Exhibit 99.1

Cenovus oil sands production increases 25% in 2014

Proved bitumen reserves up 7%

·Combined oil sands production averaged more than 128,000 barrels per day (bbls/d) net in 2014, up 25% from 2013.

·Non-fuel operating costs per barrel at the company’s oil sands projects declined 14% compared with the previous year.

·Total oil production averaged more than 203,000 bbls/d net, up 14% from 2013.

·Capital investment was $3.1 billion, 6% lower than in 2013.

·Cash flow was $3.5 billion, a 4% decrease compared with 2013. Rising oil sands production and higher average prices for heavy crude oil were more than offset by the impact of lower realized margins in Cenovus’s refining business.

·In 2014, the company received regulatory approval for its Grand Rapids and Telephone Lake oil sands projects and its Foster Creek phase J expansion.

·Production replacement was 193% due to strong growth in proved reserves. Proved year-end bitumen reserves were nearly two billion barrels (bbls), up 7% from 2013.

“We had strong operating performance in our oil sands and conventional businesses in 2014, with significant growth in oil sands production and additions to our portfolio of regulatory-approved projects,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “With low oil prices expected to persist through 2015, we plan to continue building our production capacity, but at a slower pace, focusing on expansion projects at Foster Creek and Christina Lake that are already well advanced.”

Production & financial summary

(for the period ended December 31)Production (before royalties)	2014 Q4	2013 Q4	% change	2014 Full Year	2013 Full Year	% change
Oil sands (bbls/d)	142,213	113,890	25	128,195	102,500	25
Conventional oil1 (bbls/d)	73,964	74,853	-1	75,298	76,775	-2
Total oil (bbls/d)	216,177	188,743	15	203,493	179,275	14
Natural gas (MMcf/d)	479	514	-7	488	529	-8

Financial ($ millions, except per share amounts)
Cash flow2	401	835	-52	3,479	3,609	-4
Per share diluted	0.53	1.10		4.59	4.76
Operating earnings2	-590	212	-378	633	1,171	-46
Per share diluted	-0.78	0.28		0.84	1.55
Net earnings	-472	-58	-714	744	662	12
Per share diluted	-0.62	-0.08		0.98	0.87
Capital investment	786	898	-12	3,051	3,262	-6

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.

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Calgary, Alberta (February 12, 2015) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) achieved solid production growth in 2014, driven by strong performance at its oil sands projects in northern Alberta. In addition, while the average benchmark price for Brent crude and West Texas Intermediate (WTI) decreased year over year, the company’s upstream operations benefited from higher average prices for its heavy crude oil sold as Western Canadian Select (WCS). These factors, along with a weakening in the Canadian dollar versus the U.S. dollar, contributed to 19% higher upstream operating cash flow compared with 2013. This increase was more than offset by a sharp decline in operating cash flow from refining, largely due to lower average market crack spreads and higher heavy crude oil feedstock costs. Cenovus also increased its reserves base in 2014, achieving 193% production replacement.

“These are challenging times for the oil and gas industry,” said Ferguson. “Cenovus is taking steps to ensure we remain strong during this market downturn. We have a solid foundation supported by great assets that provide us with the opportunity to create long-term value for investors.”

In 2014, Cenovus achieved 25% production growth from its Christina Lake and Foster Creek oil sands operations, averaging more than 128,000 bbls/d net (256,000 bbls/d gross). Oil sands production volumes exceeded the company’s full-year guidance by approximately 4,000 bbls/d net to Cenovus. Christina Lake production increased 40% to average about 69,000 bbls/d net after expansion phase E reached design capacity in early 2014. The facility also achieved a consistently high utilization rate for the year.

Foster Creek production averaged more than 59,000 bbls/d net in 2014, up 11% from the previous year. The production increase was the result of improved plant performance, continued optimization efforts and increased production from wells using Cenovus’s Wedge WellTM technology. The company achieved first production from the phase F wells in September. Phase F, which added 30,000 bbls/d of gross production capacity, was producing approximately 4,000 bbls/d net (8,000 bbls/d gross) at the end of the year.

“We’re pleased with the strong performance of our oil sands projects. Both Christina Lake and Foster Creek delivered reliable production with lower non-fuel operating costs per barrel and improved safety performance compared with 2013,” said John Brannan, Executive Vice-President & Chief Operating Officer. “During this current period of lower oil prices, we’re focusing on achieving additional cost savings to help keep our projects among the most cost efficient in the industry.”

Cash flow was $3.5 billion in 2014, down 4% from the previous year, primarily due to an 82% decrease in operating cash flow from refining. In the fourth quarter of 2014, benchmark crude oil prices dropped sharply, and a narrowing of the Brent-WTI price differential contributed to lower average market crack spreads for the year. In addition, Cenovus’s refining feedstock cost advantage - the price differential between WCS and WTI - narrowed in 2014 compared with the previous year, which increased heavy crude oil feedstock costs. As well, in the fourth quarter, refining operating cash flow was negatively impacted by an inventory writedown of $110 million and a $163 million adjustment related to accounting policy differences between Canada and the U.S. These adjustments were related to the decline in refined product and crude oil prices late in 2014.

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Cenovus’s operating and net earnings were negatively affected in 2014 by a $497 million non-cash goodwill impairment associated with Pelican Lake. The impairment was caused by a decline in forecast crude oil prices as well as a slowing of the development plan at Pelican Lake. There were no goodwill impairments in 2013. Cenovus also had non-cash asset impairments of $151 million related to tight oil exploration activities as well as to property, plant and equipment.

Cenovus had free cash flow of $428 million in 2014, 23% higher than in 2013, after capital investment of approximately $3.1 billion.

“We ended 2014 in a solid financial position with approximately $900 million in cash and cash equivalents on our balance sheet and debt ratios well within our target ranges,” said Ferguson. “In the current challenging oil price environment, we’re reducing capital spending in order to help preserve our financial resilience. As well, we have additional flexibility to further reduce capital spending if oil prices continue to fall or remain low for an extended period.”

Cenovus is undertaking various measures to reduce its costs, including an expected 15% staff reduction, the bulk of which will come from its contract workforce. Employee salary increases have also been suspended for 2015 and the company is significantly reducing its discretionary spending, including spending on travel, conferences, offsite meetings and information technology upgrades.

Continued additions to reserves

Cenovus continued to add to its reserves in 2014. Proved bitumen reserves increased 7% in the year to almost two billion bbls, and proved plus probable bitumen reserves increased 30% to 3.3 billion bbls. Total proved reserves gained 4%, while total proved plus probable reserves increased 22%, according to the company’s independent reserves and contingent resources evaluation. As a result of the large growth in proved plus probable bitumen reserves, economic bitumen best estimate contingent resources declined approximately 5% to 9.3 billion bbls from 2013.

Maximizing shareholder value

Cenovus has been evaluating opportunities to crystalize value for shareholders from its existing portfolio of assets. The options available to the company to maximize the value of its fee lands include a possible sale or initial public offering. Cenovus is market-ready to pursue various potential options with respect to its fee lands when the timing presents itself. In 2014, royalty interest production from these conventional oil and natural gas properties provided approximately 7,600 barrels of oil equivalent per day (BOE/d). This resulted in operating cash flow of about $150 million for Cenovus.

Q4 2014

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Oil Projects

Daily production1

	2014					2013					2012
(Before royalties) (Mbbls/d)	Full Year	Q4	Q3	Q2	Q1	Full  Year	Q4	Q3	Q2	Q1	Full  Year
Oil sands
Christina Lake	69	74	68	68	66	49	61	53	38	44	32
Foster Creek	59	68	57	57	55	53	52	49	55	56	58
Oil sands total	128	142	125	125	120	103	114	102	94	100	90
Conventional oil
Pelican Lake	25	26	24	25	25	24	25	25	24	24	23
Weyburn	16	16	16	16	16	16	16	16	16	17	16
Other conventional2	34	32	34	36	36	36	34	34	37	39	37
Conventional total	75	74	74	77	76	77	75	75	77	80	76
Total oil	203	216	199	202	197	179	189	177	171	180	165

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 69,023 bbls/d net in 2014, 40% higher than in 2013, primarily due to phase E reaching design capacity in the second quarter. Average production levels for the year ran slightly above Christina Lake’s total gross design capacity and exceeded the company’s expectations for 2014. In the fourth quarter, Christina Lake produced an average of 73,836 bbls/d net, an increase of 20% from the same period in 2013. Christina Lake continued to perform well in January with production averaging almost 77,000 bbls/d.

·The steam to oil ratio (SOR) was 1.8 for 2014, similar to 2013.

·Total operating costs at Christina Lake were better than the company’s expectations at $11.20/bbl for the year, a 10% decline from $12.47/bbl in 2013 and below its 2014 guidance of $12.00/bbl. The decrease was primarily due to increased

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production and a decline in fluid, waste handling and trucking costs. Fuel costs increased $0.62/bbl due to a rise in natural gas prices, partially offset by a decrease in per-barrel fuel consumption.

·Non-fuel operating costs for 2014 were $7.55/bbl, a 20% decline from $9.44/bbl in 2013.

·The netback the company received for its Christina Lake oil rose 33% to $42.44/bbl in 2014 compared with 2013, due to an increase in the full year average realized crude oil sales price and lower per-barrel operating costs.

Expansions

·The company continued construction at Christina Lake phases F and G in 2014. Phase F is well advanced, and Cenovus plans to continue building the project in 2015. First oil from phase F 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 preserve cash.

·Cenovus expects to continue to progress its plant optimization project at Christina Lake, with incremental production expected in the fourth quarter of 2015.

·In 2014, total capital investment at Christina Lake was $794 million, 15% higher compared with the previous year. Most of the investment was focused on expansion phases F and G, phase E well pad and facility construction as well as sustaining well programs that included the use of Cenovus’s Wedge WellTM technology. Capital was also directed to the plant optimization program.

Foster Creek

Production

·Foster Creek production exceeded the company’s guidance for the year, averaging 59,172 bbls/d net in 2014, 11% higher than in 2013. The increase was primarily due to improved performance at the operation’s facilities, optimization efforts and increased production from wells using the company’s Wedge WellTM technology. Fourth quarter production was 68,377 bbls/d net, up 30% compared with the same period in 2013. The strong operational performance continued in January with production averaging approximately 72,000 bbls/d.

·Phase F is ramping up as expected and ended the year with production of approximately 4,000 bbls/d net (8,000 bbls/d gross). Phase F has a design capacity of 30,000 bbls/d of gross production. Production is expected to ramp up over a period of 18 months from first oil, which was achieved last September.

·The SOR at Foster Creek was 2.6 in 2014, compared with 2.5 in 2013. The 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.

·Total operating costs at Foster Creek were 5% higher than in 2013 but were lower than the company’s forecast, largely due to better than expected production volumes and SOR coming in at the low end of guidance. Operating costs for 2014 averaged $16.55/bbl compared with $15.77/bbl in 2013 and Cenovus’s 2014 guidance of $17.50/bbl. Fuel costs had a significant impact on per-unit operating costs at Foster Creek in 2014, increasing $1.58/bbl, or 55% compared with 2013. The increase was due to higher natural gas prices and increased consumption compared with the previous year.

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·Non-fuel operating costs were down 6% to $12.09/bbl compared with $12.89/bbl in 2013, reflecting the increased production volumes.

·The netback the company received for its Foster Creek crude oil production was $44.95/bbl in 2014, a slight increase from the previous year. This was largely due to the higher average sales price the company received for its crude oil in 2014 compared with 2013.

Expansions

·Capital investment in 2014 was $796 million, similar to 2013. Investment during the year was focused on the completion of phase F, the construction of phases G and H, the drilling of sustaining wells and operational improvement projects.

·Cenovus plans to continue advancing phase G in 2015 and anticipates first oil in the first half of 2016. Due to the significant decrease in crude oil prices, construction work on phase H has been deferred to preserve cash.

·In the fourth quarter of 2014, Cenovus received regulatory approval for phase J, which could add approximately 50,000 bbls/d of gross production capacity.

Narrows Lake

·Engineering, procurement and construction work for phase A progressed in 2014.

·Cenovus invested $175 million at Narrows Lake, compared with $152 million in 2013.

·The company 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.

·In response to the substantial decline in crude oil prices, Cenovus has decided to defer further work at Narrows Lake to preserve 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. The third pilot well pair is expected to be completed in early March, and steam circulation is expected to begin in the second quarter of 2015. It is anticipated that data from these well pairs will be used to help determine the company’s development plan for Grand Rapids, subject to a recovery in crude oil prices.

·The company has almost completed the dismantling and moving 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. The project has received regulatory approval for total production capacity of 180,000 bbls/d.

·Capital investment was $63 million at Grand Rapids in 2014, compared with $39 million in 2013.

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Telephone Lake

·Cenovus received approval during the fourth quarter from the Alberta Energy Regulator for its Telephone Lake oil sands project located in northern Alberta.

