Exhibit 99.1

Cenovus oil operating cash flow 40% higher in third quarter

Oil sands production at Christina Lake up 63%

·Operating cash flow from oil production increased 40% to $915 million, compared with the third quarter of 2012, driven by higher oil prices and increased volumes.

·Refining operating cash flow decreased 75% to $133 million compared with the third quarter of 2012 due to lower market crack spreads and higher feedstock costs.

·Cash flow decreased 17% to $932 million in the third quarter compared with the same period of 2012, mainly due to lower refining operating cash flow.

·Combined oil sands production at Foster Creek and Christina Lake averaged nearly 102,000 barrels per day (bbls/d) net in the third quarter.

·Average production at Christina Lake increased 63% from the third quarter of 2012, with first oil production from phase E achieved in mid-July.

·Foster Creek production was 22% lower than in the third quarter of 2012, partly due to a planned major turnaround in September.

·Plant construction began on the first phase of the Narrows Lake oil sands project.

·Cenovus was recently named to the Dow Jones Sustainability World Index for the second year in a row and to the Canada 200 Climate Disclosure Leadership Index for the fourth consecutive year.

“Stronger realized crude prices and higher oil production led to a solid increase in operating cash flow from our oil assets in the third quarter,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “That helped offset most of the impact from a significant drop in market crack spreads and higher feedstock costs which led to a large year-over-year decrease in operating cash flow from our refining assets.”

Production & financial summary

(for the period ended September 30)Production (before royalties)	2013Q3	2012 Q3	% change
Oil sands total (bbls/d)	101,824	95,625	6
Conventional oil1 (bbls/d)	75,114	75,725	-1
Total oil (bbls/d)	176,938	171,350	3
Natural gas (MMcf/d)	523	577	-9

Financial ($ millions, except per share amounts)
Cash flow2	932	1,117	-17
Per share diluted	1.23	1.47
Operating earnings2	313	432	-28
Per share diluted	0.41	0.57
Net earnings	370	289	28
Per share diluted	0.49	0.38
Capital investment	743	830	-10

1 Includes natural gas liquids (NGLs) and Pelican Lake production.

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

Calgary, Alberta (October 24, 2013) — Cenovus Energy Inc. (TSX, NYSE: CVE) continued to expand its oil production in the third quarter as the company remains on track to achieve its goal of reaching more than 500,000 bbls/d of net oil production by 2023. The increased production, combined with stronger crude prices, contributed to solid growth in operating cash flow from oil in the quarter.

Operating cash flow from oil production was $915 million, 40% higher than in the same period a year earlier. The increase was driven primarily by a 56% increase in operating cash flow from oil sands. Cenovus’s oil sands operations benefited from a $13.61 per barrel (bbl) increase in the average price of benchmark West Texas Intermediate (WTI), a 20% narrowing of the WTI to Western Canadian Select (WCS) differential to an average of US$17.48/bbl and a 6% increase in volumes compared with the third quarter of 2012.

Strong performance from Cenovus’s oil operations helped reduce the impact of a 75% year-over-year decline in third quarter operating cash flow from its refining operations to $133 million. The commodity price changes that led to higher realized prices for the company’s oil in the third quarter also resulted in higher feedstock costs for its refineries. At the same time, market crack spreads fell by more than half from near-record highs reached in the third quarter of 2012.

The gross margin from refining was also negatively affected by costs for renewable identification numbers (RINs), which increased to $55 million, net to Cenovus, in the third quarter compared with $10 million in the same period a year earlier. Refineries that do not blend renewable fuels such as ethanol into their gasoline and diesel are required to purchase RINs in the open market to comply with the Renewable Fuel Standards set by the U.S. Environmental Protection Agency (EPA). The EPA is reported to be considering a reduction to biofuel blending requirements next year, which has led to a significant drop in the cost of RINs recently.

Operationally, the Wood River and Borger refineries performed extremely well in the quarter, processing more oil, including record levels of heavy crude, and producing more refined products than in the third quarter of 2012. The company anticipates fourth quarter refining operating cash flow of $100 million to $200 million excluding inventory adjustments, based on a crack spread assumption of US$10.50 per barrel.

Solid growth at Christina Lake

The stronger results from oil operations were largely driven by a significant increase in production at the company’s Christina Lake oil sands project. Christina Lake volumes increased 63% in the quarter compared with the same period a year earlier as a result of  phase D reaching full capacity in the first quarter of 2013 and phase E commencing  production in mid-July. The Christina Lake increase helped push combined average oil sands production to nearly 102,000 bbls/d net in the third quarter, a 6% improvement over the same period in 2012.

At Foster Creek, quarterly production decreased 22% year over year due to a variety of factors. A planned major turnaround reduced production by approximately 4,400 bbls/d net during the quarter. The turnaround is now complete and Foster Creek is producing about 54,000 bbls/d net. Cenovus has also been catching up on a backlog of well maintenance that was deferred from 2012. Most of the deferred maintenance is now complete, although the facility experienced minor treating issues when some wells were being brought back on in July, which had a slight impact on production.

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In addition, Cenovus is developing new operating procedures to address changes to the steam chambers as they mature in the initial areas of the project. Foster Creek is the first commercial project of its kind in the oil sands industry and the initial wells at the operation are entering a new stage of development. The company is assessing how best to manage this change in order to optimize production.

“Foster Creek is a high-quality reservoir that will continue to play a key role in our oil growth strategy,” said Ferguson. “The lessons we’ve learned there over the years have made Cenovus a leader in steam-assisted gravity drainage. As we move into the next stage of reservoir management for the initial phases at Foster Creek, we will continue to test and implement new techniques to maintain our position as one of the most efficient, low-cost producers in the oil sands industry.”

The company anticipates gross production at Foster Creek to be between 100,000 and 110,000 bbls/d for the first half of 2014 and steam to oil ratios (SORs) in the range of 2.4 to 2.5 as the company continues to optimize its operating procedures.

Total conventional oil production, including Pelican Lake, averaged more than 75,000 bbls/d in the quarter, essentially flat compared with the third quarter of 2012. This reflects the July sale of the company’s Shaunavon tight oil assets in Saskatchewan, partially offset by increased production from the company’s horizontal well program in southern Alberta. Cenovus’s heavy oil operations at Pelican Lake increased production by 5% in the quarter, compared with the same period a year ago, as the company brought on more infill wells and saw increased response from its polymer flood program.

In the third quarter, Cenovus generated $189 million in free cash flow, above what it invested in its operations. Cenovus invested $743 million during the quarter, nearly half of which went towards expansion phases at Christina Lake and Foster Creek. In August, the company also began plant construction for the first phase of Narrows Lake, its next major oil sands development in northeastern Alberta. First oil production from Narrows Lake is expected in 2017.

“We are expanding our oil sands operations with some of the best capital efficiencies in the industry,” said John Brannan, Cenovus Executive Vice-President & Chief Operating Officer. “Over the next decade, we expect to more than quadruple our current oil sands production to about 435,000 barrels per day net to Cenovus.”

New market access a top priority

Cenovus continues to pursue a portfolio approach to getting its oil to market with a key focus on finding new customers in North America and overseas. The company successfully participated in the open season for the Energy East project earlier this year and in the third quarter committed to moving up to 200,000 bbls/d on the proposed pipeline to Quebec and New Brunswick. This would give Cenovus the opportunity to sell its oil to refineries in the East and provide options for sending oil to offshore markets where it could receive higher prices.

“Our predictable, reliable oil sands growth gives us the confidence to make these kinds of long-term transportation commitments,” said Ferguson. “In addition to Energy East, we’ve committed to ship another 175,000 barrels per day on proposed pipelines to the West Coast and 150,000 barrels per day on proposed lines to the U.S. Gulf Coast. We also expect to expand rail capacity to move up to 10% of our marketable oil over the long term.”

Cenovus markets gross oil production from its oil sands operations, including its partner’s volumes.

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Recognition for corporate responsibility

In September, Cenovus was named to the Dow Jones Sustainability World Index for the second year in a row and was the only North American oil and gas company to make the index this year. The company was also named to the Dow Jones Sustainability North America Index for the fourth consecutive year. The Dow Jones Sustainability Indexes recognize companies around the world for leadership in corporate responsibility. Cenovus was also recently named to the Canada 200 Climate Disclosure Leadership Index for the fourth consecutive year. The index, published by CDP (formerly known as the Carbon Disclosure Project), recognizes companies for their open and transparent disclosure of greenhouse gas emissions.

Guidance updated

Cenovus has updated its 2013 full-year guidance to reflect actual numbers for the first nine months of the year and the company’s estimates for the fourth quarter. Updated guidance can be found at cenovus.com under “Investors”.

2014 budget to be released in December

Cenovus is in the process of compiling its 2014 budget and will present details during a conference call on December 12, 2013. The company anticipates spending less on capital investment in 2014 while at the same time achieving an increase in oil production.

Oil Projects

Daily production1

(Before royalties)	2013			2012					2011
(Mbbls/d)	Q3	Q2	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Oil sands
Foster Creek	49	55	56	58	59	63	52	57	55
Christina Lake	53	38	44	32	42	32	29	25	12
Oil sands total	102	94	100	90	101	96	80	82	67
Conventional oil
Pelican Lake	25	24	24	23	24	24	22	21	20
Weyburn	16	16	17	16	16	16	16	17	16
Other conventional2	34	37	39	37	37	36	36	38	31
Conventional total	75	77	80	76	77	76	75	75	68
Total oil	177	171	180	165	178	171	156	157	134

1 Totals may not add due to rounding.

2 Includes NGLs production.

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Oil sands

Cenovus has a substantial portfolio of oil sands assets in northern Alberta with the potential to provide decades of growth. The two operations currently producing, Foster Creek and Christina Lake, use steam-assisted gravity drainage (SAGD), which involves drilling into the reservoir and pumping the oil to the surface. Cenovus is currently building its third major oil sands project at Narrows Lake, which is part of the Christina Lake Region. These projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus has enormous opportunity to deliver increased shareholder value through production growth from future developments. The company has identified several emerging projects and continues to assess its resources to prioritize development plans and support regulatory applications for new projects.

Foster Creek and Christina Lake

Production

·Combined oil sands production at Foster Creek and Christina Lake increased 6% to 101,824 bbls/d net in the third quarter from the same period a year earlier.

·Christina Lake production averaged 52,732 bbls/d net in the quarter, a 63% increase from the same period a year earlier. The increase is the result of phase D reaching full capacity in the first quarter of 2013 and the addition of new production from phase E, which achieved first oil production in mid-July. Cenovus expects the ramp-up of phase E will take six to nine months overall, similar to phases C and D, with production capacity reaching 138,000 bbls/d gross early in 2014. Ultimately, the company expects Christina Lake will have total gross production capacity of up to 310,000 bbls/d.

·During the third quarter, Cenovus received regulatory approval for its previously announced optimization program at Christina Lake phases C, D and E. This is expected to add 22,000 bbls/d of gross capacity in 2015.

·Foster Creek production averaged 49,092 bbls/d net in the quarter, a 22% decrease compared with 2012. The decrease was partly due to a planned major turnaround that included six days of full production outage in the quarter and to ongoing work on a backlog of well maintenance deferred from 2012. Most of that maintenance is now complete. In addition, Cenovus continues to modify its operating procedures to optimize production as the reservoir for phases A to E enters a new stage of SAGD development.

·The company remains confident in its expectations for the phase F, G and H expansions, which are on track and expected to have production success similar to the initial Foster Creek phases.

Wedge Well™ technology

·Cenovus’s Wedge Well™ technology uses single horizontal wells, drilled between existing SAGD well pairs, to reach oil that would otherwise be unrecoverable. The technology has the potential to increase overall recovery from the reservoir between 10% and 15%, while reducing the SOR.

·There are 60 wells at Foster Creek using Wedge Well™ technology and Cenovus anticipates bringing an additional 45 wells using this technology on production in 2014.

·Christina Lake is also benefiting from the use of Wedge Well™ technology with 10 of these wells on production.

Expansions

·At Christina Lake, the phase F expansion is on schedule and on budget with about 37% of the project complete and procurement, plant construction and engineering work continuing. Engineering work also continues for phase G at Christina Lake. First production is expected from phase F in 2016 and phase G in 2017.

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·At Foster Creek, phase F is also on schedule and on budget with 85% of the project complete and first production expected in the third quarter of 2014. Phase G is 60% complete with initial production expected in 2015. Phase H is 27% complete and first production is expected in 2016.

·Combined capital investment at Foster Creek and Christina Lake was $367 million in the third quarter, up 6% from $346 million in the same period of 2012.

Operating costs

·Operating costs at Christina Lake were $11.46/bbl in the third quarter, a 16% decrease from $13.59/bbl in the same period a year earlier. This was due to the increase in production from phases D and E, offset by higher fuel consumption and increased costs for repairs and maintenance, mainly related to routine issues. Per barrel operating costs at Christina Lake are expected to remain relatively flat in the fourth quarter. Non-fuel operating costs at Christina Lake were $9.00/bbl in the quarter, an 18% decrease from $11.03/bbl in the third quarter of 2012.

·Operating costs at Foster Creek averaged $17.12/bbl in the third quarter, a 49% increase from $11.50/bbl in the same period last year. The increase was primarily due to lower production volumes, higher workover activities and repairs and maintenance costs related to the planned major turnaround in late September. The company expects operating costs in the fourth quarter to average $15.25/bbl since they will continue to be affected by the turnaround, which was completed in October. Non-fuel operating costs at Foster Creek were $14.65/bbl in the third quarter compared with $9.76/bbl in the same period a year earlier, a 50% increase.

·Cenovus anticipates slightly higher per barrel operating costs at Foster Creek next year as a result of incremental labour costs associated with bringing on phase F as well as additional preventative well maintenance and the expected higher SORs as the company implements its new reservoir management procedures.

Steam to oil ratio (SOR)

·Cenovus uses natural gas to produce steam. The SOR measures the number of barrels of steam needed for every barrel of oil produced. A lower SOR means less steam is required, which reduces the amount of natural gas used. This lowers capital and operating costs, and results in fewer emissions and lower water usage per barrel of oil.

·Cenovus continues to achieve among the lowest SORs in the industry. The combined SOR for Cenovus’s oil sands operations was 2.2 in the third quarter of 2013.

·The third quarter SOR at Christina Lake was 1.9, consistent with the same period a year ago.

·Foster Creek’s SOR was 2.5, up from 2.1 in the third quarter of 2012. The increased SOR is largely the result of the move into a new stage of the SAGD process on the initial phases at Foster Creek and the company’s need to adjust its reservoir management processes. Cenovus expects an annual average SOR for Foster Creek of 2.4 for 2013.

Narrows Lake

·Plant construction on the first phase of Narrows Lake, Cenovus’s next major oil sands development, began in August. The first phase of the project is anticipated to have production capacity of 45,000 bbls/d gross, with first oil production expected in 2017.

·Narrows Lake is expected to be the industry’s first project to demonstrate solvent aided process (SAP), using butane, on a commercial scale.

·Cenovus invested $40 million to advance the Narrows Lake project in the third quarter of this year.

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Emerging projects

Telephone Lake

·Cenovus’s 100%-owned Telephone Lake property is located within the Borealis Region of northern Alberta. A revised application and environmental impact assessment (EIA) submitted in December 2011 is advancing through the regulatory process with approval anticipated in the second quarter of 2014.

·A dewatering pilot project designed to remove an underground layer of non-potable water sitting on top of the oil sands deposit at Telephone Lake has been running successfully. It has removed approximately 65% of the top water, replacing it with air, and Cenovus plans to complete the pilot by the end of October.

·While dewatering is not essential to the development of Telephone Lake, the company believes it could help improve the project’s SOR by up to 30%, which should enhance project economics and reduce its impact on the environment.

·Cenovus invested $17 million in its Telephone Lake project in the third quarter. After recognizing $16 million in scientific research and experimental development credits, net capital investment in the project was $1 million for the quarter.

Grand Rapids

·At the company’s 100%-owned Grand Rapids project, located within the Greater Pelican Region, work continues on a SAGD pilot project with two well pairs in production.

·Cenovus completed a turnaround at Grand Rapids in the third quarter to resolve facility constraints affecting production on both well pairs in the first half of 2013.

·A regulatory application and EIA for the 180,000 bbl/d commercial project has been submitted and Cenovus anticipates receiving regulatory approval within the next few months.

·Capital investment at Grand Rapids was $6 million in the third quarter of 2013, a slight decrease from $7 million a year earlier.

Conventional oil

Pelican Lake

Cenovus produces heavy oil from the Wabiskaw formation at its 100%-owned Pelican Lake operation in the Greater Pelican Region, about 300 kilometres north of Edmonton. While this property produces conventional heavy oil, it’s managed as part of Cenovus’s oil sands segment. Since 2006, Cenovus has been injecting polymer to enhance production from the reservoir, which is also under waterflood.

·Pelican Lake produced 24,826 bbls/d in the third quarter of 2013, a 5% increase from the same period in 2012 due to additional infill wells coming on production and increased response from the polymer flood.

·Cenovus invested $96 million at Pelican Lake in the third quarter, primarily for the infill drilling and polymer flood programs. Capital investment at Pelican Lake was down 25% from the third quarter of 2012 as the company decided to slow the pace of development at the project.

·Operating costs at Pelican Lake averaged $19.90/bbl in the third quarter, a 14% increase from $17.47/bbl in the same quarter a year earlier, mainly due to increased chemical costs related to the expansion of the polymer flood and higher property taxes. Operating costs are expected to be approximately $20.50/bbl in the fourth quarter.

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Other conventional oil

In addition to Pelican Lake, Cenovus has conventional oil assets in Alberta, including tight oil opportunities, as well as the established Weyburn operation in Saskatchewan that uses carbon dioxide injection to enhance oil recovery.

·Total conventional oil production, excluding Pelican Lake, averaged 50,288 bbls/d in the third quarter, a 4% decrease compared with the same quarter in 2012. The decrease was largely due to the July sale of the company’s Shaunavon assets in Saskatchewan for approximately $240 million. Shaunavon was producing an average of 4,550 bbls/d in the third quarter of 2012 and 3,596 bbls/d in the second quarter of 2013, prior to closing of the sale. Total conventional oil production primarily included:

·average production in Alberta of 32,667 bbls/d, a 9% increase compared with the third quarter of 2012, primarily due to successful horizontal well drilling in Alberta

·average production at the Weyburn operation in Saskatchewan of 16,438 bbls/d, a slight increase from 16,100 bbls/d in the third quarter of 2012.

·Cenovus invested $173 million in its conventional oil assets in the third quarter, the majority of which was dedicated to the development of emerging tight oil plays in Alberta. The company also invested in drilling and facilities work at Weyburn.

·Operating cash flow from conventional oil assets in excess of capital investment was $112 million in the quarter compared with $3 million in the same period in 2012.

·Operating costs for Cenovus’s conventional oil operations were $15.10/bbl in the third quarter, decreasing 6% from $16.02/bbl compared with the same period in 2012. This was mainly due to lower workforce, repairs and maintenance, fluid, waste handling and trucking costs, in line with the decrease in production volumes, partially offset by rising electricity costs due to higher market rates.

Natural Gas

Daily production

(Before royalties)	2013			2012					2011
(MMcf/d)	Q3	Q2	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Natural gas	523	536	545	594	566	577	596	636	656

Cenovus has a solid base of established, reliable natural gas properties in Alberta. These assets are important components of the company’s financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations because natural gas fuels the company’s oil sands and refining operations.

·Natural gas production in the third quarter of 2013 was approximately 523 million cubic feet per day (MMcf/d), down 9% from the same period last year. The decrease was driven by expected natural declines and Cenovus’s ongoing allocation of capital towards the company’s oil opportunities.

·Cenovus’s average realized sales price for natural gas, including hedges, was $3.21 per thousand cubic feet (Mcf) in the period compared with $3.54 per Mcf in the third quarter of 2012.

·The company invested $6 million in its natural gas properties in the third quarter of 2013. Operating cash flow from natural gas in excess of capital investment was $88 million in the quarter, a 25% decrease from the same period a year earlier.

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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 when crude oil prices are discounted by providing lower feedstock costs to the Wood River Refinery in Illinois and Borger Refinery in Texas, which Cenovus jointly owns with the operator, Phillips 66.

·Operating cash flow from refining was $133 million in the quarter, 75% lower than in the same period of 2012. The decline was due to a significant drop in market crack spreads and higher heavy crude feedstock costs at our refineries.

·Crack spreads were impacted by higher pipeline takeaway capacity in the southern tier of the U.S., which alleviated inland congestion and increased WTI prices closer to Brent Crude. Higher refinery utilization, which increased supplies of transportation fuels across the U.S. Midwest, also impacted crack spreads.

·Cenovus’s refining results were also negatively impacted by a narrowing of the WTI to WCS differential year over year. The narrower differential was the result of stronger U.S. demand for Canadian heavy oil, combined with supply disruptions in Canada during the third quarter, which led to higher refinery feedstock costs compared with the same period a year earlier.

·A more than five-fold increase in the cost of RINs, compared with the same quarter in 2012, also reduced gross refining margins. RIN costs have been trending significantly lower lately after the U.S. EPA suggested it might reduce its requirement for renewable fuel blending.

·Cenovus’s refineries processed an average of 464,000 bbls/d of crude oil in the third quarter, resulting in 487,000 bbls/d of refined product output. This was up about 5% from the same quarter a year ago when product output was reduced by minor refinery outages.

·The amount of Canadian heavy oil processed in the third quarter of 2013 was approximately 240,000 bbls/d, up 30,000 bbls/d compared with the same quarter of 2012.

·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 third quarter 2013 refining operating cash flow would have been $64 million lower than reported under FIFO compared with $6 million lower in the same quarter of 2012.

·The company invested $19 million in its refining operations during the third quarter compared with $37 million in the same quarter of 2012.

Financial

Dividend

The Cenovus Board of Directors declared a fourth quarter dividend of $0.242 per share, payable on December 31, 2013 to common shareholders of record as of December 13, 2013. Based on the October 23, 2013 closing share price on the Toronto Stock Exchange of $30.69, this represents an annualized yield of about 3.2%. Declaration of dividends is at the sole discretion of the Board. Cenovus’s continued commitment to a meaningful dividend is an important aspect of the company’s strategy to focus on increasing total shareholder return.

Hedging strategy

Cenovus’s natural gas and crude oil hedging strategy helps it to achieve more predictability around cash flow and safeguard its capital program. The Board-approved risk management policy allows the company to financially hedge up to 75% of this year’s and next year’s expected natural gas production, net of internal fuel usage, and up to 50% and 25%, respectively, in the following two years. The policy also allows the company to enter fixed price hedges on as much as 50% of net liquids production this year and next, as well as 25% of expected net liquids production for each of the following two years. In addition to financial hedges, Cenovus

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benefits from a natural hedge with its gas production. About 135 MMcf/d of natural gas is expected to be consumed at the company’s SAGD and refinery operations, which is more than offset by the natural gas Cenovus produces. The company’s financial hedging positions are determined after considering this natural hedge.

Cenovus’s financial hedge positions at September 30, 2013 include:

·approximately 10% or 18,500 bbls/d of expected oil production hedged for 2013 at an average Brent price of US$110.36/bbl and an additional 10% or 18,500 bbls/d at an average Brent price of C$111.72/bbl

·approximately 32% or 166 MMcf/d of expected natural gas production hedged for 2013 at an average NYMEX price of US$4.64/Mcf, plus internal usage of about 135 MMcf/d of natural gas and long-term sales of 29 MMcf/d of natural gas

·approximately 49,000 bbls/d of heavy crude exposure hedged for 2013 at an average WCS differential to WTI of US$20.74/bbl

·30,000 bbls/d of expected oil production hedged for 2014 at an average Brent price of US$102.04/bbl and an additional 20,000 bbls/d at an average Brent price of C$107.06/bbl

·approximately 15,400 bbls/d of heavy crude exposure hedged for 2014 at an average WCS differential to WTI of US$20.39/bbl.

Financial highlights

·Operating cash flow was approximately $1.1 billion in the quarter, a 12% decrease compared with the same period a year earlier. The decrease was due to a significant decline in operating cash flow from refining related to a sharp drop in market crack spreads, largely offset by increased operating cash flow from oil operations related to improved crude prices and increased production.

·Cash flow in the third quarter was $932 million, or $1.23 per share diluted compared with $1.1 billion, or $1.47 per share diluted, in the same period a year earlier. The decrease was due to the same factors affecting operating cash flow as well as an increase in finance costs related to the early redemption of debt, offset by lower current taxes.

·Operating earnings in the quarter were $313 million, or $0.41 per share diluted, down 28% from the same quarter in 2012. The decrease was due to the same factors affecting operating cash flow, as well as a $33 million increase in depreciation, depletion and amortization, partially offset by a decline in deferred income tax expense of $56 million and a realized foreign exchange gain of $33 million on the redemption of debt.

·Cenovus’s net earnings for the third quarter were $370 million compared with $289 million in the same period a year earlier, primarily as a result of unrealized risk management gains compared with losses in the same period a year earlier, partially offset by lower unrealized foreign exchange gains in this year’s quarter.

·Cenovus had a realized after-tax hedging loss of $22 million in the third quarter. The company received an average realized price, including hedging, of $84.26/bbl for its oil in the third quarter compared with $67.37/bbl during the same period in 2012. The average realized price for natural gas in the third quarter, including hedging, was $3.21/Mcf compared with $3.54/Mcf a year earlier.

·Cenovus recorded income tax expense of $172 million in the third quarter of 2013, giving the company an effective tax rate of 32% compared with an effective rate of 39% in the year-earlier period, reflecting a higher proportion of earnings from Canadian sources.

·Capital investment during the quarter was $743 million, a 10% decrease from $830 million in the third quarter of 2012 as a result of lower capital spending on conventional assets.

·General and administrative (G&A) expenses were $103 million in the third quarter, a slight decrease from $104 million in the same period a year earlier.

·In August, Cenovus completed a public offering in the U.S. of US$800 million in senior unsecured notes in order to partially fund the early redemption of US$800 million in senior unsecured notes

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due September 2014. The notes were issued in 10 and 30 year tranches. The offering allowed the company to secure favourable interest rates while also extending the weighted average term to maturity of our long-term debt.

