Exhibit 99.1

Cenovus oil sands production climbs 20% in first quarter

Plans to move forward with Grand Rapids oil sands project

·Combined oil sands production at Foster Creek and Christina Lake averaged 120,444 barrels per day (bbls/d) net in the first quarter, up 20% from a year earlier.

·Production at Christina Lake averaged 65,738 bbls/d net in the first quarter, an increase of 48% when compared with the same period a year earlier as phase E approached full production capacity.

·Foster Creek performed at the upper end of Cenovus’s expected production range, averaging 54,706  bbls/d net in the quarter, a slight decrease from the same period a year earlier.

·Cenovus generated nearly $1.2 billion in operating cash flow, a 4% decrease when compared with the same period in 2013, as rising production and higher commodity prices were offset by significantly lower refining margins.

·Cenovus received regulatory approval for its 180,000 bbls/d wholly-owned Grand Rapids oil sands project and plans to move forward with an initial phase of 8,000 to 10,000 bbls/d.

“Our first quarter results have us off to a good start for delivering predictable, reliable performance this year,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “Our oil sands projects are on track and we continue to see value from our integrated business plan. Our strong cash flow and healthy balance sheet allow us to keep our focus on growing total shareholder return.”

Production & financial summary

(for the period ended March 31) Production (before royalties)	2014Q1	2013 Q1	% change
Oil sands total (bbls/d)	120,444	100,347	20
Conventional oil1 (bbls/d)	76,410	79,878	-4
Total oil (bbls/d)	196,854	180,225	9
Natural gas (MMcf/d)	476	545	-13

Financial ($ millions, except per share amounts)
Cash flow2	904	971	-7
Per share diluted	1.19	1.28
Operating earnings2	378	391	-3
Per share diluted	0.50	0.52
Net earnings	247	171	44
Per share diluted	0.33	0.23
Capital investment	829	915	-9

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 (April 30, 2014) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) reported solid first quarter results that continued to reflect the strength of its integrated business plan. While increased oil prices and lower market crack spreads reduced margins from the company’s refining operations, those higher prices benefited Cenovus’s operating cash flow from its producing oil assets.

Cenovus’s oil sands production averaged 120,444 bbls/d net in the first quarter, up 20% from a year earlier, primarily driven by strong performance at the company’s Christina Lake oil sands project. Production at Christina Lake increased 48% from 2013, averaging 65,738 bbls/d net as phase E approached full production capacity. This latest expansion phase, which was on time and on budget, brought Christina Lake’s gross production capacity to 138,000 bbls/d.

Foster Creek production was at the upper end of Cenovus’s expected range, averaging 54,706 bbls/d net in the quarter, a 2% decrease from the same period a year earlier. Cenovus is on track with its plan to optimize steam use at Foster Creek. The company is using new operating techniques to improve the conformance of steam along wellbores. Cenovus continues to strategically use its Wedge Well™ technology, which involves drilling single, horizontal producing wells between well pairs, allowing Cenovus to recover more oil while adding very little additional steam. The company drilled 11 of these wells in the first quarter of 2014 and expects to have 42 starting production over the next 14 months.

“We’re pleased with how Foster Creek has responded to the changes we’ve made,” said John Brannan, Cenovus Executive Vice-President and Chief Operating Officer. “We’re on track with our expansion plans and expect to produce between 100,000 and 110,000 barrels per day gross until we begin ramping up production from our next expansion phase in the third quarter.”

Demonstrating the value of integration

Total operating cash flow was nearly $1.2 billion in the quarter, a 4% decrease from the same period a year earlier. Cenovus’s upstream operations generated $924 million in operating cash flow in the first quarter, an increase of 35% due to a rise in oil and natural gas sale prices and higher oil sands production. This helped offset a 54% decline in operating cash flow from the company’s refining operations, which generated $241 million in the first quarter. The decrease in operating cash flow from refining was primarily due to lower market crack spreads, higher feedstock costs associated with increased oil prices and planned maintenance and turnarounds in the quarter.

Cenovus’s conventional oil and natural gas assets also demonstrate the strength of integration. The company’s conventional oil operations provide predictable near-term cash flow to help fund the development of its oil sands projects, and natural gas acts as an economic hedge for the fuel required at both Cenovus’s oil sands and refining operations. These assets generated $228 million in operating cash flow in excess of capital investment in the first quarter.

Taking the next step at Grand Rapids

Cenovus received regulatory approval for its Grand Rapids oil sands project in the first quarter. Similar to its existing oil sands projects, the company plans to develop Grand Rapids through a series of expansion phases. Phase A is expected to produce between

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8,000 and 10,000 bbls/d, with first steam planned in 2017. Cenovus has purchased a pre-existing facility, which has a design capacity of 10,000 bbls/d, from the Joslyn steam-assisted gravity drainage (SAGD) oil sands project and plans to move it to the Grand Rapids project site. This will allow Cenovus to quickly implement what the company has learned from its pilot project.

“Our focus on attacking costs is one way we’re building shareholder value,” said Ferguson. “Using this pre-existing facility at Grand Rapids is a great opportunity for us and a good example of our strategy in action.”

Cenovus plans to continue work on the existing pilot project, which consists of two producing well pairs. Grand Rapids has regulatory approval for a gross production capacity of 180,000 bbls/d.

Oil Projects

Daily production1

(Before royalties)	2014	2013					2012
(Mbbls/d)	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Oil sands
Christina Lake	66	49	61	53	38	44	32
Foster Creek	55	53	52	49	55	56	58
Oil sands total	120	103	114	102	94	100	90
Conventional oil
Pelican Lake	25	24	25	25	24	24	23
Weyburn	16	16	16	16	16	17	16
Other conventional2	36	36	34	34	37	39	37
Conventional total	76	77	75	75	77	80	76
Total oil	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 SAGD, which involves drilling into the reservoir and pumping the oil to the surface. Cenovus is currently building its third major oil sands project at Narrows Lake, which is part of the Christina Lake Region. These projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus has 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.

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Christina Lake

Production

·Production at Christina Lake averaged 65,738 bbls/d net in the first quarter, 48% higher than the same period a year earlier due to phase E approaching full production capacity, both on time and on budget. Work to optimize phases C, D and E is on track, with additional production from the project expected in 2015.

·The SOR at Christina Lake was 1.9 in the first quarter, consistent with the same period a year earlier.

·Operating costs at Christina Lake were $13.30 per barrel (bbl) in the first quarter, a slight increase from the same period a year ago. This was primarily due to higher natural gas fuel prices. Workover activities related to well maintenance were also higher in the quarter.

·Non fuel-operating costs were $8.47/bbl, compared with $9.24/bbl in the first quarter of 2013, a decrease of 8% mainly due to higher production volumes.

Expansions

·The phase F expansion is on schedule and on budget. About 50% of the project is complete, with work continuing primarily on procurement and construction. First production is expected in 2016. Cenovus is also working on engineering and procurement for phase G.

Foster Creek

Production

·Foster Creek production averaged 54,706 bbls/d net in the quarter, a 2% decrease from the same period a year earlier.

·The SOR at Foster Creek was 2.7 in the first quarter of 2014, compared with 2.4 in the same period a year earlier.

·Operating costs at Foster Creek averaged $19.09 in the first quarter, a 36% increase from the same period a year ago. The majority of the increase was driven by higher natural gas fuel prices and higher gas consumption as a result of the increased SOR. Workforce costs associated with the start-up of phase F and workover activities also contributed to the increase.

·Non-fuel operating costs were $13.64/bbl in the quarter compared with $11.12/bbl in the same period of 2013.

Expansions

·Phase F is on schedule and on budget with 93% of the project complete. Cenovus is on track to start injecting steam in the next month, and expects production in the third quarter of 2014. The company anticipates full ramp-up to be completed 12 to 18 months after first production begins.

·Phase G is 69% complete with initial production expected in 2015. Phase H is 42% complete with first production expected in 2016.

Narrows Lake

·Overall progress on phase A was 19% complete at the end of the quarter and site construction, engineering and procurement are progressing as expected.

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·The first phase of the project is anticipated 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 $47 million at Narrows Lake in the first quarter, compared with $25 million in the same period a year earlier.

Emerging projects

Grand Rapids

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

·Cenovus plans to move forward with phase A, which is expected to produce between 8,000 and 10,000 bbls/d, and continue its work on the SAGD pilot project, which has two producing well pairs.

·Cenovus invested $11 million at Grand Rapids in the first quarter, compared with $18 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 $52 million at Telephone Lake in the first quarter, consistent with the same period a year earlier.

Conventional oil

Pelican Lake

Cenovus produces heavy oil from the Wabiskaw formation at its 100%-owned Pelican Lake operation in the Greater Pelican Region, about 300 kilometres north of Edmonton. Cenovus has been injecting polymer since 2006 to enhance production from the reservoir, which is also under waterflood.

·Pelican Lake produced an average of 24,782 bbls/d in the quarter, increasing 5% from the same period a year earlier as additional infill wells started producing and the project continued to experience increased response from the polymer flood program.

·Cenovus invested $71 million at Pelican Lake in the first quarter, approximately half of what it invested in the same period a year earlier due to the decision to align spending with the current response the company is receiving from the polymer flood

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program. Pelican Lake generated $22 million in operating cash flow in excess of capital investment in the first quarter.

·Operating costs at Pelican Lake were $24.96/bbl in the first quarter, up from $19.23/bbl in 2013. The increase is primarily due to increased workover activities and higher chemical expenses associated with expansion of the polymer flood.

Other conventional oil

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

·Conventional oil production, excluding Pelican Lake, averaged 51,628 bbls/d in the first quarter, decreasing 8% from the same period a year earlier. The decrease was primarily due to the sale of Cenovus’s Shaunavon assets in 2013 and expected natural declines, partially offset by successful performance from the company’s horizontal drilling program in southern Alberta.

·Production at the Weyburn operation was about 16,100 bbls/d net compared with approximately 16,700 bbls/d net in the first quarter of 2013.

·Cenovus invested $192 million in its conventional oil assets, excluding Pelican Lake, in the first quarter, consistent with the same period a year earlier. These assets generated $62 million of operating cash flow in excess of capital investment in the first quarter.

·Cenovus completed the sale of certain of its Bakken assets in April for proceeds of approximately $36 million before closing adjustments. Cenovus has retained the royalty interest in these properties, as they are primarily fee title lands.

·Operating costs for Cenovus’s conventional oil operations, excluding Pelican Lake, were $19.16/bbl, a 16% increase compared with the same period in 2013 due to lower sales volumes, costs associated with workovers and repairs and maintenance, as well as higher energy costs.

Natural Gas

Daily production

(Before royalties)	2014	2013					2012
(MMcf/d)	Q1	Full Year	Q4	Q3	Q2	Q1	Full Year
Natural gas	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 476 million cubic feet per day (MMcf/d) in the first quarter, a 13% decrease compared with the same period a year earlier. The production drop was driven primarily by expected natural declines, challenging

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winter weather conditions resulting in freeze-offs, and the decision to direct capital investment toward the company’s oil opportunities.

·The company invested $9 million at its natural gas assets in the first quarter, consistent with the same period a year earlier. Natural gas assets generated $142 million in operating cash flow in excess of capital investment.

·Cenovus’s average realized sales price for natural gas, including hedges, was $4.47 per thousand cubic feet (Mcf), an increase of $0.83 per Mcf. Higher natural gas prices more than offset the increase in fuel costs at Cenovus’s oil sands operations.

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 continues to expand its access to new markets and delivered approximately 7,117 bbls/d of oil for transportation by rail to destinations in the U.S. and on Canada’s East Coast.

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

·Cenovus has 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 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 $241 million in the first quarter, a 54% decrease when compared with the first quarter of 2013, due to a decline in market crack spreads consistent with narrowing differentials and higher prices for its heavy oil feedstock, as well as planned maintenance and turnarounds at both refineries.

·Capital investment was $23 million, decreasing from $25 million in the same period a year earlier. Capital expenditures were related to maintenance and reliability and safety projects. Cenovus’s refining operations generated $218 million in operating cash flow in excess of capital investment in the first quarter.

·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 $83 million lower.

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Operations

·Cenovus’s refineries processed an average of 400,000 bbls/d gross in the quarter, a 4% decrease from the same period a year earlier due to planned maintenance and turnaround activities in the quarter.

·Together, the two refineries processed an average of 195,000 bbls/d of heavy oil in the quarter, consistent with the year previous.

·The refineries produced an average of 420,000 bbls/d gross of refined products in the quarter, a 4% decrease from the first quarter of 2013.

·Cenovus and Phillips 66 sanctioned a debottlenecking project to fully utilize the assets installed with the original coker and refinery expansion (CORE) at the Wood River Refinery. The project is expected to start up in the first quarter of 2016. Cenovus’s share of the project costs is expected to be US$50 million.

Financial

Dividend

The Cenovus Board of Directors declared a second quarter dividend of $0.2662 per share, payable on June 30, 2014 to common shareholders of record as of June 13, 2014. Based on the April 29, 2014 closing share price on the Toronto Stock Exchange of $33.02, 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.

