Exhibit 99.1

Cenovus oil sands production increases 33%

Cash flow up 37% on higher volumes and prices

·Combined oil sands production at Foster Creek and Christina Lake averaged almost 125,000 barrels per day (bbls/d) net in the second quarter, up 33% from a year earlier.

·Production at Christina Lake averaged nearly 68,000 bbls/d net in the second quarter, an increase of 77% when compared with the same period a year earlier as phase E reached its design capacity.

·Foster Creek production averaged almost 57,000 bbls/d net in the quarter, an increase of 3% from the second quarter of 2013.

·Steaming at Foster Creek’s phase F expansion began in May.

·Cenovus generated nearly $1.2 billion in cash flow, a 37% increase when compared with the same period in 2013 due to increased production and higher commodity prices.

“Cenovus generated record cash flow in the second quarter, with strong contributions from all of our business operations,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “Once again, we’ve been able to generate predictable, reliable results and deliver growing total shareholder return.”

Production & financial summary

(for the period ended June 30) Production (before royalties)	2014Q2	2013 Q2	% change
Oil sands total (bbls/d)	124,827	93,797	33
Conventional oil1 (bbls/d)	76,861	77,330	-1
Total oil (bbls/d)	201,688	171,127	18
Natural gas (MMcf/d)	507	536	-5

Financial ($ millions, except per share amounts)
Cash flow2	1,189	871	37
Per share diluted	1.57	1.15
Operating earnings2	473	255	85
Per share diluted	0.62	0.34
Net earnings	615	179	244
Per share diluted	0.81	0.24
Capital investment	686	706	-3

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 (July 30, 2014) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) achieved strong second quarter results as the company benefited from increased oil production and higher commodity prices, contributing to a significant increase in cash flow compared with the same period a year earlier.

Cenovus’s oil sands production averaged almost 125,000 bbls/d net in the second quarter, up 33% from a year earlier, primarily driven by strong performance at the company’s Christina Lake project. Christina Lake production increased 77% from the second quarter of 2013, averaging nearly 68,000 bbls/d net as phase E reached its design capacity and the company completed a planned partial turnaround with minimal impact to production.

Foster Creek performed in line with expectations, achieving production that averaged almost 57,000 bbls/d net in the second quarter, up 3% from the same period in 2013. Through the remainder of the year, the company expects the steam to oil ratio (SOR) at Foster Creek to be at the upper end of its annual guidance range of 2.6 to 3.0 as steaming of the phase F expansion continues. First production from phase F wells is expected in the fourth quarter.

Cash flow for the quarter was almost $1.2 billion, an increase of 37% from the same period in 2013. The increase was driven by 34% higher operating cash flow from the company’s oil and natural gas producing assets, largely due to a year-over-year increase in oil sands production and higher crude oil and natural gas prices. In addition, current tax and exploration expenses were lower in the quarter than in the same period in 2013. Cenovus’s strong performance from its oil sands and conventional oil and natural gas producing assets more than offset a decline in refining operating cash flow due to lower market crack spreads and higher crude oil feedstock costs. Cenovus had free cash flow in the quarter of $503 million.

“We’re pleased with the solid growth in our oil sands production, supported by strong cash flow from both our conventional and refining assets,” said John Brannan, Executive Vice-President & Chief Operating Officer. “This continues to demonstrate the value of our integrated business strategy.”

Strengthening our leadership team

As Cenovus continues to ensure it has adequate transportation capacity to move its growing production to market, the company has added new expertise to its leadership team. Robert (Bob) Pease joined Cenovus in June as the company’s Executive Vice-President, Markets, Products & Transportation. He is responsible for all commercial activities associated with crude oil, natural gas and natural gas liquids as well as the company’s refining business. With more than 34 years of experience in refining, marketing and transporting oil, he will be responsible for developing and executing strategies that help Cenovus maximize the return it receives for its products across the value chain.

The company has also added new expertise to support its growing capacity to ship crude oil by rail to access higher value markets. Kent Avery has joined Cenovus’s management team as Vice-President, Rail. He has extensive experience in rail operations and business development involving the transportation of oil and other petroleum products.

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Oil Projects

Daily production1

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

1 Totals may not add due to rounding.

2 Includes NGLs production.

Oil sands

Cenovus has a substantial portfolio of oil sands assets in northern Alberta with the potential to provide decades of growth. The two operations currently producing, Foster Creek and Christina Lake, use steam-assisted gravity drainage (SAGD), which involves drilling into the reservoir and injecting steam at low pressures to soften the thick oil so it can be pumped to the surface. Cenovus 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 an enormous opportunity to deliver increased shareholder value through production growth from several identified emerging projects and additional future developments. The company continues to assess its resources and prioritize development plans to create long-term value.

Christina Lake

Production

·Production at Christina Lake averaged 67,975 bbls/d net in the second quarter, 77% higher than the same period a year earlier due to phase E reaching its design capacity, both on time and on budget. Work to optimize phases C, D and E continues, with incremental production expected in 2015.

·The SOR at Christina Lake was 1.8 in the second quarter, consistent with the same period a year earlier.

·Operating costs at Christina Lake were $12.08 per barrel (bbl) in the second quarter, a 28% decline from the same period a year ago. This was primarily due to higher production volumes. The decrease was partially offset by increased fuel expenses, consistent with higher natural gas prices.

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·Non-fuel operating costs were $8.22/bbl, compared with $13.46/bbl in the second quarter of 2013, a 39% decline.

·The netback the company received for its Christina Lake oil production increased 81% to $51.66/bbl in the second quarter compared with the same period of 2013.

Expansions

·The phase F expansion at Christina Lake is on schedule and on budget with about 57% of the project complete. First production is expected in 2016. Cenovus is also working on engineering and procurement for phase G.

·Total capital investment was $183 million, 13% higher compared with the second quarter of 2013. Most of the increase was driven by phase F plant and well pad construction, the drilling of sustaining wells and phase G engineering and procurement.

Foster Creek

Production

·Foster Creek production averaged 56,852 bbls/d net in the quarter, in line with company expectations, representing a 3% increase from the same period a year earlier.

·The SOR at Foster Creek was 2.6 in the second quarter of 2014, compared with 2.4 in the same period of 2013. The SOR is expected to be at the upper end of the company’s projected annual range of 2.6 to 3.0 for the remainder of 2014 as the company steams phase F in advance of first production, anticipated in the fourth quarter. The ramp-up to design capacity is expected to take 12 to 18 months after first production.

·During the quarter, the company received regulatory approval for blowdown for two additional well pads. This brings the total number of well pads approved for blowdown at Foster Creek to five. The company expects to begin rampdown of these two additional pads by early 2015. Rampdown is the first phase of the blowdown process, which enables the company to move steam from well pads that no longer need it for continued production to new or existing areas of the reservoir. The company currently has one pad on full blowdown and two well pads on rampdown using methane co-injection. Cenovus continues to monitor conditions in the reservoir to optimize steam placement.

·Operating costs at Foster Creek averaged $19.38/bbl in the second quarter, a 20% increase from the same period a year ago. The majority of the per-barrel operating cost increase was due to higher fuel expenses, consistent with higher natural gas prices and increased consumption.

·Non-fuel operating costs were $14.78/bbl in the quarter compared with $13.36/bbl in the same period of 2013. The increase was mainly associated with higher workforce and workover costs.

·The netback the company received for its Foster Creek oil production rose 4% to $50.15/bbl in the second quarter from the same period in 2013.

Expansions

·The Foster Creek phase F main plant was 96% complete at the end of the second quarter. Capital costs for the F, G and H expansion phases are trending higher as a

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result of a decision to incorporate additional learnings from existing operations at Foster Creek and related scope changes. Final capital efficiencies for the expansion will be dependent on SOR performance, costs associated with optimization activity, and debottlenecking, which is expected to increase production capacity and improve operating efficiency.

·Phase G is 73% complete with initial production expected in 2015. Phase H is 48% complete with first production expected in 2016.

·Capital investment was $209 million, an increase of 11% compared with the same period in 2013. The increase was primarily directed to phase F well pad construction and phase F start-up.

Narrows Lake

·Work on phase A was 25% complete at the end of the quarter and site construction, engineering and procurement are progressing.

·The first phase of the project is designed to have production capacity of 45,000  bbls/d gross. 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 $45 million at Narrows Lake in the second quarter, compared with $25 million in the same period a year earlier.

Emerging projects

Grand Rapids

·Cenovus received regulatory approval for its 100%-owned Grand Rapids project in the first quarter of 2014. The project, which is located within the Greater Pelican Region, is expected to produce up to 180,000 bbls/d.

·Cenovus is moving forward with phase A, which is expected to produce between 8,000 and 10,000 bbls/d. The company has begun decommissioning an existing SAGD central plant facility that it purchased earlier this year and plans to relocate it to the Grand Rapids site for use at phase A.

·Work continues on the SAGD pilot project, which has two producing well pairs.

·Excluding the central plant purchase, Cenovus invested $5 million at Grand Rapids in the second quarter, compared with $8 million in the same period a year earlier.

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 half of 2014.

·In 2013, Cenovus successfully concluded 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. Approximately 70% of the top water was removed during the pilot and replaced with compressed air. While dewatering is not essential to the development of Telephone Lake, the company believes it could help improve the SOR by up to 30%, which would enhance project economics and reduce its impact on the environment.

·Cenovus invested $19 million at Telephone Lake in the second quarter, compared with $17 million in the same period a year ago. The company plans to drill 13

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stratigraphic test wells at Telephone Lake this summer using Cenovus’s SkyStratTM drilling rig.

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. Cenovus has been injecting polymer since 2006 to enhance production from the reservoir, which is also under waterflood.

·Pelican Lake produced an average of 24,806 bbls/d in the quarter, up 4% from the same period a year earlier as additional infill wells came on production and there was increased response from the polymer flood program.

·Cenovus invested $68 million at Pelican Lake in the second quarter, compared with $111 million in the same period a year earlier. Pelican Lake generated $51 million in operating cash flow in excess of capital investment in the second quarter.

·Operating costs at Pelican Lake were $21.23/bbl in the quarter, down from $22.21/bbl in 2013. The decrease was primarily due to higher production volumes and lower workover costs.

Other conventional oil

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

·Conventional oil production, excluding Pelican Lake, averaged 52,055 bbls/d in the second quarter, a decline of 2% from the same period a year earlier. The decrease primarily reflects production associated with the sale of the company’s Shaunavon assets in 2013 and certain of its Bakken assets earlier in the second quarter of this year.

·The transaction to sell the company’s operated Bakken assets closed on April 1,  2014, with a gain of $16 million recorded on the sale. Cenovus retained a royalty interest in production from these assets as they are on Cenovus fee title lands.

·Solid operational performance from the company’s horizontal drilling program in southern Alberta more than offset expected natural declines in production.

·Production at the Weyburn operation was about 16,485 bbls/d net compared with approximately 15,938 bbls/d net in the second quarter of 2013.

·Operating costs for Cenovus’s conventional oil operations, excluding Pelican Lake, were $17.75/bbl, a 9% increase compared with the same period in 2013 due to higher chemical, workforce, repairs and maintenance expenses, partially offset by a decline in electricity costs.

·Cenovus invested $81 million in its conventional oil assets, excluding Pelican Lake, in the second quarter, compared with $130 million a year earlier, due to a decrease in facility spending. These assets generated $188 million of operating cash flow in excess of capital investment in the second quarter.

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Natural Gas

Daily production

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

Cenovus has a solid base of established, reliable natural gas properties in Alberta. These properties are managed as financial assets, not production assets, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as an economic hedge against price fluctuations because natural gas fuels the company’s oil sands and refining operations.

·Natural gas production averaged 507 million cubic feet per day (MMcf/d) in the second quarter, down 5% compared with the same period a year earlier, driven by expected natural declines.

·The company invested $5 million in its natural gas assets in the second quarter, consistent with the same period a year earlier. Natural gas assets generated $157  million in operating cash flow in excess of capital investment.

·Cenovus’s average realized sales price for natural gas, including hedges, was $4.85  per thousand cubic feet (Mcf), compared with $3.68 per Mcf in the same quarter of 2013. Higher cash flow from natural gas more than offset the increase in fuel costs at Cenovus’s oil sands operations as the company produced more natural gas than it consumed.

Market access

Cenovus is concentrating on finding new customers in North America and around the world and working to ensure it has the ability to move its oil to these customers.

·Cenovus loaded its first unit train at the U.S. Development Group/Gibson Hardisty rail terminal during the second quarter. The company also has a multi-year agreement for unit train loading services at the Canexus Bruderheim rail terminal. In total, Cenovus completed eight unit train deliveries in the first half of the year. The company remains on track to reach 30,000 bbls/d of rail loading capacity by the end of 2014.

·Through their oil sands partnership, Cenovus and ConocoPhillips have a transportation agreement in place with Inter Pipeline (IPL) to receive up to 350,000  bbls/d of diluent via the new Polaris East pipeline. Deliveries on the Polaris line commenced at Foster Creek in July and are anticipated to begin at Christina Lake in September. These deliveries are expected to increase over the next few years as the company’s diluent needs grow. The agreement also includes future diluent deliveries to the Narrows Lake project.

·The partnership also has an agreement in place with IPL to ship up to 500,000 bbls/d of oil blend via the planned Cold Lake pipeline expansion. Oil blend deliveries on the Cold Lake expansion are expected to commence in early 2015. The agreement also includes future oil blend shipping capacity from the partnership’s Narrows Lake project.

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·Cenovus has committed to ship 75,000 bbls/d on Enbridge’s Flanagan South system and expects to start moving an initial 50,000 bbls/d in the second half of 2014.

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

Refining

Cenovus’s refining operations allow the company to capture value from crude oil production through to refined products such as diesel, gasoline and jet fuel. This integrated strategy provides a natural economic hedge 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.

Financial

·Operating cash flow from refining was $219 million in the second quarter, a 32% decline when compared with the second quarter of 2013, due to lower market crack spreads and higher heavy crude oil feedstock costs reflecting increased prices for Western Canadian Select and increased operating expenses.

·Capital investment was $46 million, up from $26 million in the same period a year earlier. Increased capital expenditures were related to planned maintenance and reliability and safety projects.

·Cenovus’s refining operating cash flow is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, Cenovus’s operating cash flow from refining would have been approximately $31 million lower.

Operations

·Cenovus’s refineries processed an average of 466,000 bbls/d gross in the quarter, a 6% increase from the same period a year earlier due to reliable refinery performance and an unplanned outage in 2013.

·Together, the two refineries processed an average of 221,000 bbls/d gross of heavy oil in the quarter, compared with 230,000 bbls/d gross in the same period of 2013.

·The refineries produced an average of 489,000 bbls/d gross of refined products in the quarter, a 7% increase from the second quarter of 2013.

Financial

Dividend

The Cenovus Board of Directors declared a third quarter dividend of $0.2662 per share, payable on September 30, 2014 to common shareholders of record as of September 15,  2014. Based on the July 29, 2014 closing share price on the Toronto Stock Exchange of $32.81, 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 its strategy to focus on increasing total shareholder return.

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Cash flow, earnings and capital investment

·Cenovus generated almost $1.2 billion in cash flow in the second quarter, 37% higher than the same period a year earlier due to increased oil production and higher oil and natural gas prices, plus decreases in current tax, financing costs and pre-exploration expense. Current tax was $68 million lower than in the second quarter of 2013 due to a favourable adjustment related to previous years and lower U.S. cash flow. This was partially offset by higher Canadian cash flow. Cenovus had a non-recurring pre-exploration expense in the second quarter of 2013 that reduced cash flow.

·Operating cash flow was nearly $1.3 billion in the second quarter of 2014, a 15% increase from the same period a year earlier.

·Operating cash flow from Cenovus’s refineries was $219 million, a 32% decline from the same period in 2013 due to increased heavy crude oil feedstock costs and lower market crack spreads that reduced margins. The strong crude oil prices benefited Cenovus’s oil and natural gas producing assets, which generated approximately $1.1  billion of operating cash flow, a 34% increase compared with the second quarter of 2013.

·Operating cash flow in excess of capital invested was $48 million from oil sands crude oil, $239 million from conventional oil, $157 million from natural gas and $173  million from refining.

·Operating earnings were $473 million in the second quarter, an 85% increase when compared with the same period a year earlier due to an increase in oil and natural gas prices and oil production volumes and a decrease in exploration expense. This was partially offset by an increase in deferred income tax mainly because of higher Canadian income as well as higher long-term incentive expense that is consistent with a rise in the company’s share price.

·Cenovus’s net earnings for the quarter were $615 million, more than three times higher than the same period a year earlier. The increase was primarily due to higher operating earnings and a non-operating unrealized foreign exchange gain of $177  million compared with a loss of $97 million a year ago. This was partially offset by an $11 million unrealized risk management loss compared with a gain of $26  million in 2013.

·Capital investment was $686 million in the second quarter, a 3% decline when compared with the same period a year earlier, primarily due to planned reduced spending at Pelican Lake and the company’s other conventional operations.

Risk management, G&A expenses and financial ratios

·In the second quarter, Cenovus increased its fixed-price Canadian dollar Brent crude hedge position, adding 14,500 bbls/d of additional protection for expected 2015 oil production at an average price of $113.64/bbl. This increased fixed-price protection for expected 2015 oil production to 18,000 bbls/d at an average price of $113.75.

·Cenovus also added Canadian dollar hedges for 10,000 bbls/d of expected 2015 oil production using Brent collars, establishing a floor price at an average of $105.25/bbl with an average ceiling price of $123.57/bbl.

·Cenovus had a realized after-tax hedging loss of $41 million in the quarter. The company received an average realized price, including hedging, of $78.39/bbl for its oil. The average realized price for natural gas, including hedging, was $4.85/Mcf.

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·General and administrative (G&A) expenses were $3.98 per barrel of oil equivalent (BOE) in the second quarter, compared with $3.54/BOE in the second quarter of 2013 due to higher long-term incentives resulting from an increase in the company’s share price versus a decline in the same period of 2013.

·Cenovus filed a new $1.5 billion debt shelf prospectus and a new US$2 billion U.S. debt shelf prospectus to replace the previously filed prospectuses. These filings are normal course of business and were completed in order to provide flexibility and maintain efficient access to the debt capital markets.

·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 June 30, 2014, the company’s debt to capitalization ratio was 33% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.2 times.

Operating earnings1

(for the period ended June 30) ($ millions, except per share amounts)	2014Q2		2013Q2
Earnings, before income tax	824		280
Add back (deduct):
Unrealized risk management (gains) losses2	11		(26	)
Non-operating unrealized foreign exchange (gains) losses3	(177	)	97
(Gains) losses on divestiture of assets	(20	)	—
Operating earnings, before income tax	638		351
Income tax expense	165		96
Operating earnings	473		255

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

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

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“we”, “our”, “us”, “its”, “Cenovus”, or the “Company”) dated July 29, 2014, should be read in conjunction with our June 30, 2014 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2013 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2013 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of July 29, 2014, unless otherwise indicated. This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The interim MD&As are approved by the Audit Committee of the Cenovus Board of Directors (the “Board”) and the annual MD&A is reviewed by the Audit Committee and recommended for approval by the Board. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at www.sedar.com, EDGAR at www.sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

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

Non-GAAP Measures

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

OVERVIEW OF CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares trading on the Toronto and New York stock exchanges. On June 30, 2014, we had a market capitalization of approximately $26 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “crude oil”) production in the first six months of 2014 was in excess of 199,000 barrels per day and our average natural gas production was 492 MMcf per day. Our refineries processed an average of 433,000 gross barrels per day of crude oil feedstock into an average of 458,000 gross barrels per day of refined products.

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.

We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek, Christina Lake, Narrows Lake, Telephone Lake, Grand Rapids and our conventional 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 through our annual stratigraphic test well drilling program.

We plan to increase our annual net crude oil production, including our conventional oil operations, to more than 500,000 barrels per day. We anticipate the capital investment necessary to achieve this production level will 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 business plan in a safe, predictable and reliable way, leveraging the strong foundation we have built to date.

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Oil Sands

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

	Six Months Ended June 30, 2014
	Ownership Interest (percent)	NetProduction Volumes(bbls/d)	Gross Production Volumes (bbls/d)
Existing Projects
Foster Creek	50	55,785	111,570
Christina Lake	50	66,863	133,726
Narrows Lake	50	—	—
Emerging Projects
Telephone Lake	100	—	—
Grand Rapids	100	—	—

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated U.S. public company. They are located in the Athabasca region of northeastern Alberta.

Conventional

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

	Six Months Ended June 30, 2014
($ millions)	Crude Oil (1)	Natural Gas
Operating Cash Flow (2)	735	275
Capital Investment	412	11
Operating Cash Flow Net of Related Capital Investment	323	264

(1)Includes NGLs.

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

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

Approximately 70 percent, or 4.5 million net acres, of our conventional land is owned in fee title, which means we own the mineral rights. Where we have working interest production from fee lands, we do not pay a third party royalty, rather we pay mineral tax to the government which is generally lower than royalties paid to mineral interest owners. In addition, a portion of our fee lands are leased to third parties which may give rise to royalty income. Approximately 50 percent of our total conventional production comes from our fee lands.