·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 September 30, 2013, the company’s debt to capitalization ratio was 32% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.2 times.

Operating earnings1

(for the period ended September 30) ($ millions, except per share amounts)	2013 Q3		2012 Q3
Net earnings	370		289
Add back (deduct):
Unrealized risk management (gains) losses, after-tax	(5	)	218
Non-operating unrealized foreign exchange (gains) losses, after-tax	(53	)	(76	)
Divestiture (gains) losses, after-tax	1		1
Operating earnings	313		432
Per share diluted	0.41		0.57

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

Oil sands project schedule

Project phase	Regulatory status	First production target	Expected production capacity (bbls/d) gross
Foster Creek1 A – E			120,000
F	Approved	Q3-2014F	45,000	2
G	Approved	2015F	40,000
H	Approved	2016F	40,000
J	Submitted Q1-2013	2019F	50,000
Future optimization			15,000
Total capacity			310,000
Christina Lake1 A – E			138,000
Optimization (phases CDE)	Approved	2015F	22,000	3
F	Approved	2016F	50,000
G	Approved	2017F	50,000
H	Submitted Q1-2013	2019F	50,000
Total capacity			310,000
Narrows Lake1
A	Approved	2017F	45,000
B-C	Approved	TBD	85,000
Total capacity			130,000
Telephone Lake4	Submitted Q4-2011	TBD	90,000
Grand Rapids	Submitted Q4-2011	TBD	180,000

1 Properties 50% owned by ConocoPhillips. Certain phases may be subject to partner approval.

2 Includes 5,000 bbls/d gross submitted to the regulator in Q1 2013.

3 Increased from 12,000 bbls/d in Q2 2013 due to the addition of blowdown boilers.

4 Projected total capacity of more than 300,000 bbls/d.

Cenovus Energy Inc.
Third Quarter 2013 Report	News Release

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MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc., (“we”, “our”, “Cenovus”, or the “Company”) dated October 23, 2013, should be read in conjunction with our September 30, 2013 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2012 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2012 MD&A (“annual MD&A”). This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The interim MD&A is approved by the Audit Committee of the Cenovus Board of Directors (the “Board”) and the annual MD&A is reviewed by the Audit Committee and recommended for its approval by the Board. Additional information about Cenovus, including our quarterly and annual reports and the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at www.sedar.com, EDGAR at www.sec.gov and on our website at cenovus.com.

Basis of Presentation

This MD&A and the interim Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, except where another currency has been indicated and have been prepared in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis.

Non-GAAP Measures

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

OVERVIEW OF CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares trading on the Toronto and New York stock exchanges. On September 30, 2013, we had a market capitalization of approximately $23 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with refining operations in the United States (“U.S.”). Our average crude oil and NGLs production (collectively, “crude oil”) for the nine months ended September 30, 2013, was in excess of 176,000 barrels per day, our average natural gas production was 535 MMcf per day and our refinery operations processed an average of 440,000 gross barrels per day of crude oil feedstock into an average of 461,000 gross barrels per day of refined product.

Our Strategy

Our strategy is to create long-term value through the development of our vast oil sands resources, our execution excellence, our ability to innovate and our financial strength. We are focused on continually building our net asset value and paying a strong and sustainable dividend.

Our integrated approach, which enables us to capture the full value chain from production to high-quality end products like transportation fuels, relies on our entire asset mix:

·Oil sands for growth;

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

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

·Refining to help reduce the impact of commodity price fluctuations.

To achieve our expected production targets, we anticipate our total annual capital investment to average between $3.3 and $3.7 billion for the next decade. This capital investment is expected to be primarily internally funded through cash flow generated from our crude oil, natural gas and refining operations as well as prudent use of our balance sheet capacity. We continue to focus on executing our 10-year business plan in a predictable and reliable way, leveraging the strong foundation we have built to date.

Oil Production

We plan to increase our net oil sands bitumen production to approximately 435,000 barrels per day and our net crude oil production, including our conventional oil operations, to approximately 525,000 barrels per day by the end of 2023. We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek, Christina Lake, Pelican Lake, Narrows Lake, Telephone Lake and our conventional tight oil opportunities. Our future opportunities are currently based on the development of the land positions that we hold in the oil sands in northern Alberta and we plan to continue assessing our emerging resource base by drilling approximately 350-450 gross stratigraphic test wells each year for the next five years.

(1)Expected net production.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Oil Sands

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

	Ownership Interest(percent)	Nine Months EndedSeptember 30, 2013 NetProduction Volumes(bbls/d)	Nine Months EndedSeptember 30, 2013 Gross ProductionVolumes (bbls/d)	CurrentExpectedGross ProductionCapacity(bbls/d)
Existing Projects
Foster Creek	50	53,450	106,900	310,000
Christina Lake	50	45,211	90,422	310,000
Narrows Lake	50	—	—	130,000
Emerging Projects
Telephone Lake	100	—	—	300,000
Grand Rapids	100	—	—	180,000

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and located in the Athabasca region of northeastern Alberta.

Foster Creek is producing from phases A through E. Expansion work is underway at phases F, G and H with added production capacity from phase F expected in the third quarter of 2014 and phases G and H in 2015 and 2016, respectively. In the first quarter of 2013, we submitted a joint application and environmental impact assessment (“EIA”) for Foster Creek phase J, a 50,000 barrel per day phase. We anticipate receiving regulatory approval in the first quarter of 2015.

Christina Lake is producing from phases A through E. Our phase E expansion commenced steam injection in June 2013 and first production was achieved in mid-July 2013. Expansion work is currently underway for phases F, including cogeneration, and G with added production capacity expected in 2016 and 2017, respectively. In the first quarter of 2013, we submitted an EIA for Christina Lake phase H, a 50,000 barrel per day phase and we anticipate receiving regulatory approval in the fourth quarter of 2014.

For our Narrows Lake property, we received regulatory approval in May 2012 for phases A, B and C, and final partner approval for phase A in December 2012. Construction of the phase A plant commenced in August 2013 and we anticipate first production in 2017.

Two of our emerging projects are Telephone Lake and Grand Rapids. At our Telephone Lake project, located within the Borealis region, we commenced a dewatering pilot in the fourth quarter of 2012. The pilot is expected to be completed by the end of October 2013. In December 2011, we submitted a revised joint application and EIA due to an increase in the Telephone Lake project development area. We anticipate receiving regulatory approval in the second quarter of 2014. At our Grand Rapids project, located within the Greater Pelican region, a SAGD pilot project is underway. In December 2011, we filed a joint application and EIA for a 180,000 barrel per day commercial SAGD operation. We anticipate receiving regulatory approval in the fourth quarter of 2013.

Also located within the Athabasca region is our wholly owned Pelican Lake property. While this property produces conventional heavy oil using polymer flood technology, it’s managed within our Oil Sands segment. For the nine months ended September 30, 2013, our production averaged 24,162 barrels per day.

Conventional

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

	Nine Months EndedSeptember 30, 2013
($ millions)	Crude Oil (1)	Natural Gas
Operating Cash Flow	771	314
Capital Investment	493	17
Operating Cash Flow net of Related Capital Investment	278	297

(1)Includes NGLs.

We have established conventional crude oil and natural gas producing assets and developing tight oil assets in Alberta. We also inject carbon dioxide to enhance oil recovery at our Weyburn operations in Saskatchewan.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Refining and Marketing

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

	OwnershipInterest(percent)	Current Nameplate Capacity(Mbbls/d)
Wood River	50	311
Borger	50	146

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

($ millions)	Nine Months EndedSeptember 30, 2013
Operating Cash Flow	985
Capital Investment	70
Operating Cash Flow net of Related Capital Investment	915

Technology and Environment

Technology development plays a key role in all aspects of our business. We advance technologies with the goal of improving the amount of crude oil we can access and extract from the ground while reducing the amount of water, natural gas and electricity consumed in our operations and minimizing environmental disturbance. The Cenovus culture fosters new ideas and new approaches and has a track record of developing innovative solutions that unlock challenging crude oil resources, potentially reducing costs and building on our history of excellent project execution. Environmental considerations are embedded into our business approach with the objective of reducing our environmental impact.

Dividend

Our disciplined approach to capital allocation includes continuing to pay a strong and sustainable dividend as part of delivering total shareholder return. The Board of Directors approved a dividend increase of 10 percent to $0.242 per share for the first three quarters of 2013 compared to the same periods in 2012. The annualized dividend in 2012 was 10 percent higher than in 2011.

Net Asset Value

We measure our success in a number of ways with a key measure being growth in net asset value. We continue to be on track to reach our goal of doubling our December 2009 net asset value by the end of 2015.

QUARTERLY OPERATING AND FINANCIAL HIGHLIGHTS

The third quarter of 2013 continued to reflect the strength of our integrated approach. Overall, the integration of our business and growing crude oil production helped to mitigate the declines in our Operating Cash Flow from refining for the quarter. Upstream Operating Cash Flow increased 29 percent due to higher crude oil and natural gas prices as well as increased crude oil production. Crude oil sales prices increased mainly due to the narrowing of the West Texas Intermediate (“WTI”) to Western Canadian Select (“WCS”) differential. While contributing to higher upstream Operating Cash Flow, the narrowing WTI-WCS differential increased the cost of refinery crude oil feedstock which, along with sharp declines in market crack spreads, resulted in lower Operating Cash Flow from our refining operations.

Operational Results for the Third Quarter of 2013 as Compared to the Third Quarter of 2012

In the third quarter, crude oil production from our Oil Sands segment averaged 126,650 barrels per day, an increase of six percent, due primarily to growing production at Christina Lake. Average production at Christina Lake for the quarter was 52,732 barrels per day, a 63 percent increase, as phase D reached full capacity and phase E, our tenth expansion phase, started to produce in mid-July 2013. We expect the ramp-up of phase E will take six to nine months overall, similar to phases C and D, with production capacity expected to reach 138,000 barrels per day gross early in 2014.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Within our Conventional segment, crude oil production averaged 50,288 barrels per day, a decline of 1,898 barrels per day. Strong horizontal well performance from our current drilling program offset declines in production due to the sale of our Shaunavon asset in July 2013. Prior to closing the sale, our Shaunavon asset was producing an average of approximately 3,600 barrels per day in the second quarter of 2013.

Our refining operations processed an average of 464,000 (2012 — 442,000) gross barrels per day of crude oil, of which 240,000 gross barrels per day was heavy crude oil (2012 — 210,000). We produced 487,000 gross barrels per day of refined products, an increase of about 24,000 gross barrels per day, or five percent, as refined product output in the same period last year was impacted by minor refinery outages.

Other significant operational results in the third quarter compared to 2012 include:

·Foster Creek production averaging 49,092 barrels per day, a decrease of 22 percent, resulting from a number of production matters which are discussed in the Reportable Segments section under Oil Sands;

·Pelican Lake production averaging 24,826 barrels per day, an increase of five percent resulting from additional infill wells coming on-stream throughout 2012 and 2013 as well as increased response from the polymer flood program;

·Receiving regulatory approval for an optimization program at Christina Lake phases C, D and E which is expected to add 22,000 barrels per day of gross capacity in 2015;

·The closing of the Shaunavon asset disposition for proceeds of approximately $240 million;

·Managing our natural gas production, which declined nine percent to an average of 523 MMcf per day due to expected natural declines; and

·Increasing our access to new sales markets with approximately 4,100 barrels per day of conventional crude oil transported by rail to the East Coast and the U.S.

Financial Results for the Third Quarter of 2013 as Compared to the Third Quarter of 2012

For an understanding of the trends and events that impacted our financial results, the following discussion should be read in conjunction with our 2012 annual MD&A.

Upstream operations benefited from higher crude oil and natural gas prices and production increases at Christina Lake. Crude oil sales prices increased 32 percent mainly due to the narrowing of the WTI-WCS differential by 20 percent, which averaged US$17.48 per barrel for the quarter (2012 — US$21.72 per barrel). Our refining operations reflected lower Operating Cash Flow primarily as a result of lower market crack spreads and higher feedstock costs consistent with the narrowing of the WTI-WCS differential and increases in costs associated with renewable identification numbers (“RINs”). The Chicago 3-2-1 and the Group 3 market crack spreads decreased by US$19.45 per barrel and US$18.64 per barrel, respectively.

Cash Flow decreased 17 percent to $932 million, primarily related to a decrease in Refining and Marketing Operating Cash Flow and realized risk management losses as compared to gains in 2012, partially offset by higher Operating Cash Flow from our upstream operations.

In August, we completed a public offering in the U.S. of US$800 million of senior unsecured notes. The net proceeds from the offering were used to partially fund the early redemption of our US$800 million senior unsecured notes due September 2014.

We paid a third quarter dividend of $0.242 per share (2012 — $0.22 per share), an increase of 10 percent over 2012, demonstrating our continuing commitment to pay a strong and sustainable dividend as part of delivering total shareholder return.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Other financial highlights for the third quarter compared to 2012 include:

Revenues

Revenues of $5,075 million, increasing $735 million or 17 percent, primarily a result of:

·Our crude oil average sales price (excluding financial hedging) increasing 32 percent to $86.28 per barrel;

·An increase in refining revenues primarily as a result of higher refined product output;

·Higher marketing revenues from third party sales undertaken to provide operational flexibility;

·A rise in condensate prices and volumes; and

·Higher crude oil production volumes.

Operating Cash Flow

Operating Cash Flow of $1,148 million, decreasing $162 million or 12 percent due to:

·Operating Cash Flow from our Refining and Marketing segment decreasing by $390 million due to a sharp decline in market crack spreads as a result of increases in refinery crude oil feedstock costs from higher commodity prices, narrowing crude oil discounts and increases in the cost of RINs. These factors were partially offset by higher refined product output; and

·Upstream realized risk management losses before tax of $12 million as compared to a gain of $99 million in 2012.

Partially offset by:

·An increase in upstream Operating Cash Flow as a result of higher average crude oil and natural gas sales prices and growing crude oil production volumes.

Operating Earnings

Operating Earnings were $313 million, a 28 percent decrease, due to lower cash flow as discussed above and higher depreciation, depletion and amortization (“DD&A”), partially offset by lower deferred income tax expense, not including income tax on unrealized risk management gains and non-operating unrealized foreign exchange losses, and a realized foreign exchange gain of $33 million on the early redemption of debt.

Net Earnings

Net earnings increased 28 percent to $370 million primarily due to unrealized risk management gains compared to losses in 2012.

Capital Investment

Capital investment of $743 million, decreasing from 2012 by 10 percent, primarily due to declines in our Corporate and Refining and Marketing segments, in addition to declines in our Conventional segment with reduced capital investment at our Shaunavon property. Within our oil sands operations there was a decrease at Pelican Lake, as the rate at which we are expanding the polymer flood has slowed to better match our production growth, and at Telephone Lake, as increases in spending related to the dewatering pilot were offset with the recognition of scientific research and development credits. Declines in capital investment were partially offset by increases at Foster Creek and Christina Lake, with continued focus on the development of our expansion phases, and at Narrows Lake, with construction commencing on phase A in the quarter.

OPERATING RESULTS

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Crude Oil Production Volumes

	Three Months Ended September 30,				Nine Months Ended September 30,
(barrels per day)	2013	Percent Change		2012	2013	Percent Change		2012
Oil Sands
Foster Creek	49,092	(22	)%	63,245	53,450	(7	)%	57,421
Christina Lake	52,732	63	%	32,380	45,211	58	%	28,577
Pelican Lake	24,826	5	%	23,539	24,162	9	%	22,231
Conventional
Heavy Oil	15,507	—	%	15,492	16,163	1	%	15,938
Light and Medium Oil	33,651	(6	)%	35,695	36,081	—	%	36,083
NGLs (1)	1,130	13	%	999	1,018	(2	)%	1,041
Total Crude Oil Production	176,938	3	%	171,350	176,085	9	%	161,291

(1)NGLs include condensate volumes.

Our crude oil production increased for the three and nine months ended September 30, 2013, primarily from higher production at Christina Lake. Production from Christina Lake phase D, which started in the third quarter of 2012, reached full capacity in the first quarter of 2013 and first production was achieved at phase E in mid-July 2013.

For the three months ended September 30, 2013, Foster Creek production averaged 49,092 barrels per day, a 22 percent decrease from 2012 due to a variety of factors. In the third quarter of 2012, Foster Creek production averaged 63,245 barrels per day (126,490 barrels per day, gross), exceeding plant capacity. In the fourth quarter of 2012, we made a decision to defer some routine workover activity until 2013. That deferral of maintenance resulted in a backlog in the number of wells requiring workovers. In 2013, we have been catching up on routine well maintenance. These factors, along with the commencement of a planned turnaround in the third quarter of 2013 which decreased production by approximately 4,400 barrels per day and minor treating issues, contributed to lower production compared to the prior year.

Pelican Lake production increased due to additional infill wells coming on-stream throughout 2012 and 2013 and increased response from our polymer flood program.

Our crude oil production from the Conventional segment during the third quarter declined slightly and remained flat year-to-date as better horizontal well performance from our current drilling program was offset by the divestiture of our Shaunavon asset. Prior to closing the sale, our Shaunavon asset was producing an average of approximately 3,600 barrels per day in the second quarter of 2013 and 4,200 barrels per day year-to-date (year-to-date 2012 — 4,265 barrels per day).

Natural Gas Production Volumes

	Three Months EndedSeptember 30,		Nine Months EndedSeptember 30,
(MMcf per day)	2013	2012	2013	2012
Conventional	498	550	512	569
Oil Sands	25	27	23	33
	523	577	535	602

In the low commodity price environment, management of our natural gas spending resulted in production declines during the three and nine months ended September 30, 2013, in line with our decision to focus on high rate of return projects and direct capital investment to our crude oil properties.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Operating Netbacks

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013		2012
	CrudeOil (1)		NaturalGas	CrudeOil (1)	NaturalGas	CrudeOil (1)	NaturalGas	CrudeOil (1)	NaturalGas
	($/bbl)		($/Mcf)	($/bbl)	($/Mcf)	($/bbl)	($/Mcf)	($/bbl)	($/Mcf)
Price (2)	86.28		2.83	65.35	2.30	69.91	3.20	67.89	2.25
Royalties	7.40		0.05	7.83	0.02	5.28	0.05	6.91	0.03
Transportation and Blending (2)	3.61		0.10	2.45	0.08	3.00	0.11	2.69	0.10
Operating Expenses	15.29		1.13	14.14	1.08	15.88	1.14	14.27	1.05
Production and Mineral Taxes	0.59		0.03	0.53	0.02	0.58	0.02	0.56	0.02
Netback Excluding RealizedRisk Management	59.39		1.52	40.40	1.10	45.17	1.88	43.46	1.05
Realized Risk Management Gain (Loss)	(2.02	)	0.38	2.02	1.24	0.45	0.31	0.66	1.21
Netback Including RealizedRisk Management	57.37		1.90	42.42	2.34	45.62	2.19	44.12	2.26

(1)Includes NGLs.

(2)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate for the three months ended September 30, 2013 was $25.16 per barrel (2012 — $23.06 per barrel) and $28.05 per barrel (2012 — $26.96 per barrel) for the nine months ended September 30, 2013.

In the three months ended September 30, 2013, our average crude oil netback, excluding realized risk management gains and losses, increased $18.99 per barrel from 2012 primarily due to higher sales prices, consistent with increased benchmark prices with the average WTI price increasing US$13.61 per barrel and the WTI-WCS differential narrowing US$4.24 per barrel, and lower royalties, partially offset by increased transportation and blending and operating costs.

For the nine months ended September 30, 2013, our average crude oil netback, excluding realized risk management gains and losses, rose $1.71 per barrel from 2012 primarily due to higher sales prices and lower royalties, partially offset by higher operating costs. Sales price increases were consistent with increases in benchmark prices with the average WCS price increasing US$1.18 per barrel, despite a widening WTI-WCS differential as a result of a larger increase in the WTI price as compared to WCS.

Our average natural gas netback, excluding realized risk management gains and losses, increased $0.42 and $0.83 per Mcf in the third quarter and year-to-date, respectively. This was predominantly due to higher sales prices, partially offset by higher per-unit operating costs as a result of the decline in production volumes.

Refining (1)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013	Percent Change		2012	2013	Percent Change		2012
Crude Oil Runs (Mbbls/d)	464	5	%	442	440	(1	)%	446
Heavy Crude Oil	240	14	%	210	223	5	%	213
Crude Utilization (percent)	101	3	%	98	96	(3	)%	99
Refined Product (Mbbls/d)	487	5	%	463	461	(1	)%	467

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

Crude oil runs, including heavy crude oil, crude utilization and refined product output increased during the three months ended September 30, 2013 as a result of both plants operating in the quarter with minimal disruptions. Year-to-date, there was a reduction in crude oil runs, crude utilization and refined product output primarily as a result of planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter of 2013. Despite these decreases, our heavy crude oil processed increased five percent, reflecting our ability to process a greater proportion of heavy oil feedstock and the optimization of our total crude input slate.

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

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

	Nine Months Ended September 30,
	2013		2012		Q3 2013	Q2 2013		Q3 2012
Crude Oil Prices (US$/bbl)
Brent Futures
Average	108.49		112.20		109.65	103.35		109.42
End of Period	108.37		112.39		108.37	102.16		112.39
WTI
Average	98.20		96.16		105.81	94.17		92.20
End of Period	102.33		92.19		102.33	96.56		92.19
Average Differential Brent-WTI	10.29		16.04		3.84	9.18		17.22
WCS
Average	75.34		74.16		88.33	75.01		70.48
End of Period	70.39		82.26		70.39	82.16		82.26
Average Differential WTI-WCS	22.86		22.00		17.48	19.16		21.72
Condensate (C5 @ Edmonton) Average	104.24		101.83		103.79	101.45		96.12
Average Differential WTI-Condensate (Premium)/Discount	(6.04	)	(5.67	)	2.02	(7.28	)	(3.92	)
Refining Margin 3-2-1 Average Market Crack Spreads (US$/bbl)
Chicago	24.93		27.61		16.19	31.06		35.64
Midwest Combined (“Group 3”)	24.17		28.59		17.35	27.24		35.99
Natural Gas Average Prices
AECO (C$/GJ)	3.00		2.07		2.67	3.40		2.08
NYMEX (US$/MMBtu)	3.67		2.59		3.58	4.09		2.81
Basis Differential NYMEX-AECO (US$/MMBtu)	0.57		0.41		0.89	0.56		0.61
Foreign Exchange Rate (US$/C$1)
Average	0.977		0.998		0.963	0.977		1.005

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

Crude Oil Benchmarks

The Brent benchmark is representative of global crude oil prices and is also a better indicator than WTI of changes in inland refined product prices. The average price of Brent crude oil increased by US$0.23 per barrel for the thirdquarter, compared to 2012, due to increased global supply outages with the largest contributor being labour and political unrest in Libya and fear of further supply outages arising from an escalation of events in the Syrian conflict. Year-to-date, there was a US$3.71 per barrel decline in the average price of Brent crude oil due to concerns over the pace of growth of the Chinese economy this spring while 2012 prices increased as a result of the Iranian nuclear situation and associated sanctions.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. The average price of WTI increased by US$13.61 per barrel and US$2.04 per barrel for the three and nine months ended September 30, 2013, respectively, compared to 2012, as a result of new pipeline infrastructure being added from the Cushing area to the U.S. Gulf Coast thereby relieving congestion that developed due to rapid growth in U.S. inland supply.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. This blended heavy oil is traded at a discount to the light oil benchmark WTI. The WTI-WCS average differential narrowed by US$4.24 per barrel in the third quarter, compared to 2012, due to improved pipeline access from inland markets to the heavy crude oil refining complex in the U.S. Gulf Coast through pipeline expansions and more effective use of existing pipeline infrastructure. Substantial increases in rail shipments and more frequent supply outages also reduced pipeline congestion for all grades of crude oil. For the nine months of 2013, the WTI-WCS average differential widened by US$0.86 per barrel due to increased levels of congestion early in the year.

Cenovus Energy Inc.
Third Quarter 2013 Report	Management’s Discussion and Analysis

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Blending condensate with bitumen and heavy oil enables our production to be transported. Our blending ratios range from 10 percent to 33 percent. The WTI-Condensate differential is the Edmonton benchmark price of condensate relative to the price of WTI. The differentials for WTI-WCS and WTI-Condensate are independent of one another and tend not to move in tandem. Condensate differentials at Edmonton weakened by US$5.94 per barrel in the third quarter, as condensate traded at a discount to WTI for the first time since the third quarter of 2010.  Despite strengthening U.S. condensate prices the reductions in pipeline congestion caused WTI prices to increase more than condensate prices. Year-to-date, condensate differentials strengthened by US$0.37 per barrel, compared to 2012, as greater access to export markets for U.S. condensate improved Gulf Coast prices and growing Canadian condensate requirements saw a further strengthening of Edmonton prices, which was partially offset by strengthening WTI prices.

Refining 3-2-1 Crack Spread Benchmarks

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. Our realized crack spreads are affected by many other factors such as the variety of feedstock crude oil inputs, refinery configuration and product output, and feedstock costs which are based on a first in, first out accounting basis. Average market crack spreads in the U.S. inland Chicago and Group 3 markets for the third quarter of 2013 fell sharply compared to 2012, primarily due to the strengthening of WTI prices as inland congestion issues were being resolved and as a result of higher refinery crude oil runs which kept product markets well supplied. Average market crack spreads for the Chicago and Group 3 markets also fell year-to-date, due to the rise in WTI prices in the third quarter of 2013.

Other Benchmarks

Average natural gas prices increased in both the third quarter and the nine months of 2013 as the impact to markets from growth in northeastern U.S. natural gas production and an extremely warm winter in the previous year was gradually reduced. The low prices of 2012 have significantly slowed the pace of supply growth outside of the northeastern U.S., while steady demand growth has enabled markets to be balanced without price-induced switching from coal to gas-fired generation in the power sector.

A decrease in the value of the Canadian dollar compared to the U.S. dollar has a positive impact on our revenues as the sales prices of our crude oil and refined products are determined by reference to U.S. benchmarks. Similarly, our refining results are in U.S. dollars and therefore a weakened Canadian dollar improves our reported results, although a weaker Canadian dollar also inflates our current period’s reported refining capital investment. For the three and nine months ended September 30, 2013, the Canadian dollar weakened relative to the U.S. dollar, compared to the same periods last year, caused by a general downturn in commodity markets.

