Exhibit 99.1

Expected 2015 cost savings increase to $400 million

Third-quarter oil sands production up 17%

Calgary, Alberta (October 29, 2015) — Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continues to make significant progress in reducing its costs while delivering strong operational performance and oil sands production growth. The company is benefiting from the decisive steps taken over the past year to increase its financial resilience in the face of what is expected to be a prolonged period of lower oil prices.

“We’re delivering on the commitments we made at the outset of 2015 to improve Cenovus’s position as a  low-cost producer,” said Brian Ferguson, Cenovus President & Chief Executive Officer. “We’ve realized substantial, sustainable cost reductions, maintained capital discipline and strengthened our balance sheet. We  will continue to look for additional opportunities to reduce costs, become more efficient and enhance shareholder value.”

Third quarter highlights

·Maintained financial strength with approximately $4.4 billion of cash and cash equivalents on the balance sheet and a net debt to capitalization ratio of 13%

·Achieved cost reductions that were better than forecast, bringing total anticipated savings for 2015 to approximately $400 million

·On track to achieve $100 million in forecast annual savings, starting in 2016, from workforce reductions

·Reduced oil sands per-unit operating costs by 23% from the third quarter of 2014 and total crude oil per-unit operating expenses by 22%

·Generated cash flow of $444 million, down 55% from the same period a year earlier

·Recognized for strong performance in corporate responsibility as the only North American oil and gas producer to be included in this year’s Dow Jones Sustainability (DJSI) World Index

Production & financial summary

(For the period ended September 30) Production (before royalties)	2015 Q3		2014 Q3	% change
Oil sands (bbls/d)	146,743		125,089	17
Conventional oil1 (bbls/d)	63,679		74,000	-14
Total oil (bbls/d)	210,422		199,089	6
Natural gas (MMcf/d)	430		489	-12
Financial ($ millions, except per share amounts)
Cash flow2	444		985	-55
Per share diluted	0.53		1.30
Operating earnings (loss)2	(28	)	372	-108
Per share diluted	(0.03	)	0.49
Net earnings	1,801		354	409
Per share diluted	2.16		0.47
Capital investment3	400		750	-47

1 Includes natural gas liquids (NGLs) and the impact of non-core asset divestitures in 2014 and 2015.

2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory.

3 Excludes acquisitions and divestitures.

Overview

Cenovus continues to take action to reduce its cost structures to be competitive with light tight oil producers in the U.S. and address the more than 50% decline in benchmark crude oil prices since mid-2014. The company committed earlier this year to streamline its operations and become more efficient to help ensure it is positioned for long-term success during a prolonged period of lower oil prices. To date, the company has achieved meaningful and sustainable improvements in its operating, capital and general and administrative (G&A) costs and reduced the size of its workforce. To align with current market conditions, the company has also made changes to its compensation, benefits and time-off practices, effective in 2016. Cenovus realized significant value for shareholders by selling its royalty interest and fee land business in July for gross cash proceeds of $3.3 billion. Earlier this year, Cenovus also raised capital by issuing common shares and reducing its quarterly dividend as part of the company’s strategy to maintain its long-term financial resilience.

Successful cost reductions

The company’s cost reduction efforts have progressed at a faster pace than expected. Cenovus is now anticipating total 2015 cost savings of approximately $400 million — significantly higher than its July forecast of $280 million in cost reductions and original April forecast of $200 million in cost reductions for the year. Of Cenovus’s targeted 2015 savings, about 65% are expected to come from operating and G&A cost improvements, with the remaining 35% anticipated to come from reduced capital costs. Cenovus anticipates about 60% of the $400 million in savings would be sustainable, even with oil prices recovering to between US$60 per barrel (bbl) and US$65/bbl West Texas Intermediate (WTI).

These cost reductions are being achieved across the company. They include savings related to improved drilling efficiency, optimized scheduling and prioritization of repair and maintenance activities, lower chemical costs and better oil sands waste disposal and handling processes. Some of the savings are the result of work that has been deferred.

In addition to its $400 million overall cost-reduction target for 2015, Cenovus expects to achieve significant additional structural cost savings from its workforce reduction program. In July, the company said it anticipated reducing the size of its workforce by another 300 to 400 positions through the remainder of the year, following an initial round of staff cuts made in February. The company has since identified additional workforce efficiencies and reduced its staff count by 700 positions for the second half of the year, double its July forecast. As a result, Cenovus anticipates finishing 2015 with 24% fewer staff than it had at the end of 2014. The cost savings associated with these workforce reductions are expected to be at least $100 million annually, starting in 2016. Cenovus incurred severance costs of about $3 million in the third quarter and expects to incur additional severance costs of approximately $32 million in the fourth quarter related to its most recent round of staff reductions. Cenovus has completed a review of its compensation, benefits and time-off practices to make sure they are aligned with those of its peers and with market conditions, while remaining competitive and allowing the company to continue to attract and retain talented staff. As a result of this review, the company will be making changes to these practices starting in 2016.

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“We’ve made difficult, but necessary decisions to help us remain financially resilient,” said Ferguson. “It’s important that the size of our workforce matches our more moderate approach to oil sands growth and our reduced cash flow in a lower commodity price environment.”

As previously announced, Cenovus expects to make additional staff reductions in 2016 as a result of the company’s transition to a functional organizational model.

Financial performance

In the third quarter, upstream operating cash flow declined 48% to $570 million primarily due to a 56% decrease in Cenovus’s average crude oil sales price and a 29% decline in its average natural gas sales price. The impact of lower sales prices on upstream operating cash flow was partially offset by realized risk management gains of $206 million on oil and natural gas production, lower royalties due to the weaker crude oil sales prices and a 22% reduction in crude oil operating expenses. Operating cash flow from refining and marketing declined 57% to $29 million. Total operating cash flow was $599 million, a 48% decrease compared with the third quarter of 2014.

Cash flow was $444 million in the third quarter, 55% lower than in the same period in 2014 primarily due to lower crude oil and natural gas sales prices.

Cenovus has significantly strengthened its balance sheet in 2015 with the divestiture of its royalty and fee land business in July 2015 and the $1.5 billion common share issuance that closed in March 2015. The company’s net debt to capitalization ratio was 13% and net debt to adjusted EBITDA was 0.8 times, on a trailing 12-month basis, at September 30, 2015.

“We have one of the strongest balance sheets in the industry with about $4.4 billion of cash and cash equivalents,” said Ferguson. “Cenovus is well positioned to thrive in a lower-for-longer commodity price environment, and we’ll continue to be prudent, directing capital only to projects that meet our stringent investment hurdles.”

Oil sands growth

Oil sands production from Cenovus’s Foster Creek and Christina Lake steam-assisted gravity drainage (SAGD) projects increased 17% in the third quarter of 2015 compared with the same period a year earlier. The increase was the result of the ramp-up of new wells associated with phase F at Foster Creek, improved facility performance and some flush production at Foster Creek after operations were temporarily shut down late in the second quarter due to a nearby forest fire. As expected, flush production has tapered off and production rates have returned to pre-forest fire levels.

Cenovus’s oil sands business achieved solid operating cost reductions of $2.86/bbl in the third quarter compared with the same period a year earlier. Total operating costs were $9.55/bbl, a 23% decrease from the third quarter of 2014. Increased production, workforce reductions and lower fuel and electricity expenses contributed to the oil sands per-unit operating cost savings in the third quarter. Year to date, Cenovus has also achieved operating cost reductions from improved prioritization of its repair and maintenance activities as well as lower workover costs due to fewer electric submersible pump (ESP) replacements.

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The company’s Christina Lake optimization project was completed on time and below budget, with incremental oil production expected to ramp up over a period of 12 months. The project is designed to increase steam generating capacity and optimize oil treating. Christina Lake’s phase F expansion is nearing completion, with first oil expected in the second half of 2016. At Foster Creek, the phase G expansion remains on track for expected production late in the first half of 2016. These three expansion projects are expected to add approximately 100,000 barrels per day (bbls/d) of incremental gross production capacity (50,000 bbls/d net), an increase of about 35% to the company’s current oil sands production capacity.

Disciplined capital allocation

In the third quarter of 2015, the company invested $272 million in its oil sands assets, $55 million in conventional oil and natural gas, $67 million in its refineries and $6 million in corporate activities. Cenovus expects total capital spending for 2015 of $1.8 billion to $1.9 billion, in line with the company’s budget for the year and almost 40% below 2014 spending levels.

“We have tested our financial capacity and even at prices as low as US$45 per barrel WTI through 2017, we believe we can fund our sustaining and growth capital as well as our current dividend level,” said Ferguson. “We also believe we have the financial resilience to consider restarting investment in some of our deferred expansion projects when the timing is right. Those decisions would depend on our ongoing cost-cutting success as well as fiscal and regulatory certainty.”

Currently, Cenovus anticipates capital spending of between $1.5 billion and $2.0 billion in 2016. The low end of the range would include capital for the completion of ongoing Christina Lake and Foster Creek expansion projects that are already well advanced. The high end of the range could include growth capital for the potential resumption of work at Christina Lake phase G and Foster Creek phase H, which were deferred earlier this year.

The company is currently developing its 2016 budget and intends to provide additional details in a news release scheduled for December 10, 2015.

Improving market access

Cenovus is working to develop new markets and businesses to help it gain greater control over a larger part of the value chain for its products. At the end of August, the company completed the acquisition of a crude-by-rail trans-loading facility at Bruderheim, Alberta that was announced in the second quarter. During its first full month of ownership, Cenovus and its third-party operator shipped 12 unit trains from the facility, including five unit trains loaded for contract customers.

To further enhance its market access, Cenovus continues to assess other strategic opportunities to capture global pricing for its oil and increase returns for shareholders.

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Updating guidance

Cenovus has updated its 2015 full-year guidance to reflect actual results for the first nine months of the year and the company’s estimates for the fourth quarter. The updated guidance, available at cenovus.com under “Investors,” reflects Cenovus’s expectations for lower capital spending at Foster Creek and better than anticipated oil sands and conventional operating costs compared with the company’s prior guidance.

Leadership appointments

Cenovus has created the new position on its Leadership Team of Executive Vice-President, Business Innovation. Judy Fairburn has been appointed to the role effective December 1. She will be accountable for developing ground-breaking, cross-sector partnerships in areas of strategic importance to Cenovus. Fairburn has held various leadership roles within Cenovus and its predecessor companies. She has extensive experience building partnerships within the industry and with other sectors, including an integral role in the creation of Canada’s Oil Sands Innovation Alliance (COSIA).

As previously announced as part of the Leadership Team retirement transition, Kerry Dyte will be stepping down as Executive Vice-President, General Counsel & Corporate Secretary on December 1. Al Reid, who has already joined the Leadership Team as Executive Vice-President, Environment, Corporate Affairs & Legal, will take on the role of General Counsel at that time. Gary Molnar, currently Vice-President Legal & Assistant Corporate Secretary, will become Vice-President, Legal, Assistant General Counsel & Corporate Secretary on December 1.

Third quarter details

Oil sands

Christina Lake

·Production averaged 75,329 bbls/d net in the third quarter of 2015, 10% higher than in the same period a year earlier.

·Operating costs were $7.87/bbl in the third quarter, down 24% from $10.40/bbl in the same period of 2014. Non-fuel operating costs were $5.57/bbl, down 21% from the third quarter of 2014.

·The steam to oil ratio (SOR), the amount of steam needed to produce a barrel of oil, was 1.7, unchanged from the third quarter of 2014.

·Netbacks were $13.76/bbl in the third quarter, down 72% from the same period a year ago.

Foster Creek

·Production averaged 71,414 bbls/d net in the third quarter, 26% higher than in the third quarter of 2014.

·Operating costs were $11.37/bbl, a 23% decline compared with the third quarter of 2014. Non-fuel operating costs were $8.72/bbl, a 17% decline from a year earlier.

·The SOR was 2.4 in the third quarter, an improvement from 2.8 in the same period of 2014.

·Netbacks were $13.28/bbl in the third quarter, 76% lower than a year earlier.

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Conventional oil

·Total conventional oil production was 63,679 bbls/d in the third quarter, down 14% from 74,000 bbls/d in the same period a year ago, primarily due to expected natural declines, the sale of Cenovus’s royalty and fee land business, and the sale of a non-core asset in 2014, partially offset by successful horizontal well performance in southern Alberta.

·Operating costs for Cenovus’s conventional oil operations were $15.61/bbl, down 15% from $18.45/bbl in the third quarter of 2014.

Natural gas

·Natural gas production averaged 430 million cubic feet per day (MMcf/d) in the third quarter, down 12% from 489 MMcf/d in the same period in 2014.

·Natural gas per-unit operating costs were down 6% to $1.16 per thousand cubic feet (Mcf) in the quarter, compared with the same period a year ago.

Downstream

·Cenovus’s Wood River Refinery in Illinois and Borger Refinery in Texas processed an average of 394,000 bbls/d gross of crude oil in the third quarter (86% utilization), a decrease of 3% from the same period a year ago due to an unplanned outage at Borger and a planned turnaround at Wood River. Together, the two refineries processed an average of 186,000 bbls/d gross of heavy oil compared with 201,000 bbls/d gross in the third quarter of 2014. The decrease was due to the planned turnaround at Wood River.

·The refineries produced an average of 414,000 bbls/d gross of refined products in the third quarter, down 3% from 429,000 bbls/d gross in the same period a year earlier.

·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 $130 million higher in the third quarter, compared with $53 million higher in the third quarter of 2014.

Financial

Dividends

·The Board of Directors has declared a fourth quarter dividend of $0.16 per share, payable on December 31, 2015 to common shareholders of record as of December 15, 2015. Based on the October 28, 2015 closing share price on the Toronto Stock Exchange of $19.24, this represents an annualized yield of about 3.3%. Declaration of dividends is at the sole discretion of the Board and will continue to be evaluated on a quarterly basis. Over the long term, Cenovus intends to target a dividend payout ratio of 20% to 25% of after-tax cash flows.

·In July, Cenovus announced it had discontinued a temporary discount on its Dividend Reinvestment Plan (DRIP). While the DRIP remains in place, going forward, the company plans to purchase common shares required for the DRIP in the open market, eliminating dilution caused by the issuance of shares from Treasury.

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Corporate and financial information

·In the third quarter, Cenovus had operating cash flow of $599 million. This included $326 million from its oil sands operations, $241 million from conventional oil and natural gas and $29 million from its downstream operations. The sale of the company’s royalty and fee land business reduced total third quarter operating cash flow by approximately $23 million.

·The 57% decline in operating cash flow from refining and marketing was primarily due to higher heavy oil feedstock costs relative to the WTI benchmark price as well as planned and unplanned outages at the company’s two U.S. refineries. This increased operating costs for the third quarter compared with the same period in 2014. The decline was partially offset by improved margins on the sale of secondary products, an increase in average market crack spreads and the weakening of the Canadian dollar relative to the U.S. dollar.

·After investing $400 million in the third quarter, Cenovus had free cash flow of $44 million, down from $235 million in the same period a year earlier.

·Cenovus had an operating loss of $28 million in the third quarter, compared with operating earnings of $372 million in the same quarter in 2014. The decrease was primarily due to significantly lower oil and natural gas prices compared with the third quarter of 2014, partially offset by a deferred tax recovery compared with an expense a year ago.

·Net earnings were $1.8 billion in the third quarter, a more than five-fold increase from the same period a year earlier. The increase was primarily due to an after-tax gain of $1.9 billion resulting from the disposition of Cenovus’s royalty and fee land business as well as a $385 million deferred tax recovery associated with Cenovus’s U.S. refining assets.

·G&A expenses were $75 million, 6% lower than in the third quarter of 2014. The decrease was primarily due to a reduction in discretionary spending, including travel, conferences, offsite meetings and information technology upgrades, offset by higher employee long-term incentive costs compared with the same period in 2014. Cenovus also incurred third quarter severance costs of $3 million related to workforce reductions.

·Over the long term, Cenovus continues to target a debt to capitalization ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of between 1.0 and 2.0 times. At September 30, 2015, the company’s debt to capitalization ratio was 33% and debt to adjusted EBITDA was 2.7 times, on a trailing 12-month basis. The net debt to capitalization ratio was 13% and net debt to adjusted EBITDA was 0.8 times, on a trailing 12-month basis.

Commodity price hedging

·Cenovus had a realized after-tax hedging gain of $161 million in the third quarter, as the company’s contract prices exceeded the average benchmark price. The company had unrealized after-tax hedging gains of $93 million in the quarter, primarily due to changes in market prices.

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Other milestones

·Cenovus had its best safety performance ever during the first nine months of 2015, with a total recordable injury frequency (TRIF) of 0.35, a 50% improvement from the same period in 2014. Foster Creek achieved injury-free operations over the first nine months of the year. In the third quarter, the company-wide TRIF was down 40% from the same period the previous year.

·In September, Cenovus received recognition for its continued strong performance in the area of corporate responsibility. The company was included in the DJSI World Index for the fourth consecutive year and in the DJSI North America Index for the sixth year in a row. Cenovus is the only North American oil and gas producer to make the World Index this year.

·Cenovus shares the public’s concerns about climate change and is investing in technology to reduce CO2 emissions from its operations as well as looking for solutions to help eliminate emissions from the end use of oil. The company is proud to be a member of COSIA, which is sponsoring the recently announced NRG COSIA Carbon XPRIZE. The competition challenges innovators from around the world to find ways to turn waste CO2 emissions from fossil fuels into usable products.

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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 October 28, 2015, should be read in conjunction with our September 30, 2015 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2014 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2014 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of October 28, 2015, unless otherwise indicated. This MD&A provides an update to our annual MD&A and contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information. Cenovus Management prepared the MD&A. The interim MD&As are approved by the Audit Committee of the Cenovus Board of Directors (the “Board”) and the annual MD&A is reviewed by the Audit Committee and recommended for its approval by the Board. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A.

Basis of Presentation

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

Non-GAAP Measures

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

OVERVIEW OF CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. On September 30, 2015, we had a market capitalization of approximately $17 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 nine months ended September 30, 2015 was approximately 209,000 barrels per day and our average natural gas production was 447 MMcf per day. Our refineries processed an average of 424,000 gross barrels per day of crude oil feedstock into an average of 448,000 gross barrels per day of refined products.

The low commodity price environment continued to significantly impact the oil and gas industry in the third quarter. After experiencing a modest improvement in average crude oil benchmark prices in the second quarter of 2015, average prices fell between 19 percent and 28 percent. Average crude oil prices were also 51 percent to 57 percent lower than in the third quarter of 2014. The significant decline and volatility in commodity prices has caused widespread reductions in capital spending programs and extensive efforts to reduce costs across the industry. We continue to focus on preserving our financial resilience, exercising capital discipline and achieving sustainable cost reductions as we anticipate crude oil prices will remain low for a prolonged period of time.

Our Strategy

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

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

·Our producing asset mix, including:

·Oil sands for growth;

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

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

·Our marketing, products and transportation activities, including:

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

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

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

We have adopted a more moderate and staged approach to future oil sands expansions. We will consider expanding existing projects and developing emerging projects only when we believe we will maximize cost savings and capital efficiencies.

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Oil Development

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

We anticipate increasing our annual net crude oil production, including our conventional crude oil operations, by fully developing our producing projects and those that currently have regulatory approval.

Execution Excellence

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

Financial Strength

We anticipate our total annual capital investment for 2015 to be between $1.8 billion and $1.9 billion. This is a significant reduction from 2014 levels in response to the continued low commodity price environment. We expect proceeds from our common share issuance in March 2015, the sale of our royalty interest and mineral fee title lands business in July 2015 and internally generated cash flow to fund our capital investment in 2015 and into the next years of our business plan. We remain well positioned to manage through these volatile times. To continue to help ensure our financial flexibility, we plan to prudently use our balance sheet capacity, manage our asset portfolio and consider other corporate and financial opportunities that may be available to us.

Dividend

In the third quarter of 2015, we paid a dividend of $0.16 per share, a decrease of 40 percent from our first and second quarter dividends of $0.2662 per share. The declaration of dividends is at the sole discretion of our Board and is considered each quarter.

In the first quarter of 2015, we initiated a temporary three percent discount under our dividend reinvestment plan (“DRIP”) for shareholders who reinvested their dividends in common shares. While the DRIP continues to be in place, the discount has been discontinued as of July 2015.

Innovation and the Environment

Technology development, research activities and understanding our impact on the environment play increasingly larger roles in all aspects of our business. We continue to seek out new technologies and are actively developing our own technologies with the goal 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 footprint. The Cenovus culture fosters the pursuit of new ideas and new approaches. We have a track record of developing innovative solutions that unlock challenging crude oil resources, building on our history of excellent project execution. Environmental considerations are embedded into our business approach with the objective of reducing our environmental impact.

Our Operations

Oil Sands

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

	Nine Months Ended September 30, 2015
	Ownership Interest (percent)	Net Production Volumes (bbls/d)	Gross Production Volumes (bbls/d)
Existing Projects
Foster Creek	50	65,906	131,812
Christina Lake	50	74,720	149,440
Narrows Lake	50	—	—
Emerging Projects
Telephone Lake	100	—	—
Grand Rapids	100	—	—

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated U.S. public company. Foster Creek and Christina Lake are producing and Narrows Lake is in the initial stages of development. These projects are located in the Athabasca region of northeastern Alberta. Two of our

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100 percent-owned emerging projects are Telephone Lake and Grand Rapids, located within the Borealis and Greater Pelican Lake regions, respectively.

	Nine Months Ended September 30, 2015
($ millions)	Crude Oil		Natural Gas
Operating Cash Flow	853		7
Capital Investment	945		1
Operating Cash Flow Net of Related Capital Investment	(92	)	6

Conventional

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

	Nine Months Ended September 30, 2015
($ millions)	Crude Oil (1)	Natural Gas
Operating Cash Flow	549	231
Capital Investment	148	9
Operating Cash Flow Net of Related Capital Investment	401	222

(1)Includes NGLs.

We have established crude oil and natural gas producing assets, including a carbon dioxide (“CO2”) enhanced oil recovery project in Weyburn, Saskatchewan, as well as heavy oil assets at Pelican Lake and developing tight oil assets, located 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.

	Nine Months Ended September 30, 2015
	Ownership Interest (percent)	Gross Nameplate Capacity (Mbbls/d)
Wood River	50	314
Borger	50	146

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

	Nine Months Ended
	September 30,
($ millions)	2015
Operating Cash Flow	424
Capital Investment	159
Operating Cash Flow Net of Related Capital Investment	265

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QUARTERLY OPERATING AND FINANCIAL HIGHLIGHTS

Challenges from the sustained low commodity price environment continued to significantly impact our industry in the third quarter of 2015. Average crude oil benchmark prices declined between 19 percent and 28 percent from the second quarter. Commodity prices are expected to stay low for the remainder of 2015 and throughout 2016. The forward price of Western Canadian Select (“WCS”) for the fourth quarter as at September 30, 2015 is expected to average approximately US$32 per barrel. Maintaining financial resilience, capital spending discipline and conserving cash are extremely important in this low commodity price environment.