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.

	Ownership Interest (percent)	2014 Gross Nameplate Capacity (Mbbls/d)
Wood River	50	314
Borger	50	146

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

($ millions)	Six Months Ended June 30,  2014
Operating Cash Flow (1)	465
Capital Investment	69
Operating Cash Flow Net of Related Capital Investment	396

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

Cenovus Energy Inc.	12
Second Quarter 2014 Report	Management’s Discussion and Analysis

Technology and Environment

Technology development, research activities and the environment are playing increasingly larger roles in all aspects of our business. We continue to seek out new technologies and are actively developing our own technology with the goals of increasing recoveries from our reservoirs, while reducing the amount of water, natural gas and electricity consumed in our operations, potentially reducing costs and minimizing our environmental disturbance. The Cenovus culture fosters the pursuit of new ideas and new approaches. We have a track record of developing innovative solutions that unlock challenging crude oil resources and builds 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. In the first and second quarters of 2014, we paid a dividend of $0.2662 per share, a 10 percent increase from 2013.

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 believe that our goal of doubling our December 2009 net asset value by the end of 2015 is an achievable target.

QUARTERLY OPERATING AND FINANCIAL HIGHLIGHTS

Our results continue to reflect the strength of our integrated approach. In the second quarter, higher upstream Operating Cash Flow was partially offset by lower Operating Cash Flow from Refining and Marketing. Upstream Operating Cash Flow increased 34 percent compared to 2013 due to higher sales prices for crude oil blend and natural gas, as well as increased crude oil production. Crude oil sales prices increased 17 percent mainly due to the 11 percent increase in the Western Canadian Select (“WCS”) benchmark price and the weakening of the Canadian dollar. The rise in WCS to US$82.95 per barrel (2013 — US$75.06 per barrel) increased the cost of our heavy crude oil feedstock which, along with declines in market crack spreads, resulted in a 32 percent decrease in Operating Cash Flow from our refining operations.

Operational Results for the Second Quarter of 2014 Compared With the Second Quarter of 2013

Total crude oil production in the second quarter averaged 201,688 barrels per day, up 18 percent from 2013.

In the second quarter, crude oil production from our Oil Sands segment averaged 124,827 barrels per day, an increase of 33 percent, primarily driven by higher production at Christina Lake. Average production at Christina Lake was 67,975 barrels per day, a 77 percent increase, as phase E reached nameplate production capacity in the second quarter of 2014.

Foster Creek production averaged 56,852 barrels per day, up three percent and in line with our expectations.

Our Conventional crude oil production averaged 76,861 barrels per day, a slight decline from 2013. The increase in production from successful horizontal well performance in southern Alberta and higher production at Pelican Lake was offset by expected natural declines and the sale of our Lower Shaunavon and Bakken assets in July 2013 and April 2014, respectively. Pelican Lake production averaged 24,806 barrels per day, an increase of four percent, resulting from additional infill wells coming on-stream and an increased response from the polymer flood program.

Our refineries processed an average of 466,000 gross barrels per day (2013 — 439,000 gross barrels per day) of crude oil, of which 221,000 gross barrels per day (2013 — 230,000 gross barrels per day) was heavy crude oil. As a result of the optimization of our total crude input slate, there was a decrease in heavy crude oil processed. We produced 489,000 gross barrels per day of refined products, an increase of 32,000 gross barrels per day, or seven percent, as a result of reliable refinery performance in 2014 as compared to an unplanned hydrocracker outage in 2013 and the timing of planned turnarounds and maintenance. The 2014 Borger planned turnaround was completed in the first quarter of 2014 and the 2013 turnaround was completed in the second quarter.

Other significant operational results in the second quarter of 2014 include:

·Commencing circulation steaming at Foster Creek phase F;

·Completing a planned turnaround at Christina Lake phases A and B with minimal impact to production;

·Receiving anticipated regulatory approval for expansion of the Foster Creek development area;

·Closing of the disposition of certain of our Bakken assets for proceeds of $36 million before closing adjustments; and

·Transporting approximately 5,500 barrels per day of crude oil by rail to the U.S., including five unit train shipments.

Cenovus Energy Inc.	13
Second Quarter 2014 Report	Management’s Discussion and Analysis

Financial Results for the Second Quarter of 2014 Compared With the Second Quarter of 2013

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

Financial highlights for the second quarter of 2014 compared with 2013 include:

Revenues

Revenues of $5,422 million, increasing $906 million or 20 percent as a result of:

·Refining and Marketing revenues increasing $405 million primarily due to the weakening of the Canadian dollar and higher refined product output, partially offset by the decline in refined product prices, consistent with the decrease in Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices, and an increase in revenues from third-party sales of crude oil and natural gas;

·Higher sales prices for crude oil blend and natural gas, consistent with the rise in the WCS and AECO benchmark prices; and

·An increase in blended crude oil sales volumes, consistent with higher production volumes.

Operating Cash Flow

In the second quarter, Operating Cash Flow was $1,296 million, an increase of $171 million. Upstream Operating Cash Flow increased 34 percent, to $1,076 million, due to increasing crude oil and natural gas sales prices and higher crude oil sales volumes, partially offset by realized risk management losses compared to gains in 2013, higher royalties and a rise in operating costs. Operating costs increased primarily due to a rise in fuel costs, consistent with the increase in the AECO benchmark price. While higher natural gas prices increased our operating costs, overall the rise in natural gas pricing had a positive impact on Operating Cash Flow as we produced more natural gas than we used.

Increases in upstream Operating Cash Flow were partially offset by lower Operating Cash Flow from our Refining and Marketing segment, which decreased 32 percent to $220 million. The decrease was primarily due to lower market crack spreads, higher heavy crude oil feedstock costs, and increased operating costs partially related to an increase in natural gas prices, offset by an increase in refined product output. The Chicago and Midwest Combined (“Group 3”) 3-2-1 market crack spreads decreased by approximately US$10 per barrel or 35 percent.

Cash Flow

Cash Flow increased $318 million to $1,189 million, primarily due to changes discussed above in Operating Cash Flow, a decrease in current income tax and no pre-exploration expense in 2014.

Operating Earnings

Operating Earnings increased $218 million, or 85 percent, to $473 million. The increase was primarily due to higher Cash Flow discussed above and lower exploration expense, partially offset by increased deferred income tax related to operating earnings, and higher non-cash long-term incentive expense.

Cenovus Energy Inc.	14
Second Quarter 2014 Report	Management’s Discussion and Analysis

Net Earnings

Net Earnings increased $436 million, to $615 million, primarily due to changes in Operating Earnings discussed above and non-operating unrealized foreign exchange gains on long-term debt and the Partnership Contribution Receivable of $177 million compared with losses of $97 million in 2013.

Capital Investment

Capital investment was $686 million, with most of our spend occurring at our oil sands assets. We continue to focus on the development of our expansion phases at Foster Creek and Christina Lake, and construction at Narrows Lake.

OPERATING RESULTS

Crude Oil Production Volumes

	Three Months Ended June 30,				Six Months Ended June 30,
(barrels per day)	2014	Percent Change		2013	2014	Percent Change		2013
Oil Sands
Foster Creek	56,852	3	%	55,338	55,785	—	%	55,665
Christina Lake	67,975	77	%	38,459	66,863	62	%	41,388
	124,827	33	%	93,797	122,648	26	%	97,053
Conventional
Pelican Lake	24,806	4	%	23,959	24,794	4	%	23,824
Other Heavy Oil	15,498	(5)	%	16,284	15,756	(4)	%	16,497
Total Heavy Oil	40,304	—	%	40,243	40,550	1	%	40,321
Light & Medium Oil	35,329	(2)	%	36,137	34,966	(6)	%	37,317
NGLs (1)	1,228	29	%	950	1,121	17	%	961
	76,861	(1)	%	77,330	76,637	(2)	%	78,599
Total Crude Oil Production	201,688	18	%	171,127	199,285	13	%	175,652

(1)NGLs include condensate volumes.

Our crude oil production has increased in 2014, driven by higher production at Christina Lake as a result of phase E reaching nameplate production capacity in the second quarter of 2014. Phase E started producing in July 2013. The ramp up of phase E proceeded similarly to the ramp up of phases C and D, approaching nameplate capacity within six to nine months of first production. In the second quarter of 2014, a planned turnaround was completed at Christina Lake phases A and B. There was minimal impact to production as volumes from phases A and B were processed through the phase C, D and E plant. In the second quarter of 2013, we completed our first major planned turnaround at Christina Lake.

Cenovus Energy Inc.	15
Second Quarter 2014 Report	Management’s Discussion and Analysis

Foster Creek is operating as expected. We are on track with our plan to optimize steam placement and continue to closely monitor conditions in the reservoir to track steam movement between well pads. We are also working to improve how steam moves along individual wells through the use of new operating techniques. Circulation steaming of phase F commenced in the quarter. We expect first production from phase F in the fourth quarter of 2014, with ramp up to design capacity expected to take twelve to eighteen months.

Our Conventional crude oil production decreased slightly in the quarter and for the first half of the year. Increased production from successful horizontal well performance in southern Alberta and higher production at Pelican Lake, was offset by expected natural declines and the divestiture of our Lower Shaunavon and Bakken assets. Lower Shaunavon produced an average of 3,592 barrels per day in the second quarter of 2013 and 4,236 barrels per day in the first six months of 2013. Prior to the sale, crude oil production from these Bakken assets was 396 barrels per day in the first quarter of 2014 (Q2 2013 — 618 barrels per day and for the six months ended June 30, 2013 — 695 barrels per day). Pelican Lake production averaged 24,806 barrels per day, an increase of four percent, resulting from additional infill wells coming on-stream and an increased response from the polymer flood program.

Natural Gas Production Volumes

	Three Months Ended June 30,		Six Months Ended June 30,
(MMcf per day)	2014	2013	2014	2013
Conventional	484	514	471	520
Oil Sands	23	22	21	20
	507	536	492	540

In 2014, our natural gas production declined as expected. We continue to focus natural gas capital investment on high rate of return projects and directing the majority of our total capital investment to our crude oil properties.

Operating Netbacks

	Three Months Ended June 30,							Six Months Ended June 30,
	Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)				Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)
	2014		2013	2014		2013		2014		2013	2014		2013
Price (2)	81.33		69.61	4.87		3.50		77.29		61.55	4.68		3.38
Royalties	7.41		5.03	0.09		0.04		6.59		4.19	0.08		0.05
Transportation and Blending (2)	3.20		2.55	0.11		0.08		2.90		2.69	0.11		0.12
Operating Expenses	16.77		17.24	1.23		1.16		17.36		16.18	1.24		1.15
Production and Mineral Taxes	0.60		0.61	0.13		(0.01	)	0.51		0.58	0.06		0.01
Netback Excluding Realized Risk Management	53.35		44.18	3.31		2.23		49.93		37.91	3.19		2.05
Realized Risk Management Gain (Loss)	(2.94	)	0.72	(0.02	)	0.18		(2.48	)	1.71	(0.01	)	0.28
Netback Including Realized Risk Management	50.41		44.90	3.29		2.41		47.45		39.62	3.18		2.33

(1)Includes NGLs.

(2)The crude oil price and transportation and blending cost excludes the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate in the second quarter was $32.94 per barrel (2013 — $27.83 per barrel) and in the six months ended June 30, 2014 was $33.73 per barrel (2013 — $29.52 per barrel).

In 2014, our average crude oil netback, excluding realized risk management gains and losses, increased primarily due to higher sales prices, consistent with the strengthening of the West Texas Intermediate (“WTI”) and WCS benchmark prices and the weakening of the Canadian dollar.

In 2014, our average natural gas netback, excluding realized risk management gains and losses, increased primarily 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 June 30,				Six Months Ended June 30,
	2014	Percent Change		2013	2014	Percent Change		2013
Crude Oil Runs (Mbbls/d)	466	6	%	439	433	1	%	428
Heavy Oil	221	(4)	%	230	208	(3)	%	214
Refined Products (Mbbls/d)	489	7	%	457	458	2	%	448
Crude Utilization (percent)	101	5	%	96	94	—	%	94

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

In the quarter, reliable refinery performance resulted in increased crude oil runs and refined product output as compared to 2013. In 2013, our refinery operations were negatively impacted by an unplanned hydrocracker outage. In addition, the timing of planned turnaround and maintenance activities at Borger impacted refined product output, as the 2013 planned turnaround was completed in the second quarter compared to the completion of the 2014 turnaround in the first quarter.

Cenovus Energy Inc.	16
Second Quarter 2014 Report	Management’s Discussion and Analysis

In the first half of the year, our crude oil runs and refined product output increased slightly when compared to the prior year. Reliable refinery performance in the second quarter of 2014 offset the negative impact of the unplanned hydrocracker outage in 2013. Crude utilization remained consistent as a result of the increase in our 2014 refinery capacity.

In 2014, the decrease in heavy oil processed reflected 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.

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)

	Six Months Ended June 30,
	2014		2013		Q2 2014		Q1 2014		Q2 2013
Crude Oil Prices (US$/bbl)
Brent
Average	108.83		108.00		109.77		107.90		103.35
End of Period	112.36		102.16		112.36		107.76		102.16
WTI
Average	100.84		94.30		102.99		98.68		94.22
End of Period	105.37		96.56		105.37		101.58		96.56
Average Differential Brent-WTI	7.99		13.70		6.78		9.22		9.13
WCS (2)
Average	79.25		68.74		82.95		75.55		75.06
End of Period	83.18		82.16		83.18		80.71		82.16
Average Differential WTI-WCS	21.59		25.56		20.04		23.13		19.16
Condensate (C5 @ Edmonton) Average	103.90		104.37		105.15		102.64		101.50
Average Differential WTI-Condensate (Premium)/Discount	(3.06	)	(10.07	)	(2.16	)	(3.96	)	(7.28	)
Average Differential WCS-Condensate (Premium)/Discount	(24.65	)	(35.63	)	(22.20	)	(27.09	)	(26.44	)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)	117.51		121.15		121.98		113.04		124.28
Chicago Ultra-low Sulphur Diesel (“ULSD”)	125.09		128.22		124.34		125.83		126.97
Refining 3-2-1 WTI Average Crack Spreads (US$/bbl)
Chicago	19.13		29.30		19.72		18.55		31.06
Group 3	17.58		27.59		17.75		17.41		27.24
Natural Gas Average Prices
AECO ($/Mcf)	4.72		3.33		4.67		4.76		3.59
NYMEX (US$/Mcf)	4.80		3.71		4.67		4.94		4.09
Basis Differential NYMEX-AECO (US$/Mcf)	0.50		0.42		0.40		0.60		0.56
Foreign Exchange Rate (US$ per C$1)
Average	0.912		0.984		0.917		0.906		0.977

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

(2)The Canadian dollar average WCS benchmark price for the second quarter of 2014 was $90.46 per barrel (2013 — $76.83 per barrel) and for the six months ended June 30, 2014 was $86.90 per barrel (2013 — $69.86 per barrel).

Crude Oil Benchmarks

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland refined product prices. The average price of Brent crude oil increased by US$6.42 per barrel for the three months ended June 30, 2014 compared to 2013. Higher prices were driven by unrest in Iraq resulting in increased risk to Iraqi oil supply and infrastructure. On a year-to-date basis, the average price of Brent crude oil increased by US$0.83 per barrel. Higher prices due to unrest in Iraq were offset by weakness in the first quarter of 2014 as a result of declines in the U.S. economy from adverse weather conditions, economic uncertainty in China and the potential return of Iranian and Libyan production to the global market. In 2013, Brent crude oil prices rose in the first part of the year as a result of global economic optimism. That optimism was later offset by significant North American crude oil supply increases.

Cenovus Energy Inc.	17
Second Quarter 2014 Report	Management’s Discussion and Analysis

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 discount between WTI and Brent narrowed in 2014 as new pipeline infrastructure from the Cushing, Oklahoma area to the U.S. Gulf Coast relieved congestion that developed in the first half of 2013. New pipeline infrastructure allowed inland production greater access to U.S. Gulf Coast refineries and reduced the discount applied to the WTI benchmark price. The 2013 congestion resulted from the rapid growth in U.S. inland supply.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WTI-WCS average differential widened by US$0.88 per barrel in the three months ended June 30, 2014 compared to last year. This was primarily due to stronger WTI prices resulting from U.S. Gulf Coast refineries having greater access to inland production, as described above. On a year-to-date basis, the differential narrowed by US$3.97 per barrel. This was primarily due to increased Canadian heavy crude oil volumes shipped by rail, providing access to more Canadian and U.S. markets; and higher utilization of existing pipelines and new pipeline capacity, allowing growing Alberta crude oil production improved access to U.S. refineries.

Blending condensate with bitumen and heavy oil enables our production to be transported. Our blending ratios range from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. As the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices are driven by U.S. Gulf Coast condensate prices plus the value attributed to transporting the condensate to Edmonton. Edmonton based condensate prices increased by US$3.65 per barrel in the quarter compared to 2013 due to increased condensate sales to global markets reducing the supply of condensate available in North America, partially offset by additional pipeline capacity to Edmonton. On a year-to-date basis, condensate prices decreased as a result of more pipeline capacity from the U.S. Gulf Coast to Western Canada. The WCS-Condensate differential narrowed in 2014 compared to 2013 primarily due to the increase in the WCS benchmark price as Canadian congestion issues were resolved.

Refining Benchmarks

The Chicago RUL and Chicago ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1 Crack Spread. The 3-2-1 WTI crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based crude oil feedstock prices and valued on a last in, first out accounting basis. Average inland refined product prices declined in 2014 as a result of increased inland refinery utilization, creating additional supply and decreasing the premium over the Brent crude oil benchmark price. Average market crack spreads in the U.S. inland Chicago and Group 3 markets fell in 2014 compared with 2013 primarily due to the strengthening of WTI prices as inland crude oil congestion issues were addressed (as noted above), a reduction in refinery outages in 2014, and a decline in refined product prices.

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 valued on a first in, first out accounting basis.

Cenovus Energy Inc.	18
Second Quarter 2014 Report	Management’s Discussion and Analysis

Other Benchmarks

Average natural gas prices increased in 2014 compared to the prior year due to an abnormally cold winter leading to large draws of natural gas and the subsequent need for larger than normal injections of natural gas into storage.

A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on all of our revenues as the sales prices of our crude oil and natural gas are determined directly in US$ or by reference to US$ benchmarks. In addition, our refining results are in U.S. dollars and therefore a weakened Canadian dollar improves our reported results, although a weaker Canadian dollar also increases our current period’s reported refining capital investment and results in unrealized foreign exchange losses on our U.S. dollar denominated debt. In the three and six months ended June 30, 2014, the Canadian dollar weakened relative to the U.S. dollar by $0.06 or six percent, and $0.07 or seven percent, respectively. The Canadian dollar weakened due to narrowing of U.S./Canadian interest differentials, as U.S. interest rates rose, while Canadian interest rates increased only slightly as a result of a shift in the Bank of Canada’s concern from inflation to deflation risks. The weakening of the Canadian dollar in 2014 as compared with 2013 increased our year-to-date revenues by US$750 million.

FINANCIAL RESULTS

Selected Consolidated Financial Results

For an understanding of the trends and events that impacted our financial results, the following discussion should be read in conjunction with our 2013 annual MD&A and our March 31, 2014 MD&A. The following key performance indicators are discussed in more detail within this section.

($ millions, except per share	Six Months Ended June 30,		2014		2013					2012
amounts)	2014	2013	Q2	Q1	Q4		Q3	Q2	Q1	Q4		Q3	Q2
Revenues	10,434	8,835	5,422	5,012	4,747		5,075	4,516	4,319	3,724		4,340	4,214
Operating Cash Flow (1) (2)	2,465	2,339	1,296	1,169	976		1,153	1,125	1,214	966		1,314	1,081
Cash Flow (1)	2,093	1,842	1,189	904	835		932	871	971	697		1,117	925
Per Share — Diluted	2.76	2.43	1.57	1.19	1.10		1.23	1.15	1.28	0.92		1.47	1.22
Operating Earnings (Loss) (1)	851	646	473	378	212		313	255	391	(188	)	432	284
Per Share — Diluted	1.12	0.85	0.62	0.50	0.28		0.41	0.34	0.52	(0.25	)	0.57	0.37
Net Earnings (Loss)	862	350	615	247	(58	)	370	179	171	(117	)	289	397
Per Share — Basic	1.14	0.46	0.81	0.33	(0.08	)	0.49	0.24	0.23	(0.15	)	0.38	0.53
Per Share — Diluted	1.14	0.46	0.81	0.33	(0.08	)	0.49	0.24	0.23	(0.15	)	0.38	0.52
Capital Investment (3)	1,515	1,621	686	829	898		743	706	915	978		830	660
Cash Dividends	403	367	201	202	183		182	183	184	167		166	166
Per Share	0.5324	0.484	0.2662	0.2662	0.242		0.242	0.242	0.242	0.22		0.22	0.22

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

(2)Research activities included in operating expense in prior periods were reclassified to conform to the presentation adopted for the year ended December 31, 2013. This increased Operating Cash Flow in prior periods.