Cash flow, earnings and capital investment

·Operating cash flow was nearly $1.2 billion in the quarter, a 4% decrease from the same period a year earlier. Operating cash flow from Cenovus’s refining operations was $241 million, a 54% decline from the same period a year earlier due to lower market crack spreads and higher costs related to high oil prices, as well as planned maintenance and turnarounds at both refineries. The strong prices did benefit Cenovus’s producing assets, which generated $924 million of operating cash flow, a 35% increase compared with the first quarter of 2013.

·Cenovus generated $904 million in cash flow in the first quarter, about 7% lower than the same period a year earlier due to the slight decline in operating cash flow and a decrease in interest income related to the receipt of the partnership contribution receivable when ConocoPhillips elected to prepay it in the fourth quarter of 2013.

·Operating earnings were $378 million in the first quarter, a 3% decrease when compared with the same period a year earlier due to a decrease in cash flow and a non-cash long-term incentive expense as compared to a recovery in 2013, partially offset by a reduction in deferred income tax expense.

·Cenovus’s net earnings for the quarter were $247 million, about 44% higher than the same period a year earlier primarily due to unrealized risk management gains (compared with a loss in the first quarter of 2013), partially offset by non-operating unrealized foreign exchange losses as a result of a weaker Canadian dollar.

·Capital investment was $829 million in the first quarter, a 9% decrease when compared with the same period a year earlier, primarily due to reduced capital investment at Pelican Lake.

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·Cenovus elected to prepay the remaining principal and accrued interest due under the partnership contribution payable to WRB Refining LP. This resulted in a net cash payment of approximately US$1.4 billion from Cenovus.

Risk management, expenses and financial ratios

·Cenovus hedged approximately 111 MMcf/d of expected natural gas production at an average AECO price of $4.61/MMcf for 2014.

·Cenovus hedged 3,500 bbls/d of expected oil production at an average Brent price of $114.21/bbl for 2015.

·Cenovus had a realized after-tax hedging loss of $23 million in the quarter. The company received an average realized price, including hedging, of $71.12/bbl for its oil. The average realized price for natural gas, including hedging, was $4.47/Mcf.

·General and administrative (G&A) expenses were $4.43 per barrel of oil equivalent (BOE) in the first quarter, compared with $3.40/BOE in the first quarter of 2013 due to higher workforce costs associated with growing oil sands production and long-term incentive costs.

·Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) ratio of between 1.0 and 2.0 times. At March 31, 2014, the company’s debt to capitalization ratio was 36% and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.4 times.

Operating earnings1

(for the period ended March 31) ($ millions, except per share amounts)	2014Q1		2013Q1
Earnings, before income tax	358		294
Add back (deduct):
Unrealized risk management (gains) losses2	(26	)	230
Non-operating unrealized foreign exchange (gains) losses3	196		47
Operating earnings, before income tax	528		571
Income tax expense	150		180
Operating earnings	378		391

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 April 29, 2014, should be read in conjunction with our March 31, 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 April 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 its approval by the Board. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at 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 March 31, 2014, we had a market capitalization of approximately $24 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with refining operations in the United States (“U.S.”). Our average crude oil and NGLs (collectively, “crude oil”) production for the three months ended March 31, 2014, was in excess of 196,800 barrels per day and our average natural gas production was 476 MMcf per day. Our refinery operations processed an average of 400,000 gross barrels per day of crude oil feedstock into an average of 420,000 gross barrels per day of refined product.

Our Strategy

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

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

·Oil sands for growth;

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

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

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

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 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:

	Three Months Ended March 31, 2014
	Ownership Interest (percent)	NetProduction Volumes(bbls/d)	Gross Production Volumes (bbls/d)
Existing Projects
Foster Creek	50	54,706	109,412
Christina Lake	50	65,738	131,476
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.

Conventional

	Three Months Ended March 31, 2014
($ millions)	Crude Oil (1)	Natural Gas
Operating Cash Flow (2)	347	128
Capital Investment	263	7
Operating Cash Flow Net of Related Capital Investment	84	121

(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.

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)	Three Months Ended March 31, 2014
Operating Cash Flow (1)	245
Capital Investment	23
Operating Cash Flow Net of Related Capital Investment	222

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

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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 quarter, we paid a dividend of $0.2662 per share, a 10 percent increase from 2013 (2013 — $0.242 per share).

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

The first quarter of 2014 continued to reflect the strength of our integrated approach. Upstream Operating Cash Flow increased 35 percent compared to 2013 due to higher crude oil blend and natural gas sales prices and rising crude oil production. Crude oil sales prices increased 35 percent mainly due to the narrowing of the West Texas Intermediate (“WTI”) to Western Canadian Select (“WCS”) differential by 28 percent and the weakening of the Canadian dollar. The WTI-WCS differential narrowed to an average of US$23.13 per barrel (2013 — US$31.96). The rise in WCS to US$75.55 per barrel (2013 — US$62.41 per barrel) increased the cost of our heavy crude oil feedstock which, along with sharp declines in market crack spreads, resulted in lower Operating Cash Flow from our refining operations.

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

Total crude oil production in the first quarter averaged 196,854 barrels per day, in line with our expectations and an increase of nine percent from 2013.

Crude oil production from our Oil Sands segment averaged 120,444 barrels per day, an increase of 20 percent, primarily driven by higher production at Christina Lake. Average production at Christina Lake was 65,738 barrels per day, a 48 percent increase, as phase D reached full production capacity in 2013 and phase E approached full production capacity in 2014. With the addition of phase E, our tenth oil sands expansion phase, nameplate capacity increased to 138,000 gross barrels per day.

Foster Creek production averaged 54,706 barrels per day, in line with our expectations.

Our Conventional crude oil production averaged 76,410 barrels per day. The sale of our Lower Shaunavon asset in July 2013 reduced production which offset the increased production at Pelican Lake. Pelican Lake production averaged 24,782 barrels per day, an increase of five percent, resulting from additional infill wells coming on-stream and an increased response from the polymer flood program.

Our refining operations processed an average of 400,000 gross barrels per day (2013 — 416,000 gross barrels per day) of crude oil, of which 195,000 gross barrels per day was heavy crude oil (2013 — 197,000 gross barrels per day). We produced 420,000 gross barrels per day of refined products (2013 — 439,000). Refined product output in the first quarter of 2014 was impacted by planned maintenance and turnarounds at both refineries. In the first quarter of 2013, there were no significant turnaround activities at Borger.

Other significant operational results in the first quarter of 2014 compared with 2013 include:

·Christina Lake reaching a cumulative production milestone of 100 million barrels of crude oil;

·Receiving regulatory approval for a 180,000 barrel per day commercial SAGD operation at our Grand Rapids project;

·Expanding our access to sales markets with approximately 7,117 barrels per day of crude oil transported by rail, including three unit train shipments, to the East Coast and the U.S.; and

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·Entering into a purchase and sale agreement with an unrelated third party to sell certain of our Bakken properties. The sale was completed in April 2014 for proceeds of approximately $36 million before closing adjustments.

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

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.

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

In March 2014, we prepaid our Partnership Contribution Payable to WRB Refining LP in the amount of US$1.4 billion. To fund the prepayment, we used the net proceeds of US$1.4 billion received in December 2013 from our partner when they elected to prepay the Partnership Contribution Receivable. Other financial highlights for the first quarter of 2014 compared with 2013 include:

Revenues

Revenues of $5,012 million, increasing $693 million or 16 percent as a result of:

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

·Refining and Marketing revenues increasing $312 million primarily due to higher revenues from third-party sales of crude oil and natural gas. Increases were partially offset by a decrease in refining revenues due to lower refined product prices and declines in refined product output, partially offset by the weakening of the Canadian dollar; and

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

These increases to revenues were partially offset by declines in natural gas production volumes.

Operating Cash Flow

In the first quarter, Operating Cash Flow was $1,169 million, a decrease of $45 million. Upstream Operating Cash Flow increased $239 million, or 35 percent, to $924 million due to increasing crude oil and natural gas sales prices and higher crude oil production volumes at Christina Lake, partially offset by realized risk management losses compared to gains in 2013, a rise in operating costs, higher royalties and declines in natural gas production volumes. 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 $284 million, or 54 percent, to $245 million primarily due to lower market crack spreads, higher heavy crude oil feedstock costs and decreased refined product output as a result of planned maintenance and turnarounds at both of our refineries. The Chicago and Midwest Combined 3-2-1 (“Group 3”) market crack spreads decreased by approximately US$10 per barrel.

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Cash Flow

Cash Flow decreased $67 million to $904 million, primarily due to changes discussed above in Operating Cash Flow and a decrease in interest income related to the early receipt of the Partnership Contribution Receivable in December 2013.

Operating Earnings

Operating Earnings decreased $13 million, or three percent, to $378 million. In addition to changes in Cash Flow discussed above, the decline was primarily due to a non-cash long-term incentive expense as compared to a recovery in 2013. Declines were partially offset by a decrease in deferred income tax expense and unrealized foreign exchange gains related to operating items compared to losses in 2013.

Net Earnings

Net Earnings increased $76 million, or 44 percent, to $247 million primarily due to unrealized risk management gains of $26 million compared with losses of $230 million in 2013. Increases were partially offset by an unrealized foreign exchange loss on long-term debt of $196 million compared with losses of $47 million related to long-term debt and the Partnership Contribution Receivable in 2013, and changes in Operating Earnings discussed above.

Capital Investment

Capital investment was $829 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

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Crude Oil Production Volumes

	Three Months Ended March 31,
(barrels per day)	2014	Percent Change		2013
Oil Sands
Foster Creek	54,706	(2)	%	55,996
Christina Lake	65,738	48	%	44,351
	120,444	20	%	100,347
Conventional
Pelican Lake	24,782	5	%	23,687
Other Heavy Oil	16,017	(4)	%	16,712
Total Heavy Oil	40,799	1	%	40,399
Light & Medium Oil	34,598	(10)	%	38,508
NGLs (1)	1,013	4	%	971
Total Conventional	76,410	(4)	%	79,878
Total Crude Oil Production	196,854	9	%	180,225

(1)NGLs include condensate volumes.

In the first quarter, our crude oil production increased nine percent driven by higher production at Christina Lake as a result of phase D reaching full production capacity in 2013 and phase E approaching full production capacity in 2014. The ramp up of phase E, which started producing in July 2013, proceeded similar to the ramp up of phases C and D, approaching nameplate capacity within six to nine months of first production.

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.

Our crude oil production from the Conventional segment decreased primarily due to the divestiture of our Lower Shaunavon asset, which produced an average of 4,888 barrels per day in the first quarter of 2013. The decline was partially offset by higher Pelican Lake production with additional infill wells coming on-stream and an increased response from our polymer flood program.

See the Reportable Segments section of this MD&A for more detail.

Natural Gas Production Volumes

	Three Months Ended March 31,
(MMcf per day)	2014	2013
Conventional	457	527
Oil Sands	19	18
	476	545

We continue to focus on high rate of return projects and directing capital investment to our crude oil properties.

Operating Netbacks

	Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)
	Three Months Ended March 31,			Three Months Ended March 31,
	2014		2013	2014		2013
Price (2)	73.12		54.10	4.47		3.25
Royalties	5.74		3.42	0.06		0.05
Transportation and Blending (2)	2.59		2.81	0.11		0.15
Operating Expenses	17.96		15.19	1.26		1.14
Production and Mineral Taxes	0.42		0.55	(0.01	)	0.03
Netback Excluding Realized Risk Management	46.41		32.13	3.05		1.88
Realized Risk Management Gain (Loss)	(2.00	)	2.62	—		0.39
Netback Including Realized Risk Management	44.41		34.75	3.05		2.27

(1)Includes NGLs.

(2)The crude oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate was $34.54 per barrel for the first quarter (2013 — $31.09 per barrel).

In the first quarter, our crude oil netback, excluding realized risk management gains and losses, increased $14.28 per barrel from 2013 primarily due to higher sales prices, partially offset by increased operating costs. The rise in sales prices is consistent with the narrowing of the WTI-WCS differential and the weakening of the Canadian dollar. The increase in operating costs was primarily related to the increase in natural gas price, consistent with the rise in the AECO benchmark price.

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The impact of rising natural gas prices on our operating costs, which represented $1.38 per barrel of the $2.77 per barrel increase, was more than offset by the benefit received from higher prices through an increase in natural gas revenues. In total, natural gas revenues increased $48 million and operating expenses related to fuel increased $27 million.

Our natural gas netback, excluding realized risk management gains and losses, increased $1.17 per Mcf predominantly due to higher sales prices, partially offset by higher per-unit operating costs as a result of the decline in production volumes.

Refining (1)

	Three Months Ended March 31,
	2014	Percent Change		2013
Crude Oil Runs (Mbbls/d)	400	(4	)%	416
Heavy Crude Oil	195	(1	)%	197
Refined Product (Mbbls/d)	420	(4	)%	439
Crude Utilization (percent)	87	(4	)%	91

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

In the first quarter of 2014, both of our refineries underwent planned maintenance and turnarounds resulting in a decline in crude oil runs, refined product output and crude utilization. In the first quarter of 2013, there were no significant turnaround activities at Borger.

