Cenovus total proved reserves up 19% to 1.7 billion BOE

Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE):

• Proved bitumen reserves at December 31, 2010 were 1.2 billion barrels (bbls), a 33% increase over 2009.
• Best estimate bitumen economic contingent resources at December 31, 2010 were 6.1 billion bbls, a 13% increase over 2009.
• Finding and development (F&D) costs for 2010 were $3.65 per barrel of oil equivalent (BOE), without future development costs.
• Combined Foster Creek and Christina Lake production was 59,045 barrels per day (bbls/d) net to Cenovus in 2010, a 33% increase compared with 2009.
• Cash flow remained strong in 2010 at $2.4 billion, or $3.21 per share, for the year.
• Conventional oil and gas properties generated about $1.3 billion of operating cash flow in excess of the capital spent on them, providing the majority of the cash required to fund oil sands growth.

“We have made huge strides in Cenovus’s first year as an independent company and laid the groundwork for substantial growth from our oil assets,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “The milestones we set at the beginning of 2010 were met or exceeded. Production at our oil sands operations is higher than anticipated, our conventional assets continue to deliver strong operating cash flow, we have a solid balance sheet that enables us to proceed with our expansion plans and we continue to develop technologies that allow us to be more effective, operationally and environmentally.”

“The increase in our reserves and resources bookings, combined with our highly competitive finding and development costs, confirms the wealth of opportunity Cenovus has to build net asset value and generate an attractive total shareholder return,” Ferguson said. “We are working hard to determine the most efficient way to bring forward the value of our huge resource base for the benefit of our investors.”

1 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory. See also the Earnings Reconciliation Summary.
2 Does not include volumes from the Senlac property, which was sold in the fourth quarter of 2009.

Cenovus Energy Inc. delivered excellent operating and financial performance in 2010 with significant oil sands production increases, a strong balance sheet that further improved throughout the year and ongoing investments in technology development that are expected to result in even more of the resource being captured through greater efficiencies.

“We achieved great success in all elements of our business,” Ferguson said. “We continued to expand our oil sands operations and increase production, our established natural gas and conventional oil properties generated reliable cash flow that was invested in our oil sands growth and Cenovus continued to be recognized as a low-cost and responsible producer.”

The Foster Creek and Christina Lake oil sands operations achieved a 33% production increase in 2010 compared with 2009. Foster Creek exited 2010 with net production of approximately 54,000 bbls/d and is expected to be producing 56,000 bbls/d net at the end of 2011 with planned expansions leading to greater growth in the following years. At Christina Lake, oil production exceeded 9,000 bbls/d net at year-end 2010. The 2011 exit rate at Christina Lake is expected to reach 16,000 bbls/d net, mainly as a result of production from phase C commencing in the third quarter of 2011. Oil sands production growth is expected to continue for years as new expansions are brought on and more innovative technologies are implemented on a commercial scale.

The 2010 independent reserves and contingent resources evaluation supports Cenovus’s plans to grow oil sands production. The independent qualified reserves evaluators estimated that Cenovus had nearly 1.2 billion bbls of proved bitumen reserves on December 31, 2010, 33% more than a year earlier. The increase in reserves is mainly attributed to the approved expansion of the Foster Creek development area and increased recovery due to advancements in technology, such as wedge wells, and improved reservoir performance.

In addition to the expanded reserves numbers, there was a significant increase to the company’s bitumen economic contingent resources in 2010, mainly attributed to the assessment data collected from stratigraphic (strat) wells. Best estimate bitumen economic contingent resources at year-end 2010 were 6.1 billion bbls, a 13% increase over 2009.

Cenovus continues to assess its resources and prepare for additional regulatory applications through its strat well program. On a gross basis, about 260 of these assessment wells were drilled at the company’s oil sands properties in 2010 and an additional 450 strat wells are expected to be completed in 2011.

Cash flow remains strong

Higher oil production and strong oil prices contributed to 2010 cash flow of $2.4 billion. Cash flow was 15% less than in 2009 due to lower realized natural gas prices and lower natural gas volumes, partially as a result of divestitures. Cenovus’s refineries experienced lower cash flow in 2010 mainly due to planned turnarounds, higher crude costs and refinery optimization in response to weaker diesel and gasoline prices in the first half of the year. As expected, cash flow at the refineries improved considerably in the fourth quarter of 2010 due to stronger refining margins and increased utilization.