Cenovus remains well positioned to manage through these volatile times. We are focused on preserving our financial flexibility, exercising capital discipline and achieving sustainable cost reductions. In the third quarter, we:

·Completed the sale of our royalty interest and mineral fee title lands business, which included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. We received cash proceeds of approximately $3.3 billion. A royalty on Cenovus’s working interest production on these fee lands and a Gross Overriding Royalty (“GORR”) on production from our Pelican Lake and Weyburn assets were also included in the sale;

·Closed the purchase of a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of transportation options;

·Reduced our total crude oil operating costs by $53 million or $3.21 per barrel, compared with 2014;

·Continued to reduce our discretionary spending;

·Additional workforce reductions were identified in the third quarter and implemented in early October, resulting in a 24 percent reduction of our workforce in 2015; and

·Reduced our third quarter dividend to $0.16 per share in response to the low commodity price environment.

Operational Results

Our upstream assets continued to perform well in the third quarter. Total crude oil production averaged 210,422 barrels per day in the quarter.

Crude oil production from our Oil Sands segment averaged 146,743 barrels per day in the third quarter, an increase of 17 percent from the third quarter of 2014.

Production from Foster Creek averaged 71,414 barrels per day in the third quarter, an increase of 26 percent compared with 2014 due to the ramp-up of phase F, strong initial production after operations were temporarily shut down in the second quarter due to a nearby forest fire, and production from additional wells.

Average production at Christina Lake rose to 75,329 barrels per day, a 10 percent increase from the third quarter of 2014. The increase was due to production from additional wells, including wells using our Wedge WellTM technology and improved performance of our facilities.

Our Conventional crude oil production averaged 63,679 barrels per day, a 14 percent decrease compared with 2014. An increase in production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the sale of our royalty interest and mineral fee title lands business, and the divestiture of a non-core asset in 2014. Third party royalty interest volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.

Crude oil processed and refined product output decreased slightly from 2014 due to unplanned outages and planned turnaround activities. We processed an average of 394,000 gross barrels per day (2014 — 407,000 gross barrels per day) of crude oil, of which 186,000 gross barrels per day (2014 — 201,000 gross barrels per day) was heavy crude oil. We produced 414,000 gross barrels per day of refined products, a three percent decrease from 2014.

We commenced operations of our crude-by-rail facility at Bruderheim, Alberta, and 12 unit trains, including five unit trains for third parties, were loaded in the first month of operations.

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Financial Results

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

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

Crude oil benchmark prices declined from the second quarter of 2015 and were significantly lower than in the third quarter of 2014. Low commodity prices continue to significantly impact our financial results.

Financial highlights for the third quarter of 2015 compared with 2014 include:

Operating Cash Flow

Operating Cash Flow decreased 48 percent to $599 million. Upstream Operating Cash Flow of $570 million (2014 — $1,086 million) declined primarily due to the low commodity price environment. The sale of our royalty interest and mineral fee title lands business reduced third quarter Operating Cash Flow by approximately $23 million.

The decreases in upstream Operating Cash Flow were partially offset by:

·Realized risk management gains of $206 million compared with losses of $4 million in 2014;

·Lower royalties due to a decline in crude oil sales prices, partially offset by additional royalties resulting from the sale of our royalty interest and mineral fee title lands business; and

·A reduction in crude oil operating expenses of $3.21 per barrel to $11.39 per barrel, primarily related to lower fuel costs due to a decrease in natural gas prices, lower repairs and maintenance costs, and a decline in workforce costs.

Operating Cash Flow from our Refining and Marketing segment declined $39 million or 57 percent. The decrease resulted from higher heavy crude oil feedstock costs relative to the West Texas Intermediate (“WTI”) benchmark price, higher operating costs and lower refined product output, partially offset by improved margins on the sale of secondary products such as coke and asphalt, an increase in average market crack spreads and weakening of the Canadian dollar relative to the U.S. dollar.

Cash Flow

Cash Flow decreased 55 percent to $444 million primarily due to the decline in Operating Cash Flow discussed above.

Operating Earnings (Loss)

Operating Earnings decreased $400 million to a loss of $28 million primarily due to lower Cash Flow, as discussed above, partially offset by a recovery of deferred income tax compared with an expense in 2014.

Net Earnings

Net Earnings was $1,801 million compared with $354 million in 2014. Net Earnings increased due to an after-tax gain of approximately $1.9 billion from the divestiture of our royalty interest and mineral fee title lands business, partially offset by lower Operating Earnings discussed above, an increase in non-operating unrealized foreign exchange losses, and lower unrealized risk management gains compared with 2014.

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Capital Investment

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

Capital investment in the quarter was $400 million, a decrease of 47 percent. We continued to focus on sustaining existing oil sands production, and completing the Foster Creek phase G expansion and Christina Lake phase F expansion.

OPERATING RESULTS

Crude Oil Production Volumes

	Three Months Ended September 30,				Nine Months Ended September 30,
(barrels per day)	2015	Percent Change		2014	2015	Percent Change		2014
Oil Sands
Foster Creek	71,414	26	%	56,631	65,906	18	%	56,070
Christina Lake	75,329	10	%	68,458	74,720	11	%	67,400
	146,743	17	%	125,089	140,626	14	%	123,470
Conventional
Heavy Oil	33,997	(13	)%	39,096	35,739	(11	)%	40,060
Light and Medium Oil	28,491	(15	)%	33,548	31,787	(8	)%	34,488
NGLs (1)	1,191	(12	)%	1,356	1,286	7	%	1,200
	63,679	(14	)%	74,000	68,812	(9	)%	75,748
Total Crude Oil Production	210,422	6	%	199,089	209,438	5	%	199,218

(1)NGLs include condensate volumes.

Foster Creek production increased in the three and nine months ended September 30, 2015, primarily due to the ramp-up of phase F, strong initial production after operations were temporarily shut down in the second quarter due to a nearby forest fire, and production from additional wells. The ramp-up of phase F, our eleventh oil sands phase, is expected to take approximately eighteen months from start-up, which occurred in the third quarter of 2014. On a year-to-date basis, production increases were partially offset when production at Foster Creek was shut down for 11 full days as a safety precaution due to a nearby forest fire. The forest fire decreased production by approximately 3,500 barrels per day on a year-to-date basis.

Production from Christina Lake increased in the third quarter and on a year-to-date basis due to production from additional wells, including wells using our Wedge WellTM technology, and improved performance of our facilities.

Our Conventional crude oil production in the three and nine months ended September 30, 2015 decreased from 2014. An increase in production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest

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and mineral fee title lands business. Production from these divested assets was 1,251 barrels per day in the third quarter (2014 — 6,947 barrels per day) and 3,417 barrels per day on a year-to-date basis (2014 — 7,293 barrels per day).

Natural Gas Production Volumes

	Three Months Ended September 30,		Nine Months Ended September 30,
(MMcf per day)	2015	2014	2015	2014
Conventional	411	466	427	469
Oil Sands	19	23	20	22
	430	489	447	491

In the three and nine months ended September 30, 2015, our natural gas production declined 12 percent and nine percent, respectively. Production decreased primarily due to expected natural declines and from the sale of our royalty interest and mineral fee title lands business, which produced 6 MMcf per day and 13 MMcf per day in the three and nine months ended September 30, 2015, respectively (2014 — 20 MMcf per day and 20 MMcf per day).

Operating Netbacks

	Three Months Ended September 30,					Nine Months Ended September 30,
	Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)		Crude Oil (1) ($/bbl)			Natural Gas ($/Mcf)
	2015	2014		2015	2014	2015	2014		2015	2014
Price (2)	34.03	76.57		3.00	4.22	37.90	77.04		2.96	4.52
Royalties	1.60	6.52		0.11	0.08	1.85	6.56		0.06	0.08
Transportation and Blending (2)	5.61	3.08		0.10	0.11	5.39	2.96		0.11	0.11
Operating Expenses	11.39	14.60		1.16	1.24	12.23	16.41		1.19	1.24
Production and Mineral Taxes	0.23	0.54		0.01	0.05	0.25	0.52		0.01	0.06
Netback Excluding Realized Risk Management	15.20	51.83		1.62	2.74	18.18	50.59		1.59	3.03
Realized Risk Management Gain (Loss)	10.07	(0.45	)	0.37	0.11	6.25	(1.78	)	0.35	0.03
Netback Including Realized Risk Management	25.27	51.38		1.99	2.85	24.43	48.81		1.94	3.06

(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 $19.18 per barrel for the third quarter (2014 — $28.48 per barrel) and in the nine months ended September 30, 2015 was $21.32 per barrel (2014 — $31.92 per barrel).

Our average crude oil netback in the three and nine months ended September 30, 2015, excluding realized risk management gains and losses, decreased $36.63 per barrel and $32.41 per barrel, respectively, compared with 2014. The declines primarily resulted from lower sales prices, consistent with the decline in benchmark prices, partially offset by weakening of the Canadian dollar relative to the U.S. dollar, a decline in royalties and lower operating costs. The weakening of the Canadian dollar, on a year-to-date basis, compared with 2014 had a positive impact on our crude oil price of approximately $4.98 per barrel. Royalties declined due to lower crude oil sales prices.

In 2015, our average natural gas netback, excluding realized risk management gains and losses, decreased primarily due to lower sales prices consistent with the decline in the AECO benchmark price.

Refining (1)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015	Percent Change		2014	2015	Percent Change		2014
Crude Oil Runs (Mbbls/d)	394	(3	)%	407	424	—		424
Heavy Crude Oil	186	(7	)%	201	202	(1	)%	205
Refined Product (Mbbls/d)	414	(3	)%	429	448	—		446
Crude Utilization (percent)	86	(2	)%	88	92	—		92

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

In the third quarter, unplanned process unit outages at our Borger refinery for most of July and the start of a planned turnaround at Wood River reduced crude oil runs and refined product output. The Wood River turnaround is expected to be completed in October. In the third quarter of 2014, we had an unplanned coker outage at Borger that lasted approximately two weeks and a planned turnaround at Wood River.

On a year-to-date basis, crude oil runs and refined product output remained consistent. The unplanned outages at Borger and planned turnarounds at both of our refineries in 2015 had a similar impact on crude oil runs and refined product output as the outage and turnarounds in 2014.

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

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

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

Selected Benchmark Prices and Exchange Rates (1)

	Nine Months Ended September 30,
	2015		Percent Change		2014		Q3 2015		Q2 2015		Q3 2014
Crude Oil Prices (US$/bbl)
Brent
Average	56.61		(47	)%	107.02		51.17		63.50		103.39
End of Period	48.37		(49	)%	94.67		48.37		63.59		94.67
WTI
Average	51.00		(49	)%	99.61		46.43		57.94		97.17
End of Period	45.09		(51	)%	91.16		45.09		59.47		91.16
Average Differential Brent-WTI	5.61		(24	)%	7.41		4.74		5.56		6.22
WCS (2)
Average	37.80		(52	)%	78.49		33.16		46.35		76.99
End of Period	31.62		(58	)%	75.84		31.62		48.14		75.84
Average Differential WTI-WCS	13.20		(38	)%	21.12		13.27		11.59		20.18
Condensate (C5 @ Edmonton)
Average	49.25		(51	)%	100.41		44.21		57.94		93.45
Average Differential WTI-Condensate (Premium)/Discount	1.75		(319	)%	(0.80	)	2.22		—		3.72
Average Differential WCS-Condensate (Premium)/Discount	(11.45	)	(48	)%	(21.92	)	(11.05	)	(11.59	)	(16.46	)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)	71.82		(38	)%	116.11		73.05		79.96		113.30
Chicago Ultra-low Sulphur Diesel (“ULSD”)	71.09		(42	)%	122.91		67.02		75.92		118.56
Refining Margin: Average 3-2-1 Crack Spreads (US$/bbl)
Chicago	20.66		11	%	18.61		24.67		20.77		17.57
Group 3	19.61		14	%	17.27		22.03		19.34		16.65
Average Natural Gas Prices
AECO (C$/Mcf)	2.81		(38	)%	4.55		2.80		2.67		4.22
NYMEX (US$/Mcf)	2.80		(39	)%	4.56		2.77		2.64		4.06
Basis Differential NYMEX-AECO (US$/Mcf)	0.56		44	%	0.39		0.61		0.50		0.16
Foreign Exchange Rates (US$ per C$1)
Average	0.794		(13	)%	0.914		0.764		0.813		0.918

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

(2)The average Canadian dollar WCS benchmark price for the third quarter was $43.40 per barrel (2014 — $83.87 per barrel) and for the nine months ended September 30, 2015 was $47.61 per barrel (2014 — $85.88 per barrel).

Crude Oil Benchmarks

Crude oil benchmark prices in the third quarter declined from the second quarter and were significantly lower than in 2014. The average Brent, WTI and WCS benchmark prices continued to be impacted by a global imbalance of supply and demand which began in the last half of 2014. This global imbalance was created by weak global demand and strong growth in North American crude oil supply which was further amplified by the sustained decision of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain its level of crude oil output and discontinue its role as the swing supplier of crude oil. Despite significantly lower crude oil prices in 2015, the global imbalance has only slightly improved. After a slight increase in crude oil prices in the second quarter of 2015, economic uncertainty in China and strong production from Saudi Arabia and Iraq have caused prices to fall.

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland refined product prices. In the three and nine months ended September 30, 2015, the average price of Brent crude oil decreased compared with 2014. The decline was due to the global supply and demand imbalance discussed above.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. The average Brent-WTI differential narrowed in the third quarter and on a year-to-date basis compared with 2014. WTI

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benchmark prices strengthened relative to Brent as a result of declining U.S. supply, high global crude oil inventory levels and continued strong demand in the U.S., leaving transportation costs as the primary driver of the Brent-WTI differential.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential narrowed by US$6.91 per barrel in the third quarter of 2015 and by US$7.92 per barrel on a year-to-date basis compared with 2014. The narrower differential resulted primarily from increased demand for WCS due to new pipeline infrastructure to the U.S. Gulf Coast, growing rail capacity and the slow return of heavy crude oil supply forced offline due to forest fires in northeastern Alberta during the second quarter of 2015. Late in the third quarter, Canadian crude oil supply was close to levels experienced prior to the fires, causing the WTI-WCS differential to widen compared with the second quarter.

Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our blending ratios range from approximately 10 percent to 33 percent. The WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand, Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the value attributed to transporting the condensate to Edmonton.

In the third quarter of 2015, the average WTI-Condensate differential decreased by US$1.50 per barrel compared with 2014. On a year-to-date basis, the differential changed by US$2.55 per barrel, with condensate being sold at a discount to WTI in 2015 as compared with being sold at a premium in 2014. This change was primarily due to new diluent pipeline infrastructure into Alberta and condensate supply growth.

The average WCS-Condensate differential narrowed by US$5.41 per barrel in the third quarter and US$10.47 per barrel on a year-to-date basis compared with 2014 due to condensate supply growth as well as improved diluent transportation infrastructure for condensate imports into Alberta and heavy oil exports to market.

Refining Benchmarks

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

Average inland refined product prices decreased in the third quarter and on a year-to-date basis from 2014 due to weaker global crude oil pricing.

Average Chicago 3-2-1 crack spreads increased in the third quarter compared with 2014 as a major unplanned refinery outage in August 2015 caused product inventory drawdowns during the driving season. On a year-to-date basis, Chicago 3-2-1 crack spreads were higher driven by stronger product demand. Average Group 3 crack spreads increased in the third quarter and on a year-to-date basis as the unplanned refinery outage, as discussed above, slightly improved refined product pricing.

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

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Natural Gas Benchmarks

Average natural gas prices decreased in the third quarter of 2015 and on a year-to-date basis primarily due to an increase in supply from the U.S. and Canada.

Foreign Exchange Benchmarks

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

In the third quarter and on a year-to-date basis compared with 2014, the Canadian dollar weakened relative to the U.S. dollar by $0.15 and $0.12, respectively, due to Canadian political and economic uncertainty, strengthening of the U.S. economy and lower commodity prices. The weakening of the Canadian dollar for the nine months ended September 30, 2015 compared with 2014, had a positive impact of approximately $1,329 million on our revenues and also resulted in an increase of $852 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.

FINANCIAL RESULTS

Selected Consolidated Financial Results

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

($ millions, except per share	Nine Months Ended September 30,		2015					2014					2013
amounts)	2015	2014	Q3		Q2	Q1		Q4		Q3	Q2	Q1	Q4		Q3
Revenues	10,140	15,404	3,273		3,726	3,141		4,238		4,970	5,422	5,012	4,747		5,075
Operating Cash Flow (1)	2,076	3,619	599		928	549		539		1,154	1,296	1,169	976		1,153
Cash Flow (1)	1,416	3,078	444		477	495		401		985	1,189	904	835		932
Per Share — Diluted	1.74	4.06	0.53		0.58	0.64		0.53		1.30	1.57	1.19	1.10		1.23
Operating Earnings (Loss) (1)	35	1,223	(28	)	151	(88	)	(590	)	372	473	378	212		313
Per Share — Diluted	0.04	1.61	(0.03	)	0.18	(0.11	)	(0.78	)	0.49	0.62	0.50	0.28		0.41
Net Earnings (Loss)	1,259	1,216	1,801		126	(668	)	(472	)	354	615	247	(58	)	370
Per Share — Basic	1.55	1.61	2.16		0.15	(0.86	)	(0.62	)	0.47	0.81	0.33	(0.08	)	0.49
Per Share — Diluted	1.55	1.60	2.16		0.15	(0.86	)	(0.62	)	0.47	0.81	0.33	(0.08	)	0.49
Capital Investment (2)	1,286	2,265	400		357	529		786		750	686	829	898		743
Dividends
Cash Dividends	396	604	133		125	138		201		201	201	202	183		182
In Shares from Treasury	182	—	—		98	84		—		—	—	—	—		—
Per Share	0.6924	0.7986	0.16		0.2662	0.2662		0.2662		0.2662	0.2662	0.2662	0.242		0.242

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

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

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Revenues

In the third quarter, revenues decreased $1,697 million compared with 2014. On a year-to-date basis, revenues decreased $5,264 million compared with 2014.

($ millions)	Three Months Ended		Nine Months Ended
Revenues for the Periods Ended September 30, 2014	4,970		15,404
Increase (Decrease) due to:
Oil Sands	(532	)	(1,438	)
Conventional	(374	)	(1,112	)
Refining and Marketing	(902	)	(3,110	)
Corporate and Eliminations	111		396
Revenues for the Periods Ended September 30, 2015	3,273		10,140

Upstream revenues declined in the third quarter and on a year-to-date basis by 45 percent and 41 percent, respectively. Revenues decreased due to lower crude oil blend and natural gas sales prices, partially offset by higher crude oil sales volumes, weakening of the Canadian dollar relative to the U.S. dollar and lower royalties. The sale of our royalty interest and mineral fee title lands business also reduced revenues.

Revenues from our Refining and Marketing segment in the three and nine months ended September 30, 2015 decreased 29 percent and 31 percent, respectively. Refining revenues declined due to the decrease in refined product pricing, consistent with lower Chicago RUL and Chicago ULSD benchmark prices, partially offset by the weakening of the Canadian dollar relative to the U.S. dollar. Refining revenues in the third quarter were also impacted by lower refined product output compared with 2014. Revenues from third-party crude oil and natural gas sales undertaken by the marketing group in the three and nine months ended September 30, 2015 decreased 40 percent and 37 percent from 2014, primarily due to a decline in sales prices, partially offset by an increase in purchased crude oil volumes.

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

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

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

	Three Months Ended September 30,			Nine Months Ended September 30,
($ millions)	2015		2014	2015		2014
Revenues	3,359		5,167	10,400		16,060
(Add) Deduct:
Purchased Product	2,012		2,918	5,826		8,836
Transportation and Blending	483		592	1,509		1,900
Operating Expenses	480		491	1,390		1,584
Production and Mineral Taxes	5		12	16		36
Realized (Gain) Loss on Risk Management Activities	(220	)	—	(417	)	85
Operating Cash Flow	599		1,154	2,076		3,619

Three Months Ended September 30, 2015 Compared With September 30, 2014

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Operating Cash Flow declined 48 percent in the third quarter compared with 2014 primarily due to:

·A 56 percent decrease in our average crude oil sales price and a 29 percent decrease in our average natural gas sales price, consistent with lower associated benchmark prices;

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

·A 12 percent decline in our natural gas sales volumes.

These declines to Operating Cash Flow were partially offset by:

·Realized risk management gains of $206 million, excluding Refining and Marketing, compared with losses of $4 million in 2014;

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

·A reduction of $3.21 per barrel in crude oil operating expenses primarily related to lower fuel costs due to a decrease in natural gas prices, lower repairs and maintenance costs, and a decline in workforce costs; and

·A four percent increase in our crude oil sales volumes.

Nine Months Ended September 30, 2015 Compared With September 30, 2014

Operating Cash Flow declined 43 percent for the nine months ended September 30, 2015 primarily due to:

·A 51 percent decrease in our average crude oil sales price and a 35 percent decrease in our average natural gas sales price, consistent with lower associated benchmark prices;

·Lower Operating Cash Flow from Refining and Marketing as a result of higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher operating costs, partially offset by improved margins on the sale of secondary products and weakening of the Canadian dollar relative to the U.S. dollar; and

·A nine percent decline in our natural gas sales volumes.

These declines to Operating Cash Flow were partially offset by:

·Realized risk management gains of $390 million, excluding Refining and Marketing, compared with losses of $94 million in 2014;

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

·A decrease of $4.18 per barrel in crude oil operating expenses primarily due to a decline in workover activities, a reduction in fuel costs due to lower natural gas prices, and lower repairs and maintenance costs; and

·A five percent increase in our crude oil sales volumes.

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

Cash Flow

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

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Cash From Operating Activities	542		1,092		1,152		2,658
(Add) Deduct:
Net Change in Other Assets and Liabilities	(13	)	(28	)	(81	)	(97	)
Net Change in Non-Cash Working Capital	111		135		(183	)	(323	)
Cash Flow	444		985		1,416		3,078

In the three and nine months ended September 30, 2015, Cash Flow decreased $541 million and $1,662 million, respectively, due to lower Operating Cash Flow, as discussed above, and higher current income tax. On a year-to-date basis, current income tax rose due to the acceleration in timing of income tax payable in response to the Alberta corporate tax rate increase.

