Energy Inc.	72
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

Net Fair Value Methodologies Used to Calculate Unrealized Risk ManagementPositions

As at (C$ millions)	June 30, 2010	December 31, 2009
Prices actively quoted	254		6
Prices sourced from observable data or market corroboration	(8)		(19)
Total Fair Value	246		(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.

Net Fair Value of Commodity Price Positions at June 30, 2010

As at June 30, 2010 (C$ millions)	Notional Volumes	Term	Average Price	FairValue
Crude Oil Contracts
Fixed Price Contracts
WTI NYMEX Fixed Price	29,100 bbls/d	2010	US$78.91/bbl	11
WTI NYMEX Fixed Price	5,000 bbls/d	2010	C$89.65/bbl	7
WTI NYMEX Fixed Price	5,000 bbls/d	2011	US$90.98/bbl	22
WTI NYMEX Fixed Price	6,000 bbls/d	2011	C$92.77/bbl	17
Other Financial Positions *				(1)
Crude Oil Fair Value Position				56
Natural Gas Contracts
Fixed Price Contracts
NYMEX Fixed Price	444 MMcf/d	2010	US$6.12/Mcf	114
NYMEX Fixed Price	351 MMcf/d	2011	US$5.82/Mcf	65
NYMEX Fixed Price	60 MMcf/d	2012	US$6.49/Mcf	19
Basis Contracts **
Canada		2010		1
Canada		2011-2013		-
Natural Gas Fair Value Position				199
Power Purchase Contracts
Power Fair Value Position				(9)

*  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		Six Months Ended
For the period ended June 30, (C$ millions)	2010	2009	2010	2009
Gross Revenues	81	349	109	652
Less: Royalties	-	-	-	-
Net Revenues	81	349	109	652
Operating Expenses and Other	10	(2)	7	(33)
Gain (Loss) on Risk Management	91	347	116	619

Cenovus Energy Inc.	73
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

	Unrealized Gain (Loss)
	Three Months Ended		Six Months Ended
For the period ended June 30, (C$ millions)	2010	2009	2010	2009
Gross Revenues	20	(294)	261	(189)
Less:  Royalties	-	-	-	-
Net Revenues	20	(294)	261	(189)
Operating Expenses and Other	2	(3)	(2)	(22)
Gain (Loss) on Risk Management	22	(297)	259	(211)

Reconciliation of Unrealized Risk Management Positions from January 1 to June 30,

(C$ millions)		2010	2009
		Total	Total
	Fair	Unrealized	Unrealized
	Value	Gain (Loss)	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	375	375	408
Fair Value of Contracts Realized During the Period	(116)	(116)	(619)
Fair Value of Contracts, End of Period	246	259	(211)

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 June 30, 2010 as follows:

	10%Price		10%Price
(C$ millions)	Increase		Decrease
Natural gas price	(125	)	125
Crude oil price	(45	)	45
Power price	3		(3)

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.

Cenovus Energy Inc.	74
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 2010

17.  FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (continued)

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.

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 June 30, 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 June 30, 2010, Cenovus had three 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.  It is Cenovus’s intention to maintain investment grade credit ratings on its senior unsecured debt.

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, undrawn credit facilities, commercial paper and availability under its shelf prospectuses.  At June 30, 2010, Cenovus had $2.3 billion available on its committed bank credit facility and $1.5 billion in unused capacity under its Canadian shelf prospectus, the availability of which is dependent on market conditions. On July 7, 2010 an additional US$1.5 billion in unused capacity was made available under Cenovus’s U.S. shelf prospectus, the availability of which is dependent on market conditions.

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	1,547	-	-	-	1,547
Risk Management Liabilities	8	4	-	-	12
Long-Term Debt*	218	600	1,263	5,673	7,754
Partnership Contribution Payable*	518	1,037	1,037	908	3,500
Member Loans Payable	-	292	-	-	292

*Principal and interest, including current portion

Cenovus Energy Inc.	75
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in C$ millions, unless otherwise indicated

For the period ended June 30, 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 June 30, 2010, Cenovus had US$3,575 million in U.S. dollar debt issued from Canada (US$3,525 million at December 31, 2009) and US$2,672 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 $9 million change in foreign exchange (gain) loss at June 30, 2010 (2009–$10 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.