Production targets achieved

Cenovus invested about $2.1 billion in capital during 2010, slightly lower than the previous year. The lower spending was mainly due to project delays at conventional oil properties caused by poor weather and various module delivery delays for the expansion project at the Wood River Refinery as a result of record Mississippi River levels. About $750 million of 2010 capital investment focused on the continued development of Foster Creek and Christina Lake, the start up of the Grand Rapids pilot and the assessment of future oil sands projects. An additional $104 million was spent expanding the heavy oil growth opportunity at Pelican Lake. More than $530 million was spent on other conventional properties, primarily oil assets, including appraisal projects in the Bakken and Lower Shaunavon areas. Despite deferred capital investment in 2010, conventional oil and natural gas production remained at expected levels.

Cenovus anticipating increased industry activity in oil sands

Cenovus is well positioned to deal with inflationary pressure expected to result from renewed investment in several industry oil sands projects in 2011. The company anticipates 3% to 5% higher costs – mainly due to labour – for the expansion of its oil sands operations this year. The location of its major properties, away from the Fort McMurray area, provides advantages in attracting workers and allows the company to support contractors in smaller communities near its operations. Cenovus expects to continue to bring on new expansions at an industry-leading capital efficiency of about $22,000 - $28,000 per flowing barrel.

“We believe our proven track record of developing oil sands properties at a low cost will benefit Cenovus as construction activity picks up in northern Alberta,’’ said John Brannan, Cenovus Executive Vice-President & Chief Operating Officer. “Our phased, manufacturing approach to expansions and our module assembly yard in Nisku provide us with greater control over quality, costs and project delivery. We’ve earned a reputation for developing our projects safely, on time and on budget and we have every intention of maintaining that performance.”

2011 refining performance better than anticipated

The improved results experienced at Cenovus’s refineries in the fourth quarter of 2010 are continuing to date in 2011 with operating cash flow from the refineries for the first quarter expected to be in the $25 million to $75 million range, net to Cenovus excluding inventory adjustments. This is mainly due to the lower cost of heavy crudes which has resulted in stronger than normal realized crack spreads for this time of year. Cenovus is currently maintaining its full year guidance for refining operating cash flow at $0 to $100 million.

Oil Growth Projects

1 Totals may not add due to rounding.

Foster Creek and Christina Lake

Cenovus’s oil sands properties in northern Alberta offer opportunities for substantial growth. The Foster Creek and Christina Lake operations use steam-assisted gravity drainage (SAGD) to drill and pump the oil to the surface. Those two projects are operated by Cenovus and jointly owned with ConocoPhillips. In addition, Cenovus has identified 10 other oil sands projects for future development. Advancing technologies that reduce the amount of water, natural gas and electricity used and minimize land disturbance is a priority for Cenovus.

Production

• Net production at Foster Creek and Christina Lake increased 33% in 2010 compared with 2009.
• Foster Creek produced more than 51,000 bbls/d net. This was mainly as a result of the continued ramp up of production from phases D and E, which started producing in early 2009, as well as increased production from wedge wells.
• About 13% of current production at Foster Creek comes from wedge wells. These single horizontal wells, drilled between existing SAGD well pairs, reach oil that would otherwise be unrecoverable. Wedge wells have the potential to increase overall recovery from the reservoir by 10%, while reducing the steam to oil ratio (SOR). The company plans to drill 10 additional wedge wells at Foster Creek in 2011. There are 51 wedge wells drilled to date at Foster Creek, with 33 producing and the rest expected to start producing in the first half of the year. One wedge well is producing at Christina Lake, with three more drilled and expected to start producing later this year.
• Christina Lake production averaged nearly 8,000 bbls/d net in 2010. This was mainly due to increased production from the phase B expansion and production from the first wedge well.