Operating Earnings (Loss)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Earnings, Before Income Tax	2,020		533		1,419		1,715
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)	(127	)	(165	)	169		(180	)
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)	437		253		852		272
(Gain) Loss on Divestiture of Assets	(2,379	)	(137	)	(2,395	)	(157	)
Operating Earnings (Loss), Before Income Tax	(49	)	484		45		1,650
Income Tax Expense (Recovery)	(21	)	112		10		427
Operating Earnings (Loss)	(28	)	372		35		1,223

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

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

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Operating Earnings decreased $400 million in the third quarter of 2015, primarily due to lower Cash Flow, as discussed above, partially offset by a recovery of deferred income tax compared with an expense in 2014.

On a year-to-date basis, Operating Earnings decreased $1,188 million, primarily due to:

·A decrease in Cash Flow, as discussed above;

·Unrealized foreign exchange losses of $26 million related to operating items, as compared with gains of $51 million in 2014; and

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

These decreases were partially offset by a recovery of deferred income tax compared with an expense in 2014, and a recovery of employee long-term incentive costs compared with an expense in 2014.

Net Earnings

($ millions)	Three Months Ended		Nine Months Ended
Net Earnings for the Periods Ended September 30, 2014	354		1,216
Increase (Decrease) due to:
Operating Cash Flow (1)	(555	)	(1,543	)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)	(38	)	(349	)
Unrealized Foreign Exchange Gain (Loss)	(198	)	(657	)
Gain (Loss) on Divestiture of Assets	2,242		2,238
Expenses (2)	34		75
Depreciation, Depletion and Amortization	2		(40	)
Exploration Expense	—		(20	)
Income Tax Expense	(40	)	339
Net Earnings for the Periods Ended September 30, 2015	1,801		1,259

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

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

Net Earnings in the third quarter of 2015 increased $1,447 million and $43 million on a year-to-date basis primarily due to an after-tax gain of approximately $1.9 billion from the divestiture of our royalty interest and mineral fee title lands business, and a deferred tax recovery related to non-operating items compared with an expense in 2014.

This increase was partially offset by:

·A decline in Operating Earnings, as discussed above;

·Non-operating unrealized foreign exchange losses of $437 million in the quarter and $852 million on a year-to-date basis (2014 — unrealized losses of $253 million and $272 million, respectively); and

·Unrealized risk management gains of $127 million in the quarter and unrealized risk management losses of $169 million on a year-to-date basis (2014 — unrealized gains of $165 million and $180 million, respectively).

Net Capital Investment

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Oil Sands	272		494		946		1,492
Conventional	55		198		157		621
Refining and Marketing	67		42		159		111
Corporate and Eliminations	6		16		24		41
Capital Investment	400		750		1,286		2,265
Acquisitions	84		—		84		17
Divestitures	(3,329	)	(235	)	(3,345	)	(276	)
Net Capital Investment (1)	(2,845	)	515		(1,975	)	2,006

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

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

Capital investment in the three and nine months ended September 30, 2015 declined 47 percent and 43 percent, respectively. In January, we reduced our planned capital investment with the intent of conserving cash and maintaining the strength of our balance sheet in light of the low commodity price environment. We plan to focus 2015 capital investment on ensuring our assets are appropriately maintained, meet safety, regulatory and contractual obligations, and on our Christina Lake phase F and Foster Creek phase G expansions.

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In 2015, Oil Sands capital investment focused primarily on sustaining capital related to existing production, the phase G expansion at Foster Creek, Christina Lake’s phase F expansion and the optimization project, and the drilling of 158 gross stratigraphic test wells in the nine months ended September 30, 2015, which were primarily related to near-term phase expansions to determine pad placement.

Conventional capital investment focused primarily on maintenance capital and spending for our CO2 enhanced oil recovery project at Weyburn and drilling activity at our tight oil projects in southeast Alberta.

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

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

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

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

Capital Investment Decisions

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

·First, to capital for our existing business operations;

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

·Third, for growth or discretionary capital.

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

We expect our total annual capital investment for 2015 to be between $1.8 billion and $1.9 billion, significantly below prior years in light of the commodity price environment. Our capital budget has a degree of flexibility and, as such, we will continue to assess spending plans on a regular basis and make adjustments, if required. Refer to the Reportable Segments section of this MD&A for more details.

	Three Months Ended September 30,			Nine Months Ended September 30,
($ millions)	2015		2014	2015		2014
Cash Flow (1)	444		985	1,416		3,078
Capital Investment (Committed and Growth)	400		750	1,286		2,265
Free Cash Flow (2)	44		235	130		813
Cash Dividends	133		201	396		604
	(89	)	34	(266	)	209

(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.

We expect our capital investment for the remainder of 2015 and the next years of our business plan to be funded from internally generated cash flow, proceeds from our common share issuance in March 2015 and the sale of our royalty interest and mineral fee title lands business in July 2015. These transactions strengthen our balance sheet and provide us with greater resiliency to consider investing in opportunities that we believe have strong future returns. Refer to the Liquidity and Capital Resources section of this MD&A for further information.

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REPORTABLE SEGMENTS

Our reportable segments are as follows:

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

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

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

Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory.

Revenues by Reportable Segment

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Oil Sands	749		1,281		2,353		3,791
Conventional	368		742		1,272		2,384
Refining and Marketing	2,242		3,144		6,775		9,885
Corporate and Eliminations	(86	)	(197	)	(260	)	(656	)
	3,273		4,970		10,140		15,404

OIL SANDS

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

Significant developments in our Oil Sands segment in the third quarter of 2015 compared with 2014 include:

·Production at Foster Creek increasing 26 percent, to an average of 71,414 barrels per day primarily as a result of phase F coming on stream, strong initial production after operations were temporarily shut down in the second quarter due to a nearby forest fire, and production from additional wells; and

·Christina Lake production increasing 10 percent, to an average of 75,329 barrels per day primarily due to production from additional wells, including wells using our Wedge WellTM technology, and improved performance of our facilities; and

·Reduced our crude oil operating costs by $19 million or $2.86 per barrel, compared with 2014.

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Oil Sands — Crude Oil

Three Months Ended September 30, 2015 Compared With September 30, 2014

Financial and Per-unit Results

	Three Months Ended September 30, 2015				Three Months Ended September 30, 2014
($ millions, unless otherwise noted)			$ per-unit (1)			$ per-unit (1)
Gross Sales	749		56		1,334	112
Less: Royalties	7		1		62	5
Revenues	742		55		1,272	107
Expenses
Transportation and Blending	431		32		518	44
Operating	128		10		147	12
(Gain) Loss on Risk Management	(143	)	(11	)	2	—
Operating Cash Flow	326		24		605	51
Capital Investment	272				493
Operating Cash Flow Net of Related Capital Investment	54				112

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

(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 third quarter, our average crude oil sales price was $30.35 per barrel, a 33 percent decline from the second quarter and 58 percent lower than the third quarter of 2014. The prices we receive continue to be adversely impacted by the worldwide commodity price environment. The decline in our crude oil price was consistent with the decrease in the WCS and Christina Dilbit Blend (“CDB”) benchmark prices, partially offset by weakening of the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market that secure a higher sales price. The WCS-CDB differential narrowed to a discount of US$3.00 per barrel (2014 — a discount of US$3.91 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process a wider variety of heavier crude oils. In the third quarter, 84 percent of our Christina Lake production was sold as CDB (2014 — 90 percent), with the remainder sold into the WCS stream.

Production Volumes

	Three Months Ended September 30,
(barrels per day)	2015	Percent Change		2014
Foster Creek	71,414	26	%	56,631
Christina Lake	75,329	10	%	68,458
	146,743	17	%	125,089

Foster Creek production increased primarily due to the ramp-up of phase F, strong initial production after operations were temporarily shut down in the second quarter due to a nearby forest fire, and production from additional wells. The ramp-up of phase F, our eleventh oil sands phase, is expected to take approximately eighteen months from start-up, which occurred in the third quarter of 2014. Strong initial production following the forest fire has subsided and production rates have returned to levels prior to the forest fire.

Production from Christina Lake increased in the third quarter due to production from additional wells, including wells using our Wedge WellTM technology, and improved performance of our facilities.

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Condensate

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

Royalties

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

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

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

Effective Royalty Rates

	Three Months Ended September 30,
(percent)	2015	2014
Foster Creek	0.8	7.2
Christina Lake	3.7	7.9

Royalties decreased $55 million in the third quarter compared with 2014, primarily due to the decline in crude oil sales prices, partially offset by an increase in sales volumes. Foster Creek royalties were based on gross revenues in 2015 as compared with a calculation based on net profits in 2014. The further decline in WTI in the third quarter caused the annual calculation to change from a net profits basis to a gross revenues basis, resulting in a significant decrease in the royalty rate at Foster Creek. The Christina Lake royalty rate decreased in 2015 as a result of lower realized sales prices.

Expenses

Transportation and Blending

Transportation and blending costs decreased $87 million or 17 percent. Blending costs declined primarily due to lower condensate prices, partially offset by an increase in condensate volumes consistent with the rise in production. Our condensate costs were higher than the average benchmark price in 2015 primarily due to the transportation cost associated with moving the condensate to our oil sands projects.

Transportation costs increased $54 million primarily due to higher pipeline tariffs and additional sales to the U.S. market which attract higher tariffs. To ensure adequate capacity for our expected future production growth, we hold long-term transportation agreements on the Cold Lake pipeline expansion. Deliveries commenced in the first quarter of 2015. We also have added capacity on the Flanagan South system which increases our sales opportunities into the U.S. market with the expectation of achieving higher sales prices. Deliveries on the Flanagan South system began in the fourth quarter of 2014. Future production growth is expected to reduce our per-barrel transportation costs.

Transportation costs also increased as lower volumes transported by rail were more than offset by new lease costs for rail cars, and higher loading fees and storage costs. Overall, in the third quarter of 2015, we moved an average of 6,642 gross barrels per day of crude oil by rail, consisting of 10 unit train shipments (2014 — 11,186 gross barrels per day, 18 unit train shipments). Rail transportation costs are generally higher than pipeline costs; however, rail provides flexibility in destinations, products transported and the duration of the cost commitment, which is typically shorter in term than pipeline commitments.

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Operating

Primary drivers of our operating expenses in the third quarter of 2015 were workforce, fuel, repairs and maintenance, chemical costs and workovers. Total operating expenses decreased $19 million or $2.86 per barrel, primarily as a result of higher production, lower natural gas prices reducing fuel costs, and a decline in workforce costs.

Per-unit Operating Expenses

	Three Months Ended September 30,
($/bbl)	2015	Percent Change		2014
Foster Creek
Fuel	2.65	(39	)%	4.31
Non-fuel	8.72	(17	)%	10.48
Total	11.37	(23	)%	14.79
Christina Lake
Fuel	2.30	(31	)%	3.32
Non-fuel	5.57	(21	)%	7.08
Total	7.87	(24	)%	10.40
Total	9.55	(23	)%	12.41

At Foster Creek, fuel costs decreased $1.66 per barrel primarily due to the decline in natural gas prices and a decrease in fuel consumption on a per-barrel basis.

Non-fuel operating expenses declined $1.76 per barrel primarily due to higher production volumes and lower electricity costs. Workover costs in the third quarter of 2015 included costs savings associated with well servicing and pump changes, but were higher than in 2014.  In the third quarter of 2014, after a review of our 2014 re-drilling programs at Foster Creek, certain costs that had previously been recognized as workover costs were capitalized in the third quarter as these activities were beyond normal maintenance and enhanced future production capacity. This reduced third quarter 2014 operating expenses by $1.60 per barrel.

At Christina Lake, fuel costs decreased by $1.02 per barrel primarily due to the decline in natural gas prices. Non-fuel operating expenses decreased $1.51 per barrel, primarily due to lower workover costs related to fewer pump changes, increased production and a decrease in electricity costs.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate in the third quarter was $24.20 per barrel (2014 — $38.50 per barrel) for Foster Creek, and $26.42 per barrel (2014 — $42.57 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.

Risk Management

Risk management activities in the third quarter resulted in realized gains of $143 million (2014 — realized losses of $2 million), consistent with our contract prices exceeding average benchmark prices.

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Nine Months Ended September 30, 2015 Compared With September 30, 2014

Financial and Per-unit Results

	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
($ millions, unless otherwise noted)			$ per-unit (1)			$ per-unit (1)
Gross Sales	2,356		63		3,909	117
Less: Royalties	26		1		180	5
Revenues	2,330		62		3,729	112
Expenses
Transportation and Blending	1,336		36		1,636	48
Operating	390		10		483	15
(Gain) Loss on Risk Management	(249	)	(7	)	59	2
Operating Cash Flow	853		23		1,551	47
Capital Investment	945				1,488
Operating Cash Flow Net of Related Capital Investment	(92	)			63

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

Capital investment in excess of Operating Cash Flow from Oil Sands was funded through Operating Cash Flow generated by our Conventional and Refining and Marketing segments, proceeds from our common share issuance in the first quarter of 2015, and the sale of our royalty interest and mineral fee title lands business in July 2015.

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

Revenues

Pricing

For the nine months ended September 30, 2015, our average crude oil sales price was $33.56 per barrel, a 53 percent decrease from 2014 as the prices we received continued to be adversely impacted by the worldwide commodity price environment. The decline in our crude oil price was consistent with the decrease in the WCS and CDB benchmark prices, partially offset by weakening of the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market which secure a higher sales price. The WCS-CDB differential narrowed by 43 percent to a discount of US$2.51 per barrel (2014 — a discount of US$4.38 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process a wider variety of heavier crude oils. In the nine months ended September 30, 2015, 86 percent of our Christina Lake production was sold as CDB (2014 — 86 percent), with the remainder sold into the WCS stream.

Production Volumes

	Nine Months Ended September 30,
(barrels per day)	2015	Percent Change		2014
Foster Creek	65,906	18	%	56,070
Christina Lake	74,720	11	%	67,400
	140,626	14	%	123,470

Foster Creek production increased due to production from phase F coming on stream in September 2014, and ramping up as expected, and production from additional wells, partially offset by the impact of the forest fire in the second quarter. The forest fire decreased production by approximately 3,500 barrels per day on a year-to-date basis. Strong initial production has subsided and production rates have returned to levels prior to the forest fire.

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Production from Christina Lake increased in the nine months ended September 30, 2015 due to production from additional wells, including wells using our Wedge WellTM technology, phase E reaching nameplate production capacity in the second quarter of 2014, and improved performance of our facilities.

Royalties

Effective Royalty Rates

	Nine Months Ended September 30,
(percent)	2015	2014
Foster Creek	2.1	8.2
Christina Lake	3.0	7.6

Royalties decreased $154 million, primarily related to the decline in crude oil sales prices, partially offset by an increase in sales volumes. At Foster Creek, the royalty calculation was based on gross revenues as compared with a calculation based on net profits for the nine months ended September 30, 2014. In the first quarter of 2015, we received regulatory approval to include certain capital costs incurred in previous years in our royalty calculation and recorded an associated credit, decreasing the overall royalty rate on a year-to-date basis. Excluding the credit, the effective royalty rate for Foster Creek would have been 3.6 percent for the nine months ended September 30, 2015. The Christina Lake royalty rate decreased in 2015 as a result of lower realized sales prices.

Expenses

Transportation and Blending

Transportation and blending costs decreased $300 million or 18 percent. Blending costs declined primarily due to lower condensate prices, partially offset by an increase in condensate volumes consistent with the rise in production. Our condensate costs were higher than the average benchmark price in 2015 primarily due to the utilization of higher-priced inventory and the transportation cost associated with moving the condensate to our oil sands projects.

Transportation costs increased $157 million primarily due to higher pipeline tariffs and additional sales to the U.S. market which attract higher tariffs. To help ensure adequate capacity for our expected future production growth, we have capacity commitments in excess of our current production. Future production growth is expected to reduce our per-barrel transportation costs.

In addition, transportation costs increased as a result of higher volumes moved by rail. In the nine months ended September 30, 2015, we transported an average of 7,889 gross barrels per day of crude oil by rail, consisting of 36 unit train shipments (2014 — 5,285 gross barrels per day, 25 unit train shipments).

Operating

Primary drivers of our operating expenses for the nine months ended September 30, 2015 were workforce, fuel, repairs and maintenance, chemical costs and workovers. Total operating expenses decreased $93 million or $4.12 per barrel, primarily as a result of lower natural gas prices that reduced fuel costs, higher production and a decline in workover activities.

Per-unit Operating Expenses

	Nine Months Ended September 30,
($/bbl)	2015	Percent Change		2014
Foster Creek
Fuel	2.78	(42	)%	4.77
Non-fuel	10.22	(21	)%	12.88
Total	13.00	(26	)%	17.65
Christina Lake
Fuel	2.22	(44	)%	3.98
Non-fuel	5.91	(25	)%	7.89
Total	8.13	(32	)%	11.87
Total	10.39	(28	)%	14.51

At Foster Creek, fuel costs decreased $1.99 per barrel due to the decline in natural gas prices and a decrease in fuel consumption on a per-barrel basis. Non-fuel operating expenses declined $2.66 per barrel, primarily due to:

·Higher production volumes;

·A reduction in workover expenses due to lower costs associated with well servicing and pump changes; and

·Lower electricity costs.

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Foster Creek non-fuel operating expenses included approximately $2.6 million or $0.15 per barrel of incremental costs associated with the shut-down due to the nearby forest fire that occurred in the second quarter of 2015.

At Christina Lake, fuel costs decreased by $1.76 per barrel due to the decline in natural gas prices and a decrease in fuel consumption on a per-barrel basis. Non-fuel operating expenses decreased $1.98 per barrel, primarily due to:

·Increased production;

·Lower workover costs related to fewer pump changes; and

·A decrease in repairs and maintenance costs due to a focus on critical operational activities and no turnaround costs in 2015.

(1)The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate for the nine months ended September 30, 2015 was $27.94 per barrel (2014 — $44.49 per barrel) for Foster Creek, and $30.23 per barrel (2014 — $48.02 per barrel) for Christina Lake. Our blending ratios range from approximately 25 percent to 33 percent.

Risk Management

Risk management activities for the nine months ended September 30, 2015 resulted in realized gains of $249 million (2014 — realized losses of $59 million), consistent with our contract prices exceeding average benchmark prices.

Oil Sands — Natural Gas

Oil Sands includes our 100 percent-owned natural gas operations in Athabasca. A portion of the natural gas produced from our Athabasca property is used as fuel at Foster Creek. Our natural gas production for the three and nine months ended September 30, 2015, net of internal usage, was 19 MMcf per day and 20 MMcf per day, respectively (2014 — 23 MMcf per day and 22 MMcf per day, respectively). Operating Cash Flow was $3 million in the third quarter (2014 — $5 million) and $7 million on a year-to-date basis (2014 — $43 million). These decreases were primarily related to the decline in natural gas sales prices.

Oil Sands — Capital Investment

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2015	2014	2015	2014
Foster Creek	96	207	318	637
Christina Lake	147	198	515	563
	243	405	833	1,200
Narrows Lake	12	38	41	130
Telephone Lake	4	23	19	94
Grand Rapids	6	20	32	36
Other (1)	7	8	21	32
Capital Investment (2)	272	494	946	1,492

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

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

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

Existing Projects

Capital investment at Foster Creek in 2015 is focused on sustaining capital related to existing production, expansion phase G and the drilling of stratigraphic test wells primarily related to future sustaining well pads. In the third quarter, capital investment declined compared with 2014 due to lower spending related to field construction and completion costs associated with the commissioning of phase F in 2014. On a year-to-date basis, capital investment decreased mainly due to lower spending on phase F construction.

In 2015, Christina Lake capital investment is focused on sustaining capital related to existing production, expansion phases F and G, and the optimization project. Capital investment in the third quarter decreased from 2014 primarily due to lower spending on phase F facility detailed engineering and procurement. On a year-to-date basis, capital investment decreased due to lower spending on phase F facilities, partially offset by increased investment in sustaining activities.

Capital investment at Narrows Lake in 2015 is focused on detailed engineering and construction wind-down. Capital investment declined in the third quarter and on a year-to-date basis compared with 2014 due to the suspension of new construction at Narrows Lake until further notice.

Emerging Projects

In 2015, Telephone Lake capital investment has primarily focused on completing front-end engineering work on the central processing facility and preliminary infrastructure development. Capital spending decreased in the third quarter and on a year-to-date basis as we did not drill any stratigraphic test wells in the nine months ended September 30, 2015 (2014 — 45 stratigraphic test wells).

Capital investment at Grand Rapids in 2015 has primarily focused on continued operation of the SAGD pilot project. A third well pair was drilled, completed and commenced steam circulation in the second quarter. Costs incurred with the third SAGD well pair were partially offset by not drilling any stratigraphic test wells in 2015 (2014 — 9 stratigraphic test wells). Capital investment decreased compared with 2014 as all work related to the dismantling and removal of an existing SAGD facility purchased in 2014 has been completed.

Drilling Activity (1)

	Gross Stratigraphic Test Wells (2)		Gross Production Wells (3) (4)
Nine Months Ended September 30,	2015	2014	2015	2014
Foster Creek	122	147	21	61
Christina Lake	36	52	67	40
	158	199	88	101
Narrows Lake	—	22	—	—
Telephone Lake	—	45	—	—
Grand Rapids	—	9	1	—
Other	—	21	—	—
	158	296	89	101

(1)In addition to the drilling activity included within the table, we drilled seven gross service wells in the nine months ended September 30, 2015 (2014 — three gross service wells).

(2)Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to occur year-round in remote drilling locations. In the nine months ended September 30, 2015, we drilled seven wells (2014 — 14 wells) and commissioned our second SkyStratTM drilling rig.

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

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

Future Capital Investment

Due to our expectation that low commodity prices will persist for an extended period, we have adopted a more moderate and staged approach to future oil sands expansions. We will consider expanding existing projects and developing emerging projects only when we believe we will maximize cost savings and capital efficiencies.

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Existing Projects

Foster Creek is currently producing from phases A through F. Capital investment for 2015 is forecast to be between $415 million and $435 million. We plan to continue focusing on sustaining capital related to existing production as well as progressing expansion phase G. We expect phase G to add initial design capacity of 30,000 gross barrels per day and first production is anticipated in the first half of 2016. Spending related to construction work on phase H was deferred in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase H has an initial design capacity of 30,000 gross barrels per day. In December 2014, we received regulatory approval for expansion phase J, a 50,000 gross barrel per day phase.