For the six months ended June 30, 2010, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to $1 million (2009–$3 million).

18.  PER SHARE AMOUNTS

For the period ended June 30,	Three Months Ended		Six Months Ended
	2010	2009	2010	2009
Weighted Average Common Shares Outstanding – Basic	751.7	751.0	751.6	750.8
Effect of Dilutive Securities	0.1	0.4	0.2	0.6
Weighted Average Common Shares Outstanding – Diluted	751.8	751.4	751.8	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.	76
Second Quarter 2010 Interim Report	Notes to Consolidated Financial Statements

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

(C$ millions, except per share amounts)		2010				2009
		Year to Date	Q2	Q1			Year		Q4		Q3		Q2		Q1
Gross Revenues		6,920	3,318	3,602			11,790		3,103		3,080		2,871		2,736
Less: Royalties		234	123	111			273		98		79		53		43
Net Revenues		6,686	3,195	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		391	176	215			663		232		198		162		71
Canadian Plains		543	234	309			1,057		289		314		275		179
Natural Gas		582	268	314			2,061		412		500		555		594
Other Upstream Operations		17	11	6			50		9		27		3		11
		1,533	689	844			3,831		942		1,039		995		855
Downstream		(30)	(24)	(6	)		358		12		95		178		73
Operating Cash Flow		1,503	665	838			4,189		954		1,134		1,173		928
Cash Flow Information
Cash from Operating Activities		1,291	471	820			3,039		150		1,414		793		682
Deduct (Add back):
Net change in other assets and liabilities		(28)	(13)	(15	)		(26	)	(14	)	(3	)	(6	)	(3	)
Net change in non-cash working capital		61	(53)	114			220		(71	)	493		(146	)	(56	)
Cash Flow (1)		1,258	537	721			2,845		235		924		945		741
Per share           - Basic		1.67	0.71	0.96			3.79		0.31		1.23		1.26		0.99
- Diluted		1.67	0.71	0.96			3.79		0.31		1.23		1.26		0.99
Operating Earnings (2)		495	142	353			1,522		169		427		512		414
Per share           - Diluted		0.66	0.19	0.47			2.03		0.23		0.57		0.68		0.55
Net Earnings		697	172	525			818		42		101		160		515
Per share           - Basic		0.93	0.23	0.70			1.09		0.06		0.13		0.21		0.69
- Diluted		0.93	0.23	0.70			1.09		0.06		0.13		0.21		0.69
Effective Tax Rates using
Net Earnings		15.3%					29.6%
Operating Earnings, excluding divestitures		12.4%					25.0%
Canadian Statutory Rate		28.2%					29.2%
Foreign Exchange Rates (US$ per C$1)
Average		0.967	0.973	0.961			0.876		0.947		0.911		0.857		0.803
Period end		0.943	0.943	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 (Non-GAAP measures)
Debt to Capitalization (1)		28%	28%
Debt to Adjusted EBITDA (1)		1.2x	1.1x
Return on Capital Employed (2)		8%	8%
Return on Common Equity (3)		8%	8%
(1)	Non-GAAP measure as defined in the Interim Consolidated Financial Statements and Management’s Discussion and Analysis
(2)	Calculated as, on a trailing twelve-month basis, net earnings before after tax interest divided by average shareholder’s equity plus average debt, including current portion
(3)	Calculated as, on a trailing twelve-month basis, net earnings divided by average shareholder’s equity