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

Revenues

In the second quarter, revenues increased $906 million or 20 percent compared with 2013. On a year-to-date basis, revenues increased $1,599 million or 18 percent compared with 2013.

($ millions)	Three Months Ended		Six Months  Ended
Revenues for the Periods Ended June 30, 2013	4,516		8,835
Increase (Decrease) due to:
Oil Sands	456		827
Conventional	133		262
Refining and Marketing	405		717
Corporate and Eliminations	(88	)	(207	)
Revenues for the Periods Ended June 30, 2014	5,422		10,434

Upstream revenues, which includes Oil Sands and Conventional, rose in the quarter and year to date by 38 percent and 36 percent, respectively. The increases were primarily due to rising sales prices for crude oil blend and natural gas, and higher blended crude oil sales volumes, partially offset by increased royalties and lower natural gas production.

Cenovus Energy Inc.	19
Second Quarter 2014 Report	Management’s Discussion and Analysis

Revenues for the three and six months ended June 30, 2014 generated by our Refining and Marketing segment increased 13 percent and 12 percent, respectively. Increases due to the weakening of the Canadian dollar and higher refined product output were partially offset by declines in refined product prices. Revenues from third party sales undertaken by the marketing group also rose, primarily due to higher blended crude oil and natural gas sales prices and an increase in purchased crude oil volumes.

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

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

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.

Operating Cash Flow

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014	2013		2014	2013
Revenues	5,640	4,646		10,893	9,087
(Add) Deduct:
Purchased Product	3,098	2,616		5,918	4,893
Transportation and Blending	655	460		1,308	1,018
Operating Expenses	519	456		1,093	896
Production and Mineral Taxes	17	9		24	19
Realized (Gain) Loss on Risk Management Activities	55	(20	)	85	(78	)
Operating Cash Flow	1,296	1,125		2,465	2,339

Three Months Ended June 30, 2014 Compared With June 30, 2013

As highlighted in the graph below, our Operating Cash Flow increased 15 percent in the second quarter primarily due to higher upstream revenues resulting from:

·A 17 percent increase in our average crude oil sales price to $81.33 per barrel and a 39 percent increase in our average natural gas sales price to $4.87 per Mcf; and

·An increase in our crude oil sales volumes by 20 percent.

The increases were partially offset by:

·A decline in Operating Cash Flow from Refining and Marketing of $104 million primarily due to lower market crack spreads and higher heavy crude oil feedstock costs, partially offset by an increase in refined product output;

·Realized risk management losses before tax, excluding Refining and Marketing, of $55 million compared with gains of $24 million in 2013;

·An increase in royalties expense, primarily due to the increase in crude oil sales prices; and

·Higher crude oil operating expenses of $37 million, primarily due to higher fuel costs. On a per barrel basis, crude oil operating costs decreased by $0.47 to $16.77 per barrel, due to the substantial increase in production at Christina Lake, partially offset by an increase of $0.94 per barrel in fuel costs, primarily related to an increase in natural gas prices.

Cenovus Energy Inc.	20
Second Quarter 2014 Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2014 Compared With June 30, 2013

As highlighted in the graph below, our Operating Cash Flow increased five percent in the first six months of 2014 primarily due to higher upstream revenues resulting from:

·A 26 percent increase in our average crude oil sales price to $77.29 per barrel and a 38 percent increase in our average natural gas sales price to $4.68 per Mcf; and

·An increase in our crude oil sales volumes by 13 percent.

The increases were partially offset by:

·A decline in Operating Cash Flow from Refining and Marketing of $388 million primarily due to lower market crack spreads and higher heavy crude oil feedstock costs, partially offset by higher refined product output;

·Realized risk management losses before tax, excluding Refining and Marketing, of $90 million compared with gains of $86 million in 2013;

·Higher royalties expense, primarily due to the increase in crude oil sales prices; and

·An increase in crude oil operating expenses of $105 million, primarily due to a rise in fuel costs consistent with the increase in the AECO natural gas price. The impact of rising natural gas prices on our operating expenses was offset by the increase in natural gas revenues, as we produced more natural gas than we used. On a per barrel basis, crude oil operating costs increased by $1.18 to $17.36 per barrel, with an increase of $1.14 per barrel in fuel costs, primarily related to an increase in natural gas prices.

Cenovus Energy Inc.	21
Second Quarter 2014 Report	Management’s Discussion and Analysis

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 June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
Cash From Operating Activities	1,109		828		1,566		1,723
(Add) Deduct:
Net Change in Other Assets and Liabilities	(27	)	(31	)	(69	)	(65	)
Net Change in Non-Cash Working Capital	(53	)	(12	)	(458	)	(54	)
Cash Flow	1,189		871		2,093		1,842

In the three and six months ended June 30, 2014, Cash Flow increased $318 million and $251 million, respectively, primarily due to:

·Higher Operating Cash Flow, as discussed above;

·A decrease in current income tax, primarily due to a favourable adjustment related to prior years, a decrease in U.S. cash flow, partially offset by an increase in Canadian cash flow; and

·A pre-exploration expense of $63 million recorded in the second quarter of 2013.

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 Earnings Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings.

	Three Months Ended June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
Earnings, Before Income Tax	824		280		1,182		574
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)	11		(26	)	(15	)	204
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)	(177	)	97		19		144
(Gain) Loss on Divestiture of Assets	(20	)	—		(20	)	—
Operating Earnings, Before Income Tax	638		351		1,166		922
Income Tax Expense	165		96		315		276
Operating Earnings	473		255		851		646

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

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

Cenovus Energy Inc.	22
Second Quarter 2014 Report	Management’s Discussion and Analysis

Operating Earnings increased $218 million in the second quarter and $205 million on a year-to-date basis, primarily due to:

·Higher Cash Flow discussed above; and

·A decrease in exploration expense related to previously capitalized E&E costs.

Increases in Operating Earnings were partially offset by:

·An increase in deferred income tax primarily as a result of higher Canadian income; and

·Higher non-cash long-term incentive expense as compared to 2013.

Net Earnings

($ millions)	Three Months Ended		Six Months Ended
Net Earnings for the Periods Ended June 30, 2013	179		350
Increase (Decrease) due to:
Operating Cash Flow (1)	171		126
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)	(37	)	219
Unrealized Foreign Exchange Gain (Loss)	265		172
Gain (Loss) on Divestiture of Assets	20		20
Expenses (2)	23		(32	)
Depreciation, Depletion and Amortization	(6	)	(5	)
Exploration Expense	108		108
Income Tax Expense	(108	)	(96	)
Net Earnings for the Periods Ended June 30, 2014	615		862

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

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

Our Net Earnings for the three and six months ended June 30, 2014 increased by $436 million and $512 million, respectively, primarily due to the increase in Cash Flow and Operating Earnings as discussed above:

·Non-operating unrealized foreign exchange gains of $177 million in the quarter and losses of $19 million on a year-to-date basis (2013 — unrealized foreign exchange losses of $97 million and $144 million, respectively); and

·Unrealized risk management losses of $11 million in the quarter and gains of $15 million on a year-to-date basis (2013 — unrealized gains of $26 million and unrealized losses of $204 million, respectively).

Net Capital Investment

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014		2013	2014		2013
Oil Sands	471		420	998		957
Conventional	153		245	423		583
Refining and Marketing	46		26	69		51
Corporate	16		15	25		30
Capital Investment	686		706	1,515		1,621
Acquisitions	16		1	17		4
Divestitures	(39	)	—	(41	)	(1	)
Net Capital Investment (1)	663		707	1,491		1,624

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

Oil Sands capital investment in 2014 focused primarily on the development of the expansion phases at Foster Creek and Christina Lake, and the construction of phase A at Narrows Lake. Capital investment includes the drilling of 284 gross stratigraphic test wells.

In 2014, Conventional capital investment focused primarily on tight oil development, facilities work and on the expansion of the polymer flood at Pelican Lake. Spending on natural gas activities continues to be strategically focused on a small number of high return opportunities.

Our capital investment in the Refining and Marketing segment focused on capital maintenance and projects improving refinery reliability and safety in 2014.

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

Cenovus Energy Inc.	23
Second Quarter 2014 Report	Management’s Discussion and Analysis

Capital investment in our Corporate and Eliminations segment includes spending on corporate assets, such as computer equipment, leasehold improvements and office furniture.

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

Capital Investment Decisions

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

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

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

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

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 allow us to be financially resilient in times of lower cash flow.

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014	2013		2014	2013
Cash Flow (1)	1,189	871		2,093	1,842
Capital Investment (Committed and Growth)	686	706		1,515	1,621
Free Cash Flow (2)	503	165		578	221
Dividends Paid	201	183		403	367
	302	(18	)	175	(146	)

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

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

While 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 prudent use of balance sheet capacity and management of our asset portfolio.

Approximately two-thirds of our planned 2014 capital investment is for committed capital, which is used to progress approved expansions at Foster Creek and Christina Lake, construction of phase A at Narrows Lake and support existing business operations. The remaining one-third is discretionary capital for activities that include further developing our tight oil opportunities, advancing future oil sands expansions through the regulatory process and investment in technology development. Refer to the Liquidity and Capital Resources section of this MD&A for further discussion.

Cenovus Energy Inc.	24
Second Quarter 2014 Report	Management’s Discussion and Analysis

REPORTABLE SEGMENTS

Our reportable segments are as follows:

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

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

Refining and Marketing, which is 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, research costs 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 operating and reportable segments shown above reflect the change in Cenovus’s operating structure adopted for the year ended December 31, 2013; as such, prior periods have been restated. In addition, research activities previously included in operating expense have been reclassified to conform to the presentation adopted for the year ended December 31, 2013.

Revenues by Reportable Segment

	Three Months Ended June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
Oil Sands	1,301		845		2,510		1,683
Conventional	856		723		1,642		1,380
Refining and Marketing	3,483		3,078		6,741		6,024
Corporate and Eliminations	(218	)	(130	)	(459	)	(252	)
	5,422		4,516		10,434		8,835

OIL SANDS

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

Cenovus Energy Inc.	25
Second Quarter 2014 Report	Management’s Discussion and Analysis

Significant factors that impacted our Oil Sands segment in the second quarter of 2014 compared with 2013 include:

·Commencing circulation steaming at Foster Creek phase F;

·Successfully completing a planned turnaround at Christina Lake phases A and B, with minimal impact to production;

·Christina Lake production increasing 77 percent, to an average of 67,975 barrels per day, with phase E reaching nameplate production capacity;

·Foster Creek production averaging 56,852 barrels per day, in line with our expectations; and

·Receiving anticipated regulatory approval for expansion of the Foster Creek development area.

Oil Sands — Crude Oil

Financial Results

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014	2013		2014		2013
Gross Sales	1,345	856		2,575		1,697
Less: Royalties	67	27		118		41
Revenues	1,278	829		2,457		1,656
Expenses
Transportation and Blending	559	373		1,118		838
Operating	166	132		336		255
(Gain) Loss on Risk Management	35	(4	)	57		(27	)
Operating Cash Flow (1)	518	328		946		590
Capital Investment	470	419		995		955
Operating Cash Flow Net of Related Capital Investment	48	(91	)	(49	)	(365	)

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

Capital investment in excess of Operating Cash Flow is funded through Operating Cash Flow generated by our Conventional and Refining and Marketing segments.

Three Months Ended June 30, 2014 Compared With June 30, 2013

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

Revenues

Pricing

In the second quarter, our average crude oil sales price was $75.65 per barrel, 22 percent higher than in 2013. This is consistent with the increase in the WCS benchmark price, the strengthening of the Christina Dilbit Blend (“CDB”) price and the weakening of the Canadian dollar. The WCS-CDB differential narrowed by 26 percent, to a discount of US$4.33 per barrel (2013 — US$5.82 per barrel), primarily related to improved pipeline access to the U.S. Gulf Coast and the associated access to refineries that can process heavier crude oil. In the second quarter, 54,982 barrels per day of Christina Lake production was sold as CDB (2013 — 32,894 barrels per day), with the remainder sold into the WCS stream. Christina Lake production, whether sold as CDB or blended with WCS and subject to a quality equalization charge, is priced at a discount to WCS.

Cenovus Energy Inc.	26
Second Quarter 2014 Report	Management’s Discussion and Analysis

Production Volumes

	Three Months Ended June 30,
(barrels per day)	2014	PercentChange		2013
Foster Creek	56,852	3	%	55,338
Christina Lake	67,975	77	%	38,459
	124,827	33	%	93,797

In line with our expectations, Foster Creek production averaged 56,852 barrels per day in the second quarter of 2014. We continue to optimize steam placement and are pursuing new technologies to improve the conformance of steam along wellbores. In addition, we continue to use our Wedge WellTM technology to capture production from areas between steam chambers. In the near-term, we expect to continue to see a higher steam to oil ratio (“SOR”) and production levels between 100,000 and 110,000 gross barrels per day. As we continue to learn more about operating a SAGD project with common steam chambers and build out the remaining phases, we will look to further optimize both the SOR and plant upgrades for the entire facility.

Christina Lake production increased primarily as a result of phase E reaching nameplate production capacity. In addition, there was a reduction in downtime due to the smaller scope of the 2014 turnaround as compared to an 11 day full production outage in 2013. The 2014 planned turnaround had minimal impact on production as volumes from phases A and B were processed through the phase C, D and E plant. In the second quarter of 2013, the turnaround reduced production by approximately 7,600 barrels per day.

Condensate

The bitumen produced by Cenovus must be blended with condensate to reduce its viscosity in order to transport it to market. Revenues represent the total value of blended crude oil sold and include the value of condensate. As the WCS benchmark price narrows in relation to the Condensate benchmark we recover a larger proportion of the cost to blend our product. Consistent with the narrowing of the WCS-Condensate benchmark, the proportion of the cost of condensate recovered increased in the second quarter of 2014 compared to 2013.

Royalties

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

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

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

Effective Royalty Rates

	Three Months Ended June 30,
(percent)	2014	2013
Foster Creek	9.3	5.7
Christina Lake	7.7	5.6

Royalties increased $40 million in the second quarter of 2014, primarily due to higher realized prices at both Foster Creek and Christina Lake, an increase in sales volumes at Christina Lake, and a rise in the Canadian dollar equivalent WTI benchmark price. At Foster Creek this resulted in a royalty calculation based on net profits as compared to a calculation based on gross revenues in 2013.

Expenses

Transportation and Blending

Transportation and blending costs rose $186 million or 50 percent. Blending costs rose $167 million due to higher production and an increase in the cost of condensate, consistent with the change in benchmark prices. Transportation charges were $19 million higher primarily due to production increases.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Operating

Our operating costs for the second quarter were primarily for workforce, fuel, and workover activities. In total, operating costs increased $34 million and decreased on a per barrel basis by $1.07 per barrel, consistent with the increase in production.

Per-unit Operating Costs

	Three Months Ended June 30,
($/bbl)	2014	PercentChange		2013
Foster Creek
Fuel	4.60	63	%	2.83
Non-fuel	14.78	11	%	13.36
Total	19.38	20	%	16.19
Christina Lake
Fuel	3.86	15	%	3.37
Non-fuel	8.22	(39)	%	13.46
Total	12.08	(28)	%	16.83

In the second quarter, Foster Creek operating costs rose $3.19 per barrel, primarily due to:

·Fuel costs increasing by $1.77 per barrel related to the rise in natural gas prices, consistent with the rising benchmark AECO price, and higher consumption;

·Higher workforce costs primarily related to the rise in long-term incentive costs, consistent with the increase in our share price; and

·Increased workover activities related to well servicing.

Increases were partially offset by decreases in the cost of electricity, primarily related to a decline in the price of electricity.

Christina Lake operating costs decreased $4.75 per barrel, primarily due to an increase in production.

Decreases were partially offset by:

·Fuel costs increasing by $0.49 per barrel primarily due to the rise in natural gas prices, consistent with the rising benchmark AECO price; and

·An increase in workover activities related to well servicing.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate in the second quarter was $47.28 per barrel (2013 — $42.60 per barrel) for Foster Creek and $49.30 per barrel (2013 — $47.13 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.

Risk Management

Risk management activities resulted in realized losses of $35 million in the second quarter of 2014 (2013 — realized gains of $4 million), consistent with average benchmark prices exceeding our contract prices.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Six Months Ended June 30, 2014 Compared With June 30, 2013

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

Revenues

Pricing

For the six months ended June 30, 2014, our average crude oil sales price was $70.48 per barrel, a 34 percent increase from 2013. This is consistent with the increase in the WCS benchmark price, the strengthening of the CDB price and the weakening of the Canadian dollar. The WCS-CDB differential narrowed by 31 percent, to a discount of US$4.61 per barrel (2013 — US$6.67 per barrel), primarily related to the reasons discussed previously for the current quarter. Year to date, 54,414 barrels per day of Christina Lake production was sold as CDB (2013 — 35,247 barrels per day), with the remainder sold into the WCS stream.

Production Volumes

	Six Months Ended June 30,
(barrels per day)	2014	PercentChange		2013
Foster Creek	55,785	—	%	55,665
Christina Lake	66,863	62	%	41,388
	122,648	26	%	97,053

On a year-to-date basis, production remained flat at Foster Creek, in line with expectations as previously discussed. The substantial increase in production at Christina Lake resulted from phase E reaching nameplate production capacity in the second quarter of 2014. We completed a partial planned turnaround in 2014 which had minimal impact on production. In 2013, a full planned turnaround was performed which reduced production by approximately 3,800 barrels per day for the six months.

Condensate

As the WCS benchmark price narrows in relation to the Condensate benchmark we recover a larger proportion of the cost to blend our product. The proportion of the cost of condensate recovered increased on a year-to-date basis compared to 2013, consistent with the narrowing of the WCS-Condensate differential.

Royalties

	Six Months Ended June 30,
(percent)	2014	2013
Foster Creek	8.7	4.5
Christina Lake	7.4	5.6

Royalties increased $77 million in 2014 primarily related to higher realized prices at both Foster Creek and Christina Lake, an increase in sales volumes at Christina Lake, and a rise in the Canadian dollar equivalent WTI benchmark price. At Foster Creek this resulted in a royalty calculation based on net profits as compared to a calculation based on gross revenues in 2013.

Cenovus Energy Inc.	29
Second Quarter 2014 Report	Management’s Discussion and Analysis

Expenses

Transportation and Blending

Transportation and blending costs rose $280 million or 33 percent year to date. Blending costs rose $265 million due to higher production and an increase in the cost of condensate. Transportation charges were $15 million higher primarily due to production increases.

Operating

In the first half of 2014, operating costs were primarily for fuel, workforce and workover activities. In total, operating costs increased $81 million or $0.77 per barrel.

Per-unit Operating Costs

	Six Months Ended June 30,
($/bbl)	2014	PercentChange		2013
Foster Creek
Fuel	5.03	75	%	2.87
Non-fuel	14.21	16	%	12.21
Total	19.24	28	%	15.08
Christina Lake
Fuel	4.33	22	%	3.55
Non-fuel	8.35	(25	)%	11.11
Total	12.68	(14	)%	14.66

At Foster Creek operating costs rose $4.16 per barrel primarily due to higher fuel prices and consumption, workforce and workover activities, as discussed previously.

Christina Lake operating costs decreased $1.98 per barrel primarily due to our production growth. Decreases were offset by higher fuel prices and an increase in workover activities.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate for the six months ended June 30, 2014 was $47.81 per barrel (2013 — $44.34 per barrel) for Foster Creek and $51.02 per barrel (2013 — $49.54 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.

Risk Management

Risk management activities resulted in realized losses of $57 million in the first six months of 2014 (2013 — realized gains of $27 million), consistent with average benchmark prices exceeding our contract prices.

Oil Sands — Natural Gas

Oil Sands includes our 100 percent-owned natural gas operation in Athabasca. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production, net of internal usage, for the three and six months ended June 30, 2014 remained consistent at 23 MMcf per day and 21 MMcf per day, respectively (2013 — 22 MMcf per day and 20 MMcf per day, respectively). Operating Cash Flow was $15 million in the second quarter of 2014 (2013 — $6 million) and $38 million on a year-to-date basis (2013 — $10 million). The increases were due to higher realized natural gas sales prices.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Oil Sands — Capital Investment

	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2014	2013	2014	2013
Foster Creek	209	189	430	399
Christina Lake	183	162	365	337
	392	351	795	736
Narrows Lake	45	25	92	50
Telephone Lake	19	17	71	70
Grand Rapids	5	8	16	26
Other (1)	10	19	24	75
Capital Investment (2)	471	420	998	957

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

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

Existing Projects

Capital investment at Foster Creek in 2014 focused on expansion phases F, G and H, drilling of sustaining wells, and operational improvement projects. Capital investment increased in the second quarter and on a year-to-date basis due to phase F well pad construction, drilling using Wedge WellTM technology, and an increase in stratigraphic test wells drilled.