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FINANCIAL RESULTS

Selected Consolidated Financial Results

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

($ millions, except per share	Nine Months Ended September 30,		2013			2012					2011
amounts)	2013	2012	Q3	Q2	Q1	Q4		Q3	Q2	Q1	Q4	Q3
Revenues	13,910	13,118	5,075	4,516	4,319	3,724		4,340	4,214	4,564	4,329	3,858
Operating Cash Flow (1)	3,478	3,473	1,148	1,119	1,211	963		1,310	1,078	1,085	1,019	945
Cash Flow (1)	2,774	2,946	932	871	971	697		1,117	925	904	851	793
Per Share — Diluted	3.66	3.88	1.23	1.15	1.28	0.92		1.47	1.22	1.19	1.12	1.05
Operating Earnings (1) (2)	959	1,056	313	255	391	(188	)	432	284	340	332	303
Per Share — Diluted (2)	1.27	1.39	0.41	0.34	0.52	(0.25	)	0.57	0.37	0.45	0.44	0.40
Net Earnings (2)	720	1,112	370	179	171	(117	)	289	397	426	266	510
Per Share — Basic (2)	0.95	1.47	0.49	0.24	0.23	(0.15	)	0.38	0.53	0.56	0.35	0.68
Per Share — Diluted (2)	0.95	1.47	0.49	0.24	0.23	(0.15	)	0.38	0.52	0.56	0.35	0.67
Capital Investment (3)	2,364	2,390	743	706	915	978		830	660	900	903	631
Cash Dividends	549	498	182	183	184	167		166	166	166	151	150
Per Share	0.726	0.66	0.242	0.242	0.242	0.22		0.22	0.22	0.22	0.20	0.20

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

(2)We have restated prior periods as a result of adoption of new accounting standards. See Critical Accounting Judgments, Estimates and Accounting Policies within this MD&A for more details.

(3)Includes expenditures on property, plant and equipment (“PP&E”) and exploration and evaluation (“E&E”) assets.

Revenues Variance

During the three and nine months ended September 30, 2013, revenues increased $735 million (17 percent) and $792 million (six percent), respectively.

($ millions)	Three Months Ended		NineMonths Ended
Revenues for the Periods Ended September 30, 2012	4,340		13,118
Increase (Decrease) due to:
Oil Sands	345		434
Conventional	87		172
Refining and Marketing	393		463
Corporate and Eliminations	(90	)	(277	)
Revenues for the Periods Ended September 30, 2013	5,075		13,910

Upstream revenues rose for the third quarter by 31 percent due to higher crude oil sales and condensate prices, a rise in crude oil sales and condensate volumes and higher realized natural gas prices, partially offset by lower natural gas production.

Year-to-date upstream revenues rose 14 percent due to increased crude oil sales volumes, higher natural gas sales prices, a rise in condensate volumes used in blending, higher crude oil sales prices, reduced royalties and increased condensate prices, offset by a decline in natural gas production.

Revenues for the three and nine months ended September 30, 2013 generated by the Refining and Marketing segment increased 13 percent and five percent, respectively. In the third quarter of 2013, we had higher revenues from third party sales, undertaken to provide operational flexibility, primarily due to an increase in purchased crude oil volumes and increases in crude oil and condensate pricing, as well as higher revenue from refining primarily as a result of increased refined product output.

Revenue from third party sales was higher on a year-to-date basis as a result of increased purchased crude oil volumes and higher crude oil and condensate pricing. Refining revenue increased due to a weakening of the Canadian dollar and an increase in refined product prices, partially offset by reduced refined product output, as a result of planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter.

Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on current market prices. Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.

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Operating Cash Flow

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

	Three Months Ended September 30,			Nine Months EndedSeptember 30,
($ millions)	2013	2012		2013		2012
Revenues	5,265	4,440		14,352		13,283
(Add Back) Deduct:
Purchased Product	3,172	2,403		8,065		7,500
Transportation and Blending	464	398		1,482		1,323
Operating Expenses	437	419		1,342		1,203
Production and Mineral Taxes	11	9		30		28
Realized (Gain) Loss on Risk Management Activities	33	(99	)	(45	)	(244	)
Operating Cash Flow	1,148	1,310		3,478		3,473

Operating Cash Flow Variance for the Three Months Ended September 30, 2013 compared to September 30, 2012

Operating Cash Flow Variance for the Three Months Ended
September 30, 2013 compared to September 30, 2012

In the third quarter, Operating Cash Flow decreased $162 million (12 percent).

Operating Cash Flow from crude oil increased 40 percent due to higher average sales prices, consistent with the increase in the WTI benchmark price and the WTI-WCS differential narrowing, and increased production volumes, partially offset by realized risk management losses as compared to gains in 2012, and higher operating and transportation and blending expenses.

Operating Cash Flow from natural gas decreased 25 percent as lower realized risk management gains and reduced production volumes from expected natural declines, partially offset by increased sales prices.

Refining and Marketing Operating Cash Flow declined 74 percent primarily related to the sharp decline in the market crack spreads and increases in refinery feedstock costs, consistent with the narrowing of the WTI-WCS differential and increases in the cost of RINs, partially offset by higher refined product output.

Operating Cash Flow by Segment

Upstream Operating Cash Flow by Product

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Operating Cash Flow Variance for the Nine Months Ended September 30, 2013 compared to September 30, 2012

Operating Cash Flow Variance for the Nine Months Ended
September 30, 2013 compared to September 30, 2012

Year-to-date, Operating Cash Flow increased $5 million.

Operating Cash Flow from crude oil increased 11 percent due to growing production volumes, higher average sales prices consistent with the increase in benchmark prices, and a reduction in royalties, partially offset by higher operating expenses.

Operating Cash Flow from natural gas declined 14 percent due to lower realized risk management gains and reduced production volumes from expected natural declines, partially offset by increased sales prices.

Refining and Marketing Operating Cash Flow was lower by 14 percent due to lower market crack spreads, higher refinery feedstock costs, consistent with the increase in the WCS benchmark price and increases in the cost of RINs, and decreased refined product output as a result of planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter.

Operating Cash Flow by Segment

Upstream Operating Cash Flow by Product

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

Cash Flow

Cash Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Cash Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
Cash From Operating Activities	840		1,029		2,563		2,662
(Add Back) Deduct:
Net Change in Other Assets and Liabilities	(25	)	(19	)	(90	)	(71	)
Net Change in Non-Cash Working Capital	(67	)	(69	)	(121	)	(213	)
Cash Flow	932		1,117		2,774		2,946

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Cash Flow Variance for the Three Months Ended September 30, 2013 compared to September 30, 2012

In the third quarter, our Cash Flow decreased $185 million or 17 percent due to:

· A decline in Operating Cash Flow from Refining and Marketing of $390 million related to the sharp decline in market crack spreads and increases in refinery crude oil feedstock costs consistent with the narrowing of the WTI-WCS differential and higher costs associated with RINs, partially offset by higher refined product output;

· Realized risk management losses before tax, excluding Refining and Marketing, of $12 million compared to gains of $99 million in 2012;

· An increase in finance costs primarily due to a US$32 million premium paid on the early redemption of the US$800 million of senior unsecured notes that were due in September 2014;

· An increase in crude oil upstream operating expenses of $26 million, partially from higher crude oil production. On a per barrel basis, crude oil operating costs increased by $1.15 to $15.29 per barrel due to higher fuel prices, consistent with the increase in the benchmark AECO natural gas price and increased fuel usage; higher workover activities; and rising electricity costs as a result of increases in market prices and consumption; and

· A nine percent decline in natural gas production from expected natural declines.

The decreases in our Cash Flow were partially offset by:

·A 32 percent increase in our average sales price of crude oil to $86.28 per barrel;

·A decrease in current tax of $36 million as it includes a recovery of U.S. tax which reflects lower estimates of U.S. source income for 2013;

·An increase in our crude oil sales volumes by three percent; and

·A 23 percent increase in our average sales price of natural gas to $2.83 per Mcf.

Cash Flow Variance for the Nine Months Ended September 30, 2013 compared to September 30, 2012

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Year-to-date, our Cash Flow decreased $172 million primarily due to:

·A decrease in Operating Cash Flow from Refining and Marketing of $160 million as a result of lower market crack spreads, increases in refinery crude oil feedstock costs consistent with increases in benchmark prices and higher costs associated with RINs, and declines in refined product output from planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter;

·Realized risk management gains before tax, excluding Refining and Marketing, of $74 million compared to gains of $230 million in 2012;

·An increase in upstream operating expenses of $124 million, partially from higher crude oil production. On a per barrel basis, crude oil operating costs increased by $1.61 to $15.88 per barrel primarily due to higher fuel prices, consistent with the increase in the AECO benchmark price and increased fuel usage; increased workover activities related to Foster Creek and Pelican Lake; and rising electricity costs, as a result of higher market rates and consumption;

·Increased general and administrative expenses, excluding non-cash long-term incentive costs, due to higher rent and staffing costs;

·Pre-exploration expense of $63 million recorded in the second quarter of 2013;

·An 11 percent decline in natural gas production from expected natural declines; and

·An increase in finance costs primarily due to a US$32 million premium paid on the early redemption of the US$800 million of senior unsecured notes that were due in September 2014.

The decreases in our Cash Flow were partially offset by:

·A seven percent increase in our crude oil sales volumes;

·A 42 percent increase in our average sales price of natural gas to $3.20 per Mcf;

·A three percent increase in our average sales price of crude oil to $69.91 per barrel; and

·A decrease in royalties of $53 million primarily at Foster Creek as a result of lower crude oil production volumes and increased capital and operating expenditures.

Operating Earnings

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 net earnings excluding after-tax gain (loss) on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized risk management gains (losses) on derivative instruments, after-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, after-tax gains (losses) on divestiture of assets, deferred income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013	2012
Net Earnings	370		289		720	1,112
Add Back (Deduct):
Unrealized Risk Management (Gain) Loss, after-tax (1)	(5	)	218		147	44
Non-operating Unrealized Foreign Exchange (Gain)Loss, after-tax (2)	(53	)	(76	)	91	(100	)
Gain (Loss) on Divestiture of Assets, after-tax	1		1		1	—
Operating Earnings	313		432		959	1,056

(1)The unrealized risk management gains (losses), after-tax includes the reversal of unrealized gains (losses) recognized in prior periods.

(2)After-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions and deferred income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt.

Operating Earnings decreased $119 million or 28 percent in the third quarter, primarily as a result of:

·Lower Cash Flow as discussed above; and

·Increase in DD&A of $33 million primarily due to higher DD&A rates.

The decrease in Operating Earnings was partially offset by:

·A decline in deferred income tax expense of $56 million, not including income tax on unrealized risk management gains and non-operating unrealized foreign exchange losses, primarily because of decreased U.S. income; and

·A realized foreign exchange gain of $33 million on the early redemption of the US$800 million of senior unsecured notes that was due in September 2014.

Year-to-date Operating Earnings decreased $97 million or nine percent, primarily as a result of:

·Increased DD&A of $189 million, including an impairment loss on our Lower Shaunavon asset held for sale, recorded in the second quarter of 2013; and

·Previously discussed declines in Cash Flow.

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The decline in Operating Earnings was partially offset by:

·A decrease in deferred income tax expense of $164 million, not including income tax on unrealized risk management gains and non-operating unrealized foreign exchange losses;

·No non-cash long-term incentive expense or recovery in 2013 as compared to an expense in 2012;

·Lower exploration expense; and

·A realized foreign exchange gain of $33 million on the extinguishment of debt.

Net Earnings Variance

($ millions)	Three Months Ended		Nine Months Ended
Net Earnings for the Periods Ended September 30, 2012	289		1,112
Increase (Decrease) due to:
Operating Cash Flow	(162	)	5
Corporate and Eliminations:
Unrealized Risk Management (Gain) Loss, after-tax	223		(103	)
Unrealized Foreign Exchange (Gain) Loss	(12	)	(168	)
Expenses (1)	(27	)	(59	)
Depreciation, Depletion and Amortization	(33	)	(189	)
Exploration Expense	—		(41	)
Income Taxes, Excluding Income Taxes on Unrealized Risk Management (Gain) Loss	92		163
Net Earnings for the Periods Ended September 30, 2013	370		720

(1)Includes general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, (gain) loss on divestiture of assets, after-tax, other (income) loss, net and Corporate and Eliminations operating expenses.

In addition to the changes discussed above in the Cash Flow and Operating Earnings sections, our net earnings increased 28 percent during the third quarter, primarily due to unrealized risk management gains, after-tax, of $5 million in the quarter, compared to losses of $218 million in 2012. These increases were partially offset by unrealized foreign exchange gains of $48 million in the quarter, compared to gains of $60 million in 2012.

For the nine months ended September 30, 2013, our net earnings decreased 35 percent primarily due to unrealized foreign exchange losses of $86 million, compared to gains of $82 million in 2012 and unrealized risk management losses after-tax of $147 million compared to losses of $44 million in 2012.

Net Capital Investment

	Three Months Ended September 30,			Nine Months EndedSeptember 30,
($ millions)	2013		2012	2013		2012
Oil Sands	523		516	1,731		1,606
Conventional	178		231	510		591
Refining and Marketing	19		38	70		60
Corporate	23		45	53		133
Capital Investment	743		830	2,364		2,390
Acquisitions	1		8	5		44
Divestitures	(241	)	—	(242	)	(65	)
Net Capital Investment (1)	503		838	2,127		2,369

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

Oil Sands capital investment in 2013 has been focused on the development of the expansion phases at Foster Creek and Christina Lake, development of phase A at Narrows Lake and infill drilling activities related to our Pelican Lake polymer flood. Increases in capital investment were partially offset by declines at Telephone Lake, with the completion of drilling and facility construction for the dewatering pilot in the third quarter of 2012 and the recognition of scientific research and experimental development credits in the third quarter of 2013, and decreased spending at Pelican Lake, as the rate at which we are expanding the polymer flood has slowed to better match our production growth in 2013. Capital investment includes the drilling of 337 gross stratigraphic test wells. The results of these stratigraphic test wells will be used primarily to support the expansion and development of our Oil Sands projects.

In 2013, Conventional capital investment has been centered on drilling, completion and recompletion programs as well as work on facilities, partially offset by reduced capital investment in our Shaunavon asset.

Our capital investment in the Refining and Marketing segment focused on capital maintenance and projects improving refinery reliability and safety in 2013.

Spending on technology development is included in our capital investment. Our teams look for ways to improve existing technology, evaluate new ideas and pursue new technology in an effort to enhance the recovery techniques we use to access crude oil and natural gas and improve our refining processes.

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Capital investment in our Corporate and Eliminations segment decreased as costs related to tenant improvements and information technology were lower due to the move into our new office space in the first quarter of 2013.

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

Capital Investment Decisions

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

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

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

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

This capital allocation process includes evaluating all opportunities using specific rigorous criteria as well as achieving our objectives of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which allows us to be financially resilient in times of lower cash flows.

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013		2012
Cash Flow	932	1,117	2,774		2,946
Capital Investment (Committed and Growth)	743	830	2,364		2,390
Free Cash Flow (1)	189	287	410		556
Dividends Paid	182	166	549		498
	7	121	(139	)	58

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

Over the next decade, we expect to increase our net crude oil production to approximately 525,000 barrels per day. In order to meet project targets, we anticipate our total annual capital investment to average between $3.3 and $3.7 billion for the next decade. While internally generated cash flow from our crude oil, natural gas and refining operations is expected to fund a significant portion of our cash requirements, a portion may be required to be funded through financing activities and management of our asset portfolio. As at September 30, 2013, we had cash and cash equivalents of $1 billion to fund future capital investment. Refer to the Liquidity and Capital Resources section of this MD&A for further discussion of our financial metrics.

REPORTABLE SEGMENTS

Our reportable segments are as follows:

Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as heavy oil assets at Pelican Lake. This segment also includes the Athabasca natural gas assets and projects in the early stages of development such as Grand Rapids and Telephone Lake. 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 carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by Phillips 66. This segment also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

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 and financing activities. 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.

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Revenue by Reportable Segment

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
Oil Sands	1,269		924		3,285		2,851
Conventional	537		450		1,584		1,412
Refining and Marketing	3,459		3,066		9,483		9,020
Corporate and Eliminations	(190	)	(100	)	(442	)	(165	)
	5,075		4,340		13,910		13,118

OIL SANDS

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

Significant factors that impacted our Oil Sands segment in the third quarter compared to 2012 include:

·Christina Lake production increasing 63 percent, to an average of 52,732 barrels per day. Phase D reached full production capacity in 2013 and phase E, our tenth expansion phase, started up in July 2013;

·Foster Creek production averaging 49,092 barrels per day, a decrease of 22 percent, resulting from a number of production matters discussed below;

·Receiving regulatory approval for an optimization program at Christina Lake phases C, D and E which is expected to add 22,000 barrels per day of gross capacity in 2015; and

·Operating cash flow increasing 45 percent as a result of higher crude oil sales prices and increased production volumes.

Oil Sands — Crude Oil

Financial Results

	Three Months Ended September 30,			Nine Months EndedSeptember 30,
($ millions)	2013	2012		2013		2012
Gross Sales	1,324	998		3,368		2,994
Less: Royalties	67	84		124		175
Revenues	1,257	914		3,244		2,819
Expenses
Transportation and Blending	425	367		1,351		1,211
Operating	175	142		519		405
(Gain) Loss on Risk Management	27	(23	)	(9	)	(20	)
Operating Cash Flow	630	428		1,383		1,223
Capital Investment	522	515		1,728		1,600
Operating Cash Flow net of Related Capital Investment	108	(87	)	(345	)	(377	)

Capital expenditures in excess of Operating Cash Flow for the Oil Sands segment are funded through Operating Cash Flow generated by our conventional and refining operations.

Production

	Three Months Ended September 30,				Nine Months Ended September 30,
(barrels per day)	2013	Percent Change		2012	2013	Percent Change		2012
Foster Creek	49,092	(22	)%	63,245	53,450	(7	)%	57,421
Christina Lake	52,732	63	%	32,380	45,211	58	%	28,577
	101,824	6	%	95,625	98,661	15	%	85,998
Pelican Lake	24,826	5	%	23,539	24,162	9	%	22,231
	126,650	6	%	119,164	122,823	13	%	108,229

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Three Months Ended September 30, 2013 Compared to September 30, 2012

Revenue Variance

Revenue Variance for the Three Months Ended September 30, 2013
Compared to September 30, 2012

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

Pricing

In the third quarter, our average crude oil sales price was $82.52 per barrel, 34 percent higher than 2012, generally consistent with the increase in the WCS benchmark price and strengthening of the Christina Dilbit Blend (“CDB”) price.

In the third quarter, approximately 88 percent of our Christina Lake production was sold as CDB (2012 — 85 percent), which sells at a discount to WCS. The remaining Christina Lake production was sold as part of the WCS stream and is subject to a quality equalization charge.

Production

In the third quarter of 2013, Foster Creek production averaged 49,092 barrels per day, a 22 percent decrease from 2012. Our planned major turnaround began in September reducing our volumes by 4,400 barrels per day for the third quarter. We also experienced some minor treating issues in the quarter.

In the third quarter of 2012, we were producing approximately 126,000 barrels per day gross, above our nameplate capacity of 120,000 barrels per day gross. In the fourth quarter of 2012 we chose to defer some routine well maintenance until 2013. This deferral of maintenance resulted in a higher than usual inventory of well maintenance work and had a negative impact on our 2013 production volumes.

Through the nine months ended September 30, 2013, we have been able to complete the majority of our backlog in well work and have recently had time to analyze the data and more fully assess how we are operating the initial phases of Foster Creek. Based on this new information, we have made two key observations on the way we operate Foster Creek. First, with respect to wells, we require more preventative maintenance and are investing in improved instrumentation which will allow for increased data collection and monitoring capability. We have also improved our liner design, which we expect to improve reliability. The second key observation relates to the evolution to common steam chambers in the initial phases of the project and our need to focus on optimizing the formation of common steam chambers across the field rather than on a well or pad basis.

Foster Creek is the industry’s first commercial SAGD project and is a top tier asset that will continue to evolve as we optimize the management of the facilities and maximize the recovery of the reserves. We expect to operate Foster Creek phases A to E at a production level of between 100,000 to 110,000 barrels per day in the near-term at a steam to oil ratio of about 2.4 to 2.5. As we continue to learn more about operating a SAGD project with one common steam chamber, we will look to further optimize production.

Christina Lake production increased as a result of phase D reaching full capacity, approximately six months after production began in the third quarter of 2012, and phase E production continuing to ramp up as expected after first production in mid-July 2013. In the third quarter, we had unplanned minor downtime related to phase E start-up and commissioning.

Pelican Lake production continues to increase from additional infill wells coming on-stream throughout 2012 and 2013 and increased response from our polymer flood program.

Royalties

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

Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate (ranging from one to nine percent) to the gross revenues from the project. Gross revenues are a function of volumes and realized prices.

Royalties for Foster Creek and Pelican Lake, post-payout projects, use an annualized calculation which is based on the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent). Net profits are a function of volumes, realized prices and allowed operating and capital costs.

Royalties decreased in the third quarter primarily as a result of lower volumes at Foster Creek with the production matters noted above, and the commencement of the planned turnaround, as well as increased projected annual capital expenditures and operating costs resulting in a royalty calculation based on gross revenues.

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Effective Royalty Rates

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
(percent)	2013	2012	2013	2012
Foster Creek	7.6	19.1	5.7	13.0
Christina Lake	7.0	5.3	6.4	6.4
Pelican Lake	7.7	6.6	6.7	5.1

Expenses

Transportation and Blending

The heavy oil and bitumen produced by Cenovus requires the blending of condensate to reduce its viscosity in order to transport the product to market. Transportation and blending costs rose $58 million or 16 percent in the third quarter. Blending costs rose $46 million, mainly due to the higher average cost of condensate and increased condensate volumes required for blending with the increase in production at Christina Lake, offset by lower production volumes at Foster Creek. Transportation charges were higher due to production increases and higher sales into the U.S. market which attract higher tariffs.

Operating

Our operating costs for the third quarter were primarily for workforce, workover activities, repairs and maintenance and fuel costs. In total, operating costs increased $33 million or $2.08 per barrel.

Per-unit Operating Costs

	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
($/bbl)	2013	Percent Change		2012	2013	Percent Change		2012
Foster Creek	17.12	49	%	11.50	15.73	28	%	12.26
Christina Lake	11.46	(16	)%	13.59	13.42	(2	)%	13.76
Pelican Lake	19.90	14	%	17.47	20.46	20	%	17.04

At Foster Creek operating costs rose $5.62 per barrel or $13 million. The total dollar increase was associated with:

·Workover activities, as we continue to resolve production matters;

·Repairs and maintenance and workforce costs as a result of a planned turnaround commencing in late September; and

·Fuel prices consistent with the rising benchmark AECO natural gas price and higher fuel consumption.

Increases were partially offset by a decline in chemical costs due to the planned turnaround and the operational issues mentioned above.

Christina Lake operating costs decreased $2.13 on a per barrel basis as a result of higher production volumes. The total dollar increase of $16 million was due to:

·Increasing fuel usage, as a result of rising production and higher fuel prices consistent with the benchmark AECO natural gas price;

·Additional repairs and maintenance costs mainly related to routine maintenance;

·Higher workforce, workover and chemicals costs associated with increased production; and

·Electricity due to higher prices and increased consumption.

Operating costs at Pelican Lake increased $2.43 on a per barrel basis or $4 million due to higher chemical costs and consumption related to the expansion of the polymer flood program and property taxes as a result of the expanded development areas.

Risk Management

Risk management activities resulted in realized losses of $27 million in the third quarter of 2013 (2012 — realized gains of $23 million), consistent with the average benchmark prices exceeding our contract prices.

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Nine Months Ended September 30, 2013 Compared to September 30, 2012

Revenue Variance

Revenue Variance for the Nine Months Ended September 30, 2013
Compared to September 30, 2012

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

Pricing

For the nine months ended September 30, 2013, our average crude oil sales price was $64.29 per barrel, a two percent increase from 2012, generally consistent with the increase in the WCS benchmark price and strengthening of the CDB price.

Approximately 88 percent of our Christina Lake production was sold as CDB (2012 — 70 percent), which sells at a discount to WCS. The CDB price differential to WCS improved $1.34 per barrel compared to 2012, as CDB continues to gain wider market acceptance in 2013. The remaining Christina Lake production was sold as part of the WCS stream and is subject to a quality equalization charge.

Production

Year-to-date production declined at Foster Creek as we have been catching up on the backlog of well maintenance because of a decision made in the fourth quarter of 2012 to defer some of that work. Most of the maintenance backlog is now complete. The substantial increase in production at Christina Lake resulted from phase D, which started up in the third quarter of 2012 and reached full production capacity in 2013, and the start-up of phase E in mid-July 2013. Pelican Lake production increased due to additional infill wells coming on-stream throughout 2012 and 2013 as well as increased response from our polymer flood program.

Royalties

Year-to-date, royalties decreased $51 million primarily related to lower volumes and increased projected annual capital expenditures and operating expense at Foster Creek resulting in a royalty calculation based on gross revenues.

Expenses

Transportation and Blending

Transportation and blending costs rose $140 million or 12 percent year-to-date. Blending costs increased $134 million, mainly due to the increased condensate volumes required for blending with the increase in production from Christina Lake and higher average condensate prices. Transportation charges were higher mainly due to the production growth at Christina Lake.

Operating

Year-to-date, operating costs were primarily for workforce, workover activities, fuel, repairs and maintenance and chemicals. In total, operating costs increased $114 million.

At Foster Creek, operating costs rose $3.47 per barrel or $36 million. The total dollar increase was related to:

·Increased workover activities, as we continue to resolve production matters;

·Rising fuel prices, consistent with the increase in the benchmark AECO natural gas price and higher fuel consumption;

·Higher workforce to support expansions; and

·Higher electricity as a result of increased market rates on purchased electricity, while our cogeneration units were down for maintenance. The cogeneration units returned to operation in July 2013.

