Exhibit 99.1

Cenovus first-quarter oil sands production up 20%

Oil sands per-unit operating costs decline 31%

·Combined oil sands production averaged more than 144,000 barrels per day (bbls/d) net in the first quarter, up 20% from the same period in 2014.

·Total oil production was more than 218,000 bbls/d, 11% higher than in 2014.

·Upstream per-unit operating costs declined 23%, including a 31% decrease in oil sands per-unit operating costs, compared with the first quarter of 2014.

·Cash flow was $495 million, a 45% decline from the first quarter in 2014. Higher oil sands production and lower operating costs were more than offset by a significant decline in crude oil and natural gas prices and lower realized refining margins.

·To conserve cash, the 2015 capital spending budget was cut by approximately $700 million in January, and workforce and discretionary spending reductions were made.

·The company completed a bought-deal financing, issuing 67.5 million common shares for net proceeds of approximately $1.4 billion.

“We had very strong operational performance in the first quarter, with solid production increases and significantly lower operating costs across our assets,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “We also took decisive steps during the quarter to help preserve our financial resilience in this challenging oil price environment without compromising our future.”

Production & financial summary

(For the period ended March 31) Production (before royalties)	2015 Q1	2014 Q1	% change
Oil sands (bbls/d)	144,372	120,444	20
Conventional oil1 (bbls/d)	73,648	76,410	-4
Total oil (bbls/d)	218,020	196,854	11
Natural gas (MMcf/d)	462	476	-3

Financial ($ millions, except per share amounts)
Cash flow2	495		904	-45
Per share diluted	0.64		1.19
Operating earnings2 (loss)	(88	)	378	-123
Per share diluted	(0.11	)	0.50
Net earnings (loss)	(668	)	247	-370
Per share diluted	(0.86	)	0.33
Capital investment	529		829	-36

1 Includes natural gas liquids (NGLs).

2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory. See also the earnings reconciliation summary in the operating earnings table.

Calgary, Alberta (April 29, 2015) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) achieved solid production growth in the first quarter compared with the same period in 2014, driven by 20% higher production at the company’s oil sands operations. Oil sands per-unit operating costs were 31% lower than in the first quarter of 2014, primarily due to higher production and a decrease in fuel costs. Cash flow in the quarter declined 45% as a result of lower crude oil and natural gas sales prices and lower average market crack spreads.

Production from Cenovus’s jointly owned Christina Lake and Foster Creek oil sands operations averaged more than 144,000 bbls/d net in the first quarter. During the quarter, Christina Lake production increased 16% compared with the same period a year earlier, averaging more than 76,000 bbls/d net. The increase was primarily due to phase E reaching design capacity in the second quarter of 2014, the start-up of new wells, including those using the company’s Wedge WellTM technology, and improved facilities performance, all of which contributed to a lower steam to oil ratio (SOR). The current full-year outlook at Christina Lake is for production to be above the mid-point of the company’s annual guidance of between 67,000 bbls/d and 74,000 bbls/d net.

Foster Creek production volumes averaged almost 68,000 bbls/d net in the first quarter, up 24% from the same period in 2014. After six months of ramp-up, phase F wells were contributing approximately 5,400 bbls/d net in incremental production in the first quarter. The phase F ramp-up is proceeding on schedule and is expected to be complete in the first quarter of 2016, approximately 18 months after first production. The start-up of new wells, including those using Cenovus’s Wedge WellTM technology, also contributed to the production gain. In addition, last year’s well workovers led to some flush production, which is starting to taper off, as expected. The company anticipates full-year production at Foster Creek to be above the mid-point of its guidance of between 62,000 bbls/d and 68,000  bbls/d net.

In the first quarter, oil sands operating expenses declined $4.99 per barrel (bbl), or 31%, compared with the same period in 2014. This was due, in part, to lower natural gas prices, which reduced fuel costs at Foster Creek and Christina Lake. Non-fuel per-unit operating costs declined primarily as a result of stronger production and high plant operating efficiencies. The company’s efforts to improve productivity and further prioritize work also contributed to the decrease. For example, savings were achieved by reducing workover costs and lowering fluid, waste handling and trucking costs related to the optimization of the chemical application process. Lower repair and maintenance costs resulting from improved scheduling of less time-sensitive work also contributed to the savings. In addition, Cenovus is starting to see results from its efforts to reduce supplier costs. In general, the company is seeing cost reductions from its suppliers of between 5% and 10%.

“I’m pleased with the performance of both of our oil sands projects in the quarter,” said John Brannan, Executive Vice-President & Chief Operating Officer. “We’ve made progress in significantly reducing our operating costs, and further cost-cutting measures are underway. We expect many of these savings to be sustainable and to make our oil sands assets even more efficient and productive.”

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Commodity price impact

Production increases and lower operating costs and royalties during the first quarter were more than offset by a sharp decline in benchmark prices resulting from a global supply-demand imbalance that accelerated through 2014 and into the first quarter of 2015. Average Brent, West Texas Intermediate (WTI) and Western Canadian Select (WCS) prices decreased 49%, 51% and 55%, respectively, from the same period a year earlier. In addition, the timing of condensate inventory drawdown affected Cenovus’s realized pricing for its heavy oil. Condensate purchased at higher prices at the end of 2014 was blended into product sold in the first quarter of 2015. These factors negatively impacted operating cash flow at Cenovus’s upstream operations.

Operating cash flow from the refining and marketing segment declined to $95 million in the first quarter, down 61% from the same period in 2014. Cenovus’s refining margins were impacted by lower average market crack spreads due to narrower Brent-WTI differentials and higher heavy oil feedstock costs relative to WTI. This was partially offset by improved margins on the sale of secondary products such as coke and asphalt, an increase in refined product output and the weakening of the Canadian dollar.

These factors contributed to a decline in Cenovus’s operating cash flow to $549 million, 53% below the same period a year earlier. Cash flow was down 45% in the quarter to $495  million. After investing $529 million in the first quarter, Cenovus had a free cash flow shortfall of $34 million, compared with free cash flow of $75 million in the same period of 2014.

Since the first quarter of 2015, benchmark prices have improved somewhat. At current strip pricing and market crack spreads, Cenovus expects its 2015 cash flow would essentially cover its capital expenditures and its current level of dividends for the year.

Cost management and financial resilience

Over the next 18 months, Cenovus expects to add approximately 100,000 bbls/d of gross incremental oil sands production capacity from its phase F expansion and optimization work at Christina Lake as well as the phase G expansion at Foster Creek. That would bring total expected oil sands production capacity to 390,000 bbls/d gross in 2016. To help ensure that it has the financial resilience to carry out these expansions and continue to focus on strong operational performance in this low oil price environment, Cenovus has adjusted its business plan for the next three years. This includes taking steps to cut costs and strengthen the company’s balance sheet.

During the first quarter, the company conserved cash by:

·Cutting its 2015 capital spending budget by $700 million in January. At $1.8 billion to $2.0 billion, the 2015 capital budget is about 40% below 2014 levels

·Largely completing a 15% workforce reduction which primarily affected its contract workforce

·Deferring executive and employee salary increases for 2015

·Reducing discretionary spending on items including travel, conferences, offsite meetings and information technology upgrades. Cenovus expects most of the savings from its discretionary spending reductions to be evident in the second quarter.

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For 2015, Cenovus expects to be near the low end of its guidance range for operating expenses. Compared with the previous year, general and administrative (G&A) expenses were 34% lower in the first quarter of 2015. The decrease was primarily due to lower  employee long-term incentive costs. The company anticipates its G&A expenses will also be near the low end of guidance for the year.

As a result of initiatives already underway, Cenovus expects to realize approximately $200  million in G&A and upstream operating and capital cost savings in 2015. The company continues to look for additional cost savings for the year and is pursuing opportunities it has identified to potentially achieve hundreds of millions of dollars in additional sustainable annual cost reductions in the years ahead.

After careful consideration and lengthy discussion with its board of directors, Cenovus’s management decided to issue 67.5 million common shares during the first quarter. The net proceeds of approximately $1.4 billion are expected to be used to fund any potential shortfall in the company’s capital expenditure program for 2015 and for general corporate purposes. Part of the proceeds was used to repay commercial paper outstanding as it matured.

“We examined a number of alternatives, including issuing debt, lowering the dividend, further reducing capital and issuing preferred shares,” said Ferguson. “In the end, we believed that issuing common shares was the best option to strengthen our balance sheet, provide greater certainty of funding for our planned capital program and reinforce our strong investment-grade credit rating over our three-year planning horizon. This should also position us well to be able to take advantage of opportunities that only come about in market conditions like these.”

To further conserve cash, the company exercised its ability under Cenovus’s Dividend Reinvestment Plan (DRIP) to offer shareholders the opportunity to reinvest their dividends in Cenovus common shares issued from the company’s treasury at a 3% discount to current market prices. For the first quarter, more than one-third of Cenovus shareholders participated in the discounted DRIP, resulting in cash savings for the company of approximately $81 million. The 3% discount on the DRIP will remain in effect for the second quarter and will be reassessed by the company on a quarterly basis thereafter.

Royalty production and fee lands

The company has been evaluating opportunities to crystalize value for shareholders from its existing portfolio of assets. Cenovus is pursuing various potential options with respect to its royalty production and fee lands, including a possible sale or initial public offering, so that the company is market-ready when an appropriate opportunity presents itself.

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Oil Projects

Daily production1

(Before royalties)	2015	2014					2013
(Mbbls/d)	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Oil sands
Christina Lake	76	69	74	68	68	66	49
Foster Creek	68	59	68	57	57	55	53
Oil sands total	144	128	142	125	125	120	103
Conventional oil2	74	75	74	74	77	76	77
Total oil2	218	203	216	199	202	197	179

1 Totals may not add due to rounding.

2 Includes NGLs production.

Oil sands

Cenovus has a substantial portfolio of oil sands assets in northern Alberta with the potential to provide decades of production growth. The two operations currently producing, Christina Lake and Foster Creek, use steam-assisted gravity drainage (SAGD), which involves drilling into the reservoir and injecting steam at low pressures to soften the thick oil, so it can be pumped to the surface. Cenovus has a third major oil sands project under initial development at Narrows Lake, which is part of the Christina Lake region. These projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus has a significant opportunity to deliver increased shareholder value over the long term through production growth from several identified emerging projects and additional future developments.

Christina Lake

Production

·Production at Christina Lake averaged 76,471 bbls/d net in the first quarter of 2015, 16% higher than in the same period a year earlier. The increase was primarily due to phase E reaching design capacity in the second quarter of 2014, the start-up of new wells, including those using Cenovus’s Wedge WellTM technology, and improved facilities performance. Wedge WellTM technology allows the company to increase production with the use of very little additional steam.

·The SOR was 1.7, compared with 1.9 in the first quarter of 2014.

·Operating costs at Christina Lake declined 38% to $8.22/bbl in the first quarter from $13.30/bbl in the same period of 2014. The decrease was primarily due to higher production, lower fuel costs and a decline in fluid, waste handling and trucking costs related to the optimization of the chemical application process. The decrease in costs also reflects a reduction in workover activities related to well servicing, primarily due to fewer pump changes.

·Non-fuel operating costs were $6.03/bbl, a decline of 29% from $8.47/bbl in the first quarter of 2014. Fuel costs were down 55% to $2.19/bbl.

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·The netback the company received for its Christina Lake crude oil production was $10.30/bbl in the first quarter, compared with $39.53/bbl in the same quarter in 2014.

Expansions

·Cenovus continues to progress its plant optimization project at Christina Lake. The optimization is expected to increase total production capacity to 160,000 bbls/d gross, starting in the fourth quarter of 2015.

·The company is continuing construction at Christina Lake phase F. Plant construction is mostly complete. First oil from this phase is expected in the second half of 2016. Due to the substantial decline in crude oil prices, construction work on phase G has been deferred to conserve cash.

·First-quarter capital investment at Christina Lake was $207 million, compared with $182 million in the first quarter of 2014.

Foster Creek

Production

·Foster Creek production averaged 67,901 bbls/d net in the first quarter, 24% higher than in the first quarter of 2014. The increase was primarily due to additional volumes from phase F, which began producing in the third quarter of 2014, and the start-up of new wells.

·Phase F wells are ramping up as expected and ended the first quarter with production of approximately 5,400 bbls/d net (10,800 bbls/d gross). The phase F plant has a gross design capacity of 30,000 bbls/d.

·The SOR at Foster Creek was 2.4 in the first quarter, down from 2.7 in the same period a year ago. The decrease was primarily due to boiler maintenance which temporarily reduced steam use during the quarter. The SOR was also lower due to production from new wells, including wells using Cenovus’s Wedge WellTM technology.  Foster Creek’s SOR is expected to range between 2.6 and 3.0 while expansion phases F and G are ramping up. After ramp-up, the SOR is expected to drop below 2.5.

·Operating costs at Foster Creek declined 24% to $14.48/bbl compared with $19.09/bbl a year earlier, mainly because of higher production and lower fuel costs. The decrease also reflects a reduction in workover activities related to well servicing, primarily due to fewer pump changes. Non-fuel operating costs declined 16% to $11.52/bbl in the first quarter, compared with $13.64/bbl in the same quarter a year ago. Fuel costs declined 46% to $2.96/bbl.

·The netback the company received for its Foster Creek oil declined to $5.80/bbl in the first quarter compared with $45.86/bbl in the same period a year earlier.

Expansions

·Construction is continuing on phase G, which is anticipated to begin producing in the first half of 2016. Plant construction at phase G is approximately two-thirds complete.

·As previously announced, due to the significant decrease in crude oil prices, construction work on phase H has been deferred to conserve cash.

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·First-quarter capital investment at Foster Creek was $149 million compared with $221 million in the first quarter of 2014.

Narrows Lake

·Cenovus believes Narrows Lake has the potential to achieve total production capacity of 130,000 bbls/d. Narrows Lake is expected to be the industry’s first project to use a solvent aided process (SAP) on a commercial scale, combining butane with steam to improve oil recovery.

·As previously announced, in response to the substantial decline in crude oil prices, Cenovus has decided to defer further work at Narrows Lake to conserve cash. The company plans to take advantage of the slower pace of development to optimize its engineering and execution strategy with a focus on achieving the lowest capital efficiencies for the Narrows Lake project.

Emerging projects

Grand Rapids

·Cenovus continues to operate a SAGD pilot project at Grand Rapids with two producing well pairs. A third pilot well pair was completed in early March 2015, and steam circulation is expected to begin in the second quarter. It is anticipated that data from these well pairs will be used to help determine the company’s development plan for Grand Rapids.

·The company has completed the dismantling and storage of an existing SAGD facility that Cenovus purchased in 2014 and plans to relocate to the Grand Rapids site once the development plan has been finalized, subject to a recovery in crude oil prices. The project has received regulatory approval for total production capacity of 180,000  bbls/d.

Telephone Lake

·Cenovus continues to review development options for Telephone Lake after receiving approval from the Alberta Energy Regulator for the project in late 2014.

Conventional oil

Cenovus has tight oil opportunities in Alberta as well as the established Weyburn operation in Saskatchewan that uses carbon dioxide injection to enhance oil recovery. Cenovus also produces conventional heavy oil from the Wabiskaw formation at its 100%-owned Pelican Lake operation in northern Alberta. Cenovus has been injecting polymer since 2006 to enhance production from the reservoir, which is also under waterflood.

·Total conventional oil production fell 4% to 73,648 bbls/d in the first quarter compared with 76,410 bbls/d in the same period a year ago due to the divestiture of non-core assets in 2014. Production from the divested assets averaged 3,174 bbls/d in the first quarter of 2014.

·Operating costs for Cenovus’s conventional oil operations were $16.29/bbl in the first quarter, a 23% decline from $21.06/bbl in the first quarter of 2014. The decline was primarily due to reduced expenses for workover activities, repairs and maintenance, electricity and fuel costs.

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·As previously announced, Cenovus has temporarily suspended the majority of its conventional drilling program in southern Alberta and Saskatchewan for 2015. This suspension, along with asset dispositions completed in 2014, is expected to reduce production to between 66,000 bbls/d and 70,000 bbls/d for 2015 compared with approximately 75,000 bbls/d in 2014.

·Cenovus invested $62 million in its conventional oil assets in the first quarter, compared with $263 million a year earlier. These assets generated $104 million of operating cash flow in excess of capital investment in the first quarter.

Natural Gas

Daily production

(Before	2015	2014					2013
royalties) (MMcf/d)	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Natural gas	462	488	479	489	507	476	529

Cenovus has a solid base of established, reliable natural gas properties in Alberta. These properties are managed as financial assets, not production assets, 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.

·Natural gas production averaged 462 million cubic feet per day (MMcf/d) in the first quarter, down 3% from 476 MMcf/d in the same period in 2014. Cenovus anticipates continued declines in its natural gas production in future quarters, as the company continues to direct the majority of its capital investment to its crude oil properties.

·The company invested $5 million in its natural gas assets in the first quarter compared with $9 million in the same quarter a year earlier. The natural gas assets generated $76 million in operating cash flow in excess of capital investment in the quarter.

·Cenovus’s average realized sales price for natural gas, including hedging, was $3.34  per thousand cubic feet (Mcf) compared with $4.47/Mcf a year earlier.

·Natural gas use at Cenovus’s operations is forecast to be about 180 MMcf/d in 2015.

Markets, Products and Transportation

To capture the highest value for its oil, Cenovus takes an integrated approach to production, transportation and refining. The company is focused on finding new customers in North America and around the world where it expects to receive the best prices, and on ensuring it has the ability to move oil to those customers. Cenovus is also working to create a variety of oil blends that it expects will help maximize its transportation and refining options.

Cenovus has ownership in the Wood River Refinery in Illinois and the Borger Refinery in Texas. These Midwest refineries, which are jointly-owned with the operator, Phillips 66, produce high-quality end products like diesel, gasoline and jet fuel. On an integrated basis, Cenovus’s refining business provides an economic hedge against heavy crude oil discounts to WTI.

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The company continues to support proposed pipelines to Canada’s east and west coasts as well as to the U.S. to help secure additional shipping capacity for its expected production growth. To complement this approach and access markets not served by pipeline, the company has also been pursuing a strategy to expand its capacity to transport oil by rail.

Refining and marketing

Operations

·Cenovus’s refineries processed an average of 439,000 bbls/d gross of crude oil in the first quarter, a 10% increase from 400,000 bbls/d gross in the same period a year ago, due to lower turnaround and maintenance activity. Together, the two refineries processed an average of 220,000 bbls/d gross of heavy oil in the quarter, compared with 195,000 bbls/d gross in the first quarter of 2014.

·The refineries produced an average of 469,000 bbls/d gross of refined products in the quarter, an increase of 12% from the previous year.

Financial

·Operating cash flow from refining and marketing was $95 million for the first quarter, a 61% decline from $245 million in the same quarter in 2014, as the benefit of improved refinery operations was more than offset by significant changes in benchmark prices in the first quarter of 2015.

·Reported results in the quarter were negatively impacted by lower average market crack spreads and narrower WTI-WCS differentials. These pricing factors were partly offset by improved margins on the sale of secondary products, an increase in refined product output as well as the effect of a weakening of the Canadian dollar relative to the U.S. dollar, compared with the first quarter of 2014.

·Cenovus’s refining operating cash flow is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovus’s operating cash flow from refining would have been approximately $55 million higher in the first quarter, compared with $83  million lower in the first quarter of 2014.

·Capital investment was $44 million in the first quarter compared with $23 million a year earlier. The increase was primarily due to the debottlenecking project at Wood River, which received permit approval in the first quarter of 2015. Planned start-up is anticipated in 2016.

Market access

·Cenovus has 50,000 bbls/d of contracted capacity on Enbridge’s Flanagan South system, increasing to 75,000 bbls/d in 2018. Initial deliveries on Flanagan South, which provides additional pipeline access to the U.S. Gulf Coast, began in December 2014.

·Cenovus has firm service capacity of 11,500 bbls/d on the existing Trans Mountain pipeline, giving the company access to the West Coast.

·The company has also committed to moving 200,000 bbls/d on TransCanada’s proposed Energy East pipeline, has additional shipping capacity of 175,000 bbls/d on

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planned pipelines to the West Coast and has 75,000 bbls/d of committed capacity on TransCanada’s proposed Keystone XL system.