In 2014, Christina Lake capital investment focused on expansion phase F, phase E well pad and facility construction, and Wedge WellTM technology and sustaining well programs. Capital investment increased in the second quarter and on a year-to-date basis due to higher spending on our Wedge WellTM technology and sustaining well programs, and phase F plant construction, partially offset by lower spending on phase E plant construction.

Capital investment at Narrows Lake increased in the three and six months ended June 30, 2014, as spending continued on phase A engineering, procurement, and plant construction, which started in the third quarter of 2013.

Emerging Projects

In 2014, Telephone Lake capital investment was primarily focused on front end engineering and costs related to the dewatering pilot project and the drilling of stratigraphic test wells. We are currently executing a summer stratigraphic well program using our SkyStratTM drilling rig. Capital spending in 2014 remained relatively consistent to 2013.

Capital investment at Grand Rapids in 2014 was primarily focused on costs related to the pilot project and the drilling of stratigraphic test wells. In the first quarter of 2014, we received regulatory approval for a 180,000 barrel per day commercial SAGD operation. Capital investment declined in the three and six months ended June 30, 2014. Reductions in spending on the pilot project were partially offset by the initiation of the dismantling of the Joslyn central plant facility to be relocated and used for Phase A.

Drilling Activity

Consistent with our strategy to further delineate our resources, we completed another stratigraphic test well program over the winter drilling season.

	Gross Stratigraphic Test Wells (1)		Gross Production Wells (2) (3)
Six Months Ended June 30,	2014	2013	2014	2013
Foster Creek	147	111	38	25
Christina Lake	52	69	35	11
	199	180	73	36
Narrows Lake	22	26	—	—
Telephone Lake	33	28	—	—
Grand Rapids	9	1	—	—
Other	21	80	—	—
	284	315	73	36

(1)Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. In the six months ended June 30, 2014, we drilled two wells (2013 — eight wells).

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

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

(4)In addition to the drilling activity noted above, we drilled one gross service well in the six months ended June 30, 2014 (2013 — 16 gross service wells).

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Future Capital Investment

Foster Creek is currently producing from phases A through E. Expansion work is underway at phases F, G and H. Foster Creek capital investment for 2014 is forecast to be between $680 million and $760 million and is primarily focused on expansion phases, sustaining wells and operational improvement projects. Expansion work at phases F, G and H is proceeding as planned. We expect phases F, G and H to each add initial design capacity of 30,000 barrels per day. We will continue to focus on optimizing production performance and monitoring our long-term reservoir management plan. Circulation steaming commenced at phase F in the second quarter of 2014. Production from phase F is expected to start in the fourth quarter of 2014 with ramp-up to design capacity expected to take twelve to eighteen months. Production start-up from phases G and H is anticipated in 2015 and 2016, respectively. We submitted a joint application and environmental impact assessment (“EIA”) to regulators in February 2013 for an additional expansion, phase J, and we anticipate receiving regulatory approval in the first quarter of 2015. In the second quarter of 2014, we received anticipated regulatory approval for a Foster Creek development area expansion.

Christina Lake is producing from phases A through E. Expansion work is currently underway for phase F, including cogeneration, and phase G, with added production capacity expected in 2016 and 2017, respectively. Christina Lake capital investment in 2014 is forecast to be between $750 million and $820 million and is primarily focused on expansion phases F and G, the phase C, D and E optimization program, and drilling and facilities work for drilling using our Wedge WellTM technology and sustaining wells. Phase E development spending for well pad and facility construction is expected to continue to the end of 2014. Expansion work on phases F, including cogeneration, and G is continuing as planned and we expect to add gross production capacity of 50,000 barrels per day from each phase. We submitted a joint application and EIA to regulators in the first quarter of 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.

For our Narrows Lake property, we received regulatory approval in May 2012 for phases A, B and C, and final partner approval in December 2012 for phase A. Construction of the phase A plant commenced in August 2013. Capital investment at Narrows Lake is forecast to be between $210 million and $230 million in 2014 and is primarily focused on plant construction, procurement and offsite fabrication for phase A and infrastructure for a construction camp.

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 and we completed the pilot in October 2013. At our Grand Rapids project located within the Greater Pelican region, we received regulatory approval in March 2014 for a 180,000 barrel per day commercial SAGD operation. We plan to develop Grand Rapids through a series of expansion phases. Phase A is expected to produce between 8,000 and 10,000 barrels per day, with first steam planned in 2017. The project will benefit from the purchase of an existing central plant facility that will be relocated to the Grand Rapids project site. We continue to operate a SAGD pilot project to gather additional information on the reservoir.

Capital investment of approximately $140 million to $160 million in 2014 is expected for our emerging oil sands projects and is primarily focused on drilling stratigraphic test wells, front end engineering at Telephone Lake and Grand Rapids, as well as costs related to the pilot project at Grand Rapids. At Telephone Lake we are advancing the regulatory application for the project and anticipate receiving approval in the second half of 2014. The first two phases of the project are anticipated to have a production capacity of 90,000 barrels per day.

DD&A

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

The following calculation illustrates how the implied depletion rate for our upstream assets could be determined using the reported consolidated data:

($ millions, unless otherwise indicated)	As at December 31, 2013
Upstream Property, Plant and Equipment	13,692
Estimated Future Development Capital	17,795
Total Estimated Upstream Cost Base	31,487
Total Proved Reserves (MBOE)	2,284
Implied Depletion Rate ($/BOE)	13.79

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Second Quarter 2014 Report	Management’s Discussion and Analysis

While this illustrates the calculation of the implied depletion rate, our depletion rates are slightly higher and result in a total average rate ranging between $15.50 to $16.00 per BOE. Amounts related to assets under construction, which would be included in the total upstream cost base and would have proved reserves attributed to them, are not depleted. Property specific rates will exclude upstream assets that are depreciated on a straight-line basis. As such, our actual depletion will differ from depletion calculated by applying the above implied depletion rate. Further information on our accounting policy for DD&A is included in our notes to the Consolidated Financial Statements.

In the three and six months ended June 30, 2014, Oil Sands DD&A increased $53 million and $91 million, respectively. The increases were due to higher sales volumes, and higher DD&A rates for both of our properties from additional expenditures and a rise in future development costs associated with total proved reserves.

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, the heavy oil assets at Pelican Lake and developing tight oil assets in Alberta. Pelican Lake produces conventional heavy oil using polymer flood technology. The established assets in this segment are strategically important for their long life reserves, stable operations and diversity of crude oil produced.

Furthermore, we own the mineral rights on approximately 70 percent or 4.5 million net acres of our conventional lands (fee lands), of which 2.5 million acres are developed. Our ownership of fee lands benefits our netback. Fee lands where we have maintained a working interest are subject to mineral tax, which is generally lower than the royalties paid to the government or other mineral interest owners. Of the 4.5 million net acres of fee land, we lease over 2.0 million acres to third parties, which may result in royalty income. In the first half of 2014, we had approximately 7,800 barrels of oil equivalent per day of royalty interest production from fee lands. Production from fee lands comprises approximately 50 percent of our total conventional production.

Our natural gas production acts as an economic hedge for the natural gas required as a fuel source at both our oil sands and refining operations. The cash flow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment.

Significant factors that impacted our Conventional segment in the second quarter of 2014 compared with 2013 include:

·Crude oil production averaging 76,861 barrels per day, decreasing one percent. Increased production from successful horizontal well performance in southern Alberta and higher production at Pelican Lake, was offset by expected natural declines and the sale of our Lower Shaunavon and Bakken assets; and

·Generating Operating Cash Flow net of related capital investment of $385 million, an increase of $169 million.

In March 2014, we entered into a purchase and sale agreement with an unrelated third party, to sell certain of our Bakken assets in southeastern Saskatchewan. The sale was completed in April 2014 for proceeds of $36 million before closing adjustments. A gain on disposition of $16 million was recorded on the sale. Prior to the sale, crude oil production from these Bakken assets was 396 barrels per day in the first quarter of 2014 (Q2 2013 — 618 barrels per day and YTD 2013 — 695 barrels per day, respectively).

In July 2013, we sold our Lower Shaunavon asset for proceeds of approximately $240 million before closing adjustments. Lower Shaunavon produced an average of 3,592 barrels per day in the second quarter of 2013 and 4,236 barrels per day in the first six months of 2013.

Conventional — Crude Oil

Financial Results

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014	2013		2014	2013
Gross Sales	708	607		1,359	1,150
Less: Royalties	67	48		116	90
Revenues	641	559		1,243	1,060
Expenses
Transportation and Blending	91	83		180	169
Operating	133	130		278	254
Production and Mineral Taxes	10	9		18	18
(Gain) Loss on Risk Management	19	(10	)	32	(30	)
Operating Cash Flow (1)	388	347		735	649
Capital Investment	149	241		412	571
Operating Cash Flow Net of Related Capital Investment	239	106		323	78

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

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Three Months Ended June 30, 2014 Compared With June 30, 2013

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

Revenues

Pricing

Our average crude oil sales price in the quarter increased 15 percent to $89.98 per barrel, consistent with the change in crude oil benchmark prices and associated differentials.

Production Volumes

	Three Months Ended June 30,
(barrels per day)	2014	PercentChange		2013
Pelican Lake	24,806	4	%	23,959
Other Heavy Oil	15,498	(5	)%	16,284
Total Heavy Oil	40,304	—	%	40,243
Light and Medium Oil	35,329	(2	)%	36,137
NGLs	1,228	29	%	950
	76,861	(1	)%	77,330

Increased production from successful horizontal well performance in southern Alberta and higher production at Pelican Lake, was offset by expected natural declines and the divestiture of our Lower Shaunavon and Bakken assets. Pelican Lake production increased as a result of additional infill wells coming on-stream and an increased response from the polymer flood program.

Condensate

Revenues represent the total value of blended crude oil sold and include the value of condensate. In the quarter, the value of condensate increased $7 million compared to 2013. The proportion of the cost of condensate recovered increased, consistent with the narrowing of the WCS-Condensate differential.

Royalties

Royalties increased $19 million primarily due to higher realized prices, an increase in sales volumes at Pelican Lake, and a rise in the Canadian dollar equivalent WTI benchmark price.

Royalties at Pelican Lake are determined under oil sands royalty calculations. Pelican Lake is a post-payout project, therefore royalties are based on an annualized calculation which uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one to nine percent); or (2) the net profits of the project multiplied by the applicable royalty rate (25 to 40 percent). Net profits are a function of sales volumes, realized prices and allowed operating and capital costs. In 2014 and 2013, the Pelican Lake royalty calculation was based on gross revenues. Our other conventional crude oil producing assets are located primarily on crown or fee lands. Production from fee lands results in mineral tax recorded within production and mineral taxes.

In the second quarter of 2014, the effective crude oil royalty rate for all of our Conventional properties was 10.8 percent (2013 — 9.3 percent).

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Expenses

Transportation and Blending

Transportation and blending costs increased $8 million in the second quarter of 2014, primarily due to higher condensate costs as discussed in the Revenues section. Transportation costs remained relatively consistent compared to 2013.

Operating

Primary drivers of our operating costs in the second quarter of 2014 were for workforce, workover activities, repairs and maintenance, electricity and chemical consumption. Our operating costs increased $3 million, or $0.73 per barrel.

Operating costs increased to $18.89 per barrel, primarily due to:

·Increased workforce costs due to an increase in long-term incentive costs, consistent with the rise in our share price;

·Higher chemical costs associated with polymer consumption and price related to the polymer flood programs; and

·Increased repairs and maintenance activities related to well optimizations.

The increases in our crude oil operating costs were partially offset by declines in operating costs due to the sale of Lower Shaunavon and Bakken assets, in addition to lower electricity and workover costs.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended heavy oil basis, the cost of condensate for our heavy oil properties was $17.70 per barrel in the second quarter (2013 — $16.72 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

Risk Management

Risk management activities in the second quarter resulted in realized losses of $19 million (2013 — realized gains of $10 million), consistent with average benchmark prices exceeding our contract prices.

Six Months Ended June 30, 2014 Compared With June 30, 2013

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

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Revenues

Pricing

In the first half of the year, our average crude oil sales price increased 21 percent to $87.72 per barrel, consistent with the change in crude oil benchmark prices and associated differentials.

Production Volumes

	Six Months Ended June 30,
(barrels per day)	2014	Percent Change		2013
Pelican Lake	24,794	4	%	23,824
Other Heavy Oil	15,756	(4)	%	16,497
Total Heavy Oil	40,550	1	%	40,321
Light and Medium Oil	34,966	(6)	%	37,317
NGLs	1,121	17	%	961
	76,637	(2)	%	78,599

Increased production related to our successful horizontal well performance in southern Alberta and higher production at Pelican Lake, was offset by expected natural declines and the sale of our Lower Shaunavon and Bakken assets.

Condensate

On a year-to-date basis the value of condensate increased $8 million. The proportion of the cost of condensate recovered increased on a year-to-date basis, consistent with the narrowing of the WCS-Condensate differential.

Royalties

Royalties increased $26 million largely due to a rise in realized prices, and an increase in sales volumes at Pelican Lake, partially offset by lower sales volumes at our other conventional properties. The effective crude oil royalty rate during the first six months of the year was 10.0 percent (2013 — 9.2 percent).

Expenses

Transportation and Blending

Transportation and blending costs increased $11 million in the first six months of the year. The cost of condensate increased by $8 million as discussed in the Revenues section. Transportation costs rose $3 million due to higher pipeline and storage costs related to our Pelican Lake property, partially offset by reduced transportation costs from lower sales volumes at our other conventional properties.

Operating

Year to date, operating costs were predominantly composed of workover activities, workforce, electricity costs and repairs and maintenance. Operating costs rose $24 million, or $2.22 per barrel.

Operating costs increased to $19.95 per barrel, primarily due to:

·Higher chemical costs associated with polymer consumption and price related to the polymer flood programs;

·Increased workforce costs related to an increase in long-term incentive costs, consistent with the rise in our share price; and

·Higher workover and repair and maintenance activities related to well optimizations.

Higher crude oil operating costs were partially offset by declines in operating costs due to the sale of Lower Shaunavon and Bakken assets, in addition to lower electricity costs.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended heavy oil basis, the cost of condensate for our heavy oil properties was $17.63 per barrel on a year-to-date basis (2013 — $17.33 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

Risk Management

In the first six months of the year, risk management activities resulted in realized losses of $32 million (2013 — realized gains of $30 million), consistent with average benchmark prices exceeding our contract prices.

Conventional — Natural Gas

Financial Results

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014	2013		2014	2013
Gross Sales	214	164		398	319
Less: Royalties	3	2		6	4
Revenues	211	162		392	315
Expenses
Transportation and Blending	4	4		9	11
Operating	52	55		101	107
Production and Mineral Taxes	7	—		6	1
(Gain) Loss on Risk Management	1	(9	)	1	(27	)
Operating Cash Flow (1)	147	112		275	223
Capital Investment	4	4		11	12
Operating Cash Flow Net of Related Capital Investment	143	108		264	211

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

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

Three and Six Months Ended June 30, 2014 Compared With June 30, 2013

Revenues

Pricing

In the second quarter and the first half of the year, our average natural gas sales price increased $1.38 per Mcf to $4.88 per Mcf and $1.30 per Mcf to $4.68 per Mcf, respectively. The increases are consistent with the rise in the benchmark AECO natural gas price.

Production

Production decreased six percent to 484 MMcf per day in the second quarter of 2014 and declined nine percent to 471 MMcf per day on a year-to-date basis, primarily due to expected natural declines.

Royalties

Royalties increased in the second quarter of 2014 and on a year-to-date basis, as a result of higher prices, despite production declines. The average royalty rate in the second quarter was 1.7 percent (2013 — 1.2 percent) and 1.5 percent (2013 — 1.4 percent) on a year-to-date basis. Most of our natural gas production is located on fee lands where we hold mineral rights, which results in mineral tax being recorded within production and mineral taxes.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Expenses

Transportation

In the three months ended June 30, 2014, transportation costs remained consistent and declined $2 million on a year-to-date basis as a result of lower production volumes.

Operating

In the second quarter and for the first half of the year, our operating expenses were primarily composed of property taxes and lease costs, workforce and repairs and maintenance. During the quarter, operating expenses decreased $3 million primarily due to natural production declines, decreases in the cost of electricity, and lower repairs and maintenance costs, partially offset by higher property taxes and lease costs. On a year-to-date basis, operating expenses decreased $6 million due to natural production declines, lower repairs and maintenance costs, and declines in electricity pricing and consumption, partially offset by higher property taxes and lease costs.

Risk Management

Risk management activities resulted in realized losses of $1 million in the second quarter and on a year-to-date basis (2013 — realized gains of $9 million and $27 million, respectively), consistent with the average benchmark price exceeding our contract prices.

Conventional — Capital Investment (1)

	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2014	2013	2014	2013
Pelican Lake	68	111	139	251
Other Heavy Oil	14	39	49	71
Light and Medium Oil	67	91	224	249
Natural Gas	4	4	11	12
	153	245	423	583

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

Capital investment in the first half of 2014 was primarily composed of spending on tight oil development, facilities work, and on infill drilling, maintenance capital and facilities upgrades at Pelican Lake associated with the expansion of the polymer flood. Spending on natural gas activities continues to be managed in response to the natural gas price environment.

The decline in capital investment at Pelican Lake reflects our decision to align spending with the more moderate production ramp-up associated with the initial results of the polymer flood program.

Conventional Drilling Activity

	Six Months Ended June 30,
(net wells, unless otherwise stated)	2014	2013
Crude Oil	66	95
Recompletions	354	317
Gross Stratigraphic Test Wells	14	19
Other (1)	24	40

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

Crude oil wells drilled reflect the continued development of our Conventional properties. Well recompletions are primarily related to lower-risk Alberta coal bed methane development.

Future Capital Investment

In 2014, Pelican Lake capital investment is forecast to be between $230 million and $250 million with spending mainly focused on infill drilling, pipeline construction and maintenance capital for the polymer flood.

Capital investment on other Conventional crude oil properties, which will be focused on tight oil development and facilities work, is forecast to be between $540 million and $590 million.

DD&A

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

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Conventional DD&A decreased $53 million and $100 million for the three and six months ended June 30, 2014, respectively. The decreases were primarily due to the impairment loss recorded in 2013 and a decline in sales volumes.

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 that impacted our Refining and Marketing segment in the second quarter of 2014 compared with 2013 include:

·Refined product output increasing as a result of an unplanned hydrocracker outage in 2013 and the timing of the planned turnarounds in 2014 as compared to 2013; and

·Operating Cash Flow decreasing 32 percent to $220 million primarily due to declines in market crack spreads and higher heavy crude oil feedstock costs, partially offset by higher refined product output.

Refinery Operations (1)

	Three Months Ended June 30,		Six Months Ended June 30,
	2014	2013	2014	2013
Crude Oil Capacity (2) (Mbbls/d)	460	457	460	457
Crude Oil Runs (Mbbls/d)	466	439	433	428
Heavy Crude Oil	221	230	208	214
Light/Medium	245	209	225	214
Refined Products (Mbbls/d)	489	457	458	448
Gasoline	240	221	228	223
Distillate	155	145	142	139
Other	94	91	88	86
Crude Utilization (percent)	101	96	94	94

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

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

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

In the three months ended June 30, 2014, reliable refinery performance resulted in an increase to crude oil runs, refined product output and crude utilization as compared to 2013. In 2013, our refinery operations were negatively impacted by an unplanned hydrocracker outage and the completion of the planned Borger turnaround in the second quarter of 2013. The 2014 planned turnaround at Borger was completed in the first quarter.

In the first half of the year, our crude oil runs and our refined product output increased slightly over 2013. Reliable refinery performance in the second quarter of 2014 offset the unplanned hydrocracker outage in 2013. Crude utilization remained consistent as a result of the increase in our 2014 refinery capacity. While total refined product output increased, the proportion of gasoline, distillate and other refined product output remained relatively the same in the second quarter of 2014 and on a year-to-date basis.

Our crude utilization represents the percentage of total crude oil processed in our refineries relative to the total capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by processing less expensive crude oil. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate being optimized at each refinery to maximize economic benefit. The amount of heavy crude oil processed in 2014 decreased as a result of processing higher volumes of medium crude oil due to more favourable economics.

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Second Quarter 2014 Report	Management’s Discussion and Analysis

Financial Results

	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2014	2013	2014		2013
Revenues	3,483	3,078	6,741		6,024
Purchased Product	3,098	2,616	5,918		4,893
Gross Margin	385	462	823		1,131
Expenses
Operating	165	134	363		270
(Gain) Loss on Risk Management	—	4	(5	)	8
Operating Cash Flow (1)	220	324	465		853
Capital Investment	46	26	69		51
Operating Cash Flow Net of Capital Investment	174	298	396		802

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

Gross Margin

In the second quarter and the first half of the year, the gross margin for the Refining and Marketing segment declined 17 percent and 27 percent, respectively. This was primarily due to the decline in market crack spreads, consistent with the narrowing of the Brent-WTI differential; higher heavy crude oil feedstock costs, consistent with the increase in the WCS price; and higher operating costs as described below. The declines were partially offset by an increase in refined product output primarily due to an unplanned hydrocracker outage in 2013. In addition, refined product output in the second quarter was higher as a result of the timing of the 2014 planned turnarounds and maintenance as compared to 2013.