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 and the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates (1)

	Q1 2014		Q4 2013		Q1 2013
Crude Oil Prices (US$/bbl)
Brent
Average	107.90		109.35		112.65
End of Period	107.76		110.80		110.02
WTI
Average	98.68		97.46		94.37
End of Period	101.58		98.42		97.23
Average Differential Brent-WTI	9.22		11.89		18.28
WCS (2)
Average	75.55		65.26		62.41
End of Period	80.71		74.80		82.71
Average Differential WTI-WCS	23.13		32.20		31.96
Condensate (C5 @ Edmonton) Average	102.64		94.22		107.24
Average Differential WTI-Condensate (Premium)/Discount	(3.96	)	3.24		(12.87	)
Average Differential WCS-Condensate (Premium)/Discount	(27.09	)	(28.96	)	(44.83	)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)	113.04		103.52		118.01
Chicago Ultra-low Sulphur Diesel (“ULSD”)	125.83		121.98		129.46
Refining 3-2-1 WTI Average Crack Spreads (US$/bbl)
Chicago	18.55		12.29		27.53
Group 3	17.41		10.66		27.93
Natural Gas Average Prices
AECO (C$/Mcf)	4.76		3.15		3.08
NYMEX (US$/Mcf)	4.94		3.60		3.34
Basis Differential NYMEX-AECO (US$/Mcf)	0.60		0.59		0.27
Foreign Exchange Rates (US$/C$1)
Average	0.906		0.953		0.992

(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 first quarter of 2014 was C$83.39 (2013 — C$62.91).

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Crude Oil Benchmarks

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of changes in inland refined product prices. In the first quarter of 2014, the average price of Brent crude oil decreased by US$4.75 per barrel compared to the same period last year. Lower prices in the quarter resulted from 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. The first quarter of 2013 experienced higher Brent crude oil pricing as a result of accelerating U.S. economic momentum and Iranian supply uncertainty.

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 significantly in the first quarter. New pipeline infrastructure from the Cushing, Oklahoma area to the U.S. Gulf Coast relieved congestion that developed in 2013 due to the rapid growth of U.S. inland supply, allowing U.S. Gulf Coast refineries access to WTI crude oil, reducing the discount applied to the WTI benchmark price.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WTI-WCS average differential narrowed by US$8.83 per barrel due to increased Canadian heavy crude oil volumes shipped by rail, allowing access to more Canadian and U.S. markets; and higher utilization of existing pipelines and new pipeline capacity, increasing U.S. refinery access to the growing crude oil production in Alberta.

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 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. Condensate prices decreased in the first quarter by US$4.60 per barrel compared to 2013 due to the same reasons discussed above that impacted the Brent benchmark price. The WCS-Condensate differential narrowed by US$17.74 per barrel in the first quarter compared to 2013 primarily due to the increase in the WCS benchmark price.

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 market crack spreads in the U.S. inland Chicago and Group 3 markets fell in the first quarter compared with 2013 primarily due to the strengthening of WTI prices as inland congestion issues were addressed, 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 based on a first in, first out accounting basis.

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Other Benchmarks

Average natural gas prices increased significantly in the first quarter of 2014 compared to the same period last year due to an abnormally cold winter leading to large draws of natural gas from 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 first quarter of 2014 compared to the same period last year, the Canadian dollar weakened by $0.09, or nine percent, relative to the U.S. dollar due to narrowing U.S./Canadian interest differentials. 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 the first quarter of 2014 as compared with 2013 increased our current period’s revenues by US$431 million.

FINANCIAL RESULTS

Selected Consolidated Financial Results

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

($ millions, except per share	2014	2013					2012
amounts)	Q1	Q4		Q3	Q2	Q1	Q4		Q3	Q2	Q1
Revenues	5,012	4,747		5,075	4,516	4,319	3,724		4,340	4,214	4,564
Operating Cash Flow (1) (2)	1,169	976		1,153	1,125	1,214	966		1,314	1,081	1,090
Cash Flow (1)	904	835		932	871	971	697		1,117	925	904
Per Share — Diluted	1.19	1.10		1.23	1.15	1.28	0.92		1.47	1.22	1.19
Operating Earnings (Loss) (1)	378	212		313	255	391	(188	)	432	284	340
Per Share — Diluted	0.50	0.28		0.41	0.34	0.52	(0.25	)	0.57	0.37	0.45
Net Earnings (Loss)	247	(58	)	370	179	171	(117	)	289	397	426
Per Share — Basic	0.33	(0.08	)	0.49	0.24	0.23	(0.15	)	0.38	0.53	0.56
Per Share — Diluted	0.33	(0.08	)	0.49	0.24	0.23	(0.15	)	0.38	0.52	0.56
Capital Investment (3)	829	898		743	706	915	978		830	660	900
Cash Dividends	202	183		182	183	184	167		166	166	166
Per Share	0.2662	0.242		0.242	0.242	0.242	0.22		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 first quarter, revenues increased $693 million or 16 percent compared with 2013.

($ millions)
Revenues for the Three Months Ended March 31, 2013	4,319
Increase (Decrease) due to:
Oil Sands	371
Conventional	129
Refining and Marketing	312
Corporate and Eliminations	(119	)
Revenues for the Three Months Ended March 31, 2014	5,012

Upstream revenues increased 33 percent due to rising crude oil blend and natural gas sales prices, and higher blended crude oil sales volumes, partially offset by increased royalties and lower natural gas production.

Revenues generated by the Refining and Marketing segment increased 11 percent as revenues from third-party sales, undertaken to provide operational flexibility, increased as a result of a rise in crude oil and natural gas pricing and purchased volumes. Revenue from our refining operations declined due to lower refined product prices and decreases in refined product output, partially offset by the weakening of the Canadian dollar.

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

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

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Operating Cash Flow

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

	Three Months Ended March 31,
($ millions)	2014	2013
Revenues	5,253	4,441
(Add) Deduct:
Purchased Product	2,820	2,277
Transportation and Blending	653	558
Operating Expenses	574	440
Production and Mineral Taxes	7	10
Realized (Gain) Loss on Risk Management Activities	30	(58	)
Operating Cash Flow	1,169	1,214

As highlighted in the above graph, our Operating Cash Flow decreased four percent primarily due to:

·A decline in Operating Cash Flow from Refining and Marketing of $284 million primarily due to a decline in market crack spreads, higher heavy crude oil feedstock costs and lower refined product output, consistent with planned maintenance and turnarounds at both of our refineries in the quarter;

·Realized risk management losses before tax, excluding Refining and Marketing, of $35 million compared with gains of $62 million in 2013; and

·An increase in crude oil operating expenses of $68 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 price 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 $2.77 to $17.96 per barrel, with $1.38 per barrel of the increase related to the rise in natural gas prices.

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The decreases were partially offset by:

·A 35 percent increase in our average crude oil sales price to $73.12 per barrel and a 38 percent increase in our average natural gas sales price to $4.47 per Mcf; and

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

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

Cash Flow

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

	Three Months Ended March 31,
($ millions)	2014		2013
Cash From Operating Activities	457		895
(Add) Deduct:
Net Change in Other Assets and Liabilities	(42	)	(34	)
Net Change in Non-Cash Working Capital	(405	)	(42	)
Cash Flow	904		971

In the first quarter of 2014, Cash Flow decreased $67 million due to the decline in Operating Cash Flow and a decrease of $25 million in interest income primarily due to the receipt of the Partnership Contribution Receivable in December 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 March 31,
($ millions)	2014		2013
Earnings, Before Income Tax	358		294
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)	(26	)	230
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)	196		47
Operating Earnings, Before Income Tax	528		571
Income Tax Expense	150		180
Operating Earnings	378		391

(1)The unrealized risk management (gains) losses include 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.

Including the changes discussed above in Cash Flow, Operating Earnings decreased $13 million in the first quarter primarily related to a non-cash long-term incentive expense compared to a recovery in 2013. Decreases were partially offset by:

·Unrealized foreign exchange gains related to operating items of $53 million compared to losses of $3 million in 2013; and

·A decrease in income tax of $30 million primarily as a result of lower U.S. deferred taxes.

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Net Earnings

($ millions)
Net Earnings for the Three Months Ended March 31, 2013	171
Increase (Decrease) due to:
Operating Cash Flow (1)	(45	)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)	256
Unrealized Foreign Exchange Gain (Loss)	(93	)
Expenses (2)	(55	)
Depreciation, Depletion and Amortization	1
Income Taxes	12
Net Earnings for the Three Months Ended March 31, 2014	247

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

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

Including the changes discussed above in the Cash Flow and Operating Earnings sections, our Net Earnings increased 44 percent in the first quarter primarily due to unrealized risk management gains of $26 million compared to losses of $230 million in 2013. Increases were partially offset by an unrealized foreign exchange loss on long-term debt of $196 million compared to losses of $47 million related to long-term debt and the Partnership Contribution Receivable in 2013 as a result of a weaker Canadian dollar.

Net Capital Investment

	Three Months Ended March 31,
($ millions)	2014		2013
Oil Sands	527		537
Conventional	270		338
Refining and Marketing	23		25
Corporate	9		15
Capital Investment	829		915
Acquisitions	1		3
Divestitures	(2	)	(1	)
Net Capital Investment (1)	828		917

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

Oil Sands capital investment in the first quarter 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 279 gross stratigraphic test wells.

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 managed in response to the natural gas price environment.

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

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.

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.

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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 March 31,
($ millions)	2014		2013
Cash Flow (1)	904		971
Capital Investment (Committed and Growth)	829		915
Free Cash Flow (2)	75		56
Dividends Paid	202		184
	(127	)	(128	)

(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.

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.

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Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, 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 March 31,
($ millions)	2014		2013
Oil Sands	1,209		838
Conventional	786		657
Refining and Marketing	3,258		2,946
Corporate and Eliminations	(241	)	(122	)
	5,012		4,319

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.

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

·Christina Lake production increasing 48 percent, to an average of 65,738 barrels per day, primarily due to phase E approaching full production capacity in the first quarter of 2014;

·Foster Creek production averaging 54,706 barrels per day;

·Receiving regulatory approval for a 180,000 barrel per day commercial SAGD operation at our Grand Rapids project; and

·Successfully completing a winter stratigraphic test well program, drilling 279 gross wells.

Oil Sands — Crude Oil

Financial Results

	Three Months Ended March 31,
($ millions)	2014		2013
Gross Sales	1,230		841
Less: Royalties	51		14
Revenues	1,179		827
Expenses
Transportation and Blending	559		465
Operating	170		123
(Gain) Loss on Risk Management	22		(23	)
Operating Cash Flow (1)	428		262
Capital Investment	525		536
Operating Cash Flow Net of Related Capital Investment	(97	)	(274	)

(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.

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

Revenues

Pricing

In the first quarter, our average crude oil sales price was $65.19 per barrel, 48 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 35 percent, to a discount of US$4.90 per barrel (2013 — US$7.51 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 first quarter, 53,839 barrels per day of Christina Lake production was sold as CDB (2013 — 37,635 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.

Production Volumes

	Three Months Ended March 31,
(barrels per day)	2014	Percent Change		2013
Foster Creek	54,706	(2)	%	55,996
Christina Lake	65,738	48	%	44,351
	120,444	20	%	100,347

In line with our expectations, Foster Creek production averaged 54,706 barrels per day in the first quarter of 2014. We are on track with our plan to optimize steam placement and continue to monitor conditions in the reservoir as common steam chambers form in the initial project areas. We are using new operating techniques 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 see a higher steam to oil ratio (“SOR”) and production levels between 100,000 and 110,000 gross barrels per day. We remain confident in the overall magnitude of the resource. 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 as a result of phase D reaching full production capacity in 2013 and phase E approaching full production capacity in 2014.

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 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. The proportion of the cost of condensate recovered increased in the first 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.

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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.

Royalties increased $37 million during the first quarter of 2014, primarily due to higher realized prices at both Foster Creek and Christina Lake. At Foster Creek this resulted in a royalty calculation based on net profits in the first quarter of 2014 as compared to a calculation based on gross revenues in 2013.

Effective Royalty Rates

	Three Months Ended March 31,
(percent)	2014	2013
Foster Creek	8.1	2.9
Christina Lake	7.1	5.7

Expenses

Transportation and Blending

Transportation and blending costs rose $94 million or 20 percent. Blending costs rose due to higher production and an increase in the cost of condensate. Transportation charges were $4 million lower due to volumes shipped on the Trans Mountain pipeline system, resulting in lower transportation charges for our net share, and lower sales into the U.S. market which attract higher tariffs.

Operating

Primary drivers of our operating costs in the first quarter of 2014 were fuel costs, workforce and workover activities. In total, operating costs increased $47 million or $2.43 per barrel.

Per-unit Operating Costs

	Three Months Ended March 31,
($/bbl)	2014	Percent Change		2013
Foster Creek
Fuel	5.45	87	%	2.91
Non-fuel	13.64	23	%	11.12
Total	19.09	36	%	14.03
Christina Lake
Fuel	4.83	31	%	3.69
Non-fuel	8.47	(8)	%	9.24
Total	13.30	3	%	12.93

Foster Creek operating costs rose $5.06 per barrel, primarily due to an increase of $1.89 per barrel related to the rise in natural gas price. Overall, operating costs rose $23 million due to:

·Higher fuel costs, an increase of $12 million primarily related to the rise in natural gas price, consistent with the rising benchmark AECO price;

·Higher workforce costs as we hired additional field staff in advance of the start-up of the phase F expansion expected in the third quarter of 2014; and

·Increased workover activities related to well servicing.