·In 2014, the company invested $112 million at Telephone Lake, compared with $93 million in 2013. The 2014 investment program included the drilling of 45 stratigraphic test wells. Most of the planned development at Telephone Lake in 2015 has been deferred to preserve cash. The company continues to review development options to help ensure the lowest capital efficiencies possible for the project.

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 declined 2% to 75,298 bbls/d in 2014 compared with the previous year. Increased production from the company’s successful horizontal well program in southern Alberta and a slight rise in Pelican Lake production was more than offset by expected natural declines and the sale of the company’s Lower Shaunavon asset in 2013 as well as a portion of its Bakken and Wainwright properties in 2014. Together, these assets produced approximately 2,200 bbls/d in 2014 compared with approximately 5,200 bbls/d in 2013. Total fourth quarter production declined 1% to 73,964 bbls/d compared with the same quarter in 2013. January production averaged more than 75,000 bbls/d.

·Production at Pelican Lake in 2014 averaged 24,924 bbls/d, 3% higher compared with a year earlier due to increased response from the polymer flood program and additional infill wells coming online, partially offset by a planned turnaround. Fourth quarter production rose 6% to 25,906 bbls/d compared with the same period a year earlier.

·Production from Weyburn averaged 16,196 bbls/d net compared with 16,361 bbls/d net in 2013. Fourth quarter production declined 2% to 16,050 bbls/d compared with the same period a year earlier.

·As previously announced, Cenovus has suspended the majority of its conventional drilling program in southern Alberta and Saskatchewan for 2015. This suspension, along with the asset dispositions, 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.

·Operating costs for Cenovus’s conventional oil operations were $18.81/bbl, a 7% increase from $17.61/bbl in 2013. The increase was primarily due to higher costs for chemicals, lower production volumes, increased expenses for fluid, waste handling and trucking as well as repairs and maintenance. This was partially offset by lower electricity costs.

·Cenovus invested $812 million in its conventional oil assets in 2014, compared with approximately $1.2 billion a year earlier. These assets generated $548 million of operating cash flow in excess of capital investment in 2014.

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Natural Gas

Daily production

	2014					2013					2012
(Before royalties)(MMcf/d)	Full Year	Q4	Q3	Q2	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Natural gas	488	479	489	507	476	529	514	523	536	545	594

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 488 million cubic feet per day (MMcf/d) in 2014, down 8% compared with the previous year, driven by expected natural declines and the company’s decision to focus capital investment on its crude oil assets. Production was 479 MMcf/d in the fourth quarter of 2014, a decline of 7% from the same period in 2013.

·The company invested $34 million in its natural gas assets in 2014, up from $27 million in 2013. The assets generated $519 million in operating cash flow in excess of capital investment in 2014.

·Cenovus’s average realized sales price for natural gas, including hedges, was $4.41 per thousand cubic feet (Mcf) compared with $3.52 per Mcf in 2013.

·Higher cash flow from natural gas more than offset the increase in fuel costs at Cenovus’s operations in 2014 because the company produced more natural gas than it consumed at its oil sands and refining operations. Natural gas use at Cenovus’s operations is forecast to be about 180 MMcf/d in 2015.

Market Access

Cenovus is concentrating on finding new customers in North America and around the world and is working to enhance its ability to move its oil to these customers. The company continues to support proposed pipelines to Canada’s east and west coasts as well as to the U.S. to provide additional shipping capacity for its expected production growth. To complement its pipeline strategy, Cenovus takes a portfolio approach to marketing and transportation that also includes rail.

·Cenovus now has 30,000 bbls/d of crude oil rail loading capacity. On average, the company transported approximately 10,000 bbls/d of crude oil by rail in 2014 to markets in Canada and the U.S., including 47 unit train shipments. Cenovus also began taking delivery of 825 coiled and insulated rail cars in the fourth quarter to further support its rail strategy.

·As part of its oil sands partnership with ConocoPhillips, Cenovus is responsible for marketing the total gross production from its Christina Lake and Foster Creek projects. To ensure adequate capacity for expected future production growth from these projects, the company has been securing additional pipeline capacity. This

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includes a long-term transportation agreement signed with Inter Pipeline (IPL) to ship up to 500,000 bbls/d of oil blend via the recently completed Cold Lake pipeline expansion. Deliveries on the Cold Lake expansion began in early 2015.

·Cenovus also 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.

·In combination, this additional transportation capacity via rail and on the Cold Lake and Flanagan South pipeline systems is expected to increase per-barrel transportation costs at Foster Creek and Christina Lake to about $8.00/bbl in 2015 from approximately $3.00/bbl in 2014. Longer term, these transportation initiatives should allow Cenovus to capture higher pricing for a portion of its production. The increase in transportation costs on the Cold Lake pipeline is expected to be temporary. As the company’s planned expansion phases come online at Foster Creek, incremental production growth is expected to reduce per-barrel costs.

·Cenovus continues to use its 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 move 200,000 bbls/d on TransCanada’s proposed Energy East pipeline, has additional shipping capacity of 175,000 bbls/d on planned pipelines to the West Coast and has 75,000 bbls/d of committed capacity on TransCanada’s proposed Keystone XL system.

Refining

Cenovus’s refining operations allow the company to capture value from crude oil production through to refined products such as diesel, gasoline and jet fuel. This integrated strategy provides a natural economic hedge to discounted crude oil prices by providing lower feedstock costs to the Wood River Refinery in Illinois and the Borger Refinery in Texas, which Cenovus jointly owns with the operator, Phillips 66.

Financial

·Operating cash flow from refining was $201 million for the year, an 82% decline from $1.1 billion in 2013. The year-over-year decline was largely due to significant changes in benchmark crude oil prices in the fourth quarter of 2014. A narrowing of the Brent-WTI price differential contributed to lower average market crack spreads for the year. In addition, refining margins were negatively impacted by higher heavy crude oil feedstock costs.

·Refining results were also affected by an inventory writedown of $110 million recorded in the fourth quarter of 2014, reflecting the significant decline in forecast refined product and crude oil prices.

·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 $101 million higher in 2014, excluding the impact of inventory writedowns. In the fourth quarter, the company’s operating cash flow from refining would have been approximately $163 million higher using the LIFO accounting method.

·Capital investment was $162 million compared with $106 million a year earlier.

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Operations

·Cenovus’s refineries processed an average of 423,000 bbls/d gross in 2014, a 4% decrease from 2013, due to planned and unplanned outages in 2014.

·Together, the two refineries processed an average of 199,000 bbls/d gross of heavy oil in 2014, compared with 222,000 bbls/d gross in 2013. The decline was primarily a result of the decision to process higher volumes of medium crude oil due to more favourable economics.

·The refineries produced an average of 445,000 bbls/d gross of refined products in 2014, a 4% decrease from the previous year.

Reserves and Contingent Resources

All of Cenovus’s reserves and resources are evaluated each year by independent qualified reserves evaluators (IQREs).

·At year-end 2014, Cenovus had total proved reserves of 2.4 billion BOE, an increase of 4% compared with 2013.

·Proved bitumen reserves for 2014 were up 7% compared with 2013 to approximately two billion bbls, while proved plus probable bitumen reserves increased 30% to approximately 3.3 billion bbls. This increase in proved reserves was primarily due to an area expansion at Foster Creek and improved performance at Christina Lake. These increases, plus additional probable reserves contained in the Foster Creek area expansion and the significant area expansion at Christina Lake, drove the growth in proved plus probable reserves.

·Economic bitumen best estimate contingent resources fell to 9.3 billion bbls, declining approximately 5% from 2013 as a result of significant conversions to proved and probable reserves. For additional information on the company’s contingent resources, see Oil and Gas Information in the Advisory.

·Proved light and medium oil plus natural gas liquids (NGLs) reserves increased 4% to 120 million bbls, while proved heavy oil reserves declined approximately 13% due to the deferral of drilling at Pelican Lake and the sale of part of the Wainwright property. Natural gas proved reserves declined about 8% compared with 2013 as Cenovus continued to focus capital on developing its oil assets. As expected, this reallocation of capital has resulted in natural gas production outpacing reserves additions.

·Cenovus’s 2014 proved finding and development (F&D) costs, excluding changes in future development costs, were $13.39/BOE, down from $14.51/BOE in 2013, due to reduced capital spending while maintaining reserves additions. The three-year average F&D costs were $11.77/BOE, excluding changes in future development costs. The 2014 recycle ratio was 2.8 times.

·For Cenovus’s proved reserves, the IQREs have estimated the company’s total future development costs to be $8.44/BOE, or $6.55/BOE on a de-escalated basis.

·Cenovus achieved production replacement of 193% in 2014.

·The overall proved reserves life index is approximately 23 years. The magnitude of the company’s bitumen assets is significant with a bitumen proved reserves life index of 42 years, down 14% due to the company’s increasing bitumen production. The conventional oil and NGLs proved reserves life is approximately 11 years.

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Proved reserves reconciliation

(Before royalties)	Bitumen  (MMbbls)		Heavy Oil(MMbbls)		Light & Medium Oil & NGLs  (MMbbls)		Natural Gas &CBM(Bcf)
Start of 2014	1,846		179		115		865
Extensions & improved recovery	108		14		17		23
Technical revisions	63		(13	)	1		98
Economic factors	0		0		0		(12	)
Acquisitions	0		0		0		2
Divestitures	0		(10	)	(1	)	(5	)
Production1	(47	)	(14	)	(12	)	(175	)
End of 2014	1,970		156		120		796
% Change	7		(13	)	4		(8	)
Developed	238		116		98		792
Undeveloped	1,732		40		22		4
Total proved	1,970		156		120		796
Total probable	1,330		123		46		260
Total proved plus probable	3,300		279		166		1,056

1 Production used for the reserves reconciliation differs from reported production as it includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production. See the Advisory — Oil and Gas Information for more information about royalty interest production.

Proved reserves costs1

(Before royalties)	2014	2013	3 Year
Capital Investment ($ millions)
Finding and Development	2,782	3,026	8,821
Finding, Development and Acquisitions	2,800	3,058	8,985
Proved Reserves Additions2 (MMBOE)
Finding and Development	208	208	749
Finding, Development and Acquisitions	208	208	751
Proved Reserves Costs2 ($/BOE)
Finding and Development3	13.39	14.51	11.77
Finding, Development and Acquisitions4	13.46	14.67	11.97

1 Finding and Development Cost calculations presented in the table do not include changes in future development costs. See the Advisory - Finding and Development Costs - for a full description of the methods used to calculate Finding and Development Costs which include the change in future development costs.

2 Reserves Additions for Finding and Development are calculated by summing technical revisions, extensions and improved recovery, discoveries and economic factors. Reserves Additions for Finding, Development and Acquisitions are calculated by summing Reserves Additions for Finding and Development and additions from acquisitions. See the Advisory — Oil and Gas Information.

3  Finding and Development Costs without changes in future development costs is equal to Finding and Development Capital Investment divided by Finding and Development Reserves Additions.

4 Finding, Development and Acquisitions without changes in future development costs is equal to Finding, Development and Acquisitions Capital Investment divided by Finding, Development and Acquisitions Reserves Additions.

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Financial

Dividend

The Cenovus Board of Directors declared a first quarter dividend of $0.2662 per share, payable on March 31, 2015 to common shareholders of record as of March 13, 2015. Based on the February 11, 2015 closing share price on the Toronto Stock Exchange of $24.68, this represents an annualized yield of about 4.3%. Declaration of dividends is at the sole discretion of the Board. Cenovus’s continued commitment to a meaningful dividend is an important aspect of its strategy to focus on increasing total shareholder return.

To help further support balance sheet flexibility, the company has approved an update to its dividend reinvestment plan (DRIP), which permits shareholders to automatically reinvest cash dividends paid on their common shares in additional common shares. Cenovus intends to offer shareholders who wish to take advantage of the DRIP a 3% discount to the average market price for its shares. The company plans to issue common shares under the DRIP from treasury.

Cash flow, earnings and capital investment

·Cenovus generated $3.5 billion in cash flow for the year, 4% lower than in 2013, largely due to the significant change in benchmark crude oil prices in the fourth quarter of 2014. Between September 30, 2014 and December 31, 2014, Brent crude, WTI and WCS prices fell between 40% and 50%. On an annual basis, average Brent crude prices declined approximately 9% in 2014, compared with the previous year, while average WTI prices fell approximately 5% and WCS prices increased 1%.

·Operating cash flow was $4.2 billion in 2014, a decline of 7% compared with 2013. Approximately $3.9 billion of that operating cash flow was generated by Cenovus’s oil and natural gas producing assets in 2014. Operating cash flow from the company’s refining business was $201 million.

·For the year, operating cash flow in excess of capital invested was $36 million from crude oil production at the company’s oil sands projects, $548 million from conventional oil, $519 million from natural gas and $39 million from refining.