Expansions

• Construction of phases C and D at Christina Lake is progressing with phase C nearly 90% complete and production expected to begin in the second half of 2011. Phase D is expected to begin producing in 2013, approximately six months ahead of the original schedule. Each phase is expected to add an additional 40,000 bbls/d of gross production capacity, bringing total gross production capacity at Christina Lake to 98,000 bbls/d.
• In the third quarter of 2010, the company received regulatory approval from the Alberta Energy Resources Conservation Board (ERCB) for the Foster Creek expansion phases F, G and H. When these phases are completed, they are expected to increase Foster Creek’s gross production capacity to 210,000 bbls/d from the current 120,000 bbls/d.
• Interim funding for phase F at Foster Creek has been approved by the partners with final approval for phases F, G and H expected later this year.
• Engineering and preliminary ground work on phase F continues, with first production expected in 2014, a year ahead of initial plans. Phases G and H are expected to start producing in 2016 and 2017, respectively.
• Cenovus plans to present a more detailed update on the Foster Creek and Christina Lake expansions later this year.

Costs

• Operating costs at Foster Creek and Christina Lake averaged $11.28/bbl in 2010, a 10% decrease from $12.53/bbl in 2009. This was mainly due to increased production combined with fewer workovers, repairs and maintenance.
• Non-fuel operating costs were $8.90/bbl in 2010 compared with $10.30/bbl in 2009, a 14% decrease.
• As a result of the Foster Creek project reaching payout for royalty purposes in February 2010, its average royalty rate was 16.2% in 2010, including pre-payout royalties for one month, compared with 2.7% in 2009, a $146 million increase.
• Cenovus continued to achieve some of the best SORs in the industry with a ratio of approximately 2.0 at Christina Lake and 2.3 at Foster Creek for a combined SOR of 2.2 in 2010. This means 2.2 barrels of steam are needed for every barrel of oil produced. A lower SOR means less natural gas is used to create the steam, which results in reduced capital and operating costs, fewer emissions and lower water usage.

Greater Pelican Region

Cenovus produces heavy oil from the mobile Wabiskaw formation at its 100% owned Pelican Lake operation in the Greater Pelican Region, about 300 kilometres north of Edmonton. Since 2006, polymer has been injected along with the water flood to enhance production from this reservoir. Based on reservoir performance of the polymer flood, the company has initiated a new multi-year growth plan for Pelican Lake Wabiskaw.

• Cenovus is investing capital at Pelican Lake to expand the polymer flood and drill additional infill wells, which is expected to result in higher production beginning in late 2011.
• The company is initiating a multi-year plan to increase drilling with production expected to reach 40,000 bbls/d to 50,000 bbls/d.
• Pelican Lake produced about 23,000 bbls/d in 2010, an 8% decrease in production compared with 2009, due to expected natural declines.
• Operating costs at Pelican Lake in 2010 averaged $12.76/bbl, a 33% increase over 2009 due to higher chemical costs associated with the expansion of the polymer flood as well as increased maintenance and workover expenses.

Future Projects

Cenovus has an enormous opportunity to deliver increased shareholder value through production growth from its oil sands assets in the Athabasca region of northeast Alberta, most of which are undeveloped. The company continues to assess its resources to prioritize development plans and support regulatory applications.

• A regulatory application for the Narrows Lake project, jointly owned with ConocoPhillips, is now with the ERCB and Alberta Environment. The application is the first to include the option of using a combination of SAGD and solvent aided process (SAP) for oil production. Narrows Lake is expected to have gross production capacity of 130,000 bbls/d with initial production expected in 2016. In preparation for regulatory approval, 39 gross strat wells were drilled in 2010 at Narrows Lake.
• A SAGD pilot project is underway at the 100% owned Grand Rapids asset in the Greater Pelican Region. Cenovus drilled 71 strat wells at Grand Rapids in 2010, bringing the total to 96. Steaming of the single well pair for the pilot started in December and early results are expected in the first half of 2011. A regulatory application for a commercial operation could be filed by the end of the year. The first commercial phase of the project, with capacity of 60,000 bbls/d, could be on production as early as 2017. Grand Rapids is a 100% Cenovus-owned project that has the potential for production capacity of up to 180,000 bbls/d.
• At the 100% owned Telephone Lake project in the Borealis Region, Cenovus is awaiting regulatory approval on its initial 35,000 bbls/d application and is working with the regulators to provide additional information required for approvals. More information about the geology of the reservoir continues to be collected. Cenovus drilled 26 strat wells and 16 additional groundwater monitoring wells during 2010 at Telephone Lake to better assess the characteristics and quality of the resource and support the regulatory application.

