Exhibit 99.2

Management’s Discussion and Analysis

For the PERIOD ended September 30, 2018

OVERVIEW OF CENOVUS	2
QUARTERLY HIGHLIGHTS	3
OPERATING RESULTS	4
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	6
FINANCIAL RESULTS	9
REPORTABLE SEGMENTS	15
OIL SANDS	16
DEEP BASIN	23
REFINING AND MARKETING	26
CORPORATE AND ELIMINATIONS	28
DISCONTINUED OPERATIONS	30
LIQUIDITY AND CAPITAL RESOURCES	31
RISK MANAGEMENT AND RISK FACTORS	34
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	35
CONTROL ENVIRONMENT	36
OUTLOOK	37
ADVISORY	39
ABBREVIATIONS	41
NETBACK RECONCILIATIONS	42

This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”, or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated October 30, 2018, should be read in conjunction with our September 30, 2018 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2017 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2017 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of October 30, 2018, 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 (“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, on 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 and Additional Subtotals

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow, Operating Earnings, Free Funds Flow, Debt, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found in Notes 1 and 9 of our interim Consolidated Financial Statements. 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, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating Results, Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A.

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	Q3 2018 Management’s Discussion and Analysis

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, 2018 we had an enterprise value of approximately $24 billion. Operations include oil sands projects in northeast Alberta and established crude oil, natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our upstream assets averaged nearly 496,000 BOE per day for the three months ended September 30, 2018. We also conduct marketing activities and have refining operations in the United States (“U.S.”). The refining operations processed an average of 492,000 gross barrels per day of crude oil feedstock into an average of 518,000 gross barrels per day of refined products in the three months ended September 30, 2018.

Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle. We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage.

Our Operations

Oil Sands

Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northeast Alberta, including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the Athabasca region of northeastern Alberta. Our project at Telephone Lake is located within the Borealis region of northeastern Alberta.

Deep Basin

Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil assets located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities (collectively, the “Deep Basin Assets”). The Deep Basin Assets were acquired from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) in conjunction with the remaining 50 percent interest in the FCCL Partnership (“FCCL”) on May 17, 2017 (“the Acquisition”). The Deep Basin Assets provide short‑cycle development opportunities with high return potential that complement our long-term oil sands development. A portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining operations.

Refining and Marketing

Our operations include two refineries located in the U.S. in Illinois and Texas that are jointly owned with (50 percent interest) and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River refinery and Borger refinery (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day, respectively. This includes processing capability of up to 255,000 gross barrels per day of blended heavy crude oil. The 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 light/heavy crude oil price 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.

Operating Margin Net of Related Capital Investment

Nine Months Ended September 30, 2018 ($ millions)	Oil Sands		Deep Basin		Refining and Marketing
Operating Margin		1,264		250		745
Capital Investment		718		193		147
Operating Margin Net of Related Capital Investment		546		57		598

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	Q3 2018 Management’s Discussion and Analysis

QUARTERLY HIGHLIGHTS

Cenovus delivered very strong operational performance during the third quarter and continued to make progress on deleveraging the balance sheet. Production from continuing operations averaged 495,592 BOE per day, a four percent increase from the third quarter of 2017. Oil sands production in the quarter returned to normal levels following increased production well rates in the second quarter due to our decision to restrict production well rates earlier in the year in response to pipeline capacity constraints and discounted heavy oil prices. Production from our Deep Basin Assets decreased eight percent from the second quarter of 2018 due, in part, to the divestiture of Cenovus Pipestone Partnership (“CPP”). Operational performance at the Refineries was very good during the quarter, following major planned turnarounds earlier in the year, with crude utilization rates averaging 107 percent.

Financial results for the quarter reflect the ongoing strong operational performance of our assets and an improvement in crude oil prices from 2017. While light crude oil prices averaged roughly 45 percent higher than in the third quarter of 2017, Canadian heavy oil prices continued to be negatively impacted by takeaway capacity constraints, with Western Canadian Select (“WCS”) benchmark prices increasing only 23 percent over the same period. Increasing West Texas Intermediate (“WTI”) crude oil prices and the widening of the differential between WTI and WCS benchmark prices resulted in our realized liquids sales price from continuing operations averaging $49.19 per barrel, a three percent decrease compared with the second quarter of 2018. The impact of lower crude oil realized sales prices on our upstream financial results was offset by higher operating margin from our refining and marketing operations, as wider differentials between WTI and WCS as well as WTI and West Texas Sour (“WTS”) crude oil prices provided a feedstock cost advantage. Our financial results were negatively impacted by a before-tax loss on the divestiture of CPP of $795 million, a non-cash provision for onerous contracts related to office space of $630 million and realized risk management losses of $325 million.

Other highlights in the third quarter of 2018 compared with the third quarter of 2017 include:

• Completing the sale of CPP on September 6, 2018 for cash proceeds of $625 million, before closing adjustments. CPP held Cenovus’s Pipestone and Wembley natural gas and liquids business in northwestern Alberta and included our 39 percent operated working interest in the Wembley gas plant;

• Reducing net debt to less than $8.0 billion compared with $9.6 billion as at June 30, 2018, driven by Free Funds Flow of $706 million in the quarter and proceeds from the divestiture of CPP;

• Signing rail agreements for capacity to transport approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast, providing a means of mitigating some of the price impact of pipeline congestion;

• Reaching an agreement to sublease a portion of our Calgary office space that was in excess of our current and near-term requirements;

• Upstream operating margin from continuing operations of $755 million compared with $886 million in 2017 as increased realized sales prices and higher production volumes were offset by increased transportation and blending costs, realized risk management losses and higher royalties;

• Our Christina Lake project achieving payout for royalty purposes upon cumulative project revenues exceeding cumulative project allowable costs, resulting in the royalty calculation now being based on post-payout royalty rates, as discussed in the Oil Sands section of this MD&A;

• Earning an average companywide Netback from continuing operations, before realized hedging, of $26.05 per BOE, up 30 percent from the third quarter of 2017;

• Increased crude utilization at both Refineries and the feedstock cost advantage associated with wider crude oil differentials resulting in an operating margin of $436 million, more than double compared with 2017;

• Adjusted Funds Flow of $977 million compared with $980 million in 2017;  

• Recording a net loss from continuing operations of $242 million compared with net earnings of $275 million in 2017;

• Capital investment of $271 million compared with $438 million in 2017, reflecting our continued focus on capital discipline; and

• On September 27, 2018, initiating the process to redeem US$800 million of our US$1,300 million unsecured notes due October 15, 2019. A redemption premium of US$21 million and associated unamortized discount and debt issue cost of $1 million were recognized in the third quarter.  