·Operating earnings were $633 million in 2014, a 46% decrease compared with 2013, primarily due to a $497 million, or $0.66/share, goodwill impairment. The goodwill impairment, associated with the company’s Pelican Lake asset, is due to a decline in forecast benchmark crude oil prices and a slowing of the long-term development plan for the project.

·The company also recorded an impairment on property, plant and equipment which totalled $65 million, or $0.06/share, including $52 million on equipment Cenovus doesn’t plan to use in the future and doesn’t expect to be able to sell for its carrying value. In addition, Cenovus wrote down the value of crude oil and refined product inventories by $131 million, or $0.11/share, the majority of which was in its refining segment, and had $86 million, or $0.08/share, in exploration expense. The majority of the exploration expense was related to a determination that certain tight oil exploration assets weren’t commercially viable.

·Cenovus’s net earnings for the year were $744 million, an increase of 12% from the previous year.

·Capital investment was $3.1 billion, a 6% decline from 2013. Approximately two-thirds of the investment was at the company’s oil sands operations as it progressed expansion phases at Christina Lake and Foster Creek as well as construction at

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Narrows Lake. Most of the remaining capital investment was directed to the company’s conventional oil business, which focused on tight oil development, facilities work and the expansion of the polymer flood at Pelican Lake.

Risk management, G&A expenses and financial ratios

·In the fourth quarter, Cenovus added Brent fixed price contracts for the first half of 2015 of 1,000 bbls/d at an average price of $100.25/bbl and 6,000 bbls/d at US$65.03/bbl. The company also added natural gas AECO fixed price contracts for 149 MMcf/d at an average price of $3.86/Mcf.

·In 2014, total realized gains on risk management were $66 million and unrealized gains were $596 million, driven by the decline in average crude oil and natural gas benchmark prices relative to Cenovus’s contract prices.

·Cenovus received an average realized price, including hedging, of $71.85/bbl for its oil. The average realized price for natural gas, including hedging, was $4.41/Mcf.

·General and administrative (G&A) expenses were $3.49/BOE for the year, compared with $3.58/BOE in 2013 due to increased production volumes.

·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 December 31, 2014, the company’s debt to capitalization ratio was 35% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.4 times.

Operating earnings1

(for the period ended December 31) ($ millions, except per share amounts)	2014 Q4		2013Q4		2014 Full Year		2013Full Year
Earnings (loss) before income tax
Add back (deduct):	(520	)	(22	)	1,195		1,094
Unrealized risk management (gains) losses2	(416	)	219		(596	)	415
Non-operating unrealized foreign exchange (gains) losses3	186		(39	)	458		52
Realized foreign exchange loss on Partnership contribution	—		146		—		146
(Gains) losses on divestiture of assets	1		—		(156	)	1
Operating earnings (loss), before income tax	(749	)	304		901		1,708
Income tax expense (recovery)	(159	)	92		268		537
Operating earnings	(590	)	212		633		1,171

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 the Partnership Contribution Receivable and foreign exchange (gains) losses on settlement of intercompany transactions.

Conference Call Today

9 a.m. Mountain Time (11 a.m. Eastern Time)

Cenovus will host a conference call today, February 12, 2015, starting at 9 a.m. MT (11 a.m. ET). To participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 minutes prior to the conference call. A live audio webcast of the conference call will also be available via cenovus.com. The webcast will be archived for approximately 90 days.

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13

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 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.

·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, excluding any amounts with respect to the partnership contribution payable and receivable. 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, 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.

These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus’s most recent Management’s Discussion & Analysis (MD&A) available at cenovus.com.

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OIL AND GAS INFORMATION

The estimates of reserves and resources data and related information were prepared effective December 31, 2014 by independent qualified reserves evaluators (“IQREs”), based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented using McDaniel & Associates Consultants Ltd. (“McDaniel”) January 1, 2015 price forecast. Cenovus holds significant fee title rights which generate production for the company’s account from third parties leasing those lands. The before royalties volumes presented in the reserves reconciliation (i) do not include reserves associated with this production and (ii) the production differs from other publicly reported production as it includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production.

Resources Information

Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate.

Contingent resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. The McDaniel estimates of contingent resources have not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Economic contingent resources are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. Economic contingent resources are estimated using volumetric calculations of the in-place quantities, combined with performance from analog reservoirs. Existing SAGD projects that are producing from the McMurray-Wabiskaw formations are used as performance analogs at Foster Creek and Christina Lake. Other regional analogs are used for contingent resources estimation in the Cretaceous Grand Rapids formation at the Grand Rapids property in the Pelican Lake region, in the McMurray formation at the Telephone Lake property in the Borealis region and in the Clearwater formation in the Foster Creek region.

Contingencies which must be overcome to enable the reclassification of contingent resources as reserves can be categorized as economic, non-technical and technical. The Canadian Oil and Gas Evaluation Handbook identifies non-technical contingencies as legal, environmental, political and regulatory matters or a lack of markets. Technical contingencies include available infrastructure and project justification. The outstanding contingencies applicable to our disclosed economic contingent resources do not include economic contingencies.

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Our bitumen contingent resources are located in four general regions: Foster Creek, Christina Lake, Borealis and Greater Pelican. Further information in respect of contingencies faced in these four regions is included in our Annual Information Form.

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 news release are calculated as set out in the AIF. Heavy oil prices and transportation and blending costs exclude the costs of purchased condensate, which is blended with heavy oil. For 2014, the cost of condensate on a per barrel of unblended crude oil basis was as follows: Christina Lake - $45.45 and Foster Creek - $42.01.

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

Finding and development costs for proved reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $31.65/BOE for the year ended December 31, 2014, $32.97/BOE for the year ended December 31, 2013 and averaged $29.27/BOE for the three years ended December 31, 2014. Finding and development costs for proved plus probable reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs were $19.38/BOE for the year ended December 31, 2014, $40.85/BOE for the year ended December 31, 2013 and averaged $22.98/BOE for the three years ended December 31, 2014. These finding and development costs were calculated by dividing the sum of exploration costs, development costs and changes in future development costs in the particular period by the reserves additions (the sum of extensions and improved recovery, discoveries, technical revisions and economic factors) in that period. The aggregate of the exploration and development costs incurred in a particular period and the change during that period in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that period.

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. 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” or similar expressions and includes suggestions of future outcomes, including statements about: growth strategy and related schedules; projections contained in the company’s 2015 guidance; anticipated finding and development costs; expected reserves and resources additions; 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

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16

the industry; potential options with respect to 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; operating cash flow relative to ongoing capital investment requirements for properties; expected future refining capacity; broadening market access; improving cost structures; 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; Western Canada Select 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;

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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; 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 our material risk factors, see “Risk Factors” in Cenovus’s most recent Annual Information Form/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.

TM denotes a trademark of Cenovus Energy Inc.

Cenovus Energy Inc.

Cenovus Energy Inc. is a Canadian integrated oil company. It is committed to applying fresh, progressive thinking to safely and responsibly unlock energy resources the world needs. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and Saskatchewan. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. Its enterprise value is approximately $24 billion. For more information, visit cenovus.com.

Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and Instagram.

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CENOVUS CONTACTS:
Investor Relations	Media
Susan Grey	Brett Harris
Director, Investor Relations	Media Lead
403-766-4751	403-766-3420
Graham Ingram	Reg Curren
Senior Analyst, Investor Relations	Senior Media Advisor
403-766-2849	403-766-2004
Anna Kozicky	General media line
Senior Analyst, Investor Relations	403-766-7751
403-766-4277
Steve Murray
Senior Analyst, Investor Relations
403-766-3382

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19

Cenovus Energy Inc.

Interim Consolidated Financial Statements
(unaudited)

For the Period Ended December 31, 2014

(Canadian Dollars)

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the period ended December 31,

($ millions, except per share amounts)

		Three Months Ended						Twelve Months Ended
	Notes	2014			2013			2014			2013
Revenues	1
Gross Sales		4,338			4,827			20,107			18,993
Less: Royalties		100			80			465			336
		4,238			4,747			19,642			18,657
Expenses	1
Purchased Product		2,775			2,776			10,955			10,399
Transportation and Blending		577			592			2,477			2,074
Operating		486			474			2,066			1,798
Production and Mineral Taxes		10			5			46			35
(Gain) Loss on Risk Management	21	(567		)	142			(662		)	293
Depreciation, Depletion and Amortization	11	531			468			1,946			1,833
Goodwill Impairment	13	497			—			497			—
Exploration Expense	10	85			5			86			114
General and Administrative		67			81			358			349
Finance Costs	4	108			122			445			529
Interest Income	5	(2		)	(23		)	(33		)	(96		)
Foreign Exchange (Gain) Loss, Net	6	188			115			411			208
Research Costs		6			10			15			24
(Gain) Loss on Divestiture of Assets	12	1			—			(156		)	1
Other (Income) Loss, Net		(4		)	2			(4		)	2
Earnings (Loss) Before Income Tax		(520		)	(22		)	1,195			1,094
Income Tax Expense (Recovery)	7	(48		)	36			451			432
Net Earnings (Loss)		(472		)	(58		)	744			662
Other Comprehensive Income (Loss), Net of Tax	18
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits		(7		)	(1		)	(18		)	14
Items That May be Reclassified to Profit or Loss:
Change in Value of Available for Sale Financial Assets		—			2			—			10
Foreign Currency Translation Adjustment		107			59			215			117
Total Other Comprehensive Income (Loss), Net of Tax		100			60			197			141
Comprehensive Income (Loss)		(372		)	2			941			803
Net Earnings (Loss) Per Common Share	8
Basic		$	(0.62	)	$	(0.08	)	$	0.98		$	0.88
Diluted		$	(0.62	)	$	(0.08	)	$	0.98		$	0.87

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. For the period ended December 31, 2014

2

CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		December 31,	December 31,
	Notes	2014	2013
Assets
Current Assets
Cash and Cash Equivalents		883	2,452
Accounts Receivable and Accrued Revenues		1,582	1,874
Income Tax Receivable		28	15
Inventories	9	1,224	1,259
Risk Management	21	478	10
Current Assets		4,195	5,610
Exploration and Evaluation Assets	1,10	1,625	1,473
Property, Plant and Equipment, Net	1,11	18,563	17,334
Other Assets		70	68
Goodwill	1,13	242	739
Total Assets		24,695	25,224
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		2,588	2,937
Income Tax Payable		357	268
Current Portion of Partnership Contribution Payable	14	—	438
Risk Management	21	12	136
Current Liabilities		2,957	3,779
Long-Term Debt	15	5,458	4,997
Partnership Contribution Payable	14	—	1,087
Risk Management	21	4	3
Decommissioning Liabilities	16	2,616	2,370
Other Liabilities		172	180
Deferred Income Taxes		3,302	2,862
Total Liabilities		14,509	15,278
Shareholders’ Equity		10,186	9,946
Total Liabilities and Shareholders’ Equity		24,695	25,224

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. For the period ended December 31, 2014

3

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

($ millions)

	ShareCapital		Paid inSurplus	RetainedEarnings		AOCI (1)	Total
	(Note 17)					(Note 18)
Balance as at December 31, 2012	3,829		4,154	1,730		69	9,782
Net Earnings	—		—	662		—	662
Other Comprehensive Income (Loss)	—		—	—		141	141
Total Comprehensive Income (Loss)	—		—	662		141	803
Common Shares Issued Under Stock Option Plans	31		—	—		—	31
Common Shares Cancelled	(3	)	3	—		—	—
Stock-Based Compensation Expense	—		62	—		—	62
Dividends on Common Shares	—		—	(732	)	—	(732	)
Balance as at December 31, 2013	3,857		4,219	1,660		210	9,946
Net Earnings	—		—	744		—	744
Other Comprehensive Income (Loss)	—		—	—		197	197
Total Comprehensive Income (Loss)	—		—	744		197	941
Common Shares Issued Under Stock Option Plans	32		—	—		—	32
Stock-Based Compensation Expense	—		72	—		—	72
Dividends on Common Shares	—		—	(805	)	—	(805	)
Balance as at December 31, 2014	3,889		4,291	1,599		407	10,186

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. For the period ended December 31, 2014

4

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the period ended December 31,

($ millions)

		Three Months Ended				Twelve Months Ended
	Notes	2014		2013		2014		2013
Operating Activities
Net Earnings (Loss)		(472	)	(58	)	744		662
Depreciation, Depletion and Amortization	11	531		468		1,946		1,833
Goodwill Impairment	13	497		—		497		—
Exploration Expense	10	85		5		86		50
Deferred Income Taxes	7	(37	)	33		359		244
Unrealized (Gain) Loss on Risk Management	21	(416	)	219		(596	)	415
Unrealized Foreign Exchange (Gain) Loss	6	190		(46	)	411		40
(Gain) Loss on Divestiture of Assets	12	1		—		(156	)	1
Unwinding of Discount on Decommissioning Liabilities	4,16	30		25		120		97
Other		(8	)	189		68		267
		401		835		3,479		3,609
Net Change in Other Assets and Liabilities		(38	)	(30	)	(135	)	(120	)
Net Change in Non-Cash Working Capital		505		171		182		50
Cash From Operating Activities		868		976		3,526		3,539
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	10	(81	)	(76	)	(279	)	(331	)
Capital Expenditures — Property, Plant and Equipment	11	(706	)	(824	)	(2,779	)	(2,938	)
Proceeds From Divestiture of Assets	12	1		16		276		258
Net Change in Investments and Other	14	(2	)	1,489		(1,583	)	1,486
Net Change in Non-Cash Working Capital		(10	)	33		15		6
Cash (Used in) Investing Activities		(798	)	638		(4,350	)	(1,519	)
Net Cash Provided (Used) Before Financing Activities		70		1,614		(824	)	2,020
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		(139	)	(9	)	(18	)	(8	)
Issuance of U.S. Unsecured Notes		—		—		—		814
Repayment of U.S. Unsecured Notes		—		—		—		(825	)
Proceeds on Issuance of Common Shares		—		5		28		28
Dividends Paid on Common Shares	8	(201	)	(183	)	(805	)	(732	)
Other		—		—		(2	)	(3	)
Cash From (Used in) Financing Activities		(340	)	(187	)	(797	)	(726	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(3	)	1		52		(2	)
Increase (Decrease) in Cash and Cash Equivalents		(273	)	1,428		(1,569	)	1,292
Cash and Cash Equivalents, Beginning of Period		1,156		1,024		2,452		1,160
Cash and Cash Equivalents, End of Period		883		2,452		883		2,452

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc. For the period ended December 31, 2014

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

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 publicly traded 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.