Our refineries do not blend renewable fuels into the motor fuel products we produce and consequently we are obligated to purchase Renewable Identification Numbers (“RINs”). In the second quarter of 2014, the cost of our RINs was $30 million, a decrease from 2013 (2013 — $54 million). On a year-to-date basis, the cost of our RINs was $56 million (2013 — $77 million). These decreases are consistent with the decline in the ethanol RINs benchmark price. This cost remains a minor component of our total refinery feedstock costs.

Operating

Primary drivers of operating costs in the second quarter of 2014 and on a year-to-date basis were maintenance, labour, utilities and supplies. Operating costs increased 23 percent (YTD — 34 percent), primarily due to higher costs related to planned maintenance and turnaround activities and an increase in utility costs resulting from a rise in natural gas and electricity costs.

Refining and Marketing — Capital Investment

	Three Months Ended June 30,		Six Months Ended June 30,
($ millions)	2014	2013	2014	2013
Wood River Refinery	23	13	34	26
Borger Refinery	23	13	35	25
	46	26	69	51

Capital expenditures in 2014 focused on capital maintenance and refinery reliability and safety projects. In the first quarter of 2014, we and our partner sanctioned the Wood River debottleneck project. We are currently awaiting permit approval, which is anticipated in the fourth quarter of 2014, and planned start-up of the project is anticipated in the first quarter of 2016.

In 2014, we expect to invest between $150 million and $160 million mainly related to routine safety initiatives, meeting new low sulphur (Tier III) gasoline requirements and additional capital investments expected to enhance returns at the Wood River Refinery.

DD&A

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A increased $5 million in the second quarter of 2014 and $12 million on a year-to-date basis, primarily due to the change in the US$/C$ foreign exchange rate.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices and the unrealized mark-to-market gains and losses on the long-term power purchase contract. In the second quarter of 2014, our risk

Cenovus Energy Inc.	40
Second Quarter 2014 Report	Management’s Discussion and Analysis

management activities resulted in $11 million of unrealized losses, before tax (2013 — $26 million of unrealized gains, before tax). On a year-to-date basis, we had $15 million of unrealized gains, before tax from risk management activities (2013 — $204 million of unrealized losses, before tax). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing activities and research costs.

	Three Months Ended June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
General and Administrative	102		82		211		165
Finance Costs	102		124		232		247
Interest Income	(25	)	(23	)	(27	)	(50	)
Foreign Exchange (Gain) Loss, Net	(187	)	96		(40	)	148
Research Costs	4		6		6		9
(Gain) Loss on Divestiture of Assets	(20	)	—		(20	)	—
Other (Income) Loss, Net	(1	)	(2	)	(2	)	—
	(25	)	283		360		519

Expenses

General and Administrative

In 2014, primary drivers of our general and administrative expenses were staffing costs, long-term incentive costs and office rent. General and administrative expenses increased in the second quarter of 2014 and on a year-to-date basis by $20 million and $46 million, respectively, primarily due to higher long-term incentive costs, consistent with the increase in our share price, and higher staffing 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. Finance costs decreased $22 million and $15 million in the three and six months ended June 30, 2014, respectively. The decreases were primarily due to lower interest incurred on the Partnership Contribution Payable, partially offset by higher unwinding of the discount on decommissioning liabilities and higher interest expenses on long-term debt resulting primarily from the weakening of the Canadian dollar.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for the second quarter was 4.9 percent (2013 — 5.3 percent) and for the six months ended June 30, 2014 was 5.0 percent (2013 — 5.3 percent).

Foreign Exchange

	Three Months Ended June 30,			Six Months Ended June 30,
($ millions)	2014		2013	2014		2013
Unrealized Foreign Exchange (Gain) Loss	(181	)	84	(38	)	134
Realized Foreign Exchange (Gain) Loss	(6	)	12	(2	)	14
	(187	)	96	(40	)	148

The majority of unrealized gains in the second quarter of 2014 stem from translation of our U.S. dollar denominated debt.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A for the second quarter was $21 million (2013 — $20 million) and $41 million on a year-to-date basis (2013 — $39 million).

Income Tax Expense (Recovery)

	Three Months Ended June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
Current Tax
Canada	(10	)	57		33		87
U.S.	3		4		35		58
Total Current Tax	(7	)	61		68		145
Deferred Tax	216		40		252		79
	209		101		320		224
Effective Tax Rate	25	%	36	%	27	%	39	%

Cenovus Energy Inc.	41
Second Quarter 2014 Report	Management’s Discussion and Analysis

Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for taxes is adequate. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation. A provision for income taxes on earnings in the interim periods is accrued using the income tax rate that would be applicable to the expected total annual earnings.

The 2014 provision for income tax includes the effect of a favourable adjustment related to prior years, which has minimal impact on total tax. In the second quarter and the first half of the year, current income tax decreased $68 million and $77 million, respectively. The decline was primarily due to a favourable adjustment related to prior periods and a decrease in U.S. operating cash flow, partially offset by an increase in Conventional operating cash flow. Deferred income tax increased $176 million and $173 million, respectively. The increase in deferred income tax resulted from an increase in Canadian timing differences arising from increased Oil Sands income, the effect of the favourable adjustment to current tax related to prior years (as described above), offset by a decrease in the reversal of U.S. timing differences in 2014. Given expected levels of income in the U.S. in 2014, the residual pool of U.S. federal net operating losses is expected to be substantially claimed in 2014.

Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before income taxes. The effective tax rate differs from the Canadian statutory tax rate as it reflects higher U.S. tax rates on U.S. sources of income and permanent differences.

The decrease in our effective tax rate in the second quarter of 2014 and on a year-to-date basis is primarily due to lower levels of U.S. source income in 2014.

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended June 30,				Six Months Ended June 30,
($ millions)	2014		2013		2014		2013
Net Cash From (Used In)
Operating Activities	1,109		828		1,566		1,723
Investing Activities	(692	)	(803	)	(3,089	)	(1,706	)
Net Cash Provided (Used) Before Financing Activities	417		25		(1,523	)	17
Financing Activities	(471	)	(183	)	(225	)	(349	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	(1	)	5		56		(3	)
Increase (Decrease) in Cash and Cash Equivalents	(55	)	(153	)	(1,692	)	(335	)

	As At
($ millions)	June 30,2014	December 31, 2013
Cash and Cash Equivalents	760	2,452

Operating Activities

Cash from operating activities was $281 million higher in the second quarter of 2014 primarily due to the increase in Cash Flow as discussed in the Financial Results section of this MD&A. Year to date, there was a decrease of $157 million in cash from operating activities primarily due to the change in non-cash working capital, partially offset by the increase 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 $1,019 million at June 30, 2014 compared to $1,957 million at December 31, 2013. We anticipate that we will continue to meet our payment obligations as they come due.

Investing Activities

Cash used in investing activities in the second quarter of 2014 was $111 million lower (year to date — increase of $1,383 million). The decrease in the second quarter was primarily due to proceeds received on the divestiture of our Bakken asset and a reduction in capital expenditures. The year-to-date increase in cash used in investing activities was predominately due to the prepayment of the US$1.4 billion Partnership Contribution Payable in March 2014.

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 second quarter, we paid a dividend of $0.2662 per share, an increase of 10 percent from 2013 (2013 — $0.242 per share). Year-to-date dividend payments were $403 million (2013 — $367 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Cenovus Energy Inc.	42
Second Quarter 2014 Report	Management’s Discussion and Analysis

In the second quarter, cash flow used in financing activities increased $288 million primarily due to the net repayment of short-term borrowings. In the six months ended June 30, 2014, cash flow used in financing activities declined $124 million as a result of short-term borrowings, partially offset by the increase in dividends paid.

Our long-term debt was $5,018 million at June 30, 2014 with no principal payments due until October 2019 (US$1.3 billion). The $21 million increase in long-term debt from December 31, 2013 is primarily related to foreign exchange.

As at June 30, 2014, we are in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

We expect cash flow from our crude oil, natural gas and refining operations to fund a significant portion of our cash requirements over the next decade. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity or management of our asset portfolio. The following sources of liquidity are available as at June 30, 2014.

($ millions)	Amount		Term
Cash and Cash Equivalents	760		Not Applicable
Committed Credit Facility	2,848		November 2017
U.S. Base Shelf Prospectus (1)	US$	2,000	July 2016
Canadian Base Shelf Prospectus (1)	1,500		July 2016

(1)Availability is subject to market conditions.

We have a commercial paper program which, together with our committed credit facility, is used to manage our short-term cash requirements. We reserve capacity under our committed credit facility for amounts of outstanding commercial paper.

On June 24, 2014, we filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion, which replaced the U.S. base shelf prospectus dated June 6, 2012, as amended May 9, 2013. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at June 30, 2014, no notes have been issued under this U.S. base shelf prospectus.

On June 25, 2014, we filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion, which replaced the Canadian base shelf prospectus dated May 24, 2012. The Canadian base shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at June 30, 2014, no medium term notes have been issued under this Canadian base shelf prospectus.

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 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, calculated on a trailing 12 month basis. These metrics are used to steward our overall debt position and as measures of our overall financial strength.

	June 30,		December 31,
As at	2014		2013
Debt to Capitalization	33	%	33	%
Debt to Adjusted EBITDA (times)	1.2	x	1.2	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 of between 1.0 to 2.0 times. At June 30, 2014, our Debt to Capitalization and Debt to Adjusted EBITDA metrics were near the low end of our target ranges. Additional information regarding our financial metrics and capital structure can be found in the notes to the interim Consolidated Financial Statements.

Cenovus Energy Inc.	43
Second Quarter 2014 Report	Management’s Discussion and Analysis

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 second preferred shares. As at June 30, 2014, 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.

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 entitle the holder to receive upon vesting either a Cenovus common share or a cash payment equal to the value of a Cenovus common share. Refer to the notes of the interim Consolidated Financial Statements for more details.

Total Outstanding Common Shares and Stock-Based Compensation Plans

As at June 30, 2014	Units (thousands)
Common Shares	757,034
Stock Options
NSRs	41,290
TSARs	4,116
Cenovus Replacement TSARs	3
Encana Replacement TSARs	48
Other Stock-Based Compensation Plans
PSUs	7,110
DSUs	1,274

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, see the notes to the interim Consolidated Financial Statements.

We anticipate increasing our rail shipping capacity for crude oil to approximately 30,000 barrels per day by the end of 2014, subject to favourable market conditions.

Legal Proceedings

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

RISK MANAGEMENT

For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with the Risk Management section of our 2013 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 the risks identified in our 2013 annual MD&A has not changed substantially since December 31, 2013. In addition, no new material risks were identified.

A description of the risk factors and uncertainties affecting Cenovus can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2013. The following provides an update on our commodity price risk management.

Cenovus Energy Inc.	44
Second Quarter 2014 Report	Management’s Discussion and Analysis

Commodity Price Risk

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

We manage our commodity price exposure through a combination of activities including integration, financial hedges and physical contracts. We have a variety of instruments and strategies available to us within our financial hedges and physical contracts, such as swaps, futures, options, collars, differentials and fixed-price contracts, that will be utilized as market conditions warrant. For further details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see the notes to the interim and annual Consolidated Financial Statements. The financial impact is summarized below:

Financial Impact of Risk Management Activities

	Three Months Ended June 30,
	2014						2013
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	52		12		64		(11	)	(21	)	(32	)
Natural Gas	1		(3	)	(2	)	(8	)	(6	)	(14	)
Refining	—		3		3		4		3		7
Power	2		(1	)	1		(5	)	(2	)	(7	)
(Gain) Loss on Risk Management	55		11		66		(20	)	(26	)	(46	)
Income Tax Expense (Recovery)	(14	)	(3	)	(17	)	4		5		9
(Gain) Loss on Risk Management, After Tax	41		8		49		(16	)	(21	)	(37	)

	Six Months Ended June 30,
	2014						2013
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	86		(14	)	72		(54	)	169		115
Natural Gas	1		(2	)	(1	)	(27	)	36		9
Refining	(4	)	2		(2	)	8		1		9
Power	2		(1	)	1		(5	)	(2	)	(7	)
(Gain) Loss on Risk Management	85		(15	)	70		(78	)	204		126
Income Tax Expense (Recovery)	(21	)	4		(17	)	18		(52	)	(34	)
(Gain) Loss on Risk Management, After Tax	64		(11	)	53		(60	)	152		92

In the quarter and the first half of the year, management of commodity price risk resulted in realized losses on crude oil financial instruments, consistent with average benchmark prices exceeding our contract prices.

In the quarter, we recognized unrealized losses on our crude oil financial instruments as a result of the changes in forward prices compared with prices at the end of the prior quarter and changes in prices for transactions executed during the quarter, partially offset by the realization of settled positions and the widening of forward light/heavy differentials.

On a year-to-date basis, we recognized unrealized gains on our crude oil financial instruments as a result of the realization of settled positions, the widening of forward light/heavy differentials, partially offset by changes in forward prices compared with prices at the end of the prior year and changes in prices for transactions executed during the period.

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 2013 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 preparation and our significant accounting policies can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2013.

Cenovus Energy Inc.	45
Second Quarter 2014 Report	Management’s Discussion and Analysis

Critical Accounting Judgments in Applying Accounting Policies

Critical accounting 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 our annual and interim Consolidated Financial Statements and accompanying notes. There have been no changes to our critical judgments used in applying accounting policies in the first six months of 2014. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2013.

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 in the first six months of 2014. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2013.

Future Accounting Pronouncements

New and Amended Standards and Interpretations Adopted

Offsetting Financial Assets and Financial Liabilities

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

New Standards and Interpretations not yet Adopted

Revenue Recognition

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

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

Financial Instruments

On July 24, 2014, the IASB issued IFRS 9, “Financial Instruments” (“IFRS 9”) to replace International Accounting Standard 39, “Financial Instruments: Recognition and Measurement”. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. We are currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.

Additional Standards

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 Consolidated Financial Statements for the year ended December 31, 2013.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) in the three months ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, ICFR.

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

TRANSPARENCY AND CORPORATE RESPONSIBILITY

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

Cenovus Energy Inc.	46
Second Quarter 2014 Report	Management’s Discussion and Analysis

Our Corporate Responsibility (“CR”) policy continues to drive our commitments, our CR approach and reporting, and enables alignment with our business objectives and processes. Our future CR reporting activities will be guided by this policy and will focus on improving performance by continuing to track, measure and monitor our CR performance indicators. Our CR policy and CR report is available on our website at cenovus.com. Our 2013 CR report was issued in July 2014.

In June 2014, Cenovus was named one of the Top 50 Socially Responsible Corporations in Canada by Maclean’s magazine and Sustainalytics for the third year in a row and for the fourth consecutive year by Corporate Knights magazine as one of the 2014 Best Corporate Citizens in Canada. We were also included in the Euronext Vigeo World 120 Index. This index recognizes the top 120 companies globally for their high degree of control of corporate responsibility risk and contributions to sustainable development.

In February 2014, Cenovus was named the top Canadian company for Best Sustainability Practice at the Investor Relations Magazine Awards for the second year in a row. In January 2014, Cenovus was included for the first time in the RobecoSAM 2014 Sustainability Yearbook with a Bronze Class distinction. RobecoSAM is a Swiss-based specialist in international sustainability investment that publishes the Dow Jones Sustainability Index. Corporate Knights magazine also named Cenovus to their 2014 Global 100 clean capitalism ranking for the second consecutive year, as announced during the World Economic Forum in Davos, Switzerland in January 2014.

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

OUTLOOK

We continue to move forward on our business plan targeting net crude oil production, including our conventional oil operations, of more than 500,000 barrels per day. 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 driven by technology, innovation and continued respect for the health and safety of our employees and contractors, with an emphasis on environmental performance and meaningful dialogue with our stakeholders.

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

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

·We expect the general outlook for crude oil prices will continue to be tied to global economic growth, the pace of North American supply growth and production interruptions. Economic indicators suggest an improvement in crude oil demand growth from the U.S. as the adverse weather impacts experienced in the first half of 2014 dissipate. North American crude oil supply growth is expected to continue at a strong, but moderating pace. Global supply disruptions are difficult to predict and materially impact the price of Brent crude oil. Recent unrest in Iraq has driven Brent crude oil prices higher. Given the uncertainty in Iraq and increased risk of supply outages, we expect Brent crude oil prices in 2014 to be higher than 2013;

·The Brent-WTI differential has narrowed from 2013 as new pipeline capacity from Cushing to the U.S. Gulf Coast has reduced inland congestion. Growing tight oil supply should reduce the need for imports to the U.S. and create occasional congestion issues. We expect that this, coupled with the increased risk of geopolitical outages, will result in wider Brent-WTI differentials;

·The WTI-WCS differential will continue to be set by the marginal transportation cost to the U.S. Gulf Coast. Differentials will likely remain close to current levels as a result of excess rail capacity from rail infrastructure additions. The differential may be volatile due to uncertainty around the timing of upcoming rail and pipeline infrastructure additions; and

·With refinery turnaround season complete, we expect a slight decline in inland refining crack spreads in the short term.

Cenovus Energy Inc.	47
Second Quarter 2014 Report	Management’s Discussion and Analysis

Natural gas prices are expected to remain consistent to prices experienced in the first half of the year, with the potential for volatility based on weather. As storage levels return to more normal levels, we expect a modest weakening of pricing.

Foreign exchange prices have strengthened in the second quarter of 2014 as compared to the first quarter. The average foreign exchange forward price is US$0.932/C$1 over the next four quarters. Overall, the Canadian dollar remains relatively weak, which has a positive impact on our revenues and Operating Cash Flow.

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 oil prices from downside risk by entering into financial transactions that fix the WTI-WCS differential;

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

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

(1)Expected gross production capacity.

Key Priorities for 2014

Our key priorities for 2014 remain unchanged from 2013.

Market Access

We are focused on near and mid-term strategies to broaden market access for our crude oil production. 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 crude oil to approximately 30,000 barrels per day by the end of 2014, subject to favourable market conditions, by supporting industry transportation projects as well as new and expanded market development initiatives for our crude oil.

Attacking Cost Structures

We continue to take aim at cost structures across the organization to maintain our track record of cost efficiency. We must ensure that, over the long term, we maintain an efficient and sustainable cost structure and take advantage of our business model. For example, we are actively identifying opportunities in supply chain management to further reduce 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 our industry. Additional details regarding the impact of these factors on our financial results are discussed in the Risk Management section of this MD&A.