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	Q3 2018 Management’s Discussion and Analysis

OPERATING RESULTS

Upstream Production Volumes

	Three Months Ended September 30,							Nine Months Ended September 30,
	2018		Percent Change			2017		2018		Percent Change			2017
Continuing Operations
Liquids(barrels per day)
Oil Sands
Foster Creek		163,939		6			154,363		164,160		43			114,632
Christina Lake		212,733		2			208,131		211,141		37			154,634
		376,672		4			362,494		375,301		39			269,266
Deep Basin
Crude Oil		5,674		(13	)		6,494		6,148		92			3,208
NGLs		26,595		1			26,370		27,770		106			13,498
		32,269		(2	)		32,864		33,918		103			16,706
Liquids Production(barrels per day)		408,941		3			395,358		409,219		43			285,972
Natural Gas(MMcf per day)
Oil Sands		-		(100	)		6		2		(82	)		11
Deep Basin (1)		520		5			495		546		118			251
		520		4			501		548		109			262
Production From Continuing Operations    (BOE per day)		495,592		4			478,817		500,558		52			329,601
Production From Discontinued Operations    (Conventional)(BOE per day)		16		(100	)		112,034		394		(100	)		112,542
Total Production(BOE per day)		495,608		(16	)		590,851		500,952		13			442,143

(1) Includes production used for internal consumption by the Oil Sands segment of 293 MMcf per day and 305 MMcf per day, respectively, for the three and nine months ended September 30, 2018 (2017 – no internal usage of Deep Basin production).

Oil Sands production increased in the third quarter compared with 2017 due to strong operational performance at both facilities. On a year-to-date basis, oil sands production was higher compared with 2017 primarily due to the Acquisition, and downtime in 2017 due to a major planned turnaround at Foster Creek.

Production from the Deep Basin Assets increased in the third quarter by three percent to 118,920 BOE per day compared with 2017 due to strong performance from the drilling program and the production well optimization efforts. Production in the third quarter was down eight percent compared with the second quarter of 2018 due to increased downtime as a result of third-party turnaround activity, and the divestiture of CPP. In the nine months ended September 30, 2018, production was 124,984 BOE per day, a seven percent increase in production from the closing of the Acquisition on May 17, 2017 to September 30, 2017, which averaged 116,605 BOE per day, primarily due to the results of our capital program.

Production for the nine months ended September 30, 2018 from our Conventional segment includes the results of our Suffield operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted for as a discontinued operation.

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	Q3 2018 Management’s Discussion and Analysis

Netbacks From Continuing Operations

Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see the Advisory section of this MD&A.

	Three Months Ended September 30,						Nine Months Ended September 30,
($/BOE)	2018			2017			2018			2017
Sales Price		45.73			34.58			42.11			35.70
Royalties		6.91			1.52			4.63			1.55
Transportation and Blending		5.66			5.10			5.79			5.43
Operating Expenses		7.10			7.94			7.55			8.52
Production and Mineral Taxes		0.01			0.01			0.01			-
Netback Excluding Realized Risk Management (1)		26.05			20.01			24.13			20.20
Realized Risk Management Gain (Loss)		(8.00	)		(0.21	)		(12.05	)		(0.81	)
Netback Including Realized Risk Management (1)		18.05			19.80			12.08			19.39

(1) Excludes results from our Conventional segment, which has been classified as a discontinued operation. Excludes intersegment sales.

Our average Netback, excluding realized risk management gains and losses, increased in the third quarter and on a year-to-date basis compared with 2017 primarily due to higher realized sales prices, consistent with the rise in benchmark prices, and lower operating costs, partially offset by increased royalties. For the nine months ended September 30, 2018, the strengthening of the Canadian dollar relative to the U.S. dollar compared with 2017 had a negative impact on our sales price of approximately $0.60 per BOE.

Refining and Marketing

Both refineries demonstrated strong operational performance, partially offset by planned fall maintenance and an unplanned outage, with crude utilization rates averaging 107 percent during the quarter. On a year-to-date basis, crude oil runs and refined product output declined due to the larger scope of the planned turnarounds at both refineries during the first quarter of 2018 compared with 2017.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2018		Percent Change			2017		2018		Percent Change			2017
Crude Oil Runs (1) (Mbbls/d)		492		6			462		436		(1	)		439
Heavy Crude Oil (1)		204		(4	)		213		190		(7	)		205
Refined Product (1) (Mbbls/d)		518		6			490		459		(2	)		467
Crude Utilization (1) (percent)		107		7			100		95		-			95
Operating Margin ($ millions)		436		107			211		745		162			284

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

Operating Margin from Refining and Marketing more than doubled in the third quarter of 2018 primarily due to wider crude oil price differentials, improved crude utilization rates, and a reduction in the cost of Renewable Identification Numbers (“RINs”). On a year-to-date basis, wider crude oil price differentials, higher market crack spreads, and a reduction in the cost of RINs was partially offset by increased operating costs due to the planned turnarounds at both refineries in the first quarter of 2018.

Further information on the changes in our production volumes, and other items included in our Netbacks and refining results 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 and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements.

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	Q3 2018 Management’s Discussion and Analysis

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,
(US$/bbl, unless otherwise indicated)	2018			Percent Change			2017			Q3 2018			Q2 2018			Q3 2017
Brent
Average		72.68			38			52.59			75.97			74.90			52.18
End of Period		82.72			44			57.54			82.72			79.44			57.54
WTI
Average		66.75			35			49.47			69.50			67.88			48.21
End of Period		73.25			42			51.67			73.25			74.15			51.67
Average Differential Brent-WTI		5.93			90			3.12			6.47			7.02			3.97
WCS
Average		44.82			19			37.59			47.25			48.61			38.27
Average (C$/bbl)		57.69			18			49.07			61.75			62.75			47.96
End of Period		37.75			(7	)		40.71			37.75			51.32			40.71
Average Differential WTI-WCS		21.93			85			11.88			22.25			19.27			9.94
WTS
Average		58.86			22			48.24			55.48			59.64			47.16
End of Period		66.85			32			50.62			66.85			62.05			50.62
Average Differential WTI-WTS		7.89			541			1.23			14.02			8.24			1.05
Condensate (C5 @ Edmonton)
Average		66.23			34			49.44			66.82			68.83			47.61
Average (C$/bbl)		85.24			32			64.54			87.35			88.81			59.66
Average Differential WTI-Condensate    (Premium)/Discount		0.52			1,633			0.03			2.68			(0.95	)		0.60
Average Differential WCS-Condensate    (Premium)/Discount		(21.41	)		81			(11.85	)		(19.57	)		(20.22	)		(9.34	)
Mixed Sweet Blend ("MSW" @ Edmonton)
Average		60.69			30			46.57			62.67			62.42			45.32
Average (C$/bbl)		78.11			28			60.80			81.92			80.54			56.79
End of Period		53.25			7			49.76			53.25			64.32			49.76
Average Refined Product Prices
Chicago Regular Unleaded Gasoline ("RUL")		81.73			27			64.48			87.10			85.00			66.87
Chicago Ultra-low Sulphur Diesel ("ULSD")		87.58			34			65.26			92.33			89.07			69.73
Refining Margin: Average 3-2-1 Crack    Spreads (2)
Chicago		16.82			10			15.33			19.14			18.36			19.66
Group 3		17.47			10			15.89			18.71			18.04			20.20
Average Natural Gas Prices
AECO (C$/Mcf) (3)		1.41			(45	)		2.58			1.35			1.03			2.04
NYMEX (US$/Mcf)		2.90			(9	)		3.17			2.90			2.80			3.00
Basis Differential NYMEX-AECO (US$/Mcf)		1.80			49			1.21			1.88			2.00			1.39
Foreign Exchange Rate(US$ per C$1)
Average		0.777			1			0.766			0.765			0.775			0.798
End of Period		0.773			(3	)		0.801			0.773			0.759			0.801

(1) These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the Netbacks tables in the Operating Results and Reportable Segments sections of this MD&A.