Certain information provided for the prior year has been reclassified to conform to the presentation adopted for the year ended December 31, 2014.

The following tabular financial information presents the segmented information first by segment, then by product and geographic location.

Cenovus Energy Inc. For the period ended December 31, 2014

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

A) Results of Operations — Segment and Operational Information

	Oil Sands				Conventional				Refining and Marketing
For the three months ended December 31,	2014		2013		2014		2013		2014		2013
Revenues
Gross Sales	1,064		1,075		657		692		2,773		3,223
Less: Royalties	55		38		45		42		—		—
	1,009		1,037		612		650		2,773		3,223
Expenses
Purchased Product	—		—		—		—		2,931		2,939
Transportation and Blending	494		517		83		75		—		—
Operating	145		153		161		179		182		143
Production and Mineral Taxes	—		—		10		5		—		—
(Gain) Loss on Risk Management	(97	)	(31	)	(36	)	(36	)	(18	)	(10	)
Operating Cash Flow	467		398		394		427		(322	)	151
Depreciation, Depletion and Amortization	166		133		303		279		40		36
Goodwill Impairment	—		—		497		—		—		—
Exploration Expense	3		—		82		5		—		—
Segment Income	298		265		(488	)	143		(362	)	115

	Corporate and Eliminations				Consolidated
For the three months ended December 31,	2014		2013		2014		2013
Revenues
Gross Sales	(156	)	(163	)	4,338		4,827
Less: Royalties	—		—		100		80
	(156	)	(163	)	4,238		4,747
Expenses
Purchased Product	(156	)	(163	)	2,775		2,776
Transportation and Blending	—		—		577		592
Operating	(2	)	(1	)	486		474
Production and Mineral Taxes	—		—		10		5
(Gain) Loss on Risk Management	(416	)	219		(567	)	142
	418		(218	)	957		758
Depreciation, Depletion and Amortization	22		20		531		468
Goodwill Impairment	—		—		497		—
Exploration Expense	—		—		85		5
Segment Income (Loss)	396		(238	)	(156	)	285
General and Administrative	67		81		67		81
Finance Costs	108		122		108		122
Interest Income	(2	)	(23	)	(2	)	(23	)
Foreign Exchange (Gain) Loss, Net	188		115		188		115
Research Costs	6		10		6		10
(Gain) Loss on Divestiture of Assets	1		—		1		—
Other (Income) Loss, Net	(4	)	2		(4	)	2
	364		307		364		307
Earnings (Loss) Before Income Tax					(520	)	(22	)
Income Tax Expense (Recovery)					(48	)	36
Net Earnings (Loss)					(472	)	(58	)

Cenovus Energy Inc. For the period ended December 31, 2014

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands				Conventional				Total
For the three months ended December 31,	2014		2013		2014		2013		2014		2013
Revenues
Gross Sales	1,054		1,053		478		544		1,532		1,597
Less: Royalties	53		38		43		40		96		78
	1,001		1,015		435		504		1,436		1,519
Expenses
Transportation and Blending	494		517		77		70		571		587
Operating	139		145		110		126		249		271
Production and Mineral Taxes	—		—		9		4		9		4
(Gain) Loss on Risk Management	(97	)	(30	)	(34	)	(20	)	(131	)	(50	)
Operating Cash Flow	465		383		273		324		738		707

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the three months ended December 31,	2014	2013		2014		2013		2014		2013
Revenues
Gross Sales	9	14		164		145		173		159
Less: Royalties	2	—		2		2		4		2
	7	14		162		143		169		157
Expenses
Transportation and Blending	—	—		6		5		6		5
Operating	5	6		48		52		53		58
Production and Mineral Taxes	—	—		1		1		1		1
(Gain) Loss on Risk Management	—	(1	)	(2	)	(16	)	(2	)	(17	)
Operating Cash Flow	2	9		109		101		111		110

	Other
	Oil Sands		Conventional		Total
For the three months ended December 31,	2014	2013	2014	2013	2014	2013
Revenues
Gross Sales	1	8	15	3	16	11
Less: Royalties	—	—	—	—	—	—
	1	8	15	3	16	11
Expenses
Transportation and Blending	—	—	—	—	—	—
Operating	1	2	3	1	4	3
Production and Mineral Taxes	—	—	—	—	—	—
(Gain) Loss on Risk Management	—	—	—	—	—	—
Operating Cash Flow	—	6	12	2	12	8

	Total Upstream
	Oil Sands				Conventional				Total
For the three months ended December 31,	2014		2013		2014		2013		2014		2013
Revenues
Gross Sales	1,064		1,075		657		692		1,721		1,767
Less: Royalties	55		38		45		42		100		80
	1,009		1,037		612		650		1,621		1,687
Expenses
Transportation and Blending	494		517		83		75		577		592
Operating	145		153		161		179		306		332
Production and Mineral Taxes	—		—		10		5		10		5
(Gain) Loss on Risk Management	(97	)	(31	)	(36	)	(36	)	(133	)	(67	)
Operating Cash Flow	467		398		394		427		861		825

Cenovus Energy Inc. For the period ended December 31, 2014

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

C) Geographic Information

	Canada			United States				Consolidated
For the three months ended December 31,	2014		2013	2014		2013		2014		2013
Revenues
Gross Sales	2,269		2,270	2,069		2,557		4,338		4,827
Less: Royalties	100		80	—		—		100		80
	2,169		2,190	2,069		2,557		4,238		4,747
Expenses
Purchased Product	541		497	2,234		2,279		2,775		2,776
Transportation and Blending	577		592	—		—		577		592
Operating	310		335	176		139		486		474
Production and Mineral Taxes	10		5	—		—		10		5
(Gain) Loss on Risk Management	(543	)	153	(24	)	(11	)	(567	)	142
	1,274		608	(317	)	150		957		758
Depreciation, Depletion and Amortization	490		432	41		36		531		468
Goodwill Impairment	497		—	—		—		497		—
Exploration Expense	85		5	—		—		85		5
Segment Income	202		171	(358	)	114		(156	)	285

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.

Cenovus Energy Inc. For the period ended December 31, 2014

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

D) Results of Operations — Segment and Operational Information

	Oil Sands				Conventional				Refining and Marketing
For the twelve months ended December 31,	2014		2013		2014		2013		2014		2013
Revenues
Gross Sales	5,036		3,912		3,225		2,980		12,658		12,706
Less: Royalties	236		132		229		204		—		—
	4,800		3,780		2,996		2,776		12,658		12,706
Expenses
Purchased Product	—		—		—		—		11,767		11,004
Transportation and Blending	2,131		1,749		346		325		—		—
Operating	647		555		718		708		707		540
Production and Mineral Taxes	—		—		46		35		—		—
(Gain) Loss on Risk Management	(38	)	(37	)	(1	)	(104	)	(27	)	19
Operating Cash Flow	2,060		1,513		1,887		1,812		211		1,143
Depreciation, Depletion and Amortization	625		446		1,082		1,170		156		138
Goodwill Impairment	—		—		497		—		—		—
Exploration Expense	4		—		82		114		—		—
Segment Income	1,431		1,067		226		528		55		1,005

	Corporate and Eliminations				Consolidated
For the twelve months ended December 31,	2014		2013		2014		2013
Revenues
Gross Sales	(812	)	(605	)	20,107		18,993
Less: Royalties	—		—		465		336
	(812	)	(605	)	19,642		18,657
Expenses
Purchased Product	(812	)	(605	)	10,955		10,399
Transportation and Blending	—		—		2,477		2,074
Operating	(6	)	(5	)	2,066		1,798
Production and Mineral Taxes	—		—		46		35
(Gain) Loss on Risk Management	(596	)	415		(662	)	293
	602		(410	)	4,760		4,058
Depreciation, Depletion and Amortization	83		79		1,946		1,833
Goodwill Impairment	—		—		497		—
Exploration Expense	—		—		86		114
Segment Income (Loss)	519		(489	)	2,231		2,111
General and Administrative	358		349		358		349
Finance Costs	445		529		445		529
Interest Income	(33	)	(96	)	(33	)	(96	)
Foreign Exchange (Gain) Loss, Net	411		208		411		208
Research Costs	15		24		15		24
(Gain) Loss on Divestiture of Assets	(156	)	1		(156	)	1
Other (Income) Loss, Net	(4	)	2		(4	)	2
	1,036		1,017		1,036		1,017
Earnings Before Income Tax					1,195		1,094
Income Tax Expense					451		432
Net Earnings					744		662

Cenovus Energy Inc. For the period ended December 31, 2014

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

E) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands				Conventional			Total
For the twelve months ended December 31,	2014		2013		2014	2013		2014		2013
Revenues
Gross Sales	4,963		3,850		2,456	2,373		7,419		6,223
Less: Royalties	233		131		217	196		450		327
	4,730		3,719		2,239	2,177		6,969		5,896
Expenses
Transportation and Blending	2,130		1,748		326	305		2,456		2,053
Operating	622		531		512	495		1,134		1,026
Production and Mineral Taxes	—		—		37	32		37		32
(Gain) Loss on Risk Management	(38	)	(33	)	4	(43	)	(34	)	(76	)
Operating Cash Flow	2,016		1,473		1,360	1,388		3,376		2,861

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the twelve months ended December 31,	2014	2013		2014		2013		2014		2013
Revenues
Gross Sales	67	38		744		594		811		632
Less: Royalties	3	1		12		8		15		9
	64	37		732		586		796		623
Expenses
Transportation and Blending	1	1		20		20		21		21
Operating	18	18		200		209		218		227
Production and Mineral Taxes	—	—		9		3		9		3
(Gain) Loss on Risk Management	—	(4	)	(5	)	(61	)	(5	)	(65	)
Operating Cash Flow	45	22		508		415		553		437

	Other
	Oil Sands			Conventional		Total
For the twelve months ended December 31,	2014		2013	2014	2013	2014	2013
Revenues
Gross Sales	6		24	25	13	31	37
Less: Royalties	—		—	—	—	—	—
	6		24	25	13	31	37
Expenses
Transportation and Blending	—		—	—	—	—	—
Operating	7		6	6	4	13	10
Production and Mineral Taxes	—		—	—	—	—	—
(Gain) Loss on Risk Management	—		—	—	—	—	—
Operating Cash Flow	(1	)	18	19	9	18	27

	Total Upstream
	Oil Sands				Conventional				Total
For the twelve months ended December 31,	2014		2013		2014		2013		2014		2013
Revenues
Gross Sales	5,036		3,912		3,225		2,980		8,261		6,892
Less: Royalties	236		132		229		204		465		336
	4,800		3,780		2,996		2,776		7,796		6,556
Expenses
Transportation and Blending	2,131		1,749		346		325		2,477		2,074
Operating	647		555		718		708		1,365		1,263
Production and Mineral Taxes	—		—		46		35		46		35
(Gain) Loss on Risk Management	(38	)	(37	)	(1	)	(104	)	(39	)	(141	)
Operating Cash Flow	2,060		1,513		1,887		1,812		3,947		3,325

Cenovus Energy Inc. For the period ended December 31, 2014

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

F) Geographic Information

	Canada			United States			Consolidated
For the twelve months ended December 31,	2014		2013	2014		2013	2014		2013
Revenues
Gross Sales	10,604		8,943	9,503		10,050	20,107		18,993
Less: Royalties	465		336	—		—	465		336
	10,139		8,607	9,503		10,050	19,642		18,657
Expenses
Purchased Product	2,310		2,022	8,645		8,377	10,955		10,399
Transportation and Blending	2,477		2,074	—		—	2,477		2,074
Operating	1,387		1,276	679		522	2,066		1,798
Production and Mineral Taxes	46		35	—		—	46		35
(Gain) Loss on Risk Management	(625	)	275	(37	)	18	(662	)	293
	4,544		2,925	216		1,133	4,760		4,058
Depreciation, Depletion and Amortization	1,790		1,695	156		138	1,946		1,833
Goodwill Impairment	497		—	—		—	497		—
Exploration Expense	86		114	—		—	86		114
Segment Income	2,171		1,116	60		995	2,231		2,111

G) 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 December 31, 2014 was $382 million and $(321) million, respectively (three months ended December 31, 2013 — $355 million and $154 million). Cenovus’s share of operating cash flow from FCCL and WRB for the year ended December 31, 2014 was $1,933 million and $214 million, respectively (year ended December 31, 2013 — $1,383 million and $1,144 million).