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

1 Reflects production from the sale of non-core assets in the fourth quarter of 2009, and the second quarter of 2010.
2 Pelican Lake production is listed in the Oil Growth Projects table.
3 Does not include volumes from the Senlac property, which was sold in the fourth quarter of 2009.

Cenovus has a large base of conventional oil and natural gas properties across Alberta and Saskatchewan. The oil operations include Weyburn, the emerging Bakken and Lower Shaunavon assets as well as other production in southern Alberta. Cenovus’s natural gas properties in Alberta are established, reliable fields with efficient operations. These 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 an economic hedge against price fluctuations, because natural gas fuels the company’s oil sands and refining operations.

• Despite crude oil pipeline apportionment and poor weather causing delays in capital investment in 2010, production from Cenovus’s conventional oil and natural gas properties met company expectations.
• Conventional oil and NGLs production was about 47,000 bbls/d in 2010, a 5% decrease compared with 2009. This was primarily the result of expected natural declines, divestitures of non-core properties, as well as capital project delays caused by weather. The declines were partially offset by increased production from well optimizations at Weyburn and production from new wells in southern Alberta and Saskatchewan. Pipeline apportionment in the second half of the year did not significantly affect production but did result in higher volumes of oil in storage.
• The Lower Shaunavon and Bakken oil assets in Saskatchewan are early stage development opportunities for Cenovus. Production averaged about 2,000 bbls/d in 2010, including royalty volumes. Cenovus had 25 wells producing at year-end 2010 with plans to drill an additional 36 horizontal wells in the area in 2011. The company anticipates production at the end of 2011 could reach 5,700 bbls/d.
• Operating costs for Cenovus’s conventional oil and liquids operations increased 25% to $11.90/bbl in 2010 compared with 2009. This was mainly due to increased workover activity, primarily at Weyburn, increased trucking costs related to pipeline curtailments and new production in Saskatchewan and higher repair and maintenance activity in all of the conventional oil operations as well as the impact of lower volumes.
• Natural gas production was 737 million cubic feet per day (MMcf/d), a 12% decrease in 2010 compared with 2009, with about one-third of that decrease attributed to the sale of natural gas properties. The remaining decline was due to the company shifting capital to crude oil development and away from natural gas in response to low natural gas prices as well as natural production declines and poor weather causing capital project delays.
• Cenovus plans to manage declines in natural gas volumes, targeting a long-term production level of between 400 and 500 MMcf/d to match Cenovus’s future anticipated internal usage at its oil sands and refining facilities.

Refining

Cenovus’s refining operations include the Wood River Refinery in Illinois and the Borger Refinery in Texas, which are jointly owned with the operator, ConocoPhillips. The Borger Refinery has gross coking capacity of 25,000 bbls/d. The coker and refinery expansion (CORE) project at Wood River is adding 65,000 bbls/d of gross coking capacity, bringing the total at Wood River to 83,000 bbls/d. With completion of the CORE project, Cenovus’s Wood River Refinery will have an increased ability to process a variety of crude oil feedstocks and produce a larger percentage of high value clean products. It is anticipated operating cash flow at Wood River will improve by about US$200 million a year net to Cenovus once the project is fully operational. The company’s two refineries will then have a combined capacity to process as much as 275,000 bbls/d of heavy crude oil.

• In 2010, the two refineries produced 405,000 bbls/d of refined products, down about 3% compared with 2009.
• Refinery crude utilization averaged 86% or 386,000 bbls/d of crude throughput, about 2% lower than 2009.
• Operating cash flow from refining operations in 2010 was $67 million, $291 million less than in 2009, mainly due to refinery optimization activities in response to weaker diesel and gasoline margins in the first half of the year, higher crude costs and planned turnarounds at both refineries.
• The CORE project was more than 90% complete at the end of 2010. Commissioning of several of the process units has been completed with an anticipated coker startup in the fourth quarter of 2011, when the company expects that CORE project expenditures will have reached US$3.7 billion (US$1.85 billion net to Cenovus).