Christina Lake operating costs increased $0.37 on a per barrel basis primarily due to an increase of $1.64 per barrel related to the rise in natural gas price. Per barrel non-fuel costs decreased primarily due to higher production volumes. Overall, operating costs rose $24 million due to:

·Higher fuel costs, an increase of $13 million, as a result of rising production and increased fuel prices consistent with the rising benchmark AECO natural gas price; and

·Increased workover activities related to well servicing.

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(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per barrel of unblended crude oil basis, the cost of condensate in the first quarter was $48.35 per barrel (2013 — $46.00 per barrel) for Foster Creek; and $52.81 per barrel (2013 — $51.46 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.

Risk Management

Risk management activities in the first quarter resulted in realized losses of $22 million (2013 — gains of $23 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, remained consistent at 19 MMcf per day in the first quarter compared to 2013 (2013 — 18 MMcf per day). Operating Cash Flow was $23 million in the first quarter (2013 — $4 million), increasing due to higher realized natural gas sales prices.

Oil Sands — Capital Investment

	Three Months Ended March 31,
($ millions)	2014	2013
Foster Creek	221	210
Christina Lake	182	175
	403	385
Narrows Lake	47	25
Telephone Lake	52	53
Grand Rapids	11	18
Other (1)	14	56
Capital Investment (2)	527	537

(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 the first quarter focused on expansion of phases F, G and H, drilling of sustaining wells, and operational improvement projects. Spending also included the drilling of 145 gross stratigraphic test wells (2013 — 111 gross wells). Capital investment increased due to phase F well pad construction, wedge well drilling and an increase in stratigraphic test wells drilled.

In the first quarter, Christina Lake capital investment focused on expansion of phase F, phase E well pad and facility construction, and the drilling of sustaining wells. Capital investment also included the drilling of 51 gross stratigraphic test wells (2013 — 68 gross wells). Capital investment increased slightly due to higher spending on wedge well and sustaining well drilling, and phase F plant construction, partially offset by lower spending on phase E plant construction.

In the first quarter, capital investment increased at Narrows Lake as spending continued on phase A engineering, procurement and plant construction, which started in the third quarter of 2013.  Capital investment also included the drilling of 22 gross stratigraphic test wells (2013 — 26 gross wells).

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Emerging Projects

At Telephone Lake, our capital investment was primarily focused on front end engineering and costs related to the pilot project. In the first quarter, investment remained consistent to 2013 and included the drilling of 31 stratigraphic test wells (2013 — 28 wells).

Capital investment at Grand Rapids was primarily focused on costs related to the pilot project. Capital investment declined in the first quarter due to a reduction in spending on the pilot project, partially offset by drilling nine stratigraphic test wells in 2014 (2013 — one well). The purpose of the pilot is to test reservoir performance.

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		Gross Production Wells (1) (2)
	Three Months Ended March 31,
	2014	2013	2014	2013
Foster Creek	145	111	15	1
Christina Lake	51	68	18	5
	196	179	33	6
Narrows Lake	22	26	—	—
Telephone Lake	31	28	—	—
Grand Rapids	9	1	—	—
Other	21	72	—	—
	279	306	33	6

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

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

(3)   In addition, we drilled one gross service well in the first quarter of 2014 (2013 — eight gross service wells).

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. Production from phase F is expected to start in the third 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 EIA to regulators in February 2013 for an additional expansion, phase J, and we anticipate receiving regulatory approval in the first quarter of 2015.

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 wedge wells 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. The first phase of the project is anticipated to have a production capacity of 45,000 gross barrels per day, with first oil expected in 2017.

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, a SAGD pilot project is underway. We received regulatory approval in March 2014 for a 180,000 barrel per day commercial SAGD operation. We plan to continue operating the pilot project to gather additional information on the reservoir.

Additional capital investment of approximately $140 million to $160 million in 2014 is expected for our emerging SAGD projects and is primarily focused on drilling stratigraphic test wells, front end engineering at Telephone Lake and costs related to the pilot projects at Telephone Lake and 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.

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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

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 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 first quarter, Oil Sands DD&A increased $38 million to $143 million (2013 — $105 million) due to increased DD&A rates for both of our properties due to increased expenditures, a rise in future development costs associated with total proved reserves and higher sales volumes.

CONVENTIONAL

Our Conventional operations include predictable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a carbon dioxide enhanced oil recovery project in Weyburn, 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. 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 our future growth opportunities in our Oil Sands segment.

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

·Crude oil production averaging 76,410 barrels per day, decreasing four percent primarily due to the sale of our Lower Shaunavon asset and expected natural declines, partially offset by successful horizontal well performance in southern Alberta associated with our current drilling program and higher production at Pelican Lake; and

·Generating Operating Cash Flow net of capital investment of $207 million, an increase of $130 million.

In March, we entered into a purchase and sale agreement with an unrelated third party, to sell certain of our Bakken properties in southeastern Saskatchewan. The sale was completed in April 2014 for proceeds of $36 million before closing adjustments. A gain on disposition of approximately $17 million is expected to be recorded in the second quarter of 2014. The associated property, plant and equipment and decommissioning liabilities of $28 million and $10 million, respectively, were reclassified at March 31, 2014 as assets and liabilities held for sale. During the first quarter, these Bakken properties had crude oil production averaging 396 barrels per day (2013 — 773 barrels per day).

In the first quarter of 2013, we entered into a purchase and sale agreement with an unrelated third party to sell our Lower Shaunavon asset. The sale was completed in July 2013 for proceeds of approximately $240 million plus closing adjustments. Lower Shaunavon produced an average of 4,888 barrels per day in the first quarter of 2013.

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Conventional — Crude Oil

Financial Results

	Three Months Ended March 31,
($ millions)	2014	2013
Gross Sales	651	543
Less: Royalties	49	42
Revenues	602	501
Expenses
Transportation and Blending	89	86
Operating	145	124
Production and Mineral Taxes	8	9
(Gain) Loss on Risk Management	13	(20	)
Operating Cash Flow (1)	347	302
Capital Investment	263	330
Operating Cash Flow Net of Related Capital Investment	84	(28	)

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

Capital investment in excess of Operating Cash Flow in 2013 was funded through Operating Cash Flow generated by natural gas sales in our Conventional segment and from our Refining and Marketing segment.

(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 28 percent to $85.38 per barrel, consistent with the change in crude oil benchmark prices and associated differentials.

Production Volumes

	Three Months Ended March 31,
(barrels per day)	2014	Percent Change		2013
Pelican Lake	24,782	5	%	23,687
Other Heavy Oil	16,017	(4)	%	16,712
Total Heavy Oil	40,799	1	%	40,399
Light and Medium Oil	34,598	(10)	%	38,508
NGLs	1,013	4	%	971
	76,410	(4)	%	79,878

Our crude oil production decreased four percent primarily due to the sale of our Lower Shaunavon asset in July 2013 and expected natural declines, partially offset by successful horizontal well performance in southern Alberta associated with our current drilling program and higher production at Pelican Lake as a result of additional infill wells coming on-stream and an increased response from the polymer flood program. In the first quarter of 2013, Lower Shaunavon produced an average of 4,888 barrels per day.

Condensate

Revenues represent the total value of blended oil sold and include the value of condensate. The total value of condensate remained consistent in the first quarter as compared to 2013.

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Royalties

Royalties increased $7 million primarily 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.

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 the first quarter of 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 land, which is the land we hold the mineral rights to. Production from fee lands results in mineral tax recorded within production and mineral taxes.

In the first quarter, the effective crude oil royalty rate for all of our Conventional properties was 9.1 percent (2013 — 9.2 percent).

Expenses

Transportation and Blending

Transportation and blending costs increased $3 million in the first quarter of 2014. Transportation costs rose $3 million largely due to the higher cost associated with transporting our light and medium crude oil production by rail. The higher transportation cost for rail was more than offset by higher prices which overall improved our netback. The overall cost of condensate was unchanged as discussed in the Revenues section.

Operating

Primary drivers of our operating costs in the first quarter of 2014 were workover activities, workforce costs, electricity, repairs and maintenance and chemical consumption.

Operating costs for our Conventional crude oil properties increased $3.76 per barrel to $21.06 per barrel. The total dollar increase of $21 million was primarily due to:

·Increased workover and repairs and maintenance activities related to well optimizations; and

·Higher chemical costs associated with polymer consumption and price related to the expansion of the polymer flood program at Pelican Lake.

The cost increases in our crude oil operating costs were partially offset by declines in operating costs due to the sale of Lower Shaunavon.

(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 our heavy oil properties was $17.56 per barrel in the first quarter (2013 — $17.93 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

Risk Management

Risk management activities in the first quarter resulted in realized losses of $13 million (2013 — gains of $20 million), consistent with average benchmark prices exceeding our contract prices.

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Conventional — Natural Gas

Financial Results

	Three Months Ended March 31,
($ millions)	2014		2013
Gross Sales	184		155
Less: Royalties	3		2
Revenues	181		153
Expenses
Transportation and Blending	5		7
Operating	49		52
Production and Mineral Taxes	(1	)	1
(Gain) Loss on Risk Management	—		(18	)
Operating Cash Flow (1)	128		111
Capital Investment	7		8
Operating Cash Flow Net of Related Capital Investment	121		103

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

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

Revenues

Pricing

Our average natural gas sales price increased $1.21 per Mcf to $4.46 per Mcf, consistent with the rise in the benchmark AECO natural gas price.

Production

Production decreased 13 percent to 457 MMcf per day primarily due to expected natural declines and temporary production losses due to wellhead freeze-offs as a result of cold weather.

Royalties

Royalties increased slightly as a result of higher prices, despite declines in production. The average royalty rate in the first quarter was 1.3 percent (2013 — 1.6 percent). Most of our natural gas production is located on fee land which results in mineral tax recorded within production and mineral taxes.

Expenses

Operating

Primary drivers of our operating expenses in the first quarter of 2014 were property taxes and lease costs, workforce costs and repairs and maintenance. Operating expenses decreased $3 million in the first quarter primarily related to a decrease in workforce costs due to strategic redeployment of workforce away from natural gas activities to focus on crude oil activities.

Risk Management

In the first quarter of 2014, there were no realized gains or losses on our natural gas contracts. Risk management activities in the first quarter of 2013 resulted in realized gains of $18 million, consistent with our contract prices exceeding average benchmark prices.

Conventional — Capital Investment (1)

	Three Months Ended March 31,
($ millions)	2014	2013
Pelican Lake	71	140
Other Heavy Oil	35	32
Light and Medium Oil	157	158
Natural Gas	7	8
	270	338

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

Capital investment in the first quarter of 2014 was composed primarily 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.

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Conventional Drilling Activity

	Three Months Ended March 31,
(net wells, unless otherwise stated)	2014	2013
Crude Oil	52	78
Recompletions	223	293
Gross Stratigraphic Test Wells	13	9
Other (1)	16	26

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

Crude oil wells drilled reflect the continued development of our Conventional properties. Well recompletions are mostly related to lower-risk Alberta coal bed methane development. Drilling of stratigraphic test wells increased in the first quarter of 2014 in order to further assess our tight oil plays in Alberta.

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 is forecast to be between $540 million and $590 million, which will be focused on tight oil development and facilities work.

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. We believe that this method of calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by total proved reserves.

In the first quarter, Conventional DD&A decreased $47 million to $252 million (2013 — $299 million) as a result of a decrease in the average DD&A rates and declines in sales volumes, due primarily to the sale of the Lower Shaunavon asset in July 2013.

REFINING AND MARKETING

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

Significant factors related to our Refining and Marketing segment in the first quarter of 2014 compared with 2013 include:

·Refined product output declined as a result of planned maintenance and turnarounds at both refineries in 2014 as compared to 2013;

·Sanctioning a debottlenecking project at the Wood River Refinery; and

·Operating Cash Flow decreasing 54 percent to $245 million primarily due to declines in market crack spreads, higher heavy crude oil feedstock costs, and lower refined product output.

Refinery Operations (1)

	Three Months Ended March 31,
	2014	2013
Crude Oil Capacity (2) (Mbbls/d)	460	457
Crude Oil Runs (Mbbls/d)	400	416
Heavy Crude Oil	195	197
Light/Medium	205	219
Crude Utilization (percent)	87	91
Refined Products (Mbbls/d)	420	439
Gasoline	215	225
Distillate	130	133
Other	75	81

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

(2)   The official nameplate capacity 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.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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In the first quarter of 2014, crude oil runs and refined product output declined due to planned maintenance and turnarounds at both of our refineries. In the first quarter of 2013, there were no significant turnaround activities at Borger. While total refined product output was decreased, the proportion of gasoline, distillate and other refined product output remained relatively the same.

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 heavy crude oil, a feedstock cost advantage is created by processing less expensive heavy 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.

Financial Results

	Three Months Ended March 31,
($ millions)	2014		2013
Revenues	3,258		2,946
Purchased Product	2,820		2,277
Gross Margin	438		669
Expenses
Operating (1)	198		136
(Gain) Loss on Risk Management	(5	)	4
Operating Cash Flow (2)	245		529
Capital Investment	23		25
Operating Cash Flow Net of Related Capital Investment	222		504

(1)In 2013, we reclassified expenditures related to research activities from operating expenses to research costs.

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

Gross Margin

In the first quarter of 2014, the gross margin for the Refining and Marketing segment declined $231 million or 35 percent as a result of 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 a decrease in refined product output, as a result of planned maintenance and turnarounds at both of our refineries in 2014.