·Cenovus has 30,000 bbls/d gross of crude oil rail loading capacity. On average, the company transported more than 13,000 bbls/d gross of crude oil by rail in the first quarter to markets in Canada and the U.S., including 18 unit train shipments.

·As of March 31, Cenovus had also taken delivery of more than half of the 825 coiled and insulated rail cars it had ordered to further support its rail strategy.

Financial

Dividend

The Cenovus Board of Directors declared a second-quarter dividend of $0.2662 per share, payable on June 30, 2015 to common shareholders of record as of June 15, 2015. Based on the April 28, 2015 closing share price on the Toronto Stock Exchange of $23.13, this represents an annualized yield of about 4.6%. The company has exercised its ability under Cenovus’s DRIP to offer shareholders the opportunity to reinvest their dividends in Cenovus common shares issued from the company’s treasury at a 3% discount to current market prices. The 3% discount will remain in effect for the second quarter and will be reassessed by the company thereafter. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis. Cenovus’s continued commitment to a meaningful dividend is an important aspect of its strategy to focus on increasing total shareholder return.

Cash flow, earnings, capital investment, G&A and debt ratios

·Operating cash flow was $549 million in the first quarter, a decline of 53% compared with the first quarter of 2014. This decrease was primarily due to lower average crude oil and natural gas sales prices, and lower average market crack spreads. The decrease was partially offset by realized risk management gains, increased crude oil sales volumes, lower royalties and a decrease in crude oil operating expenses.

·Cenovus generated $495 million in cash flow for the first quarter, 45% less than in the same quarter a year ago, largely due to the decline in operating cash flow, partially offset by a decrease in current income tax.

·For the quarter, operating cash flow in excess of capital invested was $104 million from conventional oil, $76 million from natural gas and $51 million from refining and marketing. The company had an operating cash flow shortfall, net of capital expenditures, of $213 million from crude oil production at its oil sands projects.

·Cenovus had an operating loss of $88 million in the first quarter, compared with operating earnings of $378 million in the first quarter of 2014. The loss was primarily due to the decline in cash flow, unrealized foreign exchange losses of $9 million compared with gains of $53 million in 2014, and an increase in depreciation, depletion and amortization due to increased oil sands sales volumes. This was partially offset by a recovery of employee long-term incentive costs and lower deferred income tax.

·Cenovus’s net loss for the quarter was $668 million compared with net earnings of $247 million in the first quarter of 2014. The net loss was partly due to non-operating unrealized foreign exchange losses of $514 million compared with losses of $196 million in the same period of 2014 and unrealized risk management losses compared with gains in 2014. The net loss was partially offset by a recovery of income taxes of $113 million.

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·Capital investment was $529 million, a 36% decline from $829 million in the first quarter of 2014, as the company reduced capital spending to conserve cash. Almost 80% of the investment was at the company’s oil sands operations as it progressed expansion phases at Christina Lake and Foster Creek.

·G&A expenses declined 34% to $72 million in the first quarter from a year ago. The decrease was primarily due to a recovery of employee long-term incentive costs resulting from a decline in the company’s share price.

·Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) ratio of between 1.0 and 2.0 times. At March  31, 2015, the company’s debt to capitalization ratio was 35% and debt to adjusted EBITDA was 1.9 times, on a trailing 12-month basis. The net debt to capitalization ratio was 27%, and net debt to adjusted EBITDA was 1.3 times, on a trailing 12-month basis.

Commodity price hedging

·In the first quarter, Cenovus added Brent fixed price contracts for the period March through June 2015 of 45,000 bbls/d at an average price of US$56.45/bbl, 18,000  bbls/d for the third quarter of 2015 at an average price of US$60.03/bbl and 1,000 bbls/d for the fourth quarter of 2015 at an average price of US$64.00/bbl. The company also added Brent fixed price contracts for 2016 of 4,000 bbls/d at an average price of US$65.75/bbl.

·Cenovus had a realized after-tax hedging gain of $111 million in the quarter, as the company’s contract prices exceeded the average benchmark price. Unrealized losses were $108 million after tax in the first quarter, primarily due to the realization of settled positions.

·Cenovus received an average realized price, including hedging, of $37.66/bbl for its oil in the first quarter. This compares to an average realized price, including hedging, of $71.12/bbl in the first quarter of 2014. The average realized price for natural gas, including hedging, was $3.34/Mcf, compared with $4.47/Mcf a year ago.

Operating earnings1

(For the period ended March 31) ($ millions, except per share amounts)	2015 Q1		2014 Q1
Earnings (loss) before income tax	(781	)	358
Add back (deduct):
Unrealized risk management (gains) losses2	145		(26	)
Non-operating unrealized foreign exchange (gains) losses3	514		196
(Gains) losses on divestiture of assets	(16	)	—
Operating earnings (loss), before income tax	(138	)	528
Income tax expense (recovery)	(50	)	150
Operating earnings (loss)	(88	)	378

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

2 The unrealized risk management (gains) losses include the reversal of unrealized (gains) losses recognized in  prior periods.

3 Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“we”, “our”, “us”, “its”, “Cenovus”, or the “Company”) dated April 28, 2015, should be read in conjunction with our March 31, 2015 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2014 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2014 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of April 28, 2015, unless otherwise indicated. This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The interim MD&As are approved by the Audit Committee of the Cenovus Board of Directors (the “Board”) and the annual MD&A is reviewed by the Audit Committee and recommended for its approval by the Board. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

This MD&A and 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 International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis.

Non-GAAP Measures

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Operating Cash Flow, Cash Flow, Operating Earnings, Free Cash Flow, Debt, Capitalization and Adjusted Earnings before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) 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 order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation of each non-GAAP measure is presented in the Financial Results or Liquidity and Capital Resources sections of this MD&A.

OVERVIEW OF CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On March 31, 2015, we had a market capitalization of approximately $18 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “crude oil”) production for the three months ended March 31, 2015 was approximately 218,000 barrels per day and our average natural gas production was 462 MMcf per day. Our refineries processed an average of 439,000 gross barrels per day of crude oil feedstock into an average of 469,000 gross barrels per day of refined products.

The latter part of 2014 and the first quarter of 2015 have been very challenging for the oil and gas industry. The approximate 55 percent decline in crude oil prices since June 2014 has resulted in widespread reductions in capital spending programs and extensive efforts to reduce costs across the industry. Like all of our peers, Cenovus’s share price has fallen, causing our market capitalization to drop approximately $8 billion since June 30, 2014. We are confident that commodity prices will eventually improve; however, the timing of that improvement is uncertain and we expect crude oil price and cash flow volatility in the near term. In the meantime, we are focused on preserving our financial resilience, exercising capital restraint and identifying sustainable cost reductions.

Our Strategy

Our strategy is to create value by developing our vast oil sands resources and by achieving stronger global prices for our products. It is based on our execution excellence, our ability to innovate and our financial strength. The manufacturing approach we use to produce oil is a key factor in how we execute our strategy. Applying standardized and repeatable designs and processes to the construction and operation of our facilities provides us with opportunities to reduce costs, and improve productivity and efficiencies at every phase of our oil sands projects. We are focused on driving total shareholder returns through share price appreciation and a strong and sustainable dividend.

Our integrated approach enables us to capture the full value chain from production to high-quality end products like transportation fuels. It relies on:

·Our producing asset mix, including:

·Oil sands for growth;

·Conventional crude oil for near-term cash flow and diversification of our revenue stream; and

·Natural gas for the fuel we use at our oil sands and refining facilities, and for the cash flow it provides to help fund our capital spending programs.

·Our marketing, products and transportation activities, including:

·Refining oil into various products to reduce the impact of commodity price fluctuations;

·Creating a variety of oil blends to help maximize our transportation and refining options; and

·Accessing new markets that will enable us to achieve the best pricing for our oil.

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Oil Development

We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek and Christina Lake. Our future opportunities are currently based on the development of the land positions that we hold in the oil sands in northern Alberta, including Narrows Lake, Telephone Lake and Grand Rapids, as well as our conventional oil opportunities. Our normal development planning is to evaluate these resources through stratigraphic test well drilling programs.

We anticipate increasing our annual net crude oil production, including our conventional crude oil operations, to more than 500,000 barrels per day by fully developing our producing projects and those that currently have regulatory approval.

Execution Excellence

We apply a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates learnings from previous phases into future growth plans, allowing us to minimize costs. We continue to focus on executing our business plan in a safe, predictable and reliable way, leveraging the strong foundation we have built to date. We are committed to developing our resources safely and responsibly.

Financial Strength

We anticipate our total annual capital investment to be between $1.8 billion and $2.0 billion for 2015. This is a significant reduction from 2014 levels in response to the continued low commodity price environment. A portion of our capital investment is expected to be internally funded through cash flow generated from our crude oil, natural gas and refining operations and the proceeds from our common share issuance in March 2015. We remain well positioned to manage through these volatile times. To continue to help ensure our financial flexibility, we will prudently use our balance sheet capacity, manage our asset portfolio and consider other corporate and financial opportunities that may be available to us.

Dividend

The declaration of dividends is at the sole discretion of our Board and is considered each quarter. In the first quarter, we paid a dividend of $0.2662 per share or $222 million, of which $138 million was paid in cash (2014 —$0.2662 per share or $202 million paid in cash). In February 2015, we initiated a three percent discount under our dividend reinvestment plan (“DRIP”) for shareholders who reinvested their dividends in common shares.

Innovation and the Environment

Technology development, research activities and understanding our impact on the environment continue to play increasingly larger roles in all aspects of our business. We continue to seek out new technologies and are actively developing our own technology with the goals of increasing recoveries from our reservoirs, while reducing the amount of water, natural gas and electricity consumed in our operations, potentially reducing costs and minimizing our environmental disturbance. The Cenovus culture fosters the pursuit of new ideas and new approaches. We have a track record of developing innovative solutions that unlock challenging crude oil resources, building on our history of excellent project execution. Environmental considerations are embedded into our business approach with the objective of reducing our environmental impact.

Our Operations

Oil Sands

Our operations include the following steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta:

	Three Months Ended March 31, 2015
	Ownership Interest (percent)	Net Production Volumes (bbls/d)	Gross Production Volumes (bbls/d)
Existing Projects
Foster Creek	50	67,901	135,802
Christina Lake	50	76,471	152,942
Narrows Lake	50	—	—
Emerging Projects
Telephone Lake	100	—	—
Grand Rapids	100	—	—

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated U.S. public company. Foster Creek and Christina Lake are producing and Narrows Lake is in the initial stages of development. These projects are located in the Athabasca region of northeastern Alberta. Two of our 100 percent owned emerging projects are Telephone Lake and Grand Rapids, located within the Borealis and Greater Pelican Lake regions, respectively.

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	Three Months Ended March 31, 2015
($ millions)	Crude Oil (1)		Natural Gas
Operating Cash Flow	200		3
Capital Investment	413		1
Operating Cash Flow Net of Related Capital Investment	(213	)	2

(1)Includes NGLs.

Conventional

Crude oil production from our Conventional business segment continues to generate predictable near-term cash flows. This production provides diversification to our revenue stream and enables further development of our oil sands assets. Our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations and provides cash flow to help fund our growth opportunities.

	Three Months Ended March 31, 2015
($ millions)	Crude Oil (1)	Natural Gas
Operating Cash Flow	166	78
Capital Investment	62	4
Operating Cash Flow Net of Related Capital Investment	104	74

(1)Includes NGLs.

We have established crude oil and natural gas producing assets, including a carbon dioxide enhanced oil recovery project in Weyburn, Saskatchewan, as well as heavy oil assets at Pelican Lake and developing tight oil assets, located in Alberta.

Approximately 70 percent, or 4.5 million net acres, of our conventional land is owned in fee title, which means we own the mineral rights. About 50 percent of our total conventional production comes from our fee lands. We do not pay third-party royalties where we have working interest production from fee lands. Rather, we pay mineral tax to the government that is generally lower than royalties paid to mineral interest owners. In addition, a portion of our fee lands are leased to third parties, which resulted in approximately $25 million of Operating Cash Flow in the quarter (2014 — approximately $40 million). We continue to evaluate alternatives to maximize the value of our fee lands and if an appropriate opportunity arises and market conditions warrant, we may initiate a transaction.

Refining and Marketing

Our operations include two refineries located in Illinois and Texas that are jointly owned with and operated by Phillips 66, an unrelated U.S. public company.

	Three Months Ended March 31, 2015
	Ownership Interest (percent)	Gross Nameplate Capacity (Mbbls/d)
Wood River	50	314
Borger	50	146

Our refining operations allow us to capture the value from crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility associated with regional North American crude oil differential fluctuations. This segment also includes our marketing of third-party purchases and sales of product undertaken to provide operational flexibility for transportation commitments, product quality, delivery points and customer diversification.

($ millions)	Three Months Ended March 31, 2015
Operating Cash Flow	95
Capital Investment	44
Operating Cash Flow Net of Related Capital Investment	51

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QUARTERLY OPERATING AND FINANCIAL HIGHLIGHTS

The challenges of the current commodity price environment continued to significantly impact our industry in the first quarter of 2015. Average crude oil benchmark prices fell between 28 and 42 percent compared with the fourth quarter of 2014 and between 49 and 55 percent compared with the first quarter of 2014. Forward commodity prices are expected to be low for the remainder of 2015. The forward price of Western Canadian Select (“WCS”) is expected to average approximately US$40 per barrel for the remainder of 2015. Maintaining financial resilience, capital spending restraint and conservation of cash are extremely important in this low commodity price environment.

Cenovus remains well positioned to manage through these volatile times. To help preserve our financial flexibility, we completed the following in the first quarter:

·Significantly reduced our 2015 capital budget in January in an effort to exercise further capital spending restraint. We anticipate 2015 capital investment will continue to focus on base business and our oil sands expansion phases that are expected to generate near-term cash flow;

·Reducing our discretionary spend and realigning our workforce, including reducing the size of our contract workforce, based on our revised spending plans;

·Issued 67.5 million common shares at $22.25 per share for net proceeds of $1.4 billion. We intend to use the net proceeds to partially fund our 2015 capital expenditure program and for general corporate purposes. The net proceeds from this financing combined with $3 billion available on our committed credit facility, provides us with a stronger balance sheet and increased financial flexibility; and

·Initiated a three percent discount to the average market price for shareholders participating in our DRIP. For our first quarter dividend, we had a participation rate of approximately 37 percent, resulting in cash savings of $81 million.

Operational Results

Both our upstream and refining assets have performed well in the first quarter. Facility run times were very good, resulting in average crude oil production of 218,020 barrels per day and 469,000 gross barrels per day of refined product output, up 11 percent and 12 percent from 2014, respectively.

Crude oil production from our Oil Sands segment averaged 144,372 barrels per day, an increase of 20 percent. Production from Foster Creek averaged 67,901 barrels per day, an increase of 24 percent, primarily due to phase F coming on stream in September 2014 and ramping up as expected, and increased production from additional wells including wells using our Wedge WellTM technology. Phase F is our eleventh oil sands phase.

Average production at Christina Lake increased to 76,471 barrels per day, a 16 percent increase. The increase was due to phase E reaching nameplate production capacity in the second quarter of 2014, additional wells including wells using our Wedge WellTM technology and improved performance of our facilities, all of which contributed to a lower steam to oil ratio (“SOR”).

Our Conventional crude oil production averaged 73,648 barrels per day, a four percent decrease primarily due to the divestitures of non-core assets in 2014. The crude oil production from these non-core assets was 3,174 barrels per day in the first quarter of 2014.

Crude oil processed and refined product output increased compared with 2014. In the first quarter of 2015, the Borger refinery completed a planned turnaround. In the first quarter of 2014, we completed planned maintenance and turnarounds at both of our refineries. We processed an average of 439,000 gross barrels per day (2014 — 400,000 gross barrels per day) of crude oil, of which 220,000 gross barrels per day (2014 — 195,000 gross barrels per day) was heavy crude oil. We produced 469,000 gross barrels per day of refined products, an increase of 49,000 gross barrels per day, or 12 percent.

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Financial Results

For an understanding of the trends and events that impacted our financial results, the following discussion should be read in conjunction with our 2014 annual MD&A.

(1)Non-GAAP measure defined in this MD&A.

In the first quarter of 2015, benchmark prices continued to decline resulting in a significant decrease in our financial results. Financial highlights for the first quarter of 2015 compared with 2014 include:

Operating Cash Flow

Operating Cash Flow decreased 53 percent to $549 million. Upstream Operating Cash Flow of $454 million (2014 – $924 million) declined primarily due to the low commodity price environment with our crude oil and natural gas sales prices declining by 57 percent and 32 percent, respectively.

This decrease in upstream Operating Cash Flow due to the significant decline in crude oil and natural gas sales prices was partially offset by:

·Realized risk management gains of $137 million, excluding Refining and Marketing, compared with losses of $35 million in 2014;

·Crude oil sales volumes increasing by 11 percent;

·Lower royalties primarily due to a decline in crude oil sales prices; and

·A reduction in crude oil operating expenses of $5.13 per barrel to $12.83 per barrel, primarily related to an increase in production volumes, a decline in workover activities, lower fuel costs due to a decrease in natural gas prices, and lower repairs and maintenance costs.

Operating Cash Flow from our Refining and Marketing segment declined $150 million or 61 percent. The decrease was due to higher heavy crude oil feedstock costs relative to the West Texas Intermediate (“WTI”) benchmark price and lower average market crack spreads, partially offset by improved margins on the sale of secondary products such as coke and asphalt, an increase in refined product output, and the weakening of the Canadian dollar relative to the U.S. dollar.

Cash Flow

Cash Flow decreased 45 percent to $495 million. Cash Flow was lower primarily due to a decline in Operating Cash Flow as discussed above, partially offset by a decrease in current income tax.

Operating Earnings (Loss)

Operating Earnings decreased $466 million primarily due to:

·A decrease in Cash Flow as discussed above;

·Unrealized foreign exchange losses of $9 million related to operating items as compared with gains of $53 million in 2014; and

·An increase in depreciation, depletion and amortization (“DD&A”) primarily due to higher production.

These decreases were partially offset by a recovery related to employee long-term incentives and lower deferred income tax.

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Net Earnings (Loss)

We had a Net Loss of $668 million in the quarter compared with Net Earnings of $247 million in 2014. The change was primarily related to non-operating unrealized foreign exchange losses of $514 million compared with a loss of $196 million in 2014. In addition, the decrease was due to an Operating Loss as discussed above and unrealized risk management losses compared with gains in 2014. The decrease to Net Earnings was partially offset by lower deferred income taxes.

Capital Investment

We continue to pursue our long-term strategy, though at a pace we believe is more in line with the low commodity price environment, focusing on capital restraint and conservation of cash. We have strong producing assets, an integrated portfolio, a solid balance sheet and flexibility in our capital plans, which should allow us to face the challenges ahead in 2015.

Capital investment in the quarter was $529 million, a decrease of 36 percent. We have suspended the majority of our conventional drilling program in southern Alberta and Saskatchewan as a result of the current low commodity price environment. Expansion work at Foster Creek phase G and Christina Lake phase F continues. However, construction work on Foster Creek phase H, Christina Lake phase G, and Narrows Lake phase A has been deferred in response to the low commodity price environment.

OPERATING RESULTS

Crude Oil Production Volumes

	Three Months Ended March 31,
(barrels per day)	2015	Percent Change		2014
Oil Sands
Foster Creek	67,901	24	%	54,706
Christina Lake	76,471	16	%	65,738
	144,372	20	%	120,444
Conventional
Heavy Oil	37,155	(9	)%	40,799
Light and Medium Oil	35,135	2	%	34,598
NGLs (1)	1,358	34	%	1,013
	73,648	(4	)%	76,410
Total Crude Oil Production	218,020	11	%	196,854

(1)NGLs include condensate volumes.

Foster Creek production increased compared with the first quarter of 2014 due to production from phase F coming on stream in September 2014 and ramping up as expected, and increased production from additional wells including wells using our Wedge WellTM technology. Ramp-up of phase F wells is expected to take approximately eighteen months from start up.

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Production from Christina Lake increased in the first quarter due to phase E reaching nameplate production capacity in the second quarter of 2014, additional wells including wells using our Wedge WellTM technology and improved performance of our facilities, all of which contributed to a lower SOR.