Christina Lake is producing from phases A through E. Capital investment for 2015 is forecast to be between $685 million and $705 million and we plan to continue focusing on sustaining capital related to existing production, expansion phase F and the optimization project. Expansion work on phase F, including cogeneration, is continuing as planned. We anticipate adding production capacity of 50,000 gross barrels per day from phase F in the second half of 2016. The optimization project is expected to add production capacity of 22,000 gross barrels per day with a ramp-up over a twelve month period. The optimization project began steam injection late in the third quarter of 2015. Spending on phase G engineering and procurement has continued in 2015. Construction work on phase G was deferred earlier this year in response to the low commodity price environment, pushing the expected start-up to beyond 2017. Phase G has an initial design capacity of 50,000 gross barrels per day. We submitted a joint application and environmental impact assessment to regulators in March 2013 for the phase H expansion, a 50,000 gross barrel per day phase, for which we expect to receive regulatory approval in the fourth quarter of 2015.

Capital investment at Narrows Lake is forecast to be between $45 million and $50 million in 2015. For the remainder 2015, we plan to continue to focus our capital investment on detailed engineering and procurement. We suspended new construction in response to low commodity prices.

Emerging Projects

Two of our emerging projects are Telephone Lake and Grand Rapids. Capital investment for our new resource plays is forecast to be between $70 million and $80 million in 2015. We plan to continue the pilot project at Grand Rapids and engineering activities at Telephone Lake.

DD&A

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

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

	As at
	December 31,
($ millions, unless otherwise indicated)	2014
Upstream Property, Plant and Equipment	14,644
Estimated Future Development Capital	20,084
Total Estimated Upstream Cost Base	34,728
Total Proved Reserves (MMBOE)	2,393
Implied Depletion Rate ($/BOE)	14.51

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 $16.50 per barrel of oil equivalent. Amounts related to assets under construction, which would be included in the total upstream cost base and would have proved reserves attributed to them, are not depleted. Property specific rates will exclude upstream assets that are depreciated on a straight-line basis. As such, our actual depletion will differ from depletion calculated by applying the above implied depletion rate. Further information on our accounting policy for DD&A is included in our notes to the Consolidated Financial Statements.

In the three and nine months ended September 30, 2015, Oil Sands DD&A increased $16 million and $49 million, respectively, primarily due to higher sales volumes.

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CONVENTIONAL

Our Conventional operations include predictable cash flow producing crude oil and natural gas assets in Alberta and Saskatchewan, including a CO2 enhanced oil recovery project in Weyburn, our heavy oil asset at Pelican Lake and developing tight oil assets in Alberta. Pelican Lake produces conventional heavy oil using polymer flood technology. The established assets in this segment are strategically important for their long life reserves, stable operations and diversity of crude oil produced. The cash flow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment while 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.

On July 29, 2015, we completed the sale of our royalty interest and mineral fee title lands business, which included approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. A royalty on our working interest production from these fee lands and a GORR on production from our Pelican Lake and Weyburn assets were also included in the sale. We received cash proceeds of approximately $3.3 billion and recorded an after-tax gain of approximately $1.9 billion. Associated third party royalty-interest volumes prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.

Additional developments in our Conventional segment in the third quarter of 2015 compared with 2014 include:

·Crude oil production averaging 63,679 barrels per day, decreasing 14 percent, as an increase in production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the sale of our royalty interest and mineral fee title lands business, and the divestiture of a non-core asset in 2014;

·Reduced our crude oil operating costs by $34 million or $2.84 per barrel, compared with 2014;

·Generating Operating Cash Flow net of capital investment of $186 million, a decrease of 34 percent; and

·Resuming drilling activity at our tight oil projects in southeast Alberta and at our CO2 enhanced oil recovery project at Weyburn.

Conventional — Crude Oil

Three Months Ended September 30, 2015 Compared With September 30, 2014

Financial and Per-unit Results

	Three Months Ended September 30, 2015				Three Months Ended September 30, 2014
($ millions, unless otherwise noted)			$ per-unit (1)			$ per-unit (1)
Gross Sales	279		48		619	92
Less: Royalties	23		4		58	9
Revenues	256		44		561	83
Expenses
Transportation and Blending	49		8		69	11
Operating	90		16		124	18
Production and Mineral Taxes	4		1		10	1
(Gain) Loss on Risk Management	(49	)	(9	)	6	1
Operating Cash Flow	162		28		352	52
Capital Investment	52				189
Operating Cash Flow Net of Related Capital Investment	110				163

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

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

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Revenues

Pricing

Our average crude oil sales price was $42.43 per barrel in the third quarter, 50 percent lower than in 2014, consistent with the decline in crude oil benchmark prices.

Production Volumes

(barrels per day)	2015	Percent Change		2014
Heavy Oil	33,997	(13	)%	39,096
Light and Medium Oil	28,491	(15	)%	33,548
NGLs	1,191	(12	)%	1,356
	63,679	(14	)%	74,000

Production declined as higher production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the sale of our royalty interest and mineral fee title lands business, and the divestiture of a non-core asset in 2014. Production from the divested assets was 1,251 barrels per day in the third quarter (2014 — 6,947 barrels per day).

Condensate

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

Royalties

Royalties decreased $35 million primarily due to lower realized sales prices, partially offset by additional royalties at Pelican Lake, Weyburn and other conventional assets resulting from the sale of our royalty interest and mineral fee title lands business. In the third quarter, the effective crude oil royalty rate for our Conventional properties was 10.1 percent (2014 — 10.8 percent).

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

Production and mineral taxes decreased, consistent with the decline in crude oil prices and due to the sale of our royalty interest and mineral fee title lands business.

Expenses

Transportation and Blending

Transportation and blending costs decreased $20 million. Blending costs declined primarily due to lower condensate prices. Transportation charges were $3 million lower primarily due to a decline in sales volumes and a reduction in volumes moved by rail. In the third quarter of 2015, we did not transport any crude oil by rail (2014 — 1,534 barrels per day).

Operating

Primary drivers of our operating expenses in the third quarter of 2015 were workforce costs, workover activities, electricity, chemical consumption, and property taxes and lease costs. Operating expenses declined $34 million or $2.84 per barrel.

The per-unit decline was primarily due to:

·A decline in workover costs;

·Lower repairs and maintenance due to a focus on critical operational activities; and

·Lower trucking expenses as we added pipeline infrastructure.

These decreases were partially offset by lower production.

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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 heavy oil basis, the cost of condensate for our heavy oil properties was $9.56 per barrel in the third quarter (2014 —$13.25 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

Risk Management

Risk management activities in the third quarter resulted in realized gains of $49 million (2014 — realized losses of $6 million), consistent with our contract prices exceeding average benchmark prices.

Nine Months Ended September 30, 2015 Compared With September 30, 2014

Financial and Per-unit Results

	Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
($ millions, unless otherwise noted)			$ per-unit (1)			$ per-unit (1)
Gross Sales	1,000		53		1,978	95
Less: Royalties	78		4		174	8
Revenues	922		49		1,804	87
Expenses
Transportation and Blending	160		8		249	13
Operating	299		16		402	19
Production and Mineral Taxes	14		1		28	1
(Gain) Loss on Risk Management	(100	)	(5	)	38	2
Operating Cash Flow	549		29		1,087	52
Capital Investment	148				601
Operating Cash Flow Net of Related Capital Investment	401				486

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

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

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Revenues

Pricing

Our average crude oil sales price decreased 47 percent to $46.41 per barrel, consistent with the sustained decline in crude oil benchmark prices.

Production Volumes

(barrels per day)	2015	Percent Change		2014
Heavy Oil	35,739	(11	)%	40,060
Light and Medium Oil	31,787	(8	)%	34,488
NGLs	1,286	7	%	1,200
	68,812	(9	)%	75,748

Increased production from successful horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production from the divested assets was 3,417 barrels per day on a year-to-date basis (2014 — 7,293 barrels per day).

Royalties

Royalties decreased $96 million primarily due to lower realized sales prices, partially offset by additional royalties at Pelican Lake, Weyburn and other conventional assets resulting from the sale of our royalty interest and mineral fee title lands business. For the nine months ended September 30, 2015, the effective crude oil royalty rate for our Conventional properties was 9.3 percent (2014 — 10.2 percent). The Pelican Lake royalty calculation was based on net profits in 2015 as compared with a calculation based on gross revenues in 2014.

Production and mineral taxes also decreased, consistent with lower crude oil prices in 2015.

Expenses

Transportation and Blending

Transportation and blending costs decreased $89 million. Blending costs declined primarily due to lower condensate prices. Transportation charges were $23 million lower largely due to a decline in sales volumes and a reduction in volumes moved by rail. In the nine months ended September 30, 2015, we transported an average of 799 barrels per day of crude oil by rail (2014 — 3,099 barrels per day).

Operating

Primary drivers of our operating expenses for the nine months ended September 30, 2015 were workforce costs, workover activities, electricity, chemical consumption, and property taxes and lease costs. Operating expenses declined $103 million or $3.63 per barrel.

The per-unit decline was primarily due to:

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

·Lower trucking expenses as we added pipeline infrastructure; and

·Lower electricity costs as a result of a decrease in consumption due in part to the disposition of non-core assets, and a decline in prices.

These decreases were partially offset by lower production.

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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 heavy oil basis, the cost of condensate for our heavy oil properties was $11.21 per barrel on a year-to-date basis (2014 — $16.23 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.

Risk Management

Risk management activities for the nine months ended September 30, 2015 resulted in realized gains of $100 million (2014 — realized losses of $38 million), consistent with our contract prices exceeding average benchmark prices.

Conventional — Natural Gas

Financial Results

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Gross Sales	113		182		346		580
Less: Royalties	5		4		8		10
Revenues	108		178		338		570
Expenses
Transportation and Blending	3		5		12		14
Operating	41		51		131		152
Production and Mineral Taxes	1		2		2		8
(Gain) Loss on Risk Management	(13	)	(4	)	(38	)	(3	)
Operating Cash Flow	76		124		231		399
Capital Investment	3		9		9		20
Operating Cash Flow Net of Related Capital Investment	73		115		222		379

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

Three and Nine Months Ended September 30, 2015 Compared With September 30, 2014

Revenues

Pricing

In the third quarter and on a year-to-date basis, our average natural gas sales price decreased 29 percent to $3.00 per Mcf and 34 percent to $2.97 per Mcf, respectively, consistent with the decline in the AECO benchmark price.

Production

Production decreased 12 percent to 411 MMcf per day in the third quarter (nine percent to 427 MMcf per day on a year-to-date basis) due to expected natural declines and from the sale of our royalty interest and mineral fee title lands business, which produced 6 MMcf per day and 13 MMcf per day in the three and nine months ended September 30, 2015, respectively (2014 — 20 MMcf per day and 20 MMcf per day).

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Royalties

Royalties remained consistent compared with the third quarter of 2014 and decreased on a year-to-date basis. Reduced royalties as a result of lower prices and production declines were offset by additional royalties due to the sale of our royalty interest and mineral fee title lands business. The average royalty rate in the third quarter was 4.1 percent (2014 — 2.0 percent) and 2.3 percent (2014 — 1.7 percent) on a year-to-date basis.

Expenses

Transportation

In 2015, transportation costs decreased as a result of lower production volumes, partially offset by higher pipeline tariffs.

Operating

Primary drivers of our operating expenses were property taxes and lease costs, and workforce. In the three and nine months ended September 30, 2015, operating expenses decreased by $10 million and $21 million, respectively, primarily due to lower repairs and maintenance, and workforce, partially offset by lower production volumes.

Risk Management

Risk management activities resulted in realized gains of $13 million in the third quarter and $38 million on a year-to-date basis (2014 — realized gains of $4 million in the third quarter and $3 million on a year-to-date basis), consistent with our contract prices exceeding average benchmark prices.

Conventional — Capital Investment

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2015	2014	2015	2014
Heavy Oil	14	76	46	264
Light and Medium Oil	38	113	102	337
Natural Gas	3	9	9	20
Capital Investment (1)	55	198	157	621

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

Capital investment declined in 2015 primarily due to spending reductions on crude oil activities in response to the low commodity price environment. Capital investment in 2015 was primarily related to maintenance capital and spending for our CO2 enhanced oil recovery project at Weyburn and drilling activities at our tight oil projects in southeast Alberta.

Conventional Drilling Activity

	Nine Months Ended September 30,
(net wells, unless otherwise stated)	2015	2014
Crude Oil	15	101
Recompletions	498	620
Gross Stratigraphic Test Wells	—	18
Other (1)	1	34

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

Drilling activity declined in 2015, reflecting the decision to suspend the majority of our 2015 drilling program in southern Alberta and Saskatchewan as a result of the low commodity price environment. In the third quarter, some drilling activity resumed at our tight oil projects in southeast Alberta and at our CO2 enhanced oil recovery project at Weyburn.

Future Capital Investment

Consistent with our expectation that commodity prices will continue to be low for a prolonged period of time, we are planning a more moderate approach to developing our conventional crude oil opportunities. We plan to focus on drilling projects that are considered to be relatively low risk, with short production cycle times and strong expected returns.

Our 2015 crude oil capital investment forecast is between $250 million and $270 million with spending plans mainly focused on maintenance capital and spending for our CO2 enhanced oil recovery project at Weyburn and development of our tight oil assets.

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DD&A and Exploration Expense

DD&A

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

Conventional DD&A decreased $28 million and $34 million for the three and nine months ended September 30, 2015, respectively.

Exploration Expense

Costs incurred after the legal right to explore has been obtained and before technical feasibility and commercial viability have been established are capitalized as E&E assets. If a field, area or project is determined not to be technically feasible and commercially viable or we decide not to continue the exploration activity, the unrecoverable costs are charged to exploration expense.

For the nine months ended September 30, 2015, $21 million (2014 — $nil) of previously capitalized E&E costs related to certain conventional tight oil exploration assets were deemed not to be commercially viable and technically feasible and were recorded as exploration expense.

REFINING AND MARKETING

We are a 50-percent partner in the Wood River and Borger refineries, which are located in the U.S. Our Refining and Marketing segment allows us to capture the value from crude oil production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to our refineries. The Refining and Marketing segment’s results are affected by changes in the U.S./Canadian dollar exchange rate. The weakening of the Canadian dollar relative to the U.S. dollar by 17 percent in the three months ended September 30, 2015, and 13 percent on a year-to-date basis, as compared with 2014, had a positive impact of approximately $36 million and $120 million, respectively, on our refining gross margin.

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

·Closing the purchase of a crude-by-rail terminal for $75 million, plus adjustments, and commencing operations;

·Crude oil runs and refined product output decreasing as a result of unplanned process unit outages at our Borger refinery and the start of a planned turnaround at our Wood River refinery in September 2015; and

·Operating Cash Flow decreasing 57 percent to $29 million primarily due to higher heavy crude oil feedstock costs relative to the WTI benchmark price, higher operating costs and lower refined product output, partially offset by improved margins on the sale of secondary products, an increase in average market crack spreads and weakening of the Canadian dollar relative to the U.S. dollar.

Refinery Operations (1)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2015	2014	2015	2014
Crude Oil Capacity (2) (Mbbls/d)	460	460	460	460
Crude Oil Runs (Mbbls/d)	394	407	424	424
Heavy Crude Oil	186	201	202	205
Light/Medium	208	206	222	219
Refined Products (Mbbls/d)	414	429	448	446
Gasoline	208	230	228	228
Distillate	131	131	141	138
Other	75	68	79	80
Crude Utilization (percent)	86	88	92	92

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

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

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

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We commenced operations of our crude-by-rail facility at Bruderheim, Alberta, and 12 unit trains, including five unit trains for third parties, were loaded in the first month of operations.

Financial Results

In the third quarter, unplanned process unit outages at our Borger refinery for most of July and the start of a planned turnaround at Wood River reduced crude oil runs and refined product output. The Wood River turnaround is expected to be completed in October. In the third quarter of 2014, we had an unplanned coker outage at Borger that lasted approximately two weeks and a planned turnaround at Wood River.

On a year-to-date basis, crude oil runs and refined product output was consistent with 2014. The unplanned outages at Borger and planned turnarounds at both of our refineries in 2015 had a similar impact on crude oil runs and refined product output as the outage and turnarounds in 2014.

Our crude utilization represents the percentage of total crude oil processed in our refineries relative to the total capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by processing less expensive crude oil. The amount of heavy crude oil processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total input slate being optimized at each refinery to maximize economic benefit. The volume of heavy crude oil processed in 2015 decreased from 2014 as a result of processing higher volumes of medium crude oils due to more favorable economics.

Financial Results

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Revenues	2,242		3,144		6,775		9,885
Purchased Product	2,012		2,918		5,826		8,836
Gross Margin	230		226		949		1,049
Expenses
Operating	215		162		552		525
(Gain) Loss on Risk Management	(14	)	(4	)	(27	)	(9	)
Operating Cash Flow	29		68		424		533
Capital Investment	67		42		159		111
Operating Cash Flow Net of Related Capital Investment	(38	)	26		265		422

Gross Margin

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

In the third quarter of 2015, the increase in gross margin was primarily due to:

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

·Average market crack spreads increased as unplanned refinery outages in the industry caused product inventory drawdowns and slightly improved refined product pricing; and

·Weakening of the Canadian dollar relative to the U.S. dollar.

The increase in gross margin was partially offset by higher heavy crude oil feedstock costs relative to WTI, consistent with the narrowing of the WTI-WCS differential, and lower refined product output.

On a year-to-date basis, the decline in gross margin was primarily due to higher heavy crude oil feedstock costs relative to WTI, consistent with the narrowing of the WTI-WCS differential.

The decrease in gross margin was partially offset by:

·Improved margins on the sale of our secondary products, due to lower overall feedstock costs consistent with the decline in WTI; and

·Weakening of the Canadian dollar relative to the U.S. dollar.

Our refineries do not blend renewable fuels into the motor fuel products we produce. Consequently, we are obligated to purchase Renewable Identification Numbers (“RINs”). In the third quarter of 2015 and on a year-to-date basis, the cost of our RINs was $27 million and $120 million, respectively (2014 — $29 million and $85 million, respectively). The increase on a year-to-date basis is consistent with the rise in the ethanol RINs benchmark price. This cost remains a minor component of our total refinery feedstock costs.

Operating Expense

Primary drivers of operating expenses in the third quarter of 2015 and on a year-to-date basis were maintenance, labour, utilities and supplies. Operating expenses increased in the three and nine months ended September 30, 2015 compared with 2014 primarily due to weakening of the Canadian dollar relative to the U.S.

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dollar, partially offset by a decline in utility costs resulting from lower natural gas prices. In the third quarter, operating expenses were also impacted by higher maintenance costs related to unplanned outages and planned turnaround activities.

Refining and Marketing — Capital Investment

	Three Months Ended September 30,		Nine Months Ended September 30,
($ millions)	2015	2014	2015	2014
Wood River Refinery	47	30	108	64
Borger Refinery	19	12	49	47
Marketing	1	—	2	—
	67	42	159	111

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

In 2015, we expect to invest between $220 million and $250 million mainly related to the debottlenecking project at Wood River, in addition to maintenance, reliability and environmental initiatives.

DD&A

Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities. The service lives of these assets are reviewed on an annual basis. Refining and Marketing DD&A increased by $10 million in the third quarter and $24 million on a year-to-date basis, primarily due to the change in the U.S./Canadian dollar exchange rate.

CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been recorded at transfer prices based on current market prices, as well as unrealized intersegment profits in inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses related to derivative financial instruments used to mitigate fluctuations in commodity prices and the unrealized mark-to-market gains and losses on the long-term power purchase contract. In the third quarter, our risk management activities resulted in $127 million of unrealized gains (2014 — $165 million of unrealized gains). On a year-to-date basis, we had $169 million of unrealized losses (2014 — $180 million of unrealized gains). The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing costs and research costs.

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
General and Administrative	75		80		220		291
Finance Costs	122		105		359		337
Interest Income	(6	)	(4	)	(20	)	(31	)
Foreign Exchange (Gain) Loss, Net	417		263		832		223
Research Costs	6		3		20		9
(Gain) Loss on Divestiture of Assets	(2,379	)	(137	)	(2,395	)	(157	)
Other (Income) Loss, Net	(1	)	2		1		—
	(1,766	)	312		(983	)	672

Expenses

General and Administrative

Primary drivers of our general and administrative expenses in 2015 were workforce, office rent and information technology costs. General and administrative expenses decreased by $5 million in the third quarter due to reductions in discretionary spending, offset by higher employee long-term incentive costs. During the third quarter, we incurred severance costs of $3 million related to the previously announced reductions to our workforce. It is expected that additional severance costs of $32 million will be recorded in the fourth quarter.

On a year-to-date basis, general and administrative expenses decreased by $71 million primarily due to lower employee long-term incentive costs driven by the decline in our share price, and lower discretionary spending.

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

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costs increased $17 million in the third quarter ($22 million on a year-to-date basis) compared with 2014 due to higher interest incurred on our U.S. dollar denominated debt due to weakening of the Canadian dollar relative to the U.S. dollar. On a year-to-date basis, the increase was partially offset by lower interest incurred on the Partnership Contribution Payable which was repaid in the first quarter of 2014.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable, for the three and nine months ended September 30, 2015 was 5.3 percent (2014 — 5.0 percent).

Foreign Exchange

	Three Months Ended September 30,			Nine Months Ended September 30,
($ millions)	2015		2014	2015		2014
Unrealized Foreign Exchange (Gain) Loss	457		259	878		221
Realized Foreign Exchange (Gain) Loss	(40	)	4	(46	)	2
	417		263	832		223

The majority of unrealized foreign exchange gains and losses stem from translation of our U.S. dollar denominated debt. The Canadian dollar weakened by seven percent relative to the U.S. dollar from June 30, 2015 to September 30, 2015 resulting in an unrealized loss in the third quarter; the Canadian dollar weakened by 13 percent relative to the U.S. dollar from December 31, 2014 to September 30, 2015 resulting in a year-to-date unrealized loss of $878 million.

DD&A

Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment, leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service lives of these assets are reviewed on an annual basis. DD&A in the third quarter of 2015 was $20 million (2014 — $20 million) and $62 million on a year-to-date basis (2014 — $61 million).

Income Tax

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Current Tax
Canada	451		49		686		82
United States	(4	)	(14	)	(10	)	21
Total Current Tax Expense (Recovery)	447		35		676		103
Deferred Tax Expense (Recovery)	(228	)	144		(516	)	396
	219		179		160		499

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

	Nine Months Ended September 30,
($ millions)	2015		2014
Earnings Before Income Tax	1,419		1,715
Canadian Statutory Rate	26.1	%	25.2	%
Expected Income Tax	370		431
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(15	)	18
Non-Deductible Stock-Based Compensation	7		15
Non-Taxable Capital Losses	113		33
Unrecognized Capital Losses Arising from Unrealized Foreign Exchange	113		33
Adjustments Arising From Prior Year Tax Filings	(13	)	—
Recognition of Capital Losses	(149	)	(6	)
Recognition of U.S. Tax Basis	(385	)	—
Change in Statutory Rate	158		—
Other	(39	)	(25	)
Total Tax	160		499
Effective Tax Rate	11.3	%	29.1	%

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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 income taxes is adequate. There are usually a number of tax matters under review and as a result income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation.