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 first quarter of 2014, our RINs cost was $26 million relatively consistent with 2013 (2013 — $24 million). These costs remain a minor component of our total refinery feedstock costs.

Operating Expense

Primary drivers of operating costs in the first quarter of 2014 were maintenance, labour, utilities and supplies. Operating costs increased 46 percent in 2014 primarily due to higher utility costs, resulting from a rise in natural gas and electricity prices, and increased costs associated with planned maintenance and turnaround activities in the quarter.

Refining and Marketing — Capital Investment

	Three Months Ended March 31,
($ millions)	2014	2013
Wood River Refinery	11	13
Borger Refinery	12	12
	23	25

Capital expenditures in the first quarter of 2014 focused on capital maintenance and refinery reliability and safety projects. We sanctioned a debottlenecking project at the Wood River Refinery in the first quarter of 2014. We are currently awaiting permit approval, which is expected in the fourth quarter of 2014, and planned start-up of the project is expected 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.

In the first quarter, Refining and Marketing DD&A increased $7 million to $39 million (2013 — $32  million) primarily due to the change in the US$/C$ foreign exchange rate.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices and the unrealized mark-to-market gains and losses on the long-term power purchase contract. In the first quarter, our risk management activities resulted in $26 million of unrealized gains, before tax (2013 — $230 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 March 31,
($ millions)	2014		2013
General and Administrative	109		83
Finance Costs	130		123
Interest Income	(2	)	(27	)
Foreign Exchange (Gain) Loss, Net	147		52
Research Costs	2		3
Other (Income) Loss, Net	(1	)	2
	385		236

Expenses

General and Administrative

Primary drivers of our general and administrative expenses in the first quarter of 2014 were workforce, office rent and long-term incentive costs. General and administrative expenses increased $26 million primarily due to increases in long-term incentive expense, consistent with the change in our common 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 were $7 million higher than in 2013 due to higher interest expenses on long-term debt resulting from the weakening of the Canadian dollar and higher unwinding of the discount on decommissioning liabilities. Increases were partially offset by lower interest incurred on the Partnership Contribution Payable as the balance continued to be repaid. On March 28, 2014, we exercised our right to prepay the remaining principal and accrued interest due under the Partnership Contribution Payable in the amount of US$1.4 billion, net to Cenovus. In order to fund this prepayment, we used the net proceeds of approximately US$1.4 billion received in December 2013 from our partner when they elected to prepay the Partnership Contribution Receivable.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for the first quarter was 5.1 percent (2013 — 5.3 percent).

Foreign Exchange

	Three Months Ended March 31,
($ millions)	2014	2013
Unrealized Foreign Exchange (Gain) Loss	143	50
Realized Foreign Exchange (Gain) Loss	4	2
	147	52

In the first quarter of 2014, the majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt with the weakening of the Canadian dollar at March 31, 2014.

DD&A

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.

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. DD&A for the first quarter was $20 million (2013 — $19 million) remaining relatively consistent.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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Income Tax Expense

	Three Months Ended March 31,
($ millions)	2014		2013
Current Tax
Canada	43		30
U.S.	32		54
Total Current Tax	75		84
Deferred Tax	36		39
	111		123
Effective Tax Rate	31	%	42	%

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.

In the first quarter of 2014, current taxes decreased $9 million compared with 2013 primarily due to a shift in the mix of where income is derived. Deferred tax decreased $3 million when compared to 2013. A decrease in the reversal of U.S. timing differences in the current quarter was offset by Canadian source unrealized risk management gains compared with losses in 2013. Given expected levels of income in the U.S. in 2014, the residual pool of U.S. net operating losses is expected to be fully 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 first quarter when compared with 2013 is primarily due to lower levels of U.S. source income in 2014.

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

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended March 31,
($ millions)	2014		2013
Net Cash From (Used In)
Operating Activities	457		895
Investing Activities	(2,397	)	(903	)
Net Cash Provided (Used) Before Financing Activities	(1,940	)	(8	)
Financing Activities	246		(166	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	57		(8	)
Increase (Decrease) in Cash and Cash Equivalents	(1,637	)	(182	)

	March 31, 2014	December 31, 2013
Cash and Cash Equivalents	815	2,452

At March 31, 2014, cash and cash equivalents of $815 million included $692 million of cash in FCCL Partnership and WRB Refining LP.

Operating Activities

Cash from operating activities was $438 million lower in the first quarter of 2014 mainly due to the change in non-cash working capital primarily due to increases in inventory related to downtime at our refinery in the quarter and to meet line fill requirements on new pipeline commitments. Excluding risk management assets and liabilities and assets and liabilities held for sale, working capital was $724 million at March 31, 2014 compared with $1,957 million at December 31, 2013. We anticipate that we will continue to meet our payment obligations as they come due.

Investing Activities

In the first quarter, cash used in investing activities was $2,397 million, $1,494 million higher than in 2013. The increase was predominately due to the prepayment of the US$1.4 billion Partnership Contribution Payable in March 2014. In order to fund this prepayment, we used the net proceeds of approximately US$1.4 billion received in December 2013 from our partner when they elected to prepay the Partnership Contribution Receivable. The early repayment of the Partnership Contribution Payable will result in savings on interest costs that would have been paid over the next three years.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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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. On March 31, 2014, we paid a dividend of $0.2662 per share (2013 — $0.242 per share). The total dividend payment in the first quarter was $202 million (2013 — $184 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Cash provided in financing activities in the first quarter increased $412 million from 2013 primarily as a result of an increase in short-term borrowings.

Our long-term debt at March 31, 2014, was $5,196 million with no principal payments due until October 2019 (US$1.3 billion). The $199 million increase in long-term debt from December 31, 2013 was due to fluctuations in foreign exchange rates.

As at March 31, 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 March 31, 2014.

($ millions)	Amount	Term
Cash and Cash Equivalents	815	Not applicable
Committed Credit Facility	2,561	November 2017
Canadian Base Shelf Prospectus (1)	1,500	June 2014
U.S. Base Shelf Prospectus (1)	US$1,200	July 2014

(1)Availability is subject to market conditions.

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.

As of March 31, 2014, no medium-term notes were issued under our Canadian shelf prospectus and US$1.2 billion remains available under our US$3.25 billion U.S. base shelf prospectus, the availability of which is dependent on market conditions.

It is our intention to file a new Canadian shelf prospectus and a new U.S. shelf prospectus prior to the maturity of the existing prospectuses.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. We define our non-GAAP measure of Debt as short-term borrowings and the current and long-term portions of long-term debt 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. These metrics are used to steward our overall debt position and as measures of our overall financial strength.

	March 31,		December 31,
As at	2014		2013
Debt to Capitalization	36	%	33	%
Debt to Adjusted EBITDA (times)	1.4	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 March 31, 2014, our Debt to Capitalization and Debt to Adjusted EBITDA metrics were near the middle of our target ranges. The increase in our metrics can be attributed, in part, to higher long-term debt as a result of a weaker Canadian dollar and an increase in our short-term borrowings. Additional information regarding our financial metrics and capital structure can be found in the notes to the interim Consolidated Financial Statements.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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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. At March 31, 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 March 31, 2014	Units (thousands)
Common Shares	756,868
Stock Options
NSRs	41,299
TSARs	4,571
Cenovus Replacement TSARs	10
Encana Replacement TSARs	64
Other Stock-Based Compensation Plans
PSUs	7,094
DSUs	1,263

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.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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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.

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. 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 March 31,
	2014						2013
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	34		(26	)	8		(43	)	190		147
Natural Gas	—		1		1		(19	)	42		23
Refining	(4	)	(1	)	(5	)	4		(2	)	2
Power	—		—		—		—		—		—
(Gain) Loss on Risk Management	30		(26	)	4		(58	)	230		172
Income Tax Expense (Recovery)	(7	)	7		—		14		(57	)	(43	)
(Gain) Loss on Risk Management, After Tax	23		(19	)	4		(44	)	173		129

In the first quarter of 2014, management of commodity price risk resulted in realized losses on crude oil financial instruments, consistent with average benchmark prices exceeding our contract prices. We recognized unrealized gains as a result of the changes in forward commodity prices compared with prices at the end of 2013 and changes in prices for transactions executed during the three months ended March 31, 2014, as well as the realization of settled positions, partially offset by the narrowing of forward light/heavy differentials.

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.

Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts 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 quarter 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 quarter 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.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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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

There were no new or amended standards issued during the three months ended March 31, 2014 that are applicable to Cenovus in future periods. A description of standards and interpretations that will be adopted by Cenovus in future periods can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2013.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) during the three months ended March 31, 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.

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

In February 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.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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

Commodity Prices Underlying our Financial Results

Our 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 demand growth from the U.S. as the adverse weather impacts experienced in the first quarter of 2014 dissipate. North American 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. The impact of returning Iranian production could be offset by the Russian involvement in Crimea. The overall expectation is for a modest decline in Brent crude oil prices in 2014 compared with 2013, with higher valuations anticipated in the second half of 2014;

·The Brent-WTI differential is expected to narrow from 2013 as new pipeline capacity from Cushing to the Gulf Coast reduces inland congestion, partially offset by increased discounts of Gulf Coast crude oil prices relative to Brent crude oil prices as growing tight oil supply reduces the need for imports and creates occasional congestion;

·We expect 2014 WTI-WCS price differentials to narrow compared to 2013 levels with increased crude oil transport by rail and pipeline takeaway capacity more than offsetting crude supply growth;

·Average refining crack spreads in 2014 are expected to weaken compared with 2013, mostly due to a narrower Brent-WTI differential;

·Natural gas prices are expected to strengthen compared with 2013 due to reduced storage levels as a result of an abnormally cold winter; and

·An average foreign exchange forward price of US$0.901/C$1 over the next four quarters. The weakening of the Canadian dollar 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 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 U.S. markets and also to tidewater markets.

(1) Expected gross production capacity.

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First Quarter 2014 Report	Management’s Discussion and Analysis

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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.
First Quarter 2014 Report	Management’s Discussion and Analysis

41

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the Period Ended March 31,

($ millions, except per share amounts)

		Three Months Ended
	Notes	2014			2013
Revenues	1
Gross Sales		5,115			4,377
Less: Royalties		103			58
		5,012			4,319
Expenses	1
Purchased Product		2,579			2,155
Transportation and Blending		653			558
Operating		572			439
Production and Mineral Taxes		7			10
(Gain) Loss on Risk Management	21	4			172
Depreciation, Depletion and Amortization		454			455
General and Administrative		109			83
Finance Costs	4	130			123
Interest Income	5	(2		)	(27		)
Foreign Exchange (Gain) Loss, Net	6	147			52
Research Costs		2			3
Other (Income) Loss, Net		(1		)	2
Earnings Before Income Tax		358			294
Income Tax Expense	7	111			123
Net Earnings		247			171
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		(8		)	2
Items That May be Subsequently Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		70			27
Total Other Comprehensive Income (Loss), Net of Tax		62			29
Comprehensive Income		309			200
Net Earnings Per Common Share	8
Basic		$	0.33		$	0.23
Diluted		$	0.33		$	0.23

See accompanying Notes to Consolidated Financial Statements (unaudited).

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First Quarter 2014 Report	Consolidated Financial Statements

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CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		March 31,	December 31,
	Notes	2014	2013
Assets
Current Assets
Cash and Cash Equivalents		815	2,452
Accounts Receivable and Accrued Revenues		2,200	1,874
Income Tax Receivable		15	15
Inventories	9	1,597	1,259
Risk Management	21	3	10
Assets Held for Sale	10	28	—
Current Assets		4,658	5,610
Exploration and Evaluation Assets	1,11	1,580	1,473
Property, Plant and Equipment, Net	1,12	17,933	17,334
Risk Management	21	1	—
Income Tax Receivable		12	—
Other Assets		66	68
Goodwill	1	739	739
Total Assets		24,989	25,224
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		3,113	2,937
Income Tax Payable		351	268
Current Portion of Partnership Contribution Payable	13	—	438
Short-Term Borrowings	14	439	—
Risk Management	21	107	136
Liabilities Related to Assets Held for Sale	10	10	—
Current Liabilities		4,020	3,779
Long-Term Debt	15	5,196	4,997
Partnership Contribution Payable	13	—	1,087
Risk Management	21	2	3
Decommissioning Liabilities	16	2,592	2,370
Other Liabilities		149	180
Deferred Income Taxes		2,931	2,862
Total Liabilities		14,890	15,278
Shareholders’ Equity		10,099	9,946
Total Liabilities and Shareholders’ Equity		24,989	25,224

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2014 Report	Consolidated Financial Statements

43

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	—		—	171		—	171
Other Comprehensive Income (Loss)	—		—	—		29	29
Total Comprehensive Income	—		—	171		29	200
Common Shares Issued Under Stock Option Plans	20		—	—		—	20
Common Shares Cancelled	(3	)	3	—		—	—
Stock-Based Compensation Expense	—		13	—		—	13
Dividends on Common Shares	—		—	(184	)	—	(184	)
Balance as at March 31, 2013	3,846		4,170	1,717		98	9,831
Balance as at December 31, 2013	3,857		4,219	1,660		210	9,946
Net Earnings	—		—	247		—	247
Other Comprehensive Income (Loss)	—		—	—		62	62
Total Comprehensive Income	—		—	247		62	309
Common Shares Issued Under Stock Option Plans	24		—	—		—	24
Stock-Based Compensation Expense	—		22	—		—	22
Dividends on Common Shares	—		—	(202	)	—	(202	)
Balance as at March 31, 2014	3,881		4,241	1,705		272	10,099