Our Conventional crude oil production decreased in 2015 primarily due to the divestitures of non-core assets in 2014.

Natural Gas Production Volumes

	Three Months Ended March 31,
(MMcf per day)	2015	2014
Conventional	442	457
Oil Sands	20	19
	462	476

In the first quarter of 2015, our natural gas production declined as expected. We continue to direct the majority of our capital investment to our crude oil properties.

Operating Netbacks

	Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)
	Three Months Ended March 31,			Three Months Ended March 31,
	2015	2014		2015	2014
Price (2)	31.08	73.12		3.05	4.47
Royalties	1.16	5.74		0.05	0.06
Transportation and Blending (2) (3)	5.31	2.59		0.12	0.11
Operating Expenses	12.83	17.96		1.26	1.26
Production and Mineral Taxes	0.22	0.42		0.01	(0.01	)
Netback Excluding Realized Risk Management	11.56	46.41		1.61	3.05
Realized Risk Management Gain (Loss)	6.58	(2.00	)	0.29	—
Netback Including Realized Risk Management	18.14	44.41		1.90	3.05

(1)Includes NGLs.

(2)The crude oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate was $22.29 per barrel for the first quarter (2014 – $34.54 per barrel).

(3)The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in the first quarter of 2014.

In the first quarter, our average crude oil netback, excluding realized risk management gains and losses, decreased $34.85 per barrel compared with 2014 primarily due to lower sales prices, consistent with the decline in benchmark prices, partially offset by the weakening of the Canadian dollar relative to the U.S. dollar. The weakening of the Canadian dollar in the first quarter had a positive impact on our crude oil price of approximately $3.50 per barrel.

Our average natural gas netback, excluding realized risk management gains and losses, decreased $1.44 per Mcf primarily due to lower sales prices consistent with the decline in the AECO benchmark price.

Refining (1)

	2015	Percent Change		2014
Crude Oil Runs (Mbbls/d)	439	10	%	400
Heavy Crude Oil	220	13	%	195
Refined Product (Mbbls/d)	469	12	%	420
Crude Utilization (percent)	95	8	%	87

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

Crude oil runs and refined product output increased compared to 2014. In the first quarter of 2015, we completed a planned turnaround at Borger. In the first quarter of 2014, we completed planned maintenance and turnarounds at both of our refineries.

Further information on the changes in our production volumes, items included in our operating netbacks and refining statistics can be found in the Reportable Segments section of this MD&A. Further information on our risk management activities can be found in the Risk Management section of this MD&A and in the notes to the Consolidated Financial Statements.

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COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

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 the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

	Q1 2015		Percent Change		Q4 2014		Q1 2014
Crude Oil Prices (US$/bbl)
Brent
Average	55.17		(28	)%	76.98		107.90
End of Period	55.11		(4	)%	57.33		107.76
WTI
Average	48.63		(34	)%	73.15		98.68
End of Period	47.60		(11	)%	53.27		101.58
Average Differential Brent-WTI	6.54		71	%	3.83		9.22
WCS (2)
Average	33.90		(42	)%	58.91		75.55
End of Period	37.30		(1	)%	37.59		80.71
Average Differential WTI-WCS	14.73		3	%	14.24		23.13
Condensate (C5 @ Edmonton)
Average	45.62		(35	)%	70.57		102.64
Average Differential WTI-Condensate (Premium)/Discount	3.01		17	%	2.58		(3.96	)
Average Differential WCS-Condensate (Premium)/Discount	(11.72	)	1	%	(11.66	)	(27.09	)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)	62.45		(23	)%	81.26		113.04
Chicago Ultra-low Sulphur Diesel (“ULSD”)	70.33		(31	)%	101.48		125.83
Refining Margin: Average 3-2-1 Crack Spreads (US$/bbl)
Chicago	16.53		13	%	14.60		18.55
Group 3	17.46		31	%	13.28		17.41
Average Natural Gas Prices
AECO (C$/Mcf)	2.95		(26	)%	4.01		4.76
NYMEX (US$/Mcf)	2.98		(26	)%	4.00		4.94
Basis Differential NYMEX-AECO (US$/Mcf)	0.57		30	%	0.44		0.60
Foreign Exchange Rates (US$ per C$1)
Average	0.806		(9	)%	0.881		0.906

(1)These benchmark prices do not reflect our realized sales prices. For our average realized sales prices and realized risk management results, refer to the operating netbacks table in the Operating Results section of this MD&A.

(2)The average Canadian dollar WCS benchmark price for the first quarter was $42.06 per barrel (2014 — $83.39 per barrel).

Crude Oil Benchmarks

Crude oil benchmark pricing continued to decline in the first quarter of 2015 compared with the fourth quarter of 2014. The average Brent, WTI and WCS benchmark prices decreased due to a global imbalance of supply and demand which began in the last half of 2014 and persisted in the first quarter of 2015. This global imbalance was created by slowing global economic conditions outside of the U.S. and strong growth in North American crude oil supply, which was further amplified by the Organization of Petroleum Exporting Countries (“OPEC”) decision to maintain its level of crude oil output and discontinue its swing supplier role. Despite significantly lower crude oil prices, the global imbalance has not materially improved to date in 2015, resulting in higher U.S. crude oil inventories which continue to put downward pressure on crude oil prices.

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland refined product prices. In the first quarter of 2015, the average price of Brent crude oil decreased by US$52.73 per barrel or 49 percent compared with 2014. The decline was primarily due to the global supply and demand imbalance discussed above.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. The average Brent-WTI differential narrowed in the first quarter of 2015 by US$2.68 per barrel or 29 percent as compared with 2014 as a result of new pipeline capacity to the U.S. Gulf Coast, increasing the price of WTI relative to Brent.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed by US$8.40 per barrel or 36 percent compared with the first quarter of 2014 primarily due to new pipeline infrastructure to the U.S. Gulf Coast, growing rail capacity providing access to existing and new U.S. heavy oil refining markets, and an increase in heavy crude oil demand with new coker capacity in the Chicago area.

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Blending condensate with bitumen and heavy oil enables our current production to be transported through pipelines. Our blending ratios range from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. As the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices are driven by U.S. Gulf Coast condensate prices plus the value attributed to transporting the condensate to Edmonton. Compared with the first quarter of 2014, the average WTI-Condensate differential changed by US$6.97 per barrel, with condensate being sold at a discount to WTI in 2015 as compared with a premium in 2014. This change was primarily due to increased supply resulting in a sharper decline in condensate prices as compared with the decline in WTI. The average WCS-Condensate differential narrowed by US$15.37 per barrel primarily due to improved transportation infrastructure for both condensate imports into Alberta and heavy crude oil exports to market.

Refining Benchmarks

The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and valued on a last in, first out accounting basis.

Average inland refined product prices decreased by 44 percent in the first quarter of 2015 as compared with 2014 due to weaker global crude oil pricing. Average Chicago 3-2-1 crack spreads fell 11 percent in the first quarter compared with 2014 due to the narrowing of the Brent-WTI differential as a result of new pipeline capacity to the U.S. Gulf Coast. Average Group 3 crack spreads increased slightly as a result of unplanned refinery outages resulting in slightly improved refined product pricing.

Our realized crack spreads are affected by many other factors such as the variety of feedstock crude oil inputs, refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis.

Natural Gas Benchmarks

Average natural gas prices decreased in the first quarter of 2015 primarily due to an increase in supply from the U.S.

Foreign Exchange Benchmarks

All of our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, natural gas and refined products are determined by reference to U.S. benchmark prices.  A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.

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In the first quarter of 2015, the Canadian dollar weakened by $0.10, or 11 percent, compared with 2014 relative to the U.S. dollar due to weaker commodity prices and the strengthening of the U.S. economy. The weakening of the Canadian dollar had a positive impact of approximately $350 million on our revenues and also resulted in an increase of $318 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.

FINANCIAL RESULTS

Selected Consolidated Financial Results

The following key performance measures are discussed in more detail within this section.

($ millions, except per share	2015		2014					2013
amounts)	Q1		Q4		Q3	Q2	Q1	Q4		Q3	Q2	Q1
Revenues	3,141		4,238		4,970	5,422	5,012	4,747		5,075	4,516	4,319
Operating Cash Flow (1)	549		539		1,154	1,296	1,169	976		1,153	1,125	1,214
Cash Flow (1)	495		401		985	1,189	904	835		932	871	971
Per Share – Diluted	0.64		0.53		1.30	1.57	1.19	1.10		1.23	1.15	1.28
Operating Earnings (Loss) (1)	(88	)	(590	)	372	473	378	212		313	255	391
Per Share – Diluted	(0.11	)	(0.78	)	0.49	0.62	0.50	0.28		0.41	0.34	0.52
Net Earnings (Loss)	(668	)	(472	)	354	615	247	(58	)	370	179	171
Per Share – Basic	(0.86	)	(0.62	)	0.47	0.81	0.33	(0.08	)	0.49	0.24	0.23
Per Share – Diluted	(0.86	)	(0.62	)	0.47	0.81	0.33	(0.08	)	0.49	0.24	0.23
Capital Investment (2)	529		786		750	686	829	898		743	706	915
Dividends
Cash Dividends	138		201		201	201	202	183		182	183	184
In Shares from Treasury	84		—		—	—	—	—		—	—	—
Per Share	0.2662		0.2662		0.2662	0.2662	0.2662	0.242		0.242	0.242	0.242

(1)Non-GAAP measure defined in this MD&A.

(2)Includes expenditures on PP&E and Exploration and Evaluation (“E&E”) assets.

Revenues

In the first quarter, revenues decreased $1,871 million or 37 percent compared with 2014 primarily due to the significant decline in commodity prices.

Upstream revenues declined by 42 percent primarily due to sharp declines in our crude oil blend and natural gas sales prices, consistent with the 55 percent decrease in WCS and 38 percent decrease in the AECO benchmark price.

($ millions)
Revenues for the Three Months Ended March 31, 2014	5,012
Increase (Decrease) due to:
Oil Sands	(480	)
Conventional	(364	)
Refining and Marketing	(1,162	)
Corporate and Eliminations	135
Revenues for the Three Months Ended March 31, 2015	3,141

The decrease to upstream revenues was partially offset by:

·Crude oil sales volumes increasing 11 percent; and

·A decrease in royalties of $79 million primarily due to a decline in crude oil sales prices.

Revenues generated by our Refining and Marketing segment decreased 36 percent. Refining revenues declined due to the continued decrease in refined product pricing consistent with lower Chicago RUL and Chicago ULSD benchmark prices, partially offset by higher refined product output and the weakening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party sales undertaken by the marketing group decreased primarily due to a decline in crude oil and natural gas sales prices, partially offset by an increase in purchased crude oil volumes.

Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on current market prices.

Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.

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Operating Cash Flow

Operating Cash Flow is a non-GAAP measure that is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between years. Operating Cash Flow is defined as revenues less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Cash Flow.

	Three Months Ended March 31,
($ millions)	2015		2014
Revenues	3,247		5,253
(Add) Deduct:
Purchased Product	1,838		2,820
Transportation and Blending	528		653
Operating Expenses	478		574
Production and Mineral Taxes	5		7
Realized (Gain) Loss on Risk Management Activities	(151	)	30
Operating Cash Flow	549		1,169

As highlighted in the graph below, Operating Cash Flow declined 53 percent in the first quarter as compared with 2014 primarily due to:

· A 57 percent decrease in our average crude oil sales price to $31.08 per barrel and a 32 percent decrease in our average natural gas sales price to $3.05 per Mcf, consistent with the sharp drop in associated benchmark prices; and

· Lower Operating Cash Flow from Refining and Marketing as a result of higher heavy crude oil feedstock costs relative to WTI and a decrease in average market crack spreads, partially offset by improved margins on the sale of secondary products due to lower overall feedstock costs, an increase in refined product output, and the weakening of the Canadian dollar relative to the U.S. dollar.

These declines to Operating Cash Flow were partially offset by:

· Realized risk management gains of $137 million, excluding Refining and Marketing, compared with losses of $35 million in 2014;

· An 11 percent increase in our crude oil sales volumes;

· Lower royalties primarily due to a decrease in crude oil and natural gas sales prices; and

· A decrease in crude oil operating expenses of $5.13 per barrel to $12.83 per barrel primarily due to higher crude oil production, a decline in workover activities, a reduction in fuel costs due to lower natural gas prices, and lower repairs and maintenance costs.

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Additional details explaining the changes in Operating Cash Flow can be found in the Reportable Segments section of this MD&A.

Cash Flow

Cash Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. 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.

	Three Months Ended March 31,
($ millions)	2015		2014
Cash From Operating Activities	275		457
(Add) Deduct:
Net Change in Other Assets and Liabilities	(54	)	(42	)
Net Change in Non-Cash Working Capital	(166	)	(405	)
Cash Flow	495		904

In the first quarter of 2015, Cash Flow decreased $409 million primarily due to lower Operating Cash Flow, as discussed above. Declines in Cash Flow were partially offset by a current income tax recovery in 2015.

Operating Earnings (Loss)

Operating Earnings (Loss) is a non-GAAP measure that is used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax.

	Three Months Ended March 31,
($ millions)	2015		2014
Earnings (Loss), Before Income Tax	(781	)	358
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)	145		(26	)
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)	514		196
(Gain) Loss on Divestiture of Assets	(16	)	—
Operating Earnings (Loss), Before Income Tax	(138	)	528
Income Tax Expense (Recovery)	(50	)	150
Operating Earnings (Loss)	(88	)	378

(1)Includes the reversal of unrealized (gains) losses recorded in prior periods.

(2)Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange (gains) losses on settlement of intercompany transactions.

In the first quarter of 2015, Operating Earnings decreased $466 million primarily due to:

·A decrease in Cash Flow as discussed above;

·Unrealized foreign exchange losses of $9 million related to operating items as compared with gains of $53 million in 2014; and

·An increase in DD&A primarily related to higher sales volumes from our Oil Sands assets.

These decreases were partially offset by a recovery of employee long-term incentive costs compared with an expense in 2014 and lower deferred income tax primarily related to a decrease in income before income tax.

Net Earnings (Loss)

($ millions)
Net Earnings for the Three Months Ended March 31, 2014	247
Increase (Decrease) due to:
Operating Cash Flow (1)	(620	)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)	(171	)
Unrealized Foreign Exchange Gain (Loss)	(380	)
Gain (Loss) on Divestiture of Assets	16
Expenses (2)	61
Depreciation, Depletion and Amortization	(45	)
Income Tax Expense	224
Net Earnings (Loss) for the Three Months Ended March 31, 2015	(668	)

(1)Non-GAAP measure defined in this MD&A.

(2)Includes general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net and Corporate and Eliminations operating expenses.

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Net Earnings decreased $915 million in the first quarter of 2015 primarily due to:

·A decline in Operating Earnings of $466 million as discussed above;

·Non-operating unrealized foreign exchange losses of $514 million (2014 — unrealized losses of $196 million); and

·Unrealized risk management losses of $145 million (2014 — unrealized gains of $26 million).

The decreases in Net Earnings were partially offset by:

·Lower deferred income taxes as a result of a decrease in Canadian and U.S. income and unrealized risk management losses compared with a gain in 2014.

Net Capital Investment

	Three Months Ended March 31,
($ millions)	2015		2014
Oil Sands	414		527
Conventional	66		270
Refining and Marketing	44		23
Corporate and Eliminations	5		9
Capital Investment	529		829
Acquisitions	—		1
Divestitures	(16	)	(2	)
Net Capital Investment (1)	513		828

(1)Includes expenditures on PP&E and E&E.

We continue to pursue our long-term strategy, though at a pace we believe is more in line with the low commodity price environment, with a focus on capital restraint and conservation of cash. We have strong producing assets, an integrated portfolio, a solid balance sheet and flexibility in our capital plans, which should allow us to face the challenges in 2015.

Capital investment in the first quarter of 2015 was $529 million, a decrease of 36 percent. In January, we reduced our planned capital investment with the intent of conserving cash and maintaining the strength of our balance sheet in light of the continued low commodity price environment. We plan to focus 2015 capital investment on ensuring our assets are appropriately maintained, meet safety, regulatory and contractual obligations, and on our Christina Lake phase F and Foster Creek phase G expansions.

In the first quarter of 2015, Oil Sands capital investment focused primarily on sustaining capital related to existing production, phase G expansion at Foster Creek, Christina Lake’s phase F expansion and the optimization project, and the drilling of 158 gross stratigraphic test wells which were primarily related to near-term phase expansions to determine pad placement.

Conventional capital investment focused primarily on maintenance capital and spending for our CO2 project at Weyburn.

Our capital investment in the Refining and Marketing segment focused on the debottlenecking project at Wood River, in addition to capital maintenance, projects improving our refinery reliability and safety, and environmental initiatives.

Capital also includes spending on technology development, which plays an integral role in our business. Having a strategy focused on innovation and technology development is vital to our ability to minimize our environmental footprint and execute our projects with excellence. Our teams look for ways to improve existing operations and evaluate new ideas to potentially reduce costs, enhance the recovery techniques we use to access crude oil and natural gas and improve our refining processes.

Capital investment in our Corporate and Eliminations segment includes spending on corporate assets, which was primarily for computer equipment.

Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.

Capital Investment Decisions

Our disciplined approach to capital allocation includes prioritizing our uses of cash flow in the following manner:

·First, to committed capital, which is the capital spending required for continued progress on approved expansions at our multi-phase projects, and capital for our existing business operations;

·Second, to paying a dividend as part of providing strong total shareholder return; and

·Third, for growth or discretionary capital, which is the capital spending for projects beyond our committed capital projects.

Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria as well as achieving our objectives of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which allow us to be financially resilient in times of lower cash flow. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. We anticipate maintaining investment grade credit ratings.

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In January 2015, in light of the current low commodity price environment, we revised our 2015 capital budget in order to help conserve cash and maintain the strength of our balance sheet. We anticipate our total annual capital investment to be between $1.8 billion and $2.0 billion for 2015. Our capital budget has a degree of flexibility and, as such, we will continue to assess spending plans on a regular basis and make adjustments, if required. Refer to the Reportable Segments section of this MD&A for more details and the news release for our revised 2015 budget dated January 28, 2015. The news release is available on our website at cenovus.com, on SEDAR at sedar.com and on EDGAR at sec.gov.

	Three Months Ended March 31,
($ millions)	2015		2014
Cash Flow (1)	495		904
Capital Investment (Committed and Growth)	529		829
Free Cash Flow (2)	(34	)	75
Cash Dividends	138		202
	(172	)	(127	)

(1)Non-GAAP measure defined in this MD&A.

(2)Free Cash Flow is a non-GAAP measure defined as Cash Flow less capital investment.

Cash flow from our crude oil, natural gas and refining operations is expected to fund a portion of our cash requirements, with any remainder expected to be funded through prudent use of our balance sheet capacity and management of our asset portfolio. In the first quarter of 2015 we issued 67.5 million common shares for net proceeds of $1.4 billion. Refer to the Liquidity and Capital Resources section of this MD&A for further information.

REPORTABLE SEGMENTS

Our reportable segments are as follows:

Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. The Athabasca natural gas assets also form part of this segment. Certain of Cenovus’s operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company.

Conventional, which includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake. This segment also includes the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.

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Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the 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.

Revenues by Reportable Segment

	Three Months Ended March 31,
($ millions)	2015		2014
Oil Sands	729		1,209
Conventional	422		786
Refining and Marketing	2,096		3,258
Corporate and Eliminations	(106	)	(241	)
	3,141		5,012

OIL SANDS

In northeastern Alberta, we are a 50 percent partner in the Foster Creek, Christina Lake and Narrows Lake oil sands projects. We have several emerging projects in the early stages of development, including our 100 percent-owned projects at Telephone Lake and Grand Rapids. The Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.

Significant developments in our Oil Sands segment in the first quarter of 2015 compared with 2014 include Foster Creek production increasing 24 percent, to an average of 67,901 barrels per day and Christina Lake production increasing 16 percent, to an average of 76,471 barrels per day as facility run times were very good. Foster Creek production increased primarily as a result of phase F coming on stream. Christina Lake production rose primarily due to phase E reaching nameplate production capacity in the second quarter of 2014.