Increases were partially offset by lower repairs and maintenance with the 2013 planned turnaround being completed in the fourth quarter. The 2012 planned turnaround was completed in the second quarter.

Christina Lake operating costs decreased $0.34 on a per barrel basis. The total dollar increase of $56 million was related to:

·Higher fuel prices, consistent with the benchmark AECO natural gas price and increased usage to support production growth;

·Higher workforce to support expansions;

·Additional waste, fluid handling and trucking costs due to treating and emulsion hauling associated with the ramp-up of phase D and E and the planned turnaround in the second quarter of 2013; and

·Increased repairs and maintenance cost associated with the planned turnaround.

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Operating costs at Pelican Lake increased $3.42 on a per barrel basis or $22 million. The total dollar increase was due to increased workover activities due to equipment failure, additional chemical consumption related to expansion of the polymer flood and electricity with a rise in market rates and higher consumption.

Risk Management

Risk management activities resulted in realized gains of $9 million (2012 — realized gains of $20 million) year-to-date, consistent with our contract prices exceeding average benchmark prices.

Oil Sands — Natural Gas

Oil Sands also includes our 100 percent owned natural gas operation in Athabasca and other minor natural gas properties. Our natural gas production for the three and nine months ended September 30, 2013 was 25 MMcf per day and 23 MMcf per day, respectively, decreasing as the result of expected natural declines. The internal use of our natural gas production at Foster Creek decreased in the three months ended September 30, 2013 due to the commencement of a planned turnaround in September 2013 and other plant downtime. Internal use of natural gas increased slightly on a year-to-date basis.

Operating Cash Flow was $13 million year-to-date (2012 — $21 million) due primarily to lower realized gains on risk management.

Oil Sands — Capital Investment

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013	2012
Foster Creek	205	199	604	527
Christina Lake	162	147	499	425
	367	346	1,103	952
Pelican Lake	96	128	350	371
Narrows Lake	40	7	90	25
Telephone Lake	1	13	71	117
Grand Rapids	6	7	32	46
Other (1)	13	15	85	95
Capital Investment (2)	523	516	1,731	1,606

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

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

Foster Creek

Capital investment for the third quarter was higher due to phase F pipeline construction and drilling and phase H procurement, partially offset by a reduction in phase G engineering and procurement. For the nine months ended September 30, 2013, spending increased mainly due to phase H site preparation, piling and procurement, phase F drilling and phase G piling and procurement. Year-to-date spending includes the drilling of 111 gross stratigraphic test wells (2012 – 124 gross wells), maintenance capital and the construction of a new camp facility.

Christina Lake

Christina Lake capital investment increased for the three and nine months ended September 30, 2013, primarily due to phase F plant construction, procurement and engineering and phase E plant and well pad construction and drilling of well pairs. Year-to-date capital investment also includes the drilling of stratigraphic test wells (2013 — 69 gross wells; 2012 — 97 gross wells) and maintenance and infrastructure capital.

Pelican Lake

Pelican Lake capital investment was lower in the three and nine months ended September 30, 2013 as the rate at which we were expanding the polymer flood has slowed to better match our production growth. These decreases were partially offset by engineering and procurement for long lead items related to facility construction and maintenance. Capital investment also included the drilling of six stratigraphic test wells (2012 – five wells).

Narrows Lake

Capital investment increased at Narrows Lake in the third quarter and year-to-date due to engineering and procurement, commencement of phase A plant construction in August 2013, and infrastructure. Capital investment also included the drilling of 26 gross stratigraphic test wells (2012 – 38 gross wells).

Telephone Lake

Capital investment on the dewatering pilot, which commenced in the fourth quarter of 2012, continued in 2013 with the removal and reinjection of water and monitoring of results. Capital investment decreased in the third quarter, as increases related to the dewatering pilot were offset by the recognition of $16 million in scientific research and experimental development credits. In the nine months ended September 30, 2013, capital investment was lower than the prior period with the completion of drilling and facility construction for the dewatering pilot in

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the third quarter of 2012. Capital investment also included the drilling of 28 stratigraphic test wells (2012 – 29 wells).

Gross Production Wells Drilled (1)

	Nine Months EndedSeptember 30,
	2013	2012
Foster Creek	31	20
Christina Lake	18	25
	49	45
Pelican Lake	38	52
Grand Rapids	—	1
	87	98

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

Future Capital Investment

Expansion work at phases F, G and H at Foster Creek is proceeding as planned. Additional production capacity of 45,000 gross barrels per day is expected from phase F in the third quarter of 2014, with production from phases G and H expected in 2015 and 2016, respectively. We submitted a joint application and EIA to regulators in February 2013 for an additional expansion, phase J, and we anticipate receiving regulatory approval in the first quarter of 2015. Foster Creek capital investment for 2013 is forecasted to be between $810 million and $830 million.

At Christina Lake, phase E development spending for the completion of drilling and well pad and facility construction is expected to continue to the end of 2014. We expect the ramp-up of phase E will take six to nine months overall, similar to phases C and D, with production capacity expected to reach 138,000 barrels per day gross early in 2014. We received regulatory approval to add cogeneration facilities and to increase expected total gross production capacity by 10,000 barrels per day at each of phases F and G in the fourth quarter of 2012. Expansion work on these phases is continuing in 2013 as planned and we expect production from phases F and G in 2016 and 2017, respectively. In the third quarter of 2013, we received regulatory approval for the optimization program at Christina Lake phases C, D and E which is expected to add 22,000 barrels per day of gross capacity in 2015. We submitted a joint application and EIA to regulators in March 2013 for the phase H expansion, a 50,000 barrel per day phase, for which we expect to receive regulatory approval in the fourth quarter of 2014. In 2013, Christina Lake capital investment is forecasted to be between $675 million and $690 million.

At Pelican Lake, we are continuing with the infill drilling program in addition to piloting new techniques to optimize production. In 2013, the rate at which we are expanding the polymer flood, including construction of a new battery, has slowed to better match our production growth. In 2013, Pelican Lake capital investment is forecasted to be between $480 million and $500 million.

In 2012, we received regulatory approval for Narrows Lake phases A, B and C, and partner approval for phase A. We are continuing with site construction, engineering and procurement and construction of the phase A plant started in the third quarter of 2013. The first phase of the project is anticipated to have a production capacity of 45,000 gross barrels per day, with first oil expected in 2017. Capital investment in the project is forecasted to be between $150 million and $160 million in 2013.

Additional capital investment of approximately $240 million to $250 million in 2013 is expected for our emerging SAGD projects, including Telephone Lake and Grand Rapids. At Telephone Lake, we are advancing the regulatory application for the project and anticipate receiving approval in the second quarter of 2014. In 2013, we are continuing with the dewatering pilot and plan to complete the pilot by the end of October 2013. We have successfully replaced water and confined air, displacing approximately 65 percent of below ground top water in the pilot area to date.

At Grand Rapids we anticipate regulatory approval by the end of 2013. Steam injection started on the second pilot well pair in the third quarter of 2012 and first production was achieved in February 2013. The pilot experienced facility constraints that impacted the production of both well pairs in the first half of 2013. A facility turnaround was performed in the third quarter of 2013 that mitigated these constraints.

Stratigraphic Test Wells

Consistent with our strategy to unlock the value of our resource base, we completed another stratigraphic test well program over the winter drilling season. The stratigraphic test wells drilled at Foster Creek, Christina Lake and Narrows Lake are to support the expansion phases, while the other stratigraphic test wells were drilled to continue gathering data on the quality of our projects and to support regulatory applications for project approval.

To minimize the impact on local infrastructure, the drilling of stratigraphic test wells is primarily completed in the winter months, typically between the end of the fourth quarter and the end of the first quarter. Since 2012, we have been developing the SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. This rig does not require roads for many

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of its locations and reduces the water, drill cuttings and pad size compared to traditional drilling methods. Our first prototype rig has now drilled 42 wells and we are completing the construction of a second rig.

Gross Stratigraphic Test Wells Drilled

	Nine Months EndedSeptember 30,
	2013	2012
Foster Creek	111	124
Christina Lake	69	97
	180	221
Pelican Lake	6	5
Narrows Lake	26	38
Telephone Lake	28	29
Grand Rapids	1	41
Other	96	95
	337	429

CONVENTIONAL

Our Conventional operations include predictable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a carbon dioxide enhanced oil recovery project in Weyburn, and developing tight oil assets in Alberta. The established assets in this segment are strategically important for their long life reserves, stable operations and diversity of crude oil produced.

Significant factors that impacted our Conventional segment in the third quarter compared to 2012 include:

·Crude oil production averaging 50,288 barrels per day, decreasing four percent primarily as successful horizontal well performance associated with our current drilling program was offset by the sale of our Shaunavon asset; and

·Generating Operating Cash Flow, net of capital investment, of $201 million, an increase of 72 percent from 2012.

Conventional — Crude Oil

Financial Results

	Three Months Ended September 30,			Nine Months EndedSeptember 30,
($ millions)	2013	2012		2013		2012
Gross Sales	455	368		1,258		1,187
Less: Royalties	51	38		125		130
Revenues	404	330		1,133		1,057
Expenses
Transportation and Blending	34	27		115		96
Operating	71	78		236		224
Production and Mineral Taxes	10	7		28		24
(Gain) Loss on Risk Management	4	(9	)	(17	)	(9	)
Operating Cash Flow	285	227		771		722
Capital Investment	173	224		493		562
Operating Cash Flow Net of Related Capital Investment	112	3		278		160

Production

	Three Months Ended September 30,				Nine Months Ended September 30,
(barrels per day)	2013	Percent Change		2012	2013	Percent Change		2012
Heavy Oil	15,507	—	%	15,492	16,163	1	%	15,938
Light and Medium Oil	33,651	(6	)%	35,695	36,081	—	%	36,083
NGLs	1,130	13	%	999	1,018	(2	)%	1,041
	50,288	(4	)%	52,186	53,262	—	%	53,062

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Three Months Ended September 30, 2013 Compared to September 30, 2012

Revenue Variance

Revenue Variance for the Three Months Ended September 30, 2013
Compared to September 30, 2012

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

Pricing

In the third quarter, our average crude oil sales price increased 30 percent to $95.54 per barrel, consistent with the change in crude oil benchmark prices and the narrowing of associated differentials.

Production

Our crude oil production was 1,898 barrels per day lower in the third quarter primarily due to a 2,044 barrels per day decline in light and medium crude oil production as a result of the sale of our Shaunavon asset in July 2013, partially offset by improved horizontal well performance. During the third quarter of 2013 we had no production volumes associated with Shaunavon (2012 — 4,550 barrels per day).

Royalties

Royalties increased by $13 million in the quarter, as a result of higher crude oil prices, partially offset by a decline in production volumes. The effective crude oil royalty rate in the third quarter for the Conventional segment was 12.4 percent (2012 — 11.1 percent). Most of our crude oil production in the Conventional segment is located on fee lands which results in mineral tax recorded within production and mineral taxes.

Expenses

Transportation and Blending

Transportation and blending costs were $7 million higher for the third quarter. Transportation costs rose $8 million due to the higher cost associated with transporting our light and medium crude oil production by rail. During the quarter, we transported approximately 4,100 barrels per day by rail to the East Coast and the U.S. (2012 — 3,150 barrels per day). The overall cost of condensate used in blending decreased $1 million as a result of lower condensate volumes, partially offset by higher condensate prices.

Operating

In the third quarter of 2013, operating costs of $71 million were predominantly composed of workover activities, electricity and workforce. Compared to the third quarter of 2012, operating costs declined $7 million primarily due to decreases in production volumes as a result of the Shaunavon sale, partially offset by rising electricity costs due to higher market rates.

Risk Management

Risk management activities in the third quarter resulted in realized losses of $4 million (2012 — realized gains of $9 million) consistent with the average benchmark prices exceeding our contract prices.

Operating Cash Flow, Net of Capital Investment

Operating Cash Flow, net of capital investment increased by $109 million in the third quarter due to higher Operating Cash Flow and lower capital investment.

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Nine Months Ended September 30, 2013 Compared to September 30, 2012

Revenue Variance

Revenue Variance for the Nine Months Ended September 30, 2013
Compared to September 30, 2012

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

Pricing

Year-to-date, our average crude oil sales price increased six percent to $82.61 per barrel, consistent with the change in crude oil benchmark prices and as a result of higher realized prices on volumes shipped by rail.

Production

Overall, our crude oil production remained flat as higher heavy crude oil production was offset by reduced production from the sale of our Shaunavon asset in July 2013. During the nine months ended September 30, 2013, Shaunavon production averaged 2,807 barrels per day (2012 — 4,265 barrels per day).

Royalties

Royalties decreased $5 million largely due to lower royalties in Suffield as a result of lower production volumes, partially offset by higher prices. The effective crude oil royalty rate during the nine months of the year was 11.1 percent (2012 — 12.2 percent).

Expenses

Transportation and Blending

Transportation and blending costs increased $19 million year-to-date. Transportation costs rose $17 million due to the higher cost associated with transporting our light and medium crude oil production by rail. During the nine months of 2013, we transported approximately 6,000 barrels per day by rail to the East Coast and the U.S. (2012 — 2,000 barrels per day). The overall cost of condensate used in blending increased $2 million as a result of higher condensate volumes and higher condensate prices.

Operating

Year-to-date, operating costs were predominantly composed of workforce, workover activities, and electricity. Operating costs rose $12 million as compared to 2012, primarily due to rising electricity costs from higher market rates, increased workforce costs, higher property taxes and workover activities associated with high-return well optimizations that have helped mitigate production declines, partially offset by declines in repairs and maintenance.

Risk Management

Risk management activities resulted in realized gains of $17 million (2012 — realized gains of $9 million), consistent with our contract prices exceeding average benchmark prices.

Operating Cash Flow, Net of Capital Investment

Operating Cash Flow, net of capital investment, increased by $118 million due to higher Operating Cash Flow and lower capital investment.

Conventional — Natural Gas

Financial Results

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
Gross Sales	130		116		447		350
Less: Royalties	2		1		6		4
Revenues	128		115		441		346
Expenses
Transportation and Blending	4		4		15		15
Operating	50		53		155		155
Production and Mineral Taxes	1		2		2		4
(Gain) Loss on Risk Management	(18	)	(62	)	(45	)	(186	)
Operating Cash Flow	91		118		314		358
Capital Investment	5		7		17		29
Operating Cash Flow Net of Related Capital Investment	86		111		297		329

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Three Months Ended September 30, 2013 Compared to September 30, 2012

Revenues Variance

Revenue Variance for the Three Months Ended September 30, 2013
Compared to September 30, 2012

Pricing

In the third quarter, our average natural gas sales price increased $0.54 per Mcf to $2.85 per Mcf, consistent with the rise in the benchmark AECO natural gas price.

Production

Production decreased nine percent to 498 MMcf per day in the third quarter primarily due to expected natural declines.

Royalties

Royalties increased in the third quarter as a result of higher prices, despite production declines. The average royalty rate in the third quarter was 1.5 percent (2012 — 1.1 percent). Most of our natural gas production in the Conventional segment is located on fee lands where we hold mineral rights which results in mineral tax being recorded within production and mineral taxes.

Expenses

Transportation

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

Operating

Our operating expenses were composed of property taxes and lease costs, workforce and repairs and maintenance. Operating expenses decreased $3 million due to a reduction in natural gas production.

Risk Management

Risk management activities resulted in realized gains in the third quarter of $18 million (2012 — realized gains of $62 million), consistent with our contract prices exceeding the average benchmark price.

Operating Cash Flow, Net of Capital Investment

Our Conventional natural gas assets generate significant Operating Cash Flow with minimal capital investment. Operating Cash Flow, net of capital investment decreased 23 percent to $86 million in the third quarter due to lower Operating Cash Flow and relatively flat capital investment.

Nine Months Ended September 30, 2013 Compared to September 30, 2012

Revenue Variance

Revenue Variance for the Nine Months Ended September 30, 2013
Compared to September 30, 2012

Pricing

Year-to-date, our average natural gas sales price increased $0.95 per Mcf to $3.20 per Mcf, consistent with the rise in the benchmark AECO natural gas price.

Production

Production decreased 10 percent to 512 MMcf per day primarily due to expected natural declines.

Royalties

Royalties increased as a result of higher prices, despite declines in production. The average royalty rate was 1.5 percent (2012 — 1.3 percent).

Expenses

Transportation

Transportation costs remained flat year-to-date with higher pipeline rates offset by lower production volumes.

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Operating

For the nine months ended September 30, 2013, our operating expenses are composed primarily of property taxes and lease costs, workforce and repairs and maintenance. Operating expenses remained flat when compared to 2012.

Risk Management

Risk management activities resulted in year-to-date realized gains of $45 million (2012 — realized gains of $186 million) consistent with our contract prices exceeding the average benchmark price.

Operating Cash Flow, Net of Capital Investment

Operating Cash Flow from natural gas net of capital investment decreased $32 million to $297 million, due to lower Operating Cash Flow offset by reduced capital investment.

Conventional — Capital Investment (1)

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013	2012
Crude Oil	173	224	493	562
Natural Gas	5	7	17	29
	178	231	510	591

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

Capital investment in our Conventional segment focused on crude oil opportunities. In the three and nine months ended September 30, 2013, capital was invested primarily in our tight oil drilling programs and in drilling and facilities work at Weyburn. Spending on natural gas activities continues to be managed in response to the low price natural gas environment.

In June 2013, we entered into a purchase and sale agreement with an unrelated third party, to sell our Lower Shaunavon asset. The sale was completed in July 2013 for proceeds of $240 million plus closing adjustments. We continue to market certain of our Bakken assets. The Bakken properties for sale had crude oil production averaging 617 barrels per day year-to-date in 2013 (2012 — 1,228 barrels per day).

Conventional Drilling Activity

	Nine Months EndedSeptember 30,
(net wells, unless otherwise stated)	2013	2012
Crude Oil	117	202
Recompletions	649	745
Gross Stratigraphic Test Wells	32	7

Crude oil wells drilled, primarily horizontal wells, reflect the ongoing development of our Conventional properties. Well recompletions are mostly related to low-risk southern Alberta coal bed methane development that continues to deliver acceptable rates of return.

REFINING AND MARKETING

We are a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. Our Refining and Marketing segment allows us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated strategy provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to our refineries. The Refining and Marketing segment’s results are affected by changes in the U.S./Canadian dollar exchange rate.

Significant factors related to our Refining and Marketing segment in the third quarter, compared to 2012, include:

·Our refineries processing 464,000 barrels per day of crude oil, including 240,000 barrels per day of heavy crude oil, resulting in 487,000 barrels per day of refined product output, an increase of five percent, as refined product output was reduced in 2012 as a result of minor refinery outages; and

·Operating Cash Flow decreasing 74 percent to $137 million primarily due to a sharp decline in market crack spreads and higher refinery feedstock costs consistent with the increase in WCS benchmark price and the narrowing of the WTI-WCS differential, partially offset by higher refined product output.

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Refinery Operations (1)

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
	2013	2012	2013	2012
Crude Oil Capacity (2)(Mbbls/d)	457	452	457	452
Crude Oil Runs (Mbbls/d)	464	442	440	446
Heavy Oil	240	210	223	213
Light/Medium	224	232	217	233
Crude Utilization (percent)	101	98	96	99
Refined Products (Mbbls/d)	487	463	461	467
Gasoline	244	224	230	231
Distillate	152	148	143	152
Other	91	91	88	84

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

(2)The official nameplate capacity of Wood River increased effective January 1, 2013.

On a 100 percent basis, our refineries have a capacity of approximately 457,000 barrels per day of crude oil and 45,000 barrels per day of NGLs, including processing capability to refine between 235,000 to 255,000 barrels per day of blended heavy crude oil. The ability to refine heavy crudes demonstrates our ability to economically integrate our heavy oil production.

In the three months ended September 30, 2013, the amount of crude oil processed increased five percent of which the amount of heavy crude oil increased 14 percent as both refineries operated efficiently with minimal disruptions compared to minor outages experienced in the third quarter of 2012. Year-to-date, our crude oil processed decreased one percent primarily as a result of planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter of 2013.

Our crude utilization represents the percentage of crude oil, heavy and other, that is processed in our refineries relative to the total capacity. The amount of heavy crude oils processed, such as WCS and CDB, is dependent on the quality of available crude oils with the total crude input slate being optimized to maximize economic benefit.

Total refined product output increased by five percent in the third quarter and declined one percent year-to-date, with the proportion of gasoline, distillate and other refined products remaining relatively the same. The improvement in the third quarter was primarily due to minor refinery outages in 2012. The year-to-date decline is the result of planned maintenance in the first quarter of 2013 and an unplanned hydrocracker outage in the second quarter of 2013.

Financial Results

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013	2012
Revenues	3,459	3,066	9,483	9,020
Purchased Product	3,172	2,403	8,065	7,500
Gross Margin	287	663	1,418	1,520
Expenses
Operating	129	136	404	389
(Gain) Loss on Risk Management	21	—	29	(14	)
Operating Cash Flow	137	527	985	1,145
Capital Investment	19	38	70	60
Operating Cash Flow, Net of Capital Investment	118	489	915	1,085

Three Months Ended September 30, 2013 Compared to September 30, 2012

Gross Margin

The gross margin for the Refining and Marketing segment declined $376 million, or 57 percent in the third quarter, as a result of sharp declines in market crack spreads due to increases in refinery feedstock costs consistent with the increase in WTI benchmark pricing. In addition, narrower discounts on both Canadian heavy and U.S. inland crude oil and higher costs associated with RINs increased feedstock costs at our refineries, negatively affecting gross margin.

As part of the U.S. Environmental Protection Agency’s (“EPA”) Renewable Fuel Standards, refineries in the U.S. are obligated to blend renewable fuels (such as ethanol) into petroleum-based motors fuel products at rates determined by the EPA. To the extent they do not, refineries must purchase credits, referred to as RINs, in the open market. RINs are a number assigned to each gallon of renewable fuel produced or imported into the U.S., and were implemented to provide refiners with flexibility in complying with the renewable fuel standards.

Our refineries do not blend renewable fuels into their motor fuel products and consequently we are obligated to purchase RINs in the open market. Since the beginning of 2013, the cost of RINs has increased significantly due

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primarily to the current and potential impending increases to the EPA’s mandated blending quotas. In the three months ended September 30, 2013, the cost associated with RINs increased $45 million compared to 2012, consistent with the increase in the ethanol benchmark price of US$0.83 per barrel. Despite the recent increase in RIN prices, these costs remain a minor component of our total refinery feedstock costs.

Operating

Total operating costs for the three months ended September 30, 2013 consist mainly of labour, maintenance, utilities and supplies. Operating costs were lower by $7 million, or five percent, due to lower maintenance expense during the quarter, partially offset by higher utilities expense from increased throughput and natural gas prices.

Operating Cash Flow

Operating Cash Flow from the Refining and Marketing segment decreased $390 million, or 74 percent, primarily due to declines in market crack spreads, as well as, narrower discounts on both Canadian heavy and U.S. inland crude oil, increasing feedstock costs.

Nine Months Ended September 30, 2013 Compared to September 30, 2012

Gross Margin

The gross margin for the Refining and Marketing segment declined $102 million, or seven percent, year-to-date as a result of lower market crack spreads, increases in refinery crude oil feedstock costs consistent with increases in the WCS benchmark prices, declines in refined product output from planned maintenance in the first quarter and an unplanned hydrocracker outage in the second quarter, and increased costs associated with RINs. The cost associated with RINs is a minor component of our total refinery feedstock costs and increased $105 million as compared to 2012, consistent with the increase in the ethanol benchmark price of US$0.64 per barrel. Refined product prices increased during the nine months ended September 30, 2013.

Operating

Total operating costs for the nine months ended September 30, 2013 consist mainly of labour, maintenance, utilities and supplies. Operating costs were higher by $15 million, or four percent, due to planned maintenance activities in the first quarter and higher utilities as natural gas prices have increased.

Operating Cash Flow

Operating Cash Flow from the Refining and Marketing segment declined $160 million, or 14 percent year-to-date due to lower market crack spreads, increases in refinery crude oil feedstock costs and declines in refined product output.

Refining and Marketing — Capital Investment

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013	2012
Wood River Refinery	12	22	38	28
Borger Refinery	7	15	32	31
Marketing	—	1	—	1
	19	38	70	60

Capital expenditures year-to-date focused on capital maintenance and projects improving refinery reliability and safety. In the first quarter of 2012, we recognized Illinois tax credits of $14 million related to capital expenditures incurred at the Wood River Refinery in prior periods, which reduced capital investment for the nine months ended September 30, 2012.

Future capital investment may include heavy crude debottlenecking opportunities at our Wood River Refinery.

DD&A

	Three Months Ended September 30,		Nine Months EndedSeptember 30,
($ millions)	2013	2012	2013	2012
Oil Sands	153	127	451	352
Conventional	220	222	753	680
Refining and Marketing	37	36	102	109
Corporate and Eliminations	20	12	59	35
	430	397	1,365	1,176

Oil Sands DD&A in the third quarter increased $26 million (year-to-date — $99 million increase) due to additional sales volumes at Christina Lake and Pelican Lake and higher DD&A rates for all of our properties. The year-to-date

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DD&A rates averaged 16 percent higher due to higher future development costs associated with total proved reserves.

DD&A in the Conventional segment was $2 million lower in the third quarter (year-to-date — increased $73 million) primarily due to the sale of the Shaunavon asset. Year-to-date, DD&A was higher as a result of an increase in the average DD&A rate of eight percent from 2012 due to lower proved reserves. During the second quarter of 2013 there was an impairment loss of $57 million related to our Lower Shaunavon asset sold in July 2013.

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. The increase in 2013 is due to the depreciation of our new office space leaseholds which commenced in October 2012.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices and unrealized mark-to-market gains and losses on the long-term power purchase contract. Unrealized gains on risk management before tax were $8 million for the third quarter (2012 — unrealized losses of $293 million) and year-to-date unrealized losses before tax were $196 million (2012 — unrealized losses of $60 million). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative and financing activities.