Cenovus Energy Inc.	48
Second Quarter 2014 Report	Management’s Discussion and Analysis

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the Period Ended June 30,

($ millions, except per share amounts)

		Three Months Ended						Six Months Ended
	Notes	2014			2013			2014			2013
Revenues	1
Gross Sales		5,560			4,594			10,675			8,971
Less: Royalties		138			78			241			136
		5,422			4,516			10,434			8,835
Expenses	1
Purchased Product		2,880			2,486			5,459			4,641
Transportation and Blending		655			460			1,308			1,018
Operating		518			455			1,090			894
Production and Mineral Taxes		17			9			24			19
(Gain) Loss on Risk Management	21	66			(46		)	70			126
Depreciation, Depletion and Amortization		486			480			940			935
Exploration Expense	10	1			109			1			109
General and Administrative		102			82			211			165
Finance Costs	4	102			124			232			247
Interest Income	5	(25		)	(23		)	(27		)	(50		)
Foreign Exchange (Gain) Loss, Net	6	(187		)	96			(40		)	148
Research Costs		4			6			6			9
(Gain) Loss on Divestiture of Assets	12	(20		)	—			(20		)	—
Other (Income) Loss, Net		(1		)	(2		)	(2		)	—
Earnings Before Income Tax		824			280			1,182			574
Income Tax Expense	7	209			101			320			224
Net Earnings		615			179			862			350
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		3			7			(5		)	9
Items That May be Subsequently Reclassified to Profit or Loss:
Change in Value of Available for Sale Financial Assets		—			8			—			8
Foreign Currency Translation Adjustment		(111		)	45			(41		)	72
Total Other Comprehensive Income (Loss), Net of Tax		(108		)	60			(46		)	89
Comprehensive Income		507			239			816			439
Net Earnings Per Common Share	8
Basic		$	0.81		$	0.24		$	1.14		$	0.46
Diluted		$	0.81		$	0.24		$	1.14		$	0.46

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	49
Second Quarter 2014 Report	Consolidated Financial Statements

CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		June 30,	December 31,
	Notes	2014	2013
Assets
Current Assets
Cash and Cash Equivalents		760	2,452
Accounts Receivable and Accrued Revenues		2,192	1,874
Income Tax Receivable		15	15
Inventories	9	1,647	1,259
Risk Management	21	3	10
Current Assets		4,617	5,610
Exploration and Evaluation Assets	1,10	1,613	1,473
Property, Plant and Equipment, Net	1,11	18,078	17,334
Income Tax Receivable		12	—
Other Assets		65	68
Goodwill	1	739	739
Total Assets		25,124	25,224
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		3,154	2,937
Income Tax Payable		289	268
Current Portion of Partnership Contribution Payable	13	—	438
Short-Term Borrowings	14	152	—
Risk Management	21	113	136
Current Liabilities		3,708	3,779
Long-Term Debt	15	5,018	4,997
Partnership Contribution Payable	13	—	1,087
Risk Management	21	4	3
Decommissioning Liabilities	16	2,691	2,370
Other Liabilities		161	180
Deferred Income Taxes		3,114	2,862
Total Liabilities		14,696	15,278
Shareholders’ Equity		10,428	9,946
Total Liabilities and Shareholders’ Equity		25,124	25,224

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	50
Second Quarter 2014 Report	Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

($ millions)

	ShareCapital		Paid inSurplus	RetainedEarnings		AOCI (1)		Total
	(Note 17)					(Note 18)
Balance as at December 31, 2012	3,829		4,154	1,730		69		9,782
Net Earnings	—		—	350		—		350
Other Comprehensive Income (Loss)	—		—	—		89		89
Total Comprehensive Income	—		—	350		89		439
Common Shares Issued Under Stock Option Plans	21		—	—		—		21
Common Shares Cancelled	(3	)	3	—		—		—
Stock-Based Compensation Expense	—		31	—		—		31
Dividends on Common Shares	—		—	(367	)	—		(367	)
Balance as at June 30, 2013	3,847		4,188	1,713		158		9,906
Balance as at December 31, 2013	3,857		4,219	1,660		210		9,946
Net Earnings	—		—	862		—		862
Other Comprehensive Income (Loss)	—		—	—		(46	)	(46	)
Total Comprehensive Income	—		—	862		(46	)	816
Common Shares Issued Under Stock Option Plans	30		—	—		—		30
Stock-Based Compensation Expense	—		39	—		—		39
Dividends on Common Shares	—		—	(403	)	—		(403	)
Balance as at June 30, 2014	3,887		4,258	2,119		164		10,428

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	51
Second Quarter 2014 Report	Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the Period Ended June 30,

($ millions)

		Three Months Ended				Six Months Ended
	Notes	2014		2013		2014		2013
Operating Activities
Net Earnings		615		179		862		350
Depreciation, Depletion and Amortization		486		480		940		935
Exploration Expense		1		46		1		46
Deferred Income Taxes	7	216		40		252		79
Unrealized (Gain) Loss on Risk Management	21	11		(26	)	(15	)	204
Unrealized Foreign Exchange (Gain) Loss	6	(181	)	84		(38	)	134
(Gain) Loss on Divestitures of Assets	12	(20	)	—		(20	)	—
Unwinding of Discount on Decommissioning Liabilities	4,16	30		24		60		48
Other		31		44		51		46
		1,189		871		2,093		1,842
Net Change in Other Assets and Liabilities		(27	)	(31	)	(69	)	(65	)
Net Change in Non-Cash Working Capital		(53	)	(12	)	(458	)	(54	)
Cash From Operating Activities		1,109		828		1,566		1,723
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	10	(39	)	(53	)	(143	)	(221	)
Capital Expenditures — Property, Plant and Equipment	11	(653	)	(654	)	(1,378	)	(1,404	)
Proceeds From Divestiture of Assets	12	39		—		40		1
Net Change in Investments and Other	13	—		(4	)	(1,579	)	(6	)
Net Change in Non-Cash Working Capital		(39	)	(92	)	(29	)	(76	)
Cash (Used in) Investing Activities		(692	)	(803	)	(3,089	)	(1,706	)
Net Cash Provided (Used) Before Financing Activities		417		25		(1,523	)	17
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		(273	)	(1	)	153		(1	)
Proceeds on Issuance of Common Shares		4		1		26		19
Dividends Paid on Common Shares	8	(201	)	(183	)	(403	)	(367	)
Other		(1	)	—		(1	)	—
Cash From (Used in) Financing Activities		(471	)	(183	)	(225	)	(349	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(1	)	5		56		(3	)
Increase (Decrease) in Cash and Cash Equivalents		(55	)	(153	)	(1,692	)	(335	)
Cash and Cash Equivalents, Beginning of Period		815		978		2,452		1,160
Cash and Cash Equivalents, End of Period		760		825		760		825

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.	52
Second Quarter 2014 Report	Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

1.DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

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

Cenovus 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 preparation for these interim Consolidated Financial Statements is found in Note 2.

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

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

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

·Refining and Marketing, which is 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, research costs 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 operating and reportable segments shown above reflect the change in Cenovus’s operating structure adopted for the year ended December 31, 2013; as such, prior periods have been restated. In addition, research activities previously included in operating expense have been reclassified to conform to the presentation adopted for the year ended December 31, 2013.

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

Cenovus Energy Inc.	53
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

A) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the three months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	1,369	873		926	773		3,483	3,078
Less: Royalties	68	28		70	50		—	—
	1,301	845		856	723		3,483	3,078
Expenses
Purchased Product	—	—		—	—		3,098	2,616
Transportation and Blending	560	373		95	87		—	—
Operating	168	137		186	185		165	134
Production and Mineral Taxes	—	—		17	9		—	—
(Gain) Loss on Risk Management	35	(5	)	20	(19	)	—	4
Operating Cash Flow	538	340		538	461		220	324
Depreciation, Depletion and Amortization	152	99		275	328		38	33
Exploration Expense	1	—		—	109		—	—
Segment Income	385	241		263	24		182	291

	Corporate and Eliminations				Consolidated
For the three months ended June 30,	2014		2013		2014		2013
Revenues
Gross Sales	(218	)	(130	)	5,560		4,594
Less: Royalties	—		—		138		78
	(218	)	(130	)	5,422		4,516
Expenses
Purchased Product	(218	)	(130	)	2,880		2,486
Transportation and Blending	—		—		655		460
Operating	(1	)	(1	)	518		455
Production and Mineral Taxes	—		—		17		9
(Gain) Loss on Risk Management	11		(26	)	66		(46	)
	(10	)	27		1,286		1,152
Depreciation, Depletion and Amortization	21		20		486		480
Exploration Expense	—		—		1		109
Segment Income (Loss)	(31	)	7		799		563
General and Administrative	102		82		102		82
Finance Costs	102		124		102		124
Interest Income	(25	)	(23	)	(25	)	(23	)
Foreign Exchange (Gain) Loss, Net	(187	)	96		(187	)	96
Research Costs	4		6		4		6
(Gain) Loss on Divestiture of Assets	(20	)	—		(20	)	—
Other (Income) Loss, Net	(1	)	(2	)	(1	)	(2	)
	(25	)	283		(25	)	283
Earnings Before Income Tax					824		280
Income Tax Expense					209		101
Net Earnings					615		179

Cenovus Energy Inc.	54
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the three months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	1,345	856		708	607		2,053	1,463
Less: Royalties	67	27		67	48		134	75
	1,278	829		641	559		1,919	1,388
Expenses
Transportation and Blending	559	373		91	83		650	456
Operating	166	132		133	130		299	262
Production and Mineral Taxes	—	—		10	9		10	9
(Gain) Loss on Risk Management	35	(4	)	19	(10	)	54	(14	)
Operating Cash Flow	518	328		388	347		906	675

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional			Total
For the three months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	22	9		214	164		236	173
Less: Royalties	1	1		3	2		4	3
	21	8		211	162		232	170
Expenses
Transportation and Blending	1	—		4	4		5	4
Operating	5	3		52	55		57	58
Production and Mineral Taxes	—	—		7	—		7	—
(Gain) Loss on Risk Management	—	(1	)	1	(9	)	1	(10	)
Operating Cash Flow	15	6		147	112		162	118

	Other
	Oil Sands			Conventional		Total
For the three months ended June 30,	2014		2013	2014	2013	2014		2013
Revenues
Gross Sales	2		8	4	2	6		10
Less: Royalties	—		—	—	—	—		—
	2		8	4	2	6		10
Expenses
Transportation and Blending	—		—	—	—	—		—
Operating	(3	)	2	1	—	(2	)	2
Production and Mineral Taxes	—		—	—	—	—		—
(Gain) Loss on Risk Management	—		—	—	—	—		—
Operating Cash Flow	5		6	3	2	8		8

	Total Upstream
	Oil Sands			Conventional			Total
For the three months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	1,369	873		926	773		2,295	1,646
Less: Royalties	68	28		70	50		138	78
	1,301	845		856	723		2,157	1,568
Expenses
Transportation and Blending	560	373		95	87		655	460
Operating	168	137		186	185		354	322
Production and Mineral Taxes	—	—		17	9		17	9
(Gain) Loss on Risk Management	35	(5	)	20	(19	)	55	(24	)
Operating Cash Flow	538	340		538	461		1,076	801

Cenovus Energy Inc.	55
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

C) Geographic Information

	Canada			United States		Consolidated
For the three months ended June 30,	2014	2013		2014	2013	2014	2013
Revenues
Gross Sales	2,822	2,144		2,738	2,450	5,560	4,594
Less: Royalties	138	78		—	—	138	78
	2,684	2,066		2,738	2,450	5,422	4,516
Expenses
Purchased Product	519	491		2,361	1,995	2,880	2,486
Transportation and Blending	655	460		—	—	655	460
Operating	361	325		157	130	518	455
Production and Mineral Taxes	17	9		—	—	17	9
(Gain) Loss on Risk Management	63	(53	)	3	7	66	(46	)
	1,069	834		217	318	1,286	1,152
Depreciation, Depletion and Amortization	448	447		38	33	486	480
Exploration Expense	1	109		—	—	1	109
Segment Income	620	278		179	285	799	563

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.	56
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

D) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the six months ended June 30,	2014	2013		2014	2013		2014		2013
Revenues
Gross Sales	2,629	1,725		1,764	1,474		6,741		6,024
Less: Royalties	119	42		122	94		—		—
	2,510	1,683		1,642	1,380		6,741		6,024
Expenses
Purchased Product	—	—		—	—		5,918		4,893
Transportation and Blending	1,119	838		189	180		—		—
Operating	349	264		381	362		363		270
Production and Mineral Taxes	—	—		24	19		—		—
(Gain) Loss on Risk Management	57	(29	)	33	(57	)	(5	)	8
Operating Cash Flow	985	610		1,015	876		465		853
Depreciation, Depletion and Amortization	295	204		527	627		77		65
Exploration Expense	1	—		—	109		—		—
Segment Income	689	406		488	140		388		788

	Corporate and Eliminations				Consolidated
For the six months ended June 30,	2014		2013		2014		2013
Revenues
Gross Sales	(459	)	(252	)	10,675		8,971
Less: Royalties	—		—		241		136
	(459	)	(252	)	10,434		8,835
Expenses
Purchased Product	(459	)	(252	)	5,459		4,641
Transportation and Blending	—		—		1,308		1,018
Operating	(3	)	(2	)	1,090		894
Production and Mineral Taxes	—		—		24		19
(Gain) Loss on Risk Management	(15	)	204		70		126
	18		(202	)	2,483		2,137
Depreciation, Depletion and Amortization	41		39		940		935
Exploration Expense	—		—		1		109
Segment Income (Loss)	(23	)	(241	)	1,542		1,093
General and Administrative	211		165		211		165
Finance Costs	232		247		232		247
Interest Income	(27	)	(50	)	(27	)	(50	)
Foreign Exchange (Gain) Loss, Net	(40	)	148		(40	)	148
Research Costs	6		9		6		9
(Gain) Loss on Divestiture of Assets	(20	)	—		(20	)	—
Other (Income) Loss, Net	(2	)	—		(2	)	—
	360		519		360		519
Earnings Before Income Tax					1,182		574
Income Tax Expense					320		224
Net Earnings					862		350

Cenovus Energy Inc.	57
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

E) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the six months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	2,575	1,697		1,359	1,150		3,934	2,847
Less: Royalties	118	41		116	90		234	131
	2,457	1,656		1,243	1,060		3,700	2,716
Expenses
Transportation and Blending	1,118	838		180	169		1,298	1,007
Operating	336	255		278	254		614	509
Production and Mineral Taxes	—	—		18	18		18	18
(Gain) Loss on Risk Management	57	(27	)	32	(30	)	89	(57	)
Operating Cash Flow	946	590		735	649		1,681	1,239

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional			Total
For the six months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	49	16		398	319		447	335
Less: Royalties	1	1		6	4		7	5
	48	15		392	315		440	330
Expenses
Transportation and Blending	1	—		9	11		10	11
Operating	9	7		101	107		110	114
Production and Mineral Taxes	—	—		6	1		6	1
(Gain) Loss on Risk Management	—	(2	)	1	(27	)	1	(29	)
Operating Cash Flow	38	10		275	223		313	233

	Other
	Oil Sands		Conventional		Total
For the six months ended June 30,	2014	2013	2014	2013	2014	2013
Revenues
Gross Sales	5	12	7	5	12	17
Less: Royalties	—	—	—	—	—	—
	5	12	7	5	12	17
Expenses
Transportation and Blending	—	—	—	—	—	—
Operating	4	2	2	1	6	3
Production and Mineral Taxes	—	—	—	—	—	—
(Gain) Loss on Risk Management	—	—	—	—	—	—
Operating Cash Flow	1	10	5	4	6	14

	Total Upstream
	Oil Sands			Conventional			Total
For the six months ended June 30,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	2,629	1,725		1,764	1,474		4,393	3,199
Less: Royalties	119	42		122	94		241	136
	2,510	1,683		1,642	1,380		4,152	3,063
Expenses
Transportation and Blending	1,119	838		189	180		1,308	1,018
Operating	349	264		381	362		730	626
Production and Mineral Taxes	—	—		24	19		24	19
(Gain) Loss on Risk Management	57	(29	)	33	(57	)	90	(86	)
Operating Cash Flow	985	610		1,015	876		2,000	1,486

Cenovus Energy Inc.	58
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

F) Geographic Information

	Canada		United States			Consolidated
For the six months ended June 30,	2014	2013	2014		2013	2014	2013
Revenues
Gross Sales	5,637	4,196	5,038		4,775	10,675	8,971
Less: Royalties	241	136	—		—	241	136
	5,396	4,060	5,038		4,775	10,434	8,835
Expenses
Purchased Product	1,227	982	4,232		3,659	5,459	4,641
Transportation and Blending	1,308	1,018	—		—	1,308	1,018
Operating	743	633	347		261	1,090	894
Production and Mineral Taxes	24	19	—		—	24	19
(Gain) Loss on Risk Management	72	117	(2	)	9	70	126
	2,022	1,291	461		846	2,483	2,137
Depreciation, Depletion and Amortization	863	870	77		65	940	935
Exploration Expense	1	109	—		—	1	109
Segment Income	1,158	312	384		781	1,542	1,093

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 June 30, 2014 was $538 million and $223 million, respectively (three months ended June 30, 2013 — $291 million and $324 million). Cenovus’s share of operating cash flow from FCCL and WRB for the six months ended June 30, 2014 was $956 million and $468 million, respectively (six months ended June 30, 2013 — $512 million and $853 million).

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

By Segment

	E&E (1)		PP&E (2)
	June 30,	December 31,	June 30,	December 31,
As at	2014	2013	2014	2013
Oil Sands	1,458	1,328	8,065	7,401
Conventional	155	145	6,382	6,291
Refining and Marketing	—	—	3,273	3,269
Corporate and Eliminations	—	—	358	373
Consolidated	1,613	1,473	18,078	17,334

	Goodwill		Total Assets
	June 30,	December 31,	June 30,	December 31,
As at	2014	2013	2014	2013
Oil Sands	242	242	10,433	9,564
Conventional	497	497	7,418	7,220
Refining and Marketing	—	—	6,033	5,491
Corporate and Eliminations	—	—	1,240	2,949
Consolidated	739	739	25,124	25,224

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

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

Cenovus Energy Inc.	59
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

By Geographic Region

	E&E		PP&E
	June 30,	December 31,	June 30,	December 31,
As at	2014	2013	2014	2013
Canada	1,613	1,473	14,808	14,066
United States	—	—	3,270	3,268
Consolidated	1,613	1,473	18,078	17,334

	Goodwill		Total Assets
	June 30,	December 31,	June 30,	December 31,
As at	2014	2013	2014	2013
Canada	739	739	20,172	20,548
United States	—	—	4,952	4,676
Consolidated	739	739	25,124	25,224

I) Capital Expenditures (1)

	Three Months Ended		Six Months Ended
For the period ended June 30,	2014	2013	2014	2013
Capital
Oil Sands	471	420	998	957
Conventional	153	245	423	583
Refining and Marketing	46	26	69	51
Corporate	16	15	25	30
	686	706	1,515	1,621
Acquisition Capital
Oil Sands (2)	15	—	15	—
Conventional	1	1	2	4
	702	707	1,532	1,625

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

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

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

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

These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting” (“IAS 34”), and have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 2013, except for income taxes. Income taxes on earnings or loss in the interim periods are accrued using the income tax rate that would be applicable to the expected total annual earnings or loss. The disclosures provided are incremental to those included with the annual Consolidated Financial Statements. Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these interim Consolidated Financial Statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended December 31, 2013, which have been prepared in accordance with IFRS as issued by the IASB.

These interim Consolidated Financial Statements of Cenovus were approved by the Audit Committee effective July 29, 2014.

Cenovus Energy Inc.	60
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

3. RECENT ACCOUNTING PRONOUNCEMENTS

A) New and Amended Standards and Interpretations Adopted

Offsetting Financial Assets and Financial Liabilities

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

B) New Standards and Interpretations not yet Adopted

Revenue Recognition

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

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

Financial Instruments

On July 24, 2014, the IASB issued IFRS 9, “Financial Instruments” (“IFRS 9”) to replace International Accounting Standard 39, “Financial Instruments: Recognition and Measurement”. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the Consolidated Financial Statements.

Additional Standards

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, 2013.

4. FINANCE COSTS

	Three Months Ended		Six Months Ended
For the period ended June 30,	2014	2013	2014	2013
Interest Expense — Short-Term Borrowings and Long-Term Debt	70	66	141	132
Interest Expense — Partnership Contribution Payable (Note 13)	—	25	22	51
Unwinding of Discount on Decommissioning Liabilities (Note 16)	30	24	60	48
Other	2	9	9	16
	102	124	232	247

5. INTEREST INCOME

	Three Months Ended				Six Months Ended
For the period ended June 30,	2014		2013		2014		2013
Interest Income — Partnership Contribution Receivable	—		(22	)	—		(45	)
Other	(25	)	(1	)	(27	)	(5	)
	(25	)	(23	)	(27	)	(50	)

Cenovus Energy Inc.	61
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

6. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended				Six Months Ended
For the period ended June 30,	2014		2013		2014		2013
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	(177	)	169		19		267
U.S. Dollar Partnership Contribution Receivable Issued From Canada	—		(72	)	—		(123	)
Other	(4	)	(13	)	(57	)	(10	)
Unrealized Foreign Exchange (Gain) Loss	(181	)	84		(38	)	134
Realized Foreign Exchange (Gain) Loss	(6	)	12		(2	)	14
	(187	)	96		(40	)	148

7. INCOME TAXES

The provision for income taxes is:

	Three Months Ended			Six Months Ended
For the period ended June 30,	2014		2013	2014	2013
Current Tax
Canada	(10	)	57	33	87
United States	3		4	35	58
Total Current Tax	(7	)	61	68	145
Deferred Tax	216		40	252	79
	209		101	320	224

8. PER SHARE AMOUNTS

A) Net Earnings Per Share

	Three Months Ended				Six Months Ended
For the period ended June 30,	2014		2013		2014		2013
Net Earnings — Basic and Diluted ($ millions)	615		179		862		350
Basic — Weighted Average Number of Shares (millions)	756.9		755.8		756.7		755.9
Dilutive Effect of Cenovus TSARs (1)	0.9		1.3		0.9		1.9
Dilutive Effect of Cenovus NSRs (2)	0.2		—		—		—
Diluted — Weighted Average Number of Shares	758.0		757.1		757.6		757.8
Net Earnings Per Common Share ($)
Basic	$	0.81	$	0.24	$	1.14	$	0.46
Diluted	$	0.81	$	0.24	$	1.14	$	0.46

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

(2) Net settlement rights (“NSRs”).

B) Dividends Per Share

The Company paid dividends of $403 million or $0.5324 per share for the six months ended June 30, 2014 (June 30, 2013 — $367 million, $0.484 per share). The Cenovus Board of Directors declared a third quarter dividend of $0.2662 per share, payable on September 30, 2014, to common shareholders of record as of September 15, 2014.