(2) The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.

(3) Alberta Energy Company (“AECO”) natural gas monthly index.

Crude Oil Benchmarks

Overall, average crude oil benchmark prices were relatively consistent with the second quarter of 2018, and significantly higher than in 2017. While Brent and WTI crude oil prices averaged roughly 45 percent higher than the third quarter of 2017, Canadian heavy oil prices only increased 23 percent.

Continued uncertainty over Venezuelan supply and the possibility of the U.S. enforcing sanctions on Iran supported improved global crude oil benchmark pricing in 2018. Reduced inventory levels from compliance with production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) and

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	Q3 2018 Management’s Discussion and Analysis

Russia have supported global oil prices. However, late in June 2018, OPEC agreed to scale back over-compliance with production cuts by its members, which is expected to result in a modest increase in production and has the potential to limit further strengthening of global oil prices.

WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In the third quarter and on a year-to-date basis, the Brent-WTI differential widened significantly compared with 2017. WTI prices were limited by production from the Permian Basin exceeding available pipeline capacity out of west Texas, leading to increased volumes moving from Cushing, Oklahoma to the U.S. Gulf Coast on pipelines that were already nearing capacity. WTI prices were also negatively impacted by reduced demand due to the start of seasonal refining maintenance in the Midwest and Midcontinent regions.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The average WTI-WCS differential was significantly wider in the third quarter of 2018 and on a year-to-date basis compared with 2017. In the first quarter of 2018, the WTI-WCS differential widened significantly as WCS weakened relative to WTI due to increasing production in Alberta and limited takeaway capacity. Canadian heavy oil prices improved somewhat in the second quarter as production declined from planned maintenance and temporary producer cuts due to insufficient pipeline takeaway capacity. During the third quarter, heavy crude oil prices weakened once again relative to WTI. Increased production resulted in pipeline apportionments while the inability to transport additional volumes by rail in the short term and the lack of clarity surrounding future pipelines continued to put downward pressure on WCS benchmark prices. In addition, heavy oil demand from U.S. refineries declined due to seasonal maintenance.

WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI and WTS benchmark prices widened significantly in the third quarter and on a year‑to‑date basis relative to the same periods in 2017, due primarily to pipeline congestion out of west Texas, as discussed above.

Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent volumes as a percentage of total blended volumes, range from approximately 25 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 cost to transport the condensate to Edmonton.

Condensate benchmark prices averaged 40 percent and 34 percent higher in the third quarter and on a year‑to‑date basis, respectively, compared with 2017, consistent with the rise in light oil prices over the same periods. However, during the third quarter, the rise in WTI prices outpaced the increase in condensate prices, resulting in a condensate price discount relative to WTI compared with a premium in the second quarter of 2018. The condensate price discount relative to WTI in the third quarter and on a year-to-date basis was more material compared with 2017 due to high domestic inventories, in addition to increasing domestic supply combined with higher than anticipated imports.

MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production, comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in 2018 compared with 2017, consistent with the general increase in average crude oil prices.

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 market crack spread. The 3‑2‑1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude

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	Q3 2018 Management’s Discussion and Analysis

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 Chicago refined product prices increased in 2018 primarily due to higher global crude oil prices. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by international prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices. The widening of the Chicago 3-2-1 and Group 3 crack spreads in 2018 can be primarily attributed to the widening of the Brent-WTI differential, as discussed above.

Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, 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.

Natural Gas Benchmarks

Average AECO prices weakened during the three and nine months ended September 30, 2018 compared with 2017 due to higher natural gas supply in Alberta and constrained export capabilities. Average NYMEX prices also decreased on a year-to-date basis compared with 2017 due to continued supply growth from the development of U.S. shale gas and natural gas associated with crude oil plays.

Foreign Exchange Benchmark

Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated in U.S. dollars, our long‑term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars.

In the third quarter of 2018, the Canadian dollar weakened relative to the U.S. dollar on average, compared with the third quarter of 2017. On a year-to-date basis, the Canadian dollar strengthened relative to the U.S. dollar on average, compared with 2017, resulting in a negative impact of approximately $233 million on our revenues in 2018, excluding our Conventional segment. The Canadian dollar as at September 30, 2018 compared with December 31, 2017 was weaker relative to the U.S. dollar, resulting in $306 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.

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	Q3 2018 Management’s Discussion and Analysis

FINANCIAL RESULTS

Selected Consolidated Financial Results

In 2018, the primary drivers of our financial results include the impact of the Acquisition, rising light oil benchmark prices, higher condensate prices, significantly wider light-heavy crude oil price differentials and realized risk management losses. The following key performance measures are discussed in more detail within this MD&A.