On a year-to-date basis, current tax increased due to the sale of our royalty interest and mineral fee title lands business, and from accelerating the timing of income tax payable as a result of certain corporate restructuring transactions and the decision to maximize availability of future income tax deductions in response to the Alberta corporate income tax rate increasing from 10 percent to 12 percent on July 1, 2015. Of the $447 million of current tax, $391 million is attributed to the sale of the royalty interest and mineral fee title lands business.

In the third quarter of 2015, we recorded a deferred tax recovery of $385 million arising from an adjustment to the tax basis of our refining assets. The increase in tax basis was a result of our partner recognizing a taxable gain on its interest in WRB Refining LP (“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets.

For the nine months ended September 30, 2015, the deferred tax recovery was also due to the reversal of timing differences associated with the recognition of partnership income, unrealized risk management losses and current year operating losses. This was partially offset by a one-time charge of approximately $158 million from the revaluation of the deferred tax liability due to the increase in the Alberta corporate income tax rate.

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

Our effective tax rate for 2015 differs from the statutory rate due to an increase in tax basis of our U.S. assets, and the recognition of the benefit of capital losses, partially offset by non-deductible foreign exchange losses and a one-time deferred tax expense arising from the Alberta corporate income tax rate increase.

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2015		2014		2015		2014
Net Cash From (Used In)
Operating Activities	542		1,092		1,152		2,658
Investing Activities	2,424		(463	)	1,357		(3,552	)
Net Cash Provided (Used) Before Financing Activities	2,966		629		2,509		(894	)
Financing Activities	(134	)	(232	)	1,032		(457	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency	(21	)	(1	)	(23	)	55
Increase (Decrease) in Cash and Cash Equivalents	2,811		396		3,518		(1,296	)

	September 30,	December 31,
	2015	2014
Cash and Cash Equivalents	4,401	883

Operating Activities

Cash from operating activities was $550 million and $1,506 million lower for the three and nine months ended September 30, 2015, respectively, mainly due to lower Cash Flow, as discussed in the Financial Results section of this MD&A. Excluding risk management assets and liabilities, working capital was $4,713 million at September 30, 2015 compared with $772 million at December 31, 2014. The increase in working capital was primarily due to the proceeds received from the sale of our royalty interest and mineral fee title lands business in July of 2015 and the common share issuance in the first quarter of 2015.

We anticipate that we will continue to meet our payment obligations as they come due.

Investing Activities

In the third quarter of 2015, cash from investing activities was $2,424 million, a $2,887 million increase from 2014 due to the divestiture of our royalty interest and mineral fee title lands business for proceeds of approximately $2.9 billion, net of current tax, and reduced capital expenditures in response to the low commodity price environment.

On a year-to-date basis, cash from investing activities was $1,357 million, a $4,909 million increase from 2014, primarily due to the divestiture of our royalty interest and mineral fee title lands business. Additionally, we spent

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US$1.4 billion to repay the Partnership Contribution Payable in March 2014, which contributed to the overall increase in cash from investing activities from 2014 to 2015.

Financing Activities

Cash used in financing activities decreased $98 million for the three months ended September 30, 2015, primarily due to the 40 percent reduction in our third quarter dividend and a net repayment of short-term borrowings in 2014.

Cash provided by financing activities increased $1,489 million on a year-to-date basis, primarily due to net proceeds from our common share issuance and cash savings from our DRIP, partially offset by a net repayment of short-term borrowings. For the nine months ended September 30, 2015, we had a net repayment of short-term borrowings compared with a net issuance in 2014. We issued 67.5 million common shares at a price of $22.25 per share for net proceeds of $1.4 billion in the first quarter of 2015. We plan to use the net proceeds to partially fund our capital expenditure program for 2015 and for general corporate purposes.

In the third quarter, we paid cash dividends of $0.16 per share or $133 million (2014 — $0.2662 per share or $201 million). On a year-to-date basis, we paid dividends of $0.6924 per share or $578 million of which $396 million was paid in cash with the remainder reinvested in common shares issued from treasury through our DRIP (2014 — $0.7986 per share or $604 million paid in cash). The declaration of dividends is at the sole discretion of the Board and is considered quarterly. While the DRIP continues to be in place, the discount has been discontinued as of July 2015.

Our long-term debt at September 30, 2015 was $6,312 million (December 31, 2014 — $5,458 million) with no principal payments due until October 2019 (US$1.3 billion). The principal amount of long-term debt outstanding in U.S. dollars has remained unchanged since August 2012. The $854 million increase in long-term debt is due to foreign exchange.

As at September 30, 2015, we were in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

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

The following sources of liquidity are available at September 30, 2015:

($ millions)	Amount	Term
Cash and Cash Equivalents	4,401	Not applicable
Committed Credit Facility	1,000	November 2017
Committed Credit Facility	3,000	November 2019
U.S. Base Shelf Prospectus (1)	US$2,000	July 2016
Canadian Base Shelf Prospectus (1)	1,500	July 2016

(1)Availability is subject to market conditions.

Committed Credit Facility

In 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. As at September 30, 2015, we had $4.0 billion available on our committed credit facility.

We have a commercial paper program which, together with our committed credit facility, is used to manage our short-term cash requirements. We reserve undrawn capacity under our committed credit facility for amounts of outstanding commercial paper. As of September 30, 2015, there was no commercial paper outstanding.

U.S. and Canadian Base Shelf Prospectuses

As at September 30, 2015, no notes were issued under our U.S. or Canadian base shelf prospectuses.

Financial Metrics

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

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	September 30,		December 31,
As at	2015		2014
Debt to Capitalization	33	%	35	%
Net Debt to Capitalization (1) (2)	13	%	31	%
Debt to Adjusted EBITDA (times)	2.7x		1.4x
Net Debt to Adjusted EBITDA (times) (1)	0.8x		1.2x

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

(2)Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.

We continue to have long-term targets for a Debt to Capitalization ratio of between 30 percent to 40 percent and a Debt to Adjusted EBITDA of between 1.0 times to 2.0 times. At September 30, 2015, our Debt to Capitalization metric was within our target range. Although our Debt to Adjusted EBITDA ratio was above our target of 2.0 times as at September 30, 2015, we believe it will return to within our target range.

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

As at September 30, 2015, we held $4.4 billion in cash and cash equivalents. Net Debt to Capitalization and Net Debt to Adjusted EBIDTA were 13 percent and 0.8 times, respectively (December 31, 2014 — 31 percent and 1.2 times, respectively).

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

Outstanding Share Data and Stock-Based Compensation Plans

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. At September 30, 2015, no preferred shares were outstanding. Cenovus issued 76.2 million common shares during the nine months ended September 30, 2015, including 8.7 million shares issued under the DRIP and 67.5 million shares issued related to the common share issuance in the first quarter of 2015.

The DRIP permits shareholders to reinvest their dividends into additional common shares. At the discretion of Cenovus, the additional common shares may be issued from treasury or purchased on the market. In the first half of 2015, participants in our DRIP were issued shares from treasury at a three percent discount to the average market price, as defined in the DRIP; this resulted in cash savings of $177 million. For the third quarter dividend, common shares acquired by the DRIP were purchased on the open market. While the DRIP continues to be in place, the discount has been discontinued as of July 2015. Refer to cenovus.com for more details.

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

PSUs and RSUs are whole share units which entitle the holder to receive upon vesting either a Cenovus common share or a cash payment equal to the value of a Cenovus common share. Refer to Note 27 of the Consolidated Financial Statements and Note 18 of our interim Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and DSU Plans.

As at September 30, 2015	Units Outstanding (thousands)	Units Exercisable (thousands)
Common Shares	833,290	N/A
Stock Options	46,950	27,462
Other Stock-Based Compensation Plans	11,368	1,459

Contractual Obligations and Commitments

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

Legal Proceedings

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

RISK MANAGEMENT

For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with the Risk Management section of our 2014 annual MD&A. A description of the risk factors and uncertainties affecting Cenovus can be found in the Advisory and a full discussion of the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2014.

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. We continue to be exposed to the risks identified in our 2014 annual MD&A in addition to jurisdictional risk.

The following provides an update on our commodity price risk management and jurisdictional risk.

Commodity Price Risk

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

We manage our commodity price exposure through a combination of activities including business integration, financial hedges and physical contracts. For further details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Note 20 to the interim Consolidated Financial Statements. The financial impact is summarized below:

Impact of Financial Risk Management Activities

	Three Months Ended September 30,
	2015						2014
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	(195	)	(141	)	(336	)	9		(159	)	(150	)
Natural Gas	(15	)	15		—		(5	)	—		(5	)
Refining	(14	)	(7	)	(21	)	(4	)	(7	)	(11	)
Power	4		6		10		—		1		1
(Gain) Loss on Risk Management	(220	)	(127	)	(347	)	—		(165	)	(165	)
Income Tax Expense (Recovery)	59		34		93		—		43		43
(Gain) Loss on Risk Management, After Tax	(161	)	(93	)	(254	)	—		(122	)	(122	)

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	Nine Months Ended September 30,
	2015						2014
($ millions)	Realized		Unrealized		Total		Realized		Unrealized		Total
Crude Oil	(355	)	120		(235	)	95		(173	)	(78	)
Natural Gas	(43	)	41		(2	)	(4	)	(2	)	(6	)
Refining	(26	)	5		(21	)	(8	)	(5	)	(13	)
Power	7		3		10		2		—		2
(Gain) Loss on Risk Management	(417	)	169		(248	)	85		(180	)	(95	)
Income Tax Expense (Recovery)	112		(48	)	64		(21	)	47		26
(Gain) Loss on Risk Management, After Tax	(305	)	121		(184	)	64		(133	)	(69	)

In the three and nine months ended September 30, 2015, management of commodity price risk resulted in realized gains on crude oil and natural gas financial instruments, consistent with our contract prices exceeding the average benchmark price. In the third quarter, we recorded unrealized gains on our crude oil financial instruments as a result of changes in market prices. On a year-to-date basis, we recorded unrealized losses on our crude oil and natural gas financial instruments primarily due to the realization of settled positions partially offset by changes in market prices.

Jurisdictional Risk

The Alberta NDP provincial government is proceeding with plans to study, and potentially modify, Alberta’s royalty structure and increase carbon levies. A change in the Alberta provincial royalty structure could have a significant impact on Cenovus’s future financial results, cost of capital and capital investment plans. We are cautiously awaiting the results of the planned royalty review before finalizing plans to begin reinvesting capital in previously deferred oil sands expansion projects.

The newly elected Federal Liberal government may implement new environmental legislation and regulatory oversight, which may have a significant impact on the oil and gas industry. Potential pipeline opposition may result in wider differentials between Canadian heavy blends and North American benchmarks.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES

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

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

Critical Judgments in Applying Accounting Policies

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in our annual and interim Consolidated Financial Statements. There have been no changes to our critical judgments used in applying accounting policies during the nine months ended September 30, 2015. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014.

Key Sources of Estimation Uncertainty

Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. There have been no changes to our key sources of estimation uncertainty during the nine months ended September 30, 2015. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014.

Changes in Accounting Policies

There were no new or amended accounting standards or interpretations adopted during the nine months ended September 30, 2015.

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Future Accounting Pronouncements

Revenue Recognition

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

On September 11, 2015, the IASB published an amendment to IFRS 15, deferring the effective date of the standard by one year to annual periods beginning on or after January 1, 2018. Early adoption is still permitted. The standard may be applied retrospectively or using a modified retrospective approach. We are currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.

Additional Standards

A description of additional standards and interpretations that will be adopted in future periods can be found in the notes to the Consolidated Financial Statements for the year ended December 31, 2014.

CONTROL ENVIRONMENT

There have been no changes to internal control over financial reporting (“ICFR”) in the three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, ICFR.

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

TRANSPARENCY AND CORPORATE RESPONSIBILITY

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

Our Corporate Responsibility (“CR”) policy continues to drive our commitments, our CR approach and reporting, and enables alignment with our business objectives and processes. Our CR reporting activities are guided by this policy and 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 September 2015, our CR practices were recognized internationally with the inclusion of Cenovus to the Dow Jones Sustainability World Index for the fourth consecutive year. We were also named to the Dow Jones Sustainability North America Index for the sixth consecutive year.

In June 2015, Cenovus was named one of the Top 50 Socially Responsible Corporations in Canada by Maclean’s magazine and Sustainalytics for the fourth year in a row and for the fifth consecutive year by Corporate Knights magazine as one of the 2015 Best 50 Corporate Citizens in Canada. We were also included in the Euronext Vigeo World 120 Index for the second year. This index recognizes the top 120 companies globally for their high degree of control of corporate responsibility risk and contributions to sustainable development.

In February 2015, Cenovus was named the top Canadian company for Best Sustainability Practice at the Investor Relations Magazine Awards for the third consecutive year. In January 2015, Cenovus was included in the RobecoSAM Sustainability Yearbook for the second time in a row. RobecoSAM is a Swiss-based specialist in international sustainability investment that publishes the Dow Jones Sustainability Index (“DJSI”). Cenovus is also part of the FTSE4Good Index series and the MSCI Global Sustainability Index series. These internationally recognized benchmarks are designed to measure the performance of companies demonstrating strong environmental, social and governance practices.

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

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

48

OUTLOOK

We expect the remainder of 2015 to continue to be a challenging time for our industry. We anticipate prices will remain low in the fourth quarter of 2015 and into 2016. We revised our 2015 budget in January, reducing our capital spending plans and introducing other initiatives intended to conserve cash and maintain the strength of our balance sheet. We have strong producing assets, an integrated portfolio, a solid balance sheet and flexible capital plans. We continue to pursue our long-term strategy at a pace we believe is in line with the current commodity price environment.

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

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

·We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current price environment and the pace of growth of the global economy. Overall, we expect crude oil price volatility in the fourth quarter of 2015 and a modest price improvement in 2016. Slower global supply growth, combined with annual increases in demand growth, should support prices for the next fifteen months, constrained by the need to draw down surplus crude oil inventories and anticipated re-entry of Iranian crude oil into markets. We continue to anticipate slower supply growth from North American producers as a result of the significant reductions in capital spending. The low crude oil price environment also serves to help boost global economic momentum. We believe there is a risk that OPEC will attempt to gain market share by increasing rig counts or increasing OPEC production, which will depress crude oil prices, and that economic uncertainty in China may slow emerging market demand;

·We expect the Brent-WTI differential to remain near current levels primarily because of high international crude oil storage levels and slowing U.S. supply growth. Overall, the differential will likely be set by transportation costs. The Brent-WTI differential is expected to remain volatile due to mismatches in demand, global imports and refinery turnarounds; and

·We also expect that the WTI-WCS differential will widen from currently narrow levels due to expected Canadian supply growth and declining U.S. light tight oil supply. However, substantially wider differentials are unlikely due to excess rail capacity and further expansions on existing pipeline systems.

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

Refining crack spreads in 2016, as forecasted at September 30, 2015, are expected to strengthen around the second quarter when refineries conduct their seasonal turnaround activities.

Natural gas production is anticipated to increase in the fourth quarter of 2015 as coal-to-gas substitution in the power sector is expected to continue to be the swing demand to balance the market. As a result, natural gas prices are expected to remain weak for the remainder of 2015 and through the first half of 2016.

The average foreign exchange forward price expected over the next fifteen months is US$0.746/C$. Canadian federal election results, commodity prices and the timing of a U.S. interest rate increase are expected to influence future foreign exchange fluctuations. We expect that the Canadian dollar, compared with the U.S. dollar, will remain relatively weak in the near term due to Canadian political and economic uncertainty, and then gradually strengthen as 2016 progresses and commodity prices improve. Overall, a weak Canadian dollar should have a positive impact on our revenues and Operating Cash Flow.

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

49

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

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

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

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

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

(1)Expected gross production capacity.

Key Priorities

Maintain Financial Resilience

We have strong producing assets, an integrated portfolio and a solid balance sheet which should position us well to face the challenges in the remainder of 2015 and into 2016. Together, our share issuance in the first quarter of 2015 and the sale of our royalty interest and mineral fee title lands business in July 2015 raised cash proceeds of approximately $4.7 billion. These transactions strengthen our balance sheet and provide us with greater financial resilience during these uncertain times to consider investing in opportunities that we believe have strong future returns.

With an additional $2.9 billion of cash on hand after the divestiture of our royalty interest and mineral fee title lands business, we have started to reinvest capital into expansion projects that were previously deferred to 2016.

Our capital planning process remains flexible. We have adopted a more moderate and staged approach to future oil sands expansions. We will consider expanding existing projects and developing emerging opportunities only when we believe we will maximize cost savings and capital efficiencies to generate the greatest potential return for shareholders. We will continue to assess our spending plans on a regular basis while closely monitoring crude oil prices in the fourth quarter of 2015 and into 2016.

Attack Cost Structures

We continue to challenge cost structures across the organization to maintain our track record of cost efficiency. We must ensure that, over the long term, we maintain an efficient and sustainable cost structure and maximize the strengths of our functional business model. In the nine months ended September 30, 2015, we captured significant savings from capital, operating and general and administrative cost reductions. As a result, we anticipate savings of approximately $400 million for the full year. As previously announced, in light of sustained low commodity price environment and our plan to moderate our pace of growth, we made substantial reductions to our workforce in 2015.

Enable Market Access

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

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

50

Other Key Challenges

The Alberta NDP provincial government is proceeding with plans to study, and potentially modify, Alberta’s royalty structure and increase carbon levies. A change in the Alberta provincial royalty structure could have a significant impact on Cenovus’s future financial results, cost of capital and capital investment plans.

The newly elected Federal Liberal government may implement new environmental legislation and regulatory oversight, which may have a significant impact on the oil and gas industry. Potential pipeline opposition may result in wider differentials between Canadian heavy blends and North American benchmarks.

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.
Third Quarter 2015 Report	Management’s Discussion and Analysis

51

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME (unaudited)

For the period ended September 30,

($ millions, except per share amounts)

		Three Months Ended						Nine Months Ended
	Notes	2015			2014			2015			2014
Revenues	1
Gross Sales		3,308			5,094			10,252			15,769
Less: Royalties		35			124			112			365
		3,273			4,970			10,140			15,404
Expenses	1
Purchased Product		1,926			2,721			5,566			8,180
Transportation and Blending		483			592			1,509			1,900
Operating		479			490			1,385			1,580
Production and Mineral Taxes		5			12			16			36
(Gain) Loss on Risk Management	20	(347		)	(165		)	(248		)	(95		)
Depreciation, Depletion and Amortization	10	473			475			1,455			1,415
Exploration Expense	9	—			—			21			1
General and Administrative		75			80			220			291
Finance Costs	4	122			105			359			337
Interest Income		(6		)	(4		)	(20		)	(31		)
Foreign Exchange (Gain) Loss, Net	5	417			263			832			223
Research Costs		6			3			20			9
(Gain) Loss on Divestiture of Assets	12	(2,379		)	(137		)	(2,395		)	(157		)
Other (Income) Loss, Net		(1		)	2			1			—
Earnings Before Income Tax		2,020			533			1,419			1,715
Income Tax Expense	6	219			179			160			499
Net Earnings		1,801			354			1,259			1,216
Other Comprehensive Income (Loss), Net of Tax	16
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post Retirement Benefits		(4		)	(6		)	5			(11		)
Items That May be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		245			149			463			108
Total Other Comprehensive Income, Net of Tax		241			143			468			97
Comprehensive Income		2,042			497			1,727			1,313
Net Earnings Per Common Share	7
Basic		$	2.16		$	0.47		$	1.55		$	1.61
Diluted		$	2.16		$	0.47		$	1.55		$	1.60

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
Third Quarter 2015 Report	Consolidated Financial Statements

52

CONSOLIDATED BALANCE SHEETS (unaudited)

As at

($ millions)

		September 30,	December 31,
	Notes	2015	2014
Assets
Current Assets
Cash and Cash Equivalents		4,401	883
Accounts Receivable and Accrued Revenues		1,113	1,582
Income Tax Receivable		—	28
Inventories	8	1,132	1,224
Risk Management	20,21	294	478
Current Assets		6,940	4,195
Exploration and Evaluation Assets	1,9	1,725	1,625
Property, Plant and Equipment, Net	1,10	17,732	18,563
Risk Management	20,21	15	—
Other Assets		71	70
Goodwill	1	242	242
Total Assets		26,725	24,695
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		1,799	2,588
Income Tax Payable		134	357
Risk Management	20,21	7	12
Current Liabilities		1,940	2,957
Long-Term Debt	13	6,312	5,458
Risk Management	20,21	5	4
Decommissioning Liabilities	14	2,368	2,616
Other Liabilities		165	172
Deferred Income Taxes		2,922	3,302
Total Liabilities		13,712	14,509
Shareholders’ Equity		13,013	10,186
Total Liabilities and Shareholders’ Equity		26,725	24,695

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
Third Quarter 2015 Report	Consolidated Financial Statements

53

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (unaudited)

($ millions)

	Share Capital	Paid in Surplus	Retained Earnings		AOCI (1)	Total
	(Note 15)				(Note 16)
Balance as at December 31, 2013	3,857	4,219	1,660		210	9,946
Net Earnings	—	—	1,216		—	1,216
Other Comprehensive Income (Loss)	—	—	—		97	97
Total Comprehensive Income (Loss)	—	—	1,216		97	1,313
Common Shares Issued Under Stock Option Plans	32	—	—		—	32
Stock-Based Compensation Expense	—	56	—		—	56
Dividends on Common Shares	—	—	(604	)	—	(604	)
Balance as at September 30, 2014	3,889	4,275	2,272		307	10,743
Balance as at December 31, 2014	3,889	4,291	1,599		407	10,186
Net Earnings	—	—	1,259		—	1,259
Other Comprehensive Income (Loss)	—	—	—		468	468
Total Comprehensive Income (Loss)	—	—	1,259		468	1,727
Common Shares Issued for Cash	1,463	—	—		—	1,463
Common Shares Issued Pursuant to Dividend Reinvestment Plan	182	—	—		—	182
Common Shares Issued Under Stock Option Plans	—	—	—		—	—
Stock-Based Compensation Expense	—	33	—		—	33
Dividends on Common Shares	—	—	(578	)	—	(578	)
Balance as at September 30, 2015	5,534	4,324	2,280		875	13,013

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
Third Quarter 2015 Report	Consolidated Financial Statements

54

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

For the period ended September 30,

($ millions)

		Three Months Ended				Nine Months Ended
	Notes	2015		2014		2015		2014
Operating Activities
Net Earnings		1,801		354		1,259		1,216
Depreciation, Depletion and Amortization	10	473		475		1,455		1,415
Exploration Expense		—		—		21		1
Deferred Income Taxes	6	(228	)	144		(516	)	396
Unrealized (Gain) Loss on Risk Management	20	(127	)	(165	)	169		(180	)
Unrealized Foreign Exchange (Gain) Loss	5	457		259		878		221
(Gain) Loss on Divestiture of Assets	12	(2,379	)	(137	)	(2,395	)	(157	)
Current Tax on Divestiture of Assets	12	391		—		391		—
Unwinding of Discount on Decommissioning Liabilities	4,14	32		30		94		90
Other		24		25		60		76
		444		985		1,416		3,078
Net Change in Other Assets and Liabilities		(13	)	(28	)	(81	)	(97	)
Net Change in Non-Cash Working Capital		111		135		(183	)	(323	)
Cash From Operating Activities		542		1,092		1,152		2,658
Investing Activities
Capital Expenditures — Exploration and Evaluation Assets	9	(23	)	(55	)	(117	)	(198	)
Capital Expenditures — Property, Plant and Equipment	10	(378	)	(695	)	(1,170	)	(2,073	)
Acquisition	11	(80	)	—		(80	)	—
Proceeds From Divestiture of Assets	12	3,329		235		3,345		275
Current Tax on Divestiture of Assets	12	(391	)	—		(391	)	—
Net Change in Investments and Other		—		(2	)	—		(1,581	)
Net Change in Non-Cash Working Capital		(33	)	54		(230	)	25
Cash From (Used in) Investing Activities		2,424		(463	)	1,357		(3,552	)
Net Cash Provided (Used) Before Financing Activities		2,966		629		2,509		(894	)
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings		—		(32	)	(19	)	121
Common Shares Issued, Net of Issuance Costs	15	—		—		1,449		—
Common Shares Issued Under Stock Option Plans		—		2		—		28
Dividends Paid on Common Shares	7	(133	)	(201	)	(396	)	(604	)
Other		(1	)	(1	)	(2	)	(2	)
Cash From (Used in) Financing Activities		(134	)	(232	)	1,032		(457	)
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency		(21	)	(1	)	(23	)	55
Increase (Decrease) in Cash and Cash Equivalents		2,811		396		3,518		(1,296	)
Cash and Cash Equivalents, Beginning of Period		1,590		760		883		2,452
Cash and Cash Equivalents, End of Period		4,401		1,156		4,401		1,156

See accompanying Notes to Consolidated Financial Statements (unaudited).