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
General and Administrative	103		104		268		253
Finance Costs	160		120		407		344
Interest Income	(23	)	(28	)	(73	)	(84	)
Foreign Exchange (Gain) Loss, net	(55	)	(51	)	93		(42	)
(Gain) Loss on Divestitures	1		1		1		—
Other (Income) Loss, net	—		—		—		(4	)
	186		146		696		467

Three and Nine Months Ended September 30, 2013 Compared to September 30, 2012

General and Administrative

General and administrative expenses remained consistent quarter over quarter, with slight increases in staffing and rent costs offset by slight declines in long-term incentive costs. For the nine months ended September 30, 2013, the increase of $15 million was due to higher staffing and rent costs, offset by lower long-term incentive costs.

Finance Costs

Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated Partnership Contribution Payable, as well as the unwinding of the discount on decommissioning liabilities. In the third quarter, finance costs were $40 million higher (year-to-date — $63 million increase) than 2012 due to a US$32 million premium paid on the early redemption of the US$800 million of senior unsecured notes that were due in September 2014, interest incurred on US$1.25 billion of senior unsecured notes issued on August 17, 2012 and US$800 million of senior unsecured notes issued August 15, 2013. Increases were partially offset by lower interest incurred on the Partnership Contribution Payable as the balance continues to be repaid. The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for the third quarter was 5.2 percent (2012 — 5.2 percent) and for the nine months ended September 30, 2013 was 5.3 percent (2012 — 5.3 percent).

Interest Income

Interest income includes interest earned on our short-term investments and U.S. dollar denominated Partnership Contribution Receivable. Interest income for the three and nine months ended September 30, 2013 decreased by $5 million and $11 million, respectively, consistent with lower interest earned on the Partnership Contribution Receivable as the balance continues to be collected.

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Foreign Exchange

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013	2012
Unrealized Foreign Exchange (Gain) Loss	(48	)	(60	)	86	(82	)
Realized Foreign Exchange (Gain) Loss	(7	)	9		7	40
	(55	)	(51	)	93	(42	)

The majority of unrealized losses stem from translation of our U.S. dollar denominated debt as a result of a weaker Canadian dollar at September 30, 2013 partially offset by unrealized gains on our U.S. dollar denominated Partnership Contribution Receivable. During the third quarter a realized foreign exchange gain of $33 million was recorded on the early redemption of the US$800 million senior unsecured notes that were due in September 2014.

Income Tax Expense

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
Current Tax
Canada	60		56		147		139
United States	(20	)	20		38		45
Total Current Tax	40		76		185		184
Deferred Tax	132		110		211		408
	172		186		396		592
Effective Tax Rate	31.7	%	39.2	%	35.5	%	34.7	%

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

Our effective tax rate also reflects the application of the relevant statutory tax rates to income from Canadian and U.S. sources. Our effective tax rate for the third quarter has decreased in comparison to 2012 due to lower U.S. income offset by increased Canadian income. Our year-to-date effective tax rate is comparable to 2012 because the relative levels of Canadian and U.S. source income are similar.

Current tax expense for the three months ended September 30, 2013 decreased as it includes a recovery of U.S. tax which reflects lower estimates of U.S. source income for 2013. Current tax expense for the nine months ended September 30, 2013 is comparable to 2012.

Deferred income tax expense for the third quarter of 2013 is higher than in 2012 as a result of increased Canadian income, primarily due to unrealized risk management gains in the quarter as compared to losses in 2012, partially offset by decreased U.S. income. Deferred income tax expense for the nine months ended September 30, 2013 decreased compared to 2012, primarily because of lower earnings.

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for taxes is adequate.

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended September 30,				Nine Months EndedSeptember 30,
($ millions)	2013		2012		2013		2012
Net Cash From (Used In)
Operating Activities	840		1,029		2,563		2,662
Investing Activities	(451	)	(741	)	(2,157	)	(2,361	)
Net Cash Provided (Used) Before Financing Activities	389		288		406		301
Financing Activities	(190	)	852		(539	)	760
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	—		(6	)	(3	)	(13	)
Increase (Decrease) in Cash and Cash Equivalents	199		1,134		(136	)	1,048

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Operating Activities

Cash from operating activities was $189 million lower in the third quarter (year-to-date — decrease of $99 million). The declines in both the three and nine months ended September 30, 2013 was mainly due to decreases in Cash Flow as discussed in the Financial Results section of this MD&A.

Excluding risk management assets and liabilities and assets and liabilities held for sale, we had working capital of $1,128 million at September 30, 2013 compared to $1,043 million at December 31, 2012. We anticipate that we will continue to meet our payment obligations as they come due.

Investing Activities

Cash used in investing activities in the third quarter was $290 million lower (year-to-date — decrease of $204 million) than in 2012. The change in both the three and nine months ended September 30, 2013 was primarily due to the proceeds received on the sale of our Shaunavon asset.

Financing Activities

Our disciplined approach to capital investment decisions means that we prioritize our use of Cash Flow first to committed capital investment, then to paying a meaningful dividend and finally to growth capital. In the third quarter, we paid a dividend of $0.242 per share, an increase of 10 percent from 2012 (2012 — $0.22 per share). Total dividend payments year-to-date are $549 million (2012 — $498 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

In the third quarter, cash flow used in financing activities increased $1,042 million (year-to-date — $1,299) primarily as a result of the issuance and repayment of debt as discussed below.

On August 15, 2013, we completed a public offering in the U.S. of senior unsecured notes in the aggregate principal amount of US$800 million under our U.S. base shelf prospectus. We issued US$450 million of our senior unsecured notes with a coupon rate of 3.8 percent due September 15, 2023 and US$350 million of senior unsecured notes with a coupon rate of 5.2 percent due September 15, 2043. The net proceeds of the offering were used to partially fund the early redemption of our US$800 million senior unsecured notes due September 2014. The offering allowed us to secure favorable interest rates while also extending the weighted average term to maturity of our long-term debt.

Our long-term debt was $4,830 million at September 30, 2013 with no principal payments due until October 2019 (US$1.3 billion). The $151 million increase in long-term debt from December 31, 2012 was related to foreign exchange.

Available Sources of Liquidity

As at	September 30, 2013
($ millions)	Amount		Term
Cash and Cash Equivalents	1,024		Not Applicable
Committed Credit Facility	3,000		November 2017
Canadian Base Shelf Prospectus (1)	1,500		June 2014
U.S. Base Shelf Prospectus (1)	US$	1,200	July 2014

(1)Availability is subject to market conditions.

A portion of our future cash requirements may be funded through management of our asset portfolio. In the first quarter of 2013, Cenovus decided to launch a public sales process to divest its Lower Shaunavon and certain of its Bakken properties in Saskatchewan. In the third quarter, the Shaunavon asset was sold for proceeds of $240 million plus closing adjustments. We continue to market certain of our Bakken properties.

On May 9, 2013, we amended our U.S. base shelf prospectus for senior unsecured notes to increase the total capacity from US$2.0 billion to US$3.25 billion. The terms of the notes, including, but not limited to, the principal amount, interest at either fixed or floating rates and maturity dates, will be determined at the date of issue. As at September 30, 2013, we have unused capacity of US$1.2 billion, the availability of which is dependent on market conditions.

In September 2013, we renegotiated our existing $3.0 billion committed credit facility extending the maturity date from November 30, 2016 to November 30, 2017.

As at September 30, 2013, we are in compliance with all of the terms of our debt agreements.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. We define our non-GAAP measure of Debt as short-term borrowings and the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable. We define Capitalization as Debt plus Shareholders’ Equity. We define trailing 12-month Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, DD&A, asset impairments, unrealized gains (losses) on risk management, foreign

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exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net. These metrics are used to steward our overall debt position and as measures of our overall financial strength.

	September 30,		December 31,
As at	2013		2012
Debt to Capitalization	32	%	32	%
Debt to Adjusted EBITDA (times)	1.2	x	1.1	x

We continue to have long-term targets for a Debt to Capitalization ratio of between 30 to 40 percent and a Debt to Adjusted EBITDA ratio of between 1.0 to 2.0 times. At September 30, 2013, our Debt to Capitalization and Debt to Adjusted EBITDA metrics were near the low end of our target ranges.

At September 30, 2013, our financial position, as measured by our Debt to Capitalization ratio and Debt to Adjusted EBITDA ratio, remained relatively consistent with the end of 2012. Additional information regarding our financial metrics and capital structure can be found in the notes to the interim Consolidated Financial Statements.

Outstanding Share Data and Stock-based Compensation Plans

Cenovus is authorized to issue an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of third preferred shares. As at September 30, 2013, no preferred shares were outstanding.

As part of our long-term incentive program, Cenovus has an employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of Cenovus. Options issued by Cenovus prior to February 24, 2011, have associated tandem stock appreciation rights (“TSARs”) and options issued after February 24, 2011 have associated net settlement rights (“NSRs”).

In addition to its Stock Option Plan, Cenovus has a Performance Share Unit (“PSU”) Plan and two Deferred Share Unit (“DSU”) Plans. PSUs are whole share units which, upon vesting, entitle the holder to receive either a Cenovus common share or a cash payment equal to the value of a Cenovus common share. DSUs vest immediately and are equivalent in value to a Cenovus common share on the date of redemption.

Our stock options are measured at fair value using the Black-Scholes-Merton valuation model and other stock-based compensation plans are measured at fair value based on the market value of our common shares. The fair value of our TSARs, PSUs and DSUs are measured at each reporting date and therefore are sensitive to fluctuations in our common share price. The fair value of NSRs is determined at the date of grant and is not re-measured at each reporting date. As NSRs become a higher proportion of our long-term incentive grants, our long-term incentive costs will become less sensitive to common share price fluctuations. The weighted average remaining contractual life of the TSARs, NSRs and PSUs are 1.41, 5.68 and 1.50 years, respectively. See the notes to the interim and annual Consolidated Financial Statements for details of our stock-based compensation plans.

Total Outstanding Common Shares and Stock-based Compensation Plans

(thousands of units)	September 30, 2013
Common Shares	755,842
Stock Options
NSRs	26,153
TSARs	7,627
Cenovus Replacement TSARs (held by Encana Employees)	2,191
Encana Replacement TSARs (held by Cenovus Employees)	4,023
Other Stock-based Compensation Plans
PSUs	5,789
DSUs	1,182

Contractual Obligations and Commitments

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

Year-to-date, Cenovus entered into various firm transportation agreements totaling approximately $11 billion. These agreements, some of which are subject to regulatory approval, are for terms up to 20 years, subsequent to the date of commencement, and will help align our future transportation requirements within our anticipated production growth.

In addition, Cenovus entered into an office lease agreement totaling approximately $1 billion over a 22 year term beginning upon completion of construction of the building expected to be late in 2017.

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Legal Proceedings

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

RISK MANAGEMENT

For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with our 2012 annual MD&A.

Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. Actively managing these risks improves our ability to effectively execute our business strategy. Our exposure to liquidity risk, safety risk, transportation restrictions, capital project execution and operating risk, reserves replacement risk, environmental risk and regulatory risk has not changed substantially since December 31, 2012.

A description of the risk factors and uncertainties affecting Cenovus can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2012. The following provides an overview of our commodity price risk management activities and the effect of our risk management position on earnings for the three and nine months ending September 30, 2013.

Commodity Price Risk

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

We manage our commodity price exposure through a combination of integration, financial hedges and physical contracts. Our business model partially mitigates our exposure to light/heavy differentials and refinery margins through our upstream and downstream integration. In addition, our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our upstream and refining operations. We further reduce our exposure to commodity price risk through the use of various financial instruments and select physical contracts.

The details of these financial instruments as at September 30, 2013 are disclosed in the notes to the interim Consolidated Financial Statements. The financial impact is summarized below.

Financial Impact of Risk Management Activities

	Three Months Ended September 30,
	2013						2012
($ millions)	Realized		Unrealized		Total		Realized	Unrealized		Total
Crude Oil	(32	)	22		(10	)	26	(189	)	(163	)
Natural Gas	19		(15	)	4		65	(83	)	(18	)
Refining	(22	)	2		(20	)	6	(11	)	(5	)
Power	2		(1	)	1		2	(10	)	(8	)
Gain (Loss) on Risk Management	(33	)	8		(25	)	99	(293	)	(194	)
Income Tax Expense (Recovery)	(11	)	3		(8	)	26	(75	)	(49	)
Gain (Loss) on Risk Management, after-tax	(22	)	5		(17	)	73	(218	)	(145	)

	Nine Months Ended September 30,
	2013						2012
($ millions)	Realized		Unrealized		Total		Realized	Unrealized		Total
Crude Oil	22		(147	)	(125	)	26	102		128
Natural Gas	46		(51	)	(5	)	200	(144	)	56
Refining	(30	)	1		(29	)	18	(3	)	15
Power	7		1		8		—	(15	)	(15	)
Gain (Loss) on Risk Management	45		(196	)	(151	)	244	(60	)	184
Income Tax Expense (Recovery)	7		(49	)	(42	)	64	(16	)	48
Gain (Loss) on Risk Management, after-tax	38		(147	)	(109	)	180	(44	)	136

In the three months ended September 30, 2013, management of commodity price risk resulted in realized losses on crude oil financial instruments consistent with the average benchmark prices exceeding our contract prices. We recognized realized gains on our natural gas financial instruments, consistent with our contract prices exceeding the average benchmark price. We recognized unrealized gains on our crude oil financial instruments as a result of the decrease in forward commodity prices, the widening of forward light/heavy differentials, compared to prices at the end of the prior quarter, and the realization of settled positions. Management of our natural gas financial

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instruments resulted in unrealized losses as a result of the increase in forward commodity prices and the realization of settled positions.

For the nine months ended September 30, 2013, management of commodity price risk resulted in realized gains on crude oil and natural gas financial instruments consistent with our contract prices exceeding the average benchmark price. We recognized unrealized losses on our crude oil and natural gas financial instruments as a result of the increase in forward commodity prices, the narrowing of forward light/heavy differentials, compared to prices at the end of the prior year, and the realization of settled positions.

Financial instruments undertaken within our refining segment by the operator, Phillips 66, are primarily for purchased product. Details of contract volumes and prices can be found in the notes to the interim Consolidated Financial Statements.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES

For more details regarding our critical accounting judgments, estimates and accounting policies the following should be read in conjunction with our 2012 annual MD&A.

We are required to make judgments, estimates and assumptions in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from those estimates and those differences may be material. The estimates and assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of presentation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2012.

Critical Accounting Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recognized in Cenovus’s annual and interim Consolidated Financial Statements and accompanying notes. On January 1, 2013, as required, we adopted the standards related to joint arrangements, consolidations and associates, which required critical judgments. See discussion below under Joint Arrangements, Consolidation, Associates and Disclosures for details. Further information on our critical accounting judgments in applying accounting policies can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2012.

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recognized in the period in which the estimates are revised. There have been no changes to our key sources of estimation uncertainty for the nine months of 2013. Further information on our key sources of estimation uncertainty can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2012.

Changes in Accounting Policies

Joint Arrangements, Consolidation, Associates and Disclosures

As disclosed in the Consolidated Financial Statements, effective January 1, 2013, Cenovus adopted, as required, IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), IFRS 11, “Joint Arrangements” (“IFRS 11”), IFRS 12, “Disclosure of Interests in Other Entities” (“IFRS 12”) as well as the amendments to International Accounting Standard (“IAS”) 28, “Investments in Associates and Joint Ventures” (“IAS 28”).

Cenovus reviewed its consolidation methodology and determined that the adoption of IFRS 10 did not result in a change in the consolidation status of its subsidiaries and investees.

Under IFRS 11, interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Cenovus performed a comprehensive review of its interests in other entities and identified two individually significant interests, FCCL Partnership (“FCCL”) and WRB Refining LP (“WRB”), for which it shares joint control. Previously, Cenovus accounted for these jointly controlled entities using proportionate consolidation.

Cenovus reviewed these joint arrangements considering their structure, the legal forms of any separate vehicles, the contractual terms of the arrangements and other facts and circumstances. The application of Cenovus’s accounting policy under IFRS 11 requires judgment in determining the classification of these joint arrangements. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB. As a result, these joint arrangements have been classified as joint operations under IFRS 11 and Cenovus’s share of the assets, liabilities, revenues and expenses have been recognized in our interim Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, Cenovus considered the following:

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·The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially, on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

·The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third party borrowings.

·FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business.

·Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and as such are not capable of performing these roles.

·In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

There has been no impact on the recognized assets, liabilities and comprehensive income of Cenovus with the application of these standards.

Employee Benefits

As disclosed in the Consolidated Financial Statements, effective January 1, 2013, Cenovus adopted, as required, by IAS 19 “Employee Benefits”, as amended in June 2011 (“IAS 19R”). Cenovus applied the standard retrospectively and in accordance with the transitional provisions. The opening Consolidated Balance Sheet of the earliest comparative period presented (January 1, 2012) was restated.

The amendments require the recognition of changes in defined benefit pension obligations and plan assets when they occur, eliminating the ‘corridor approach’ previously permitted and accelerating the recognition of past service costs. In order for the net defined benefit liability or asset to reflect the full value of the plan deficit or surplus, all actuarial gains and losses are recognized immediately through other comprehensive income. In addition, Cenovus replaced interest costs on the defined benefit obligation and the expected return on plan assets with a net interest cost based on the net defined benefit asset or liability measured by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period. Interest expense and interest income on net post-employment benefit liabilities and assets continue to be recognized in net earnings.

IAS 19R requires termination benefits to be recognized at the earlier of when the entity can no longer withdraw an offer of termination benefits or recognizes any restructuring costs. This requirement had no impact on the Consolidated Financial Statements.

The impact on adoption of IAS 19R was not material and is shown below:

Consolidated Statements of Earnings and Comprehensive Income

($ millions)	Three MonthsEndedSeptember 30, 2012		Nine MonthsEndedSeptember 30, 2012		Year EndedDecember 31, 2012
Increase (Decrease) due to:
Net Earnings	—		1		2
Other Comprehensive Income	(1	)	(3	)	(4	)

Consolidated Balance Sheets

($ millions)	December 31, 2012		January 1, 2012
Increase (Decrease) due to:
Net Defined Benefit Liability (1)	32		30
Deferred Income Taxes	(8	)	(8	)
Shareholders’ Equity	(24	)	(22	)

(1)Composed of the defined benefit pension and other post-employment benefit plans.

Fair Value Measurement

Effective January 1, 2013, Cenovus adopted, as required, IFRS 13, “Fair Value Measurement” (“IFRS 13”) and applied the standard prospectively as required by the transitional provisions. The standard provides a consistent definition of fair value and introduces consistent requirements for disclosures related to fair value measurement. There has been no change to Cenovus’s methodology for determining the fair value for its financial assets and

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liabilities and, as such, the adoption of IFRS 13 did not result in any measurement adjustments as at January 1, 2013.

Presentation of Items in Other Comprehensive Income

Effective January 1, 2013, Cenovus applied the amendment to IAS 1, “Presentation of Financial Statements” (“IAS 1”), as amended in June 2011. The amendment requires items within other comprehensive income (“OCI”) to be grouped into two categories: (1) items that will not be subsequently reclassified to profit or loss or (2) items that may be subsequently reclassified to profit or loss when specific conditions are met. The amendment has been applied retrospectively and, as such, the presentation of items in OCI has been modified. The application of the amendment to IAS 1 did not result in any adjustments to other comprehensive income or comprehensive income.

Offsetting Financial Assets and Financial Liabilities

Effective January 1, 2013, Cenovus complied with the amended disclosure requirements, regarding offsetting financial assets and financial liabilities, found in IFRS 7, “Financial Instruments: Disclosures” issued in December 2011. Refer to the interim Consolidated Financial Statements for the additional disclosure. The application of the amendment had no impact on the Consolidated Statements of Earnings and Comprehensive Income or the Consolidated Balance Sheets.

Future Accounting Pronouncements

In May 2013, the IASB released an amendment to IAS 36 “Impairment of Assets”. This amendment requires entities to disclose the recoverable amount of an impaired Cash Generating Unit (“CGU”). The amendment is effective January 1, 2014. Early adoption is permitted.

A description of additional standards and interpretations that will be adopted by Cenovus in future periods can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2012.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) in the three months ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, ICFR.

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

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner and to integrating our corporate responsibility principles into the way we conduct our business. Our Corporate Responsibility (“CR”) policy continues to drive our commitments, strategy and reporting, and enables alignment with our business objectives and processes.

In September 2013, our leading CR practices were recognized internationally with the inclusion of Cenovus to the Dow Jones Sustainability World Index for the second consecutive year, and also to the Dow Jones Sustainability North America Index for the fourth consecutive year. In June 2013, Cenovus was named one of the Top 50 Socially Responsible Corporations in Canada by Maclean’s magazine and Sustainalytics for the second year in a row and for the third consecutive year by Corporate Knights magazine as one of the 2013 Best 50 Corporate Citizens in Canada. Corporate Knights also named Cenovus to their Global 100 ranking for the first time as announced during the World Economic Forum in Davos. These external recognitions of our commitment to corporate responsibility reaffirm Cenovus’s efforts to balance economic, governance, social and environmental performance.

In July 2013, we published our 2012 CR report, with highlights including our investments in innovation and research, local and Aboriginal spending in our operating areas, advancements made in minimizing our environmental impacts, long-term agreements signed with Aboriginal communities, and our involvement with and investments in charities and non-profit organizations. Our CR policy and CR report are available on our website at cenovus.com.

In October 2013, we were recently named to the Canada 200 Climate Disclosure Leadership Index for the fourth consecutive year. The index, published by CDP (formerly known as the Carbon Disclosure Project), recognizes companies for their open and transparent disclosure of greenhouse gas emissions.

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OUTLOOK

We continue to move forward on our 10 year strategic plan targeting net oil sands bitumen production of approximately 435,000 barrels per day and net crude oil production of approximately 525,000 barrels per day by the end of 2023. To achieve our development plans, additional expansions are planned at Foster Creek, Christina Lake and Narrows Lake, as well as new projects at Telephone Lake and Grand Rapids. We will continue the development of our oil sands resources in multiple phases using a low cost manufacturing-like approach. This approach will be enabled by technology, innovation and continued respect for the health and safety of our employees, with an emphasis on environmental performance and meaningful dialogue with our stakeholders.

The outlook commentary herein is focused on the next six to 18 months. We also direct our readers to review the guidance for 2013 that we published on our website, cenovus.com, in connection with our news release.

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

·The general outlook for crude oil prices will continue to be tied to global economic growth, the pace of North American supply growth and production interruptions. Indicators suggest a continued gradual improvement in demand growth from both U.S. and Chinese markets. Global supply disruptions are difficult to predict, however, political instability which is the root cause of supply outages is unlikely to be resolved quickly;

·The Brent-WTI differential is expected to remain near recent levels as modest firming of WTI prices relative to U.S. Gulf Coast prices should be offset by weakening Gulf Coast prices relative to Brent;

·We expect WCS prices to weaken relative to U.S. Gulf Coast and WTI pricing. With several new oil sands projects starting up over the coming months, inland heavy crude oil supply should increase and push the pipeline system back into a constrained situation until significant new rail capacity is added toward the end of the year and the first quarter of 2014;

Crude Oil Benchmarks — Forward Prices

·Refining crack spreads can be expected to remain weak as we move into the historically softer winter months. The strong Chicago-WTI crack spreads witnessed over the past two to three years due to inland crude congestion are not expected to reappear in the near future as the Keystone XL Gulf Coast portion of the pipeline will solidify the excess pipeline capacity that has recently developed from the Cushing area to the Gulf Coast; and

Refining 3-2-1 Crack Spread Benchmarks —
Forward Prices

·Natural gas prices are expected to gradually firm toward the US$4 per MMBtu level through the end of the year but will be affected by winter temperatures.  The sharp reduction in drilling activity over the past couple of years has finally resulted in a flattening of supply growth. With continued growth in demand, some additional firming in prices will be required to encourage more producer activity to keep supply growth in line with demand growth.

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While we expect to see volatility in crude prices, we mitigate our exposure to light/heavy price differentials through the following:

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

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

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

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

Protection Against Canadian Crude Oil Congestion

(1)Expected net production capacity.

Update on Key Strategic Priorities

Market Access

We are focused on near and mid-term strategies to broaden market access for Canadian oil. This will allow us to build on our successful marketing and transportation strategy and broaden the portfolio of market opportunities for our growing production. We anticipate increasing our rail shipping capacity for oil to approximately 10,000 barrels per day by the end of 2013, subject to favorable market conditions, by supporting industry transportation projects as well as new and expanded market development initiatives for our crude oil. During the nine months of 2013, we transported approximately 6,000 barrels per day by rail, allowing us to realize higher prices on our crude oil and diversify our customer base. We also entered into $11 billion of new pipeline commitments (some of which include amounts for projects awaiting regulatory approval) to align our future transportation requirements with our anticipated growth.

Long-term Cost Structures

We have a track record of cost efficiency. To continue to meet our business plan, we must ensure that, over the long term, we maintain an efficient and sustainable cost structure and take advantage of our business model. For example, we have a number of opportunities to improve our cost efficiency by further leveraging our supply chain management to improve capital and operating costs.

Other Key Challenges

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

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CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the Period Ended September 30,

($ millions, except per share amounts)

		Three Months Ended						Nine Months Ended
	Notes	2013			2012			2013			2012
					(Note 3)						(Note 3)
Revenues	1
Gross Sales		5,195			4,462			14,166			13,427
Less: Royalties		120			122			256			309
		5,075			4,340			13,910			13,118
Expenses	1
Purchased Product		2,982			2,303			7,623			7,335
Transportation and Blending		464			398			1,482			1,323
Operating		435			418			1,338			1,201
Production and Mineral Taxes		11			9			30			28
(Gain) Loss on Risk Management	19	25			194			151			(184		)
Depreciation, Depletion and Amortization	10,12	430			397			1,365			1,176
Exploration Expense		—			—			109			68
General and Administrative		103			104			268			253
Finance Costs	4	160			120			407			344
Interest Income	5	(23		)	(28		)	(73		)	(84		)
Foreign Exchange (Gain) Loss, net	6	(55		)	(51		)	93			(42		)
(Gain) Loss on Divestiture of Assets		1			1			1			—
Other (Income) Loss, net		—			—			—			(4		)
Earnings Before Income Tax		542			475			1,116			1,704
Income Tax Expense	7	172			186			396			592
Net Earnings		370			289			720			1,112
Other Comprehensive Income (Loss), Net of Tax
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits		6			(1		)	15			(3		)
Items That May be Subsequently Reclassified to Profit or Loss:
Change in Value of Available for Sale Financial Assets		—			—			8			—
Foreign Currency Translation Adjustment		(14		)	(45		)	58			(36		)
Total Other Comprehensive Income (Loss), Net of Tax		(8		)	(46		)	81			(39		)
Comprehensive Income		362			243			801			1,073
Net Earnings Per Common Share	8
Basic		$	0.49		$	0.38		$	0.95		$	1.47
Diluted		$	0.49		$	0.38		$	0.95		$	1.47

See accompanying Notes to Consolidated Financial Statements (unaudited).