	Nine Months Ended September 30,					2018									2017											2016
($ millions, except per share amounts)	2018			2017		Q3			Q2			Q1			Q4			Q3			Q2		Q1			Q4			Q3
Revenues		16,299			11,964		5,857			5,832			4,610			5,079			4,386			4,037		3,541			3,324			2,945
Operating Margin (1)
From Continuing    Operations		2,259			1,974		1,191			911			157			1,018			1,097			572		305			442			335
Total Operating Margin		2,299			2,395		1,192			938			169			1,088			1,214			731		450			595			487
Cash From Operating    Activities
From Continuing    Operations		1,630			1,778		1,258			506			(134	)		833			481			1,102		195			22			189
Total Cash From    Operating Activities		1,669			2,159		1,259			533			(123	)		900			592			1,239		328			164			310
Adjusted Funds Flow (2)
From Continuing    Operations		1,670			1,651		976			747			(53	)		796			865			603		183			382			296
Total Adjusted Funds Flow		1,710			2,048		977			774			(41	)		866			980			745		323			535			422
Operating Earnings    (Loss) (2)
From Continuing    Operations		(1,085	)		499		(41	)		(292	)		(752	)		(533	)		240			298		(39	)		21			(40	)
Per Share ($) (3)		(0.88	)		0.47		(0.03	)		(0.24	)		(0.61	)		(0.43	)		0.20			0.27		(0.05	)		0.03			(0.05	)
Total Operating Earnings    (Loss)		(1,057	)		640		(42	)		(272	)		(743	)		(514	)		327			352		(39	)		321			(236	)
Per Share ($) (3)		(0.86	)		0.60		(0.03	)		(0.22	)		(0.60	)		(0.42	)		0.27			0.32		(0.05	)		0.39			(0.28	)
Net Earnings (Loss)
From Continuing    Operations		(1,566	)		3,044		(242	)		(410	)		(914	)		(776	)		275			2,558		211			(209	)		(55	)
Per Share ($) (3)		(1.27	)		2.87		(0.20	)		(0.33	)		(0.74	)		(0.63	)		0.22			2.30		0.25			(0.25	)		(0.07	)
Total Net Earnings (Loss)		(1,313	)		2,746		(241	)		(418	)		(654	)		620			(82	)		2,617		211			91			(251	)
Per Share ($) (3)		(1.06	)		2.59		(0.20	)		(0.34	)		(0.53	)		0.50			(0.07	)		2.35		0.25			0.11			(0.30	)
Capital Investment (4)
From Continuing    Operations		1,087			898		271			294			522			557			396			277		225			202			167
Total Capital Investment		1,087			1,078		271			292			524			583			438			327		313			259			208
Dividends		183			164		61			62			60			61			62			61		41			42			41
Per Share ($)		0.15			0.15		0.05			0.05			0.05			0.05			0.05			0.05		0.05			0.05			0.05

(1) Additional subtotal found in Notes 1 and 9 of the interim Consolidated Financial Statements and defined in this MD&A.

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

(3) Represented on a basic and diluted per share basis.

(4) Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets and assets held for sale.

Cenovus Energy Inc.	9
	Q3 2018 Management’s Discussion and Analysis

Revenues

($ millions)	Three Months Ended			Nine Months Ended
Revenues for the Periods Ended September 30, 2017		4,386			11,964
Increase (Decrease) due to:
Oil Sands		561			3,313
Deep Basin		16			349
Refining and Marketing		965			973
Corporate and Eliminations		(71	)		(300	)
Revenues for the Periods Ended September 30, 2018		5,857			16,299

Upstream revenues increased in the third quarter compared with the same period in 2017 due to higher average realized pricing, consistent with the rise in crude oil benchmark prices, and the weakening of the Canadian dollar relative to the U.S. dollar, partially offset by higher royalties. On a year-to-date basis, upstream revenues increased compared with 2017 due to incremental sales volumes, primarily due to the Acquisition, and higher average realized pricing, partially offset by higher royalties and the strengthening of the Canadian dollar relative to the U.S. dollar.

Refining and Marketing revenues increased 45 percent and 14 percent for the three and nine months ended September 30, 2018, respectively, compared with 2017. Refining revenues increased in the third quarter due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, and the weakening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group increased in the third quarter compared with 2017 due to higher crude oil prices and an increase in crude oil volumes sold, partially offset by a decline in natural gas volumes sold, and lower natural gas prices.

On a year-to-date basis, refining revenues increased due to higher refined product pricing, consistent with the rise in average Chicago refined product benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas sales undertaken by our marketing group decreased in 2018 compared with 2017 due to a decline in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil prices.

Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenue 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 Margin

Operating Margin is an additional subtotal found in Notes 1 and 9 of the interim Consolidated Financial Statements and 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 Margin 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. Items within the Corporate and Eliminations segment are excluded from the calculation of Operating Margin.

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Revenues		6,046		4,504		16,921		12,286
(Add) Deduct:
Purchased Product		2,483		1,782		6,664		6,295
Transportation and Blending		1,502		1,088		4,688		2,543
Operating Expenses		542		528		1,816		1,398
Production and Mineral Taxes		-		-		1		-
Realized (Gain) Loss on Risk Management Activities		328		9		1,493		76
Operating Margin From Continuing Operations		1,191		1,097		2,259		1,974
Conventional (Discontinued Operations)		1		117		40		421
Total Operating Margin		1,192		1,214		2,299		2,395

Cenovus Energy Inc.	10
	Q3 2018 Management’s Discussion and Analysis

Three Months Ended September 30, 2018 Compared With September 30, 2017

Operating Margin from continuing operations increased primarily due to: •An increase in our average liquids sales price, consistent with higher crude oil benchmark prices; and •Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials and increased utilization.   These increases in Operating Margin were partially offset by: •A rise in transportation and blending expenses primarily due to higher condensate prices;

• Upstream realized risk management losses of $330 million in the third quarter compared with losses of $9 million in 2017; and

• Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), increased realized sales prices and the Christina Lake project achieving payout, which increased the royalty rate.

Operating Margin From Continuing Operations Variance

Nine Months Ended September 30, 2018 Compared With September 30, 2017

Operating Margin from continuing operations increased primarily due to: •A rise in our liquids and natural gas sales volumes as a result of the Acquisition; •An increase in our average liquids sales price, consistent with higher crude oil benchmark prices; and •Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials and higher average market crack spreads.   These increases in Operating Margin were partially

offset by:

• A rise in transportation and blending expenses primarily due to an increase in condensate volumes required for blending our increased oil sands production and higher condensate prices;

• Upstream realized risk management losses of $1,491 million (2017 – losses of $72 million);

• Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate), higher sales volumes and realized sales prices, as well as the Christina Lake project reaching payout in the third quarter of 2018; and

• An increase in upstream operating expenses primarily due to the Acquisition.

Cenovus Energy Inc.	11
	Q3 2018 Management’s Discussion and Analysis

Operating Margin From Continuing Operations Variance

(1) Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases.

Additional details explaining the changes in Operating Margin from continuing operations can be found in the Reportable Segments section of this MD&A.

Cash From Operating Activities and Adjusted Funds Flow

Adjusted Funds 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. Adjusted Funds Flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.

Total Cash From Operating Activities and Adjusted Funds Flow

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
Cash From Operating Activities (1)		1,259			592			1,669			2,159
(Add) Deduct:
Net Change in Other Assets and Liabilities		(15	)		(19	)		(50	)		(75	)
Net Change in Non-Cash Working Capital		297			(369	)		9			186
Adjusted Funds Flow (1)		977			980			1,710			2,048

(1) Includes results from our Conventional segment, which has been classified as a discontinued operation.

In the third quarter of 2018, Cash From Operating Activities increased due to changes in non-cash working capital and higher Operating Margin, as discussed above, partially offset by a lower current tax recovery compared with the third quarter of 2017. The change in non-cash working capital in the third quarter of 2018 was primarily due to a decrease in accounts receivable and income tax receivable, partially offset by an increase in inventory. For the three months ended September 30, 2017, the change in non-cash working capital was primarily due to a decline in accounts payable, a decrease in income tax payable and an increase in accounts receivable.