Common Share Information		2010			December
		Year to Date	Q2	Q1		2009
Common Shares Outstanding (millions) (1)
Period end		751.8	751.8	751.7		751.3
Average - Basic		751.6	751.7	751.5		751.0
Average - Diluted		751.8	751.8	751.7		751.4
Price Range ($ per share)
TSX - C$
High		30.63	30.63	27.84		27.18
Low		24.26	25.83	24.26		24.68
Close		27.40	27.40	26.53		26.50
NYSE - US$
High		30.66	30.66	26.79		25.70
Low		22.87	23.84	22.87		23.37
Close		25.79	25.79	26.21		25.20
Dividends Paid ($ per share) (2)		C$0.40	C$0.20	C$0.20		US$0.20
Share Volume Traded (millions)		446.3	241.8	204.5		83.5
(1)	Cenovus Common Shares were issued under the terms of the plan of arrangement with Encana Corporation (“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 based on carve-out earnings and cash flows.

Cenovus Energy Inc.	77
Second Quarter 2010 Interim Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

Net Capital Investment (C$ millions)			2010								2009
	Year to Date		Q2		Q1		Year		Q4		Q3	Q2	Q1
Capital Investment
Upstream Canada
Foster Creek	109		52		57		262		76		62	59	65
Christina Lake	147		84		63		224		66		53	49	56
Canadian Plains	241		102		139		553		115		104	99	235
Other	42		11		31		57		5		4	14	34
	539		249		290		1,096		262		223	221	390
Downstream Refining	370		168		202		1,032		224		291	265	252
Corporate	14		13		1		34		21		1	2	10
Capital Investment	923		430		493		2,162		507		515	488	652
Acquisitions	47		47		-		148		146		1	1	-
Divestitures	(144	)	(72	)	(72	)	(367	)	(366	)	2	(3)	-
Net Acquisition and Divestiture Activity	(97	)	(25	)	(72	)	(219	)	(220	)	3	(2)	-
Net Capital Investment	826		405		421		1,943		287		518	486	652

Operating Statistics - Before Royalties

Upstream Production Volumes			2010				2009
		Year to Date	Q2	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Heavy Oil
Foster Creek		51,067	51,010	51,126	37,725	47,017	40,367	34,729	28,554
Christina Lake		7,569	7,716	7,420	6,698	7,319	6,305	6,530	6,635
Integrated Oil - Senlac		-	-	-	3,057	2,221	5,080	2,574	2,334
Canadian Plains		36,210	35,572	36,856	38,668	37,057	38,989	37,643	41,023
Light and Medium Oil
Canadian Plains		33,544	33,102	33,991	34,484	34,518	34,504	34,609	34,300
Natural Gas Liquids (1)
Canadian Plains		1,161	1,166	1,156	1,206	1,183	1,242	1,184	1,213
Total Crude Oil and Natural Gas Liquids		129,551	128,566	130,549	121,838	129,315	126,487	117,269	114,059
Natural Gas (MMcf/d)
Integrated Oil - Other		42	43	42	50	44	52	54	50
Canadian Plains		720	708	733	787	753	778	802	816
Total Natural Gas Production		762	751	775	837	797	830	856	866
(1)	Natural gas liquids include condensate volumes.

Average Royalty Rates

(excluding impact of realized financial hedging)	2010			2009
	Year to Date	Q2	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil - Foster Creek	14.5%	19.0%	9.7%	2.7%	3.9%	3.0%	1.5%	1.4%
Crude Oil - Christina Lake	4.2%	4.4%	4.0%	2.3%	3.6%	2.9%	1.6%	1.0%
Crude Oil - Pelican Lake/Weyburn	22.9%	23.5%	19.6%	19.4%	22.8%	19.9%	19.2%	15.7%
Crude Oil - Other	9.1%	9.3%	10.9%	7.8%	8.4%	9.0%	6.1%	5.4%
Natural Gas	2.3%	1.7%	2.8%	1.5%	3.9%	0.5%	-0.9%	2.8%
Natural Gas Liquids	2.1%	2.0%	2.1%	1.6%	1.6%	2.1%	1.9%	1.0%

Downstream Refining		2010			2009
		Year to Date	Q2	Q1	Year	Q4	Q3	Q2	Q1
Refinery Operations (1)
Crude oil capacity (Mbbls/d)		452	452	452	452	452	452	452	452
Crude oil runs (Mbbls/d)		367	379	355	394	348	425	404	398
Crude utilization (%)		81%	84%	79%	87%	77%	94%	89%	88%
Refined products (Mbbls/d)		388	398	377	417	370	451	428	421
(1)	Represents 100% of the Wood River and Borger refinery operations.