Oil Sands — Crude Oil

Financial and Per-unit Results

	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
($ millions, unless otherwise noted (1))			$ per-unit				$ per-unit
Gross Sales	723		57		1,230		116
Less: Royalties	3		—		51		5
Revenues	720		57		1,179		111
Expenses
Transportation and Blending	470		37		559		53
Operating	139		11		170		16
(Gain) Loss on Risk Management	(89	)	(7	)	22		2
Operating Cash Flow	200		16		428		40
Capital Investment	413				525
Operating Cash Flow Net of Related Capital Investment	(213	)			(97	)

(1)Per-unit amounts are calculated on an unblended crude oil basis.

Capital investment in excess of Operating Cash Flow from Oil Sands is funded through Operating Cash Flow generated by our Conventional and Refining and Marketing segments and proceeds from our common share issuance in the first quarter of 2015.

(1)Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

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Revenues

Pricing

In the first quarter, our average crude oil sales price was $26.04 per barrel, a 60 percent decrease from 2014 as the prices we received continued to be impacted by the worldwide commodity price environment. The decline in our crude oil price was consistent with the decrease in the WCS and Christina Dilbit Blend (“CDB”) benchmark prices, partially offset by the weakening of the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market which secure a higher sales price. The WCS-CDB differential narrowed by 34 percent to a discount of US$3.21 per barrel (2014 — a discount of US$4.90 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process heavier crude oil. In the first quarter, 86 percent of our Christina Lake production was sold as CDB (2014 — 84 percent), with the remainder sold into the WCS stream. Christina Lake production, whether sold as CDB or blended with WCS and subject to a quality equalization charge, is priced at a discount to WCS.

Production Volumes

	Three Months Ended March 31,
(barrels per day)	2015	PercentChange		2014
Foster Creek	67,901	24	%	54,706
Christina Lake	76,471	16	%	65,738
	144,372	20	%	120,444

Foster Creek production increased compared with the first quarter of 2014 due to production from phase F coming on stream in September 2014, and increased production from additional wells including wells using our Wedge WellTM technology. Ramp-up of phase F wells is proceeding as expected and is anticipated to take approximately eighteen months from start up.

Production from Christina Lake increased in the first quarter due to phase E reaching nameplate production capacity in the second quarter of 2014, a higher number of wells including wells using our Wedge WellTM technology and improved performance of our facilities, all of which contributed to a lower SOR.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market. Revenues represent the total value of blended crude oil sold and include the value of condensate.

Royalties

Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price. Royalty calculations differ between properties.

Royalties at Foster Creek, a post-payout project, are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits are a function of sales volumes, realized sales prices and allowed operating and capital costs.

Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project.

Effective Royalty Rates

	Three Months Ended March 31,
(percent)	2015		2014
Foster Creek	(1.2	)	8.1
Christina Lake	3.1		7.1

Royalties decreased $48 million in the first quarter of 2015, primarily related to the decline in crude oil sales prices, partially offset by an increase in sales volumes. At Foster Creek, this resulted in a royalty calculation based on gross revenues in the first quarter of 2015 compared with a calculation based on net profits in 2014.

In the first quarter of 2015, we received regulatory approval to include certain capital costs incurred in previous years in our royalty calculation which has resulted in a negative royalty rate at Foster Creek for the quarter. We recorded the associated credit in the first quarter of 2015. Excluding the credit, the effective royalty rate for Foster Creek would have been 5.9 percent.

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Expenses

Transportation and Blending

Transportation and blending costs decreased $89 million or 16 percent. Blending costs declined primarily due to lower condensate prices, partially offset by an increase in condensate volumes consistent with the rise in production. Our condensate costs were higher than the average benchmark price in 2015 primarily due to the utilization of higher priced inventory and the transportation expense associated with moving the condensate to our oil sands projects.

Transportation costs increased $62 million primarily due to higher pipeline tariffs and additional sales to the U.S. market which attract higher tariffs. To ensure adequate capacity for our expected future production growth, we hold long-term transportation agreements on the Cold Lake pipeline expansion. Deliveries commenced in the first quarter of 2015. We also have capacity on the Flanagan South system, which will increase our sales opportunities into the U.S. market which secure a higher sales price. Deliveries on the Flanagan South system began in the fourth quarter of 2014. Future production growth is expected to reduce our per-barrel transportation costs.

In addition, transportation costs increased as a result of higher volumes transported by rail. In the first quarter of 2015, we transported an average of 11,871 gross barrels per day of crude oil by rail, consisting of 18 unit train shipments (2014 — 1,964 gross barrels per day, including three unit train shipments). Rail transportation costs are generally higher than pipeline costs; however, rail provides flexibility in destinations, products transported and the duration of the cost commitment, which is typically shorter in term than pipeline commitments.

Operating

Primary drivers of our operating expenses in the first quarter of 2015 were workforce, fuel, workovers and repairs and maintenance. Total operating expenses decreased $31 million or $4.99 per barrel, primarily as a result of higher production, lower natural gas prices that reduced fuel costs, and a decline in workover activities.

Per-unit Operating Expenses

	Three Months Ended March 31,
($/bbl)	2015	PercentChange		2014
Foster Creek
Fuel	2.96	(46	)%	5.45
Non-fuel	11.52	(16	)%	13.64
Total	14.48	(24	)%	19.09
Christina Lake
Fuel	2.19	(55	)%	4.83
Non-fuel	6.03	(29	)%	8.47
Total	8.22	(38	)%	13.30
Total	10.97	(31	)%	15.96

At Foster Creek, fuel costs decreased $2.49 per barrel primarily due to the decline in natural gas prices. Non-fuel operating expenses declined $2.12 per barrel, primarily due to:

·Higher production volumes;

·A reduction in workover activities related to well servicing, primarily due to fewer pump changes; and

·A decline in electricity costs due to lower prices.

The decrease in non-fuel operating expenses was partially offset by higher chemical costs.

At Christina Lake, fuel costs decreased by $2.64 per barrel due to the decline in natural gas prices and a decrease in fuel consumption on a per barrel basis. Non-fuel operating expenses decreased $2.44 per barrel, primarily due to:

·Increased production;

·Declines in fluid, waste handling and trucking costs related to the optimization of the chemical application process;

·Lower workover activities related to well servicing, primarily due to fewer pump changes; and

·A decrease in repairs and maintenance costs due to a focus on critical operational activities.

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(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate in the first quarter was $30.57 per barrel (2014 — $48.35 per barrel) for Foster Creek; and $31.60 per barrel (2014 — $52.81 per barrel) for Christina Lake.

Risk Management

Risk management activities in the first quarter resulted in realized gains of $89 million (2014 — realized losses of $22 million), consistent with our contract prices exceeding average benchmark prices.

Oil Sands — Natural Gas

Oil Sands includes our 100 percent-owned natural gas operations in Athabasca. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production for the first quarter of 2015, net of internal usage, was 20 MMcf per day (2014 — 19 MMcf per day). Operating Cash Flow was $3 million in the first quarter (2014 — $23 million). The decrease was primarily related to the decline in natural gas sales prices.

Oil Sands — Capital Investment

	Three Months Ended March 31,
($ millions)	2015	2014
Foster Creek	149	221
Christina Lake	207	182
	356	403
Narrows Lake	20	47
Telephone Lake	11	52
Grand Rapids	14	11
Other (1)	13	14
Capital Investment (2)	414	527

(1)Includes new resource plays and Athabasca natural gas.

(2)Includes expenditures on PP&E and E&E assets.

We continue to pursue our long-term strategy, though at a pace we believe is more in line with the low commodity price environment, with a focus on capital restraint and conservation of cash. We have strong producing assets, an integrated portfolio, a solid balance sheet and flexibility in our capital plans, which should allow us to face the challenges in 2015. We plan to focus our 2015 capital investment on base business and our oil sands expansion phases that are expected to generate near-term cash flow.

Existing Projects

Capital investment at Foster Creek in the first quarter focused on sustaining capital related to existing production, expansion phase G and the drilling of stratigraphic test wells primarily related to future sustaining well pads. Capital investment declined compared with 2014 due to lower spending related to field construction and completion costs with the commissioning of phase F in 2014 and the drilling of fewer stratigraphic test wells.

In the first quarter, Christina Lake capital investment focused on sustaining capital related to existing production, expansion phase F and the optimization project. Capital investment increased due to higher spending on sustaining wells; phase G engineering and procurement; phase F well pads; and progressing the optimization project.

Capital investment at Narrows Lake focused on detailed engineering and procurement for phase A. Capital investment declined due to the suspension of new construction on phase A until further notice.

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Emerging Projects

In the first quarter, Telephone Lake capital investment was primarily focused on front-end engineering work on the central processing facility. Capital spending decreased as we did not drill any stratigraphic test wells in the first quarter (2014 — 31 stratigraphic test wells).

Capital investment at Grand Rapids in the first quarter was primarily focused on the drilling of a third pilot well pair at the SAGD pilot project to gather additional information on the reservoir. Capital investment increased due to the dismantling, removal and storage of an existing SAGD facility purchased in 2014, partially offset by the lack of stratigraphic test wells drilled in 2015.

Drilling Activity (1)

	Gross Stratigraphic Test Wells (2)		Gross Production Wells (3) (4)
	Three Months Ended March 31,
	2015	2014	2015	2014
Foster Creek	122	145	13	15
Christina Lake	36	51	19	18
	158	196	32	33
Narrows Lake	—	22	—	—
Telephone Lake	—	31	—	—
Grand Rapids	—	9	1	—
Other	—	21	—	—
	158	279	33	33

(1)In addition to the drilling activity included within the table, we drilled five gross service wells in the first quarter (2014 — one gross service well).

(2)Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. In the first quarter, we drilled seven wells (2014 — no wells drilled) and commissioned our second SkyStratTM drilling rig.

(3)SAGD well pairs are counted as a single producing well.

(4)Includes wells drilled using our Wedge WellTM technology.

Future Capital Investment

Due to our expectation that the low commodity price environment will continue for the near term, we decided in January to slow 2015 capital activities in order to conserve cash and maintain the strength of our balance sheet. For more details, refer to our January 28, 2015 news release available on our website at cenovus.com, on SEDAR at sedar.com and on EDGAR at sec.gov. Our capital budget has a degree of flexibility and as such we will continue to assess spending plans on a regular basis and make adjustments, if required.

Existing Projects

Foster Creek is currently producing from phases A through F. Capital investment for 2015 is forecast to be between $550 million and $600 million and we plan to focus on sustaining capital related to existing production as well as progressing expansion phase G. We expect phase G to add initial design capacity of 30,000 gross barrels per day and first production is anticipated in the first half of 2016. Spending related to construction work on phase H has been deferred in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase H has an initial design capacity of 30,000 barrels per day. In December 2014, we received regulatory approval for expansion phase J, a 50,000 gross barrel per day phase.

Christina Lake is producing from phases A through E. Capital investment in 2015 is forecast to be between $650 million and $700 million and we plan to focus on sustaining capital related to existing production, expansion phase F and the optimization project. Expansion work on phase F, including cogeneration, is expected to continue as planned. We anticipate adding production capacity of 50,000 gross barrels per day from phase F in the second half of 2016. The optimization project is expected to add production capacity of 22,000 gross barrels per day in the fourth quarter of 2015. Spending related to construction work on phase G has been deferred in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase G engineering and procurement are planned to continue in 2015. Phase G has an initial design capacity of 50,000 gross barrels per day. We submitted a joint application and environmental impact assessment to regulators in March 2013 for the phase H expansion, a 50,000 gross barrel per day phase, for which we expect to receive regulatory approval in the second quarter of 2015.

Capital investment at Narrows Lake is forecast to be between $30 million and $40 million in 2015. In 2015, we plan to focus our capital investment on detailed engineering and procurement. We have suspended new construction on phase A until crude oil prices recover.

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Emerging Projects

Two of our emerging projects are Telephone Lake and Grand Rapids. Capital investment for our new resource plays is forecast to be between $90 million and $100 million in 2015. We plan to focus on continuing the pilot project at Grand Rapids; the dismantling, removal and storage of an existing SAGD facility purchased in 2014; as well as engineering at Telephone Lake. At Grand Rapids, we drilled a third pilot well pair in the first quarter of 2015 and we plan to commence steam circulation in the second quarter, as we continue to operate the SAGD pilot project to gather additional information on the reservoir.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by total proved reserves.

In the first quarter of 2015, Oil Sands DD&A increased $27 million primarily due to higher sales volumes.

CONVENTIONAL

Our Conventional operations include predictable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a carbon dioxide enhanced oil recovery project in Weyburn, our heavy oil asset at Pelican Lake and developing tight oil assets in Alberta. Pelican Lake produces conventional heavy oil using polymer flood technology. The established assets in this segment are strategically important for their long life reserves, stable operations and diversity of crude oil produced. The cash flow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment.

We own the mineral rights on approximately 70 percent or 4.5 million net acres of our conventional lands (fee lands), of which 2.5 million acres are developed. Production from fee lands comprises approximately 50 percent of our total conventional production. Fee lands where we have maintained working interest production are subject to mineral tax, which is generally lower than the royalties paid to the government or other mineral interest owners.

Of the 4.5 million net acres of fee land, we lease over 2.0 million acres to third parties, which may result in royalty income. In the first quarter of 2015, we had approximately 7,400 barrels of oil equivalent per day of royalty interest production from fee lands which resulted in Operating Cash Flow of approximately $25 million (2014 — approximately $40 million).

Our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations.

Significant developments in our Conventional segment in the first quarter of 2015 compared with 2014 include:

·Crude oil production averaging 73,648 barrels per day, decreasing four percent primarily due to the divestitures of non-core assets in 2014; and

·Generating Operating Cash Flow net of capital investment of $183 million, a decrease of 12 percent.

Conventional — Crude Oil

Financial and Per-unit Results

	Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
($ millions, unless otherwise noted (1))			$ per-unit			$ per-unit
Gross Sales	315		46		651	95
Less: Royalties	19		3		49	7
Revenues	296		43		602	88
Expenses
Transportation and Blending	53		8		89	13
Operating	109		16		145	21
Production and Mineral Taxes	5		1		8	1
(Gain) Loss on Risk Management	(37	)	(5	)	13	2
Operating Cash Flow	166		23		347	51
Capital Investment	62				263
Operating Cash Flow Net of Related Capital Investment	104				84

(1)Per-unit amounts are calculated on an unblended crude oil basis.

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(1)Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

Revenues

Pricing

Our average crude oil sales price decreased 53 percent to $40.43 per barrel consistent with the continued decline in crude oil benchmark prices.

Production Volumes

(barrels per day)	2015	Percent Change		2014
Heavy Oil	37,155	(9	)%	40,799
Light and Medium Oil	35,135	2	%	34,598
NGLs	1,358	34	%	1,013
	73,648	(4	)%	76,410

Production declined primarily due to the divestiture of non-core assets in 2014.

Condensate

Revenues represent the total value of blended crude oil sold and include the value of condensate.

Royalties

Royalties decreased $30 million primarily due to lower realized sales prices. In the first quarter, the effective crude oil royalty rate for our Conventional properties was 7.5 percent (2014 — 9.0 percent).

Royalties at Pelican Lake are determined under oil sands royalty calculations. Pelican Lake is a post-payout project, therefore royalties are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales volumes and realized sales prices. Net profits are a function of sales volumes, realized sales prices and allowed operating and capital costs. In the first quarter of 2015, the Pelican Lake royalty calculation was based on net profits as compared with a calculation based on gross revenues in 2014.

Approximately 50 percent of our production is not subject to royalties, rather is subject to mineral tax which is generally lower than the royalties paid to the government or other mineral interest owners. In the first quarter of 2015, production and mineral taxes decreased, consistent with the decline in crude oil prices.

Expenses

Transportation and Blending

Transportation and blending costs decreased $36 million. Blending costs declined primarily due to lower condensate prices. In the first quarter of 2015, we recorded a $3 million write-down of our crude oil inventory to net realizable value as a result of the continued decline in crude oil prices. Transportation charges were $2 million lower primarily due to a decrease in volumes moved by rail. In the first quarter of 2015, we transported an average of 1,591 gross barrels per day of crude oil by rail (2014 — 5,497 barrels per day).

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Operating

Primary drivers of our operating expenses in the first quarter of 2015 were workforce costs, workover activities, chemical consumption, electricity and repairs and maintenance. Operating expenses declined $36 million or $4.77 per barrel.

The per unit decline was primarily due to:

·A decline in workover costs and lower repairs and maintenance due to a focus on critical operational activities;

·Lower electricity costs as a result of a decrease in consumption related to the dispositions of non-core assets, and a decline in prices; and

·A decrease in fuel costs primarily related to a decline in consumption and lower fuel prices.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended heavy oil basis, the cost of condensate for our heavy oil properties was $11.50 per barrel in the first quarter (2014 — $17.56 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

(2)The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in the first quarter of 2014.

Risk Management

Risk management activities in the first quarter resulted in realized gains of $37 million (2014 — realized losses of $13 million), consistent with our contract prices exceeding average benchmark prices.

Conventional — Natural Gas

Financial Results

	Three Months Ended March 31,
($ millions)	2015		2014
Gross Sales	122		184
Less: Royalties	2		3
Revenues	120		181
Expenses
Transportation and Blending	5		5
Operating	47		49
Production and Mineral Taxes	—		(1	)
(Gain) Loss on Risk Management	(10	)	—
Operating Cash Flow	78		128
Capital Investment	4		7
Operating Cash Flow Net of Related Capital Investment	74		121

Operating Cash Flow from natural gas continued to help fund growth opportunities in our Oil Sands segment.

Revenues

Pricing

In the first quarter of 2015, our average natural gas sales price decreased $1.39 per Mcf to $3.07 per Mcf, consistent with the continued decline in the AECO benchmark price.

Production

Production decreased three percent to 442 MMcf per day primarily due to expected natural declines.

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Royalties

Royalties decreased slightly as a result of lower prices and production declines. The average royalty rate in the first quarter was 1.7 percent (2014 — 1.3 percent). Most of our natural gas production is located on fee lands where we hold mineral rights and is not subject to royalties. Instead, this production is subject to mineral tax which is generally lower than royalties paid to the government or other mineral rights owners.

Expenses

Transportation

Transportation costs remained consistent as a result of lower production volumes, offset by higher pipeline rates.

Operating

In the first quarter of 2015, our operating expenses were primarily composed of property taxes and lease costs, and workforce. Operating expenses decreased slightly primarily due to lower electricity costs, partially offset by higher property taxes and lease costs.

Risk Management

Risk management activities in the first quarter resulted in realized gains of $10 million (2014 — $nil), consistent with our contract prices exceeding average benchmark prices.

Conventional — Capital Investment (1)

	Three Months Ended March 31,
($ millions)	2015	2014
Heavy Oil	22	106
Light and Medium Oil	40	157
Natural Gas	4	7
	66	270

(1)Includes expenditures on PP&E and E&E assets.

Capital investment in the first quarter was primarily related to maintenance capital and spending for our CO2 project at Weyburn. Spending on crude oil and natural gas activities continues to be managed in response to the low commodity price environment.

Conventional Drilling Activity

	Three Months Ended March 31,
(net wells, unless otherwise stated)	2015	2014
Crude Oil	5	52
Recompletions	34	223
Gross Stratigraphic Test Wells	—	13
Other (1)	—	16

(1)Includes dry and abandoned, observation and service wells.

Drilling activity declined in the first quarter, reflecting the decision to suspend the majority of our 2015 drilling program in southern Alberta and Saskatchewan as a result of the current low commodity price environment.

Future Capital Investment

In 2015, crude oil capital investment is forecast to be between $200 million and $215 million with spending plans mainly focused on maintenance capital and spending for our CO2 project at Weyburn.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate takes into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by total proved reserves.

Conventional DD&A increased $10 million in the first quarter of 2015. The increase was primarily due to higher DD&A rates related to a decrease in proved reserves.

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REFINING AND MARKETING

We are a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. Our Refining and Marketing segment allows us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to our refineries. The Refining and Marketing segment’s results are affected by changes in the U.S./Canadian dollar exchange rate. The weakening of the Canadian dollar relative to the U.S. dollar by 11 percent in the first quarter of 2015 as compared with 2014 had a positive impact of approximately $26 million on our refining gross margin.