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CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		September 30,	December 31,	January 1,
	Notes	2013	2012	2012
			(Note 3)	(Note 3)
Assets
Current Assets
Cash and Cash Equivalents		1,024	1,160	495
Accounts Receivable and Accrued Revenues		1,855	1,464	1,405
Current Portion of Partnership Contribution Receivable		413	384	372
Inventories	9	1,477	1,288	1,291
Risk Management	19	91	283	232
Assets Held for Sale	10	33	—	116
Current Assets		4,893	4,579	3,911
Exploration and Evaluation Assets	1,11	1,402	1,285	880
Property, Plant and Equipment, net	1,12	16,462	16,152	14,324
Partnership Contribution Receivable		1,133	1,398	1,822
Risk Management	19	11	5	52
Income Tax Receivable		—	—	29
Other Assets		65	58	44
Goodwill	1	739	739	1,132
Total Assets		24,705	24,216	22,194
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		2,963	2,650	2,579
Income Tax Payable		261	217	329
Current Portion of Partnership Contribution Payable		417	386	372
Risk Management	19	19	17	54
Liabilities Related to Assets Held for Sale	10	3	—	54
Current Liabilities		3,663	3,270	3,388
Long-Term Debt	13	4,830	4,679	3,527
Partnership Contribution Payable		1,159	1,426	1,853
Risk Management	19	1	1	14
Decommissioning Liabilities	14	1,970	2,315	1,777
Other Liabilities		176	183	158
Deferred Income Taxes		2,800	2,560	2,093
Total Liabilities		14,599	14,434	12,810
Shareholders’ Equity		10,106	9,782	9,384
Total Liabilities and Shareholders’ Equity		24,705	24,216	22,194

See accompanying Notes to Consolidated Financial Statements (unaudited).

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CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

($ millions)

	ShareCapital		Paid inSurplus	RetainedEarnings		AOCI (1)		Total
	(Note 15)					(Note 16)
Balance as at December 31, 2011,as Previously Reported	3,780		4,107	1,400		119		9,406
Cumulative Effect of Change in AccountingPolicy (Note 3)	—		—	—		(22	)	(22	)
Balance as at January 1, 2012, Restated	3,780		4,107	1,400		97		9,384
Net Earnings	—		—	1,112		—		1,112
Other Comprehensive Income (Loss)	—		—	—		(39	)	(39	)
Total Comprehensive Income for the Period	—		—	1,112		(39	)	1,073
Common Shares Issued Under Option Plans	47		—	—		—		47
Stock-Based Compensation Expense	—		34	—		—		34
Dividends on Common Shares	—		—	(498	)	—		(498	)
Balance as at September 30, 2012, Restated	3,827		4,141	2,014		58		10,040
Balance as at December 31, 2012,as Previously Reported	3,829		4,154	1,728		95		9,806
Cumulative Effect of Change in AccountingPolicy (Note 3)	—		—	2		(26	)	(24	)
Balance as at December 31, 2012, Restated	3,829		4,154	1,730		69		9,782
Net Earnings	—		—	720		—		720
Other Comprehensive Income (Loss)	—		—	—		81		81
Total Comprehensive Income for the Period	—		—	720		81		801
Common Shares Issued Under Option Plans	25		—	—		—		25
Common Shares Cancelled (Note 15)	(3	)	3	—		—		—
Stock-Based Compensation Expense	—		47	—		—		47
Dividends on Common Shares	—		—	(549	)	—		(549	)
Balance as at September 30, 2013	3,851		4,204	1,901		150		10,106

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

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CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the Period Ended September 30,

($ millions)

		Three Months Ended				Nine Months Ended
	Notes	2013		2012		2013		2012
				(Note 3)				(Note 3)
Operating Activities
Net Earnings		370		289		720		1,112
Depreciation, Depletion and Amortization		430		397		1,365		1,176
Exploration Expense		(1	)	—		45		68
Deferred Income Taxes	7	132		110		211		408
Unrealized (Gain) Loss on Risk Management	19	(8	)	293		196		60
Unrealized Foreign Exchange (Gain) Loss	6	(48	)	(60	)	86		(82	)
(Gain) Loss on Divestiture of Assets		1		1		1		—
Unwinding of Discount on Decommissioning Liabilities	4,14	24		22		72		64
Other		32		65		78		140
		932		1,117		2,774		2,946
Net Change in Other Assets and Liabilities		(25	)	(19	)	(90	)	(71	)
Net Change in Non-Cash Working Capital		(67	)	(69	)	(121	)	(213	)
Cash From Operating Activities		840		1,029		2,563		2,662
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	11	(34	)	(104	)	(255	)	(451	)
Capital Expenditures — Property, Plant and Equipment	12	(710	)	(734	)	(2,114	)	(1,983	)
Proceeds From Divestiture of Assets		241		—		242		65
Net Change in Investments and Other		3		5		(3	)	(10	)
Net Change in Non-Cash Working Capital		49		92		(27	)	18
Cash (Used in) Investing Activities		(451	)	(741	)	(2,157	)	(2,361	)
Net Cash Provided (Used) Before Financing Activities		389		288		406		301
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		2		(204	)	1		3
Issuance of U.S. Unsecured Notes		814		1,219		814		1,219
Repayment of U.S. Unsecured Notes		(825	)	—		(825	)	—
Proceeds on Issuance of Common Shares		4		3		23		35
Dividends Paid on Common Shares	8	(182	)	(166	)	(549	)	(498	)
Other		(3	)	—		(3	)	1
Cash From (Used in) Financing Activities		(190	)	852		(539	)	760
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		—		(6	)	(3	)	(13	)
Increase (Decrease) in Cash and Cash Equivalents		199		1,134		(136	)	1,048
Cash and Cash Equivalents, Beginning of Period		825		409		1,160		495
Cash and Cash Equivalents, End of Period		1,024		1,543		1,024		1,543

See accompanying Notes to Consolidated Financial Statements (unaudited).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

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 was 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 presentation for these interim Consolidated Financial Statements is found in Note 2.

The Company’s reportable segments are as follows:

·Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake as well as heavy oil assets at Pelican Lake. This segment also includes the Athabasca natural gas assets and projects in the early stages of development such as Grand Rapids and Telephone Lake. 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 carbon dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.

·Refining and Marketing, which is focused on the refining of crude oil products into petroleum and chemical products at two refineries located in the U.S. The refineries are jointly owned with and operated by Phillips 66, an unrelated U.S. public company. This segment also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.

·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 and financing activities. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

A) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional				Refining and Marketing
For the three months ended September 30,	2013	2012		2013		2012		2013		2012
Revenues
Gross Sales	1,336	1,007		590		489		3,459		3,066
Less: Royalties	67	83		53		39		—		—
	1,269	924		537		450		3,459		3,066
Expenses
Purchased Product	—	—		—		—		3,172		2,403
Transportation and Blending	426	367		38		31		—		—
Operating	185	150		123		133		129		136
Production and Mineral Taxes	—	—		11		9		—		—
(Gain) Loss on Risk Management	26	(28	)	(14	)	(71	)	21		—
Operating Cash Flow	632	435		379		348		137		527
Depreciation, Depletion and Amortization	153	127		220		222		37		36
Exploration Expense	—	—		—		—		—		—
Segment Income (Loss)	479	308		159		126		100		491
				Corporate and Eliminations				Consolidated
For the three months ended September 30,				2013		2012		2013		2012
Revenues
Gross Sales				(190	)	(100	)	5,195		4,462
Less: Royalties				—		—		120		122
				(190	)	(100	)	5,075		4,340
Expenses
Purchased Product				(190	)	(100	)	2,982		2,303
Transportation and Blending				—		—		464		398
Operating				(2	)	(1	)	435		418
Production and Mineral Taxes				—		—		11		9
(Gain) Loss on Risk Management				(8	)	293		25		194
				10		(292	)	1,158		1,018
Depreciation, Depletion and Amortization				20		12		430		397
Exploration Expense				—		—		—		—
Segment Income (Loss)				(10	)	(304	)	728		621
General and Administrative				103		104		103		104
Finance Costs				160		120		160		120
Interest Income				(23	)	(28	)	(23	)	(28	)
Foreign Exchange (Gain) Loss, net				(55	)	(51	)	(55	)	(51	)
(Gain) Loss on Divestiture of Assets				1		1		1		1
Other (Income) Loss, net				—		—		—		—
				186		146		186		146
Earnings Before Income Tax								542		475
Income Tax Expense								172		186
Net Earnings								370		289

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the three months ended September 30,	2013	2012		2013	2012		2013	2012
Revenues
Gross Sales	1,324	998		455	368		1,779	1,366
Less: Royalties	67	84		51	38		118	122
	1,257	914		404	330		1,661	1,244
Expenses
Transportation and Blending	425	367		34	27		459	394
Operating	175	142		71	78		246	220
Production and Mineral Taxes	—	—		10	7		10	7
(Gain) Loss on Risk Management	27	(23	)	4	(9	)	31	(32	)
Operating Cash Flow	630	428		285	227		915	655

(1) Includes natural gas liquids.

	Natural Gas
	Oil Sands				Conventional				Total
For the three months ended September 30,	2013		2012		2013		2012		2013		2012
Revenues
Gross Sales	8		7		130		116		138		123
Less: Royalties	—		(1	)	2		1		2		—
	8		8		128		115		136		123
Expenses
Transportation and Blending	1		—		4		4		5		4
Operating	5		5		50		53		55		58
Production and Mineral Taxes	—		—		1		2		1		2
(Gain) Loss on Risk Management	(1	)	(5	)	(18	)	(62	)	(19	)	(67	)
Operating Cash Flow	3		8		91		118		94		126

	Other
	Oil Sands				Conventional		Total
For the three months ended September 30,	2013		2012		2013	2012	2013	2012
Revenues
Gross Sales	4		2		5	5	9	7
Less: Royalties	—		—		—	—	—	—
	4		2		5	5	9	7
Expenses
Transportation and Blending	—		—		—	—	—	—
Operating	5		3		2	2	7	5
Production and Mineral Taxes	—		—		—	—	—	—
(Gain) Loss on Risk Management	—		—		—	—	—	—
Operating Cash Flow	(1	)	(1	)	3	3	2	2

	Total Upstream
	Oil Sands			Conventional				Total
For the three months ended September 30,	2013	2012		2013		2012		2013	2012
Revenues
Gross Sales	1,336	1,007		590		489		1,926	1,496
Less: Royalties	67	83		53		39		120	122
	1,269	924		537		450		1,806	1,374
Expenses
Transportation and Blending	426	367		38		31		464	398
Operating	185	150		123		133		308	283
Production and Mineral Taxes	—	—		11		9		11	9
(Gain) Loss on Risk Management	26	(28	)	(14	)	(71	)	12	(99	)
Operating Cash Flow	632	435		379		348		1,011	783

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

C) Geographic Information

	Canada		United States		Consolidated
For the three months ended September 30,	2013	2012	2013	2012	2013	2012
Revenues
Gross Sales	2,477	2,006	2,718	2,456	5,195	4,462
Less: Royalties	120	122	—	—	120	122
	2,357	1,884	2,718	2,456	5,075	4,340
Expenses
Purchased Product	543	502	2,439	1,801	2,982	2,303
Transportation and Blending	464	398	—	—	464	398
Operating	311	289	124	129	435	418
Production and Mineral Taxes	11	9	—	—	11	9
(Gain) Loss on Risk Management	5	189	20	5	25	194
	1,023	497	135	521	1,158	1,018
Depreciation, Depletion and Amortization	393	361	37	36	430	397
Exploration Expense	—	—	—	—	—	—
Segment Income	630	136	98	485	728	621

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.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

D) Results of Operations — Segment and Operational Information

	Oil Sands				Conventional				Refining and Marketing
For the nine months ended September 30,	2013		2012		2013		2012		2013	2012
Revenues
Gross Sales	3,410		3,026		1,715		1,546		9,483	9,020
Less: Royalties	125		175		131		134		—	—
	3,285		2,851		1,584		1,412		9,483	9,020
Expenses
Purchased Product	—		—		—		—		8,065	7,500
Transportation and Blending	1,352		1,212		130		111		—	—
Operating	544		432		394		382		404	389
Production and Mineral Taxes	—		—		30		28		—	—
(Gain) Loss on Risk Management	(12	)	(35	)	(62	)	(195	)	29	(14	)
Operating Cash Flow	1,401		1,242		1,092		1,086		985	1,145
Depreciation, Depletion and Amortization	451		352		753		680		102	109
Exploration Expense	—		—		109		68		—	—
Segment Income (Loss)	950		890		230		338		883	1,036

	Corporate and Eliminations				Consolidated
For the nine months ended September 30,	2013		2012		2013		2012
Revenues
Gross Sales	(442	)	(165	)	14,166		13,427
Less: Royalties	—		—		256		309
	(442	)	(165	)	13,910		13,118
Expenses
Purchased Product	(442	)	(165	)	7,623		7,335
Transportation and Blending	—		—		1,482		1,323
Operating	(4	)	(2	)	1,338		1,201
Production and Mineral Taxes	—		—		30		28
(Gain) Loss on Risk Management	196		60		151		(184	)
	(192	)	(58	)	3,286		3,415
Depreciation, Depletion and Amortization	59		35		1,365		1,176
Exploration Expense	—		—		109		68
Segment Income (Loss)	(251	)	(93	)	1,812		2,171
General and Administrative	268		253		268		253
Finance Costs	407		344		407		344
Interest Income	(73	)	(84	)	(73	)	(84	)
Foreign Exchange (Gain) Loss, net	93		(42	)	93		(42	)
(Gain) Loss on Divestiture of Assets	1		—		1		—
Other (Income) Loss, net	—		(4	)	—		(4	)
	696		467		696		467
Earnings Before Income Tax					1,116		1,704
Income Tax Expense					396		592
Net Earnings					720		1,112

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

E) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands				Conventional				Total
For the nine months ended September 30,	2013		2012		2013		2012		2013		2012
Revenues
Gross Sales	3,368		2,994		1,258		1,187		4,626		4,181
Less: Royalties	124		175		125		130		249		305
	3,244		2,819		1,133		1,057		4,377		3,876
Expenses
Transportation and Blending	1,351		1,211		115		96		1,466		1,307
Operating	519		405		236		224		755		629
Production and Mineral Taxes	—		—		28		24		28		24
(Gain) Loss on Risk Management	(9	)	(20	)	(17	)	(9	)	(26	)	(29	)
Operating Cash Flow	1,383		1,223		771		722		2,154		1,945

(1) Includes natural gas liquids.

	Natural Gas
	Oil Sands				Conventional				Total
For the nine months ended September 30,	2013		2012		2013		2012		2013		2012
Revenues
Gross Sales	26		25		447		350		473		375
Less: Royalties	1		—		6		4		7		4
	25		25		441		346		466		371
Expenses
Transportation and Blending	1		1		15		15		16		16
Operating	14		18		155		155		169		173
Production and Mineral Taxes	—		—		2		4		2		4
(Gain) Loss on Risk Management	(3	)	(15	)	(45	)	(186	)	(48	)	(201	)
Operating Cash Flow	13		21		314		358		327		379

	Other
	Oil Sands			Conventional		Total
For the nine months ended September 30,	2013	2012		2013	2012	2013	2012
Revenues
Gross Sales	16	7		10	9	26	16
Less: Royalties	—	—		—	—	—	—
	16	7		10	9	26	16
Expenses
Transportation and Blending	—	—		—	—	—	—
Operating	11	9		3	3	14	12
Production and Mineral Taxes	—	—		—	—	—	—
(Gain) Loss on Risk Management	—	—		—	—	—	—
Operating Cash Flow	5	(2	)	7	6	12	4

	Total Upstream
	Oil Sands				Conventional				Total
For the nine months ended September 30,	2013		2012		2013		2012		2013		2012
Revenues
Gross Sales	3,410		3,026		1,715		1,546		5,125		4,572
Less: Royalties	125		175		131		134		256		309
	3,285		2,851		1,584		1,412		4,869		4,263
Expenses
Transportation and Blending	1,352		1,212		130		111		1,482		1,323
Operating	544		432		394		382		938		814
Production and Mineral Taxes	—		—		30		28		30		28
(Gain) Loss on Risk Management	(12	)	(35	)	(62	)	(195	)	(74	)	(230	)
Operating Cash Flow	1,401		1,242		1,092		1,086		2,493		2,328

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

F) Geographic Information

	Canada			United States			Consolidated
For the nine months ended September 30,	2013	2012		2013	2012		2013	2012
Revenues
Gross Sales	6,673	6,059		7,493	7,368		14,166	13,427
Less: Royalties	256	309		—	—		256	309
	6,417	5,750		7,493	7,368		13,910	13,118
Expenses
Purchased Product	1,525	1,466		6,098	5,869		7,623	7,335
Transportation and Blending	1,482	1,323		—	—		1,482	1,323
Operating	951	830		387	371		1,338	1,201
Production and Mineral Taxes	30	28		—	—		30	28
(Gain) Loss on Risk Management	122	(169	)	29	(15	)	151	(184	)
	2,307	2,272		979	1,143		3,286	3,415
Depreciation, Depletion and Amortization	1,263	1,067		102	109		1,365	1,176
Exploration Expense	109	68		—	—		109	68
Segment Income	935	1,137		877	1,034		1,812	2,171

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 September 30, 2013 was $516 million and $136 million, respectively (three months ended September 30, 2012 — $290 million and $534 million). Cenovus’s share of operating cash flow from FCCL and WRB for the nine months ended September 30, 2013 was $1,028 million and $987 million, respectively (nine months ended September 30, 2012 — $860 million and $1,149 million).

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

By Segment

	E&E (1)		PP&E (2)
	September 30,	December 31,	September 30,	December 31,
As at	2013	2012	2013	2012
Oil Sands	1,305	1,110	8,798	7,764
Conventional	97	175	4,138	4,929
Refining and Marketing	—	—	3,160	3,088
Corporate and Eliminations	—	—	366	371
Consolidated	1,402	1,285	16,462	16,152

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2013	2012	2013	2012
Oil Sands	739	739	13,064	11,972
Conventional	—	—	4,497	5,304
Refining and Marketing	—	—	5,555	5,018
Corporate and Eliminations	—	—	1,589	1,922
Consolidated	739	739	24,705	24,216

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

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

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

By Geographic Region

	E&E		PP&E
	September 30,	December 31,	September 30,	December 31,
As at	2013	2012	2013	2012
Canada	1,402	1,285	13,302	13,065
United States	—	—	3,160	3,087
Consolidated	1,402	1,285	16,462	16,152

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2013	2012	2013	2012
Canada	739	739	19,993	19,744
United States	—	—	4,712	4,472
Consolidated	739	739	24,705	24,216

I) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the period ended September 30,	2013	2012	2013	2012
Capital
Oil Sands	523	516	1,731	1,606
Conventional	178	231	510	591
Refining and Marketing	19	38	70	60
Corporate	23	45	53	133
	743	830	2,364	2,390
Acquisition Capital
Oil Sands	1	2	1	2
Conventional	—	6	4	42
Refining and Marketing	—	—	—	—
Corporate	—	—	—	—
	744	838	2,369	2,434

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

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

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

These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting” (“IAS 34”), and have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2012, except as identified in Note 3 and 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, 2012, 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 October 23, 2013.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

3. CHANGES IN ACCOUNTING POLICIES

A) Joint Arrangements, Consolidation, Associates and Disclosures

As disclosed in the December 31, 2012 annual Consolidated Financial Statements, effective January 1, 2013, the Company adopted, as required, IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), IFRS 11, “Joint Arrangements” (“IFRS 11”), IFRS 12, “Disclosure of Interests in Other Entities” (“IFRS 12”) as well as the amendments to IAS 28, “Investments in Associates and Joint Ventures” (“IAS 28”).

Cenovus reviewed its consolidation methodology and determined that the adoption of IFRS 10 did not result in a change in the consolidation status of its subsidiaries and investees.

Under IFRS 11, interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Cenovus performed a comprehensive review of its interests in other entities and identified two individually significant interests, FCCL and WRB, for which it shares joint control. Previously, Cenovus accounted for these jointly controlled entities using proportionate consolidation.

Cenovus reviewed these joint arrangements considering their structure, the legal forms of any separate vehicles, the contractual terms of the arrangements and other facts and circumstances. The application of the Company’s accounting policy under IFRS 11 requires judgment in determining the classification of these joint arrangements. It was determined that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB. As a result, these joint arrangements have been classified as joint operations under IFRS 11 and the Company’s share of the assets, liabilities, revenues and expenses have been recognized in the interim Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:

·The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a limited life.

·The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by way of partnership notes payable and loans. The partnerships do not have any third party borrowings.

·FCCL operates like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants. WRB has a very similar structure modified only to account for the operating environment of the refining business.

·Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the partnerships do not have employees and as such are not capable of performing these roles.

·In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

There has been no impact on the recognized assets, liabilities and comprehensive income of the Company with the application of these standards.

B) Employee Benefits

As disclosed in the December 31, 2012 annual Consolidated Financial Statements, effective January 1, 2013, the Company adopted, as required, IAS 19, “Employee Benefits”, as amended in June 2011 (“IAS 19R”). The Company applied the standard retrospectively and in accordance with the transitional provisions. The opening Consolidated Balance Sheet of the earliest comparative period presented (January 1, 2012) was restated.

The amendments require the recognition of changes in defined benefit pension obligations and plan assets when they occur, eliminating the ‘corridor approach’ previously permitted and accelerating the recognition of past service costs. In order for the net defined benefit liability or asset to reflect the full value of the plan deficit or surplus, all actuarial gains and losses are recognized immediately through other comprehensive income. In addition, the Company replaced interest costs on the defined benefit obligation and the expected return on plan assets with a net interest cost based on the net defined benefit asset or liability measured by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period. Interest expense and interest income on net post-employment benefit liabilities and assets continue to be recognized in net earnings.

IAS 19R requires termination benefits to be recognized at the earlier of when the entity can no longer withdraw an offer of termination benefits or recognizes any restructuring costs. This requirement had no impact on the Consolidated Financial Statements.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

The effect on the Consolidated Balance Sheets of IAS 19R was as follows:

As at January 1, 2012	Net Defined BenefitLiability (1)	DeferredIncome Taxes		Shareholders’ Equity
Balance as Previously Reported	16	2,101		9,406
Effect of Adoption of IAS 19R	30	(8	)	(22	)
Restated Balance	46	2,093		9,384

(1) Composed of the defined benefit pension and other post-employment benefit (“OPEB”) plans which are included in other liabilities on the Consolidated Balance Sheets.

As at December 31, 2012	Net Defined BenefitLiability (1)	DeferredIncome Taxes		Shareholders’ Equity
Balance as Previously Reported	28	2,568		9,806
Effect of Adoption of IAS 19R	32	(8	)	(24	)
Restated Balance	60	2,560		9,782

(1) Composed of the defined benefit pension and OPEB plans which are included in other liabilities on the Consolidated Balance Sheets.

The effect on the Consolidated Statements of Earnings and Comprehensive Income of IAS 19R was as follows:

	Three Months EndedSeptember 30, 2012		Nine Months Ended September 30, 2012		Year EndedDecember 31, 2012
Decrease in General and Administrative Expense	—		1		2
Decrease in Income Tax Expense	—		—		—
Increase in Net Earnings for the Period	—		1		2
Remeasurement of Defined Benefit and Other Post-EmploymentBenefits Liability	1		3		4
(Increase) in Income Tax Relating to Components of OCI (1)	—		—		—
(Decrease) in OCI (1)	(1	)	(3	)	(4	)
(Decrease) in Comprehensive Income for the Period	(1	)	(2	)	(2	)

(1) Other Comprehensive Income (“OCI”).

The change in accounting policy did not have a material impact on the Consolidated Financial Statements including net earnings per share.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Additional Disclosures

Details about the Company’s defined benefit and other post-employment benefit (“OPEB”) plans can be found in the notes to the annual Consolidated Financial Statements as at December 31, 2012. Additional and restated disclosures as at December 31, 2012, as required by IAS 19R are as follows:

Defined Benefit and OPEB Plan Obligation and Funded Status

	Pension Benefits		OPEB
Defined Benefit Obligation
Defined Benefit Obligation, January 1, 2012	84		19
Current Service Costs	10		2
Interest Costs on the Defined Benefit Obligation (1)	4		1
Benefits Paid	(2	)	—
Plan Participant Contributions	1		—
Remeasurements:
Actuarial (Gains) Losses from Experience Adjustments	3		1
Actuarial (Gains) Losses from Changes in Demographic Assumptions	—		(1	)
Actuarial (Gains) Losses from Changes in Financial Assumptions	4		(2	)
Plan Conversion	30		—
Defined Benefit Obligation, December 31, 2012	134		20
Plan Assets
Balance as at December 31, 2011, as Previously Reported	61		—
Cumulative Effect of Change in Accounting Policy	(4	)	—
Balance as at January 1, 2012, Restated	57		—
Return on Plan Assets (1)	3		—
Employer Contributions	22		—
Plan Participant Contributions	1		—
Benefits Paid	(2	)	—
Remeasurements:
Gains (Losses) on Plan Assets	1		—
Assets Transferred from Plan Conversion	12		—
Fair Value of Plan Assets, December 31, 2012	94		—
Pension and Other Post-Employment Benefit (Liability)	(40	)	(20	)

(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.