Cenovus Energy Inc.	78
Second Quarter 2010 Interim Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results
(C$, excluding impact of realized financial hedging)		2010							2009
			Year to Date		Q2		Q1		Year		Q4		Q3		Q2	Q1
Crude Oil - Heavy - Foster Creek ($/bbl)
Price (1)		58.88			54.75		63.33		55.55		63.60		62.20		54.43	33.44
Royalties		7.64			9.38		5.76		1.42		2.31		1.85		0.66	0.22
Transportation and selling		2.37			2.40		2.33		2.51		1.71		2.50		3.45	2.69
Operating		10.72			10.36		11.11		11.87		10.43		10.85		11.81	15.91
Netback		38.15			32.61		44.13		39.75		49.15		47.00		38.51	14.62
Crude Oil - Heavy - Christina Lake ($/bbl)
Price (2)		58.55			54.99		62.27		53.45		57.07		64.85		57.32	32.44
Royalties		2.23			2.19		2.28		1.24		2.04		1.72		0.83	0.23
Transportation and selling		4.49			4.52		4.47		3.09		0.96		5.36		2.83	3.38
Operating		16.46			16.50		16.41		16.31		18.06		15.31		13.69	18.21
Netback		35.37			31.78		39.11		32.81		36.01		42.46		39.97	10.62
Crude Oil - Heavy - Canadian Plains ($/bbl)
Price (3)		65.22			61.02		69.40		55.00		62.00		63.01		56.09	38.76
Royalties		13.50			13.14		13.85		9.23		11.29		11.54		8.62	5.42
Production and mineral taxes		0.03			(0.03	)	0.09		(0.01	)	0.02		(0.01	)	0.02	(0.07	)
Transportation and selling		1.58			1.66		1.51		1.08		0.71		0.99		1.35	1.24
Operating		12.00			12.93		11.08		9.28		11.68		7.82		9.49	8.30
Netback		38.11			33.32		42.87		35.42		38.30		42.67		36.61	23.87
Crude Oil - Heavy - Total ($/bbl)
Price (4)		61.29			57.12		65.64		55.14		62.46		62.67		55.55	36.15
Royalties		9.45			10.20		8.66		5.20		6.02		6.42		4.85	3.03
Production and mineral taxes		0.01			(0.01	)	0.04		0.03		0.03		0.05		0.05	(0.04	)
Transportation and selling		2.24			2.29		2.18		1.90		1.27		2.05		2.39	1.98
Operating		11.70			11.86		11.53		11.03		11.45		9.60		11.09	12.19
Netback		37.89			32.78		43.23		36.98		43.69		44.55		37.17	18.99
Light and Medium Oil - Canadian Plains ($/bbl)
Price		72.11			66.43		77.71		62.36		71.25		67.53		63.59	46.57
Royalties		9.41			9.46		9.37		6.82		10.88		7.30		5.98	3.02
Production and mineral taxes		2.45			2.79		2.12		2.20		1.55		2.20		1.94	3.14
Transportation and selling		0.88			0.91		0.85		0.89		0.63		0.74		1.07	1.12
Operating		12.30			13.11		11.51		10.18		9.93		9.98		9.83	11.01
Netback		47.07			40.16		53.86		42.27		48.26		47.31		44.77	28.28
Crude Oil - Total ($/bbl)
Price		64.12			59.51		68.87		57.22		64.85		64.00		57.95	39.40
Royalties		9.44			10.01		8.85		5.67		7.34		6.66		5.18	3.03
Production and mineral taxes		0.65			0.71		0.59		0.65		0.44		0.64		0.62	0.95
Transportation and selling		1.88			1.94		1.83		1.61		1.10		1.69		2.00	1.71
Operating		11.86			12.18		11.52		10.78		11.04		9.70		10.72	11.82
Netback		40.29			34.67		46.08		38.51		44.93		45.31		39.43	21.89
Natural Gas Liquids - Canadian Plains ($/bbl)