Significant developments in our Refining and Marketing segment in the first quarter of 2015 compared with 2014 include:

·Crude oil runs and refined product output increasing as a result of the timing of planned maintenance and turnaround activities;

·Operating Cash Flow declining 61 percent to $95 million primarily due to higher heavy crude oil feedstock costs relative to WTI and lower average market crack spreads, partially offset by improved margins on the sale of secondary products, an increase in refined product output, and the weakening of the Canadian dollar relative to the U.S. dollar; and

·Successfully completed a planned turnaround at our Borger refinery.

Refinery Operations (1)

	Three Months Ended March 31,
	2015	2014
Crude Oil Capacity (2) (Mbbls/d)	460	460
Crude Oil Runs (Mbbls/d)	439	400
Heavy Crude Oil	220	195
Light/Medium	219	205
Refined Products (Mbbls/d)	469	420
Gasoline	236	215
Distillate	144	130
Other	89	75
Crude Utilization (percent)	95	87

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

(2)The official nameplate capacity, based on 95 percent of the highest average rate achieved over a continuous 30 day period.

On a 100 percent basis, our refineries have total capacity of approximately 460,000 gross barrels per day of crude oil, excluding NGLs, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil, and capacity of 45,000 gross barrels per day of NGLs. The ability to refine heavy crude oil demonstrates our ability to economically integrate our heavy crude oil production. The discount of WCS relative to WTI benefits our refining operations due to the feedstock cost advantage provided by processing heavy crude oil.

In the first quarter of 2015, crude oil runs, refined product output and crude utilization increased as a result of reduced output in 2014 primarily due to planned maintenance and turnarounds at both of our refineries. In the first quarter of 2015, we completed a planned turnaround at Borger.

Our crude utilization represents the percentage of total crude oil processed in our refineries relative to the total capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by processing less expensive crude oil. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate being optimized at each refinery to maximize economic benefit. The amount of heavy crude oil processed in the first quarter of 2015 increased, consistent with the increase in total crude oil runs.

Financial Results

	Three Months Ended March 31,
($ millions)	2015		2014
Revenues	2,096		3,258
Purchased Product	1,838		2,820
Gross Margin	258		438
Expenses
Operating	177		198
(Gain) Loss on Risk Management	(14	)	(5	)
Operating Cash Flow	95		245
Capital Investment	44		23
Operating Cash Flow Net of Related Capital Investment	51		222

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Gross Margin

Our realized crack spreads are affected by many factors such as the variety of feedstock crude oil inputs, refinery configuration and the proportion of gasoline, distillate and secondary product output, the time lag between the purchase of crude oil feedstock and the processing of that crude oil through our refineries, and the cost of feedstock. Our feedstock costs are valued on a FIFO accounting basis.

In the first quarter of 2015, the decrease in gross margin was primarily due to:

·Higher heavy crude oil feedstock costs relative to WTI, consistent with the narrowing of the WTI-WCS differential; and

·Lower average market crack spreads, which decreased by approximately five percent, primarily due to the narrowing of the Brent-WTI differential.

The decrease in gross margin was partially offset by:

·Improved margins on the sale of secondary products, such as coke and asphalt, due to lower overall feedstock costs consistent with the 51 percent decline in WTI;

·An increase in refined product output by 12 percent; and

·The weakening of the Canadian dollar relative to the U.S. dollar by 11 percent.

Our refineries do not blend renewable fuels into the motor fuel products we produce. Consequently, we are obligated to purchase Renewable Identification Numbers (“RINs”). In the first quarter of 2015, the cost of our RINs was $53 million (2014 — $26 million). This increase is consistent with the rise in the ethanol RINs benchmark price as well as the increase in refined product output. This cost remains a minor component of our total refinery feedstock costs.

Operating Expense

Primary drivers of operating expenses in the first quarter of 2015 were labour, maintenance, utilities and supplies. Operating expenses decreased 11 percent primarily due to a reduction in planned maintenance and turnaround activities and a decline in utility costs resulting from a decrease in natural gas prices.

Refining and Marketing — Capital Investment

	Three Months Ended March 31,
($ millions)	2015	2014
Wood River Refinery	27	11
Borger Refinery	17	12
Marketing	—	—
	44	23

Capital expenditures in the first quarter of 2015 focused on the debottlenecking project at Wood River, in addition to capital maintenance, projects improving our refinery reliability and safety, and environmental initiatives. In the first quarter of 2014, we and our partner sanctioned the Wood River debottleneck project. We received permit approval in the first quarter of 2015 and planned start-up is anticipated in the second half of 2016.

In 2015, we expect to invest between $240 million and $260 million mainly related to the debottlenecking project at Wood River, in addition to maintenance, reliability and environmental initiatives.

DD&A

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The service lives of these assets are reviewed on an annual basis. In the first quarter of 2015, Refining and Marketing DD&A increased by $7 million primarily due to the change in the U.S./Canadian dollar exchange rate.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices and the unrealized mark-to-market gains and losses on the long-term power purchase contract. In the first quarter, our risk management activities resulted in $145 million of unrealized losses (2014 — $26 million of unrealized gains). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing costs and research costs.

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	Three Months Ended March 31,
($ millions)	2015		2014
General and Administrative	72		109
Finance Costs	121		130
Interest Income	(11	)	(2	)
Foreign Exchange (Gain) Loss, Net	515		147
Research Costs	7		2
(Gain) Loss on Divestiture of Assets	(16	)	—
Other (Income) Loss, Net	—		(1	)
	688		385

Expenses

General and Administrative

Primary drivers of our general and administrative expenses in the first quarter of 2015 were workforce, office rent and information technology costs. General and administrative expenses decreased $37 million primarily due to lower employee long-term incentive costs consistent with the decline in our share price.

Finance Costs

Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated Partnership Contribution Payable, as well as the unwinding of the discount on decommissioning liabilities. Finance costs decreased $9 million in the first quarter of 2015. The decrease was primarily due to lower interest incurred on the Partnership Contribution Payable which was repaid in the first quarter of 2014, partially offset by a weakening of the Canadian dollar relative to the U.S. dollar.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for the first quarter was 5.2 percent (2014 — 5.1 percent).

Foreign Exchange

	Three Months Ended March 31,
($ millions)	2015		2014
Unrealized Foreign Exchange (Gain) Loss	523		143
Realized Foreign Exchange (Gain) Loss	(8	)	4
	515		147

The majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt as a result of a weaker Canadian dollar at March 31, 2015. The Canadian dollar weakened by nine percent relative to the U.S. dollar from December 31, 2014 to March 31, 2015.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in the first quarter of 2015 was $21 million (2014 — $20 million).

Income Tax

	Three Months Ended March 31,
($ millions)	2015		2014
Current Tax
Canada	(86	)	43
United States	—		32
Total Current Tax	(86	)	75
Deferred Tax	(27	)	36
	(113	)	111
Effective Tax Rate	14	%	31	%

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for taxes is adequate. There are usually a number of tax matters under review and as a result income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

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In the first quarter of 2015, current income tax decreased $161 million due to a decrease in Canadian and U.S. Operating Cash Flow. Deferred income tax declined $63 million due to decreased Canadian and U.S. income and unrealized risk management losses compared with a gain in 2014.

Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before income taxes. The effective tax rate differs from the statutory tax rate as it reflects higher U.S. tax rates, permanent differences, adjustments for changes in tax rates and other tax legislation, variations in the estimate of reserves and differences between the provision and the actual amounts subsequently reported on the tax returns.

The decrease in our effective tax rate when compared with the first quarter of 2014 is primarily due to an increase in non-deductible foreign exchange losses which reduced the income tax recovery.

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended March 31,
($ millions)	2015		2014
Net Cash From (Used In)
Operating Activities	275		457
Investing Activities	(643	)	(2,397	)
Net Cash Provided (Used) Before Financing Activities	(368	)	(1,940	)
Financing Activities	1,292		246
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	(3	)	57
Increase (Decrease) in Cash and Cash Equivalents	921		(1,637	)

	March 31, 2015	December 31, 2014
Cash and Cash Equivalents	1,804	883

Operating Activities

Cash from operating activities was $182 million lower in the first quarter of 2015 mainly due to lower Cash Flow as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, working capital was $2,026 million at March 31, 2015 compared with $772 million at December 31, 2014. The change in working capital was primarily due to the proceeds received from the common share issuance. We anticipate that we will continue to meet our payment obligations as they come due.

Investing Activities

In the first quarter of 2015, cash used in investing activities was $643 million, a $1,754 million decrease from 2014, primarily due to the repayment of the US$1.4 billion Partnership Contribution Payable in March 2014.

Financing Activities

Cash provided by financing activities increased $1,046 million, primarily due to net proceeds from our common share issuance, partially offset by the net repayment of short-term borrowings. In the first quarter of 2015, we had a net repayment of short-term borrowings compared to a net issuance in 2014. In the quarter we issued 67.5 million common shares at a price of $22.25 per share for net proceeds of $1.4 billion. We plan to use the net proceeds to partially fund our capital expenditure program for 2015 and for general corporate purposes.

In the first quarter, we paid dividends of $0.2662 per share or $222 million (2014 — $0.2662 per share or $202 million), of which $138 million was paid in cash with the remainder reinvested in common shares issued from treasury through our DRIP (2014 — $202 million paid in cash). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Our long-term debt at March 31, 2015 was $5,973 million (December 31, 2014 — $5,458) with no principal payments due until October 2019 (US$1.3 billion). The principal amount of long-term debt outstanding in U.S. dollars has remained unchanged since August 2012. The $515 million increase in long-term debt is due to foreign exchange.

As at March 31, 2015, we were in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

We expect cash flow from our crude oil, natural gas and refining operations to fund a portion of our cash requirements over the next decade. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity, management of our asset portfolio and other corporate and financial opportunities that may be available to us.

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The following sources of liquidity are available at March 31, 2015:

($ millions)	Amount		Term
Cash and Cash Equivalents	1,804		Not applicable
Committed Credit Facility	3,000		November 2018
U.S. Base Shelf Prospectus (1)	US$	2,000	July 2016
Canadian Base Shelf Prospectus (1)	1,500		July 2016

(1)Availability is subject to market conditions.

Committed Credit Facility

We have a $3.0 billion committed credit facility. As of March 31, 2015, no amounts were drawn on our committed credit facility.

We have a commercial paper program which, together with our committed credit facility, is used to manage our short-term cash requirements. We reserve undrawn capacity under our committed credit facility for amounts of outstanding commercial paper. As of March 31, 2015, there was no commercial paper outstanding.

U.S. and Canadian Base Shelf Prospectuses

As at March 31, 2015, no notes were issued under our U.S. or Canadian base shelf prospectuses.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. We define our non-GAAP measure of Debt as short-term borrowings and the current and long-term portions of long-term debt. We define Capitalization as Debt plus Shareholders’ Equity. We define Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, DD&A, goodwill and asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve month basis. These metrics are used to steward our overall debt position and as measures of our overall financial strength.

	March 31,		December 31,
As at	2015		2014
Debt to Capitalization	35	%	35	%
Net Debt to Capitalization (1)	27	%	31	%
Debt to Adjusted EBITDA (times)	1.9	x	1.4	x
Net Debt to Adjusted EBITDA (times) (1)	1.3	x	1.2	x

(1)Net Debt is defined as Debt net of cash and cash equivalents.

We continue to have long-term targets for 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. At March 31, 2015, our Debt to Capitalization and Debt to Adjusted EBITDA metrics are within our target ranges.

Debt to Capitalization remained consistent as higher debt balances, due to changes in foreign exchange consistent with the weakening of the Canadian dollar relative to the U.S. dollar, were offset by the increase in Shareholders’ Equity as a result of the common share issuance. The increase in Debt to Adjusted EBITDA was due to higher debt balances as a result of foreign exchange and lower Adjusted EBITDA primarily due to a decline in Operating Cash Flow as a result of low commodity prices.

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As at March 31, 2015, we held $1.8 billion in cash and cash equivalents. Net Debt to Capitalization and Net Debt to Adjusted EBIDTA were 27 percent and 1.3 times, respectively (December 31, 2014 — 31 percent and 1.2 times, respectively).

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

Outstanding Share Data and Stock-Based Compensation Plans

Cenovus is authorized to issue an unlimited number of common shares and, subject to certain conditions, an unlimited number of first preferred shares and an unlimited number of second preferred shares. At March 31, 2015, no preferred shares were outstanding. Cenovus issued 71.4 million common shares in the first quarter of 2015, including 67.5 million shares related to the common share issuance and 3.9 million shares issued under the DRIP.

The DRIP permits shareholders to reinvest their dividends into additional common shares. At the discretion of Cenovus, the additional common shares may be issued from treasury or purchased on the market. On February 12, 2015, we announced that the common shares issued to participants under our DRIP will be issued from treasury at a three percent discount to the average market price, as defined in the DRIP. Refer to cenovus.com for more details. For the first quarter dividend, the participation rate in the DRIP was approximately 37 percent and resulted in $81 million of cash savings.

As part of our long-term incentive program, Cenovus has an employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of Cenovus. In addition to our Stock Option Plan, Cenovus has a Performance Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit Plans.

PSUs and RSUs are whole share units which entitle the holder to receive upon vesting either a Cenovus common share or a cash payment equal to the value of a Cenovus common share. Refer to Note 27 of the Consolidated Financial Statements and Note 16 of our interim Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.

As at March 31, 2015	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	828,533	N/A
Stock Options	48,015	27,206
Other Stock-Based Compensation Plans	8,443	1,376

Contractual Obligations and Commitments

We have entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, we have commitments related to our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. For further information, see the notes to the Consolidated Financial Statements.

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations and we believe we have made adequate provisions for such claims. There are no individually or collectively significant claims.

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RISK MANAGEMENT

For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with the Risk Management section of our 2014 annual MD&A and AIF.

Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. Actively managing these risks improves our ability to effectively execute our business strategy. Our exposure to the risks identified in our 2014 annual MD&A has not changed substantially since December 31, 2014. In addition, no new material risks have been identified.

A description of the risk factors and uncertainties affecting Cenovus can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2014. The following provides an update on our commodity price risk management.

Commodity Price Risk

Fluctuations in commodity prices create volatility in our financial performance. Commodity prices are impacted by a number of factors including global and regional supply and demand, transportation constraints, weather conditions and availability of alternative fuels, all of which are beyond our control and can result in a high degree of price volatility.

We manage our commodity price exposure through a combination of activities including business integration, financial hedges and physical contracts. For further details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Note 19 to the interim Consolidated Financial Statements. The financial impact is summarized below:

Impact of Financial Risk Management Activities

	Three Months Ended March 31,
	2015						2014
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	(128	)	119		(9	)	34		(26	)	8
Natural Gas	(12	)	11		(1	)	—		1		1
Refining	(14	)	9		(5	)	(4	)	(1	)	(5	)
Power	3		6		9		—		—		—
(Gain) Loss on Risk Management	(151	)	145		(6	)	30		(26	)	4
Income Tax Expense (Recovery)	40		(37	)	3		(7	)	7		—
(Gain) Loss on Risk Management, After Tax	(111	)	108		(3	)	23		(19	)	4

In the first quarter of 2015, management of commodity price risk resulted in realized gains on crude oil and natural gas financial instruments, consistent with our contract prices exceeding the average benchmark price. We recorded unrealized losses on our crude oil and natural gas financial instruments primarily due to the realization of settled positions.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES

For more details regarding our critical accounting judgments, estimates and accounting policies the following should be read in conjunction with our 2014 annual MD&A.

Management is required to make judgments, estimates and assumptions in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from those estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014.

Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. There have been no changes to our critical judgments used in applying accounting policies in the first quarter of 2015. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014.

Cenovus Energy Inc. First Quarter 2015 Report Management’s Discussion and Analysis

41

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. There have been no changes to our key sources of estimation uncertainty in the first quarter of 2015. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014.

Changes in Accounting Policies

There were no new or amended accounting standards or interpretations adopted during the three months ended March 31, 2015.

Future Accounting Pronouncements

There were no new or amended accounting standards or interpretations issued during the three months ended March 31, 2015 that are applicable to Cenovus in future periods. A description of standards and interpretations that will be adopted by Cenovus in future periods can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2014.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) in the three months ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, ICFR.

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

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner and to integrating our corporate responsibility principles into the way we conduct our business. We recognize the importance of reporting to stakeholders in a transparent and accountable manner. We disclose not only the information we are required to disclose by legislation or regulatory authorities, but also information that more broadly describes our activities, policies, opportunities and risks.

Our Corporate Responsibility (“CR”) policy continues to drive our commitments, our CR approach and reporting, and 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. Our CR policy and CR report are available on our website at cenovus.com.

In February 2015, Cenovus was named the top Canadian company for Best Sustainability Practice at the Investor Relations Magazine Awards for the third consecutive year. In January 2015, Cenovus was included in the RobecoSAM Sustainability Yearbook for the second time in a row. RobecoSAM is a Swiss-based specialist in international sustainability investment that publishes the Dow Jones Sustainability Index (“DJSI”). Cenovus continues to be named to the DJSI family of indices and is currently listed on the DJSI World and DJSI North American Index.

These external recognitions of our commitment to corporate responsibility reaffirm Cenovus’s efforts to balance economic, governance, social and environmental performance.

Cenovus Energy Inc. First Quarter 2015 Report Management’s Discussion and Analysis

42

OUTLOOK

We expect 2015 to be a challenging time for our industry. Since December 2014, crude oil prices have remained significantly lower than prices in the first half of 2014 and we anticipate prices will remain relatively low throughout 2015. We revised our 2015 budget in January, reducing our capital spending plans and introducing other initiatives intended to conserve cash and maintain the strength of our balance sheet. We have strong producing assets, an integrated portfolio, a solid balance sheet and flexible capital plans, which should allow us to face the challenges in 2015. We continue to pursue our long-term strategy, though at a pace we believe is more in line with the current commodity price environment.

The following outlook commentary is focused on the next twelve months.

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

·We expect the general outlook for crude oil prices will be tied primarily to the non-OPEC supply response to the current price environment, the pace of growth of the global economy and the availability of storage for crude oil and refined products. Overall, we expect Brent crude oil prices to improve as the year progresses. However, there is some risk prices may fall in the second quarter due to seasonally weak demand in the spring and continued high levels of supply from OPEC. Going forward, a reduction in global supply growth, combined with annual increases in demand growth and seasonal improvements should slightly improve prices for the last half of the year. We continue to anticipate slower supply growth from North American producers as a result of the significant reductions in capital spending. The current low crude oil price environment also serves to help boost global economic momentum which, with the exception of the U.S., has been faced with mounting deflationary concerns and struggling emerging markets. Expectations have faded that OPEC may reduce production and provide some support to prices as OPEC has repeatedly placed the responsibility of supply correction on non-OPEC producers;

·We expect the Brent-WTI differential to be volatile as the uncertain pace of U.S. supply growth and its ability to displace imports will dictate price direction. In addition, the seasonality of crude oil demand, refinery turnarounds and high levels of U.S. crude oil in storage add to the volatility; and

·We expect the WTI-WCS differential to be volatile given Canadian supply growth and uncertainty around the timing of new rail infrastructure and incremental pipeline capacity.

Average market crack spreads improved late in the first quarter of 2015 as a result of a number of unplanned refinery outages. For the next twelve months, we expect average market crack spreads to decline slightly as refinery utilization improves.

Natural gas prices are expected to remain weak throughout 2015. The inventory of drilled but uncompleted wells should keep supply growth strong even with a decline in industry activity. Coal-to-gas substitution in the power sector will be required to correct anticipated high storage levels before the winter season.

The average foreign exchange forward price over the next four quarters is US$0.787/C$. The Bank of Canada rate cut in the first quarter has acted to further decrease the Canadian dollar against the U.S. dollar. Timing of key interest rate decisions, both in Canada and the U.S., and U.S. economic momentum will dictate future foreign exchange fluctuations. Overall, we expect the Canadian dollar to remain relatively weak which will have a positive impact on our revenues and Operating Cash Flow.

(1)Refer to the foreign exchange rate sensitivities found within our current guidance available at cenovus.com.

Cenovus Energy Inc. First Quarter 2015 Report Management’s Discussion and Analysis

43

Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as Canadian congestion. While we expect to see volatility in crude oil prices, we mitigate our exposure to light/heavy price differentials through the following:

·Integration — having heavy oil refining capacity able to process Canadian heavy oil. From a value perspective, our refining business is able to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products;

·Financial hedge transactions — protecting our upstream crude oil prices from downside risk by entering into financial transactions that fix the WTI-WCS differential;

·Marketing arrangements — protecting our upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and

·Transportation commitments and arrangements — supporting transportation projects that move crude oil from our production areas to consuming markets and also to tidewater markets.