Cenovus Energy Inc.
Third Quarter 2015 Report	Consolidated Financial Statements

55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

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

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

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

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

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

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

·Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, financing activities and research costs. As financial instruments are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments, recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventory.

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

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

56

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

A) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the three months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	756		1,343	396		804	2,242		3,144
Less: Royalties	7		62	28		62	—		—
	749		1,281	368		742	2,242		3,144
Expenses
Purchased Product	—		—	—		—	2,012		2,918
Transportation and Blending	431		518	52		74	—		—
Operating	133		153	132		176	215		162
Production and Mineral Taxes	—		—	5		12	—		—
(Gain) Loss on Risk Management	(144	)	2	(62	)	2	(14	)	(4	)
Operating Cash Flow	329		608	241		478	29		68
Depreciation, Depletion and Amortization	180		164	224		252	49		39
Exploration Expense	—		—	—		—	—		—
Segment Income (Loss)	149		444	17		226	(20	)	29

	Corporate and Eliminations				Consolidated
For the three months ended September 30,	2015		2014		2015		2014
Revenues
Gross Sales	(86	)	(197	)	3,308		5,094
Less: Royalties	—		—		35		124
	(86	)	(197	)	3,273		4,970
Expenses
Purchased Product	(86	)	(197	)	1,926		2,721
Transportation and Blending	—		—		483		592
Operating	(1	)	(1	)	479		490
Production and Mineral Taxes	—		—		5		12
(Gain) Loss on Risk Management	(127	)	(165	)	(347	)	(165	)
	128		166		727		1,320
Depreciation, Depletion and Amortization	20		20		473		475
Exploration Expense	—		—		—		—
Segment Income (Loss)	108		146		254		845
General and Administrative	75		80		75		80
Finance Costs	122		105		122		105
Interest Income	(6	)	(4	)	(6	)	(4	)
Foreign Exchange (Gain) Loss, Net	417		263		417		263
Research Costs	6		3		6		3
(Gain) Loss on Divestiture of Assets	(2,379	)	(137	)	(2,379	)	(137	)
Other (Income) Loss, Net	(1	)	2		(1	)	2
	(1,766	)	312		(1,766	)	312
Earnings Before Income Tax					2,020		533
Income Tax Expense					219		179
Net Earnings					1,801		354

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

57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

B) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the three months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	749		1,334	279		619	1,028		1,953
Less: Royalties	7		62	23		58	30		120
	742		1,272	256		561	998		1,833
Expenses
Transportation and Blending	431		518	49		69	480		587
Operating	128		147	90		124	218		271
Production and Mineral Taxes	—		—	4		10	4		10
(Gain) Loss on Risk Management	(143	)	2	(49	)	6	(192	)	8
Operating Cash Flow	326		605	162		352	488		957

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the three months ended September 30,	2015		2014	2015		2014		2015		2014
Revenues
Gross Sales	6		9	113		182		119		191
Less: Royalties	—		—	5		4		5		4
	6		9	108		178		114		187
Expenses
Transportation and Blending	—		—	3		5		3		5
Operating	4		4	41		51		45		55
Production and Mineral Taxes	—		—	1		2		1		2
(Gain) Loss on Risk Management	(1	)	—	(13	)	(4	)	(14	)	(4	)
Operating Cash Flow	3		5	76		124		79		129

	Other
	Oil Sands			Conventional		Total
For the three months ended September 30,	2015	2014		2015	2014	2015	2014
Revenues
Gross Sales	1	—		4	3	5	3
Less: Royalties	—	—		—	—	—	—
	1	—		4	3	5	3
Expenses
Transportation and Blending	—	—		—	—	—	—
Operating	1	2		1	1	2	3
Production and Mineral Taxes	—	—		—	—	—	—
(Gain) Loss on Risk Management	—	—		—	—	—	—
Operating Cash Flow	—	(2	)	3	2	3	—

	Total Upstream
	Oil Sands			Conventional			Total
For the three months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	756		1,343	396		804	1,152		2,147
Less: Royalties	7		62	28		62	35		124
	749		1,281	368		742	1,117		2,023
Expenses
Transportation and Blending	431		518	52		74	483		592
Operating	133		153	132		176	265		329
Production and Mineral Taxes	—		—	5		12	5		12
(Gain) Loss on Risk Management	(144	)	2	(62	)	2	(206	)	4
Operating Cash Flow	329		608	241		478	570		1,086

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

58

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

C) Geographic Information

	Canada				United States				Consolidated
For the three months ended September 30,	2015		2014		2015		2014		2015		2014
Revenues
Gross Sales	1,517		2,698		1,791		2,396		3,308		5,094
Less: Royalties	35		124		—		—		35		124
	1,482		2,574		1,791		2,396		3,273		4,970
Expenses
Purchased Product	351		542		1,575		2,179		1,926		2,721
Transportation and Blending	483		592		—		—		483		592
Operating	274		334		205		156		479		490
Production and Mineral Taxes	5		12		—		—		5		12
(Gain) Loss on Risk Management	(326	)	(154	)	(21	)	(11	)	(347	)	(165	)
	695		1,248		32		72		727		1,320
Depreciation, Depletion and Amortization	425		437		48		38		473		475
Exploration Expense	—		—		—		—		—		—
Segment Income (Loss)	270		811		(16	)	34		254		845

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

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

59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

D) Results of Operations — Segment and Operational Information

	Oil Sands			Conventional			Refining and Marketing
For the nine months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	2,379		3,972	1,358		2,568	6,775		9,885
Less: Royalties	26		181	86		184	—		—
	2,353		3,791	1,272		2,384	6,775		9,885
Expenses
Purchased Product	—		—	—		—	5,826		8,836
Transportation and Blending	1,337		1,637	172		263	—		—
Operating	405		502	433		557	552		525
Production and Mineral Taxes	—		—	16		36	—		—
(Gain) Loss on Risk Management	(252	)	59	(138	)	35	(27	)	(9	)
Operating Cash Flow	863		1,593	789		1,493	424		533
Depreciation, Depletion and Amortization	508		459	745		779	140		116
Exploration Expense	—		1	21		—	—		—
Segment Income (Loss)	355		1,133	23		714	284		417

	Corporate and Eliminations				Consolidated
For the nine months ended September 30,	2015		2014		2015		2014
Revenues
Gross Sales	(260	)	(656	)	10,252		15,769
Less: Royalties	—		—		112		365
	(260	)	(656	)	10,140		15,404
Expenses
Purchased Product	(260	)	(656	)	5,566		8,180
Transportation and Blending	—		—		1,509		1,900
Operating	(5	)	(4	)	1,385		1,580
Production and Mineral Taxes	—		—		16		36
(Gain) Loss on Risk Management	169		(180	)	(248	)	(95	)
	(164	)	184		1,912		3,803
Depreciation, Depletion and Amortization	62		61		1,455		1,415
Exploration Expense	—		—		21		1
Segment Income (Loss)	(226	)	123		436		2,387
General and Administrative	220		291		220		291
Finance Costs	359		337		359		337
Interest Income	(20	)	(31	)	(20	)	(31	)
Foreign Exchange (Gain) Loss, Net	832		223		832		223
Research Costs	20		9		20		9
(Gain) Loss on Divestiture of Assets	(2,395	)	(157	)	(2,395	)	(157	)
Other (Income) Loss, Net	1		—		1		—
	(983	)	672		(983	)	672
Earnings Before Income Tax					1,419		1,715
Income Tax Expense					160		499
Net Earnings					1,259		1,216

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

60

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

E) Financial Results by Upstream Product

	Crude Oil (1)
	Oil Sands			Conventional			Total
For the nine months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	2,356		3,909	1,000		1,978	3,356		5,887
Less: Royalties	26		180	78		174	104		354
	2,330		3,729	922		1,804	3,252		5,533
Expenses
Transportation and Blending	1,336		1,636	160		249	1,496		1,885
Operating	390		483	299		402	689		885
Production and Mineral Taxes	—		—	14		28	14		28
(Gain) Loss on Risk Management	(249	)	59	(100	)	38	(349	)	97
Operating Cash Flow	853		1,551	549		1,087	1,402		2,638

(1) Includes NGLs.

	Natural Gas
	Oil Sands			Conventional				Total
For the nine months ended September 30,	2015		2014	2015		2014		2015		2014
Revenues
Gross Sales	17		58	346		580		363		638
Less: Royalties	—		1	8		10		8		11
	17		57	338		570		355		627
Expenses
Transportation and Blending	1		1	12		14		13		15
Operating	12		13	131		152		143		165
Production and Mineral Taxes	—		—	2		8		2		8
(Gain) Loss on Risk Management	(3	)	—	(38	)	(3	)	(41	)	(3	)
Operating Cash Flow	7		43	231		399		238		442

	Other
	Oil Sands			Conventional		Total
For the nine months ended September 30,	2015	2014		2015	2014	2015	2014
Revenues
Gross Sales	6	5		12	10	18	15
Less: Royalties	—	—		—	—	—	—
	6	5		12	10	18	15
Expenses
Transportation and Blending	—	—		—	—	—	—
Operating	3	6		3	3	6	9
Production and Mineral Taxes	—	—		—	—	—	—
(Gain) Loss on Risk Management	—	—		—	—	—	—
Operating Cash Flow	3	(1	)	9	7	12	6

	Total Upstream
	Oil Sands			Conventional			Total
For the nine months ended September 30,	2015		2014	2015		2014	2015		2014
Revenues
Gross Sales	2,379		3,972	1,358		2,568	3,737		6,540
Less: Royalties	26		181	86		184	112		365
	2,353		3,791	1,272		2,384	3,625		6,175
Expenses
Transportation and Blending	1,337		1,637	172		263	1,509		1,900
Operating	405		502	433		557	838		1,059
Production and Mineral Taxes	—		—	16		36	16		36
(Gain) Loss on Risk Management	(252	)	59	(138	)	35	(390	)	94
Operating Cash Flow	863		1,593	789		1,493	1,652		3,086

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

61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

F) Geographic Information

	Canada				United States				Consolidated
For the nine months ended September 30,	2015		2014		2015		2014		2015		2014
Revenues
Gross Sales	5,009		8,335		5,243		7,434		10,252		15,769
Less: Royalties	112		365		—		—		112		365
	4,897		7,970		5,243		7,434		10,140		15,404
Expenses
Purchased Product	1,227		1,769		4,339		6,411		5,566		8,180
Transportation and Blending	1,509		1,900		—		—		1,509		1,900
Operating	858		1,077		527		503		1,385		1,580
Production and Mineral Taxes	16		36		—		—		16		36
(Gain) Loss on Risk Management	(227	)	(82	)	(21	)	(13	)	(248	)	(95	)
	1,514		3,270		398		533		1,912		3,803
Depreciation, Depletion and Amortization	1,316		1,300		139		115		1,455		1,415
Exploration Expense	21		1		—		—		21		1
Segment Income (Loss)	177		1,969		259		418		436		2,387

G) Joint Operations

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

FCCL, which is involved in the development and production of crude oil in Canada, is jointly controlled with ConocoPhillips and operated by Cenovus. WRB has two refineries in the U.S. and focuses on the refining of crude oil into petroleum and chemical products. WRB is jointly controlled with and operated by Phillips 66. Cenovus’s share of operating cash flow from FCCL and WRB for the three months ended September 30, 2015 was $196 million and $27 million, respectively (three months ended September 30, 2014 — $595 million and $67 million). Cenovus’s share of operating cash flow from FCCL and WRB for the nine months ended September 30, 2015 was $616 million and $411 million, respectively (nine months ended September 30, 2014 — $1,551 million and $535 million).

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

By Segment

	E&E (1)		PP&E (2)
	September 30,	December 31,	September 30,	December 31,
As at	2015	2014	2015	2014
Oil Sands	1,661	1,540	8,859	8,606
Conventional	64	85	4,337	6,038
Refining and Marketing	—	—	4,221	3,568
Corporate and Eliminations	—	—	315	351
Consolidated	1,725	1,625	17,732	18,563

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2015	2014	2015	2014
Oil Sands	242	242	11,175	11,024
Conventional	—	—	4,489	6,211
Refining and Marketing	—	—	5,867	5,520
Corporate and Eliminations	—	—	5,194	1,940
Consolidated	242	242	26,725	24,695

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

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

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

62

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

By Geographic Region

	E&E		PP&E
	September 30,	December 31,	September 30,	December 31,
As at	2015	2014	2015	2014
Canada	1,725	1,625	13,599	14,999
United States	—	—	4,133	3,564
Consolidated	1,725	1,625	17,732	18,563

	Goodwill		Total Assets
	September 30,	December 31,	September 30,	December 31,
As at	2015	2014	2015	2014
Canada	242	242	21,590	20,231
United States	—	—	5,135	4,464
Consolidated	242	242	26,725	24,695

I) Capital Expenditures (1)

	Three Months Ended		Nine Months Ended
For the period ended September 30,	2015	2014	2015	2014
Capital
Oil Sands	272	494	946	1,492
Conventional	55	198	157	621
Refining and Marketing	67	42	159	111
Corporate	6	16	24	41
	400	750	1,286	2,265
Acquisition Capital
Oil Sands (2)	—	—	—	15
Conventional	1	—	1	2
Refining and Marketing	83	—	83	—
	484	750	1,370	2,282

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

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

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

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

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

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

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

63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

3. RECENT ACCOUNTING PRONOUNCEMENTS

A) New and Amended Accounting Standards and Interpretations Adopted

There were no new or amended accounting standards or interpretations adopted during the nine months ended September 30, 2015.

B) New Accounting Standards and Interpretations not yet Adopted

Revenue Recognition

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

On September 11, 2015, the IASB published an amendment to IFRS 15, deferring the effective date of the standard by one year to annual periods beginning on or after January 1, 2018. Early adoption is still permitted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements.

Additional Standards

A description of additional accounting standards and interpretations that will be adopted by the Company in future periods can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2014.

4. FINANCE COSTS

	Three Months Ended		Nine Months Ended
For the period ended September 30,	2015	2014	2015	2014
Interest Expense – Short-Term Borrowings and Long-Term Debt	84	71	243	212
Interest Expense – Partnership Contribution Payable (1)	—	—	—	22
Unwinding of Discount on Decommissioning Liabilities (Note 14)	32	30	94	90
Other	6	4	22	13
	122	105	359	337

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

5. FOREIGN EXCHANGE (GAIN) LOSS, NET

	Three Months Ended			Nine Months Ended
For the period ended September 30,	2015		2014	2015		2014
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada	437		253	852		272
Other	20		6	26		(51	)
Unrealized Foreign Exchange (Gain) Loss	457		259	878		221
Realized Foreign Exchange (Gain) Loss	(40	)	4	(46	)	2
	417		263	832		223

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

64

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

6. INCOME TAXES

The provision for income taxes is:

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2015		2014		2015		2014
Current Tax
Canada	451		49		686		82
United States	(4	)	(14	)	(10	)	21
Total Current Tax Expense (Recovery)	447		35		676		103
Deferred Tax Expense (Recovery)	(228	)	144		(516	)	396
	219		179		160		499

In the third quarter of 2015, the Company recorded a deferred tax recovery of $385 million arising from an adjustment to the tax basis of the Company’s refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets.

In addition, the Alberta government enacted a two percent increase in the corporate income tax rate effective July 1, 2015. As a result, the Company’s deferred income tax liability increased by $158 million for the nine months ended September 30, 2015.

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

	Nine Months Ended
For the period ended September 30,	2015		2014
Earnings Before Income Tax	1,419		1,715
Canadian Statutory Rate	26.1	%	25.2	%
Expected Income Tax	370		431
Effect of Taxes Resulting From:
Foreign Tax Rate Differential	(15	)	18
Non-Deductible Stock-Based Compensation	7		15
Non-Taxable Capital Losses	113		33
Unrecognized Capital Losses Arising From Unrealized Foreign Exchange	113		33
Adjustments Arising From Prior Year Tax Filings	(13	)	—
Recognition of Capital Losses	(149	)	(6	)
Recognition of U.S. Tax Basis	(385	)	—
Change in Statutory Rate	158		—
Other	(39	)	(25	)
Total Tax	160		499
Effective Tax Rate	11.3	%	29.1	%

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

65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

7. PER SHARE AMOUNTS

A) Net Earnings Per Share

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2015		2014		2015		2014
Net Earnings — Basic and Diluted ($ millions)	1,801		354		1,259		1,216
Basic — Weighted Average Number of Shares (millions)	833.3		757.1		813.8		756.8
Dilutive Effect of Cenovus TSARs (1)	—		0.8		—		1.0
Dilutive Effect of Cenovus NSRs (2)	—		0.9		—		0.1
Diluted — Weighted Average Number of Shares	833.3		758.8		813.8		757.9
Net Earnings Per Common Share ($)
Basic	$	2.16	$	0.47	$	1.55	$	1.61
Diluted	$	2.16	$	0.47	$	1.55	$	1.60

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

(2) Net settlement rights (“NSRs”).

B) Dividends Per Share

For the three months ended September 30, 2015, the Company paid dividends of $0.16 per share (three months ended September 30, 2014 — $0.2662 per share). For the nine months ended September 30, 2015, the Company paid dividends of $578 million, including cash dividends of $396 million (nine months ended September 30, 2014 — $604 million, all of which was paid in cash). The Cenovus Board of Directors declared a fourth quarter dividend of $0.16 per share, payable on December 31, 2015, to common shareholders of record as of December 15, 2015. While the dividend reinvestment plan (“DRIP”) remains in place, the discount has been discontinued.

8. INVENTORIES

	September 30,	December 31,
As at	2015	2014
Product
Refining and Marketing	884	972
Oil Sands	188	182
Conventional	12	28
Parts and Supplies	48	42
	1,132	1,224

As a result of a decline in certain refined product prices, Cenovus recorded a write-down of its refined product inventory of $10 million from cost to net realizable value as at September 30, 2015. As at December 31, 2014, Cenovus recorded a write-down of its product inventory of $131 million.

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

66

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

9. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2013	1,473
Additions	279
Transfers to PP&E (Note 10)	(53	)
Exploration Expense	(86	)
Divestitures	(2	)
Change in Decommissioning Liabilities	14
As at December 31, 2014	1,625
Additions	117
Transfers to PP&E (Note 10)	(1	)
Exploration Expense	(21	)
Change in Decommissioning Liabilities	5
As at September 30, 2015	1,725

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

Additions to E&E assets for the nine months ended September 30, 2015 include $26 million of internal costs directly related to the evaluation of these projects (year ended December 31, 2014 — $51 million). No borrowing costs or costs classified as general and administrative expenses have been capitalized during the nine months ended September 30, 2015 (year ended December 31, 2014 — $nil).

For the nine months ended September 30, 2015, $1 million of E&E assets were transferred to PP&E following the determination of technical feasibility and commercial viability of the projects (year ended December 31, 2014 — $53 million).

Impairment

The impairment of E&E assets and any subsequent reversal of such impairment losses are recorded in exploration expense in the Consolidated Statements of Earnings and Comprehensive Income.

During the second quarter of 2015, $21 million of previously capitalized E&E costs related to exploration assets within the Saskatchewan cash-generating unit (“CGU”) were deemed not to be technically feasible and commercially viable, and were recorded as exploration expense in the Conventional segment.

For the year ended December 31, 2014, $82 million of previously capitalized E&E costs related to exploration assets within the Northern Alberta CGU were deemed not to be technically feasible and commercially viable, and were recorded as exploration expense in the Conventional segment. In addition, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense in the Oil Sands segment.