Price		63.02			58.71		67.42		49.08		59.06		49.17		44.65	43.42
Royalties		1.28			1.16		1.39		0.81		0.96		1.00		0.82	0.46
Netback		61.74			57.55		66.03		48.27		58.10		48.17		43.83	42.96
Total Liquids ($/bbl)
Price		64.11			59.50		68.85		57.14		64.79		63.85		57.81	39.45
Royalties		9.37			9.93		8.78		5.62		7.28		6.60		5.14	3.00
Production and mineral taxes		0.65			0.71		0.59		0.65		0.44		0.63		0.61	0.94
Transportation and selling		1.87			1.94		1.83		1.60		1.09		1.67		1.98	1.69
Operating		11.75			12.07		11.42		10.67		10.94		9.61		10.61	11.69
Netback		40.47			34.85		46.23		38.60		45.04		45.34		39.47	22.13
Total Natural Gas(5) ($/Mcf)
Price		4.53			3.78		5.27		4.15		4.17		3.14		3.80	5.47
Royalties		0.11			0.07		0.14		0.08		0.16		0.02		0.01	0.15
Production and mineral taxes		0.02			(0.04	)	0.07		0.05		0.03		0.04		0.07	0.05
Transportation and selling		0.18			0.15		0.21		0.15		0.12		0.16		0.16	0.18
Operating		0.94			0.94		0.94		0.86		0.81		0.84		0.83	0.94
Netback		3.28			2.66		3.91		3.01		3.05		2.08		2.73	4.15
Total ($/BOE)
Price		45.80			41.46		50.16		39.88		44.54		40.43		38.65	35.71
Royalties		5.04			5.26		4.81		2.87		4.05		3.22		2.35	1.81
Production and mineral taxes		0.38			0.24		0.52		0.46		0.30		0.43		0.52	0.58
Transportation and selling		1.48			1.43		1.53		1.24		0.91		1.29		1.41	1.34
Operating(6)		8.73			8.93		8.53		7.71		7.85		7.24		7.52	8.27
Netback		30.17			25.60		34.77		27.60		31.43		28.25		26.85	23.71
(1)	The Foster Creek YTD heavy oil price has been reduced by the cost of condensate purchases ($38.65/bbl) which are blended with the heavy oil.
(2)	The Christina Lake YTD heavy oil price has been reduced by the cost of condensate purchases ($40.41/bbl) which are blended with the heavy oil.
(3)	The Canadian Plains YTD heavy oil price has been reduced by the cost of condensate purchases of ($15.83/bbl) which are blended with the heavy oil.
(4)	The total YTD heavy oil price has been reduced by the cost of condensate purchases of ($30.03/bbl) which are blended with the heavy oil.
(5)	Natural gas - Total includes natural gas from Canadian Plains and the Athabasca property.
(6)	2010 year-to-date operating costs include costs related to long-term incentives of $0.04/BOE (2009 - $0.04/BOE).
Impact of Realized Financial Hedging
Liquids ($/bbl)		(0.58		)	(0.40	)	(0.78	)	1.10		(0.05	)	(0.01	)	1.54	3.29
Natural Gas ($/Mcf)		0.87			1.22		0.53		3.63		2.27		4.41		4.33	3.43
Total ($/BOE)		2.29			3.37		1.20		12.16		6.92		13.77		14.91	13.06

Cenovus Energy Inc.	79
Second 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:
Susan Grey	Rhona DelFrari
Director, Investor Relations	Manager, Media Relations
403-766-4751	403-766-4740
susan.grey@cenovus.com	rhona.delfrari@cenovus.com
James Fann
Analyst, Investor Relations
403-766-6700
james.fann@cenovus.com

www.cenovus.com