(1)Expected gross production capacity.

Key Priorities for 2015

Maintain Financial Resilience

We have strong producing assets, an integrated portfolio and a solid balance sheet which should position us well to face the challenges of 2015. Our capital planning process is flexible. Spending can be further reduced in response to declines in commodity prices and other economic factors, so that we should be able to maintain our financial strength and resilience and advance our strategy without compromising our future plans. We will continue to assess our spending plans on a regular basis while closely monitoring crude oil prices in 2015.

Attack Cost Structures

We continue to challenge cost structures across the organization to maintain our track record of cost efficiency. We must ensure that, over the long term, we maintain an efficient and sustainable cost structure and maximize the strengths of our business model. We have identified opportunities to achieve between $400 million and $500 million in anticipated annual operating and capital cost reductions in the years ahead.

As a result of the slowdown across the energy sector, we expect to see reductions in demand for labour, service and materials. This should create opportunities for us to make improvements in our cost structure.

Enable Market Access

We continue to focus on near- and mid-term strategies to broaden market access for our crude oil production. This includes continued support for proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving 10 to 20 percent of our crude oil production to market by rail, assessing options to maximize the value of our oil by offering a wider range of products, including existing dilbit blends, under blended bitumen or dry bitumen, and potential expansions of our refining capacity as our production grows.

Other Key Challenges

We will need to effectively manage our business to support our development plans, including securing timely regulatory and partner approvals, complying with environmental regulations and managing competitive pressures within our industry. Additional details regarding the impact of these factors on our financial results are discussed in the Risk Management section of this MD&A.

Cenovus Energy Inc. First Quarter 2015 Report Management’s Discussion and Analysis

44

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the period ended March 31,

($ millions, except per share amounts)

		Three Months Ended
	Notes	2015			2014
Revenues	1
Gross Sales		3,165			5,115
Less: Royalties		24			103
		3,141			5,012
Expenses	1
Purchased Product		1,732			2,579
Transportation and Blending		528			653
Operating		476			572
Production and Mineral Taxes		5			7
(Gain) Loss on Risk Management	18	(6		)	4
Depreciation, Depletion and Amortization	10	499			454
General and Administrative		72			109
Finance Costs	4	121			130
Interest Income		(11		)	(2		)
Foreign Exchange (Gain) Loss, Net	5	515			147
Research Costs		7			2
(Gain) Loss on Divestiture of Assets	11	(16		)	—
Other (Income) Loss, Net		—			(1		)
Earnings (Loss) Before Income Tax		(781		)	358
Income Tax Expense (Recovery)	6	(113		)	111
Net Earnings (Loss)		(668		)	247
Other Comprehensive Income (Loss), Net of Tax	15
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits		(1		)	(8		)
Items That May be Reclassified to Profit or Loss:
Change in Value of Available for Sale Financial Assets		—			—
Foreign Currency Translation Adjustment		272			70
Total Other Comprehensive Income (Loss), Net of Tax		271			62
Comprehensive Income (Loss)		(397		)	309
Net Earnings (Loss) Per Common Share	7
Basic		$	(0.86	)	$	0.33
Diluted		$	(0.86	)	$	0.33

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2015 Report	Consolidated Financial Statements

45

CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		March 31,	December 31,
	Notes	2015	2014
Assets
Current Assets
Cash and Cash Equivalents		1,804	883
Accounts Receivable and Accrued Revenues		1,367	1,582
Income Tax Receivable		15	28
Inventories	8	1,250	1,224
Risk Management	18	340	478
Current Assets		4,776	4,195
Exploration and Evaluation Assets	1,9	1,706	1,625
Property, Plant and Equipment, Net	1,10	19,057	18,563
Risk Management	18	1	—
Other Assets		68	70
Goodwill	1	242	242
Total Assets		25,850	24,695
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		2,134	2,588
Income Tax Payable		276	357
Risk Management	18	16	12
Current Liabilities		2,426	2,957
Long-Term Debt	12	5,973	5,458
Risk Management	18	7	4
Decommissioning Liabilities	13	2,819	2,616
Other Liabilities		146	172
Deferred Income Taxes		3,350	3,302
Total Liabilities		14,721	14,509
Shareholders’ Equity		11,129	10,186
Total Liabilities and Shareholders’ Equity		25,850	24,695

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2015 Report	Consolidated Financial Statements

46

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

($ millions)

	ShareCapital	Paid inSurplus	RetainedEarnings		AOCI (1)	Total
	(Note 14)				(Note 15)
Balance as at December 31, 2013	3,857	4,219	1,660		210	9,946
Net Earnings	—	—	247		—	247
Other Comprehensive Income (Loss)	—	—	—		62	62
Total Comprehensive Income (Loss)	—	—	247		62	309
Common Shares Issued Under Stock Option Plans	24	—	—		—	24
Stock-Based Compensation Expense	—	22	—		—	22
Dividends on Common Shares	—	—	(202	)	—	(202	)
Balance as at March 31, 2014	3,881	4,241	1,705		272	10,099
Balance as at December 31, 2014	3,889	4,291	1,599		407	10,186
Net Earnings (Loss)	—	—	(668	)	—	(668	)
Other Comprehensive Income (Loss)	—	—	—		271	271
Total Comprehensive Income (Loss)	—	—	(668	)	271	(397	)
Common Shares Issued for Cash	1,463	—	—		—	1,463
Common Shares Issued Pursuant to Dividend Reinvestment Plan	84	—	—		—	84
Common Shares Issued Under Stock Option Plans	—	—	—		—	—
Stock-Based Compensation Expense	—	15	—		—	15
Dividends on Common Shares	—	—	(222	)	—	(222	)
Balance as at March 31, 2015	5,436	4,306	709		678	11,129

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2015 Report	Consolidated Financial Statements

47

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the period ended March 31,

($ millions)

		Three Months Ended
	Notes	2015		2014
Operating Activities
Net Earnings (Loss)		(668	)	247
Depreciation, Depletion and Amortization	10	499		454
Deferred Income Taxes	6	(27	)	36
Unrealized (Gain) Loss on Risk Management	18	145		(26	)
Unrealized Foreign Exchange (Gain) Loss	5	523		143
(Gain) Loss on Divestiture of Assets	11	(16	)	—
Unwinding of Discount on Decommissioning Liabilities	4,13	31		30
Other		8		20
		495		904
Net Change in Other Assets and Liabilities		(54	)	(42	)
Net Change in Non-Cash Working Capital		(166	)	(405	)
Cash From Operating Activities		275		457
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	9	(74	)	(104	)
Capital Expenditures — Property, Plant and Equipment	10	(455	)	(725	)
Proceeds From Divestiture of Assets	11	16		1
Net Change in Investments and Other		2		(1,579	)
Net Change in Non-Cash Working Capital		(132	)	10
Cash (Used in) Investing Activities		(643	)	(2,397	)
Net Cash Provided (Used) Before Financing Activities		(368	)	(1,940	)
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		(19	)	426
Common Shares Issued, Net of Issuance Costs	14	1,449		—
Common Shares Issued Under Stock Option Plans		—		22
Dividends Paid on Common Shares	7	(138	)	(202	)
Cash From (Used in) Financing Activities		1,292		246
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(3	)	57
Increase (Decrease) in Cash and Cash Equivalents		921		(1,637	)
Cash and Cash Equivalents, Beginning of Period		883		2,452
Cash and Cash Equivalents, End of Period		1,804		815

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2015 Report	Consolidated Financial Statements

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of the development, production and marketing of crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with refining operations in the United States (“U.S.”).

Cenovus is incorporated under the Canada Business Corporations Act and its shares are listed on the Toronto (“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 2600, 500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. Information on the Company’s basis of preparation for these interim Consolidated Financial Statements is found in Note 2.

Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision makers. The Company evaluates the financial performance of its operating segments primarily based on operating cash flow. The Company’s reportable segments are:

·Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. The Athabasca natural gas assets also form part of this segment. Certain of the Company’s operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are jointly owned with ConocoPhillips, an unrelated U.S. public company.

·Conventional, which includes the development and production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake. This segment also includes the carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

·Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer diversification.

·Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the 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 following tabular financial information presents the segmented information first by segment, then by product and geographic location.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

A) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the three months ended March 31,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	732		1,260	443		838	2,096		3,258
Less: Royalties	3		51	21		52	—		—
	729		1,209	422		786	2,096		3,258
Expenses
Purchased Product	—		—	—		—	1,838		2,820
Transportation and Blending	470		559	58		94	—		—
Operating	144		181	157		195	177		198
Production and Mineral Taxes	—		—	5		7	—		—
(Gain) Loss on Risk Management	(90	)	22	(47	)	13	(14	)	(5	)
Operating Cash Flow	205		447	249		477	95		245
Depreciation, Depletion and Amortization	170		143	262		252	46		39
Segment Income (Loss)	35		304	(13	)	225	49		206

	Corporate and Eliminations				Consolidated
For the three months ended March 31,	2015		2014		2015		2014
Revenues
Gross Sales	(106	)	(241	)	3,165		5,115
Less: Royalties	—		—		24		103
	(106	)	(241	)	3,141		5,012
Expenses
Purchased Product	(106	)	(241	)	1,732		2,579
Transportation and Blending	—		—		528		653
Operating	(2	)	(2	)	476		572
Production and Mineral Taxes	—		—		5		7
(Gain) Loss on Risk Management	145		(26	)	(6	)	4
	(143	)	28		406		1,197
Depreciation, Depletion and Amortization	21		20		499		454
Segment Income (Loss)	(164	)	8		(93	)	743
General and Administrative	72		109		72		109
Finance Costs	121		130		121		130
Interest Income	(11	)	(2	)	(11	)	(2	)
Foreign Exchange (Gain) Loss, Net	515		147		515		147
Research Costs	7		2		7		2
(Gain) Loss on Divestiture of Assets	(16	)	—		(16	)	—
Other (Income) Loss, Net	—		(1	)	—		(1	)
	688		385		688		385
Earnings (Loss) Before Income Tax					(781	)	358
Income Tax Expense (Recovery)					(113	)	111
Net Earnings (Loss)					(668	)	247

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the three months ended March 31,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	723		1,230	315		651	1,038		1,881
Less: Royalties	3		51	19		49	22		100
	720		1,179	296		602	1,016		1,781
Expenses
Transportation and Blending	470		559	53		89	523		648
Operating	139		170	109		145	248		315
Production and Mineral Taxes	—		—	5		8	5		8
(Gain) Loss on Risk Management	(89	)	22	(37	)	13	(126	)	35
Operating Cash Flow	200		428	166		347	366		775

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the three months ended March 31,	2015		2014	2015		2014		2015		2014
Revenues
Gross Sales	6		27	122		184		128		211
Less: Royalties	—		—	2		3		2		3
	6		27	120		181		126		208
Expenses
Transportation and Blending	—		—	5		5		5		5
Operating	4		4	47		49		51		53
Production and Mineral Taxes	—		—	—		(1	)	—		(1	)
(Gain) Loss on Risk Management	(1	)	—	(10	)	—		(11	)	—
Operating Cash Flow	3		23	78		128		81		151

	Other
	Oil Sands			Conventional		Total
For the three months ended March 31,	2015	2014		2015	2014	2015	2014
Revenues
Gross Sales	3	3		6	3	9	6
Less: Royalties	—	—		—	—	—	—
	3	3		6	3	9	6
Expenses
Transportation and Blending	—	—		—	—	—	—
Operating	1	7		1	1	2	8
Production and Mineral Taxes	—	—		—	—	—	—
(Gain) Loss on Risk Management	—	—		—	—	—	—
Operating Cash Flow	2	(4	)	5	2	7	(2	)

	Total Upstream
	Oil Sands			Conventional			Total
For the three months ended March 31,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	732		1,260	443		838	1,175		2,098
Less: Royalties	3		51	21		52	24		103
	729		1,209	422		786	1,151		1,995
Expenses
Transportation and Blending	470		559	58		94	528		653
Operating	144		181	157		195	301		376
Production and Mineral Taxes	—		—	5		7	5		7
(Gain) Loss on Risk Management	(90	)	22	(47	)	13	(137	)	35
Operating Cash Flow	205		447	249		477	454		924

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

C) Geographic Information

	Canada			United States				Consolidated
For the three months ended March 31,	2015		2014	2015		2014		2015		2014
Revenues
Gross Sales	1,625		2,815	1,540		2,300		3,165		5,115
Less: Royalties	24		103	—		—		24		103
	1,601		2,712	1,540		2,300		3,141		5,012
Expenses
Purchased Product	432		708	1,300		1,871		1,732		2,579
Transportation and Blending	528		653	—		—		528		653
Operating	306		382	170		190		476		572
Production and Mineral Taxes	5		7	—		—		5		7
(Gain) Loss on Risk Management	(1	)	9	(5	)	(5	)	(6	)	4
	331		953	75		244		406		1,197
Depreciation, Depletion and Amortization	453		415	46		39		499		454
Segment Income (Loss)	(122	)	538	29		205		(93	)	743

The Oil Sands and Conventional segments operate in Canada. Both of Cenovus’s refining facilities are located and carry on business in the U.S. The marketing of Cenovus’s crude oil and natural gas produced in Canada, as well as the third-party purchases and sales of product, is undertaken in Canada. Physical product sales that settle in the U.S. are considered to be export sales undertaken by a Canadian business. The Corporate and Eliminations segment is attributed to Canada, with the exception of the unrealized risk management gains and losses, which have been attributed to the country in which the transacting entity resides.

D) Joint Operations

A significant portion of the operating cash flows from the Oil Sands, and Refining and Marketing segments are derived through jointly controlled entities, FCCL Partnership (“FCCL”) and WRB Refining LP (“WRB”), respectively. These joint arrangements, in which Cenovus has a 50 percent ownership interest, are classified as joint operations and, as such, Cenovus recognizes its share of the assets, liabilities, revenues and expenses.

FCCL, which is involved in the development and production of crude oil in Canada, is jointly controlled with ConocoPhillips and operated by Cenovus. WRB has two refineries in the U.S. and focuses on the refining of crude oil into petroleum and chemical products. WRB is jointly controlled with and operated by Phillips 66. Cenovus’s share of operating cash flow from FCCL and WRB for the three months ended March 31, 2015 was $134 million and $87 million, respectively (three months ended March 31, 2014 – $418 million and $245 million).

E) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets

By Segment

	E&E (1)		PP&E (2)
	March 31,	December 31,	March 31,	December 31,
As at	2015	2014	2015	2014
Oil Sands	1,621	1,540	8,803	8,606
Conventional	85	85	6,020	6,038
Refining and Marketing	—	—	3,898	3,568
Corporate and Eliminations	—	—	336	351
Consolidated	1,706	1,625	19,057	18,563

	Goodwill		Total Assets
	March 31,	December 31,	March 31,	December 31,
As at	2015	2014	2015	2014
Oil Sands	242	242	11,200	11,024
Conventional	—	—	6,251	6,211
Refining and Marketing	—	—	5,725	5,520
Corporate and Eliminations	—	—	2,674	1,940
Consolidated	242	242	25,850	24,695

(1) Exploration and evaluation (“E&E”) assets.

(2) Property, plant and equipment (“PP&E”).

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

By Geographic Region

	E&E		PP&E
	March 31,	December 31,	March 31,	December 31,
As at	2015	2014	2015	2014
Canada	1,706	1,625	15,163	14,999
United States	—	—	3,894	3,564
Consolidated	1,706	1,625	19,057	18,563

	Goodwill		Total Assets
	March 31,	December 31,	March 31,	December 31,
As at	2015	2014	2015	2014
Canada	242	242	20,984	20,231
United States	—	—	4,866	4,464
Consolidated	242	242	25,850	24,695

F) Capital Expenditures (1)

	Three Months Ended
For the period ended March 31,	2015	2014
Capital
Oil Sands	414	527
Conventional	66	270
Refining and Marketing	44	23
Corporate	5	9
	529	829
Acquisition Capital
Conventional	—	1
	529	830

(1) Includes expenditures on PP&E and E&E.

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

In these interim Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars. All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.

These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting” (“IAS 34”), and have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2014, except for income taxes. Income taxes on earnings or loss in the interim periods are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss. The disclosures provided are incremental to those included with the annual Consolidated Financial Statements. Certain information and disclosures normally included in the notes to the annual 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 annual Consolidated Financial Statements for the year ended December 31, 2014, which have been prepared in accordance with IFRS as issued by the IASB.

These interim Consolidated Financial Statements of Cenovus were approved by the Audit Committee effective April 28, 2015.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

3. RECENT ACCOUNTING PRONOUNCEMENTS

A) New and Amended Accounting Standards and Interpretations Adopted

There were no new or amended accounting standards or interpretations adopted during the three months ended March 31, 2015.

B) New Accounting Standards and Interpretations not yet Adopted

There were no new or amended accounting standards or interpretations issued during the three months ended March 31, 2015 that are applicable to the Company in future periods. A description of accounting standards and interpretations that will be adopted by the Company in future periods can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2014.

4. FINANCE COSTS

	Three Months Ended
For the period ended March 31,	2015	2014
Interest Expense — Short-Term Borrowings and Long-Term Debt	80	71
Interest Expense — Partnership Contribution Payable (1)	—	22
Unwinding of Discount on Decommissioning Liabilities (Note 13)	31	30
Other	10	7
	121	130

(1) On March 28, 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.

5. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended
For the period ended March 31,	2015		2014
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	514		196
Other	9		(53	)
Unrealized Foreign Exchange (Gain) Loss	523		143
Realized Foreign Exchange (Gain) Loss	(8	)	4
	515		147

6. INCOME TAXES

The provision for income taxes is:

	Three Months Ended
For the period ended March 31,	2015		2014
Current Tax
Canada	(86	)	43
United States	—		32
Total Current Tax	(86	)	75
Deferred Tax	(27	)	36
	(113	)	111

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

7. PER SHARE AMOUNTS

A) Net Earnings Per Share

	Three Months Ended
For the period ended March 31,	2015			2014
Net Earnings (Loss) — Basic and Diluted ($ millions)	(668		)	247
Basic — Weighted Average Number of Shares (millions)	778.9			756.4
Dilutive Effect of Cenovus TSARs (1)	—			0.9
Dilutive Effect of Cenovus NSRs (2)	—			—
Diluted — Weighted Average Number of Shares	778.9			757.3
Net Earnings (Loss) Per Common Share ($)
Basic	$	(0.86	)	$	0.33
Diluted	$	(0.86	)	$	0.33

(1) Tandem stock appreciation rights (“TSARs”).

(2) Net settlement rights (“NSRs”).

B) Dividends Per Share

The Company paid dividends of $0.2662 per share or $222 million for the three months ended March 31, 2015 (March 31, 2014 — $202 million, $0.2662 per share), including cash dividends of $138 million (March 31, 2014 — $202 million). The Cenovus Board of Directors declared a second quarter dividend of $0.2662 per share, payable on June 30, 2015, to common shareholders of record as of June 15, 2015.

8. INVENTORIES

	March 31,	December 31,
As at	2015	2014
Product
Refining and Marketing	974	972
Oil Sands	208	182
Conventional	21	28
Parts and Supplies	47	42
	1,250	1,224

As a result of a decline in crude oil and certain refined product prices, Cenovus recorded a write-down of its product inventory of $6 million from cost to net realizable value as at March 31, 2015. As at December 31, 2014, Cenovus recorded a write-down of its product inventory of $131 million, of which $11 million has been subsequently reversed due to the improvement of certain product prices.

9. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2013	1,473
Additions	279
Transfers to PP&E (Note 10)	(53	)
Exploration Expense	(86	)
Divestitures	(2	)
Change in Decommissioning Liabilities	14
As at December 31, 2014	1,625
Additions	74
Transfers to PP&E (Note 10)	—
Change in Decommissioning Liabilities	7
As at March 31, 2015	1,706

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

E&E assets consist of the Company’s projects which are pending determination of technical feasibility and commercial viability. All of the Company’s E&E assets are located within Canada.