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

By Segment

	E&E (1)		PP&E (2)
	December 31,	December 31,	December 31,	December 31,
As at	2014	2013	2014	2013
Oil Sands	1,540	1,328	8,606	7,401
Conventional	85	145	6,038	6,291
Refining and Marketing	—	—	3,568	3,269
Corporate and Eliminations	—	—	351	373
Consolidated	1,625	1,473	18,563	17,334

	Goodwill		Total Assets
	December 31,	December 31,	December 31,	December 31,
As at	2014	2013	2014	2013
Oil Sands	242	242	11,024	9,564
Conventional	—	497	6,211	7,220
Refining and Marketing	—	—	5,520	5,491
Corporate and Eliminations	—	—	1,940	2,949
Consolidated	242	739	24,695	25,224

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

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

Cenovus Energy Inc. For the period ended December 31, 2014

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

By Geographic Region

	E&E		PP&E
	December 31,	December 31,	December 31,	December 31,
As at	2014	2013	2014	2013
Canada	1,625	1,473	14,999	14,066
United States	—	—	3,564	3,268
Consolidated	1,625	1,473	18,563	17,334

	Goodwill		Total Assets
	December 31,	December 31,	December 31,	December 31,
As at	2014	2013	2014	2013
Canada	242	739	20,231	20,548
United States	—	—	4,464	4,676
Consolidated	242	739	24,695	25,224

I) Capital Expenditures (1)

	Three Months Ended		Twelve Months Ended
For the period ended December 31,	2014	2013	2014	2013
Capital
Oil Sands	494	502	1,986	1,885
Conventional	219	331	840	1,189
Refining and Marketing	52	37	163	107
Corporate	21	28	62	81
	786	898	3,051	3,262
Acquisition Capital
Oil Sands (2)	—	26	15	27
Conventional	1	1	3	5
	787	925	3,069	3,294

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

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

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, 2013, 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, 2013, 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 February 11, 2015.

Cenovus Energy Inc. For the period ended December 31, 2014

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

3. RECENT ACCOUNTING PRONOUNCEMENTS

A) New and Amended Accounting Standards and Interpretations Adopted

Offsetting Financial Assets and Financial Liabilities

Effective January 1, 2014, the Company adopted, as required, amendments to IAS 32, “Financial Instruments: Presentation” (“IAS 32”). The amendments clarify that the right to offset financial assets and liabilities must be available on the current date and cannot be contingent on a future event. The adoption of IAS 32 did not impact the interim Consolidated Financial Statements.

B) New Accounting Standards and Interpretations not yet Adopted

Revenue Recognition

On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing International Accounting Standard 11, “Construction Contracts” (“IAS 11”), IAS 18, “Revenue” (“IAS 18”), and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive, when control is transferred to the purchaser. Disclosure requirements have also been expanded.

The new standard is effective for annual periods beginning on or after January 1, 2017, with earlier adoption permitted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.

Financial Instruments

On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”).

IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Cenovus does not currently apply hedge accounting.

IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.

4. FINANCE COSTS

	Three Months Ended		Twelve Months Ended
For the period ended December 31,	2014	2013	2014	2013
Interest Expense — Short-Term Borrowings and Long-Term Debt	73	68	285	271
Premium on Redemption of Long-Term Debt	—	—	—	33
Interest Expense — Partnership Contribution Payable (Note 14)	—	23	22	98
Unwinding of Discount on Decommissioning Liabilities (Note 16)	30	25	120	97
Other	5	6	18	30
	108	122	445	529

Cenovus Energy Inc. For the period ended December 31, 2014

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

5. INTEREST INCOME

	Three Months Ended				Twelve Months Ended
For the period ended December 31,	2014		2013		2014		2013
Interest Income — Partnership Contribution Receivable (1)	—		(17	)	—		(82	)
Other	(2	)	(6	)	(33	)	(14	)
	(2	)	(23	)	(33	)	(96	)

(1) Principal and accrued interest on Partnership Contribution Receivable was received December 17, 2013.

6. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended				Twelve Months Ended
For the period ended December 31,	2014		2013		2014		2013
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	186		167		458		357
U.S. Dollar Partnership Contribution Receivable Issued From Canada	—		(206	)	—		(305	)
Other	4		(7	)	(47	)	(12	)
Unrealized Foreign Exchange (Gain) Loss	190		(46	)	411		40
Realized Foreign Exchange (Gain) Loss	(2	)	161		—		168
	188		115		411		208

7. INCOME TAXES

The provision for income taxes is:

	Three Months Ended				Twelve Months Ended
For the period ended December 31,	2014		2013		2014		2013
Current Tax
Canada	12		(4	)	94		143
United States	(23	)	7		(2	)	45
Total Current Tax	(11	)	3		92		188
Deferred Tax	(37	)	33		359		244
	(48	)	36		451		432

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

	Twelve Months Ended
For the period ended December 31,	2014		2013
Earnings Before Income Tax	1,195		1,094
Canadian Statutory Rate	25.2	%	25.2	%
Expected Income Tax	301		276
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(43	)	87
Non-Deductible Stock-Based Compensation	13		10
Foreign Exchange Gains (Losses) Not Included in Net Earnings	(13	)	19
Non-Taxable Capital (Gains) Losses	124		31
Derecognition (Recognition) of Capital Losses	(9	)	15
Adjustments Arising From Prior Year Tax Filings	(16	)	(13	)
Goodwill Impairment	125		—
Other	(31	)	7
Total Tax	451		432
Effective Tax Rate	37.7	%	39.5	%

Cenovus Energy Inc. For the period ended December 31, 2014

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

8. PER SHARE AMOUNTS

A) Net Earnings Per Share

	Three Months Ended						Twelve Months Ended
For the period ended December 31,	2014			2013			2014		2013
Net Earnings (Loss) — Basic and Diluted ($ millions)	(472		)	(58		)	744		662
Basic — Weighted Average Number of Shares (millions)	757.1			755.9			756.9		755.9
Dilutive Effect of Cenovus TSARs (1)	—			1.3			0.7		1.6
Dilutive Effect of Cenovus NSRs (2)	—			—			—		—
Diluted — Weighted Average Number of Shares	757.1			757.2			757.6		757.5
Net Earnings (Loss) Per Common Share ($)
Basic	$	(0.62	)	$	(0.08	)	$	0.98	$	0.88
Diluted	$	(0.62	)	$	(0.08	)	$	0.98	$	0.87

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

(2) Net settlement rights (“NSRs”).

B) Dividends Per Share

The Company paid dividends of $805 million or $1.0648 per share for the year ended December 31, 2014 (December 31, 2013 — $732 million, $0.968 per share). The Cenovus Board of Directors declared a first quarter dividend of $0.2662 per share, payable on March 31, 2015, to common shareholders of record as of March 13, 2015.

9. INVENTORIES

	December 31,	December 31,
As at	2014	2013
Product
Refining and Marketing	972	1,047
Oil Sands	182	156
Conventional	28	17
Parts and Supplies	42	39
	1,224	1,259

As a result of a decline in refined product and crude oil prices, Cenovus recorded a write-down of its product inventory of $131 million from cost to net realizable value as at December 31, 2014.

Cenovus Energy Inc. For the period ended December 31, 2014

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

10. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2012	1,285
Additions	331
Transfers to PP&E (Note 11)	(95	)
Exploration Expense	(50	)
Divestitures	(17	)
Change in Decommissioning Liabilities	19
As at December 31, 2013	1,473
Additions	279
Transfers to PP&E (Note 11)	(53	)
Exploration Expense	(86	)
Divestitures	(2	)
Change in Decommissioning Liabilities	14
As at December 31, 2014	1,625

E&E assets consist of the Company’s evaluation 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 year ended December 31, 2014 include $51 million of internal costs directly related to the evaluation of these projects (year ended December 31, 2013 — $60 million). No borrowing costs or costs classified as general and administrative expenses have been capitalized during the year ended December 31, 2014 (2013 — $nil).

For the year ended December 31, 2014, $53 million of E&E assets were transferred to PP&E — development and production assets following the determination of technical feasibility and commercial viability of the projects (year ended December 31, 2013 — $95 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. For the year ended December 31, 2014, $82 million of previously capitalized E&E costs related to exploration assets within the Northern Alberta CGU were deemed not to be technically feasible and commercially viable and were recorded as exploration expense in the Conventional segment. In addition, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense in the Oil Sands segment.

In 2013, $50 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially viable and were recorded as exploration expense in the Conventional segment.

Cenovus Energy Inc. For the period ended December 31, 2014

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

11. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development  & Production		OtherUpstream	RefiningEquipment		Other (1)		Total
COST
As at December 31, 2012	27,003		238	3,399		767		31,407
Additions	2,702		48	106		82		2,938
Transfers From E&E Assets (Note 10)	95		—	—		—		95
Transfers to Assets Held for Sale	(450	)	—	—		—		(450	)
Change in Decommissioning Liabilities	40		—	(1	)	—		39
Exchange Rate Movements and Other	—		—	150		—		150
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 10)	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
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2012	14,390		158	311		396		15,255
Depreciation, Depletion and Amortization	1,522		35	138		79		1,774
Transfers to Assets Held for Sale	(180	)	—	—		—		(180	)
Impairment Losses	59		—	—		—		59
Exchange Rate Movements and Other	—		—	(63	)	—		(63	)
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
CARRYING VALUE
As at December 31, 2012	12,613		80	3,088		371		16,152
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

(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 $216 million for the year ended December 31, 2014 (year ended December 31, 2013 — $204 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 year ended December 31, 2014 (2013 — $nil).

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

	December 31,	December 31,
As at	2014	2013
Development and Production	478	225
Refining Equipment	159	97
	637	322

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.

Cenovus Energy Inc. For the period ended December 31, 2014

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

DD&A expense includes impairment losses as follows:

	Three Months Ended		Twelve Months Ended
For the period ended December 31,	2014	2013	2014	2013
Development and Production	52	—	65	59
Refining Equipment	—	—	—	—
	52	—	65	59

In the fourth quarter of 2014, the Company impaired equipment for $52 million. The Company does not have future plans for the equipment and does not believe it will recover the carrying amount through a sale. The asset has been written down to fair value less costs of disposal. In the second quarter of 2014, a minor natural gas property was shut-in and abandonment commenced. These impairments have been recorded in DD&A in the Conventional segment.

In 2013, the Company impaired its Lower Shaunavon asset for $57 million prior to its divestiture. The impairment was recorded in DD&A in the Conventional segment.

12. DIVESTITURES

In the third quarter, the Company completed the sale of certain Wainwright properties to an unrelated third party for net proceeds of $234 million. A gain of $137 million was recorded on the sale. These assets, related liabilities and results of operations were reported in the Conventional segment.

In the second quarter, the Company completed the sale of certain Bakken properties to an unrelated third party for net proceeds of $35 million, resulting in a gain of $16 million. The Company also completed the sale of certain non-core properties and recorded a total gain of $4 million. These assets, related liabilities and results of operations were reported in the Conventional segment.

In 2013, the Company completed the sale of the Lower Shaunavon asset to an unrelated third party for net proceeds of $241 million, resulting in a loss of $2 million. These assets, related liabilities and results of operations were reported in the Conventional segment. Other divestitures in 2013 included undeveloped land in northern Alberta, cancellation of some of the Company’s non-core Oil Sands mineral rights under the Lower Athabasca Regional Plan and a third-party land exchange.

13. GOODWILL

	December 31,		December 31,
As at	2014		2013
Carrying Value, Beginning of Year	739		739
Impairment	(497	)	—
Carrying Value, End of Year	242		739

There were no additions to goodwill during the years ended December 31, 2014 and 2013.