On a year-to-date basis, Cash From Operating Activities and Adjusted Funds Flow were lower compared with 2017. In 2018, increased Operating Margin was offset by a lower current tax recovery, and higher general and administrative costs primarily due to $48 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $142 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. The change in non-cash working capital in 2018 was primarily due to a decrease in income tax receivable and an increase in accounts payable, partially offset by an increase in inventory. In 2017, the change in non-cash working capital was primarily due to a rise in inventory and an increase in accounts receivable, partially offset by an increase in accounts payable.

Cenovus Energy Inc.	12
	Q3 2018 Management’s Discussion and Analysis

Operating Earnings (Loss)

Operating Earnings (Loss) is a non-GAAP measure 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, revaluation gain, 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)	2018			2017			2018			2017
Earnings (Loss) From Continuing Operations, Before    Income Tax		(507	)		158			(1,969	)		3,644
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)		(247	)		486			(508	)		75
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2)		(172	)		(367	)		297			(702	)
Revaluation (Gain)		-			-			-			(2,555	)
(Gain) Loss on Divestiture of Assets		795			(1	)		794			-
Operating Earnings (Loss) From Continuing Operations,    Before Income Tax		(131	)		276			(1,386	)		462
Income Tax Expense (Recovery)		(90	)		36			(301	)		(37	)
Operating Earnings (Loss) From Continuing Operations		(41	)		240			(1,085	)		499
Operating Earnings (Loss) From Discontinued Operations		(1	)		87			28			141
Total Operating Earnings (Loss)		(42	)		327			(1,057	)		640

(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.

Operating Earnings decreased in the third quarter of 2018 compared with 2017 due to a non‑cash provision for onerous contracts of $630 million and lower unrealized foreign exchange gains on operating items compared with 2017, partially offset by higher Cash From Operating Activities, as discussed above, an income tax recovery compared with income tax expense in 2017, and a re-measurement gain on the contingent payment of $83 million compared with a gain of $43 million in 2017.

For the nine months ended September 30, 2018, Operating Earnings decreased relative to 2017 primarily due to a non-cash provision of $692 for onerous contracts related to office space, a re-measurement loss of $411 million on the contingent payment compared with a gain of $109 million in 2017, an increase in DD&A that included an impairment of $100 million in the first quarter of 2018, lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, and unrealized foreign exchange gains of $7 million on operating items compared with gains of $193 million in 2017.

Net Earnings (Loss)

($ millions)	Three Months Ended			Nine Months Ended
Net Earnings (Loss) From Continuing Operations, for the Periods Ended September 30, 2017		275			3,044
Increase (Decrease) due to:
Operating Margin From Continuing Operations		94			285
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)		733			583
Unrealized Foreign Exchange Gain (Loss)		(244	)		(1,207	)
Revaluation (Gain)		-			(2,555	)
Re-measurement of Contingent Payment		40			(520	)
Gain (Loss) on Divestiture of Assets		(796	)		(794	)
Expenses (1)		(522	)		(885	)
DD&A		31			(513	)
Exploration Expense		(1	)		(7	)
Income Tax Recovery (Expense)		148			1,003
Net Earnings (Loss) From Continuing Operations, for the Periods Ended September 30, 2018		(242	)		(1,566	)

(1) Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, finance costs, interest income, realized foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses.

Cenovus Energy Inc.	13
	Q3 2018 Management’s Discussion and Analysis

Net Earnings from continuing operations decreased in the third quarter of 2018 compared with 2017 due to:

• A before-tax loss of $795 million ($526 million after-tax) on the divestiture of CPP;

• Lower Operating Earnings, as discussed above; and

• Non-operating foreign exchange gains of $172 million compared with gains of $367 million in 2017.

These decreases to our Net Earnings from continuing operations in the third quarter were partially offset by unrealized risk management gains of $247 million compared with losses of $486 million in 2017.

On a year-to-date basis we incurred a net loss of $1,566 million from continuing operations, a significant decrease from 2017, due to:

• An after-tax revaluation gain of $1.9 billion on our pre-existing interest in FCCL recognized in 2017;

• Lower Operating Earnings, as discussed above;

• Non-operating foreign exchange losses of $297 million compared with gains of $702 million in 2017; and

• A before-tax loss of $795 million ($526 million after-tax) on the divestiture of CPP.

These decreases to our Net Earnings from continuing operations for the nine months ended September 30, 2018 were partially offset by an income tax recovery of $403 million compared with income tax expense of $600 million in 2017 and unrealized risk management gains of $508 million compared with losses of $75 million in 2017.   

Net Earnings from discontinued operations for the three and nine months ended September 30, 2018 was $1 million and $253 million, respectively (2017 – Net Loss of $357 million and $298 million, respectively). Year‑to‑date results include an after-tax gain of $223 million on the divestiture of the Suffield assets in the first quarter of 2018.

Total Capital Investment

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Oil Sands		176		273		718		660
Deep Basin		22		64		193		77
Refining and Marketing		59		38		147		124
Corporate and Eliminations		14		21		29		37
Capital Investment - Continuing Operations		271		396		1,087		898
Conventional (Discontinued Operations)		-		42		-		180
Total Capital Investment (1)		271		438		1,087		1,078

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

Capital investment in continuing operations decreased in the third quarter of 2018 compared with 2017, reflecting our continued focus on capital discipline. For the nine months ended September 30, 2018, capital investment in continuing operations increased compared with 2017, reflecting our increased ownership in FCCL and the new asset base in the Deep Basin as a result of the Acquisition. On a year‑to‑date basis, Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. Capital investment in the Deep Basin in 2018 focused on all three operating areas and included the drilling of 15 net horizontal production wells targeting liquids rich natural gas, as well as capital invested in completions, facilities and infrastructure to support production.

Refining and Marketing capital investment increased in 2018 due to increased capital maintenance and reliability work compared with the same periods in 2017.

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

Capital Investment Decisions

We continue to focus on deleveraging our balance sheet. To achieve this, we are currently marketing for sale certain non-core Deep Basin assets and are continuing to look for opportunities to further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively identifying further cost reduction opportunities.

Once our balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner:

• First, to sustaining and maintenance capital for our existing business operations;

• Second, to paying our current dividend as part of providing strong total shareholder return; and

• Third, for incremental returns to shareholders, further deleveraging, and growth or discretionary capital.

Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital Resources section of this MD&A for further information.

Cenovus Energy Inc.	14
	Q3 2018 Management’s Discussion and Analysis

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Adjusted Funds Flow (1)		977		980		1,710		2,048
Total Capital Investment (1)		271		438		1,087		1,078
Free Funds Flow (1) (2)		706		542		623		970
Cash Dividends		61		62		183		164
		645		480		440		806

(1) Includes our Conventional segment, which has been classified as a discontinued operation.