Additions to E&E assets for the three months ended March 31, 2015 include $9 million of internal costs directly related to the evaluation of these projects (year ended December 31, 2014 — $51 million). No borrowing costs or costs classified as general and administrative expenses have been capitalized during the three months ended March 31, 2015 (year ended December 31, 2014 — $nil).

For the three months ended March 31, 2015, no E&E assets were transferred to PP&E following the determination of technical feasibility and commercial viability of the projects (year ended December 31, 2014 — $53 million).

Impairment

The impairment of E&E assets and any subsequent reversal of such impairment losses are recorded in exploration expense in the Consolidated Statements of Earnings and Comprehensive Income. There was no impairment of E&E assets for the three months ended March 31, 2015 (year ended December 31, 2014 — $86 million).

10. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production		OtherUpstream	RefiningEquipment		Other (1)		Total
COST
As at December 31, 2013	29,390		286	3,654		849		34,179
Additions (2)	2,522		43	162		63		2,790
Transfers From E&E Assets (Note 9)	53		—	—		—		53
Transfers to Assets Held for Sale	(55	)	—	—		—		(55	)
Change in Decommissioning Liabilities	264		—	(3	)	—		261
Exchange Rate Movements and Other	1		—	338		—		339
Divestitures	(474	)	—	—		(2	)	(476	)
As at December 31, 2014	31,701		329	4,151		910		37,091
Additions	403		3	44		5		455
Transfers From E&E Assets (Note 9)	—		—	—		—		—
Change in Decommissioning Liabilities	204		—	—		—		204
Exchange Rate Movements and Other	—		—	388		1		389
As at March 31, 2015	32,308		332	4,583		916		38,139
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2013	15,791		193	386		475		16,845
Depreciation, Depletion and Amortization	1,602		40	156		83		1,881
Transfers to Assets Held for Sale	(27	)	—	—		—		(27	)
Impairment Losses	65		—	—		—		65
Exchange Rate Movements and Other	38		—	42		—		80
Divestitures	(316	)	—	—		—		(316	)
As at December 31, 2014	17,153		233	584		558		18,528
Depreciation, Depletion and Amortization	421		11	46		21		499
Exchange Rate Movements and Other	(1	)	—	56		—		55
As at March 31, 2015	17,573		244	686		579		19,082
CARRYING VALUE
As at December 31, 2013	13,599		93	3,268		374		17,334
As at December 31, 2014	14,548		96	3,567		352		18,563
As at March 31, 2015	14,735		88	3,897		337		19,057

(1) Includes office furniture, fixtures, leasehold improvements, information technology and aircraft.

(2) 2014 asset acquisition includes the assumption of a decommissioning liability of $10 million.

Additions to development and production assets include internal costs directly related to the development and construction of crude oil and natural gas properties of $44 million for the three months ended March 31, 2015 (year ended December 31, 2014 — $216 million). All of the Company’s development and production assets are located within Canada. No borrowing costs or costs classified as general and administrative expenses have been capitalized during the three months ended March 31, 2015 (year ended December 31, 2014 – $nil).

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

PP&E includes the following amounts in respect of assets under construction and are not subject to depreciation, depletion and amortization (“DD&A”):

	March 31,	December 31,
As at	2015	2014
Development and Production	500	478
Refining Equipment	190	159
	690	637

Impairment

The impairment of PP&E and any subsequent reversal of such impairment losses are recorded in DD&A in the Consolidated Statements of Earnings and Comprehensive Income. There was no impairment of PP&E for the three months ended March 31, 2015 (year ended December 31, 2014 — $65 million).

11. DIVESTITURES

In the first quarter of 2015, the Company divested an office building, recording a gain of $16 million.

12. LONG-TERM DEBT

		March 31,		December 31,
As at	US$ Principal	2015		2014
Revolving Term Debt (1)	—	—		—
U.S. Dollar Denominated Unsecured Notes	4,750	6,024		5,510
Total Debt Principal		6,024		5,510
Debt Discounts and Transaction Costs		(51	)	(52	)
		5,973		5,458

(1) Revolving term debt may include bankers’ acceptances, LIBOR loans, prime rate loans and U.S. base rate loans.

As at March 31, 2015, the Company is in compliance with all of the terms of its debt agreements.

13. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of upstream crude oil and natural gas assets and refining facilities. The aggregate carrying amount of the obligation is:

	March 31,		December 31,
As at	2015		2014
Decommissioning Liabilities, Beginning of Year	2,616		2,370
Liabilities Incurred	5		48
Liabilities Settled	(43	)	(93	)
Liabilities Divested	—		(60	)
Transfers and Reclassifications	—		(9	)
Change in Estimated Future Cash Flows	4		115
Change in Discount Rate	202		122
Unwinding of Discount on Decommissioning Liabilities	31		120
Foreign Currency Translation	4		3
Decommissioning Liabilities, End of Period	2,819		2,616

The undiscounted amount of estimated future cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 4.5 percent as at March 31, 2015 (December 31, 2014 – 4.9 percent).

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

14. SHARE CAPITAL

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares and, subject to certain conditions, an unlimited number of first preferred and second preferred shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding

	March 31, 2015		December 31, 2014
As at	Number of Common Shares(Thousands)	Amount	Number of Common Shares(Thousands)	Amount
Outstanding, Beginning of Year	757,103	3,889	756,046	3,857
Common Shares Issued, Net of Issuance Costs	67,500	1,463	—	—
Common Shares Issued Pursuant to Dividend Reinvestment Plan	3,930	84	—	—
Common Shares Issued Under Stock Option Plans	—	—	1,057	32
Outstanding, End of Period	828,533	5,436	757,103	3,889

On March 3, 2015, Cenovus issued 67.5 million common shares at a price of $22.25 per common share. The Company intends to use the net proceeds to partially fund its capital expenditure program for 2015 and for general corporate purposes.

The Company has 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 of the Company or purchased on the market. On March 31, 2015, the Company issued 3.9 million common shares from treasury under the DRIP.

There were no preferred shares outstanding as at March 31, 2015 (December 31, 2014 — nil).

As at March 31, 2015, there were nine million (December 31, 2014 — 13 million) common shares available for future issuance under stock option plans.

15. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at March 31, 2015	Defined Benefit Plan		Foreign Currency Translation	Availablefor Sale Investments	Total
Balance, Beginning of Year	(30	)	427	10	407
Other Comprehensive Income (Loss), Before Tax	(1	)	272	—	271
Income Tax	—		—	—	—
Balance, End of Period	(31	)	699	10	678

As at March 31, 2014	DefinedBenefit Plan		Foreign Currency Translation	Availablefor Sale Investments	Total
Balance, Beginning of Year	(12	)	212	10	210
Other Comprehensive Income (Loss), Before Tax	(11	)	70	—	59
Income Tax	3		—	—	3
Balance, End of Period	(20	)	282	10	272

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

16. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Option Plan

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Options issued under the plan have associated TSARs or NSRs.

The following table is a summary of the options outstanding at the end of the period:

As at March 31, 2015	Issued	Term(Years)	Weighted  Average  Remaining  Contractual  Life (Years)	Weighted  Average  Exercise  Price ($)	Closing Share  Price ($)	Number ofUnitsOutstanding (Thousands)
NSRs	On or After February 24, 2011	7	5.07	31.68	21.35	44,227
TSARs	On or After February 17, 2010	7	1.95	26.74	21.35	3,788

NSRs

The weighted average unit fair value of NSRs granted during the three months ended March 31, 2015 was $3.58 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model.

The following table summarizes information related to the NSRs:

As at March 31, 2015	Number of NSRs (Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	40,549		32.63
Granted	4,063		22.27
Exercised	—		—
Forfeited	(385	)	32.20
Outstanding, End of Period	44,227		31.68
Exercisable, End of Period	23,418		34.60

TSARs

The Company has recorded a liability of $4 million as at March 31, 2015 (December 31, 2014 — $8 million) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. The intrinsic value of vested TSARs held by Cenovus employees as at March 31, 2015 was $nil (December 31, 2014 — $nil).

The following table summarizes information related to the TSARs held by Cenovus employees:

As at March 31, 2015	Number of TSARs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	3,862		26.72
Exercised for Cash Payment	—		—
Exercised as Options for Common Shares	—		—
Forfeited	(5	)	26.63
Expired	(69	)	25.69
Outstanding, End of Period	3,788		26.74
Exercisable, End of Period	3,788		26.74

B) Performance Share Units

The Company has recorded a liability of $56 million as at March 31, 2015 (December 31, 2014 — $109 million) in the Consolidated Balance Sheets for performance share units (“PSUs”) based on the market value of Cenovus’s common shares as at March 31, 2015. The intrinsic value of vested PSUs was $nil as at March 31, 2015 and December 31, 2014 as PSUs are paid out upon vesting.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

The following table summarizes the information related to the PSUs held by Cenovus employees:

As at March 31, 2015	Number of PSUs(Thousands)
Outstanding, Beginning of Year	7,099
Granted	—
Vested and Paid Out	(1,436	)
Cancelled	(1,077	)
Units in Lieu of Dividends	57
Outstanding, End of Period	4,643

C) Restricted Share Units

Cenovus has granted restricted share units (“RSUs”) to certain employees under its Restricted Share Unit Plan for Employees. RSUs 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. RSUs vest after three years.

RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as compensation costs over the vesting period. Fluctuations in the fair value are recognized as compensation costs in the period they occur.

The Company has recorded a liability of $4 million as at March 31, 2015 (December 31, 2014 — $1 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares as at March 31, 2015. The intrinsic value of vested RSUs was $nil as at March 31, 2015 and December 31, 2014 as RSUs are paid out upon vesting.

The following table summarizes the information related to the RSUs held by Cenovus employees:

As at March 31, 2015	Number of RSUs(Thousands)
Outstanding, Beginning of Year	93
Granted	2,323
Vested and Paid Out	(22	)
Cancelled	—
Units in Lieu of Dividends	30
Outstanding, End of Period	2,424

D) Deferred Share Units

The Company has recorded a liability of $29 million as at March 31, 2015 (December 31, 2014 — $31 million) in the Consolidated Balance Sheets for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares as at March 31, 2015. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:

As at March 31, 2015	Number of DSUs(Thousands)
Outstanding, Beginning of Year	1,297
Granted to Directors	54
Granted From Annual Bonus Awards	10
Units in Lieu of Dividends	17
Redeemed	(2	)
Outstanding, End of Period	1,376

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

E) Total Stock-Based Compensation Expense (Recovery)

The following table summarizes the stock-based compensation expense (recovery) recorded for all plans within operating, and general and administrative expenses in the Consolidated Statements of Earnings and Comprehensive Income:

	Three Months Ended
For the period ended March 31,	2015		2014
NSRs	11		13
TSARs	(3	)	—
PSUs	(16	)	32
RSUs	3		—
DSUs	(2	)	4
Stock-Based Compensation Expense (Recovery)	(7	)	49

17. CAPITAL STRUCTURE

Cenovus’s capital structure objectives and targets have remained unchanged from previous periods. Cenovus’s capital structure consists of Shareholders’ Equity plus Debt. Debt is defined as short-term borrowings and the current and long-term portions of 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 financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Cenovus continues to target a Debt to Capitalization ratio of between 30 and 40 percent over the long-term.

	March 31,		December 31,
As at	2015		2014
Long-Term Debt	5,973		5,458
Shareholders’ Equity	11,129		10,186
Capitalization	17,102		15,644
Debt to Capitalization	35	%	35	%

Cenovus continues to target a Debt to Adjusted EBITDA ratio of between 1.0 and 2.0 times over the long-term.

	March 31,		December 31,
As at	2015		2014
Debt	5,973		5,458
Net Earnings (Loss)	(171	)	744
Add (Deduct):
Finance Costs	436		445
Interest Income	(42	)	(33	)
Income Tax Expense	277		451
Depreciation, Depletion and Amortization	1,991		1,946
Goodwill Impairment	497		497
E&E Impairment	86		86
Unrealized (Gain) Loss on Risk Management	(425	)	(596	)
Foreign Exchange (Gain) Loss, Net	779		411
(Gain) Loss on Divestitures of Assets	(172	)	(156	)
Other (Income) Loss, Net	(3	)	(4	)
Adjusted EBITDA (1)	3,203		3,791
Debt to Adjusted EBITDA	1.9x		1.4x

(1) Calculated on a trailing twelve-month basis.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

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 its 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 facilities or repay existing debt. It is Cenovus’s intention to maintain investment grade credit ratings.

As at March 31, 2015, Cenovus had $3.0 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.

As at March 31, 2015, Cenovus is in compliance with all of the terms of its debt agreements.

18. FINANCIAL INSTRUMENTS

Cenovus’s consolidated financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, long-term receivables, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of those instruments.

The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at March 31, 2015, the carrying value of Cenovus’s long-term debt was $5,973 million and the fair value was $6,445 million (December 31, 2014 carrying value — $5,458 million, fair value — $5,726 million).

Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. When fair value cannot be reliably measured, these assets are carried at cost. The following table provides a reconciliation of changes in the fair value of available for sale financial assets:

	March 31,	December 31,
As at	2015	2014
Fair Value, Beginning of Year	32	32
Acquisition of Investments	—	4
Reclassification of Equity Investments	—	(4	)
Change in Fair Value (1)	—	—
Fair Value, End of Period	32	32

(1) Unrealized gains and losses on available for sale financial assets are recorded in other comprehensive income.

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, natural gas and power purchase contracts. Crude oil and natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of power purchase contracts are calculated internally based on observable and unobservable inputs such as forward power prices in less active markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness. The forward prices used in the determination of the fair value of the power purchase contracts as at March 31, 2015 range from $31.50 to $44.25 per Megawatt Hour.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

Summary of Unrealized Risk Management Positions

	March 31, 2015				December 31, 2014
	Risk Management				Risk Management
As at	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Crude Oil	297	8	289		423	7	416
Natural Gas	44	—	44		55	—	55
Power	—	15	(15	)	—	9	(9	)
Total Fair Value	341	23	318		478	16	462

The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:

	March 31,		December 31,
As at	2015		2014
Prices Sourced From Observable Data or Market Corroboration (Level 2)	333		471
Prices Determined From Unobservable Inputs (Level 3)	(15	)	(9	)
	318		462

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. Prices determined from unobservable inputs refers to the fair value of contracts valued using data that is both unobservable and significant to the overall fair value measurement.

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities from January 1 to March 31:

	2015		2014
Fair Value of Contracts, Beginning of Year	462		(129	)
Fair Value of Contracts Realized During the Period (1)	(151	)	30
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Period (2)	6		(4	)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	1		(2	)
Fair Value of Contracts, End of Period	318		(105	)

(1) Includes a realized loss of $3 million related to the power contracts (2014 — $nil).

(2) Includes a decrease of $9 million related to the power contracts (2014 — $nil).

C) Earnings Impact of (Gains) Losses From Risk Management Positions

	Three Months Ended
For the period ended March 31,	2015		2014
Realized (Gain) Loss (1)	(151	)	30
Unrealized (Gain) Loss (2)	145		(26	)
(Gain) Loss on Risk Management	(6	)	4

(1) Realized gains and losses on risk management are recorded in the operating segment to which the derivative instrument relates.

(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.

19. RISK MANAGEMENT

The Company is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. A description of the nature and extent of risks arising from the Company’s financial assets and liabilities can be found in the notes to the annual Consolidated Financial Statements as at December 31, 2014. The Company’s exposure to these risks has not changed significantly since December 31, 2014.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

Net Fair Value of Commodity Price Positions

As at March 31, 2015	Notional Volumes	Term	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	1,000 bbls/d	January — June 2015	$100.25/bbl	3
Brent Fixed Price	18,000 bbls/d	January — December 2015	$113.75/bbl	192
Brent Fixed Price	6,000 bbls/d	January — June 2015	US$65.03/bbl	6
Brent Fixed Price	45,000 bbls/d	March — June 2015	US$56.45/bbl	(1	)
Brent Fixed Price	18,000 bbls/d	July — September 2015	US$60.03/bbl	2
Brent Fixed Price	1,000 bbls/d	October — December 2015	US$64.00/bbl	—
Brent Fixed Price	4,000 bbls/d	January — December 2016	US$65.75/bbl	2
WCS Differential (1)	4,900 bbls/d	January — June 2015	US$(19.85)/bbl	(4	)
Brent Collars	10,000 bbls/d	January — December 2015	$105.25 — $123.57/bbl	85
Other Financial Positions (2)				4
Crude Oil Fair Value Position				289
Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price	149 MMcf/d	January — December 2015	$3.86/Mcf	44
Natural Gas Fair Value Position				44
Power Purchase Contracts
Power Fair Value Position				(15	)

(1) Cenovus entered into fixed price swaps to protect against widening light/heavy price differentials for heavy crudes.

(2) Other financial positions are part of ongoing operations to market the Company’s production.

Commodity Price Sensitivities — Risk Management Positions

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. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

Risk Management Positions in Place as at March 31, 2015

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent, WTI and Condensate Hedges	(215	)	217
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges Tied to Production	2		(2	)
Natural Gas Commodity Price	± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges	(58	)	58
Power Commodity Price	± $25 per MWHr Applied to Power Hedge	19		(19	)

20. COMMITMENTS AND CONTINGENCIES

A) Commitments

Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, the Company has commitments related to its risk management program and an obligation to fund its defined benefit pension and other post-employment benefit plans. Additional information related to the Company’s commitments can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2014. The Company did not enter into any new material contracts for the three months ended March 31, 2015.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2015

B) Legal Proceedings

Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes it has made adequate provisions for such legal claims. There are no individually or collectively significant claims.

Cenovus Energy Inc.
First Quarter 2015 Report	Notes to Consolidated Financial Statements

65

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

	2015		2014
Revenues	Q1		Year		Q4		Q3		Q2		Q1
Gross Sales
Upstream	1,175		8,261		1,721		2,147		2,295		2,098
Refining and Marketing	2,096		12,658		2,773		3,144		3,483		3,258
Corporate and Eliminations	(106	)	(812	)	(156	)	(197	)	(218	)	(241	)
Less: Royalties	24		465		100		124		138		103
Revenues	3,141		19,642		4,238		4,970		5,422		5,012

	2015	2014
Operating Cash Flow	Q1	Year	Q4		Q3	Q2	Q1
Crude Oil and Natural Gas Liquids
Foster Creek	84	965	228		297	227	213
Christina Lake	116	1,051	237		308	291	215
Conventional	166	1,360	273		352	388	347
Natural Gas	81	553	111		129	162	151
Other Upstream Operations	7	18	12		—	8	(2	)
	454	3,947	861		1,086	1,076	924
Refining and Marketing	95	211	(322	)	68	220	245
Operating Cash Flow (1)	549	4,158	539		1,154	1,296	1,169

	2015		2014
Cash Flow	Q1		Year		Q4		Q3		Q2		Q1
Cash from Operating Activities	275		3,526		868		1,092		1,109		457
Deduct (Add Back):
Net Change in Other Assets and Liabilities	(54	)	(135	)	(38	)	(28	)	(27	)	(42	)
Net Change in Non-Cash Working Capital	(166	)	182		505		135		(53	)	(405	)
Cash Flow (2)	495		3,479		401		985		1,189		904
Per Share - Basic	0.64		4.60		0.53		1.30		1.57		1.20
- Diluted	0.64		4.59		0.53		1.30		1.57		1.19

	2015		2014
Earnings	Q1		Year	Q4		Q3	Q2	Q1
Operating Earnings (Loss) (3)	(88	)	633	(590	)	372	473	378
Per Share - Diluted	(0.11	)	0.84	(0.78	)	0.49	0.62	0.50
Net Earnings (Loss)	(668	)	744	(472	)	354	615	247
Per Share - Basic	(0.86	)	0.98	(0.62	)	0.47	0.81	0.33
- Diluted	(0.86	)	0.98	(0.62	)	0.47	0.81	0.33

	2015		2014
Tax & Exchange Rates	Q1		Year		Q4	Q3	Q2	Q1
Effective Tax Rates Using:
Net Earnings	14.5	%	37.7	%
Operating Earnings, Excluding Divestitures	36.2	%	29.7	%
Canadian Statutory Rate	25.2	%	25.2	%
U.S. Statutory Rate	38.1	%	38.1	%
Foreign Exchange Rates (US$ per C$1)
Average	0.806		0.905		0.881	0.918	0.917	0.906
Period End	0.789		0.862		0.862	0.892	0.937	0.905

(1)Operating Cash Flow is a non-GAAP measure defined as revenues less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Cash Flow.