Impairment Test for CGUs Containing Goodwill

For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. All of the Company’s goodwill arose in 2002 upon the formation of the predecessor corporation. The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:

	December 31,	December 31,
As at	2014	2013
Primrose (Foster Creek)	242	242
Northern Alberta	—	497
	242	739

Cenovus Energy Inc. For the period ended December 31, 2014

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

At December 31, 2014, the Company determined that the carrying amount of the Northern Alberta CGU exceeded its recoverable amount and the full amount of the impairment was attributed to goodwill. An impairment loss of $497 million was recorded as goodwill impairment on the Consolidated Statements of Earnings and Comprehensive Income. The Northern Alberta CGU includes the Pelican Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage. The operating results of the CGU are included in the Conventional segment. Future cash flows for the CGU declined due to lower crude oil prices and a slowing down of the Pelican Lake development plan.

The recoverable amount was determined using fair value less costs of disposal. The fair value for producing properties was calculated based on discounted after-tax cash flows of proved and probable reserves using forecast prices and cost estimates, consistent with Cenovus’s independent qualified reserves evaluators (Level 3). The fair value of E&E assets was determined using market comparable transactions (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a rate of 11 percent. To assess reasonableness, an evaluation of fair value based on comparable asset transactions was also completed. As at December 31, 2014, the recoverable amount of the Northern Alberta CGU was estimated to be $2.3 billion.

There were no impairments of goodwill in the year ended December 31, 2013.

Crude Oil and Natural Gas Prices

The future prices used to determine cash flows from crude oil and natural gas reserves are:

	2015	2016	2017	2018	2019	AverageAnnual %Change to2025
WTI (US$/barrel) (1)	65.00	75.00	80.00	84.90	89.30	2.5	%
WCS ($/barrel) (2)	57.60	69.90	74.70	79.50	83.70	2.5	%
AECO ($/Mcf) (3)	3.50	4.00	4.25	4.50	4.70	4.1	%

(1) West Texas Intermediate (“WTI”).

(2) Western Canadian Select (“WCS”).

(3) Assumes gas heating value of 1 million British Thermal Units per thousand cubic feet.

Discount and Inflation Rates

Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is estimated at two percent, which is common industry practice and used by Cenovus’s independent qualified reserves evaluators in preparing their reserves reports. Based on the individual characteristics of the asset, other economic and operating factors are also considered, which may increase or decrease the implied discount rate. Changes in economic conditions could significantly change the estimated recoverable amount.

There were no impairments of goodwill in the year ended December 31, 2013.

Sensitivities

Changes to the assumed discount rate or forward price estimates over the life of the reserves independently would have the following impact on the impairment of the Northern Alberta CGU:

	One Percent  Increase in theDiscount Rate	Five Percent  Decrease in the  Forward Price  Estimates
Impairment of Goodwill	—	—
Impairment of PP&E	134	419

14. PARTNERSHIP CONTRIBUTION PAYABLE

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

Cenovus Energy Inc. For the period ended December 31, 2014

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

15. LONG-TERM DEBT

	December 31,		December 31,
As at	2014		2013
Revolving Term Debt (1)	—		—
U.S. Dollar Denominated Unsecured Notes	5,510		5,052
Total Debt Principal	5,510		5,052
Debt Discounts and Transaction Costs	(52	)	(55	)
	5,458		4,997

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

As at December 31, 2014, the Company is in compliance with all of the terms of its debt agreements.

On June 24, 2014, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at December 31, 2014, no notes have been issued under this U.S. base shelf prospectus. The U.S. base shelf prospectus expires in July 2016.

On June 25, 2014, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian base shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at December 31, 2014, no medium term notes have been issued under this Canadian base shelf prospectus. The Canadian base shelf prospectus expires in July 2016.

In November 2014, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2018.

16. 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:

	December 31,		December 31,
As at	2014		2013
Decommissioning Liabilities, Beginning of Year	2,370		2,315
Liabilities Incurred	48		45
Liabilities Settled	(93	)	(76	)
Liabilities Divested	(60	)	—
Transfers and Reclassifications	(9	)	(26	)
Change in Estimated Future Cash Flows	115		414
Change in Discount Rate	122		(401	)
Unwinding of Discount on Decommissioning Liabilities	120		97
Foreign Currency Translation	3		2
Decommissioning Liabilities, End of Year	2,616		2,370

The undiscounted amount of estimated future cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 4.9 percent as at December 31, 2014 (December 31, 2013 — 5.2 percent). The Company expects to settle approximately $50 million to $100 million of decommissioning liabilities over the next year.

Cenovus Energy Inc. For the period ended December 31, 2014

21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

17. 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

	December 31, 2014		December 31, 2013
As at	Number of  Common  Shares(Thousands)	Amount	Number of  Common  Shares(Thousands)		Amount
Outstanding, Beginning of Year	756,046	3,857	755,843		3,829
Common Shares Issued Under Stock Option Plans	1,057	32	970		31
Common Shares Cancelled	—	—	(767	)	(3	)
Outstanding, End of Year	757,103	3,889	756,046		3,857

There were no preferred shares outstanding as at December 31, 2014 (December 31, 2013 — nil).

As at December 31, 2014, there were 13 million (December 31, 2013 — 24 million) common shares available for future issuance under stock option plans.

18. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at December 31, 2014	Defined  Benefit Plan		Foreign  Currency  Translation	Availablefor Sale  Investments	Total
Balance, Beginning of Year	(12	)	212	10	210
Other Comprehensive Income (Loss), Before Tax	(24	)	215	—	191
Income Tax	6		—	—	6
Balance, End of Year	(30	)	427	10	407

As at December 31, 2013	Defined  Benefit Plan		Foreign  Currency  Translation	Availablefor Sale  Investments		Total
Balance, Beginning of Year	(26	)	95	—		69
Other Comprehensive Income (Loss), Before Tax	18		117	13		148
Income Tax	(4	)	—	(3	)	(7	)
Balance, End of Year	(12	)	212	10		210

19. 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 December 31, 2014	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	5.13	32.63	23.97	40,549
TSARs	Prior to February 17, 2010	5	0.07	25.58	23.97	21
TSARs	On or After February 17, 2010	7	2.20	26.72	23.97	3,841

Cenovus Energy Inc. For the period ended December 31, 2014

22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

NSRs

The weighted average unit fair value of NSRs granted during the year ended December 31, 2014 was $4.70 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 December 31, 2014	Number of  NSRs (Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	26,315		35.26
Granted	16,307		28.59
Exercised	(125	)	32.24
Forfeited	(1,948	)	34.31
Outstanding, End of Year	40,549		32.63
Exercisable, End of Year	13,439		36.18

For options exercised during the year, the weighted average market price of Cenovus’s common shares at the date of exercise was $34.06.

TSARs

The Company has recorded a liability of $8 million as at December 31, 2014 (December 31, 2013 — $33 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 December 31, 2014 was $nil (December 31, 2013 — $27 million).

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

As at December 31, 2014	Number of  TSARs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	7,086		26.56
Exercised for Cash Payment	(2,106	)	26.34
Exercised as Options for Common Shares	(1,044	)	26.38
Forfeited	(13	)	28.66
Expired	(61	)	26.38
Outstanding, End of Year	3,862		26.72
Exercisable, End of Year	3,862		26.72

For options exercised during the year, the weighted average market price of Cenovus’s common shares at the date of exercise was $30.14.

B) Performance Share Units

The Company has recorded a liability of $109 million as at December 31, 2014 (December 31, 2013 — $103 million) in the Consolidated Balance Sheets for performance share units (“PSUs”) based on the market value of Cenovus’s common shares as at December 31, 2014. The intrinsic value of vested PSUs was $nil as at December 31, 2014 and December 31, 2013 as PSUs are paid out upon vesting.

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

As at December 31, 2014	Number of  PSUs(Thousands)
Outstanding, Beginning of Year	5,785
Granted	3,012
Vested and Paid Out	(1,625	)
Cancelled	(328	)
Units in Lieu of Dividends	255
Outstanding, End of Year	7,099

Cenovus Energy Inc. For the period ended December 31, 2014

23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

C) Deferred Share Units

The Company has recorded a liability of $31 million as at December 31, 2014 (December 31, 2013 — $36 million) in the Consolidated Balance Sheets for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares as at December 31, 2014. 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 December 31, 2014	Number of  DSUs(Thousands)
Outstanding, Beginning of Year	1,192
Granted to Directors	57
Granted From Annual Bonus Awards	7
Units in Lieu of Dividends	46
Redeemed	(5	)
Outstanding, End of Year	1,297

D) 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				Twelve Months Ended
For the period ended December 31,	2014		2013		2014		2013
NSRs	8		9		41		35
TSARs	(7	)	(5	)	(10	)	(16	)
PSUs	(15	)	—		34		32
DSUs	(7	)	—		(5	)	—
Stock-Based Compensation Expense (Recovery)	(21	)	4		60		51

20. 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 excluding any amounts with respect to the Partnership Contribution Payable. 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.

	December 31,		December 31,
As at	2014		2013
Long-Term Debt	5,458		4,997
Shareholders’ Equity	10,186		9,946
Capitalization	15,644		14,943
Debt to Capitalization	35	%	33	%

Cenovus Energy Inc. For the period ended December 31, 2014

24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

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

	December 31,		December 31,
As at	2014		2013
Debt	5,458		4,997
Net Earnings	744		662
Add (Deduct):
Finance Costs	445		529
Interest Income	(33	)	(96	)
Income Tax Expense	451		432
Depreciation, Depletion and Amortization	1,946		1,833
Goodwill Impairment	497		—
E&E Impairment	86		50
Unrealized (Gain) Loss on Risk Management	(596	)	415
Foreign Exchange (Gain) Loss, Net	411		208
(Gain) Loss on Divestitures of Assets	(156	)	1
Other (Income) Loss, Net	(4	)	2
Adjusted EBITDA	3,791		4,036
Debt to Adjusted EBITDA	1.4x		1.2x

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 December 31, 2014, 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 December 31, 2014, Cenovus is in compliance with all of the terms of its debt agreements.

21. 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, Partnership Contribution Payable, 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 the Partnership Contribution Payable and 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 December 31, 2014, the carrying value of Cenovus’s long-term debt was $5,458 million and the fair value was $5,726 million (December 31, 2013 carrying value — $4,997 million, fair value — $5,388 million).

Cenovus Energy Inc. For the period ended December 31, 2014

25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

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:

	December 31,		December 31,
As at	2014		2013
Fair Value, Beginning of Year	32		14
Acquisition of Investments	4		5
Reclassification of Equity Investments	(4	)	—
Change in Fair Value (1)	—		13
Fair Value, End of Year	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 December 31, 2014 range from $33.50 to $54.75 per Megawatt Hour.

Summary of Unrealized Risk Management Positions

	December 31, 2014				December 31, 2013
	Risk Management				Risk Management
As at	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Crude Oil	423	7	416		10	136	(126	)
Natural Gas	55	—	55		—	—	—
Power	—	9	(9	)	—	3	(3	)
Total Fair Value	478	16	462		10	139	(129	)

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

	December 31,		December 31,
As at	2014		2013
Prices Sourced From Observable Data or Market Corroboration (Level 2)	471		(126	)
Prices Determined From Unobservable Inputs (Level 3)	(9	)	(3	)
	462		(129	)

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 December 31:

	2014		2013
Fair Value of Contracts, Beginning of Year	(129	)	270
Fair Value of Contracts Realized During the Year (1)	(66	)	(122	)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year (1)	662		(293	)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(5	)	16
Fair Value of Contracts, End of Year	462		(129	)

(1) Includes a realized gain of $4 million and a decrease in fair value of $10 million related to the power contracts.

Cenovus Energy Inc. For the period ended December 31, 2014

26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

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

	Three Months Ended				Twelve Months Ended
For the period ended December 31,	2014		2013		2014		2013
Realized (Gain) Loss (1)	(151	)	(77	)	(66	)	(122	)
Unrealized (Gain) Loss (2)	(416	)	219		(596	)	415
(Gain) Loss on Risk Management	(567	)	142		(662	)	293

(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.

22. 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, 2013. The Company’s exposure to these risks has not changed significantly since December 31, 2013.

Net Fair Value of Commodity Price Positions as at December 31, 2014

As at December 31, 2014	Notional Volumes	Term	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	18,000 bbls/d	2015	$113.75/bbl	269
Brent Fixed Price	1,000 bbls/d	January - June 2015	$100.25/bbl	5
Brent Fixed Price	6,000 bbls/d	January - June 2015	US$65.03/bbl	6
WCS Differential (1)	5,000 bbls/d	January - June 2015	US$(19.85)/bbl	(2	)
Brent Collars	10,000 bbls/d	2015	$105.25 - $123.57/bbl	121
Other Financial Positions (2)				17
Crude Oil Fair Value Position				416
Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price	149 MMcf/d	2015	$3.86/Mcf	55
Natural Gas Fair Value Position				55
Power Purchase Contracts
Power Fair Value Position				(9	)

(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.