2010 Reserves and Contingent Resources

All of Cenovus’s reserves and resources are evaluated by independent qualified reserves evaluators. The 2010 disclosure is presented in accordance with Canadian reporting requirements, using forecast prices and costs before royalties. Year over year comparisons are in reference to previously disclosed 2009 estimates determined using constant prices and costs for the year ended December 31, 2009. The change in price and cost assumptions used to evaluate the company’s 2010 reserves had no material impact on the results. The gain in bitumen reserves is primarily due to 2010 development activities.

• At year end 2010, Cenovus had total proved reserves of 1.7 billion BOE, an increase of 19% compared with 2009.
• Proved bitumen reserves increased 33% in 2010 compared with 2009, to about 1.2 billion bbls. This increase was due to regulatory approval of an expanded development area at Foster Creek, combined with improved recovery due to advancements in technology, such as wedge wells, and improved reservoir performance.
• Best estimate bitumen economic contingent resources increased 13% in 2010, to 6.1 billion bbls. This growth is driven primarily by strat well drilling and improvements in overall recovery.
• Proved heavy oil reserves increased by about 2%, primarily as a result of the success of polymer flooding at Pelican Lake and the plan to expand the floods.
• Proved medium and light oil and natural gas liquids (NGLs) reserves declined by approximately 1% as additions from the expansion of water and carbon dioxide flooding at Weyburn were offset by medium and light oil and NGL production.
• Proved natural gas reserves declined by about 9% in 2010 as positive gas revisions were offset by dispositions, production and the decision to invest less capital in natural gas operations.
• Cenovus’s proved F&D costs in 2010 were $3.65 per BOE, excluding future development costs, which was an improvement of more than 30% compared to 2009, primarily as a result of the large bitumen reserves additions.
• Cenovus achieved a production replacement of nearly 400% in 2010.
• The proved reserves life index is approximately 18 years, a 21% increase compared with 2009.

1 References in the tables to December 31, 2009 (SEC) numbers are to the previously disclosed estimates as of that date prepared in accordance with U.S. disclosure requirements using constant prices and costs as prescribed by the Securities and Exchange Commission (“SEC”).
2 The change in reserves disclosed in the transition from SEC to National Instrument 51-101 (“NI 51-101”) is a result of (i) the McDaniel January 1, 2010 forecast prices and costs used under NI 51-101 being higher than the SEC prescribed constant prices and costs for the year ended December 31, 2009, restoring previously uneconomic gas reserves, and (ii) the removal of Cenovus royalty interest reserves from the before royalties reserves totals. See the Advisory – Oil and Gas Information.
3 Production used for the reserves reconciliation differs from reported production as it includes Cenovus’s share of gas volumes provided to Cenovus’s share of the FCCL partnership for steam generation, but does not include royalty interest production, as prescribed by NI 51-101

1 Finding and Development Cost calculations presented in the table do not include changes in future development costs. See the Advisory – Finding and Development Costs for a full description of the methods used to calculate Finding and Development Costs which include the change in future development costs.
2 Reserves Additions for Finding and Development are calculated by summing revisions, improved recovery, extensions and discoveries. Reserves Additions for Finding, Development and Acquisitions are calculated by summing Reserves Additions for Finding and Development and additions from acquisitions. Oil equivalency has been calculated by Cenovus. See the Advisory – Oil and Gas Information.
3 Finding and Development Costs without changes in future development costs is equal to Finding and Development Capital Investment divided by Finding and Development Reserves Additions.
4 Finding, Development and Acquisitions without changes in future development costs is equal to Finding, Development and Acquisitions Capital Investment divided by Finding, Development and Acquisitions Reserves Additions.

1 For the definition of contingent resources, economic contingent resources and low, best and high estimates and a description of the contingencies associated with Cenovus’s economic contingent resources, please see the Advisory – Oil and Gas Information. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
2 Refers to estimates prepared using the same McDaniel January 1, 2011 forecast prices and costs as used in the 2010 reserves estimates.
3 Refers to previously disclosed estimates prepared using 2009 constant prices and costs.

1 McDaniel January 1, 2011 forecast prices and costs. Ranges are de-escalated to show a range of real price assumptions contained in the forecast. Actual prices used to evaluate reserves and contingent resources are escalated at 2% per year.
2 2009 constant prices and costs as prescribed by the SEC.