Cenovus Energy Inc.	62
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

9. INVENTORIES

	June 30,	December 31,
As at	2014	2013
Product
Refining and Marketing	1,428	1,047
Oil Sands	167	156
Conventional	13	17
Parts and Supplies	39	39
	1,647	1,259

10. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2012	1,285
Additions	331
Transfers to PP&E (Note 11)	(95	)
Exploration Expense	(50	)
Divestitures	(17	)
Change in Decommissioning Liabilities	19
As at December 31, 2013	1,473
Additions	143
Transfers to PP&E (Note 11)	(25	)
Exploration Expense	(1	)
Change in Decommissioning Liabilities	23
As at June 30, 2014	1,613

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

Additions to E&E assets for the six months ended June 30, 2014 include $28 million of internal costs directly related to the evaluation of these projects (year ended December 31, 2013 — $60 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 six months ended June 30, 2014 or for the year ended December 31, 2013.

For the six months ended June 30, 2014, $25 million of E&E assets were transferred to PP&E — development and production assets following the determination of technical feasibility and commercial viability of the projects (year ended December 31, 2013 — $95 million).

Impairment

The impairment of E&E assets and any subsequent reversal of such impairment losses are recognized in exploration expense in the Consolidated Statements of Earnings and Comprehensive Income. For the year ended December 31, 2013, $50 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.

Cenovus Energy Inc.	63
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

11. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production		OtherUpstream	RefiningEquipment		Other (1)	Total
COST
As at December 31, 2012	27,003		238	3,399		767	31,407
Additions	2,702		48	106		82	2,938
Transfers From E&E Assets (Note 10)	95		—	—		—	95
Transfers and Reclassifications	(450	)	—	(88	)	—	(538	)
Change in Decommissioning Liabilities	40		—	(1	)	—	39
Exchange Rate Movements	—		—	238		—	238
As at December 31, 2013	29,390		286	3,654		849	34,179
Additions (2)	1,275		20	69		25	1,389
Transfers From E&E Assets (Note 10)	25		—	—		—	25
Transfers and Reclassifications	(55	)	—	(1	)	1	(55	)
Change in Decommissioning Liabilities	287		—	—		—	287
Exchange Rate Movements	—		—	12		—	12
Divestitures	(2	)	—	—		—	(2	)
As at June 30, 2014	30,920		306	3,734		875	35,835
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2012	14,390		158	311		396	15,255
Depreciation, Depletion and Amortization	1,522		35	138		79	1,774
Transfers and Reclassifications	(123	)	—	(88	)	—	(211	)
Impairment Losses	2		—	—		—	2
Exchange Rate Movements	—		—	25		—	25
As at December 31, 2013	15,791		193	386		475	16,845
Depreciation, Depletion and Amortization	792		17	77		41	927
Transfers and Reclassifications	(27	)	—	(1	)	—	(28	)
Impairment (gains) losses	13		—	—		—	13
As at June 30, 2014	16,569		210	462		516	17,757
CARRYING VALUE
As at December 31, 2012	12,613		80	3,088		371	16,152
As at December 31, 2013	13,599		93	3,268		374	17,334
As at June 30, 2014	14,351		96	3,272		359	18,078

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

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

Additions to development and production assets include internal costs directly related to the development and construction of crude oil and natural gas properties of $123 million for the six months ended June 30, 2014 (year ended December 31, 2013 — $204 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 six months ended June 30, 2014 or for the year ended December 31, 2013.

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

	June 30,	December 31,
As at	2014	2013
Development and Production	351	225
Refining Equipment	126	97
	477	322

Cenovus Energy Inc.	64
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

Impairment

The impairment of PP&E and any subsequent reversal of such impairment losses are recognized in depreciation, depletion and amortization in the Consolidated Statements of Earnings and Comprehensive Income. In the second quarter, a minor natural gas property was shut-in and abandonment commenced. The remaining book value of $13 million has been charged to DD&A in the Conventional segment for the period ended June 30, 2014. There were no impairment losses recognized in 2013.

12. DIVESTITURES

In the second quarter, the Company completed the sale of certain Bakken properties to an unrelated third party for proceeds of $36 million before closing adjustments. A gain of $16 million was recorded on the sale in the second quarter. These assets, related liabilities and results of operations were reported in the Conventional segment. The Company also completed the sale of certain non-core properties and recognized a total gain of $4 million. These assets and related liabilities were reported in the Conventional segment.

13. PARTNERSHIP CONTRIBUTION PAYABLE

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

14. SHORT-TERM BORROWINGS

The Company had short-term borrowings in the form of commercial paper in the amount of $152 million as at June 30, 2014 (December 31, 2013 — $nil). The Company reserves capacity under its committed credit facility for amounts of commercial paper outstanding.

15. LONG-TERM DEBT

	June 30,		December 31,
As at	2014		2013
Revolving Term Debt (1)	—		—
U.S. Dollar Denominated Unsecured Notes	5,071		5,052
Total Debt Principal	5,071		5,052
Debt Discounts and Transaction Costs	(53	)	(55	)
	5,018		4,997

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

As at June 30, 2014, the Company is in compliance with all of the terms of its debt agreements.

On June 24, 2014, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion. The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at June 30, 2014, no notes have been issued under this U.S. base shelf prospectus. The U.S. base shelf prospectus expires in July 2016.

On June 25, 2014, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. The Canadian base shelf prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue. As at June 30, 2014, no medium term notes have been issued under this Canadian base shelf prospectus. The Canadian base shelf prospectus expires in July 2016.

Cenovus Energy Inc.	65
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

16. DECOMMISSIONING LIABILITIES

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

	June 30,		December 31,
As at	2014		2013
Decommissioning Liabilities, Beginning of Year	2,370		2,315
Liabilities Incurred	35		45
Liabilities Settled	(50	)	(76	)
Transfers and Reclassifications	(9	)	(26	)
Change in Estimated Future Cash Flows	28		414
Change in Discount Rate	257		(401	)
Unwinding of Discount on Decommissioning Liabilities	60		97
Foreign Currency Translation	—		2
Decommissioning Liabilities, End of Period	2,691		2,370

The undiscounted amount of estimated future cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 4.6 percent as at June 30, 2014 (December 31, 2013 — 5.2 percent).

17. 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

	June 30, 2014		December 31, 2013
	Number of		Number of
	Common		Common
	Shares		Shares
As at	(Thousands)	Amount	(Thousands)		Amount
Outstanding, Beginning of Year	756,046	3,857	755,843		3,829
Common Shares Issued Under Stock Option Plans	988	30	970		31
Common Shares Cancelled	—	—	(767	)	(3	)
Outstanding, End of Period	757,034	3,887	756,046		3,857

There were no preferred shares outstanding as at June 30, 2014 (December 31, 2013 — nil).

As at June 30, 2014, there were 12 million (December 31, 2013 — 24 million) common shares available for future issuance under stock option plans.

Cenovus Energy Inc.	66
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

18. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at June 30, 2014	Defined Benefit Plan		Foreign Currency Translation		Availablefor Sale Investments	Total
Balance, Beginning of Year	(12	)	212		10	210
Other Comprehensive Income, Before Tax	(7	)	(41	)	—	(48	)
Income Tax	2		—		—	2
Balance, End of Period	(17	)	171		10	164

As at June 30, 2013	Defined Benefit Plan		Foreign Currency Translation	Availablefor Sale Investments		Total
Balance, Beginning of Year	(26	)	95	—		69
Other Comprehensive Income, Before Tax	11		72	10		93
Income Tax	(2	)	—	(2	)	(4	)
Balance, End of Period	(17	)	167	8		158

19. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Option Plan

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

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

As at June 30, 2014	Issued	Term(Years)	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price ($)	Closing Share Price ($)	Number ofUnitsOutstanding (Thousands)
NSRs	On or After February 24, 2011	7	5.60	32.71	34.59	41,290
TSARs	Prior to February 17, 2010	5	0.49	26.20	34.59	44
TSARs	On or After February 17, 2010	7	2.70	26.73	34.59	4,072
Encana (1)Replacement TSARs Held by Cenovus Employees	Prior to December 1, 2009	5	0.27	30.23	25.28	48
Cenovus Replacement TSARs Held by Encana Employees	Prior to December 1, 2009	5	0.37	27.84	34.59	3

(1) Encana Corporation (“Encana”).

NSRs

The weighted average unit fair value of NSRs granted during the six months ended June 30, 2014 was $4.69 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model.

The following table summarizes information related to the NSRs:

As at June 30, 2014	Number of NSRs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	26,315		35.26
Granted	15,741		28.53
Exercised	(77	)	32.34
Forfeited	(689	)	34.69
Outstanding, End of Period	41,290		32.71
Exercisable, End of Period	13,137		36.45

Cenovus Energy Inc.	67
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $34.02.

TSARs Held by Cenovus Employees

The Company has recorded a liability of $31 million at June 30, 2014 (December 31, 2013 — $33 million) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. The intrinsic value of vested TSARs held by Cenovus employees at June 30, 2014 was $30 million (December 31, 2013 — $27 million).

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

As at June 30, 2014	Number of TSARs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	7,086		26.56
Exercised for Cash Payment	(1,939	)	26.32
Exercised as Options for Common Shares	(977	)	26.33
Forfeited	(2	)	28.36
Expired	(52	)	26.38
Outstanding, End of Period	4,116		26.73
Exercisable, End of Period	4,116		26.73

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $29.82.

Encana Replacement TSARs Held by Cenovus Employees

Cenovus is required to reimburse Encana for cash payments made by Encana to Cenovus employees when a Cenovus employee exercises an Encana replacement TSAR for cash. No further Encana replacement TSARs will be granted to Cenovus employees.

The Company has recorded a liability of $nil at June 30, 2014 (December 31, 2013 — $nil) in the Consolidated Balance Sheets 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 June 30, 2014 was $nil (December 31, 2013 — $nil).

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

As at June 30, 2014	Number of TSARs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	3,904		29.06
Forfeited	(84	)	29.06
Expired	(3,772	)	29.05
Outstanding, End of Period	48		30.23
Exercisable, End of Period	48		30.23

The closing price of Encana common shares on the TSX as at June 30, 2014 was $25.28.

Cenovus Replacement TSARs Held by Encana Employees

Encana is required to reimburse Cenovus for 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 $nil as at June 30, 2014 (December 31, 2013 — $6 million) in the Consolidated Balance Sheets 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 June 30, 2014 was $nil (December 31, 2013 — $6 million).

Cenovus Energy Inc.	68
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

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

As at June 30, 2014	Number of TSARs(Thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	1,479		26.28
Exercised for Cash Payment	(1,406	)	26.28
Exercised as Options for Common Shares	(9	)	26.32
Forfeited	—		26.27
Expired	(61	)	26.27
Outstanding, End of Period	3		27.84
Exercisable, End of Period	3		27.84

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $29.27.

B) Performance Share Units

The Company has recorded a liability of $127 million at June 30, 2014 (December 31, 2013 — $103 million) in the Consolidated Balance Sheets for performance share units (“PSUs”) based on the market value of Cenovus’s common shares at June 30, 2014. The intrinsic value of vested PSUs was $nil at June 30, 2014 and December 31, 2013 as PSUs are paid out upon vesting.

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

As at June 30, 2014	Number of PSUs(Thousands)
Outstanding, Beginning of Year	5,785
Granted	2,998
Vested and Paid Out	(1,625	)
Cancelled	(162	)
Units in Lieu of Dividends	114
Outstanding, End of Period	7,110

C) Deferred Share Units

The Company has recorded a liability of $44 million at June 30, 2014 (December 31, 2013 — $36 million) in the Consolidated Balance Sheets for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares at June 30, 2014. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

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

As at June 30, 2014	Number of DSUs(Thousands)
Outstanding, Beginning of Year	1,192
Granted to Directors	54
Granted From Annual Bonus Awards	7
Units in Lieu of Dividends	21
Outstanding, End of Period	1,274

Cenovus Energy Inc.	69
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

D) Total Stock-Based Compensation Expense (Recovery)

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

	Three Months Ended			Six Months Ended
For the period ended June 30,	2014	2013		2014	2013
NSRs	11	9		24	16
TSARs Held by Cenovus Employees	4	(6	)	4	(14	)
PSUs	15	1		47	16
DSUs	3	(1	)	7	(1	)
Stock-Based Compensation Expense (Recovery)	33	3		82	17

20. CAPITAL STRUCTURE

Cenovus’s capital structure objectives and targets have remained unchanged from previous periods. Cenovus’s capital structure consists of Shareholders’ Equity plus Debt. Debt is defined as short-term borrowings and the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable. Cenovus’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due.

Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”). These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

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

	June 30,		December 31,
As at	2014		2013
Short-Term Borrowings	152		—
Long-Term Debt	5,018		4,997
Debt	5,170		4,997
Shareholders’ Equity	10,428		9,946
Capitalization	15,598		14,943
Debt to Capitalization	33	%	33	%

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

	June 30,		December 31,
As at	2014		2013
Debt	5,170		4,997
Net Earnings	1,174		662
Add (Deduct):
Finance Costs	514		529
Interest Income	(73	)	(96	)
Income Tax Expense	528		432
Depreciation, Depletion and Amortization	1,838		1,833
E&E Impairment	6		50
Unrealized (Gain) Loss on Risk Management	196		415
Foreign Exchange (Gain) Loss, Net	20		208
(Gain) Loss on Divestitures of Assets	(19	)	1
Other (Income) Loss, Net	—		2
Adjusted EBITDA (1)	4,184		4,036
Debt to Adjusted EBITDA	1.2x		1.2x

(1)Calculated on a trailing 12 month basis.

Cenovus Energy Inc.	70
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

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.

As at June 30, 2014, Cenovus had $2.8 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.

As at June 30, 2014, Cenovus is in compliance with all of the terms of its debt agreements.

21. FINANCIAL INSTRUMENTS

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

A) Fair Value of Non-Derivative Financial Instruments

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

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

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period end trading prices of long-term borrowings on the secondary market (Level 2). As at June 30, 2014, the carrying value of Cenovus’s long-term debt was $5,018 million and the fair value was $5,754 million (December 31, 2013 carrying value — $4,997 million, fair value — $5,388 million).

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

	June 30,		December 31,
As at	2014		2013
Fair Value, Beginning of Year	32		14
Acquisition of Investments	3		5
Reclassification of Equity Investments	(4	)	—
Change in Fair Value (1)	—		13
Fair Value, End of Period	31		32

(1) Unrealized gains and losses on available for sale financial assets are recorded in Other Comprehensive Income.

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, natural gas and power purchase contracts. Crude oil and natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period end forward price for the same commodity, using quoted market prices or the period end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of power purchase contracts are calculated internally based on observable and unobservable inputs such as forward power prices in less active markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness. The forward prices used in the determination of the fair value of the power purchase contracts at June 30, 2014 range from $49.00 to $67.00 per Megawatt Hour.

Cenovus Energy Inc.	71
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

Summary of Unrealized Risk Management Positions

	June 30, 2014				December 31, 2013
	Risk Management				Risk Management
As at	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Crude Oil	1	115	(114	)	10	136	(126	)
Natural Gas	2	—	2		—	—	—
Power	—	2	(2	)	—	3	(3	)
Total Fair Value	3	117	(114	)	10	139	(129	)

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

	June 30,		December 31,
As at	2014		2013
Prices Sourced From Observable Data or Market Corroboration (Level 2)	(112	)	(126	)
Prices Determined From Unobservable Inputs (Level 3)	(2	)	(3	)
	(114	)	(129	)

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data. Prices determined from unobservable inputs refers to the fair value of contracts valued using data that is both unobservable and significant to the overall fair value measurement.

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities from January 1 to June 30:

	2014		2013
Fair Value of Contracts, Beginning of Year	(129	)	270
Fair Value of Contracts Realized During the Period	85		(78	)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Period	(70	)	(126	)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	—		14
Fair Value of Contracts, End of Period	(114	)	80

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

	Three Months Ended			Six Months Ended
For the period ended June 30,	2014	2013		2014		2013
Realized (Gain) Loss (1)	55	(20	)	85		(78	)
Unrealized (Gain) Loss (2)	11	(26	)	(15	)	204
(Gain) Loss on Risk Management	66	(46	)	70		126

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

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

22. RISK MANAGEMENT

The Company is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk. A description of the nature and extent of risks arising from the Company’s financial assets and liabilities can be found in the notes to the annual Consolidated Financial Statements as at December 31, 2013. The Company’s exposure to these risks has not changed significantly since December 31, 2013.

Cenovus Energy Inc.	72
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended June 30, 2014

Net Fair Value of Commodity Price Positions as at June 30, 2014

As at June 30, 2014	Notional Volumes	Term	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	30,000 bbls/d	2014	US$102.04/bbl	(54	)
Brent Fixed Price	20,000 bbls/d	2014	$107.06/bbl	(44	)
WCS Differential (1)	12,900 bbls/d	2014	US$(20.76)/bbl	1
Brent Fixed Price	18,000 bbls/d	2015	$113.75/bbl	(12	)
Brent Collars	10,000 bbls/d	2015	$105.25 - $123.57/bbl	(2	)
Other Financial Positions (2)				(3	)
Crude Oil Fair Value Position				(114	)
Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price	95 MMcf/d	2014	$4.61/Mcf	2
Natural Gas Fair Value Position				2
Power Purchase Contracts
Power Fair Value Position				(2	)

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

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

Commodity Price Sensitivities — Risk Management Positions

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices on the Company’s open risk management positions as at June 30 could have resulted in unrealized gains (losses) impacting earnings before income tax for the six months ended June 30, 2014:

Risk Management Positions in Place as at June 30, 2014

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent, WTI and Condensate Hedges	(191	)	189
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges Tied to Production	13		(13	)
Natural Gas Commodity Price	± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges	(19	)	19
Power Commodity Price	± $25 per MWHr Applied to Power Hedge	19		(19	)

23. COMMITMENTS AND CONTINGENCIES

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.	73
Second Quarter 2014 Report	Notes to Consolidated Financial Statements

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

	2014						2013
	Year												Q2 Year
Revenues	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2		Q1
Gross Sales
Upstream	4,393		2,295		2,098		6,892		1,767		1,926		3,199		1,646		1,553
Refining and Marketing	6,741		3,483		3,258		12,706		3,223		3,459		6,024		3,078		2,946
Corporate and Eliminations	(459	)	(218	)	(241	)	(605	)	(163	)	(190	)	(252	)	(130	)	(122	)
Less: Royalties	241		138		103		336		80		120		136		78		58
Revenues	10,434		5,422		5,012		18,657		4,747		5,075		8,835		4,516		4,319

	2014				2013
	Year							Q2 Year
Operating Cash Flow	to Date	Q2	Q1		Year	Q4	Q3	to Date	Q2	Q1
Crude Oil and Natural Gas Liquids
Foster Creek	440	227	213		877	204	252	421	232	189
Christina Lake	506	291	215		596	179	248	169	96	73
Pelican Lake	212	119	93		385	92	130	163	96	67
Other Conventional	523	269	254		1,003	232	285	486	251	235
Natural Gas	313	162	151		437	110	94	233	118	115
Other Upstream Operations	6	8	(2	)	27	8	5	14	8	6
	2,000	1,076	924		3,325	825	1,014	1,486	801	685
Refining and Marketing	465	220	245		1,143	151	139	853	324	529
Operating Cash Flow (1)	2,465	1,296	1,169		4,468	976	1,153	2,339	1,125	1,214

	2014						2013
	Year												Q2 Year
Cash Flow	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2		Q1
Cash from Operating Activities	1,566		1,109		457		3,539		976		840		1,723		828		895
Deduct (Add back):
Net Change in Other Assets and Liabilities	(69	)	(27	)	(42	)	(120	)	(30	)	(25	)	(65	)	(31	)	(34	)
Net Change in Non-Cash Working Capital	(458	)	(53	)	(405	)	50		171		(67	)	(54	)	(12	)	(42	)
Cash Flow (2)	2,093		1,189		904		3,609		835		932		1,842		871		971
Per Share    - Basic	2.77		1.57		1.20		4.77		1.10		1.23		2.44		1.15		1.28
- Diluted	2.76		1.57		1.19		4.76		1.10		1.23		2.43		1.15		1.28

	2014			2013
	Year							Q2 Year
Earnings	to Date	Q2	Q1	Year	Q4		Q3	to Date	Q2	Q1
Operating Earnings (3)	851	473	378	1,171	212		313	646	255	391
Per Share    - Diluted	1.12	0.62	0.50	1.55	0.28		0.41	0.85	0.34	0.52
Net Earnings (Loss)	862	615	247	662	(58	)	370	350	179	171
Per Share    - Basic	1.14	0.81	0.33	0.88	(0.08	)	0.49	0.46	0.24	0.23
- Diluted	1.14	0.81	0.33	0.87	(0.08	)	0.49	0.46	0.24	0.23

	2014				2013
	Year								Q2 Year
Tax & Exchange Rates	to Date		Q2	Q1	Year		Q4	Q3	to Date	Q2	Q1
Effective Tax Rates using
Net Earnings	27.1	%			39.5	%
Operating Earnings, excluding Divestitures	27.0	%			31.4	%
Canadian Statutory Rate	25.2	%			25.2	%
U.S. Statutory Rate	38.5	%			38.5	%
Foreign Exchange Rates (US$ per C$1)
Average	0.912		0.917	0.906	0.971		0.953	0.963	0.984	0.977	0.992
Period end	0.937		0.937	0.905	0.940		0.940	0.972	0.951	0.951	0.985

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

(2)       Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows.