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

Upon further review of our capital program, we have updated our 2018 guidance estimates, including future capital investment, reflecting our continued focus on capital discipline and cost efficiencies identified. We now expect to spend between $1.3 billion and $1.4 billion, a 16 percent decrease from our December 13, 2017 guidance.

We expect our capital investment and cash dividends for 2018 to be funded from our internally generated cash flows and our cash balance on hand.

REPORTABLE SEGMENTS

Our reportable segments are as follows:   Oil Sands, which includes the development and production of bitumen and natural gas in northeast Alberta. Cenovus’s bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early stages of development. Our interest in certain of our operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake increased from 50 percent to 100 percent on May 17, 2017.   Deep Basin, which includes approximately three million net acres of land primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas and natural gas liquids. The assets reside in Alberta and British Columbia and include interests in numerous natural gas processing facilities. These assets were acquired on May 17, 2017.   Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleumand chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. In addition, Cenovus owns and operates a crude‑by‑rail terminal in Alberta. 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 reportable segment to which the derivative instrument relates. Eliminations include adjustments for internal usage of natural gas production between segments, crude oil production used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices based on current market prices.

In the second quarter of 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of operations have been reported as discontinued operations. As at January 5, 2018, all of the Conventional segment assets were sold. Refer to the Discontinued Operations section of this MD&A for more information.

Cenovus Energy Inc.	15
	Q3 2018 Management’s Discussion and Analysis

Revenues by Reportable Segment

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
Oil Sands (1)		2,717			2,156			8,134			4,821
Deep Basin (1)		203			187			652			303
Refining and Marketing		3,126			2,161			8,135			7,162
Corporate and Eliminations		(189	)		(118	)		(622	)		(322	)
		5,857			4,386			16,299			11,964

(1) Our results for the nine months ended September 30, 2017 include 137 days of FCCL operations at 100 percent and 137 days of operations from the Deep Basin Assets. See the Oil Sands and Deep Basin sections of this MD&A for more details.

OIL SANDS

In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of development. The Oil Sands segment includes the Athabasca natural gas property, from which the natural gas production is used as fuel at the adjacent Foster Creek operations.

Highlights in the third quarter of 2018 include:

• Total production increasing four percent compared with 2017 as a result of strong operational performance;

• The Christina Lake project achieving payout for royalty purposes upon cumulative project revenues exceeding cumulative project allowable costs;

• Crude oil netbacks of $28.77 per barrel, excluding realized risk management activities, a 16 percent increase compared with 2017 due to a higher average realized sales price and a 13 percent reduction in per-barrel operating costs, partially offset by royalties increasing by $6.29 per barrel, due primarily to higher WTI benchmark prices (which determines the royalty rate); and

• Operating Margin of $682 million, a 17 percent decrease compared with the third quarter of 2017 as higher average realized sales prices and increased sales volumes were offset by increased transportation and blending costs, realized risk management losses of $323 million compared with losses of $9 million in 2017, and increased royalties.

Oil Sands – Crude Oil

Three Months Ended September 30, 2018 Compared With September 30, 2017

Financial Results ⁽¹⁾

	Three Months Ended September 30,
($ millions)	2018		2017
Gross Sales		2,989		2,204
Less: Royalties		275		54
Revenues		2,714		2,150
Expenses
Transportation and Blending		1,482		1,066
Operating		230		254
(Gain) Loss on Risk Management		323		9
Operating Margin		679		821
Capital Investment		176		270
Operating Margin Net of Related Capital Investment		503		551

(1) Excludes results from the Athabasca natural gas property.

Operating Margin Variance

(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.

Cenovus Energy Inc.	16
	Q3 2018 Management’s Discussion and Analysis

Revenues

Price

In the third quarter of 2018, our average realized crude oil sales price increased to $49.38 per barrel (2017 – $40.02 per barrel). The increase in our crude oil price reflects the rise in WCS prices compared with the third quarter of 2017, partially offset by wider WCS-Condensate and WCS‑Christina Dilbit Blend (“CDB”) differentials. The WCS-CDB differential widened to a discount of US$2.92 per barrel (2017 – discount of US$1.47 per barrel).

Our realized crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios range between 25 percent and 33 percent. As the cost of condensate increases relative to the price of blended crude oil, our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate from U.S. markets. As such, our average cost of condensate is generally higher than the Edmonton benchmark price due to transportation between market hubs and transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to when we blend it with our production. In a rising crude oil price environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a lower price earlier in the year.

Production Volumes

	Three Months Ended September 30,
(barrels per day)	2018		Percent Change		2017
Foster Creek		163,939		6		154,363
Christina Lake		212,733		2		208,131
		376,672		4		362,494

Oil Sands production averaged 376,672 barrels per day in the third quarter of 2018, a four percent increase from the same period of 2017 as a result of strong operational performance at both facilities.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with a wider WCS-Condensate differential in the third quarter of 2018, the proportion of the cost of condensate recovered decreased. The total amount of condensate used increased as a result of higher production volumes.

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.

Royalties for 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.

Royalties for 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 sales prices. Net profits are a function of sales volumes, sales prices and allowed operating and capital costs.

Foster Creek is a post-payout project.

During the third quarter of 2018, our Christina Lake property achieved project payout. Project payout is achieved when the cumulative project revenue exceeds the cumulative project allowable costs. As a result, the Christina Lake effective royalty rate increased to an average of 11.4 percent in the third quarter of 2018 from an average of 1.6 percent in the third quarter of 2017, with only a portion of the current quarter reflecting the increased rate.

Effective Royalty Rates

	Three Months Ended September 30,
(percent)	2018		2017
Foster Creek		24.9		9.1
Christina Lake		11.4		1.6

Royalties increased $221 million in the third quarter of 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake increased primarily due to a higher WTI benchmark price (which determines the royalty rate), higher realized crude oil sales prices, and as a result of the Christina Lake project achieving payout.

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	Q3 2018 Management’s Discussion and Analysis

Expenses

Transportation and Blending

Transportation and blending costs increased $416 million compared with the third quarter of 2017. Blending costs increased primarily due to higher condensate prices, driven by higher light oil benchmark prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects.

Per-unit Transportation Expenses

At Foster Creek, transportation costs declined $2.05 per barrel due to a higher proportion of Canadian sales resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $1.56 per barrel as a result of increased U.S. sales relative to the third quarter of 2017.  

Operating

Primary drivers of our operating expenses in the third quarter of 2018 were workforce costs, fuel, chemical costs, repairs and maintenance and workovers. Total operating expenses decreased $24 million primarily due to a decrease in natural gas prices, lower workforce costs and fewer workovers, partially offset by increased chemical costs.