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2014 Report	Consolidated Financial Statements

44

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the Period Ended March 31,

($ millions)

		Three Months Ended
	Notes	2014		2013
Operating Activities
Net Earnings		247		171
Depreciation, Depletion and Amortization		454		455
Deferred Income Taxes	7	36		39
Unrealized (Gain) Loss on Risk Management	21	(26	)	230
Unrealized Foreign Exchange (Gain) Loss	6	143		50
Unwinding of Discount on Decommissioning Liabilities	4,16	30		24
Other		20		2
		904		971
Net Change in Other Assets and Liabilities		(42	)	(34	)
Net Change in Non-Cash Working Capital		(405	)	(42	)
Cash From Operating Activities		457		895
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	11	(104	)	(168	)
Capital Expenditures — Property, Plant and Equipment	12	(725	)	(750	)
Proceeds From Divestiture of Assets		1		1
Net Change in Investments and Other	13	(1,579	)	(2	)
Net Change in Non-Cash Working Capital		10		16
Cash (Used in) Investing Activities		(2,397	)	(903	)
Net Cash Provided (Used) Before Financing Activities		(1,940	)	(8	)
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		426		—
Proceeds on Issuance of Common Shares		22		18
Dividends Paid on Common Shares	8	(202	)	(184	)
Cash From (Used in) Financing Activities		246		(166	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		57		(8	)
Increase (Decrease) in Cash and Cash Equivalents		(1,637	)	(182	)
Cash and Cash Equivalents, Beginning of Period		2,452		1,160
Cash and Cash Equivalents, End of Period		815		978

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
First Quarter 2014 Report	Consolidated Financial Statements

45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

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

Cenovus 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.
First Quarter 2014 Report	Notes to Consolidated Financial Statements

46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

A) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the three months ended March 31,	2014	2013		2014	2013		2014		2013
Revenues
Gross Sales	1,260	852		838	701		3,258		2,946
Less: Royalties	51	14		52	44		—		—
	1,209	838		786	657		3,258		2,946
Expenses
Purchased Product	—	—		—	—		2,820		2,277
Transportation and Blending	559	465		94	93		—		—
Operating	181	127		195	177		198		136
Production and Mineral Taxes	—	—		7	10		—		—
(Gain) Loss on Risk Management	22	(24	)	13	(38	)	(5	)	4
Operating Cash Flow	447	270		477	415		245		529
Depreciation, Depletion and Amortization	143	105		252	299		39		32
Segment Income	304	165		225	116		206		497

	Corporate and Eliminations				Consolidated
For the three months ended March 31,	2014		2013		2014		2013
Revenues
Gross Sales	(241	)	(122	)	5,115		4,377
Less: Royalties	—		—		103		58
	(241	)	(122	)	5,012		4,319
Expenses
Purchased Product	(241	)	(122	)	2,579		2,155
Transportation and Blending	—		—		653		558
Operating	(2	)	(1	)	572		439
Production and Mineral Taxes	—		—		7		10
(Gain) Loss on Risk Management	(26	)	230		4		172
	28		(229	)	1,197		985
Depreciation, Depletion and Amortization	20		19		454		455
Segment Income (Loss)	8		(248	)	743		530
General and Administrative	109		83		109		83
Finance Costs	130		123		130		123
Interest Income	(2	)	(27	)	(2	)	(27	)
Foreign Exchange (Gain) Loss, Net	147		52		147		52
Research Costs	2		3		2		3
Other (Income) Loss, Net	(1	)	2		(1	)	2
	385		236		385		236
Earnings Before Income Tax					358		294
Income Tax Expense					111		123
Net Earnings					247		171

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

47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the three months ended March 31,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	1,230	841		651	543		1,881	1,384
Less: Royalties	51	14		49	42		100	56
	1,179	827		602	501		1,781	1,328
Expenses
Transportation and Blending	559	465		89	86		648	551
Operating	170	123		145	124		315	247
Production and Mineral Taxes	—	—		8	9		8	9
(Gain) Loss on Risk Management	22	(23	)	13	(20	)	35	(43	)
Operating Cash Flow	428	262		347	302		775	564

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the three months ended March 31,	2014	2013		2014		2013		2014		2013
Revenues
Gross Sales	27	7		184		155		211		162
Less: Royalties	—	—		3		2		3		2
	27	7		181		153		208		160
Expenses
Transportation and Blending	—	—		5		7		5		7
Operating	4	4		49		52		53		56
Production and Mineral Taxes	—	—		(1	)	1		(1	)	1
(Gain) Loss on Risk Management	—	(1	)	—		(18	)	—		(19	)
Operating Cash Flow	23	4		128		111		151		115

	Other
	Oil Sands			Conventional		Total
For the three months ended March 31,	2014		2013	2014	2013	2014		2013
Revenues
Gross Sales	3		4	3	3	6		7
Less: Royalties	—		—	—	—	—		—
	3		4	3	3	6		7
Expenses
Transportation and Blending	—		—	—	—	—		—
Operating	7		—	1	1	8		1
Production and Mineral Taxes	—		—	—	—	—		—
(Gain) Loss on Risk Management	—		—	—	—	—		—
Operating Cash Flow	(4	)	4	2	2	(2	)	6

	Total Upstream
	Oil Sands			Conventional			Total
For the three months ended March 31,	2014	2013		2014	2013		2014	2013
Revenues
Gross Sales	1,260	852		838	701		2,098	1,553
Less: Royalties	51	14		52	44		103	58
	1,209	838		786	657		1,995	1,495
Expenses
Transportation and Blending	559	465		94	93		653	558
Operating	181	127		195	177		376	304
Production and Mineral Taxes	—	—		7	10		7	10
(Gain) Loss on Risk Management	22	(24	)	13	(38	)	35	(62	)
Operating Cash Flow	447	270		477	415		924	685

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

48

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

C) Geographic Information

	Canada		United States			Consolidated
For the three months ended March 31,	2014	2013	2014		2013	2014	2013
Revenues
Gross Sales	2,815	2,052	2,300		2,325	5,115	4,377
Less: Royalties	103	58	—		—	103	58
	2,712	1,994	2,300		2,325	5,012	4,319
Expenses
Purchased Product	708	491	1,871		1,664	2,579	2,155
Transportation and Blending	653	558	—		—	653	558
Operating	382	308	190		131	572	439
Production and Mineral Taxes	7	10	—		—	7	10
(Gain) Loss on Risk Management	9	170	(5	)	2	4	172
	953	457	244		528	1,197	985
Depreciation, Depletion and Amortization	415	423	39		32	454	455
Segment Income	538	34	205		496	743	530

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

D) Joint Operations

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

FCCL, which is involved in the development and production of crude oil in Canada, is jointly controlled with ConocoPhillips and operated by Cenovus. WRB has two refineries in the U.S. and focuses on the refining of crude oil into petroleum and chemical products. WRB is jointly controlled with and operated by Phillips 66. Cenovus’s share of operating cash flow from FCCL and WRB for the three months ended March 31, 2014 was $418 million and $245 million, respectively (three months ended March 31, 2013 — $221 million and $529 million).

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

By Segment

	E&E (1)		PP&E (2)
	March 31,	December 31,	March 31,	December 31,
As at	2014	2013	2014	2013
Oil Sands	1,425	1,328	7,735	7,401
Conventional	155	145	6,455	6,291
Refining and Marketing	—	—	3,381	3,269
Corporate and Eliminations	—	—	362	373
Consolidated	1,580	1,473	17,933	17,334

	Goodwill		Total Assets
	March 31,	December 31,	March 31,	December 31,
As at	2014	2013	2014	2013
Oil Sands	242	242	10,037	9,564
Conventional	497	497	7,524	7,220
Refining and Marketing	—	—	6,117	5,491
Corporate and Eliminations	—	—	1,311	2,949
Consolidated	739	739	24,989	25,224

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

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

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

49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

By Geographic Region

	E&E		PP&E
	March 31,	December 31,	March 31,	December 31,
As at	2014	2013	2014	2013
Canada	1,580	1,473	14,553	14,066
United States	—	—	3,380	3,268
Consolidated	1,580	1,473	17,933	17,334

	Goodwill		Total Assets
	March 31,	December 31,	March 31,	December 31,
As at	2014	2013	2014	2013
Canada	739	739	19,904	20,548
United States	—	—	5,085	4,676
Consolidated	739	739	24,989	25,224

F) Capital Expenditures (1)

	Three Months Ended
For the period ended March 31,	2014	2013
Capital
Oil Sands	527	537
Conventional	270	338
Refining and Marketing	23	25
Corporate	9	15
	829	915
Acquisition Capital
Conventional	1	3
	830	918

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

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

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

These interim Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) applicable to the preparation of interim financial statements, including International Accounting Standard 34, “Interim Financial Reporting” (“IAS 34”), and have been prepared following the same accounting policies and methods of computation as the annual Consolidated Financial Statements for the year ended December 31, 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 April 29, 2014.

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

50

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 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

There were no new or amended standards issued during the three months ended March 31, 2014 that are applicable to the Company in future periods. A description of 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
For the period ended March 31,	2014	2013
Interest Expense — Short-Term Borrowings and Long-Term Debt	71	66
Interest Expense — Partnership Contribution Payable (Note 13)	22	26
Unwinding of Discount on Decommissioning Liabilities (Note 16)	30	24
Other	7	7
	130	123

5. INTEREST INCOME

	Three Months Ended
For the period ended March 31,	2014		2013
Interest Income — Partnership Contribution Receivable	—		(23	)
Other	(2	)	(4	)
	(2	)	(27	)

6. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended
For the period ended March 31,	2014		2013
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	196		98
U.S. Dollar Partnership Contribution Receivable Issued From Canada	—		(51	)
Other	(53	)	3
Unrealized Foreign Exchange (Gain) Loss	143		50
Realized Foreign Exchange (Gain) Loss	4		2
	147		52

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

51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

7. INCOME TAXES

The provision for income taxes is:

	Three Months Ended
For the period ended March 31,	2014	2013
Current Tax
Canada	43	30
United States	32	54
Total Current Tax	75	84
Deferred Tax	36	39
	111	123

8. PER SHARE AMOUNTS

A) Net Earnings Per Share

	Three Months Ended
For the period ended March 31,	2014		2013
Net Earnings — Basic and Diluted ($ millions)	247		171
Basic — Weighted Average Number of Shares (millions)	756.4		756.0
Dilutive Effect of Cenovus TSARs	0.9		2.4
Diluted — Weighted Average Number of Shares	757.3		758.4
Net Earnings Per Common Share ($)
Basic	$	0.33	$	0.23
Diluted	$	0.33	$	0.23

B) Dividends Per Share

The Company paid dividends of $202 million or $0.2662 per share for the three months ended March 31, 2014 (March 31, 2013 — $184 million, $0.242 per share). The Cenovus Board of Directors declared a second quarter dividend of $0.2662 per share, payable on June 30, 2014, to common shareholders of record as of June 13, 2014.

9. INVENTORIES

	March 31,	December 31,
As at	2014	2013
Product
Refining and Marketing	1,402	1,047
Oil Sands	137	156
Conventional	19	17
Parts and Supplies	39	39
	1,597	1,259

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

52

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

10. ASSETS AND LIABILITIES HELD FOR SALE

	March 31,	December 31,
As at	2014	2013
Assets Held for Sale
Property, Plant and Equipment	28	—
Liabilities Related to Assets Held for Sale
Decommissioning Liabilities	10	—

On March 26, 2014, the Company entered into an agreement with an unrelated third party to sell certain of its Bakken properties included in the Conventional segment. As at March 31, 2014, the Company classified these properties as held for sale. The assets were recorded at the lesser of fair value less costs of disposal and their carrying amount. No impairment was recorded on the reclassification. The sale was completed on April 1, 2014, for proceeds of $36 million before closing adjustments.

11. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2012	1,285
Additions	331
Transfers to PP&E (Note 12)	(95	)
Exploration Expense	(50	)
Divestitures	(17	)
Change in Decommissioning Liabilities	19
As at December 31, 2013	1,473
Additions	104
Transfers to PP&E (Note 12)	—
Change in Decommissioning Liabilities	3
As at March 31, 2014	1,580

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 three months ended March 31, 2014 include $15 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 three months ended March 31, 2014 or for the year ended December 31, 2013.

For the three months ended March 31, 2014, less than $1 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. There was no impairment of E&E assets for the three months ended March 31, 2014 (year ended December 31, 2013 — $50 million).