Financial

Dividend

The Cenovus Board of Directors declared a first quarter dividend of $0.20 per share, payable on March 31, 2011, to common shareholders of record as of March 15, 2011. Based on the February 17, 2011 closing share price on the Toronto Stock Exchange of $36.59, this represents an annualized yield of about 2.2%. Declaration of dividends is at the sole discretion of the Board.

Hedging Strategy

The natural gas and crude oil hedging strategy helps Cenovus to achieve more predictability around cash flow and safeguard its capital program. The strategy is to hedge up to 75% of this year’s expected natural gas production, net of internal fuel use, and up to 50% and 25%, respectively, in the following two years. The company has approval for fixed price hedges on as much as 50% of net liquids production this year and on 25% of net liquids production for each of the following two years.

In addition to financial hedges, Cenovus benefits from a natural hedge with its gas production. About 110 MMcf/d of natural gas is consumed at the company’s SAGD and refinery operations, which is offset by the gas Cenovus produces. This natural hedge is considered when determining the company’s financial hedging limits.

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

• approximately 75% of expected 2011 natural gas production hedged; 379 MMcf/d at an average NYMEX price of US$5.70/Mcf, plus 110 MMcf/d of internal usage
• 28,600 bbls/d, or approximately 22% of anticipated 2011 oil production hedged at an average WTI price of US$85.54/bbl and an additional 29,200 bbls/d, or another 22% of the year’s expected oil production, hedged at an average WTI price of C$88.32/bbl

• 130 MMcf/d of natural gas hedged for 2012 at an average NYMEX price of US$5.96/Mcf and 80 MMcf/d of natural gas hedged for 2012 at an average AECO price of C$4.49/Mcf, plus internal usage
• 5,000 bbls/d of 2012 oil production hedged at an average WTI price of US$92.44/bbl and an additional 3,000 bbls/d hedged at an average WTI price of C$93.82/bbl
• Cenovus has no fixed price commodity hedges in place for 2013.

Financial Highlights

• Cash flow for 2010 was $2.4 billion, compared with $2.8 billion in 2009. Operating earnings were $794 million, or $1.06 per share, compared with $1.5 billion in 2009. Both cash flow and operating earnings were lower compared to 2009 due to lower realized natural gas prices, decreased natural gas volumes and weaker results from refining operations.
• Cenovus’s realized after-tax hedging gains for 2010 were $199 million. Cenovus received an average realized price, including hedging, of $62.61/bbl for its oil in 2010, compared with about $58.33/bbl during 2009. The average realized price, including hedging, for natural gas was $5.16/Mcf, 34% less than in 2009, a year which included substantial hedging gains.
• Cenovus’s net earnings in 2010 were $993 million compared with $818 million in 2009. Net earnings were positively impacted by an unrealized mark-to-market after-tax gain of $34 million, compared with an after-tax loss of $494 million in 2009, and an unrealized foreign exchange gain of $69 million, compared with a loss of $327 million in 2009.
• Capital investment during the year was $2.1 billion, 2% less than in 2009.
• Free cash flow was $293 million for 2010.
• Cenovus sold certain non-core oil and natural gas assets in southeastern Alberta and southwestern Saskatchewan for net proceeds of more than $220 million in 2010. The company continues to assess its portfolio and may consider selling other non-core assets if market conditions are favourable.
• During the fourth quarter of 2010, Cenovus acquired marine terminal facilities at Kitimat, British Columbia for $38 million. Cenovus has been using the terminal to import diluent for about five years. The purchase was under the terms of an agreement entered into with the previous owner. Cenovus plans to sell the terminal, with the anticipation of contracting terminal services for its diluent with the future owner.
• 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 December 31, 2010, the company’s debt to capitalization ratio was 26% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.2 times.

• Cenovus is on schedule with its plan to switch to International Financial Reporting Standards in the first quarter of 2011 and expects no significant impact to its operations or strategy as a result of the change. Additional information can be found in Cenovus’s most recent Management’s Discussion and Analysis (MD&A) available at www.cenovus.com.