Per-unit Operating Expenses

	Three Months Ended September 30,
($/bbl)	2018		Percent Change			2017
Foster Creek
Fuel		1.60		(24	)		2.10
Non-fuel		5.88		(21	)		7.43
Total		7.48		(22	)		9.53
Christina Lake
Fuel		1.44		(19	)		1.78
Non-fuel		4.42		3			4.30
Total		5.86		(4	)		6.08
Total		6.59		(13	)		7.58

At both Foster Creek and Christina Lake, per-barrel fuel costs decreased in the third quarter of 2018 due to lower natural gas prices. Foster Creek per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes, a reduction in workforce costs and fewer workovers, partially offset by higher chemical costs. At Christina Lake, per-barrel non-fuel operating expenses increased as higher chemical costs were only partially offset by lower workforce costs and a reduction in workovers.  

Netbacks ⁽¹⁾

	Foster Creek						Christina Lake
	Three Months Ended September 30,
($/bbl)	2018			2017			2018			2017
Sales Price		53.35			41.57			46.07			38.84
Royalties		11.81			2.98			4.64			0.55
Transportation and Blending		6.63			8.68			5.70			4.14
Operating Expenses		7.48			9.53			5.86			6.08
Netback Excluding Realized Risk Management		27.43			20.38			29.87			28.07
Realized Risk Management Gain (Loss)		(8.46	)		(0.13	)		(9.94	)		(0.40	)
Netback Including Realized Risk Management		18.97			20.25			19.93			27.67

(1) Netbacks reflect our operating margin on a per-barrel basis of unblended crude oil.

Risk Management

Risk management positions in the third quarter of 2018 resulted in realized losses of $323 million (2017 – realized losses of $9 million), consistent with average benchmark prices exceeding our contract prices.

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	Q3 2018 Management’s Discussion and Analysis

Nine Months Ended September 30, 2018 Compared With September 30, 2017

Financial Results ⁽¹⁾

	Nine Months Ended September 30,
($ millions)	2018		2017
Gross Sales		8,638		4,920
Less: Royalties		512		117
Revenues		8,126		4,803
Expenses
Transportation and Blending		4,616		2,511
Operating		780		608
(Gain) Loss on Risk Management		1,465		72
Operating Margin		1,265		1,612
Capital Investment		717		654
Operating Margin Net of Related Capital Investment		548		958

(1) Excludes results from the Athabasca natural gas property.

Operating Margin Variance

(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

Price

In the nine months ended September 30, 2018, our average realized crude oil sales price increased to $45.15 per barrel (2017 – $39.52 per barrel). The increase in our crude oil price reflects the rise in WCS prices compared with 2017, partially offset by wider WCS-Condensate and WCS-CDB differentials and the strengthening of the Canadian dollar relative to the U.S. dollar. The WCS-CDB differential widened to a discount of US$2.73 per barrel (2017 – discount of US$2.22 per barrel).

Production Volumes

	Nine Months Ended September 30,
(barrels per day)	2018		Percent Change		2017
Foster Creek		164,160		43		114,632
Christina Lake		211,141		37		154,634
		375,301		39		269,266

Production at both Foster Creek and Christina Lake was higher compared with 2017 primarily due to the Acquisition. Production for the nine months ended September 30, 2017 was reduced by 3,690 barrels per day due to a major planned turnaround at Foster Creek in the second quarter.

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	Q3 2018 Management’s Discussion and Analysis

Royalties

Effective Royalty Rates

	Nine Months Ended September 30,
(percent)	2018		2017
Foster Creek		19.5		8.4
Christina Lake		6.4		2.1

On a year-to-date basis, royalties increased $395 million compared with 2017. Royalties at both Foster Creek and Christina Lake increased primarily due to a higher WTI benchmark price (which determines the royalty rate), increased sales volumes and higher crude oil sales prices, as well as the Christina Lake project achieving royalty payout status during the third quarter of 2018.

Expenses

Transportation and Blending

Transportation and blending costs increased $2,105 million. Blending costs increased due to a rise in condensate volumes required for our increased production and higher condensate prices. Our condensate costs were higher than the average Edmonton benchmark price, primarily due to the transportation expense associated with moving the condensate between market hubs and to our oil sands projects. Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition.

Per-unit Transportation Expenses

Foster Creek transportation costs declined $1.34 per barrel due to a higher proportion of Canadian sales resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $1.03 per barrel as a result of increased U.S. sales relative to 2017.

Operating

Primary drivers of our operating expenses in 2018 were workforce costs, fuel, chemical costs, repairs and maintenance and workovers. While total operating costs increased $172 million primarily due to the Acquisition, per-barrel operating expenses decreased 10 percent.

Per-unit Operating Expenses

	Nine Months Ended September 30,
($/bbl)	2018		Percent Change			2017
Foster Creek
Fuel		2.08		(18	)		2.53
Non-fuel		6.80		(15	)		7.96
Total		8.88		(15	)		10.49
Christina Lake
Fuel		1.84		(14	)		2.14
Non-fuel		4.63		(1	)		4.66
Total		6.47		(5	)		6.80
Total		7.54		(10	)		8.40

At both Foster Creek and Christina Lake, per-barrel fuel costs decreased due to lower natural gas prices, partially offset by increased consumption. At Foster Creek, per-barrel non-fuel operating expenses decreased in 2018 primarily due to higher sales volumes, lower workforce costs, fewer workovers and lower repairs and maintenance costs due to a turnaround in the second quarter of 2017, partially offset by increased chemical costs. Christina Lake per-barrel non-fuel operating expenses decreased slightly as higher sales volumes and lower workforce costs were partially offset by increased chemical costs.

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	Q3 2018 Management’s Discussion and Analysis

Netbacks ⁽¹⁾

	Foster Creek						Christina Lake
	Nine Months Ended September 30,
($/bbl)	2018			2017			2018			2017
Sales Price		49.10			42.22			41.97			37.47
Royalties		8.15			2.80			2.37			0.71
Transportation and Blending		7.67			9.01			5.15			4.12
Operating Expenses		8.88			10.49			6.47			6.80
Netback Excluding Realized Risk Management		24.40			19.92			27.98			25.84
Realized Risk Management Gain (Loss)		(13.82	)		(1.05	)		(14.43	)		(0.96	)
Netback Including Realized Risk Management		10.58			18.87			13.55			24.88

(1) Netbacks reflect our margin on a per-barrel basis of unblended crude oil.

Risk Management

Risk management positions in 2018 resulted in realized losses of $1,465 million (2017 – realized losses of $72 million), consistent with average benchmark prices exceeding our contract prices. In 2017 we entered into hedging contracts with the intent to provide downside protection and support financial resilience following the Acquisition. The majority of these hedging contracts have now expired.

Oil Sands – Capital Investment

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Foster Creek		80		122		327		312
Christina Lake		81		132		356		272
		161		254		683		584
Other (1)		15		19		35		76
Capital Investment (2)		176		273		718		660

(1) Includes new resource plays, Narrows Lake, Telephone Lake and Athabasca natural gas.