Plan Assets

Defined benefit plan assets comprise:

	December 31,	January 1,
As at	2012	2012
Equity Securities
Equity Funds and Balanced Funds	52	30
Other	3	—
Bond Funds	24	17
Non-Invested Assets	11	7
Real Estate	4	3
	94	57

Fair value of equity securities and bond funds are based on the trading price of the underlying funds. The fair value of the non-invested assets is the discounted value of the expected future payments. The fair value of real estate is determined by accredited real estate appraisers.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

C) Fair Value Measurement

Effective January 1, 2013, the Company adopted, as required, IFRS 13, “Fair Value Measurement” (“IFRS 13”) and applied the standard prospectively as required by the transitional provisions. The standard provides a consistent definition of fair value and introduces consistent requirements for disclosures related to fair value measurement. There has been no change to Cenovus’s methodology for determining the fair value for its financial assets and liabilities and, as such, the adoption of IFRS 13 did not result in any measurement adjustments as at January 1, 2013.

D) Presentation of Items in Other Comprehensive Income

Effective January 1, 2013, the Company applied the amendment to IAS 1, “Presentation of Financial Statements” (“IAS 1”), as amended in June 2011. The amendment requires items within OCI to be grouped into two categories: (1) items that will not be subsequently reclassified to profit or loss or (2) items that may be subsequently reclassified to profit or loss when specific conditions are met. The amendment has been applied retrospectively and, as such, the presentation of items in OCI has been modified. The application of the amendment to IAS 1 did not result in any adjustments to other comprehensive income or comprehensive income.

E) Offsetting Financial Assets and Financial Liabilities

Effective January 1, 2013, the Company complied with the amended disclosure requirements, regarding offsetting financial assets and financial liabilities, found in IFRS 7, “Financial Instruments: Disclosures” issued in December 2011. The additional disclosure can be found in Note 19. The application of the amendment had no impact on the Consolidated Statements of Earnings and Comprehensive Income or the Consolidated Balance Sheets.

F) Future Accounting Pronouncements

In May 2013, the IASB released an amendment to IAS 36, “Impairment of Assets”. This amendment requires entities to disclose the recoverable amount of an impaired Cash Generating Unit (“CGU”). The amendment is effective January 1, 2014. Early adoption is permitted.

A description of additional standards and interpretations that will be adopted by the Company in future periods can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2012.

4. FINANCE COSTS

	Three Months Ended		Nine Months Ended
For the period ended September 30,	2013	2012	2013	2012
Interest Expense — Short-Term Borrowings and Long-TermDebt	71	59	203	166
Premium on Redemption of Long-Term Debt (Note 13)	33	—	33	—
Interest Expense — Partnership Contribution Payable	24	29	75	91
Unwinding of Discount on Decommissioning Liabilities	24	22	72	64
Other	8	10	24	23
	160	120	407	344

5. INTEREST INCOME

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2013		2012		2013		2012
Interest Income — Partnership Contribution Receivable	(20	)	(25	)	(65	)	(79	)
Other	(3	)	(3	)	(8	)	(5	)
	(23	)	(28	)	(73	)	(84	)

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

6. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2013		2012		2013		2012
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued from Canada	(77	)	(129	)	190		(122	)
U.S. Dollar Partnership Contribution Receivable Issued from Canada	24		53		(99	)	22
Other	5		16		(5	)	18
Unrealized Foreign Exchange (Gain) Loss	(48	)	(60	)	86		(82	)
Realized Foreign Exchange (Gain) Loss	(7	)	9		7		40
	(55	)	(51	)	93		(42	)

7. INCOME TAXES

The provision for income taxes is as follows:

	Three Months Ended			Nine Months Ended
For the period ended September 30,	2013		2012	2013	2012
Current Tax
Canada	60		56	147	139
United States	(20	)	20	38	45
Total Current Tax	40		76	185	184
Deferred Tax	132		110	211	408
	172		186	396	592

8. PER SHARE AMOUNTS

A) Net Earnings Per Share

For the period ended September 30,	Three Months Ended				Nine Months Ended
($ millions, except net earnings per share)	2013		2012		2013		2012
Net Earnings — Basic and Diluted	370		289		720		1,112
Weighted Average Number of Shares — Basic	755.8		755.7		755.9		755.5
Dilutive Effect of Cenovus TSARs	1.4		2.3		1.7		3.0
Dilutive Effect of NSRs	—		—		—		—
Weighted Average Number of Shares — Diluted	757.2		758.0		757.6		758.5
Net Earnings Per Share — Basic	$	0.49	$	0.38	$	0.95	$	1.47
Net Earnings Per Share — Diluted	$	0.49	$	0.38	$	0.95	$	1.47

B) Dividends Per Share

The Company paid dividends of $549 million or $0.726 per share for the nine months ended September 30, 2013 (September 30, 2012 — $498 million, $0.66 per share). The Cenovus Board of Directors declared a fourth quarter dividend of $0.242 per share, payable on December 31, 2013, to common shareholders of record as of December 13, 2013.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

9. INVENTORIES

	September 30,	December 31,
As at	2013	2012
Product
Refining and Marketing	1,229	1,056
Oil Sands	210	202
Conventional	1	1
Parts and Supplies	37	29
	1,477	1,288

As a result of a decline in refined product prices, Cenovus recorded a write-down of its product inventory by $28 million from cost to net realizable value at September 30, 2013.

10. ASSETS AND LIABILITIES HELD FOR SALE

	September 30,	December 31,
As at	2013	2012
Assets Held for Sale
Property, Plant and Equipment	33	—
Liabilities Related to Assets Held for Sale
Decommissioning Liabilities	3	—

During the three months ended March 31, 2013, Management decided to launch a public sales process to divest its Lower Shaunavon and certain of its Bakken properties in Saskatchewan. The land base associated with these properties is relatively small and does not offer sufficient scalability to be material to Cenovus’s overall asset portfolio. The assets were recorded at the lesser of fair value less costs to sell and their carrying amount, and depletion ceased. These assets and the related liabilities are reported in the Conventional segment.

In July 2013, the Company completed the sale of the Lower Shaunavon asset to an unrelated third party for proceeds of $240 million plus closing adjustments. In the second quarter of 2013, an impairment loss of $57 million was recorded as additional depreciation, depletion and amortization on the transaction. A loss of $2 million was recorded on the sale in the third quarter.

The Company continues to market certain of its Bakken properties.

11. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2011	880
Additions (1)	687
Transfers to PP&E (Note 12)	(218	)
Exploration Expense	(68	)
Divestitures	(11	)
Change in Decommissioning Liabilities	15
As at December 31, 2012	1,285
Additions	255
Transfers to PP&E (Note 12)	(93	)
Exploration Expense	(45	)
Divestitures	(1	)
Change in Decommissioning Liabilities	1
As at September 30, 2013	1,402

(1) 2012 asset acquisition included the assumption of a decommissioning liability of $33 million.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Exploration and evaluation assets consist of the Company’s evaluation projects which are pending the 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 nine months ended September 30, 2013 include $43 million of internal costs directly related to the evaluation of these projects (year ended December 31, 2012 — $37 million). Costs classified as general and administrative expenses have not been capitalized as part of capital expenditures. No borrowing costs have been capitalized during the nine months ended September 30, 2013 or for the year ended December 31, 2012.

For the nine months ended September 30, 2013, $93 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 in question (year ended December 31, 2012 — $218 million).

Impairment

The impairment of E&E assets and any subsequent reversal of such impairment losses are recognized in exploration expense in the Consolidated Statements of Earnings and Comprehensive Income. During the nine months ended September 30, 2013, $45 million of previously capitalized E&E costs related to certain tight oil exploration assets within the Conventional segment were deemed not to be technically feasible and commercially viable and were recognized as exploration expense (year ended December 31, 2012 — $68 million).

12. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production		OtherUpstream	RefiningEquipment		Other (1)	Total
COST
As at December 31, 2011	23,858		194	3,425		576	28,053
Additions	2,442		44	118		191	2,795
Transfers from E&E Assets (Note 11)	218		—	—		—	218
Transfers and Reclassifications	—		—	(55	)	—	(55	)
Change in Decommissioning Liabilities	484		—	(16	)	—	468
Exchange Rate Movements	1		—	(73	)	—	(72	)
As at December 31, 2012	27,003		238	3,399		767	31,407
Additions	1,964		27	70		53	2,114
Transfers from E&E Assets (Note 11)	93		—	—		—	93
Transfers and Reclassifications	(501	)	—	(15	)	1	(515	)
Change in Decommissioning Liabilities	(333	)	—	—		—	(333	)
Exchange Rate Movements	—		—	115		—	115
As at September 30, 2013	28,226		265	3,569		821	32,881
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2011	13,021		139	225		344	13,729
Depreciation and Depletion Expense	1,368		19	146		52	1,585
Transfers and Reclassifications	—		—	(55	)	—	(55	)
Impairment Losses	—		—	—		—	—
Exchange Rate Movements	1		—	(5	)	—	(4	)
As at December 31, 2012	14,390		158	311		396	15,255
Depreciation and Depletion Expense	1,123		23	102		59	1,307
Transfers and Reclassifications	(140	)	—	(15	)	—	(155	)
Impairment Losses	1		—	—		—	1
Exchange Rate Movements	—		—	11		—	11
As at September 30, 2013	15,374		181	409		455	16,419
CARRYING VALUE
As at December 31, 2011	10,837		55	3,200		232	14,324
As at December 31, 2012	12,613		80	3,088		371	16,152
As at September 30, 2013	12,852		84	3,160		366	16,462

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

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Additions to development and production assets include internal costs directly related to the development and construction of crude oil and natural gas properties of $151 million for the nine months ended September 30, 2013 (year ended December 31, 2012 — $161 million). All of the Company’s development and production assets are located within Canada. Costs classified as general and administrative expenses have not been capitalized as part of capital expenditures. No borrowing costs have been capitalized during the nine months ended September 30, 2013 or for the year ended December 31, 2012.

PP&E includes the following amounts in respect of assets under construction and are not subject to depreciation, depletion and amortization:

	September 30,	December 31,
As at	2013	2012
Development and Production	43	38
Refining Equipment	33	13
Other	—	11
	76	62

13. LONG-TERM DEBT

	September 30,		December 31,
As at	2013		2012
Revolving Term Debt (1)	—		—
U.S. Dollar Denominated Unsecured Notes	4,885		4,726
Total Debt Principal	4,885		4,726
Debt Discounts and Transaction Costs	(55	)	(47	)
	4,830		4,679

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

As at September 30, 2013 the Company is in compliance with all of the terms of its debt agreements.

On May 9, 2013, Cenovus amended its U.S. base shelf prospectus for unsecured notes to increase the total capacity from $2.0 billion to $3.25 billion. The U.S. shelf prospectus allows for the issuance of debt securities in U.S. dollars or other foreign currencies, from time to time, in one or more offerings. The terms of the notes, including, but not limited to, the principal amount, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at September 30, 2013, US$1.2 billion remains under this U.S. shelf prospectus. The U.S. shelf prospectus expires in July 2014.

On August 15, 2013, Cenovus completed a public offering in the U.S. of senior unsecured notes in the aggregate principal amount of US$800 million under the Company’s U.S. base shelf prospectus. The senior unsecured notes issued are as follows:

	US$ Principal	September 30,
	Amount	2013
3.8% due 2023	450	463
5.2% due 2043	350	360
	800	823

The net proceeds from the offering were used to partially fund the early redemption of Cenovus’s US$800 million senior unsecured notes due September 2014. A premium of US$32 million was paid on the early redemption of these notes and recorded as finance costs.

In September 2013, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2017.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

14. 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 as follows:

	September 30,		December 31,
As at	2013		2012
Decommissioning Liabilities, Beginning of Year	2,315		1,777
Liabilities Incurred	34		99
Liabilities Settled	(56	)	(66	)
Transfers and Reclassifications	(30	)	3
Change in Estimated Future Cash Flows	—		144
Change in Discount Rate	(366	)	273
Unwinding of Discount on Decommissioning Liabilities	72		86
Foreign Currency Translation	1		(1	)
Decommissioning Liabilities, End of Period	1,970		2,315

The undiscounted amount of estimated cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 5.1 percent as at September 30, 2013 (December 31, 2012 — 4.2 percent).

15. SHARE CAPITAL

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares, an unlimited number of first preferred shares and an unlimited number of second preferred shares. 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

	September 30, 2013				December 31, 2012
As at	Number of Common Shares(thousands)		Amount		Number of Common Shares(thousands)	Amount
Outstanding, Beginning of Year	755,843		3,829		754,499	3,780
Common Shares Issued under Stock Option Plans	766		25		1,344	49
Common Shares Cancelled	(767	)	(3	)	—	—
Outstanding, End of Period	755,842		3,851		755,843	3,829

During the nine months ended September 30, 2013, the Company cancelled 767,327 common shares. The common shares were held in reserve for un-exchanged shares of Alberta Energy Company Ltd., pursuant to the merger of Alberta Energy Company Ltd. and PanCanadian Energy Corporation in 2002 (“AEC Merger”), in which Encana Corporation (“Encana”) was formed. Due to the plan of arrangement in 2009 involving Encana Corporation and Cenovus, common shares of the Company were held in reserve until the tenth anniversary of the AEC Merger.

There were no preferred shares outstanding as at September 30, 2013 (December 31, 2012 — nil).

As at September 30, 2013, there were 23 million (December 31, 2012 — 28 million) common shares available for future issuance under stock option plans.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at September 30, 2013	Defined Benefit Plan		Foreign Currency Translation	Availablefor Sale Investments		Total
Balance, Beginning of Year	(26	)	95	—		69
Other Comprehensive Income, Before Tax	19		58	10		87
Income Tax	(4	)	—	(2	)	(6	)
Balance, End of Period	(11	)	153	8		150

As at September 30, 2012	Defined Benefit Plan		Foreign Currency Translation		Availablefor Sale Investments	Total
Balance, Beginning of Year	(22	)	119		—	97
Other Comprehensive Income, Before Tax	(3	)	(36	)	—	(39	)
Income Tax	—		—		—	—
Balance, End of Period	(25	)	83		—	58

17. 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 tandem stock appreciation rights (“TSARs”) or net settlement rights (“NSRs”). The following table is a summary of the options outstanding at the end of the period.

As at September 30, 2013	Issued	Term(Years)	WeightedAverageRemainingContractualLife (Years)	WeightedAverageExercisePrice ($)	ClosingSharePrice ($)	Number ofUnitsOutstanding (thousands)
NSRs	On or After February 24, 2011	7	5.68	35.34	30.74	26,153
TSARs	Prior to February 17, 2010	5	0.39	26.30	30.74	2,923
TSARs	On or After February 17, 2010	7	3.45	26.70	30.74	4,704
Encana Replacement TSARs held by Cenovus Employees	Prior to December 1, 2009	5	0.34	29.08	17.80	4,023
Cenovus Replacement TSARs held by Encana Employees	Prior to December 1, 2009	5	0.34	26.28	30.74	2,191

NSRs

The weighted average unit fair value of NSRs granted during the nine months ended September 30, 2013 was $6.13 before considering forfeitures, which are required to be 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 September 30, 2013	Number of NSRs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	15,074		37.52
Granted	11,646		32.57
Exercised for Common Shares	—		—
Forfeited	(567	)	36.51
Outstanding, End of Period	26,153		35.34
Exercisable, End of Period	5,806		37.53

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

TSARs Held by Cenovus Employees

The Company has recorded a liability of $39 million at September 30, 2013 (December 31, 2012 — $64 million) based on the fair value of each TSAR held by Cenovus employees. The intrinsic value of vested TSARs held by Cenovus employees as at September 30, 2013 was $32 million (December 31, 2012 — $45 million).

The following table summarizes information related to the TSARs, including Performance TSARs, held by Cenovus employees. All Performance TSARs have vested and, as such, terms and conditions are consistent with TSARs which were not performance based.

As at September 30, 2013	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	11,251		28.13
Exercised for Cash Payment	(1,534	)	30.38
Exercised as Options for Common Shares	(750	)	29.87
Forfeited	(58	)	28.89
Expired	(1,282	)	33.83
Outstanding, End of Period	7,627		26.55
Exercisable, End of Period	7,517		26.48

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $32.95.

Encana Replacement TSARs Held by Cenovus Employees

The Company has recorded a liability of $nil as at September 30, 2013 (December 31, 2012 — $1 million) based on the fair value of each Encana Replacement TSAR held by Cenovus employees. The intrinsic value of vested Encana Replacement TSARs held by Cenovus employees at September 30, 2013 was $nil (December 31, 2012 — $nil).

The following table summarizes information related to the Encana Replacement TSARs, including Performance TSARs held by Cenovus employees. All Performance TSARs have vested and, as such, terms and conditions are consistent with TSARs which were not performance based.

As at September 30, 2013	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	7,722		32.66
Forfeited	(141	)	30.41
Expired	(3,558	)	36.80
Outstanding, End of Period	4,023		29.08
Exercisable, End of Period	4,023		29.08

The closing price of Encana common shares on the TSX as at September 30, 2013 was $17.80.

Cenovus Replacement TSARs Held by Encana Employees

Encana is required to reimburse Cenovus in respect of cash payments made by Cenovus to Encana employees when these employees exercise a Cenovus Replacement TSAR for cash. No compensation expense is recognized and no further Cenovus Replacement TSARs will be granted to Encana employees.

The Company has recorded a liability of $10 million as at September 30, 2013 (December 31, 2012 — $35 million) based on the fair value of each Cenovus Replacement TSAR held by Encana employees, with an offsetting account receivable from Encana. The intrinsic value of vested Cenovus Replacement TSARs held by Encana employees at September 30, 2013 was $10 million (December 31, 2012 — $22 million).

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

The following table summarizes the information related to the Cenovus Replacement TSARs, including Performance TSARs, held by Encana employees. All Performance TSARs have vested and, as such, terms and conditions are consistent with TSARs which were not performance based.

As at September 30, 2013	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	5,229		29.29
Exercised for Cash Payment	(1,660	)	29.79
Exercised as Options for Common Shares	(15	)	29.57
Forfeited	(11	)	32.43
Expired	(1,352	)	33.51
Outstanding, End of Period	2,191		26.28
Exercisable, End of Period	2,191		26.28

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $32.99.

B) Performance Share Units

The Company has recorded a liability of $103 million as at September 30, 2013 (December 31, 2012 — $124 million) for performance share units (“PSUs”) based on the market value of Cenovus’s common shares at September 30, 2013. As PSUs are paid out upon vesting, the intrinsic value was $nil at September 30, 2013 and December 31, 2012.

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

As at September 30, 2013	Number of PSUs(thousands)
Outstanding, Beginning of Year	5,258
Granted	2,552
Paid Out	(2,008	)
Cancelled	(143	)
Units in Lieu of Dividends	130
Outstanding, End of Period	5,789

C) Deferred Share Units

The Company has recorded a liability of $36 million as at September 30, 2013 (December 31, 2012 — $36 million) for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares at September 30, 2013. 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 September 30, 2013	Number of DSUs(thousands)
Outstanding, Beginning of Year	1,084
Granted to Directors	63
Granted from Annual Bonus Awards	8
Units in Lieu of Dividends	28
Redeemed	(1	)
Outstanding, End of Period	1,182

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

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:

	Three Months Ended		Nine Months Ended
For the period ended September 30,	2013	2012	2013		2012
NSRs	10	9	26		22
TSARs Held by Cenovus Employees	3	4	(11	)	—
Encana Replacement TSARs Held by Cenovus Employees	—	—	—		1
PSUs	16	18	32		39
DSUs	1	2	—		4
Stock-Based Compensation Expense (Recovery)	30	33	47		66

18. 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 or Receivable. 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, Depreciation and Amortization (“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.

	September 30,		December 31,
As at	2013		2012
Long-Term Debt	4,830		4,679
Shareholders’ Equity	10,106		9,782
Capitalization	14,936		14,461
Debt to Capitalization	32	%	32	%

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

	September 30,		December 31,
As at	2013		2012
Debt	4,830		4,679
Net Earnings	603		995
Add (Deduct):
Finance Costs	518		455
Interest Income	(98	)	(109	)
Income Tax Expense	587		783
Depreciation, Depletion and Amortization	1,774		1,585
Goodwill Impairment	393		393
E&E Impairment	45		68
Unrealized (Gain) Loss on Risk Management	79		(57	)
Foreign Exchange (Gain) Loss, net	115		(20	)
(Gain) Loss on Divestitures of Assets	1		—
Other (Income) Loss, net	(1	)	(5	)
Adjusted EBITDA (1)	4,016		4,088
Debt to Adjusted EBITDA	1.2x		1.1x

(1) Calculated on a trailing 12 month basis.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

It is Cenovus’s intention to maintain investment grade credit ratings to help ensure it has continuous access to capital and the financial flexibility to fund its capital programs, meet its financial obligations and finance potential acquisitions. Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle. To manage 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.

At September 30, 2013, Cenovus had $3.0 billion available on its committed credit facility. In addition, Cenovus had in place a Canadian debt shelf prospectus for $1.5 billion and unused capacity of US$1.2 billion under a U.S. debt shelf prospectus, the availability of which are dependent on market conditions.

As at September 30, 2013, Cenovus is in compliance with all of the terms of its debt agreements.

19. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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 Receivable and Payable, partner loans, 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 Financial Assets and Liabilities

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 Receivable and Payable, partner loans and long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments.

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 at September 30, 2013 range from $50.50 to $73.00 per Megawatt Hour.

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 September 30, 2013, the carrying value of Cenovus’s long-term debt was $4,830 million and the fair value was $5,250 million (December 31, 2012 carrying value — $4,679 million, fair value — $5,582 million).

Available for sale financial assets, which comprise private equity investments, are carried at fair value. When fair value cannot be reliably measured, these assets are carried at cost. Fair value is determined based on recent private placement transactions (Level 3) when available. Available for sale assets are included in other assets on the Consolidated Balance Sheets.

B) Risk Management Assets and Liabilities

Net Risk Management Position

	September 30,	December 31,
As at	2013	2012
Risk Management Assets
Current Asset	91	283
Long-Term Asset	11	5
	102	288
Risk Management Liabilities
Current Liability	19	17
Long-Term Liability	1	1
	20	18
Net Risk Management Asset (Liability)	82	270

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Summary of Unrealized Risk Management Positions

	September 30, 2013			December 31, 2012
	Risk Management			Risk Management
As at	Asset	Liability	Net	Asset	Liability	Net
Commodity Prices
Crude Oil	83	19	64	221	16	205
Natural Gas	17	—	17	66	1	65
Power	2	1	1	1	1	—
Fair Value	102	20	82	288	18	270

Financial assets and liabilities are only offset if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. Cenovus has pledged cash collateral of $12 million (December 31, 2012 — $12 million) with respect to certain of these risk management contracts, which has not been offset against the related financial liability. The following table provides a summary of the Company’s offsetting risk management positions:

	September 30, 2013					December 31, 2012
	Risk Management					Risk Management
As at	Asset		Liability		Net	Asset		Liability		Net
Recognized Risk Management Positions
Gross Amount	121		39		82	306		36		270
Amount Offset	(19	)	(19	)	—	(18	)	(18	)	—
Net Amount per Consolidated Financial Statements	102		20		82	288		18		270

Net Fair Value Methodologies Used to Calculate Unrealized Risk Management Positions

	September 30,	December 31,
As at	2013	2012
Prices Sourced from Observable Data or Market Corroboration (Level 2)	81	270
Prices Determined from Unobservable Inputs (Level 3)	1	—
	82	270

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

77

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Net Fair Value of Commodity Price Positions at September 30, 2013

	NotionalVolumes	Term	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price (1)	18,500 bbls/d	2013	110.36 US$/bbl	6
Brent Fixed Price (1)	18,500 bbls/d	2013	111.72 C$/bbl	3
Brent Fixed Price	30,000 bbls/d	2014	102.04 US$/bbl	(5	)
Brent Fixed Price	20,000 bbls/d	2014	107.06 C$/bbl	7
WCS Differential (2)	49,000 bbls/d	2013	(20.74) US$/bbl	41
WCS Differential (2)	15,400 bbls/d	2014	(20.39) US$/bbl	16
Other Financial Positions (3)				(4	)
Crude Oil Fair Value Position				64
Natural Gas Contracts
Fixed Price Contracts
NYMEX Fixed Price	166 MMcf/d	2013	4.64 US$/Mcf	17
Other Fixed Price Contracts (4)				—
Natural Gas Fair Value Position				17
Power Purchase Contracts
Power Fair Value Position				1

(1) Brent fixed price positions consist of both Brent fixed price swaps and WTI swaps converted to Brent.

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

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

(4) Cenovus entered into other fixed price contracts to protect against widening price differentials between production areas and various sales points.

Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2013		2012		2013		2012
Realized Gain (Loss) (1)
Crude Oil	(32	)	26		22		26
Natural Gas	19		65		46		200
Refining	(22	)	6		(30	)	18
Power	2		2		7		—
	(33	)	99		45		244
Unrealized Gain (Loss) (2)
Crude Oil	22		(189	)	(147	)	102
Natural Gas	(15	)	(83	)	(51	)	(144	)
Refining	2		(11	)	1		(3	)
Power	(1	)	(10	)	1		(15	)
	8		(293	)	(196	)	(60	)
Gain (Loss) on Risk Management	(25	)	(194	)	(151	)	184

(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.

Cenovus Energy Inc.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

78

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2013

Reconciliation of Unrealized Risk Management Positions from January 1 to September 30, 2013

	2013				2012
	Fair Value		TotalUnrealizedGain (Loss)		TotalUnrealizedGain (Loss)
Fair Value of Contracts, Beginning of Year	270
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered into During the Period	(151	)	(151	)	184
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	8		—		—
Fair Value of Contracts Realized During the Period	(45	)	(45	)	(244	)
Fair Value of Contracts, End of Period	82		(196	)	(60	)

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 as at September 30, 2013 could have resulted in unrealized gains (losses) impacting earnings before income tax for the nine months ended September 30, 2013 as follows:

Risk Management Positions in Place as at September 30, 2013

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent and WTI Hedges	(247	)	247
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges tied to Production	59		(59	)
Natural Gas Commodity Price	± $1 per Mcf Applied to NYMEX Natural Gas Hedges	(16	)	16
Natural Gas Basis Price	± $0.10 per Mcf Applied to Natural Gas Basis Hedges	—		—
Power Commodity Price	± $25 per MWHr Applied to Power Hedge	19		(19	)

C) Risks Associated with Financial Assets and Liabilities

The Company is exposed to a number of risks associated with its financial assets and liabilities. These risks include commodity price risk, credit risk, liquidity risk, foreign exchange risk and interest rate risk. The Company has several practices and policies in place to help mitigate these risks.