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

53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

12. 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 11)	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	682		11	23		9	725
Transfers From E&E Assets (Note 11)	—		—	—		—	—
Transfers and Reclassifications	(54	)	—	—		—	(54	)
Change in Decommissioning Liabilities	228		—	—		—	228
Exchange Rate Movements	—		—	143		—	143
Divestitures	(1	)	—	—		—	(1	)
As at March 31, 2014	30,245		297	3,820		858	35,220
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	388		7	39		20	454
Transfers and Reclassifications	(27	)	—	—		—	(27	)
Exchange Rate Movements	—		—	15		—	15
As at March 31, 2014	16,152		200	440		495	17,287
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 March 31, 2014	14,093		97	3,380		363	17,933

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

Additions to development and production assets include internal costs directly related to the development and construction of crude oil and natural gas properties of $57 million for the three months ended March 31, 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 three months ended March 31, 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”):

	March 31,	December 31,
As at	2014	2013
Development and Production	268	225
Refining Equipment	107	97
	375	322

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

54

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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 $439 million as at March 31, 2014 (December 31, 2013 — $nil). The Company reserves capacity under its committed credit facility for amounts of commercial paper outstanding.

15. LONG-TERM DEBT

	March 31,		December 31,
As at	2014		2013
Revolving Term Debt (1)	—		—
U.S. Dollar Denominated Unsecured Notes	5,250		5,052
Total Debt Principal	5,250		5,052
Debt Discounts and Transaction Costs	(54	)	(55	)
	5,196		4,997

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

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

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:

	March 31,		December 31,
As at	2014		2013
Decommissioning Liabilities, Beginning of Year	2,370		2,315
Liabilities Incurred	18		45
Liabilities Settled	(31	)	(76	)
Transfers and Reclassifications	(10	)	(26	)
Change in Estimated Future Cash Flows	5		414
Change in Discount Rate	208		(401	)
Unwinding of Discount on Decommissioning Liabilities	30		97
Foreign Currency Translation	2		2
Decommissioning Liabilities, End of Period	2,592		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 4.7 percent as at March 31, 2014 (December 31, 2013 — 5.2 percent).

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

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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

	March 31, 2014		December 31, 2013
As at	Number of Common Shares(thousands)	Amount	Number of Common Shares(thousands)		Amount
Outstanding, Beginning of Year	756,046	3,857	755,843		3,829
Common Shares Issued Under Stock Option Plans	822	24	970		31
Common Shares Cancelled	—	—	(767	)	(3	)
Outstanding, End of Period	756,868	3,881	756,046		3,857

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

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

18. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

As at March 31, 2013	Defined Benefit Plan		Foreign Currency Translation	Availablefor Sale Investments	Total
Balance, Beginning of Year	(26	)	95	—	69
Other Comprehensive Income, Before Tax	3		27	—	30
Income Tax	(1	)	—	—	(1	)
Balance, End of Period	(24	)	122	—	98

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

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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 tandem stock appreciation rights (“TSARs”) or net settlement rights (“NSRs”).

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

As at March 31, 2014	Issued	Term(Years)	Weighted  Average  Remaining  Contractual  Life (Years)	Weighted  Average  Exercise  Price ($)	Closing Share  Price ($)	Number ofUnitsOutstanding (thousands)
NSRs	On or After February 24, 2011	7	5.83	32.72	31.97	41,299
TSARs	Prior to February 17, 2010	5	0.62	26.59	31.97	90
TSARs	On or After February 17, 2010	7	2.95	26.72	31.97	4,481
Encana (1) Replacement TSARs Held by Cenovus Employees	Prior to December 1, 2009	5	0.43	30.38	23.61	64
Cenovus Replacement TSARs Held by Encana Employees	Prior to December 1, 2009	5	0.34	27.55	31.97	10

(1) Encana Corporation (“Encana”).

NSRs

The weighted average unit fair value of NSRs granted during the three months ended March 31, 2014 was $4.68 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model.

The following table summarizes information related to the NSRs:

As at March 31, 2014	Number of NSRs (thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	26,315		35.26
Granted	15,243		28.40
Forfeited	(259	)	35.84
Outstanding, End of Period	41,299		32.72
Exercisable, End of Period	13,009		36.53

TSARs Held by Cenovus Employees

The Company has recorded a liability of $27 million at March 31, 2014 (December 31, 2013 — $33 million) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. The intrinsic value of vested TSARs held by Cenovus employees at March 31, 2014 was $24 million (December 31, 2013 — $27 million).

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

As at March 31, 2014	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	7,086		26.56
Exercised for Cash Payment	(1,651	)	26.27
Exercised as Options for Common Shares	(813	)	26.28
Forfeited	—		26.32
Expired	(51	)	26.28
Outstanding, End of Period	4,571		26.72
Exercisable, End of Period	4,571		26.72

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $29.22.

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

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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 March 31, 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 March 31, 2014 was $nil (December 31, 2013 — $nil).

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

As at March 31, 2014	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	3,904		29.06
Forfeited	(83	)	29.06
Expired	(3,757	)	29.04
Outstanding, End of Period	64		30.38
Exercisable, End of Period	64		30.38

The closing price of Encana common shares on the TSX as at March 31, 2014 was $23.61.

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 less than $1 million as at March 31, 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 March 31, 2014 was less than $1 million (December 31, 2013 — $6 million).

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

As at March 31, 2014	Number of TSARs(thousands)		WeightedAverageExercisePrice ($)
Outstanding, Beginning of Year	1,479		26.28
Exercised for Cash Payment	(1,399	)	26.27
Exercised as Options for Common Shares	(9	)	26.32
Forfeited	—		26.27
Expired	(61	)	26.27
Outstanding, End of Period	10		27.55
Exercisable, End of Period	10		27.55

For options exercised during the period, the weighted average market price of Cenovus’s common shares at the date of exercise was $29.26.

B) Performance Share Units

The Company has recorded a liability of $100 million at March 31, 2014 (December 31, 2013 — $103 million) in the Consolidated Balance Sheets for performance share units (“PSUs”) based on the market value of Cenovus’s common shares at March 31, 2014. The intrinsic value of vested PSUs was $nil at March 31, 2014 and December 31, 2013 as PSUs are paid out upon vesting.

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

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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

As at March 31, 2014	Number of PSUs(thousands)
Outstanding, Beginning of Year	5,785
Granted	2,964
Vested and Paid Out	(1,625	)
Cancelled	(90	)
Units in Lieu of Dividends	60
Outstanding, End of Period	7,094

C) Deferred Share Units

The Company has recorded a liability of $40 million at March 31, 2014 (December 31, 2013 — $36 million) in the Consolidated Balance Sheets for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares at March 31, 2014. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

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

As at March 31, 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	10
Outstanding, End of Period	1,263

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
For the period ended March 31,	2014	2013
NSRs	13	7
TSARs Held by Cenovus Employees	—	(8	)
PSUs	32	15
DSUs	4	—
Stock-Based Compensation Expense (Recovery)	49	14

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 Energy Inc.
First Quarter 2014 Report	Notes to Consolidated Financial Statements

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

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

	March 31,		December 31,
As at	2014		2013
Short-Term Borrowings	439		—
Long-Term Debt	5,196		4,997
Debt	5,635		4,997
Shareholders’ Equity	10,099		9,946
Capitalization	15,734		14,943
Debt to Capitalization	36	%	33	%

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

	March 31,		December 31,
As at	2014		2013
Debt	5,635		4,997
Net Earnings	738		662
Add (Deduct):
Finance Costs	536		529
Interest Income	(71	)	(96	)
Income Tax Expense	420		432
Depreciation, Depletion and Amortization	1,832		1,833
E&E Impairment	50		50
Unrealized (Gain) Loss on Risk Management	159		415
Foreign Exchange (Gain) Loss, Net	303		208
(Gain) Loss on Divestitures of Assets	1		1
Other (Income) Loss, Net	(1	)	2
Adjusted EBITDA (1)	3,967		4,036
Debt to Adjusted EBITDA	1.4	x	1.2	x

(1)Calculated on a trailing 12 month basis.

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 March 31, 2014, Cenovus had $2.6 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian debt shelf prospectus and unused capacity of US$1.2 billion under its US$3.25 billion debt shelf prospectus, the availability of which are dependent on market conditions.

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

21. FINANCIAL INSTRUMENTS

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

A) Fair Value of Non-Derivative Financial Instruments

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

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

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

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period end trading prices of long-term borrowings on the secondary market (Level 2). As at March 31, 2014, the carrying value of Cenovus’s long-term debt was $5,196 million and the fair value was $5,780 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:

	March 31,	December 31,
As at	2014	2013
Fair Value, Beginning of Year	32	14
Acquisition of Investments	3	5
Change in Fair Value (1)	—	13
Fair Value, End of Period	35	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 March 31, 2014 range from $41.25 to $76.50 per Megawatt Hour.

Summary of Unrealized Risk Management Positions

	March 31, 2014				December 31, 2013
	Risk Management				Risk Management
As at	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Crude Oil	3	104	(101	)	10	136	(126	)
Natural Gas	1	2	(1	)	—	—	—
Power	—	3	(3	)	—	3	(3	)
Total Fair Value	4	109	(105	)	10	139	(129	)

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

	March 31,		December 31,
As at	2014		2013
Prices Sourced From Observable Data or Market Corroboration (Level 2)	(102	)	(126	)
Prices Determined From Unobservable Inputs (Level 3)	(3	)	(3	)
	(105	)	(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.

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

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:

	Three Months Ended
For the period ended March 31,	2014		2013
Fair Value of Contracts, Beginning of Year	(129	)	270
Fair Value of Contracts Realized During the Period	30		(58	)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Period	(4	)	(172	)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	(2	)	4
Fair Value of Contracts, End of Period	(105	)	44

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

	Three Months Ended
For the period ended March 31,	2014		2013
Realized (Gain) Loss (1)	30		(58	)
Unrealized (Gain) Loss (2)	(26	)	230
(Gain) Loss on Risk Management	4		172

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

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

22. RISK MANAGEMENT

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

Net Fair Value of Commodity Price Positions at March 31, 2014

As at March 31, 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	(37	)
Brent Fixed Price	20,000 bbls/d	2014	$107.06/bbl	(59	)
WCS Differential (1)	14,900 bbls/d	2014	US$(20.50)/bbl	(5	)
Brent Fixed Price	3,500 bbls/d	2015	$114.21/bbl	1
Other Financial Positions (2)				(1	)
Crude Oil Fair Value Position				(101	)
Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price	111 MMcf/d	2014	$4.61/Mcf	(1	)
Natural Gas Fair Value Position				(1	)
Power Purchase Contracts
Power Fair Value Position				(3	)

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

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

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

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended March 31, 2014

Commodity Price Sensitivities — Risk Management Positions

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to fluctuations in commodity prices, with all other variables held constant. Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity prices on the Company’s open risk management positions as at March 31 could have resulted in unrealized gains (losses) impacting earnings before income tax for the three months ended March 31, 2014:

Risk Management Positions in Place as at March 31, 2014

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent, WTI and Condensate Hedges	(173	)	173
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges tied to Production	23		(23	)
Natural Gas Commodity Price	± $1 per mcf Applied to NYMEX and AECO Natural Gas Hedges	(34	)	34
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.
First Quarter 2014 Report	Notes to Consolidated Financial Statements

63

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

	2014		2013
Revenues	Q1		Year		Q4		Q3		Q2		Q1
Gross Sales
Upstream	2,098		6,892		1,767		1,926		1,646		1,553
Refining and Marketing	3,258		12,706		3,223		3,459		3,078		2,946
Corporate and Eliminations	(241	)	(605	)	(163	)	(190	)	(130	)	(122	)
Less: Royalties	103		336		80		120		78		58
Revenues	5,012		18,657		4,747		5,075		4,516		4,319

	2014		2013
Operating Cash Flow	Q1		Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids
Foster Creek	213		877	204	252	232	189
Christina Lake	215		596	179	248	96	73
Pelican Lake	93		385	92	130	96	67
Other Conventional	254		1,003	232	285	251	235
Natural Gas	151		437	110	94	118	115
Other Upstream Operations	(2	)	27	8	5	8	6
	924		3,325	825	1,014	801	685
Refining and Marketing	245		1,143	151	139	324	529
Operating Cash Flow (1)	1,169		4,468	976	1,153	1,125	1,214

	2014		2013
Cash Flow	Q1		Year		Q4		Q3		Q2		Q1
Cash from Operating Activities	457		3,539		976		840		828		895
Deduct (Add back):
Net Change in Other Assets and Liabilities	(42	)	(120	)	(30	)	(25	)	(31	)	(34	)
Net Change in Non-Cash Working Capital	(405	)	50		171		(67	)	(12	)	(42	)
Cash Flow (2)	904		3,609		835		932		871		971
Per Share - Basic	1.20		4.77		1.10		1.23		1.15		1.28
- Diluted	1.19		4.76		1.10		1.23		1.15		1.28

	2014	2013
Earnings	Q1	Year	Q4		Q3	Q2	Q1
Operating Earnings (3)	378	1,171	212		313	255	391
Per Share - Diluted	0.50	1.55	0.28		0.41	0.34	0.52
Net Earnings (Loss)	247	662	(58	)	370	179	171
Per Share - Basic	0.33	0.88	(0.08	)	0.49	0.24	0.23
- Diluted	0.33	0.87	(0.08	)	0.49	0.24	0.23

	2014		2013
Tax & Exchange Rates	Q1		Year		Q4	Q3	Q2	Q1
Effective Tax Rates using
Net Earnings	31.0	%	39.5	%
Operating Earnings, excluding Divestitures	28.4	%	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	0.906		0.971		0.953	0.963	0.977	0.992
Period end	0.905		0.940		0.940	0.972	0.951	0.985

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

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

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

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

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

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

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

(7)We define trailing 12-month 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.