Cenovus Energy Inc. For the period ended December 31, 2014

27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended December 31, 2014

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 December 31, 2014

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent, WTI and Condensate Hedges	(145	)	146
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges Tied to Production	5		(5	)
Natural Gas Commodity Price	± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges	(70	)	70
Power Commodity Price	± $25 per MWHr Applied to Power Hedge	19		(19	)

23. COMMITMENTS AND CONTINGENCIES

A) Commitments

During the year ended December 31, 2014, the Company’s various firm transportation agreements increased by $7 billion due primarily to increased costs and tolls on existing commitments, resulting in total transportation commitments of $28 billion. These agreements, some of which are subject to regulatory approval, are for terms up to 20 years subsequent to the date of commencement.

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. For the period ended December 31, 2014

28

Cenovus Energy Inc.

Interim Supplemental Information

(unaudited)

For the period ended December 31, 2014

(Canadian Dollars)

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

	2014										2013
Revenues	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Gross Sales
Upstream	8,261		1,721		2,147		2,295		2,098		6,892		1,767		1,926		1,646		1,553
Refining and Marketing	12,658		2,773		3,144		3,483		3,258		12,706		3,223		3,459		3,078		2,946
Corporate and Eliminations	(812	)	(156	)	(197	)	(218	)	(241	)	(605	)	(163	)	(190	)	(130	)	(122	)
Less: Royalties	465		100		124		138		103		336		80		120		78		58
Revenues	19,642		4,238		4,970		5,422		5,012		18,657		4,747		5,075		4,516		4,319

	2014							2013
Operating Cash Flow	Year	Q4		Q3	Q2	Q1		Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids
Foster Creek	965	228		297	227	213		877	204	252	232	189
Christina Lake	1,051	237		308	291	215		596	179	248	96	73
Pelican Lake	403	80		111	119	93		385	92	130	96	67
Other Conventional	957	193		241	269	254		1,003	232	285	251	235
Natural Gas	553	111		129	162	151		437	110	94	118	115
Other Upstream Operations	18	12		—	8	(2	)	27	8	5	8	6
	3,947	861		1,086	1,076	924		3,325	825	1,014	801	685
Refining and Marketing	211	(322	)	68	220	245		1,143	151	139	324	529
Operating Cash Flow (1)	4,158	539		1,154	1,296	1,169		4,468	976	1,153	1,125	1,214

		2014										2013
Cash Flow		Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Cash from Operating Activities		3,526		868		1,092		1,109		457		3,539		976		840		828		895
Deduct (Add back):
Net Change in Other Assets and Liabilities		(135	)	(38	)	(28	)	(27	)	(42	)	(120	)	(30	)	(25	)	(31	)	(34	)
Net Change in Non-Cash Working Capital		182		505		135		(53	)	(405	)	50		171		(67	)	(12	)	(42	)
Cash Flow (2)		3,479		401		985		1,189		904		3,609		835		932		871		971
Per Share	- Basic	4.60		0.53		1.30		1.57		1.20		4.77		1.10		1.23		1.15		1.28
	- Diluted	4.59		0.53		1.30		1.57		1.19		4.76		1.10		1.23		1.15		1.28

		2014						2013
Earnings		Year	Q4		Q3	Q2	Q1	Year	Q4		Q3	Q2	Q1
Operating Earnings (Loss) (3)		633	(590	)	372	473	378	1,171	212		313	255	391
Per Share	- Diluted	0.84	(0.78	)	0.49	0.62	0.50	1.55	0.28		0.41	0.34	0.52
Net Earnings (Loss)		744	(472	)	354	615	247	662	(58	)	370	179	171
Per Share	- Basic	0.98	(0.62	)	0.47	0.81	0.33	0.88	(0.08	)	0.49	0.24	0.23
	- Diluted	0.98	(0.62	)	0.47	0.81	0.33	0.87	(0.08	)	0.49	0.24	0.23

	2014						2013
Tax & Exchange Rates	Year		Q4	Q3	Q2	Q1	Year		Q4	Q3	Q2	Q1
Effective Tax Rates using
Net Earnings	37.7	%					39.5	%
Operating Earnings, excluding Divestitures	29.7	%					31.4	%
Canadian Statutory Rate	25.2	%					25.2	%
U.S. Statutory Rate	38.1	%					38.5	%
Foreign Exchange Rates (US$ per C$1)
Average	0.905		0.881	0.918	0.917	0.906	0.971		0.953	0.963	0.977	0.992
Period end	0.862		0.862	0.892	0.937	0.905	0.940		0.940	0.972	0.951	0.985

(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.

	2014										2013
Financial Metrics (Non-GAAP measures)	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Debt to Capitalization (4), (5)	35	%	35	%	33	%	33	%	36	%	33	%	33	%	32	%	33	%	33	%
Net Debt to Capitalization (4), (6)	31	%	31	%	28	%	30	%	32	%	29	%	29	%	28	%	30	%	28	%
Debt to Adjusted EBITDA (5), (7)	1.4	x	1.4	x	1.3	x	1.2	x	1.4	x	1.2	x	1.2	x	1.2	x	1.2	x	1.1	x
Net Debt to Adjusted EBITDA (6), (7)	1.2	x	1.2	x	1.0	x	1.1	x	1.2	x	1.0	x	1.0	x	1.0	x	1.0	x	0.9	x
Return on Capital Employed (8)	6	%	6	%	9	%	9	%	7	%	6	%	6	%	6	%	5	%	7	%
Return on Common Equity (9)	7	%	7	%	11	%	12	%	7	%	7	%	7	%	6	%	5	%	8	%

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

(5)Debt includes the Company’s short-term borrowings and the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable.

(6)Net debt includes the Company’s short-term borrowings, current and long-term portions of long-term debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents and the current and long-term portions of the Partnership Contribution Receivable.

(7)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 12-month basis.

(8)Return on capital employed is calculated, on a trailing 12-month basis, as net earnings before after-tax interest divided by average shareholders’ equity plus average debt.

(9)Return on common equity is calculated, on a trailing 12-month basis, as net earnings divided by average shareholders’ equity.

Cenovus Energy Inc.	Supplemental Information
	for the period ended December 31, 2014

2

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

	2014										2013
Common Share Information	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Common Shares Outstanding (millions)
Period End	757.1		757.1		757.1		757.0		756.9		756.0		756.0		755.8		755.8		755.8
Average - Basic	756.9		757.1		757.1		756.9		756.4		755.9		755.9		755.8		755.8		756.0
Average - Diluted	757.6		757.1		758.8		758.0		757.3		757.5		757.2		757.2		757.1		758.4
Price Range ($ per share)
TSX - C$
High	34.79		30.13		34.79		34.70		32.02		34.13		31.69		32.77		32.08		34.13
Low	18.72		18.72		29.77		30.80		28.25		28.32		29.33		28.98		28.32		31.09
Close	23.97		23.97		30.13		34.59		31.97		30.40		30.40		30.74		30.00		31.46
NYSE - US$
High	32.64		26.89		32.64		32.44		28.96		34.50		30.34		31.60		31.58		34.50
Low	16.11		16.11		26.57		28.35		25.52		27.25		27.60		28.00		27.25		30.58
Close	20.62		20.62		26.88		32.37		28.96		28.65		28.65		29.85		28.52		30.99
Dividends Paid ($ per share)	$	1.0648	$	0.2662	$	0.2662	$	0.2662	$	0.2662	$	0.968	$	0.242	$	0.242	$	0.242	$	0.242
Share Volume Traded (millions)	803.8		333.1		147.7		152.7		170.3		685.7		146.2		183.0		201.6		154.9

	2014										2013
Net Capital Investment	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2	Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	796		159		207		209		221		797		193		205		189	210
Christina Lake	794		231		198		183		182		688		189		162		162	175
Total	1,590		390		405		392		403		1,485		382		367		351	385
Other Oil Sands	396		104		89		79		124		400		120		59		69	152
	1,986		494		494		471		527		1,885		502		426		420	537
Conventional
Pelican Lake	246		46		61		68		71		463		115		97		111	140
Other Conventional	594		173		137		85		199		726		216		178		134	198
	840		219		198		153		270		1,189		331		275		245	338
Refining and Marketing	163		52		42		46		23		107		37		19		26	25
Corporate	62		21		16		16		9		81		28		23		15	15
Capital Investment	3,051		786		750		686		829		3,262		898		743		706	915
Acquisitions (1)	18		1		—		16		1		32		27		1		1	3
Divestitures	(277	)	(1	)	(235	)	(39	)	(2	)	(283	)	(41	)	(241	)	—	(1	)
Net Acquisition and Divestiture Activity	(259	)	—		(235	)	(23	)	(1	)	(251	)	(14	)	(240	)	1	2
Net Capital Investment	2,792		786		515		663		828		3,011		884		503		707	917

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

Operating Statistics - Before Royalties

	2014					2013
Upstream Production Volumes	Year	Q4	Q3	Q2	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands - Heavy Oil
Foster Creek	59,172	68,377	56,631	56,852	54,706	53,190	52,419	49,092	55,338	55,996
Christina Lake	69,023	73,836	68,458	67,975	65,738	49,310	61,471	52,732	38,459	44,351
	128,195	142,213	125,089	124,827	120,444	102,500	113,890	101,824	93,797	100,347
Conventional Liquids
Pelican Lake - Heavy Oil	24,924	25,906	24,196	24,806	24,782	24,254	24,528	24,826	23,959	23,687
Other Heavy Oil	14,622	12,115	14,900	15,498	16,017	15,991	15,480	15,507	16,284	16,712
Light and Medium Oil	34,531	34,661	33,548	35,329	34,598	35,467	33,646	33,651	36,137	38,508
Natural Gas Liquids (2)	1,221	1,282	1,356	1,228	1,013	1,063	1,199	1,130	950	971
	75,298	73,964	74,000	76,861	76,410	76,775	74,853	75,114	77,330	79,878
Total Crude Oil and Natural Gas Liquids	203,493	216,177	199,089	201,688	196,854	179,275	188,743	176,938	171,127	180,225
Natural Gas (MMcf/d)
Oil Sands	22	22	23	23	19	21	21	23	22	18
Conventional	466	457	466	484	457	508	493	500	514	527
Total Natural Gas	488	479	489	507	476	529	514	523	536	545
Total Production (BOE/d)	284,826	296,010	280,589	286,188	276,187	267,442	274,410	264,105	260,460	271,058

(2)Natural gas liquids include condensate volumes.

Average Royalty Rates (excluding impact of Realized Gain	2014										2013
(Loss) on Risk Management)	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Oil Sands
Foster Creek	8.8	%	11.2	%	7.2	%	9.3	%	8.1	%	5.8	%	6.3	%	7.6	%	5.7	%	2.9	%
Christina Lake	7.5	%	7.2	%	7.9	%	7.7	%	7.1	%	6.8	%	7.8	%	7.0	%	5.6	%	5.7	%
Conventional
Pelican Lake	7.5	%	8.4	%	7.1	%	8.0	%	6.9	%	5.9	%	3.2	%	7.7	%	5.8	%	6.2	%
Weyburn	21.9	%	19.0	%	24.0	%	24.4	%	19.4	%	19.6	%	16.8	%	22.3	%	20.3	%	18.3	%
Other	5.9	%	6.7	%	6.5	%	5.5	%	4.9	%	6.5	%	7.4	%	6.8	%	6.0	%	5.7	%
Natural Gas Liquids	2.1	%	2.6	%	1.6	%	2.2	%	2.2	%	1.9	%	1.9	%	2.9	%	2.5	%	0.2	%
Natural Gas	1.9	%	2.5	%	2.0	%	2.0	%	1.4	%	1.4	%	1.2	%	1.8	%	1.2	%	1.7	%

Cenovus Energy Inc.	Supplemental Information
	for the period ended December 31, 2014

3

SUPPLEMENTAL INFORMATION (unaudited)    

Operating Statistics - Before Royalties (continued)

	2014										2013
Refining	Year		Q4		Q3		Q2		Q1		Year		Q4		Q3		Q2		Q1
Refinery Operations (1)
Crude Oil Capacity (2) (Mbbls/d)	460		460		460		460		460		457		457		457		457		457
Crude Oil Runs (Mbbls/d)	423		420		407		466		400		442		447		464		439		416
Heavy Oil	199		179		201		221		195		222		221		240		230		197
Light/Medium	224		241		206		245		205		220		226		224		209		219
Crude Utilization	92	%	91	%	88	%	101	%	87	%	97	%	98	%	101	%	96	%	91	%
Refined Products (Mbbls/d)	445		442		429		489		420		463		469		487		457		439

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

(2)The official nameplate capacity of Wood River increased effective January 1, 2014.