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, 2012. The Company’s exposure to these risks has not changed significantly since December 31, 2012.

20. COMMITMENTS AND CONTINGENCIES

A) Commitments

During the nine months ended September 30, 2013 the Company entered into various firm transportation agreements totaling approximately $11 billion. These agreements, some of which are subject to regulatory approval, are for terms up to 20 years subsequent to the date of commencement. In addition, Cenovus entered into an office lease agreement totaling approximately $1 billion over a 22 year term beginning upon completion of construction of the building expected to be in late 2017.

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.
Third Quarter 2013 Report	Notes to Consolidated Financial Statements

79

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

		2013								2012
		Year												Q3 Year
		to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Gross Sales
Upstream		5,125		1,926		1,646		1,553		6,156		1,584		4,572		1,496		1,382		1,694
Refining and Marketing		9,483		3,459		3,078		2,946		11,356		2,336		9,020		3,066		2,962		2,992
Corporate and Eliminations		(442	)	(190	)	(130	)	(122	)	(283	)	(118	)	(165	)	(100	)	(65	)	—
Less: Royalties		256		120		78		58		387		78		309		122		65		122
Revenues		13,910		5,075		4,516		4,319		16,842		3,724		13,118		4,340		4,214		4,564
Operating Cash Flow
Crude Oil and Natural Gas Liquids
Foster Creek		673		252		232		189		924		246		678		227		223		228
Christina Lake		417		248		96		73		343		118		225		93		70		62
Pelican Lake		293		130		96		67		418		98		320		108		85		127
Conventional		771		285		251		235		962		240		722		227		228		267
Natural Gas		327		94		118		115		513		134		379		126		121		132
Other Upstream Operations		12		2		6		4		9		5		4		2		—		2
		2,493		1,011		799		683		3,169		841		2,328		783		727		818
Refining and Marketing		985		137		320		528		1,267		122		1,145		527		351		267
Operating Cash Flow (1)		3,478		1,148		1,119		1,211		4,436		963		3,473		1,310		1,078		1,085
Cash Flow Information
Cash from Operating Activities		2,563		840		828		895		3,420		758		2,662		1,029		968		665
Deduct (Add back):
Net Change in Other Assets and Liabilities		(90	)	(25	)	(31	)	(34	)	(113	)	(42	)	(71	)	(19	)	(20	)	(32	)
Net Change in Non-Cash Working Capital		(121	)	(67	)	(12	)	(42	)	(110	)	103		(213	)	(69	)	63		(207	)
Cash Flow (2)		2,774		932		871		971		3,643		697		2,946		1,117		925		904
Per Share	- Basic	3.67		1.23		1.15		1.28		4.82		0.92		3.90		1.48		1.22		1.20
	- Diluted	3.66		1.23		1.15		1.28		4.80		0.92		3.88		1.47		1.22		1.19
Operating Earnings (3)		959		313		255		391		868		(188	)	1,056		432		284		340
Per Share	- Diluted	1.27		0.41		0.34		0.52		1.14		(0.25	)	1.39		0.57		0.37		0.45
Net Earnings		720		370		179		171		995		(117	)	1,112		289		397		426
Per Share	- Basic	0.95		0.49		0.24		0.23		1.32		(0.15	)	1.47		0.38		0.53		0.56
	- Diluted	0.95		0.49		0.24		0.23		1.31		(0.15	)	1.47		0.38		0.52		0.56
Effective Tax Rates using
Net Earnings		35.5	%							44.1	%
Operating Earnings, excluding Divestitures		31.7	%							47.0	%
Canadian Statutory Rate		25.2	%							25.2	%
U.S. Statutory Rate		38.5	%							38.5	%
Foreign Exchange Rates (US$ per C$1)
Average		0.977		0.963		0.977		0.992		1.001		1.009		0.998		1.005		0.990		0.999
Period end		0.972		0.972		0.951		0.985		1.005		1.005		1.017		1.017		0.981		1.001

(1)	Operating cash flow is a non-GAAP measure defined as revenue less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk management activities.
(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 defined as net earnings excluding after-tax gain (loss) on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized risk management gains (losses) on derivative instruments, after-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, after-tax gains (losses) on divestiture of assets, deferred income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates.

Financial Metrics (Non-GAAP measures)

	2013								2012
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Debt to Capitalization (4), (5)	32	%	32	%	33	%	33	%	32	%	32	%	32	%	32	%	27	%	28	%
Debt to Adjusted EBITDA (5), (6)	1.2	x	1.2	x	1.2	x	1.1	x	1.1	x	1.1	x	1.1	x	1.1	x	1.0	x	1.0	x
Return on Capital Employed (7)	6	%	6	%	5	%	7	%	9	%	9	%	11	%	11	%	14	%	16	%
Return on Common Equity (8)	6	%	6	%	5	%	8	%	10	%	10	%	14	%	14	%	17	%	21	%

(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)	We define trailing 12-month Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, DD&A, asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net.
(7)	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.
(8)	Return on common equity is calculated, on a trailing 12-month basis, as net earnings divided by average shareholders’ equity.

Cenovus Energy Inc.
Third Quarter 2013 Report	Supplemental Information

80

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

Common Share Information

	2013								2012
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Common Shares Outstanding (millions)
Period end	755.8		755.8		755.8		755.8		755.8		755.8		755.8		755.8		755.7		755.6
Average - Basic	755.9		755.8		755.8		756.0		755.6		755.8		755.5		755.7		755.7		755.1
Average - Diluted	757.6		757.2		757.1		758.4		758.5		758.3		758.5		758.0		757.9		759.5
Price Range ($ per share)
TSX - C$
High	34.13		32.77		32.08		34.13		39.64		35.69		39.64		36.25		36.68		39.64
Low	28.32		28.98		28.32		31.67		30.09		31.82		30.09		30.37		30.09		33.24
Close	30.74		30.74		30.00		31.46		33.29		33.29		34.31		34.31		32.37		35.90
NYSE - US$
High	34.50		31.60		31.58		34.50		39.81		36.11		39.81		37.31		37.26		39.81
Low	27.25		28.00		27.25		30.58		28.83		31.74		28.83		30.20		28.83		32.45
Close	29.85		29.85		28.52		30.99		33.54		33.54		34.85		34.85		31.80		35.94
Dividends Paid ($ per share)	$	0.726	$	0.242	$	0.242	$	0.242	$	0.88	$	0.22	$	0.66	$	0.22	$	0.22	$	0.22
Share Volume Traded (millions)	539.5		183.0		201.6		154.9		664.3		141.7		522.6		152.6		192.6		177.4

Net Capital Investment

	2013							2012
	Year											Q3 Year
	to Date		Q3		Q2	Q1		Year		Q4		to Date		Q3	Q2	Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	604		205		189	210		735		208		527		199	169	159
Christina Lake	499		162		162	175		593		168		425		147	140	138
Total	1,103		367		351	385		1,328		376		952		346	309	297
Pelican Lake	350		96		111	143		518		147		371		128	104	139
Other Oil Sands	278		60		69	149		365		82		283		42	41	200
	1,731		523		531	677		2,211		605		1,606		516	454	636
Conventional	510		178		134	198		848		257		591		231	129	231
Refining and Marketing	70		19		26	25		118		58		60		38	24	(2	)
Corporate	53		23		15	15		191		58		133		45	53	35
Capital Investment	2,364		743		706	915		3,368		978		2,390		830	660	900
Acquisitions (1)	5		1		1	3		114		70		44		8	28	8
Divestitures	(242	)	(241	)	—	(1	)	(76	)	(11	)	(65	)	—	1	(66	)
Net Acquisition and Divestiture Activity	(237	)	(240	)	1	2		38		59		(21	)	8	29	(58	)
Net Capital Investment	2,127		503		707	917		3,406		1,037		2,369		838	689	842

(1) Q4 2012 asset acquisition included the assumption of a decommissioning liability of $33 million.

Operating Statistics - Before Royalties

Upstream Production Volumes

	2013				2012
	Year						Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4	to Date	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands - Heavy Oil
Foster Creek	53,450	49,092	55,338	55,996	57,833	59,059	57,421	63,245	51,740	57,214
Christina Lake	45,211	52,732	38,459	44,351	31,903	41,808	28,577	32,380	28,577	24,733
Total	98,661	101,824	93,797	100,347	89,736	100,867	85,998	95,625	80,317	81,947
Pelican Lake	24,162	24,826	23,959	23,687	22,552	23,507	22,231	23,539	22,410	20,730
	122,823	126,650	117,756	124,034	112,288	124,374	108,229	119,164	102,727	102,677
Conventional Liquids
Heavy Oil	16,163	15,507	16,284	16,712	16,015	16,243	15,938	15,492	15,703	16,624
Light and Medium Oil	36,081	33,651	36,137	38,508	36,071	36,034	36,083	35,695	36,149	36,411
Natural Gas Liquids (2)	1,018	1,130	950	971	1,029	995	1,041	999	987	1,138
Total Crude Oil and Natural Gas Liquids	176,085	176,938	171,127	180,225	165,403	177,646	161,291	171,350	155,566	156,850
Natural Gas (MMcf/d)
Oil Sands	23	25	24	20	33	30	33	27	33	41
Conventional	512	498	512	525	561	536	569	550	563	595
Total Natural Gas	535	523	536	545	594	566	602	577	596	636
Total Production (BOE/d)	265,252	264,105	260,460	271,058	264,403	271,979	261,624	267,517	254,899	262,850

(2) Natural gas liquids include condensate volumes.

Average Royalty Rates

(excluding impact of Realized Gain (Loss) on Risk Management)

	2013								2012
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Oil Sands
Foster Creek	5.7	%	7.6	%	5.7	%	2.9	%	11.8	%	8.0	%	13.0	%	19.1	%	4.6	%	13.9	%
Christina Lake	6.4	%	7.0	%	5.6	%	5.7	%	6.2	%	5.7	%	6.4	%	5.3	%	7.2	%	7.0	%
Pelican Lake	6.7	%	7.7	%	5.8	%	6.2	%	5.0	%	4.5	%	5.1	%	6.6	%	4.2	%	4.5	%
Conventional
Weyburn	20.4	%	22.3	%	20.3	%	18.3	%	20.7	%	17.9	%	21.6	%	19.8	%	21.4	%	23.3	%
Other	6.2	%	6.8	%	6.0	%	5.7	%	7.2	%	7.1	%	7.3	%	6.6	%	6.8	%	8.3	%
Natural Gas Liquids	1.9	%	2.9	%	2.5	%	0.2	%	2.0	%	2.3	%	2.0	%	2.5	%	1.7	%	1.7	%
Natural Gas	1.5	%	1.8	%	1.2	%	1.7	%	1.2	%	0.9	%	1.3	%	0.8	%	0.4	%	2.5	%

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Third Quarter 2013 Report	Supplemental Information

81

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Refining

	2013								2012
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Refinery Operations (1)
Crude oil capacity (2) (Mbbls/d)	457		457		457		457		452		452		452		452		452		452
Crude oil runs (Mbbls/d)	440		464		439		416		412		311		446		442		451		445
Heavy Oil	223		240		230		197		198		155		213		210		229		199
Light/Medium	217		224		209		219		214		156		233		232		222		246
Crude utilization	96	%	101	%	96	%	91	%	91	%	69	%	99	%	98	%	100	%	98	%
Refined products (Mbbls/d)	461		487		457		439		433		330		467		463		473		465

(1)	Represents 100% of the Wood River and Borger refinery operations.
(2)	The official nameplate capacity of Wood River increased effective January 1, 2013.

Selected Average Benchmark Prices

	2013							2012
	Year											Q3 Year
	to Date		Q3	Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Crude Oil Prices (US$/bbl)
Brent Futures	108.49		109.65	103.35		112.64		111.68		110.13		112.20		109.42		108.76		118.45
West Texas Intermediate (“WTI”)	98.20		105.81	94.17		94.36		94.15		88.23		96.16		92.20		93.35		103.03
Average Differential Brent Futures-WTI	10.29		3.84	9.18		18.28		17.53		21.90		16.04		17.22		15.41		15.42
Western Canadian Select (“WCS”)	75.34		88.33	75.01		62.40		73.12		70.12		74.16		70.48		70.48		81.61
Differential - WTI-WCS	22.86		17.48	19.16		31.96		21.03		18.11		22.00		21.72		22.87		21.42
Condensate - (C5 @ Edmonton)	104.24		103.79	101.45		107.23		100.88		98.14		101.83		96.12		99.32		110.16
Differential - WTI-Condensate (premium)/discount	(6.04	)	2.02	(7.28	)	(12.87	)	(6.73	)	(9.91	)	(5.67	)	(3.92	)	(5.97	)	(7.13	)
Refining Margins 3-2-1 Crack Spreads (3)(US$/bbl)
Chicago	24.93		16.19	31.06		27.53		27.76		28.18		27.61		35.64		28.20		19.00
Midwest Combined (Group 3)	24.17		17.35	27.24		27.93		28.56		28.49		28.59		35.99		28.28		21.50
Natural Gas Prices
AECO ($/GJ)	3.00		2.67	3.40		2.92		2.28		2.90		2.07		2.08		1.74		2.39
NYMEX (US$/MMBtu)	3.67		3.58	4.09		3.34		2.79		3.40		2.59		2.81		2.22		2.74
Differential - NYMEX-AECO (US$/MMBtu)	0.57		0.89	0.56		0.27		0.38		0.31		0.41		0.61		0.39		0.21

(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 (Loss) on Risk Management)

	2013				2012
	Year						Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4	to Date	Q3	Q2	Q1
Heavy Oil - Foster Creek (4)($/bbl)
Price	68.79	87.49	68.17	52.60	64.55	59.93	66.18	63.95	63.83	70.71
Royalties	3.80	6.31	3.87	1.47	7.36	4.55	8.35	11.79	2.85	9.54
Transportation and Blending	2.05	4.37	0.04	1.89	2.41	2.91	2.24	2.38	1.91	2.38
Operating	15.73	17.12	16.19	14.03	11.99	11.26	12.26	11.50	12.49	12.85
Netback	47.21	59.69	48.07	35.21	42.79	41.21	43.33	38.28	46.58	45.94
Heavy Oil - Christina Lake (4)($/bbl)
Price	54.71	74.98	52.61	33.41	47.73	43.37	49.99	52.91	44.57	52.58
Royalties	3.27	5.06	2.71	1.69	2.72	2.32	2.94	2.61	2.90	3.37
Transportation and Blending	3.68	3.16	4.45	3.67	3.79	3.00	4.19	4.00	4.12	4.51
Operating	13.42	11.46	16.83	12.93	12.95	11.42	13.76	13.59	12.52	15.33
Netback	34.34	55.30	28.62	15.12	28.27	26.63	29.10	32.71	25.03	29.37
Heavy Oil - Pelican Lake (4)($/bbl)
Price	71.99	88.08	72.32	54.30	69.23	64.37	70.82	66.75	66.42	78.50
Royalties	4.69	6.64	4.08	3.22	3.34	2.82	3.51	4.34	2.68	3.37
Transportation and Blending	2.28	2.18	2.58	2.07	2.15	1.23	2.45	1.09	3.54	2.88
Operating	20.46	19.90	22.21	19.23	17.08	17.20	17.04	17.47	17.71	16.05
Netback	44.56	59.36	43.45	29.78	46.66	43.12	47.82	43.85	42.49	56.20
Heavy Oil - Oil Sands (4)($/bbl)
Price	64.29	82.52	64.09	45.92	60.84	55.11	63.07	61.71	59.00	68.36
Royalties	3.78	5.87	3.55	1.88	5.22	3.47	5.91	7.85	2.83	6.66
Transportation and Blending	2.69	3.45	1.98	2.57	2.74	2.63	2.78	2.52	2.87	2.99
Operating	15.82	15.37	17.67	14.59	13.33	12.41	13.68	13.29	13.61	14.18
Netback	42.00	57.83	40.89	26.88	39.55	36.60	40.70	38.05	39.69	44.53
Heavy Oil - Conventional (4)($/bbl)
Price	72.67	86.58	70.81	61.62	70.53	64.73	72.53	68.04	67.70	80.64
Royalties	8.77	12.27	7.67	6.57	10.06	8.68	10.54	8.81	9.36	13.06
Transportation and Blending	3.02	3.04	2.59	3.39	2.17	2.34	2.11	2.31	2.26	1.81
Operating	17.27	16.32	17.38	18.04	15.21	11.68	16.43	16.48	15.07	17.57
Production and Mineral Taxes	0.38	0.55	0.30	0.30	0.24	0.31	0.21	0.27	0.25	0.14
Netback	43.23	54.40	42.87	33.32	42.85	41.72	43.24	40.17	40.76	48.06
Total Heavy Oil (4)($/bbl)
Price	65.27	82.97	64.91	47.82	62.05	56.22	64.28	62.45	60.13	70.08
Royalties	4.37	6.58	4.05	2.45	5.83	4.07	6.50	7.96	3.68	7.56
Transportation and Blending	2.73	3.40	2.06	2.67	2.67	2.60	2.70	2.50	2.79	2.82
Operating	15.99	15.47	17.63	15.01	13.56	12.33	14.04	13.66	13.80	14.65
Production and Mineral Taxes	0.04	0.06	0.04	0.04	0.03	0.04	0.03	0.03	0.03	0.02
Netback	42.14	57.46	41.13	27.65	39.96	37.18	41.01	38.30	39.83	45.03
Light and Medium Oil ($/bbl)
Price	87.63	100.64	86.84	76.77	78.99	75.27	80.24	76.06	76.16	88.45
Royalties	8.82	11.01	8.61	7.05	8.09	6.92	8.49	7.53	7.98	9.94
Transportation and Blending	4.09	4.58	4.37	3.39	2.65	2.39	2.73	2.36	3.02	2.83
Operating	15.90	15.06	16.32	16.26	15.51	15.63	15.48	16.27	14.76	15.36
Production and Mineral Taxes	2.63	2.80	2.64	2.46	2.44	2.51	2.42	2.35	2.34	2.57
Netback	56.19	67.19	54.90	47.61	50.30	47.82	51.12	47.55	48.06	57.75

(4) 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 for 2013 YTD is as follows:  Foster Creek - $42.61/bbl; Christina Lake - $45.80/bbl; Pelican Lake - $16.28/bbl; Heavy Oil - Oil Sands - $38.58/bbl; Heavy Oil - Conventional - $14.14/bbl and Total Heavy Oil - $35.70/bbl.

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Third Quarter 2013 Report	Supplemental Information

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SUPPLEMENTAL INFORMATION (unaudited)    

Operating Statistics - Before Royalties (continued)

Per-unit Results

(excluding impact of Realized Gain (Loss) on Risk Management)

	2013						2012
	Year									Q3 Year
	to Date	Q3		Q2		Q1	Year	Q4		to Date	Q3	Q2		Q1
Total Crude Oil ($/bbl)
Price	69.96	86.41		69.75		54.02	65.76	60.10		67.87	65.37	63.91		74.22
Royalties	5.30	7.44		5.05		3.43	6.32	4.65		6.95	7.87	4.69		8.10
Transportation and Blending	3.02	3.63		2.57		2.82	2.66	2.55		2.70	2.47	2.84		2.83
Operating	15.97	15.39		17.34		15.27	13.99	13.00		14.36	14.22	14.03		14.81
Production and Mineral Taxes	0.59	0.59		0.61		0.56	0.56	0.54		0.57	0.53	0.58		0.59
Netback	45.08	59.36		44.18		31.94	42.23	39.36		43.29	40.28	41.77		47.89
Natural Gas Liquids ($/bbl)
Price	60.71	65.71		46.44		68.88	69.54	65.89		70.71	61.53	65.52		83.36
Royalties	1.12	1.92		1.17		0.12	1.42	1.52		1.38	1.55	1.13		1.45
Netback	59.59	63.79		45.27		68.76	68.12	64.37		69.33	59.98	64.39		81.91
Total Liquids ($/bbl)
Price	69.91	86.28		69.61		54.10	65.79	60.13		67.89	65.35	63.92		74.28
Royalties	5.28	7.40		5.03		3.42	6.29	4.64		6.91	7.83	4.67		8.05
Transportation and Blending	3.00	3.61		2.55		2.81	2.65	2.54		2.69	2.45	2.82		2.81
Operating	15.88	15.29		17.24		15.19	13.90	12.93		14.27	14.14	13.93		14.71
Production and Mineral Taxes	0.58	0.59		0.61		0.55	0.56	0.54		0.56	0.53	0.57		0.59
Netback	45.17	59.39		44.18		32.13	42.39	39.48		43.46	40.40	41.93		48.12
Total Natural Gas ($/Mcf)
Price	3.20	2.83		3.50		3.25	2.42	2.97		2.25	2.30	1.92		2.50
Royalties	0.05	0.05		0.04		0.05	0.03	0.02		0.03	0.02	0.01		0.06
Transportation and Blending	0.11	0.10		0.08		0.15	0.10	0.10		0.10	0.08	0.08		0.13
Operating	1.14	1.13		1.16		1.14	1.10	1.29		1.05	1.08	0.98		1.08
Production and Mineral Taxes	0.02	0.03		(0.01	)	0.03	0.01	(0.01	)	0.02	0.02	0.02		0.02
Netback	1.88	1.52		2.23		1.88	1.18	1.57		1.05	1.10	0.83		1.21
Total (1)($/BOE)
Price	52.67	63.12		52.55		42.52	46.60	45.50		46.98	46.61	43.25		50.84
Royalties	3.58	5.02		3.35		2.38	4.00	3.08		4.32	5.02	2.84		5.00
Transportation and Blending	2.20	2.60		1.82		2.17	1.88	1.86		1.88	1.74	1.90		2.00
Operating	12.81	12.44		13.64		12.39	11.18	11.12		11.20	11.35	10.75		11.46
Production and Mineral Taxes	0.42	0.45		0.38		0.42	0.38	0.33		0.40	0.38	0.40		0.40
Netback	33.66	42.61		33.36		25.16	29.16	29.11		29.18	28.12	27.36		31.98
Impact of Long-Term Incentives Costs (Recovery) on Operating Costs ($/BOE)	0.14	0.23		0.07		0.10	0.16	0.05		0.20	0.32	(0.17	)	0.42
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	0.45	(2.02	)	0.72		2.62	1.39	3.35		0.66	2.02	1.64		(1.67	)
Natural Gas ($/Mcf)	0.31	0.38		0.18		0.39	1.14	0.89		1.21	1.24	1.39		1.03
Total (1) ($/BOE)	0.94	(0.58	)	0.84		2.52	3.42	4.05		3.21	3.98	4.27		1.44

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

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ADVISORY

FINANCIAL INFORMATION

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

NON-GAAP MEASURES

This quarterly report 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.

·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.

·Operating earnings is defined as net earnings excluding after-tax gain (loss) on discontinuance, after-tax gain on bargain purchase, after-tax effect of unrealized risk management gains (losses) on derivative instruments, after-tax unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, after-tax foreign exchange gains (losses) on settlement of intercompany transactions, after-tax gains (losses) on divestiture of assets, deferred income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. Management views operating earnings as a better measure of performance than net earnings because the excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.

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

·Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength. Debt is defined as 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 quarterly report in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus’s most recent Management’s Discussion & Analysis (MD&A) available at cenovus.com.

FORWARD-LOOKING INFORMATION

This document contains certain forward-looking statements and other information (collectively “forward-looking information”) about our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast” or “F”, “target”, “project”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook”, “potential”, “may”, “objective”, “projected”, “strategy” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projected future value or net asset value, projections contained in our updated 2013 guidance, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, expected future refining capacity, broadening market access, improving cost structures, expected reserves and resources estimates, potential dividends and dividend growth strategy, anticipated timelines for future regulatory, partner or internal approvals, future impact of regulatory measures, forecasted commodity prices, future use and development of technology, including to reduce our environmental impact and projected increasing shareholder value. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

We updated our guidance for 2013, published on our website, cenovus.com. For the period 2014 to 2023 assumptions include Brent US$100.00-US$110.00/bbl; WTI of US$96.00-US$106.00/bbl; Western Canada Select of C$71.00-C$91.00/bbl; NYMEX of US$4.50-

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US$4.75/MMBtu; AECO of C$3.89-C$4.31/GJ; Chicago 3-2-1 crack spread of US$12.00-US$15.00; exchange rate of $1.00 US$/C$; and average diluted number of shares outstanding of approximately 780 million.

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 our current guidance, available at cenovus.com; our projected capital investment levels, the flexibility of our 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; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow from operations to meet our current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding oil and gas prices; the effectiveness of our risk management program, including the impact of derivative financial instruments and the success of our hedging strategies; 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 our marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted EBITDA as well as debt to capitalization; our ability to access various sources of debt and equity capital; accuracy of our reserves, resources and future production estimates; our ability to replace and expand oil and gas reserves; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated heavy oil business; reliability of our assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation, including sufficient crude-by-rail or alternate transportation; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

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

ABBREVIATIONS

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

Crude Oil and NGLs		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls/d	barrels per day	MMcf	million cubic feet
Mbbls/d	thousand barrels per day	Bcf	billion cubic feet
MMbbls	million barrels	MMBtu	million British thermal units
		GJ	Gigajoule
		CBM	Coal Bed Methane
Other
TM	Trademark of Cenovus Energy Inc.

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Cenovus Energy Inc.

500 Centre Street SE

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-7600

Cenovus Environment & Corporate Affairs
Investor contacts:	Media contact:
Graham Ingram	Media Relations
Senior Analyst, Investor Relations	403-766-7751
403-766-2849	media.relations@cenovus.com
graham.ingram@cenovus.com
Bill Stait
Senior Analyst, Investor Relations
403-766-6348
bill.stait@cenovus.com

cenovus.com