ADVISORY

NON-GAAP MEASURES

This news release contains references to non-GAAP measures as follows:

• Operating cash flow is defined as net revenues, less production and mineral taxes, transportation and blending, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of the company’s assets and improves the comparability of Cenovus’s 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 gain on asset acquisition, 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. Debt is defined as the current and long term portions of long term debt. Capitalization is a measure defined as debt plus shareholders’ equity. Adjusted EBITDA is defined as net earnings before net interest, income taxes, depreciation, depletion and amortization, accretion of asset retirement obligation, foreign exchange gains or losses, gains or losses on disposal of assets and other income and loss.

These measures have been described and presented in this news release 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 MD&A available at www.cenovus.com.

FINDING AND DEVELOPMENT COSTS

Finding and development costs disclosed in this news release do not include the change in estimated future development costs. Cenovus uses finding and development costs without changes in estimated future development costs as an indicator of relative performance to be consistent with the methodology accepted within the oil and gas industry.

Finding and development costs for proved reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $10.55/BOE for the year ended December 31, 2009, $16.01/BOE for the year ended December 31, 2010 and averaged $16.95/BOE for the three years ended December 31, 2010. Finding and development costs for proved plus probable reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $9.78/BOE for the year ended December 31, 2009, $81.70/BOE for the year ended December 31, 2010 and averaged $24.43/BOE for the three years ended December 31, 2010. These finding and development costs were calculated by dividing the sum of exploration costs, development costs and changes in future development costs in the particular year by the reserves additions (the sum of extensions and improved recovery and technical revisions) in that year. The aggregate of the exploration and development costs incurred in a particular year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

OIL AND GAS INFORMATION

The estimates of economic contingent resources were prepared by McDaniel & Associates Consultants Ltd. in accordance with the Canadian Oil and Gas Evaluation Handbook. The definitions of the resources categories and estimate levels disclosed are as follows:

• Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. The estimate of contingent resources has not been adjusted for risk based on the chance of development. For Cenovus, contingencies which must be overcome to enable the reclassification 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 a development plan with major capital expenditures planned within five years.
• Economic Contingent Resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. In Cenovus’s case, contingent resources were evaluated using the same commodity price assumptions that were used for the 2010 reserves evaluation, which comply with NI 51-101 requirements.
• Best Estimate 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 percent confidence level that the actual quantities recovered will equal or exceed the estimate.
• Low Estimate is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources at the low end of the estimate range have the highest degree of certainty - a 90 percent confidence level – that the actual quantities recovered will equal or exceed the estimate.
• High Estimate is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will meet or exceed the high estimate. Those resources at the high end of the estimate range have a lower degree of certainty - a 10 percent confidence level - that the actual quantities recovered will equal or exceed the estimate.

The economic contingent resources were estimated on a project level. The high and low estimates are arithmetic sums of multiple estimates which statistical principles indicate may be misleading as to volumes that may actually be recovered. The aggregated low estimate results shown may have a higher level of confidence than the individual projects, and the aggregated high estimate results shown may have a lower level of confidence than the individual projects.

We hold significant freehold title rights which generate production for our account from third parties leasing those lands. The before royalty volumes presented in this news release do not include reserves associated with this production.

In this document, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one bbl. 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 represent value equivalency at the wellhead.

FORWARD-LOOKING INFORMATION

This news release contains certain forward-looking statements and other information (collectively “forward-looking information”) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this AIF is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, anticipated finding and development costs, expected reserves and contingent and prospective resources estimates, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, forecasted commodity prices, future use and development of technology and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally.

The factors or assumptions on which the forward-looking information is based include: assumptions inherent in our current guidance, available at www.cenovus.com; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness 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 prices, 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; maintaining a desirable debt to cash flow ratio; our ability to access external sources of debt and equity capital; success of hedging strategies; accuracy of our reserves, resources and future production estimates; 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 our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; 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 of crude oil into petroleum and chemical products at two refineries; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in Alberta’s regulatory framework, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and 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 our business, 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 and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk factors, see “Risk Factors” in our most recent annual information form, available at www.cenovus.com. Readers should also refer to “Risk Management” in our current management’s discussion and analysis and to the risk factors described in other documents we file from time to time with securities regulatory authorities, available at www.sedar.com, www.sec.gov and www.cenovus.com.

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 $31 billion. For more information, visit www.cenovus.com.