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

67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

10. PROPERTY, PLANT AND EQUIPMENT, NET

	Upstream Assets
	Development & Production		Other Upstream	Refining Equipment		Other (1)		Total
COST
As at December 31, 2013	29,390		286	3,654		849		34,179
Additions (2)	2,522		43	162		63		2,790
Transfers From E&E Assets (Note 9)	53		—	—		—		53
Transfers to Assets Held for Sale	(55	)	—	—		—		(55	)
Change in Decommissioning Liabilities	264		—	(3	)	—		261
Exchange Rate Movements and Other	1		—	338		—		339
Divestitures	(474	)	—	—		(2	)	(476	)
As at December 31, 2014	31,701		329	4,151		910		37,091
Additions	983		3	157		27		1,170
Acquisition (Note 11)	—		—	—		83		83
Transfers From E&E Assets (Note 9)	1		—	—		—		1
Change in Decommissioning Liabilities	(305	)	—	—		—		(305	)
Exchange Rate Movements and Other	—		—	647		—		647
Divestitures	(923	)	—	—		—		(923	)
As at September 30, 2015	31,457		332	4,955		1,020		37,764
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2013	15,791		193	386		475		16,845
Depreciation, Depletion and Amortization	1,602		40	156		83		1,881
Transfers to Assets Held for Sale	(27	)	—	—		—		(27	)
Impairment Losses	65		—	—		—		65
Exchange Rate Movements and Other	38		—	42		—		80
Divestitures	(316	)	—	—		—		(316	)
As at December 31, 2014	17,153		233	584		558		18,528
Depreciation, Depletion and Amortization	1,219		34	139		63		1,455
Exchange Rate Movements and Other	(1	)	—	96		(1	)	94
Divestitures	(45	)	—	—		—		(45	)
As at September 30, 2015	18,326		267	819		620		20,032
CARRYING VALUE
As at December 31, 2013	13,599		93	3,268		374		17,334
As at December 31, 2014	14,548		96	3,567		352		18,563
As at September 30, 2015	13,131		65	4,136		400		17,732

(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.

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

Additions to development and production assets include internal costs directly related to the development and construction of crude oil and natural gas properties of $128 million for the nine months ended September 30, 2015 (year ended December 31, 2014 — $216 million). All of the Company’s development and production assets are located within Canada. No borrowing costs or costs classified as general and administrative expenses have been capitalized during the nine months ended September 30, 2015 (year ended December 31, 2014 — $nil).

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

	September 30,	December 31,
As at	2015	2014
Development and Production	526	478
Refining Equipment	246	159
	772	637

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

68

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

Impairment

The impairment of PP&E and any subsequent reversal of such impairment losses are recorded in DD&A in the Consolidated Statements of Earnings and Comprehensive Income. There was no impairment of PP&E for the nine months ended September 30, 2015 (year ended December 31, 2014 — $65 million).

11. ACQUISITION

On August 31, 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of $75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million and working capital of $1 million. Transaction costs associated with the acquisition have been expensed. These assets, related liabilities and results of operations are reported in the Refining and Marketing segment.

12. DIVESTITURES

On July 29, 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP is a royalty business consisting of approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba. Cenovus entered into lease agreements with HRP on the fee lands from which it currently has working interest production. In addition, HRP has a Gross Overriding Royalty on production from Cenovus’s Pelican Lake and Weyburn assets. These assets, related liabilities and results of operations were reported in the Conventional segment.

The divestiture gave rise to a taxable gain for which the Company has recognized current tax expense of $391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture is specifically identifiable; therefore, it has been classified as an investing activity in the Consolidated Statements of Cash Flows.

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

In the third quarter of 2014, the Company completed the sale of certain Wainwright properties to a third party for net proceeds of $234 million, resulting in a gain of $137 million. These assets, related liabilities and results of operations were reported in the Conventional segment.

In the second quarter of 2014, the Company completed the sale of certain Bakken properties to a third party for net proceeds of $35 million, resulting in a gain of $16 million. The Company also completed the sale of certain non-core properties and recorded a total gain of $4 million. These assets, related liabilities and results of operations were reported in the Conventional segment.

13. LONG-TERM DEBT

		September 30,		December 31,
As at	US$ Principal	2015		2014
Revolving Term Debt (1)	—	—		—
U.S. Dollar Denominated Unsecured Notes	4,750	6,362		5,510
Total Debt Principal		6,362		5,510
Debt Discounts and Transaction Costs		(50	)	(52	)
		6,312		5,458

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

During the second quarter of 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. As at September 30, 2015, the Company had $4.0 billion available on its committed credit facility.

As at September 30, 2015, the Company is in compliance with all of the terms of its debt agreements.

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

69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

14. DECOMMISSIONING LIABILITIES

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

	September 30,		December 31,
As at	2015		2014
Decommissioning Liabilities, Beginning of Year	2,616		2,370
Liabilities Incurred	8		48
Liabilities Acquired	4		—
Liabilities Settled	(52	)	(93	)
Liabilities Divested	—		(60	)
Transfers and Reclassifications	—		(9	)
Change in Estimated Future Cash Flows	(8	)	115
Change in Discount Rate	(300	)	122
Unwinding of Discount on Decommissioning Liabilities	94		120
Foreign Currency Translation	6		3
Decommissioning Liabilities, End of Period	2,368		2,616

The undiscounted amount of estimated future cash flows required to settle the obligation has been discounted using a credit-adjusted risk-free rate of 5.6 percent as at September 30, 2015 (December 31, 2014 — 4.9 percent).

15. SHARE CAPITAL

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.

B) Issued and Outstanding

	September 30, 2015		December 31, 2014
As at	Number of Common Shares (Thousands)	Amount	Number of Common Shares (Thousands)	Amount
Outstanding, Beginning of Year	757,103	3,889	756,046	3,857
Common Shares Issued, Net of Issuance Costs	67,500	1,463	—	—
Common Shares Issued Pursuant to Dividend Reinvestment Plan	8,687	182	—	—
Common Shares Issued Under Stock Option Plans	—	—	1,057	32
Outstanding, End of Period	833,290	5,534	757,103	3,889

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

The Company has a DRIP, whereby holders of common shares may reinvest all or a portion of the cash dividends payable on their common shares in additional common shares. At the discretion of the Company, the additional common shares may be issued from treasury of the Company or purchased on the market. For the nine months ended September 30, 2015, the Company issued 8.7 million common shares from treasury under the DRIP.

There were no preferred shares outstanding as at September 30, 2015 (December 31, 2014 — nil).

As at September 30, 2015, there were 10 million (December 31, 2014 — 13 million) common shares available for future issuance under stock option plans.

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

70

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

16. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at September 30, 2015	Defined Benefit Plan		Foreign Currency Translation	Available for Sale Investments	Total
Balance, Beginning of Year	(30	)	427	10	407
Other Comprehensive Income (Loss), Before Tax	6		463	—	469
Income Tax	(1	)	—	—	(1	)
Balance, End of Period	(25	)	890	10	875

As at September 30, 2014	Defined Benefit Plan		Foreign Currency Translation	Available for Sale Investments	Total
Balance, Beginning of Year	(12	)	212	10	210
Other Comprehensive Income (Loss), Before Tax	(15	)	108	—	93
Income Tax	4		—	—	4
Balance, End of Period	(23	)	320	10	307

17. TERMINATION BENEFITS

In July 2015, in response to the low-price environment and to align with the Company’s more moderate growth plan, the Company announced plans to reduce its workforce. During the third quarter, employee termination benefits of $3 million were recorded as incurred, and included in general and administrative expense. It is estimated that additional termination benefits of $32 million will be incurred in the fourth quarter.

18. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Option Plan

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

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

As at September 30, 2015	Issued	Term (Years)	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price ($)	Closing Share Price ($)	Number of Units Outstanding (Thousands)
NSRs	On or After February 24, 2011	7	4.58	31.65	20.24	43,231
TSARs	On or After February 17, 2010	7	1.45	26.72	20.24	3,719

NSRs

The weighted average unit fair value of NSRs granted during the nine months ended September 30, 2015 was $3.58 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model.

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

71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

The following table summarizes information related to the NSRs:

As at September 30, 2015	Number of NSRs (Thousands)		Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	40,549		32.63
Granted	4,106		22.25
Exercised	—		—
Forfeited	(1,424	)	32.46
Outstanding, End of Period	43,231		31.65
Exercisable, End of Period	23,743		34.51

TSARs

The Company has recorded a liability of $2 million as at September 30, 2015 (December 31, 2014 — $8 million) in the Consolidated Balance Sheets based on the fair value of each TSAR held by Cenovus employees. The intrinsic value of vested TSARs held by Cenovus employees as at September 30, 2015 was $nil (December 31, 2014 — $nil).

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

As at September 30, 2015	Number of TSARs (Thousands)		Weighted Average Exercise Price ($)
Outstanding, Beginning of Year	3,862		26.72
Exercised for Cash Payment	—		—
Exercised as Options for Common Shares	—		—
Forfeited	(70	)	27.53
Expired	(73	)	25.89
Outstanding, End of Period	3,719		26.72
Exercisable, End of Period	3,719		26.72

B) Performance Share Units

The Company has recorded a liability of $66 million as at September 30, 2015 (December 31, 2014 — $109 million) in the Consolidated Balance Sheets for performance share units (“PSUs”) based on the market value of Cenovus’s common shares as at September 30, 2015. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at September 30, 2015 and December 31, 2014.

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

As at September 30, 2015	Number of PSUs (Thousands)
Outstanding, Beginning of Year	7,099
Granted	2,904
Vested and Paid Out	(1,436	)
Cancelled	(1,273	)
Units in Lieu of Dividends	217
Outstanding, End of Period	7,511

C) Restricted Share Units

Cenovus has granted restricted share units (“RSUs”) to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. RSUs vest after three years.

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

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

72

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

The Company has recorded a liability of $10 million as at September 30, 2015 (December 31, 2014 — $1 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares as at September 30, 2015. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at September 30, 2015 and December 31, 2014.

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

As at September 30, 2015	Number of RSUs (Thousands)
Outstanding, Beginning of Year	93
Granted	2,328
Vested and Paid Out	(22	)
Cancelled	(82	)
Units in Lieu of Dividends	81
Outstanding, End of Period	2,398

D) Deferred Share Units

The Company has recorded a liability of $30 million as at September 30, 2015 (December 31, 2014 — $31 million) in the Consolidated Balance Sheets for deferred share units (“DSUs”) based on the market value of Cenovus’s common shares as at September 30, 2015. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.

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

As at September 30, 2015	Number of DSUs (Thousands)
Outstanding, Beginning of Year	1,297
Granted to Directors	65
Granted From Annual Bonus Awards	55
Units in Lieu of Dividends	47
Redeemed	(5	)
Outstanding, End of Period	1,459

E) Total Stock-Based Compensation Expense (Recovery)

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

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2015		2014		2015		2014
NSRs	6		9		20		33
TSARs	(1	)	(7	)	(4	)	(3	)
PSUs	—		2		(7	)	49
RSUs	2		—		5		—
DSUs	2		(5	)	(1	)	2
Stock-Based Compensation Expense (Recovery)	9		(1	)	13		81

19. CAPITAL STRUCTURE

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

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

73

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

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

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

	September 30,		December 31,
As at	2015		2014
Long-Term Debt	6,312		5,458
Shareholders’ Equity	13,013		10,186
Capitalization	19,325		15,644
Debt to Capitalization	33	%	35	%

Cenovus continues to target a Debt to Adjusted EBITDA ratio of between 1.0 and 2.0 times over the long term. As at September 30, 2015, the Company’s Debt to Adjusted EBITDA ratio was above the target of 2.0 times; however, Cenovus believes it will return to the target range.

	September 30,		December 31,
As at	2015		2014
Debt	6,312		5,458
Adjusted EBITDA (1)
Net Earnings	787		744
Add (Deduct):
Finance Costs	467		445
Interest Income	(22	)	(33	)
Income Tax Expense	112		451
Depreciation, Depletion and Amortization	1,986		1,946
Goodwill Impairment	497		497
E&E Impairment	106		86
Unrealized (Gain) Loss on Risk Management	(247	)	(596	)
Foreign Exchange (Gain) Loss, Net	1,020		411
(Gain) Loss on Divestitures of Assets	(2,394	)	(156	)
Other (Income) Loss, Net	(3	)	(4	)
	2,309		3,791
Debt to Adjusted EBITDA	2.7x		1.4x

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

Cenovus will maintain a high level of capital discipline and manage its capital structure to ensure sufficient liquidity through all stages of the economic cycle. To manage its capital structure, Cenovus may adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit facilities or repay existing debt. It is Cenovus’s intention to maintain investment grade credit ratings.

During the second quarter of 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on November 30, 2017. As at September 30, 2015, Cenovus had $4.0 billion available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market conditions.

As at September 30, 2015, Cenovus is in compliance with all of the terms of its debt agreements.

20. FINANCIAL INSTRUMENTS

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

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

74

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

A) Fair Value of Non-Derivative Financial Instruments

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

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

Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at September 30, 2015, the carrying value of Cenovus’s long-term debt was $6,312 million and the fair value was $6,205 million (December 31, 2014 carrying value — $5,458 million, fair value — $5,726 million).

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

	September 30,	December 31,
As at	2015	2014
Fair Value, Beginning of Year	32	32
Acquisition of Investments	2	4
Reclassification of Equity Investments	—	(4	)
Fair Value, End of Period	34	32

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, natural gas and power purchase contracts. Crude oil and natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of power purchase contracts are calculated internally based on observable and unobservable inputs such as forward power prices in less active markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness. The forward prices used in the determination of the fair value of the power purchase contracts as at September 30, 2015 range from $34.00 to $42.75 per megawatt hour.

Summary of Unrealized Risk Management Positions

	September 30, 2015				December 31, 2014
	Risk Management				Risk Management
As at	Asset	Liability	Net		Asset	Liability	Net
Commodity Prices
Crude Oil	295	—	295		423	7	416
Natural Gas	14	—	14		55	—	55
Power	—	12	(12	)	—	9	(9	)
Total Fair Value	309	12	297		478	16	462

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

	September 30,		December 31,
As at	2015		2014
Prices Sourced From Observable Data or Market Corroboration (Level 2)	309		471
Prices Determined From Unobservable Inputs (Level 3)	(12	)	(9	)
	297		462

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

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

75

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

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

	2015		2014
Fair Value of Contracts, Beginning of Year	462		(129	)
Fair Value of Contracts Realized During the Period (1)	(417	)	85
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Period (2)	248		95
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts	4		(3	)
Fair Value of Contracts, End of Period	297		48

(1) Includes a realized loss of $7 million related to the power contracts (2014 — $2 million loss).

(2) Includes a decrease of $10 million related to the power contracts (2014 — $2 million decrease).

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

	Three Months Ended				Nine Months Ended
For the period ended September 30,	2015		2014		2015		2014
Realized (Gain) Loss (1)	(220	)	—		(417	)	85
Unrealized (Gain) Loss (2)	(127	)	(165	)	169		(180	)
(Gain) Loss on Risk Management	(347	)	(165	)	(248	)	(95	)

(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.

21. RISK MANAGEMENT

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

Net Fair Value of Commodity Price Positions

As at September 30, 2015	Notional Volumes	Terms	Average Price	Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price	18,000 bbls/d	January – December 2015	$113.75/bbl	79
Brent Fixed Price	8,000 bbls/d	October – December 2015	$82.59/bbl	12
Brent Fixed Price	18,000 bbls/d	October – December 2015	US$67.22/bbl	40
Brent Fixed Price	9,000 bbls/d	January – June 2016	$79.69/bbl	15
Brent Fixed Price	9,000 bbls/d	January – June 2016	US$69.63/bbl	38
Brent Fixed Price	10,000 bbls/d	January – December 2016	US$66.93/bbl	65
WCS Differential (1)	26,600 bbls/d	January – December 2016	US$(13.87)/bbl	2
Brent Collars	10,000 bbls/d	January – December 2015	$105.25 – $123.57/bbl	36
Other Financial Positions (2)				8
Crude Oil Fair Value Position				295
Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price	149 MMcf/d	January – December 2015	$3.86/Mcf	14
Natural Gas Fair Value Position				14
Power Purchase Contracts
Power Fair Value Position				(12	)

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

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

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

76

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

All amounts in $ millions, unless otherwise indicated

For the period ended September 30, 2015

Commodity Price Sensitivities — Risk Management Positions

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

Risk Management in Place as at September 30, 2015

Commodity	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$10 per bbl Applied to Brent, WTI and Condensate Hedges	(176	)	176
Crude Oil Differential Price	± US$5 per bbl Applied to Differential Hedges Tied to Production	65		(65	)
Natural Gas Commodity Price	± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges	(20	)	20
Power Commodity Price	± $25 per MWHr Applied to Power Hedge	19		(19	)

22. COMMITMENTS AND CONTINGENCIES

A) Commitments

Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, the Company has commitments related to its risk management program and an obligation to fund its defined benefit pension and other post-employment benefit plans. Additional information related to the Company’s commitments can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2014. In the third quarter, net transportation commitments of $92 million were assumed upon the acquisition of the Company’s crude-by-rail terminal. The Company did not enter into any other new material contracts for the nine months ended September 30, 2015.

B) Legal Proceedings

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

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

77

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics

($ millions, except per share amounts)

Revenues

	2015								2014
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Gross Sales
Upstream	3,737		1,152		1,410		1,175		8,261		1,721		6,540		2,147		2,295		2,098
Refining and Marketing	6,775		2,242		2,437		2,096		12,658		2,773		9,885		3,144		3,483		3,258
Corporate and Eliminations	(260	)	(86	)	(68	)	(106	)	(812	)	(156	)	(656	)	(197	)	(218	)	(241	)
Less: Royalties	112		35		53		24		465		100		365		124		138		103
Revenues	10,140		3,273		3,726		3,141		19,642		4,238		15,404		4,970		5,422		5,012

Operating Cash Flow

	2015				2014
	Year							Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4		to Date	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids
Foster Creek	380	167	129	84	965	228		737	297	227	213
Christina Lake	473	159	198	116	1,051	237		814	308	291	215
Conventional	549	162	221	166	1,360	273		1,087	352	388	347
Natural Gas	238	79	78	81	553	111		442	129	162	151
Other Upstream Operations	12	3	2	7	18	12		6	—	8	(2	)
	1,652	570	628	454	3,947	861		3,086	1,086	1,076	924
Refining and Marketing	424	29	300	95	211	(322	)	533	68	220	245
Operating Cash Flow (1)	2,076	599	928	549	4,158	539		3,619	1,154	1,296	1,169

Cash Flow

		2015								2014
		Year												Q3 Year
		to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Cash from Operating Activities		1,152		542		335		275		3,526		868		2,658		1,092		1,109		457
Deduct (Add Back):
Net Change in Other Assets and Liabilities		(81	)	(13	)	(14	)	(54	)	(135	)	(38	)	(97	)	(28	)	(27	)	(42	)
Net Change in Non-Cash Working Capital		(183	)	111		(128	)	(166	)	182		505		(323	)	135		(53	)	(405	)
Cash Flow (2)		1,416		444		477		495		3,479		401		3,078		985		1,189		904
Per Share	- Basic	1.74		0.53		0.58		0.64		4.60		0.53		4.07		1.30		1.57		1.20
	- Diluted	1.74		0.53		0.58		0.64		4.59		0.53		4.06		1.30		1.57		1.19

Earnings

		2015						2014
		Year									Q3 Year
		to Date	Q3		Q2	Q1		Year	Q4		to Date	Q3	Q2	Q1
Operating Earnings (Loss) (3)		35	(28	)	151	(88	)	633	(590	)	1,223	372	473	378
Per Share	- Diluted	0.04	(0.03	)	0.18	(0.11	)	0.84	(0.78	)	1.61	0.49	0.62	0.50
Net Earnings (Loss)		1,259	1,801		126	(668	)	744	(472	)	1,216	354	615	247
Per Share	- Basic	1.55	2.16		0.15	(0.86	)	0.98	(0.62	)	1.61	0.47	0.81	0.33
	- Diluted	1.55	2.16		0.15	(0.86	)	0.98	(0.62	)	1.60	0.47	0.81	0.33

Tax & Exchange Rates

	2015					2014
	Year								Q3 Year
	to Date		Q3	Q2	Q1	Year		Q4	to Date	Q3	Q2	Q1
Effective Tax Rates Using:
Net Earnings (4)	11.3	%				37.7	%
Operating Earnings, Excluding Divestitures	22.2	%				29.7	%
Canadian Statutory Rate (4)	26.1	%				25.2	%
U.S. Statutory Rate	38.1	%				38.1	%
Foreign Exchange Rates (US$ per C$1)
Average	0.794		0.764	0.813	0.806	0.905		0.881	0.914	0.918	0.917	0.906
Period End	0.747		0.747	0.802	0.789	0.862		0.862	0.892	0.892	0.937	0.905

(1)	Operating Cash Flow is a non-GAAP measure defined as revenues less purchased product, transportation and blending, operating expenses and production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Cash Flow.
(2)	Cash Flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows.
(3)	Operating Earnings (Loss) is a non-GAAP measure that is used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, gain on bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
(4)	On June 29, 2015, the Alberta government enacted a two percent increase in the corporate income tax rate. The rate increase is effective July 1, 2015.

Financial Metrics (Non-GAAP measures)

	2015								2014
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Debt to Capitalization (1) (2)	33	%	33	%	35	%	35	%	35	%	35	%	33	%	33	%	33	%	36	%
Net Debt to Capitalization (3) (4)	13	%	13	%	28	%	27	%	31	%	31	%	28	%	28	%	30	%	32	%
Debt to Adjusted EBITDA (2) (5)	2.7	x	2.7	x	2.1	x	1.9	x	1.4	x	1.4	x	1.3	x	1.3	x	1.2	x	1.4	x
Net Debt to Adjusted EBITDA (3) (5)	0.8	x	0.8	x	1.5	x	1.3	x	1.2	x	1.2	x	1.0	x	1.0	x	1.1	x	1.2	x
Return on Capital Employed (6)	6	%	6	%	(3	)%	0	%	6	%	6	%	9	%	9	%	9	%	7	%
Return on Common Equity (7)	7	%	7	%	(6	)%	(2	)%	7	%	7	%	11	%	11	%	12	%	7	%

(1)	Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity.
(2)	Debt includes the Company’s short-term borrowings and the current and long-term portions of long-term debt.
(3)	Net debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents.
(4)	Net debt to capitalization is defined as net debt divided by net debt plus shareholders’ equity.
(5)	Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, asset impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-month basis.
(6)	Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders’ equity plus average debt.
(7)	Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders’ equity.