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

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

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

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

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

(7)We define Adjusted EBITDA as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing 12 month basis.

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

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

Cenovus Energy Inc.	74
Second Quarter 2014 Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

	2014						2013
	Year												Q2 Year
Common Share Information	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2		Q1
Common Shares Outstanding (millions)
Period End	757.0		757.0		756.9		756.0		756.0		755.8		755.8		755.8		755.8
Average - Basic	756.7		756.9		756.4		755.9		755.9		755.8		755.9		755.8		756.0
Average - Diluted	757.6		758.0		757.3		757.5		757.2		757.2		757.8		757.1		758.4
Price Range ($ per share)
TSX - C$
High	34.70		34.70		32.02		34.13		31.69		32.77		34.13		32.08		34.13
Low	28.25		30.80		28.25		28.32		29.33		28.98		28.32		28.32		31.09
Close	34.59		34.59		31.97		30.40		30.40		30.74		30.00		30.00		31.46
NYSE - US$
High	32.44		32.44		28.96		34.50		30.34		31.60		34.50		31.58		34.50
Low	25.52		28.35		25.52		27.25		27.60		28.00		27.25		27.25		30.58
Close	32.37		32.37		28.96		28.65		28.65		29.85		28.52		28.52		30.99
Dividends Paid ($ per share)	$	0.5324	$	0.2662	$	0.2662	$	0.968	$	0.242	$	0.242	$	0.484	$	0.242	$	0.242
Share Volume Traded (millions)	322.9		152.7		170.3		685.7		146.2		183.0		356.4		201.6		154.9

	2014						2013
	Year												Q2 Year
Net Capital Investment	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2	Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	430		209		221		797		193		205		399		189	210
Christina Lake	365		183		182		688		189		162		337		162	175
Total	795		392		403		1,485		382		367		736		351	385
Other Oil Sands	203		79		124		400		120		59		221		69	152
	998		471		527		1,885		502		426		957		420	537
Conventional
Pelican Lake	139		68		71		463		115		97		251		111	140
Other Conventional	284		85		199		726		216		178		332		134	198
	423		153		270		1,189		331		275		583		245	338
Refining and Marketing	69		46		23		107		37		19		51		26	25
Corporate	25		16		9		81		28		23		30		15	15
Capital Investment	1,515		686		829		3,262		898		743		1,621		706	915
Acquisitions (1)	17		16		1		32		27		1		4		1	3
Divestitures	(41	)	(39	)	(2	)	(283	)	(41	)	(241	)	(1	)	—	(1	)
Net Acquisition and Divestiture Activity	(24	)	(23	)	(1	)	(251	)	(14	)	(240	)	3		1	2
Net Capital Investment	1,491		663		828		3,011		884		503		1,624		707	917

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

Operating Statistics - Before Royalties

	2014			2013
	Year						Q2 Year
Upstream Production Volumes	to Date	Q2	Q1	Year	Q4	Q3	to Date	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands - Heavy Oil
Foster Creek	55,785	56,852	54,706	53,190	52,419	49,092	55,665	55,338	55,996
Christina Lake	66,863	67,975	65,738	49,310	61,471	52,732	41,388	38,459	44,351
	122,648	124,827	120,444	102,500	113,890	101,824	97,053	93,797	100,347
Conventional Liquids
Pelican Lake - Heavy Oil	24,794	24,806	24,782	24,254	24,528	24,826	23,824	23,959	23,687
Other Heavy Oil	15,756	15,498	16,017	15,991	15,480	15,507	16,497	16,284	16,712
Light and Medium Oil	34,966	35,329	34,598	35,467	33,646	33,651	37,317	36,137	38,508
Natural Gas Liquids (2)	1,121	1,228	1,013	1,063	1,199	1,130	961	950	971
	76,637	76,861	76,410	76,775	74,853	75,114	78,599	77,330	79,878
Total Crude Oil and Natural Gas Liquids	199,285	201,688	196,854	179,275	188,743	176,938	175,652	171,127	180,225
Natural Gas (MMcf/d)
Oil Sands	21	23	19	21	21	23	20	22	18
Conventional	471	484	457	508	493	500	520	514	527
Total Natural Gas	492	507	476	529	514	523	540	536	545
Total Production (BOE/d)	281,285	286,188	276,187	267,442	274,410	264,105	265,652	260,460	271,058

(2)    Natural gas liquids include condensate volumes.

Average Royalty Rates	2014						2013
(excluding impact of Realized Gain	Year												Q2 Year
(Loss) on Risk Management)	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2		Q1
Oil Sands
Foster Creek	8.7	%	9.3	%	8.1	%	5.8	%	6.3	%	7.6	%	4.5	%	5.7	%	2.9	%
Christina Lake	7.4	%	7.7	%	7.1	%	6.8	%	7.8	%	7.0	%	5.6	%	5.6	%	5.7	%
Conventional
Pelican Lake	7.5	%	8.0	%	6.9	%	5.9	%	3.2	%	7.7	%	6.0	%	5.8	%	6.2	%
Weyburn	22.0	%	24.4	%	19.4	%	19.6	%	16.8	%	22.3	%	19.3	%	20.3	%	18.3	%
Other	5.2	%	5.5	%	4.9	%	6.5	%	7.4	%	6.8	%	5.9	%	6.0	%	5.7	%
Natural Gas Liquids	2.2	%	2.2	%	2.2	%	1.9	%	1.9	%	2.9	%	1.1	%	2.5	%	0.2	%
Natural Gas	1.7	%	2.0	%	1.4	%	1.4	%	1.2	%	1.8	%	1.4	%	1.2	%	1.7	%

Cenovus Energy Inc.	75
Second Quarter 2014 Report	Supplemental Information

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

	2014						2013
	Year												Q2 Year
Refining	to Date		Q2		Q1		Year		Q4		Q3		to Date		Q2		Q1
Refinery Operations (1)
Crude Oil Capacity (2) (Mbbls/d)	460		460		460		457		457		457		457		457		457
Crude Oil Runs (Mbbls/d)	433		466		400		442		447		464		428		439		416
Heavy Oil	208		221		195		222		221		240		214		230		197
Light/Medium	225		245		205		220		226		224		214		209		219
Crude Utilization	94	%	101	%	87	%	97	%	98	%	101	%	94	%	96	%	91	%
Refined Products (Mbbls/d)	458		489		420		463		469		487		448		457		439

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

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

	2014						2013
	Year										Q2 Year
Selected Average Benchmark Prices	to Date		Q2		Q1		Year		Q4	Q3	to Date		Q2		Q1
Crude Oil Prices (US$/bbl)
Brent	108.83		109.77		107.90		108.76		109.35	109.71	108.00		103.35		112.65
West Texas Intermediate (“WTI”)	100.84		102.99		98.68		97.97		97.46	105.82	94.30		94.22		94.37
Differential Brent Futures-WTI	7.99		6.78		9.22		10.79		11.89	3.89	13.70		9.13		18.28
Western Canadian Select (“WCS”)	79.25		82.95		75.55		72.77		65.26	88.34	68.74		75.06		62.41
Differential - WTI-WCS	21.59		20.04		23.13		25.20		32.20	17.48	25.56		19.16		31.96
Condensate - (C5 @ Edmonton)	103.90		105.15		102.64		101.69		94.22	103.80	104.37		101.50		107.24
Differential - WTI-Condensate (premium)/discount	(3.06	)	(2.16	)	(3.96	)	(3.72	)	3.24	2.02	(10.07	)	(7.28	)	(12.87	)
Refining Margins 3-2-1 Crack Spreads (3)(US$/bbl)
Chicago	19.13		19.72		18.55		21.77		12.29	16.19	29.30		31.06		27.53
Midwest Combined (Group 3)	17.58		17.75		17.41		20.80		10.66	17.35	27.59		27.24		27.93
Natural Gas Prices
AECO ($/Mcf)	4.72		4.67		4.76		3.17		3.15	2.82	3.33		3.59		3.08
NYMEX (US$/Mcf)	4.80		4.67		4.94		3.65		3.60	3.58	3.71		4.09		3.34
Differential - NYMEX-AECO (US$/Mcf)	0.50		0.40		0.60		0.58		0.59	0.89	0.42		0.56		0.27

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

Per-unit Results	2014			2013
(excluding impact of Realized Gain	Year						Q2 Year
(Loss) on Risk Management)	to Date	Q2	Q1	Year	Q4	Q3	to Date	Q2	Q1
Heavy Oil - Foster Creek (4)($/bbl)
Price	75.62	79.77	71.44	66.30	59.39	87.49	60.21	68.17	52.60
Royalties	6.43	7.14	5.71	3.73	3.56	6.31	2.64	3.87	1.47
Transportation and Blending	1.94	3.10	0.78	2.36	3.21	4.37	0.99	0.04	1.89
Operating	19.24	19.38	19.09	15.77	15.90	17.12	15.08	16.19	14.03
Netback	48.01	50.15	45.86	44.44	36.72	59.69	41.50	48.07	35.21
Heavy Oil - Christina Lake(4) ($/bbl)
Price	66.18	72.25	59.89	51.26	44.36	74.98	41.94	52.61	33.41
Royalties	4.72	5.37	4.04	3.25	3.22	5.06	2.15	2.71	1.69
Transportation and Blending	3.08	3.14	3.02	3.55	3.29	3.16	4.02	4.45	3.67
Operating	12.68	12.08	13.30	12.47	10.57	11.46	14.66	16.83	12.93
Netback	45.70	51.66	39.53	31.99	27.28	55.30	21.11	28.62	15.12
Total Heavy Oil - Oil Sands(4) ($/bbl)
Price	70.48	75.65	65.19	59.10	51.34	81.16	52.41	61.88	44.01
Royalties	5.50	6.17	4.80	3.50	3.37	5.68	2.43	3.40	1.57
Transportation and Blending	2.56	3.12	1.99	2.93	3.25	3.76	2.28	1.82	2.69
Operating	15.67	15.38	15.96	14.19	13.04	14.26	14.90	16.45	13.53
Netback	46.75	50.98	42.44	38.48	31.68	57.46	32.80	40.21	26.22
Heavy Oil - Pelican Lake(4) ($/bbl)
Price	80.50	84.66	76.20	70.09	64.52	88.08	63.52	72.32	54.30
Royalties	5.78	6.50	5.04	4.00	1.97	6.64	3.66	4.08	3.22
Transportation and Blending	3.10	3.13	3.07	2.41	2.79	2.18	2.33	2.58	2.07
Operating	23.06	21.23	24.96	20.65	21.22	19.90	20.75	22.21	19.23
Netback	48.56	53.80	43.13	43.03	38.54	59.36	36.78	43.45	29.78
Heavy Oil - Other Conventional (4)($/bbl)
Price	81.61	81.09	82.14	70.65	64.58	86.58	66.02	70.81	61.62
Royalties	8.65	9.77	7.52	9.18	10.40	12.27	7.10	7.67	6.57
Transportation and Blending	3.54	3.94	3.13	2.90	2.54	3.04	3.01	2.59	3.39
Operating	20.78	19.74	21.81	17.34	17.54	16.32	17.72	17.38	18.04
Production and Mineral Taxes	0.58	0.84	0.32	0.31	0.12	0.55	0.30	0.30	0.30
Netback	48.06	46.80	49.36	40.92	33.98	54.40	37.89	42.87	33.32
Total Heavy Oil - Conventional (4)($/bbl)
Price	80.93	83.29	78.52	70.31	64.55	87.50	64.55	71.73	57.42
Royalties	6.90	7.76	6.01	6.08	5.31	8.83	5.07	5.50	4.65
Transportation and Blending	3.27	3.44	3.09	2.60	2.69	2.51	2.61	2.58	2.63
Operating	22.18	20.66	23.73	19.32	19.76	18.51	19.51	20.30	18.72
Production and Mineral Taxes	0.23	0.32	0.13	0.13	0.05	0.21	0.12	0.12	0.13
Netback	48.35	51.11	45.56	42.18	36.74	57.44	37.24	43.23	31.29
Total Heavy Oil (4) ($/bbl)
Price	73.19	77.63	68.64	62.23	54.61	82.97	55.99	64.91	47.82
Royalties	5.86	6.58	5.12	4.22	3.85	6.58	3.21	4.05	2.45
Transportation and Blending	2.74	3.20	2.28	2.84	3.11	3.40	2.38	2.06	2.67
Operating	17.35	16.75	17.97	15.62	14.70	15.47	16.26	17.63	15.01
Production and Mineral Taxes	0.06	0.08	0.03	0.04	0.01	0.06	0.04	0.04	0.04
Netback	47.18	51.02	43.24	39.51	32.94	57.46	34.10	41.13	27.65

(4) Cost of Condensate per barrel of unblended crude oil ($/bbl)

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

Foster Creek	47.81	47.28	48.35	42.41	41.85	38.85	44.34	42.60	46.00
Christina Lake	51.02	49.30	52.81	45.25	44.16	39.86	49.54	47.13	51.46
Heavy Oil - Oil Sands	49.56	48.39	50.77	43.77	43.09	39.36	46.56	44.43	48.44
Pelican Lake	17.92	17.55	18.30	15.59	13.58	12.09	18.49	16.74	20.31
Other Conventional Heavy Oil	17.17	17.94	16.40	13.12	10.05	10.96	15.66	16.68	14.73
Heavy Oil - Conventional	17.63	17.70	17.56	14.60	12.18	11.65	17.33	16.72	17.93
Total Heavy Oil	41.30	40.44	42.17	35.63	35.44	31.46	37.93	35.91	39.78

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SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results	2014						2013
(excluding impact of Realized Gain	Year										Q2 Year
(Loss) on Risk Management)	to Date		Q2		Q1		Year	Q4	Q3		to Date	Q2		Q1
Light and Medium Oil ($/bbl)
Price	96.27		98.27		94.18		86.30	82.12	100.64		81.68	86.84		76.77
Royalties	10.11		11.37		8.78		8.28	6.58	11.01		7.81	8.61		7.05
Transportation and Blending	3.70		3.31		4.11		4.35	5.15	4.58		3.87	4.37		3.39
Operating	17.95		17.45		18.47		16.23	17.26	15.06		16.29	16.32		16.26
Production and Mineral Taxes	2.61		2.97		2.23		2.30	1.26	2.80		2.55	2.64		2.46
Netback	61.90		63.17		60.59		55.14	51.87	67.19		51.16	54.90		47.61
Total Crude Oil ($/bbl)
Price	77.31		81.35		73.15		67.05	59.41	86.41		61.57	69.75		54.02
Royalties	6.62		7.45		5.76		5.03	4.33	7.44		4.21	5.05		3.43
Transportation and Blending	2.91		3.22		2.60		3.14	3.47	3.63		2.70	2.57		2.82
Operating	17.46		16.87		18.06		15.74	15.15	15.39		16.27	17.34		15.27
Production and Mineral Taxes	0.51		0.60		0.42		0.49	0.23	0.59		0.58	0.61		0.56
Netback	49.81		53.21		46.31		42.65	36.23	59.36		37.81	44.18		31.94
Natural Gas Liquids ($/bbl)
Price	73.41		78.38		67.31		60.34	59.39	65.71		57.72	46.44		68.88
Royalties	1.60		1.70		1.48		1.13	1.14	1.92		0.64	1.17		0.12
Netback	71.81		76.68		65.83		59.21	58.25	63.79		57.08	45.27		68.76
Total Liquids ($/bbl)
Price	77.29		81.33		73.12		67.01	59.41	86.28		61.55	69.61		54.10
Royalties	6.59		7.41		5.74		5.01	4.31	7.40		4.19	5.03		3.42
Transportation and Blending	2.90		3.20		2.59		3.12	3.45	3.61		2.69	2.55		2.81
Operating	17.36		16.77		17.96		15.65	15.06	15.29		16.18	17.24		15.19
Production and Mineral Taxes	0.51		0.60		0.42		0.48	0.23	0.59		0.58	0.61		0.55
Netback	49.93		53.35		46.41		42.75	36.36	59.39		37.91	44.18		32.13
Total Natural Gas ($/Mcf)
Price	4.68		4.87		4.47		3.20	3.21	2.83		3.38	3.50		3.25
Royalties	0.08		0.09		0.06		0.04	0.04	0.05		0.05	0.04		0.05
Transportation and Blending	0.11		0.11		0.11		0.11	0.11	0.10		0.12	0.08		0.15
Operating	1.24		1.23		1.26		1.16	1.23	1.13		1.15	1.16		1.14
Production and Mineral Taxes	0.06		0.13		(0.01	)	0.02	0.02	0.03		0.01	(0.01	)	0.03
Netback	3.19		3.31		3.05		1.87	1.81	1.52		2.05	2.23		1.88
Total (1)($/BOE)
Price	62.76		65.71		59.68		51.23	47.23	63.12		47.40	52.55		42.52
Royalties	4.78		5.36		4.19		3.44	3.07	5.02		2.85	3.35		2.38
Transportation and Blending	2.24		2.45		2.03		2.31	2.60	2.60		2.00	1.82		2.17
Operating	14.44		13.95		14.94		12.79	12.73	12.44		13.00	13.64		12.39
Production and Mineral Taxes	0.47		0.65		0.28		0.36	0.19	0.45		0.40	0.38		0.42
Netback	40.83		43.30		38.24		32.33	28.64	42.61		29.15	33.36		25.16
Impact of Long-Term Incentives Costs (Recovery) on Total Operating Costs ($/BOE)	0.33		0.36		0.29		0.12	0.06	0.23		0.09	0.07		0.10
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	(2.48	)	(2.94	)	(2.00	)	1.09	2.77	(2.02	)	1.71	0.72		2.62
Natural Gas ($/Mcf)	(0.01	)	(0.02	)	—		0.32	0.36	0.38		0.28	0.18		0.39
Total (1) ($/BOE)	(1.76	)	(2.09	)	(1.42	)	1.37	2.58	(0.58	)	1.70	0.84		2.52

(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 for the comparability of Cenovus’s underlying financial performance between periods. Items within the Corporate and Eliminations segment are excluded from the calculation of operating cash flow.

·Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows in Cenovus’s interim and annual consolidated financial statements.

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

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

·Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses as measures of the company’s overall financial strength to steward the company’s overall debt position. 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 or Receivable. Capitalization is 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 gains or losses 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 and Analysis (MD&A) available at cenovus.com.

OIL AND GAS INFORMATION

Barrels of Oil Equivalent Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion

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method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

Netbacks For the method of calculation, refer to Cenovus’s Annual Information Form (AIF)  for the year ended December 31, 2013. Netbacks reported in this quarterly report are calculated as set out in the AIF, using an updated quarterly cost of condensate on a per barrel of unblended crude oil basis, as follows: Christina Lake - $49.30 and Foster Creek - $47.28.

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”, “projected”, “could”, “focus”, “proposed”, “schedule”, “potential”, “may”, “strategy” or similar expressions and includes suggestions of future outcomes, including statements about our growth strategy and related schedules, projections contained in our 2014 guidance, growing total shareholder return, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, expected increase in production capacity through optimization activity and debottlenecking, expected future refining capacity, broadening market access, improving cost structures, 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.

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.

2014 guidance, updated February 13, 2014, available at cenovus.com, is based on an average diluted number of shares outstanding of approximately 757 million. It assumes: Brent US$105.00/bbl, WTI of US$102.00/bbl; Western Canada Select of US$76.00/bbl; NYMEX of US$4.00/MMBtu; AECO of $3.30/GJ; Chicago 3-2-1 crack spread of US$13.50/bbl; exchange rate of $0.98 US$/C$. For the period 2015 to 2023, assumptions include: Brent US$105.00-US$110.00/bbl; WTI of US$100.00-US$106.00/bbl; Western Canada Select of US$81.00-US$91.00/bbl; NYMEX of US$4.25-US$4.75/MMBtu; AECO of $3.70-$4.31/GJ; Chicago 3-2-1 crack spread of US$12.00-US$13.00/bbl; exchange rate of $1.00 US$/C$; and average diluted number of shares outstanding of approximately 782 million.

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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 other 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 Annual Information Form/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 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	Natural Gas
bblbarrel	Mcfthousand cubic feet
bbls/dbarrels per day	MMcfmillion cubic feet
Mbbls/dthousand barrels per day	Bcfbillion cubic feet
MMbblsmillion barrels	MMBtumillion British thermal units
	GJGigajoule
BOEbarrel of oil equivalent
MBOEthousand barrel of oil equivalent
TMTrademark of Cenovus Energy Inc.

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Cenovus Energy Inc.

500 Centre Street SE

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-7600

CENOVUS CONTACTS

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

cenovus.com