(2)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.

(3)Operating Earnings is a non-GAAP measure that is used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings is defined as earnings before income tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings.

	2015		2014
Financial Metrics (Non-GAAP measures)	Q1		Year		Q4		Q3		Q2		Q1
Debt to Capitalization (1) (2)	35	%	35	%	35	%	33	%	33	%	36	%
Net Debt to Capitalization (1) (3)	27	%	31	%	31	%	28	%	30	%	32	%
Debt to Adjusted EBITDA (2) (4)	1.9x		1.4x		1.4x		1.3x		1.2x		1.4x
Net Debt to Adjusted EBITDA (3) (4)	1.3x		1.2x		1.2x		1.0x		1.1x		1.2x
Return on Capital Employed (5)	0	%	6	%	6	%	9	%	9	%	7	%
Return on Common Equity (6)	-2	%	7	%	7	%	11	%	12	%	7	%

(1)Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity.

(2)Debt includes the Company’s short-term borrowings and the current and long-term portions of long-term debt.

(3)Net debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents.

(4)We define Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-month basis.

(5)Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders’ equity plus average debt.

(6)Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders’ equity.

Cenovus Energy Inc.
First Quarter 2015 Report	Supplemental Information

66

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

	2015	2014
Common Share Information	Q1	Year	Q4	Q3	Q2	Q1
Common Shares Outstanding (millions)
Period End	828.5	757.1	757.1	757.1	757.0	756.9
Average - Basic	778.9	756.9	757.1	757.1	756.9	756.4
Average - Diluted	778.9	757.6	757.1	758.8	758.0	757.3
Price Range ($ per share)
TSX - C$
High	26.42	34.79	30.13	34.79	34.70	32.02
Low	20.45	18.72	18.72	29.77	30.80	28.25
Close	21.35	23.97	23.97	30.13	34.59	31.97
NYSE - US$
High	21.12	32.64	26.89	32.64	32.44	28.96
Low	16.29	16.11	16.11	26.57	28.35	25.52
Close	16.88	20.62	20.62	26.88	32.37	28.96
Dividends ($ per share)	0.2662	1.0648	0.2662	0.2662	0.2662	0.2662
Share Volume Traded (millions)	442.1	803.8	333.1	147.7	152.7	170.3

	2015		2014
Net Capital Investment	Q1		Year		Q4		Q3		Q2		Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	149		796		159		207		209		221
Christina Lake	207		794		231		198		183		182
Total	356		1,590		390		405		392		403
Other Oil Sands	58		396		104		89		79		124
	414		1,986		494		494		471		527
Conventional	66		840		219		198		153		270
Refining and Marketing	44		163		52		42		46		23
Corporate	5		62		21		16		16		9
Capital Investment	529		3,051		786		750		686		829
Acquisitions (1)	—		18		1		—		16		1
Divestitures	(16	)	(277	)	(1	)	(235	)	(39	)	(2	)
Net Acquisition and Divestiture Activity	(16	)	(259	)	—		(235	)	(23	)	(1	)
Net Capital Investment	513		2,792		786		515		663		828

(1)Q2 2014 asset acquisition includes the assumption of a decommissioning liability of $10 million.

Operating Statistics - Before Royalties

	2015	2014
Upstream Production Volumes	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands
Foster Creek	67,901	59,172	68,377	56,631	56,852	54,706
Christina Lake	76,471	69,023	73,836	68,458	67,975	65,738
	144,372	128,195	142,213	125,089	124,827	120,444
Conventional
Heavy Oil	37,155	39,546	38,021	39,096	40,304	40,799
Light and Medium Oil	35,135	34,531	34,661	33,548	35,329	34,598
Natural Gas Liquids (1)	1,358	1,221	1,282	1,356	1,228	1,013
	73,648	75,298	73,964	74,000	76,861	76,410
Total Crude Oil and Natural Gas Liquids	218,020	203,493	216,177	199,089	201,688	196,854
Natural Gas (MMcf/d)
Oil Sands	20	22	22	23	23	19
Conventional	442	466	457	466	484	457
Total Natural Gas	462	488	479	489	507	476
Total Production (BOE/d)	295,020	284,826	296,010	280,589	286,188	276,187

(1) Natural gas liquids include condensate volumes.

Average Royalty Rates

(Excluding Impact of Realized Gain (Loss) on Risk Management)

	2015		2014
	Q1		Year		Q4		Q3		Q2		Q1
Oil Sands
Foster Creek (1)	-1.2	%	8.8	%	11.2	%	7.2	%	9.3	%	8.1	%
Christina Lake	3.1	%	7.5	%	7.2	%	7.9	%	7.7	%	7.1	%
Conventional
Pelican Lake	6.0	%	7.5	%	8.4	%	7.1	%	8.0	%	6.9	%
Weyburn	16.5	%	21.9	%	19.0	%	24.0	%	24.4	%	19.4	%
Other	3.5	%	5.9	%	6.7	%	6.5	%	5.5	%	4.9	%
Natural Gas Liquids	2.3	%	2.1	%	2.6	%	1.6	%	2.2	%	2.2	%
Natural Gas	1.6	%	1.9	%	2.5	%	2.0	%	2.0	%	1.4	%

(1)In Q1 2015, regulatory approval was received to include certain capital costs incurred in previous years in the royalty calculation which has resulted in a negative rate. Excluding the credit, the Q1 2015 royalty rate would have been 5.9 percent.

Cenovus Energy Inc.
First Quarter 2015 Report	Supplemental Information

67

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

	2015		2014
Refining	Q1		Year		Q4		Q3		Q2		Q1
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d)	460		460		460		460		460		460
Crude Oil Runs (Mbbls/d)	439		423		420		407		466		400
Heavy Oil	220		199		179		201		221		195
Light/Medium	219		224		241		206		245		205
Crude Utilization	95	%	92	%	91	%	88	%	101	%	87	%
Refined Products (Mbbls/d)	469		445		442		429		489		420

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

	2015	2014
Selected Average Benchmark Prices	Q1	Year	Q4	Q3	Q2		Q1
Crude Oil Prices (US$/bbl)
Brent	55.17	99.51	76.98	103.39	109.77		107.90
West Texas Intermediate (“WTI”)	48.63	93.00	73.15	97.17	102.99		98.68
Differential Brent - WTI	6.54	6.51	3.83	6.22	6.78		9.22
Western Canadian Select (“WCS”)	33.90	73.60	58.91	76.99	82.95		75.55
Differential WTI - WCS	14.73	19.40	14.24	20.18	20.04		23.13
Condensate (C5 @ Edmonton)	45.62	92.95	70.57	93.45	105.15		102.64
Differential WTI - Condensate (Premium)/Discount	3.01	0.05	2.58	3.72	(2.16	)	(3.96	)
Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl)
Chicago	16.53	17.61	14.60	17.57	19.72		18.55
Midwest Combined (Group 3)	17.46	16.27	13.28	16.65	17.75		17.41
Natural Gas Prices
AECO ($/Mcf)	2.95	4.42	4.01	4.22	4.67		4.76
NYMEX (US$/Mcf)	2.98	4.42	4.00	4.06	4.67		4.94
Differential NYMEX - AECO (US$/Mcf)	0.57	0.40	0.44	0.16	0.40		0.60

(1)The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”).

Per-unit Results

(Excluding Impact of Realized Gain (Loss) on Risk Management)

	2015		2014
	Q1		Year	Q4	Q3	Q2	Q1
Heavy Oil - Foster Creek (1) (2) ($/bbl)
Price	29.42		69.43	51.95	76.82	79.77	71.44
Royalties	(0.25	)	5.95	5.67	5.40	7.14	5.71
Transportation and Blending	9.39		1.98	1.85	2.17	3.10	0.78
Operating	14.48		16.55	13.65	14.79	19.38	19.09
Netback	5.80		44.95	30.78	54.46	50.15	45.86
Heavy Oil - Christina Lake (1) (2) ($/bbl)
Price	23.30		61.57	47.21	67.62	72.25	59.89
Royalties	0.61		4.40	3.14	5.07	5.37	4.04
Transportation and Blending	4.17		3.53	4.14	3.75	3.14	3.02
Operating	8.22		11.20	9.31	10.40	12.08	13.30
Netback	10.30		42.44	30.62	48.40	51.66	39.53
Total Heavy Oil - Oil Sands (1) (2) ($/bbl)
Price	26.04		65.18	49.44	71.82	75.65	65.19
Royalties	0.22		5.11	4.33	5.22	6.17	4.80
Transportation and Blending	6.50		2.82	3.06	3.03	3.12	1.99
Operating	10.97		13.66	11.35	12.41	15.38	15.96
Netback	8.35		43.59	30.70	51.16	50.98	42.44
Heavy Oil - Conventional (1) (2) ($/bbl)
Price	35.85		76.25	60.25	81.30	83.29	78.52
Royalties	2.34		7.09	6.85	7.72	7.76	6.01
Transportation and Blending	3.42		3.29	3.22	3.40	3.44	3.09
Operating	17.21		20.74	18.24	20.02	20.66	23.73
Production and Mineral Taxes	0.02		0.18	0.03	0.24	0.32	0.13
Netback	12.86		44.95	31.91	49.92	51.11	45.56
Total Heavy Oil (1) (2) ($/bbl)
Price	28.15		67.83	51.74	73.99	77.63	68.64
Royalties	0.68		5.59	4.87	5.79	6.58	5.12
Transportation and Blending	5.83		2.93	3.09	3.11	3.20	2.28
Operating	12.32		15.35	12.82	14.15	16.75	17.97
Production and Mineral Taxes	—		0.04	0.01	0.05	0.08	0.03
Netback	9.32		43.92	30.95	50.89	51.02	43.24
Light and Medium Oil ($/bbl)
Price	45.81		88.30	71.10	89.85	98.27	94.18
Royalties	3.56		9.15	6.12	10.36	11.37	8.78
Transportation and Blending	2.88		3.34	2.89	3.06	3.31	4.11
Operating	15.91		17.28	15.84	17.40	17.45	18.47
Production and Mineral Taxes	1.28		2.70	2.59	2.99	2.97	2.23
Netback	22.18		55.83	43.66	56.04	63.17	60.59

(1)The netbacks do not reflect non-cash write-downs of product inventory.

(2)Heavy oil price and transportation and blending costs exclude the costs of purchased condensate, which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate is as follows:

Cost of Condensate per Barrel of Unblended Crude Oil ($/bbl) 

Foster Creek	30.57	42.01	35.45	38.50	47.28	48.35
Christina Lake	31.60	45.45	38.23	42.57	49.30	52.81
Heavy Oil - Oil Sands	31.14	43.87	36.92	40.71	48.39	50.77
Heavy Oil - Conventional	11.50	15.71	13.98	13.25	17.70	17.56
Total Heavy Oil	26.91	37.13	32.04	34.42	40.44	42.17

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SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results

(Excluding Impact of Realized Gain (Loss) on Risk Management)

	2015		2014
	Q1		Year	Q4		Q3		Q2		Q1
Total Crude Oil (1) ($/bbl)
Price	31.09		71.39	55.05		76.64		81.35		73.15
Royalties	1.16		6.21	5.08		6.56		7.45		5.76
Transportation and Blending	5.34		3.00	3.06		3.10		3.22		2.60
Operating	12.91		15.69	13.34		14.70		16.87		18.06
Production and Mineral Taxes	0.22		0.50	0.45		0.54		0.60		0.42
Netback	11.46		45.99	33.12		51.74		53.21		46.31
Natural Gas Liquids ($/bbl)
Price	28.51		65.55	50.82		66.70		78.38		67.31
Royalties	0.66		1.38	1.34		1.07		1.70		1.48
Netback	27.85		64.17	49.48		65.63		76.68		65.83
Total Liquids (1) ($/bbl)
Price	31.08		71.35	55.02		76.57		81.33		73.12
Royalties	1.16		6.18	5.06		6.52		7.41		5.74
Transportation and Blending	5.31		2.98	3.04		3.08		3.20		2.59
Operating	12.83		15.59	13.25		14.60		16.77		17.96
Production and Mineral Taxes	0.22		0.50	0.44		0.54		0.60		0.42
Netback	11.56		46.10	33.23		51.83		53.35		46.41
Total Natural Gas ($/Mcf)
Price	3.05		4.37	3.89		4.22		4.87		4.47
Royalties	0.05		0.08	0.09		0.08		0.09		0.06
Transportation and Blending	0.12		0.12	0.13		0.11		0.11		0.11
Operating	1.26		1.23	1.21		1.24		1.23		1.26
Production and Mineral Taxes	0.01		0.05	0.03		0.05		0.13		(0.01	)
Netback	1.61		2.89	2.43		2.74		3.31		3.05
Total (1) (2) ($/BOE)
Price	27.73		58.29	46.14		61.85		65.71		59.68
Royalties	0.93		4.53	3.80		4.79		5.36		4.19
Transportation and Blending	4.11		2.32	2.40		2.39		2.45		2.03
Operating	11.44		13.22	11.57		12.53		13.95		14.94
Production and Mineral Taxes	0.17		0.44	0.36		0.48		0.65		0.28
Netback	11.08		37.78	28.01		41.66		43.30		38.24
Impact of Long-Term Incentives Costs (Recovery) on Total Operating Costs ($/BOE)	(0.05	)	0.16	(0.09	)	0.08		0.36		0.29
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	6.58		0.50	7.06		(0.45	)	(2.94	)	(2.00	)
Natural Gas ($/Mcf)	0.29		0.04	0.05		0.11		(0.02	)	—
Total (2) ($/BOE)	5.31		0.42	5.17		(0.13	)	(2.09	)	(1.42	)

(1)The netbacks do not reflect non-cash write-downs of product inventory.

(2)Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). 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.

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ADVISORY

FINANCIAL INFORMATION

Basis of Presentation Cenovus reports financial results in Canadian dollars and presents production volumes on a net to Cenovus before royalties basis, unless otherwise stated. Cenovus prepares its financial statements in accordance with International Financial Reporting Standards (IFRS).

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

·Operating cash flow is defined as revenues, less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains, less realized losses on risk management activities 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. Items within the Corporate and Eliminations segment are excluded from the calculation of operating cash flow.

·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, both of which are defined on the Consolidated Statement of Cash Flows in Cenovus’s interim and annual Consolidated Financial Statements.

·Free cash flow is defined as cash flow less capital investment.

·Operating earnings is used to provide a consistent measure of the comparability of the company’s underlying financial performance between periods by removing non-operating items. Operating earnings is defined as earnings before income tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on operating earnings (loss) before tax.

·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 short-term borrowings and long-term debt, including the current portion. Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, goodwill and asset impairments, unrealized gain or loss on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.

·Net debt is defined as debt net of cash and cash equivalents.

These measures have been described and presented in this quarterly 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 & Analysis (MD&A) available at cenovus.com.

OIL AND GAS INFORMATION

Barrels of Oil Equivalent 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.

Netbacks reported in this quarterly report are calculated as set out in the Annual Information Form (AIF). Heavy oil prices and transportation and blending costs exclude the costs of purchased condensate, which is blended with heavy oil. For first quarter 2015, the cost of condensate on a per barrel of unblended crude oil basis was as follows: Christina Lake - $31.60 and Foster Creek - $30.57.

FORWARD-LOOKING INFORMATION

This document contains certain forward-looking statements and other information (collectively “forward-looking information”) about Cenovus’s current expectations, estimates and projections, made in light of the company’s experience and perception of historical trends.

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Forward-looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast” or “F”, “target”, “projected”,  “future”, “could”, “should”, “focus”, “proposed”, “schedule”, “potential”, “capacity”, “may”, “strategy”, “outlook” or similar expressions and includes suggestions of future outcomes, including statements about: the sufficiency of projected 2015 cash flow to cover capital expenditures and the current level of dividends under current strip pricing and market crack spreads; growth strategy and related schedules; projections contained in the company’s 2015 guidance; forecast operating and financial results; planned capital expenditures; project capacities; expected future production, including the timing, stability or growth thereof; future cost savings and project costs, including relative to the industry; potential for maximizing the value of the company’s royalty fee lands; forecast natural gas use at operations; expected SOR; expected increase in production capacity through optimization activity; potential for optimization of engineering and execution strategy, including related impacts on capital efficiencies; operating cash flow relative to ongoing capital investment requirements for properties; expected future refining capacity; broadening market access; the company’s work on a variety of oil blends, including potential related impact on transportation and refining options; improving cost structures, including the expected timing and sustainability thereof and potential impact on efficiency and productivity; dividend plans and dividend strategy, including with respect to the dividend reinvestment plan; anticipated timelines for future regulatory, partner or internal approvals; future impact of regulatory measures; forecasted commodity prices; future use and development of technology; targeted future debt to capitalization and debt to adjusted EBITDA; and projected shareholder value and total shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as the company’s 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 disclosed in Cenovus’s current guidance, available at cenovus.com; 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; the company’s ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; the company’s ability to generate sufficient cash flow from operations to meet the company’s current and future obligations; and other risks and uncertainties described from time to time in the filings Cenovus makes with securities regulatory authorities.

2015 guidance, available at cenovus.com, is based on an average diluted number of shares outstanding of approximately 760 million. It assumes: Brent US$53.50/bbl, WTI US$50.50/bbl; WCS US$36.25/bbl; NYMEX US$3.00/MMBtu; AECO $2.70/GJ; Chicago 3-2-1 Crack Spread US$11.75/bbl; Exchange Rate of $0.83 US$/C$.

Underlying assumptions in Cenovus’s calculation of supply costs include: price forecast and associated royalties, capital costs, operating expenses, reservoir performance and discount rates. The company’s supply costs are estimated using these assumptions to generate a long-term WTI price that provides a project-specific after-tax rate of return of at least 9% on future capital investment.

The risk factors and uncertainties that could cause Cenovus’s actual results to differ materially include: volatility of and assumptions regarding oil and gas prices; the effectiveness of the company’s risk management program, including the impact of derivative financial instruments, the success of the company’s hedging strategies and the sufficiency of the company’s liquidity position; the 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 the company’s marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted EBITDA as well as debt to capitalization; the company’s ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; changes in credit ratings applicable to Cenovus or any of its securities; changes to the company’s dividend plans or strategy, including the dividend reinvestment plan; accuracy of reserves, resources and future production estimates; Cenovus’s ability to replace and expand oil and gas reserves; Cenovus’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated heavy oil business; reliability of the company’s 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;

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unexpected difficulties in producing, transporting or refining crude oil into petroleum and chemical products; risks associated with technology and its application to Cenovus’s business; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation, including sufficient crude-by-rail or other alternate transportation; changes in the regulatory framework in any of the locations in which Cenovus operates, 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 Cenovus’s business, financial results and its Consolidated Financial Statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which Cenovus operates; 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 Cenovus.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of the company’s material risk factors, see “Risk Factors” in Cenovus’s most recent AIF/Form 40-F, “Risk Management” in Cenovus’s current and annual MD&A and risk factors described in other documents Cenovus files from time to time with securities regulatory authorities, all of which are available on SEDAR at sedar.com, EDGAR at sec.gov and the company’s website at cenovus.com.

ABBREVIATIONS

The following is a summary of the abbreviations that have been used in this document:

Crude Oil		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls/d	barrels per day	MMcf	million cubic feet
Mbbls/d	thousand barrels per day	Bcf	billion cubic feet
MMbbls	million barrels	MMBtu	million British thermal units
		GJ	Gigajoule
BOE	barrel of oil equivalent
MBOE	thousand barrel of oil equivalent
TM	Trademark of Cenovus Energy Inc.

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Cenovus Energy Inc.

500 Centre Street SE

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-7600

CENOVUS CONTACTS
Investor Relations:	Media:
Susan Grey	General media line
Director, Investor Relations	403-766-7751
403-766-4751	media.relations@cenovus.com
susan.grey@cenovus.com
Graham Ingram
Senior Analyst, Investor Relations
403-766-2849
graham.ingram@cenovus.com
Anna Kozicky
Senior Analyst, Investor Relations
403-766-4277
anna.kozicky@cenovus.com
Steve Murray
Senior Analyst, Investor Relations
403-766-3382
steven.murray@cenovus.com

cenovus.com