Cenovus Energy Inc.
Third Quarter 2015 Report	Supplemental Information

78

SUPPLEMENTAL INFORMATION (unaudited)

Financial Statistics (continued)

Common Share Information

	2015				2014
	Year						Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4	to Date	Q3	Q2	Q1
Common Shares Outstanding (millions)
Period End	833.3	833.3	833.3	828.5	757.1	757.1	757.1	757.1	757.0	756.9
Average - Basic	813.8	833.3	828.6	778.9	756.9	757.1	756.8	757.1	756.9	756.4
Average - Diluted	813.8	833.3	828.6	778.9	757.6	757.1	757.9	758.8	758.0	757.3
Price Range ($ per share)
TSX - C$
High	26.42	20.91	24.28	26.42	34.79	30.13	34.79	34.79	34.70	32.02
Low	15.75	15.75	19.53	20.45	18.72	18.72	28.25	29.77	30.80	28.25
Close	20.24	20.24	19.98	21.35	23.97	23.97	30.13	30.13	34.59	31.97
NYSE - US$
High	21.12	15.97	19.72	21.12	32.64	26.89	32.64	32.64	32.44	28.96
Low	11.85	11.85	15.69	16.29	16.11	16.11	25.52	26.57	28.35	25.52
Close	15.16	15.16	16.01	16.88	20.62	20.62	26.88	26.88	32.37	28.96
Dividends ($ per share)	0.6924	0.1600	0.2662	0.2662	1.0648	0.2662	0.7986	0.2662	0.2662	0.2662
Share Volume Traded (millions)	1,314.1	483.3	388.7	442.1	803.8	333.1	470.7	147.7	152.7	170.3

Net Capital Investment

	2015							2014
	Year											Q3 Year
	to Date		Q3		Q2	Q1		Year		Q4		to Date		Q3		Q2		Q1
Capital Investment ($ millions)
Oil Sands
Foster Creek	318		96		73	149		796		159		637		207		209		221
Christina Lake	515		147		161	207		794		231		563		198		183		182
Total	833		243		234	356		1,590		390		1,200		405		392		403
Other Oil Sands	113		29		26	58		396		104		292		89		79		124
	946		272		260	414		1,986		494		1,492		494		471		527
Conventional	157		55		36	66		840		219		621		198		153		270
Refining and Marketing	159		67		48	44		163		52		111		42		46		23
Corporate	24		6		13	5		62		21		41		16		16		9
Capital Investment	1,286		400		357	529		3,051		786		2,265		750		686		829
Acquisitions (1)	84		84		—	—		18		1		17		—		16		1
Divestitures	(3,345	)	(3,329	)	—	(16	)	(277	)	(1	)	(276	)	(235	)	(39	)	(2	)
Net Acquisition and Divestiture Activity	(3,261	)	(3,245	)	—	(16	)	(259	)	—		(259	)	(235	)	(23	)	(1	)
Net Capital Investment	(1,975	)	(2,845	)	357	513		2,792		786		2,006		515		663		828

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

Operating Statistics - Before Royalties

Upstream Production Volumes

	2015				2014
	Year						Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4	to Date	Q3	Q2	Q1
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands
Foster Creek	65,906	71,414	58,363	67,901	59,172	68,377	56,070	56,631	56,852	54,706
Christina Lake	74,720	75,329	72,371	76,471	69,023	73,836	67,400	68,458	67,975	65,738
	140,626	146,743	130,734	144,372	128,195	142,213	123,470	125,089	124,827	120,444
Conventional
Heavy Oil	35,739	33,997	36,099	37,155	39,546	38,021	40,060	39,096	40,304	40,799
Light and Medium Oil	31,787	28,491	31,809	35,135	34,531	34,661	34,488	33,548	35,329	34,598
Natural Gas Liquids (1)	1,286	1,191	1,312	1,358	1,221	1,282	1,200	1,356	1,228	1,013
	68,812	63,679	69,220	73,648	75,298	73,964	75,748	74,000	76,861	76,410
Total Crude Oil and Natural Gas Liquids	209,438	210,422	199,954	218,020	203,493	216,177	199,218	199,089	201,688	196,854
Natural Gas (MMcf/d)
Oil Sands	20	19	21	20	22	22	22	23	23	19
Conventional	427	411	429	442	466	457	469	466	484	457
Total Natural Gas	447	430	450	462	488	479	491	489	507	476
Total Production (BOE/d)	283,938	282,089	274,954	295,020	284,826	296,010	281,051	280,589	286,188	276,187

(1) Natural gas liquids include condensate volumes.

Average Royalty Rates

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

	2015								2014
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Oil Sands
Foster Creek (1)	2.1	%	0.8	%	5.0	%	(1.2	)%	8.8	%	11.2	%	8.2	%	7.2	%	9.3	%	8.1	%
Christina Lake	3.0	%	3.7	%	2.5	%	3.1	%	7.5	%	7.2	%	7.6	%	7.9	%	7.7	%	7.1	%
Conventional
Pelican Lake	9.2	%	4.7	%	14.3	%	6.0	%	7.5	%	8.4	%	7.3	%	7.1	%	8.0	%	6.9	%
Weyburn	17.9	%	18.7	%	18.4	%	16.5	%	21.9	%	19.0	%	22.6	%	24.0	%	24.4	%	19.4	%
Other	3.8	%	8.2	%	1.2	%	3.5	%	5.9	%	6.7	%	5.6	%	6.5	%	5.5	%	4.9	%
Natural Gas Liquids	3.4	%	7.1	%	2.2	%	2.3	%	2.1	%	2.6	%	2.0	%	1.6	%	2.2	%	2.2	%
Natural Gas	2.2	%	3.7	%	1.2	%	1.6	%	1.9	%	2.5	%	1.8	%	2.0	%	2.0	%	1.4	%

(1) In Q1 2015, regulatory approval was received to include certain capital costs incurred in previous years in the royalty calculation which has resulted in a negative rate. Excluding the credit, the Q1 2015 and year-to-date royalty rate would have been 5.9 percent and 3.6 percent, respectively.

Cenovus Energy Inc.
Third Quarter 2015 Report	Supplemental Information

79

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Refining

	2015								2014
	Year												Q3 Year
	to Date		Q3		Q2		Q1		Year		Q4		to Date		Q3		Q2		Q1
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d)	460		460		460		460		460		460		460		460		460		460
Crude Oil Runs (Mbbls/d)	424		394		441		439		423		420		424		407		466		400
Heavy Oil	202		186		200		220		199		179		205		201		221		195
Light/Medium	222		208		241		219		224		241		219		206		245		205
Crude Utilization	92	%	86	%	96	%	95	%	92	%	91	%	92	%	88	%	101	%	87	%
Refined Products (Mbbls/d)	448		414		462		469		445		442		446		429		489		420

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

Selected Average Benchmark Prices

	2015				2014
	Year						Q3 Year
	to Date	Q3	Q2	Q1	Year	Q4	to Date		Q3	Q2		Q1
Crude Oil Prices (US$/bbl)
Brent	56.61	51.17	63.50	55.17	99.51	76.98	107.02		103.39	109.77		107.90
West Texas Intermediate (“WTI”)	51.00	46.43	57.94	48.63	93.00	73.15	99.61		97.17	102.99		98.68
Differential Brent - WTI	5.61	4.74	5.56	6.54	6.51	3.83	7.41		6.22	6.78		9.22
Western Canadian Select (“WCS”)	37.80	33.16	46.35	33.90	73.60	58.91	78.49		76.99	82.95		75.55
Differential WTI - WCS	13.20	13.27	11.59	14.73	19.40	14.24	21.12		20.18	20.04		23.13
Condensate (C5 @ Edmonton)	49.25	44.21	57.94	45.62	92.95	70.57	100.41		93.45	105.15		102.64
Differential WTI - Condensate (Premium)/Discount	1.75	2.22	—	3.01	0.05	2.58	(0.80	)	3.72	(2.16	)	(3.96	)
Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl)
Chicago	20.66	24.67	20.77	16.53	17.61	14.60	18.61		17.57	19.72		18.55
Group 3	19.61	22.03	19.34	17.46	16.27	13.28	17.27		16.65	17.75		17.41
Natural Gas Prices
AECO (C$/Mcf)	2.81	2.80	2.67	2.95	4.42	4.01	4.55		4.22	4.67		4.76
NYMEX (US$/Mcf)	2.80	2.77	2.64	2.98	4.42	4.00	4.56		4.06	4.67		4.94
Differential NYMEX - AECO (US$/Mcf)	0.56	0.61	0.50	0.57	0.40	0.44	0.39		0.16	0.40		0.60

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

Per-unit Results

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

	2015					2014
	Year							Q3 Year
	to Date	Q3	Q2	Q1		Year	Q4	to Date	Q3	Q2	Q1
Heavy Oil - Foster Creek (1) (2) ($/bbl)
Price	36.58	33.35	48.25	29.42		69.43	51.95	76.05	76.82	79.77	71.44
Royalties	0.59	0.20	1.97	(0.25	)	5.95	5.67	6.06	5.40	7.14	5.71
Transportation and Blending	8.95	8.50	9.04	9.39		1.98	1.85	2.02	2.17	3.10	0.78
Operating	13.00	11.37	13.47	14.48		16.55	13.65	17.65	14.79	19.38	19.09
Netback	14.04	13.28	23.77	5.80		44.95	30.78	50.32	54.46	50.15	45.86
Heavy Oil - Christina Lake (1) (2) ($/bbl)
Price	30.92	27.46	43.36	23.30		61.57	47.21	66.69	67.62	72.25	59.89
Royalties	0.80	0.83	0.99	0.61		4.40	3.14	4.84	5.07	5.37	4.04
Transportation and Blending	4.49	5.00	4.29	4.17		3.53	4.14	3.32	3.75	3.14	3.02
Operating	8.13	7.87	8.32	8.22		11.20	9.31	11.87	10.40	12.08	13.30
Netback	17.50	13.76	29.76	10.30		42.44	30.62	46.66	48.40	51.66	39.53
Total Heavy Oil - Oil Sands (1) (2) ($/bbl)
Price	33.56	30.35	45.61	26.04		65.18	49.44	70.96	71.82	75.65	65.19
Royalties	0.70	0.52	1.44	0.22		5.11	4.33	5.40	5.22	6.17	4.80
Transportation and Blending	6.57	6.72	6.48	6.50		2.82	3.06	2.73	3.03	3.12	1.99
Operating	10.39	9.55	10.74	10.97		13.66	11.35	14.51	12.41	15.38	15.96
Netback	15.90	13.56	26.95	8.35		43.59	30.70	48.32	51.16	50.98	42.44
Heavy Oil - Conventional (1) (2) ($/bbl)
Price	42.01	37.09	52.63	35.85		76.25	60.25	81.05	81.30	83.29	78.52
Royalties	3.18	1.73	5.34	2.34		7.09	6.85	7.16	7.72	7.76	6.01
Transportation and Blending	3.29	3.36	3.09	3.42		3.29	3.22	3.31	3.40	3.44	3.09
Operating	16.21	15.75	15.62	17.21		20.74	18.24	21.49	20.02	20.66	23.73
Production and Mineral Taxes	0.06	0.07	0.08	0.02		0.18	0.03	0.23	0.24	0.32	0.13
Netback	19.27	16.18	28.50	12.86		44.95	31.91	48.86	49.92	51.11	45.56
Total Heavy Oil (1) (2) ($/bbl)
Price	35.35	31.63	47.24	28.15		67.83	51.74	73.47	73.99	77.63	68.64
Royalties	1.23	0.75	2.35	0.68		5.59	4.87	5.84	5.79	6.58	5.12
Transportation and Blending	5.88	6.08	5.69	5.83		2.93	3.09	2.87	3.11	3.20	2.28
Operating	11.62	10.72	11.87	12.32		15.35	12.82	16.24	14.15	16.75	17.97
Production and Mineral Taxes	0.01	0.01	0.02	—		0.04	0.01	0.06	0.05	0.08	0.03
Netback	16.61	14.07	27.31	9.32		43.92	30.95	48.46	50.89	51.02	43.24
Light and Medium Oil ($/bbl)
Price	52.13	49.57	61.66	45.81		88.30	71.10	94.16	89.85	98.27	94.18
Royalties	5.30	7.02	5.67	3.56		9.15	6.12	10.19	10.36	11.37	8.78
Transportation and Blending	2.94	2.88	3.06	2.88		3.34	2.89	3.49	3.06	3.31	4.11
Operating	16.06	16.09	16.19	15.91		17.28	15.84	17.77	17.40	17.45	18.47
Production and Mineral Taxes	1.60	1.60	1.95	1.28		2.70	2.59	2.74	2.99	2.97	2.23
Netback	26.23	21.98	34.79	22.18		55.83	43.66	59.97	56.04	63.17	60.59

(1)	The netbacks do not reflect non-cash write-downs of product inventory.
(2)	Heavy oil price, and transportation and blending costs exclude the costs of purchased condensate, which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of condensate is as follows:

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

Foster Creek	27.94	24.20	29.82	30.57	42.01	35.45	44.49	38.50	47.28	48.35
Christina Lake	30.23	26.42	32.90	31.60	45.45	38.23	48.02	42.57	49.30	52.81
Heavy Oil - Oil Sands	29.17	25.33	31.48	31.14	43.87	36.92	46.41	40.71	48.39	50.77
Heavy Oil - Conventional	11.21	9.56	12.42	11.50	15.71	13.98	16.23	13.25	17.70	17.56
Total Heavy Oil	25.37	22.34	27.06	26.91	37.13	32.04	38.91	34.42	40.44	42.17

Cenovus Energy Inc.
Third Quarter 2015 Report	Supplemental Information

80

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties (continued)

Per-unit Results

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

	2015					2014
	Year								Q3 Year
	to Date	Q3	Q2	Q1		Year	Q4		to Date		Q3		Q2		Q1
Total Crude Oil (1) ($/bbl)
Price	37.94	34.08	49.55	31.09		71.39	55.05		77.08		76.64		81.35		73.15
Royalties	1.85	1.60	2.88	1.16		6.21	5.08		6.60		6.56		7.45		5.76
Transportation and Blending	5.42	5.64	5.27	5.34		3.00	3.06		2.98		3.10		3.22		2.60
Operating	12.31	11.46	12.56	12.91		15.69	13.34		16.51		14.70		16.87		18.06
Production and Mineral Taxes	0.26	0.23	0.33	0.22		0.50	0.45		0.52		0.54		0.60		0.42
Netback	18.10	15.15	28.51	11.46		45.99	33.12		50.47		51.74		53.21		46.31
Natural Gas Liquids ($/bbl)
Price	31.07	24.57	39.64	28.51		65.55	50.82		70.85		66.70		78.38		67.31
Royalties	1.07	1.75	0.87	0.66		1.38	1.34		1.40		1.07		1.70		1.48
Netback	30.00	22.82	38.77	27.85		64.17	49.48		69.45		65.63		76.68		65.83
Total Liquids (1) ($/bbl)
Price	37.90	34.03	49.48	31.08		71.35	55.02		77.04		76.57		81.33		73.12
Royalties	1.85	1.60	2.86	1.16		6.18	5.06		6.56		6.52		7.41		5.74
Transportation and Blending	5.39	5.61	5.24	5.31		2.98	3.04		2.96		3.08		3.20		2.59
Operating	12.23	11.39	12.48	12.83		15.59	13.25		16.41		14.60		16.77		17.96
Production and Mineral Taxes	0.25	0.23	0.33	0.22		0.50	0.44		0.52		0.54		0.60		0.42
Netback	18.18	15.20	28.57	11.56		46.10	33.23		50.59		51.83		53.35		46.41
Total Natural Gas ($/Mcf)
Price	2.96	3.00	2.82	3.05		4.37	3.89		4.52		4.22		4.87		4.47
Royalties	0.06	0.11	0.03	0.05		0.08	0.09		0.08		0.08		0.09		0.06
Transportation and Blending	0.11	0.10	0.10	0.12		0.12	0.13		0.11		0.11		0.11		0.11
Operating	1.19	1.16	1.15	1.26		1.23	1.21		1.24		1.24		1.23		1.26
Production and Mineral Taxes	0.01	0.01	0.02	0.01		0.05	0.03		0.06		0.05		0.13		(0.01	)
Netback	1.59	1.62	1.52	1.61		2.89	2.43		3.03		2.74		3.31		3.05
Total (1) (2) ($/BOE)
Price	32.58	29.95	40.50	27.73		58.29	46.14		62.45		61.85		65.71		59.68
Royalties	1.46	1.36	2.13	0.93		4.53	3.80		4.79		4.79		5.36		4.19
Transportation and Blending	4.14	4.35	3.95	4.11		2.32	2.40		2.29		2.39		2.45		2.03
Operating	10.89	10.27	10.94	11.44		13.22	11.57		13.79		12.53		13.95		14.94
Production and Mineral Taxes	0.21	0.19	0.27	0.17		0.44	0.36		0.47		0.48		0.65		0.28
Netback	15.88	13.78	23.21	11.08		37.78	28.01		41.11		41.66		43.30		38.24
Impact of Long-Term Incentives Costs (Recovery) on Total Operating Costs ($/BOE)	0.06	0.09	0.16	(0.05	)	0.16	(0.09	)	0.24		0.08		0.36		0.29
Impact of Realized Gain (Loss) on Risk Management
Liquids ($/bbl)	6.25	10.07	1.75	6.58		0.50	7.06		(1.78	)	(0.45	)	(2.94	)	(2.00	)
Natural Gas ($/Mcf)	0.35	0.37	0.39	0.29		0.04	0.05		0.03		0.11		(0.02	)	—
Total (2) ($/BOE)	5.15	8.07	1.92	5.31		0.42	5.17		(1.21	)	(0.13	)	(2.09	)	(1.42	)

(1)

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

(2)

Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) to one barrel (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. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

Cenovus Energy Inc.
Third Quarter 2015 Report	Supplemental Information

81

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 for 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. Cash flow is a 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.

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

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

·Debt to capitalization, net debt to capitalization, debt to adjusted EBITDA and net debt to adjusted EBITDA are 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. Net debt is defined as debt net of cash and cash equivalents. Capitalization is defined as debt plus shareholders’ equity. Net debt to capitalization is defined as net debt divided by net debt plus shareholders’ equity. Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, goodwill and asset impairments, unrealized gains or losses on risk management, foreign exchange gains or losses, gains or losses on divestiture of assets and other income and loss, calculated on a trailing 12-month basis.

These measures do not have a standardized meaning as prescribed by International Financial Reporting Standards (IFRS) 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 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. This information should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. For further information, refer to Cenovus’s third quarter 2015 Management’s Discussion & Analysis (MD&A) available at cenovus.com.

OIL AND GAS INFORMATION

Netbacks reported in this quarterly report are calculated as set out in the Annual Information Form (AIF). Heavy oil prices and transportation and blending costs exclude the costs of purchased condensate, which is blended with heavy oil. For the third quarter of 2015, the cost of condensate on a per barrel of unblended crude oil basis was as follows: Christina Lake - $26.42 and Foster Creek - $24.20.

Cenovus Energy Inc.
Third Quarter 2015 Report	Advisory

82

FORWARD-LOOKING INFORMATION

This document contains certain forward-looking statements and other information (collectively “forward-looking information”) about Cenovus’s current expectations, estimates and projections, made in light of the company’s experience and perception of historical trends. Forward-looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast” or “F”, “target”, “projected”, “future”, “guidance”, “could”, “should”, “focus”, “position”, “on track”, “proposed”, “schedule”, “potential”, “capacity”, “may”, “strategy”, “opportunities”, “priority”, “outlook” or similar expressions and includes suggestions of future outcomes, including statements about: the strength of the company’s position under various potential conditions to fund its planned capital programs and current dividend level; potential resumption of investment in certain projects; adequacy of the company’s liquidity to manage through the current low-price environment; growth strategy and related schedules, including priorities and focus; projections contained in the company’s updated 2015 guidance; forecast operating and financial results; planned capital expenditures, capital investment priorities and expected conditions for future capital investments; project capacities; expected future production, including the timing, stability or growth thereof; improving cost structures, including cost reduction targets, and the expected timing, sustainability and potential impacts of anticipated cost savings; the expected timing and potential impacts of the company’s transition to a new functional model; acquisition and disposition strategy; forecast natural gas use at operations; expected SOR; broadening market access and potential impacts thereof, including with respect to shareholder returns; expected increase in production capacity through optimization activity and expansion projects; dividend plans and dividend strategy, including with respect to the dividend reinvestment plan; forecasted commodity prices; targeted future debt to capitalization ratio and debt to adjusted EBITDA; and projected shareholder value. Readers are cautioned not to place undue reliance on forward-looking information, as the company’s actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally.

The factors or assumptions on which the forward-looking information is based include: assumptions disclosed in Cenovus’s current guidance, available at cenovus.com; the company’s projected capital investment levels, the flexibility of the company’s capital spending plans and the associated source of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; the company’s ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; the company’s ability to generate sufficient cash flow to meet its current and future obligations; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2015 guidance assumes: an average diluted number of shares outstanding of approximately 819 million and 833 million for 2015 and the fourth quarter of 2015, respectively; Brent of US$54.75/bbl; WTI of US$49.70/bbl; WCS of US$36.30/bbl; NYMEX of US$2.75/MMBtu; AECO of $2.65/GJ; Chicago 3-2-1 crack spread of US$18.10/bbl; and an exchange rate of $0.78 US$/C$.

The risk factors and uncertainties that could cause Cenovus’s actual results to differ materially include: volatility of and assumptions regarding oil and natural gas prices; the effectiveness of the company’s risk management program, including the impact of derivative financial instruments, the success of the company’s hedging strategies and the sufficiency of its liquidity position; the accuracy of cost estimates; fluctuations in commodity prices, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in Cenovus’s marketing operations, including credit risks; risks inherent to operation of the company’s crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of debt to adjusted EBITDA, net debt to adjusted EBITDA, debt to capitalization and net debt to capitalization; ability to access various sources of debt and equity capital, generally, and on terms acceptable to Cenovus; changes in credit ratings applicable to Cenovus or any of its securities; changes to Cenovus’s dividend plans or strategy, including the dividend reinvestment plan; accuracy of Cenovus’s reserves, resources and future production estimates; ability to replace and expand oil and gas reserves; ability to maintain the company’s relationships with its partners and to successfully manage and operate its integrated heavy oil business; reliability of the company’s assets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; refining and marketing margins; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected

Cenovus Energy Inc.
Third Quarter 2015 Report	Advisory

83

difficulties in producing, transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to Cenovus’s business; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation, including sufficient crude-by-rail or other alternate transportation; changes in the regulatory framework in any of the locations in which Cenovus operates, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on Cenovus’s business, its financial results and its consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which Cenovus operates; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against Cenovus.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of Cenovus’s material risk factors, see “Risk Factors” in our AIF or Form 40-F for the year ended December 31, 2014 and “Risk Management” in our current and annual Management’s Discussion and Analysis (MD&A), available on SEDAR at sedar.com, EDGAR at sec.gov and on the company’s website at cenovus.com.

ABBREVIATIONS

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

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

Cenovus Energy Inc.
Third Quarter 2015 Report	Advisory

84

Cenovus Energy Inc.

500 Centre Street SE

PO Box 766

Calgary, AB T2P 0M5

Phone: 403-766-2000

Fax: 403-766-7600

CENOVUS CONTACTS
Investor Relations:	Media:
Kam Sandhar	General media line
Director, Investor Relations	403-766-7751
403-766-5883	media.relations@cenovus.com
kam.sandhar@cenovus.com
Graham Ingram
Manager, Investor Relations
403-766-2849
graham.ingram@cenovus.com
Steve Murray
Senior Analyst, Investor Relations
403-766-3382
steven.murray@cenovus.com

cenovus.com