	2014							2013
Selected Average Benchmark Prices	Year	Q4	Q3	Q2		Q1		Year		Q4	Q3	Q2		Q1
Crude Oil Prices (US$/bbl)
Brent	99.51	76.98	103.39	109.77		107.90		108.76		109.35	109.71	103.35		112.65
West Texas Intermediate (“WTI”)	93.00	73.15	97.17	102.99		98.68		97.97		97.46	105.82	94.22		94.37
Differential Brent Futures-WTI	6.51	3.83	6.22	6.78		9.22		10.79		11.89	3.89	9.13		18.28
Western Canadian Select (“WCS”)	73.60	58.91	76.99	82.95		75.55		72.77		65.26	88.34	75.06		62.41
Differential - WTI-WCS	19.40	14.24	20.18	20.04		23.13		25.20		32.20	17.48	19.16		31.96
Condensate - (C5 @ Edmonton)	92.95	70.57	93.45	105.15		102.64		101.69		94.22	103.80	101.50		107.24
Differential - WTI-Condensate (premium)/discount	0.05	2.58	3.72	(2.16	)	(3.96	)	(3.72	)	3.24	2.02	(7.28	)	(12.87	)
Refining Margins 3-2-1 Crack Spreads (3) (US$/bbl)
Chicago	17.61	14.60	17.57	19.72		18.55		21.77		12.29	16.19	31.06		27.53
Midwest Combined (Group 3)	16.27	13.28	16.65	17.75		17.41		20.80		10.66	17.35	27.24		27.93
Natural Gas Prices
AECO ($/Mcf)	4.42	4.01	4.22	4.67		4.76		3.17		3.15	2.82	3.59		3.08
NYMEX (US$/Mcf)	4.42	4.00	4.06	4.67		4.94		3.65		3.60	3.58	4.09		3.34
Differential - NYMEX-AECO (US$/Mcf)	0.40	0.44	0.16	0.40		0.60		0.58		0.59	0.89	0.56		0.27

(3)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	2014					2013
(Loss) on Risk Management)	Year	Q4	Q3	Q2	Q1	Year	Q4	Q3	Q2	Q1
Heavy Oil - Foster Creek (4) (5) ($/bbl)
Price	69.43	51.95	76.82	79.77	71.44	66.30	59.39	87.49	68.17	52.60
Royalties	5.95	5.67	5.40	7.14	5.71	3.73	3.56	6.31	3.87	1.47
Transportation and Blending	1.98	1.85	2.17	3.10	0.78	2.36	3.21	4.37	0.04	1.89
Operating	16.55	13.65	14.79	19.38	19.09	15.77	15.90	17.12	16.19	14.03
Netback	44.95	30.78	54.46	50.15	45.86	44.44	36.72	59.69	48.07	35.21
Heavy Oil - Christina Lake (4) (5) ($/bbl)
Price	61.57	47.21	67.62	72.25	59.89	51.26	44.36	74.98	52.61	33.41
Royalties	4.40	3.14	5.07	5.37	4.04	3.25	3.22	5.06	2.71	1.69
Transportation and Blending	3.53	4.14	3.75	3.14	3.02	3.55	3.29	3.16	4.45	3.67
Operating	11.20	9.31	10.40	12.08	13.30	12.47	10.57	11.46	16.83	12.93
Netback	42.44	30.62	48.40	51.66	39.53	31.99	27.28	55.30	28.62	15.12
Total Heavy Oil - Oil Sands (4) (5) ($/bbl)
Price	65.18	49.44	71.82	75.65	65.19	59.10	51.34	81.16	61.88	44.01
Royalties	5.11	4.33	5.22	6.17	4.80	3.50	3.37	5.68	3.40	1.57
Transportation and Blending	2.82	3.06	3.03	3.12	1.99	2.93	3.25	3.76	1.82	2.69
Operating	13.66	11.35	12.41	15.38	15.96	14.19	13.04	14.26	16.45	13.53
Netback	43.59	30.70	51.16	50.98	42.44	38.48	31.68	57.46	40.21	26.22
Heavy Oil - Pelican Lake (4) (5) ($/bbl)
Price	76.07	61.24	81.66	84.66	76.20	70.09	64.52	88.08	72.32	54.30
Royalties	5.50	4.86	5.56	6.50	5.04	4.00	1.97	6.64	4.08	3.22
Transportation and Blending	3.18	3.29	3.24	3.13	3.07	2.41	2.79	2.18	2.58	2.07
Operating	21.41	18.84	20.49	21.23	24.96	20.65	21.22	19.90	22.21	19.23
Netback	45.98	34.25	52.37	53.80	43.13	43.03	38.54	59.36	43.45	29.78
Heavy Oil - Other Conventional (4) (5) ($/bbl)
Price	76.55	58.31	80.74	81.09	82.14	70.65	64.58	86.58	70.81	61.62
Royalties	9.70	10.71	11.10	9.77	7.52	9.18	10.40	12.27	7.67	6.57
Transportation and Blending	3.47	3.07	3.64	3.94	3.13	2.90	2.54	3.04	2.59	3.39
Operating	19.63	17.09	19.29	19.74	21.81	17.34	17.54	16.32	17.38	18.04
Production and Mineral Taxes	0.48	0.08	0.61	0.84	0.32	0.31	0.12	0.55	0.30	0.30
Netback	43.27	27.36	46.10	46.80	49.36	40.92	33.98	54.40	42.87	33.32
Total Heavy Oil - Conventional (4) (5) ($/bbl)
Price	76.25	60.25	81.30	83.29	78.52	70.31	64.55	87.50	71.73	57.42
Royalties	7.09	6.85	7.72	7.76	6.01	6.08	5.31	8.83	5.50	4.65
Transportation and Blending	3.29	3.22	3.40	3.44	3.09	2.60	2.69	2.51	2.58	2.63
Operating	20.74	18.24	20.02	20.66	23.73	19.32	19.76	18.51	20.30	18.72
Production and Mineral Taxes	0.18	0.03	0.24	0.32	0.13	0.13	0.05	0.21	0.12	0.13
Netback	44.95	31.91	49.92	51.11	45.56	42.18	36.74	57.44	43.23	31.29
Total Heavy Oil (4) (5) ($/bbl)
Price	67.83	51.74	73.99	77.63	68.64	62.23	54.61	82.97	64.91	47.82
Royalties	5.59	4.87	5.79	6.58	5.12	4.22	3.85	6.58	4.05	2.45
Transportation and Blending	2.93	3.09	3.11	3.20	2.28	2.84	3.11	3.40	2.06	2.67
Operating	15.35	12.82	14.15	16.75	17.97	15.62	14.70	15.47	17.63	15.01
Production and Mineral Taxes	0.04	0.01	0.05	0.08	0.03	0.04	0.01	0.06	0.04	0.04
Netback	43.92	30.95	50.89	51.02	43.24	39.51	32.94	57.46	41.13	27.65

(4)   The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013.

(5)   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	42.01	35.45	38.50	47.28	48.35	42.41	41.85	38.85	42.60	46.00
Christina Lake	45.45	38.23	42.57	49.30	52.81	45.25	44.16	39.86	47.13	51.46
Heavy Oil - Oil Sands	43.87	36.92	40.71	48.39	50.77	43.77	43.09	39.36	44.43	48.44
Pelican Lake	15.86	14.70	12.64	17.55	18.30	15.59	13.58	12.09	16.74	20.31
Other Conventional Heavy Oil	15.46	12.58	14.20	17.94	16.40	13.12	10.05	10.96	16.68	14.73
Heavy Oil - Conventional	15.71	13.98	13.25	17.70	17.56	14.60	12.18	11.65	16.72	17.93
Total Heavy Oil	37.13	32.04	34.42	40.44	42.17	35.63	35.44	31.46	35.91	39.78

Cenovus Energy Inc.	Supplemental Information
	for the period ended December 31, 2014

4

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results excluding impact of Realized Gain	2014									2013
(Loss) on Risk Management)	Year	Q4		Q3		Q2		Q1		Year	Q4	Q3		Q2		Q1
Light and Medium Oil ($/bbl)
Price	88.30	71.10		89.85		98.27		94.18		86.30	82.12	100.64		86.84		76.77
Royalties	9.15	6.12		10.36		11.37		8.78		8.28	6.58	11.01		8.61		7.05
Transportation and Blending	3.34	2.89		3.06		3.31		4.11		4.35	5.15	4.58		4.37		3.39
Operating	17.28	15.84		17.40		17.45		18.47		16.23	17.26	15.06		16.32		16.26
Production and Mineral Taxes	2.70	2.59		2.99		2.97		2.23		2.30	1.26	2.80		2.64		2.46
Netback	55.83	43.66		56.04		63.17		60.59		55.14	51.87	67.19		54.90		47.61
Total Crude Oil (1)($/bbl)
Price	71.39	55.05		76.64		81.35		73.15		67.05	59.41	86.41		69.75		54.02
Royalties	6.21	5.08		6.56		7.45		5.76		5.03	4.33	7.44		5.05		3.43
Transportation and Blending	3.00	3.06		3.10		3.22		2.60		3.14	3.47	3.63		2.57		2.82
Operating	15.69	13.34		14.70		16.87		18.06		15.74	15.15	15.39		17.34		15.27
Production and Mineral Taxes	0.50	0.45		0.54		0.60		0.42		0.49	0.23	0.59		0.61		0.56
Netback	45.99	33.12		51.74		53.21		46.31		42.65	36.23	59.36		44.18		31.94
Natural Gas Liquids ($/bbl)
Price	65.55	50.82		66.70		78.38		67.31		60.34	59.39	65.71		46.44		68.88
Royalties	1.38	1.34		1.07		1.70		1.48		1.13	1.14	1.92		1.17		0.12
Netback	64.17	49.48		65.63		76.68		65.83		59.21	58.25	63.79		45.27		68.76
Total Liquids (1)($/bbl)
Price	71.35	55.02		76.57		81.33		73.12		67.01	59.41	86.28		69.61		54.10
Royalties	6.18	5.06		6.52		7.41		5.74		5.01	4.31	7.40		5.03		3.42
Transportation and Blending	2.98	3.04		3.08		3.20		2.59		3.12	3.45	3.61		2.55		2.81
Operating	15.59	13.25		14.60		16.77		17.96		15.65	15.06	15.29		17.24		15.19
Production and Mineral Taxes	0.50	0.44		0.54		0.60		0.42		0.48	0.23	0.59		0.61		0.55
Netback	46.10	33.23		51.83		53.35		46.41		42.75	36.36	59.39		44.18		32.13
Total Natural Gas ($/Mcf)
Price	4.37	3.89		4.22		4.87		4.47		3.20	3.21	2.83		3.50		3.25
Royalties	0.08	0.09		0.08		0.09		0.06		0.04	0.04	0.05		0.04		0.05
Transportation and Blending	0.12	0.13		0.11		0.11		0.11		0.11	0.11	0.10		0.08		0.15
Operating	1.23	1.21		1.24		1.23		1.26		1.16	1.23	1.13		1.16		1.14
Production and Mineral Taxes	0.05	0.03		0.05		0.13		(0.01	)	0.02	0.02	0.03		(0.01	)	0.03
Netback	2.89	2.43		2.74		3.31		3.05		1.87	1.81	1.52		2.23		1.88
Total (1) (2)($/BOE)
Price	58.29	46.14		61.85		65.71		59.68		51.23	47.23	63.12		52.55		42.52
Royalties	4.53	3.80		4.79		5.36		4.19		3.44	3.07	5.02		3.35		2.38
Transportation and Blending	2.32	2.40		2.39		2.45		2.03		2.31	2.60	2.60		1.82		2.17
Operating	13.22	11.57		12.53		13.95		14.94		12.79	12.73	12.44		13.64		12.39
Production and Mineral Taxes	0.44	0.36		0.48		0.65		0.28		0.36	0.19	0.45		0.38		0.42
Netback	37.78	28.01		41.66		43.30		38.24		32.33	28.64	42.61		33.36		25.16
Impact of Long-Term Incentives Costs (Recovery) on Total Operating Costs ($/BOE)	0.16	(0.09	)	0.08		0.36		0.29		0.12	0.06	0.23		0.07		0.10
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	0.50	7.06		(0.45	)	(2.94	)	(2.00	)	1.09	2.77	(2.02	)	0.72		2.62
Natural Gas ($/Mcf)	0.04	0.05		0.11		(0.02	)	—		0.32	0.36	0.38		0.18		0.39
Total (2) ($/BOE)	0.42	5.17		(0.13	)	(2.09	)	(1.42	)	1.37	2.58	(0.58	)	0.84		2.52

(1)   The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013.

(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.

Cenovus Energy Inc.	Supplemental Information
	for the period ended December 31, 2014

5