(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.

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64

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

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

	2014		2013
Net Capital Investment	Q1		Year		Q4		Q3		Q2	Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	221		797		193		205		189	210
Christina Lake	182		688		189		162		162	175
Total	403		1,485		382		367		351	385
Other Oil Sands	124		400		120		59		69	152
	527		1,885		502		426		420	537
Conventional
Pelican Lake	71		463		115		97		111	140
Other Conventional	199		726		216		178		134	198
	270		1,189		331		275		245	338
Refining and Marketing	23		107		37		19		26	25
Corporate	9		81		28		23		15	15
Capital Investment	829		3,262		898		743		706	915
Acquisitions	1		32		27		1		1	3
Divestitures	(2	)	(283	)	(41	)	(241	)	—	(1	)
Net Acquisition and Divestiture Activity	(1	)	(251	)	(14	)	(240	)	1	2
Net Capital Investment	828		3,011		884		503		707	917

Operating Statistics - Before Royalties

	2014	2013
Upstream Production Volumes	Q1	Year	Q4	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands - Heavy Oil
Foster Creek	54,706	53,190	52,419	49,092	55,338	55,996
Christina Lake	65,738	49,310	61,471	52,732	38,459	44,351
	120,444	102,500	113,890	101,824	93,797	100,347
Conventional Liquids
Pelican Lake - Heavy Oil	24,782	24,254	24,528	24,826	23,959	23,687
Other Heavy Oil	16,017	15,991	15,480	15,507	16,284	16,712
Light and Medium Oil	34,598	35,467	33,646	33,651	36,137	38,508
Natural Gas Liquids (1)	1,013	1,063	1,199	1,130	950	971
	76,410	76,775	74,853	75,114	77,330	79,878
Total Crude Oil and Natural Gas Liquids	196,854	179,275	188,743	176,938	171,127	180,225
Natural Gas (MMcf/d)
Oil Sands	19	21	21	23	22	18
Conventional	457	508	493	500	514	527
Total Natural Gas	476	529	514	523	536	545
Total Production (BOE/d)	276,187	267,442	274,410	264,105	260,460	271,058

(1) Natural gas liquids include condensate volumes.

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

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First Quarter 2014 Report	Supplemental Information

65

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

	2014		2013
Refining	Q1		Year		Q4		Q3		Q2		Q1
Refinery Operations (1)
Crude oil capacity (2) (Mbbls/d)	460		457		457		457		457		457
Crude oil runs (Mbbls/d)	400		442		447		464		439		416
Heavy Oil	195		222		221		240		230		197
Light/Medium	205		220		226		224		209		219
Crude utilization	87	%	97	%	98	%	101	%	96	%	91	%
Refined products (Mbbls/d)	420		463		469		487		457		439

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

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

	2014		2013
Selected Average Benchmark Prices	Q1		Year		Q4	Q3	Q2		Q1
Crude Oil Prices (US$/bbl)
Brent	107.90		108.76		109.35	109.71	103.35		112.65
West Texas Intermediate (“WTI”)	98.68		97.97		97.46	105.82	94.22		94.37
Differential Brent Futures-WTI	9.22		10.79		11.89	3.89	9.13		18.28
Western Canadian Select (“WCS”)	75.55		72.77		65.26	88.34	75.06		62.41
Differential - WTI-WCS	23.13		25.20		32.20	17.48	19.16		31.96
Condensate - (C5 @ Edmonton)	102.64		101.69		94.22	103.80	101.50		107.24
Differential - WTI-Condensate (premium)/discount	(3.96	)	(3.72	)	3.24	2.02	(7.28	)	(12.87	)
Refining Margins 3-2-1 Crack Spreads (3)(US$/bbl)
Chicago	18.55		21.77		12.29	16.19	31.06		27.53
Midwest Combined (Group 3)	17.41		20.80		10.66	17.35	27.24		27.93
Natural Gas Prices
AECO ($/Mcf)	4.76		3.17		3.15	2.82	3.59		3.08
NYMEX (US$/Mcf)	4.94		3.65		3.60	3.58	4.09		3.34
Differential - NYMEX-AECO (US$/Mcf)	0.60		0.58		0.59	0.89	0.56		0.27

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

Per-unit Results	2014	2013
(excluding impact of Realized Gain (Loss) on Risk Management)	Q1	Year	Q4	Q3	Q2	Q1
Heavy Oil - Foster Creek (4) ($/bbl)
Price	71.44	66.30	59.39	87.49	68.17	52.60
Royalties	5.71	3.73	3.56	6.31	3.87	1.47
Transportation and Blending	0.78	2.36	3.21	4.37	0.04	1.89
Operating	19.09	15.77	15.90	17.12	16.19	14.03
Netback	45.86	44.44	36.72	59.69	48.07	35.21
Heavy Oil - Christina Lake (4)($/bbl)
Price	59.89	51.26	44.36	74.98	52.61	33.41
Royalties	4.04	3.25	3.22	5.06	2.71	1.69
Transportation and Blending	3.02	3.55	3.29	3.16	4.45	3.67
Operating	13.30	12.47	10.57	11.46	16.83	12.93
Netback	39.53	31.99	27.28	55.30	28.62	15.12
Total Heavy Oil - Oil Sands (4)($/bbl)
Price	65.19	59.10	51.34	81.16	61.88	44.01
Royalties	4.80	3.50	3.37	5.68	3.40	1.57
Transportation and Blending	1.99	2.93	3.25	3.76	1.82	2.69
Operating	15.96	14.19	13.04	14.26	16.45	13.53
Netback	42.44	38.48	31.68	57.46	40.21	26.22
Heavy Oil - Pelican Lake (4)($/bbl)
Price	76.20	70.09	64.52	88.08	72.32	54.30
Royalties	5.04	4.00	1.97	6.64	4.08	3.22
Transportation and Blending	3.07	2.41	2.79	2.18	2.58	2.07
Operating	24.96	20.65	21.22	19.90	22.21	19.23
Netback	43.13	43.03	38.54	59.36	43.45	29.78
Heavy Oil - Other Conventional (4)($/bbl)
Price	82.14	70.65	64.58	86.58	70.81	61.62
Royalties	7.52	9.18	10.40	12.27	7.67	6.57
Transportation and Blending	3.13	2.90	2.54	3.04	2.59	3.39
Operating	21.81	17.34	17.54	16.32	17.38	18.04
Production and Mineral Taxes	0.32	0.31	0.12	0.55	0.30	0.30
Netback	49.36	40.92	33.98	54.40	42.87	33.32
Total Heavy Oil - Conventional (4) ($/bbl)
Price	78.52	70.31	64.55	87.50	71.73	57.42
Royalties	6.01	6.08	5.31	8.83	5.50	4.65
Transportation and Blending	3.09	2.60	2.69	2.51	2.58	2.63
Operating	23.73	19.32	19.76	18.51	20.30	18.72
Production and Mineral Taxes	0.13	0.13	0.05	0.21	0.12	0.13
Netback	45.56	42.18	36.74	57.44	43.23	31.29
Total Heavy Oil (4)($/bbl)
Price	68.64	62.23	54.61	82.97	64.91	47.82
Royalties	5.12	4.22	3.85	6.58	4.05	2.45
Transportation and Blending	2.28	2.84	3.11	3.40	2.06	2.67
Operating	17.97	15.62	14.70	15.47	17.63	15.01
Production and Mineral Taxes	0.03	0.04	0.01	0.06	0.04	0.04
Netback	43.24	39.51	32.94	57.46	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	48.35	42.41	41.85	38.85	42.60	46.00
Christina Lake	52.81	45.25	44.16	39.86	47.13	51.46
Heavy Oil - Oil Sands	50.77	43.77	43.09	39.36	44.43	48.44
Pelican Lake	18.30	15.59	13.58	12.09	16.74	20.31
Other Conventional Heavy Oil	16.40	13.12	10.05	10.96	16.68	14.73
Heavy Oil - Conventional	17.56	14.60	12.18	11.65	16.72	17.93
Total Heavy Oil	42.17	35.63	35.44	31.46	35.91	39.78

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66

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results	2014		2013
(excluding impact of Realized Gain (Loss) on Risk Management)	Q1		Year	Q4	Q3		Q2		Q1
Light and Medium Oil ($/bbl)
Price	94.18		86.30	82.12	100.64		86.84		76.77
Royalties	8.78		8.28	6.58	11.01		8.61		7.05
Transportation and Blending	4.11		4.35	5.15	4.58		4.37		3.39
Operating	18.47		16.23	17.26	15.06		16.32		16.26
Production and Mineral Taxes	2.23		2.30	1.26	2.80		2.64		2.46
Netback	60.59		55.14	51.87	67.19		54.90		47.61
Total Crude Oil ($/bbl)
Price	73.15		67.05	59.41	86.41		69.75		54.02
Royalties	5.76		5.03	4.33	7.44		5.05		3.43
Transportation and Blending	2.60		3.14	3.47	3.63		2.57		2.82
Operating	18.06		15.74	15.15	15.39		17.34		15.27
Production and Mineral Taxes	0.42		0.49	0.23	0.59		0.61		0.56
Netback	46.31		42.65	36.23	59.36		44.18		31.94
Natural Gas Liquids ($/bbl)
Price	67.31		60.34	59.39	65.71		46.44		68.88
Royalties	1.48		1.13	1.14	1.92		1.17		0.12
Netback	65.83		59.21	58.25	63.79		45.27		68.76
Total Liquids ($/bbl)
Price	73.12		67.01	59.41	86.28		69.61		54.10
Royalties	5.74		5.01	4.31	7.40		5.03		3.42
Transportation and Blending	2.59		3.12	3.45	3.61		2.55		2.81
Operating	17.96		15.65	15.06	15.29		17.24		15.19
Production and Mineral Taxes	0.42		0.48	0.23	0.59		0.61		0.55
Netback	46.41		42.75	36.36	59.39		44.18		32.13
Total Natural Gas ($/Mcf)
Price	4.47		3.20	3.21	2.83		3.50		3.25
Royalties	0.06		0.04	0.04	0.05		0.04		0.05
Transportation and Blending	0.11		0.11	0.11	0.10		0.08		0.15
Operating	1.26		1.16	1.23	1.13		1.16		1.14
Production and Mineral Taxes	(0.01	)	0.02	0.02	0.03		(0.01	)	0.03
Netback	3.05		1.87	1.81	1.52		2.23		1.88
Total (1)($/BOE)
Price	59.68		51.23	47.23	63.12		52.55		42.52
Royalties	4.19		3.44	3.07	5.02		3.35		2.38
Transportation and Blending	2.03		2.31	2.60	2.60		1.82		2.17
Operating	14.94		12.79	12.73	12.44		13.64		12.39
Production and Mineral Taxes	0.28		0.36	0.19	0.45		0.38		0.42
Netback	38.24		32.33	28.64	42.61		33.36		25.16
Impact of Long-Term Incentives Costs (Recovery) on Total Operating Costs ($/BOE)	0.29		0.12	0.06	0.23		0.07		0.10
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	(2.00	)	1.09	2.77	(2.02	)	0.72		2.62
Natural Gas ($/Mcf)	—		0.32	0.36	0.38		0.18		0.39
Total (1) ($/BOE)	(1.42	)	1.37	2.58	(0.58	)	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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67

ADVISORY

FINANCIAL INFORMATION

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

Non-GAAP Measures This quarterly report contains references to non-GAAP measures as follows:

·Operating cash flow is defined as revenues, less purchased product, transportation and blending, operating expenses, production and mineral taxes plus realized gains, less realized losses on risk management activities and is used to provide a consistent measure of the cash generating performance of the company’s assets and improves the comparability of Cenovus’s underlying financial performance between periods. 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.

·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.

·Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength. Debt is defined as short-term borrowings and long-term debt, including the current portion, excluding any amounts with respect to the partnership contribution payable and receivable. Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gain or loss on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.

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

OIL AND GAS INFORMATION

The estimates of reserves and resources data and related information were prepared effective December 31, 2013 by independent qualified reserves evaluators, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented using McDaniel & Associates Consultants Ltd.  January 1, 2014 price forecast. For additional information about our reserves, resources and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2013.

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

FORWARD-LOOKING INFORMATION

This 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”, “intend”, “goal”, “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, projected net asset value, forecast operating and financial results, planned capital expenditures, expected future production, including the timing, stability or growth thereof, expected future refining capacity, broadening market access, improving cost structures, 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

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68

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 C$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; WTI of US$100.00-US$106.00/bbl; Western Canada Select of C$81.00-C$91.00/bbl; NYMEX of US$4.25-US$4.75/MMBtu; AECO of C$3.70-C$4.31/GJ; Chicago 3-2-1 crack spread of US$12.00-US$13.00; exchange rate of $1.00 US$/C$; and average diluted number of shares outstanding of approximately 782 million.

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

Cenovus Energy Inc.
First Quarter 2014 Report	Advisory

69

Cenovus Energy Inc.

500 Centre Street SE

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-7600

Cenovus Environment & Corporate Affairs
Investor contacts:	Media contact:
Susan Grey	Media Relations
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
Bill Stait
Senior Analyst, Investor Relations
403-766-6348
bill.stait@cenovus.com

cenovus.com