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

Oil Sands capital investment decreased $97 million in the third quarter, primarily due to a smaller sustaining well and re-drill program, as well as decreased spending on the Christina Lake phase G expansion compared with 2017. Capital investment in the nine months ended September 30, 2018 increased by $58 million from 2017, reflecting our 100 percent ownership of FCCL as of May 17, 2017. At Foster Creek, capital investment focused on sustaining capital related to existing production and stratigraphic test wells. In 2018 and 2017, Christina Lake capital investment focused on sustaining capital related to existing production, stratigraphic test wells and the phase G expansion.

Drilling Activity

	Gross Stratigraphic Test Wells				Gross Production Wells (1)
Nine Months Ended September 30,	2018		2017		2018		2017
Foster Creek		43		93		14		25
Christina Lake		63		105		29		8
		106		198		43		33
Other		21		16		-		-
		127		214		43		33

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

Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion phases and to further progress the evaluation of emerging assets.

Future Capital Investment

Upon further review of our capital program, we have updated our 2018 guidance estimates to reflect our continued focus on capital discipline and efficiencies identified within our Oil Sands capital programs. Our revised full year 2018 Oil Sands capital investment is forecast to be between $865 million and $930 million. Guidance has decreased from our 2018 estimates released on December 13, 2017 by approximately 18 percent. Updated guidance is available on our website at cenovus.com.

Foster Creek is currently producing from phases A through G. Capital investment for 2018 is forecast to be between $375 million and $400 million. We plan to continue focusing on sustaining capital related to existing production.

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	Q3 2018 Management’s Discussion and Analysis

Christina Lake is producing from phases A through F. Capital investment for 2018 is forecast to be between $450 million and $475 million, focused on sustaining capital and construction of the phase G expansion. Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing well and remains on track. Phase G is expected to start producing in the second half of 2019.

Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus primarily on equipment and site preservation related to the suspension of construction at Narrows Lake.

In 2018, our Technology and other capital investment, forecast to be between $35 million and $45 million, relates to technology development initiatives and annual environmental and regulatory commitments.

DD&A and Exploration Expense

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 proved reserves.

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

($ millions, unless otherwise indicated)	As at December 31, 2017
Upstream Property, Plant and Equipment		26,341
Estimated Future Development Capital		30,195
Total Estimated Upstream Cost Base		56,536
Total Proved Reserves (MMBOE)		5,232
Implied Depletion Rate ($/BOE)		10.81

While this illustrates the calculation of the implied depletion rate, our depletion rates resulted in a total average rate ranging between $8.75 to $11.30 per BOE. Amounts related to assets under construction and assets held for sale, which would be included in the total upstream cost base noted above 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 December 31, 2017 Consolidated Financial Statements.

Future development costs declined due to an increase in well pair lengths at Christina Lake, resulting in a reduction in the number of pads and well pairs required, as well as cost savings at both Foster Creek and Christina Lake related to a reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in the future development costs at Foster Creek as a result of a development area expansion.

In the third quarter, Oil Sands DD&A decreased $19 million compared with 2017 primarily due to lower depletion rates. On a year-to-date basis, Oil Sands DD&A increased by $272 million compared with 2017 as a result of increased production volumes. The average depletion rate for the three and nine months ended September 30, 2018 was approximately $10.61 per barrel (2017 – $11.53 per barrel and $11.39 per barrel for the three and nine months ended September 30, 2017, respectively).

Exploration expense of $2 million and $8 million was recorded in the three and nine months ended September 30, 2018, respectively, compared with $1 million for the three and nine months ended September 30, 2017.

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	Q3 2018 Management’s Discussion and Analysis

DEEP BASIN

Our Deep Basin Assets include liquids rich natural gas, condensate and other NGLs, as well as light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets provide short‑cycle development opportunities with high-return potential that complement our long-term oil sands development. In addition, a portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic hedge for the natural gas required as a fuel source at the Refineries. Our results for the nine months ended September 30, 2017 include 137 days of operations from the Deep Basin Assets.

Highlights in the third quarter of 2018 include:

• Closing the divestiture of CPP on September 6, 2018 for cash proceeds of $625 million, before closing adjustments;

• Total production of 118,920 BOE per day, a three percent increase compared with the third quarter of 2017 due to our drilling program and improved well performance, partially offset by increased downtime as a result of third‑party turnaround activity, and the divestiture of CPP;

• Total capital investment of $22 million related to a front end engineering design study, infrastructure to support production, as well as completing four net wells and bringing two net wells on production;

• Netback of $6.73 per BOE, before realized hedging; and

• Generating Operating Margin of $73 million.

Financial Results

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Gross Sales		214		200		714		324
Less: Royalties		11		13		62		21
Revenues		203		187		652		303
Expenses
Transportation and Blending		20		22		72		32
Operating		103		101		303		156
Production and Mineral Taxes		-		-		1		-
(Gain) Loss on Risk Management		7		-		26		-
Operating Margin		73		64		250		115
Capital Investment		22		64		193		77
Operating Margin Net of Related Capital Investment		51		-		57		38

Revenues

Price

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Light and Medium Oil ($/bbl)		73.00		52.54		73.37		55.64
NGLs ($/bbl)		41.40		30.78		40.44		29.57
Natural Gas ($/mcf)		1.31		1.77		1.62		2.15
Total Oil Equivalent ($/BOE)		18.45		17.61		19.69		19.07

For the three and nine months ended September 30, 2018, revenues include $12 million and $42 million, respectively, primarily for processing fee revenue related to our interests in natural gas processing facilities (2017 – $13 million and $19 million, respectively). We do not include processing fee revenue in our per-unit pricing metrics or our netbacks.

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	Q3 2018 Management’s Discussion and Analysis

Production Volumes

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Liquids
Crude Oil (barrels per day)		5,674		6,494		6,148		3,208
NGLs (barrels per day)		26,595		26,370		27,770		13,498
		32,269		32,864		33,918		16,706
Natural Gas (MMcf per day)		520		495		546		251
Total Production(BOE/d)		118,920		115,301		124,984		58,516
Natural Gas Production (percentage of total)		73		71		73		71
Liquids Production (percentage of total)		27		29		27		29

Production in the third quarter increased three percent from 2017 due to our drilling program and improved well performance, partially offset by increased downtime as a result of third-party turnaround activity, and the divestiture of CPP on September 6, 2018. Production from CPP was approximately 8,800 BOE per day prior to the divestiture.

Royalties

The Deep Basin Assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital and operating costs incurred to process and transport the Crown’s portion of natural gas production.

Effective January 1, 2017, the Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty Framework (“MRF”), which applies to all producing wells drilled after January 1, 2017. Under this new framework, Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January 1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF.

In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of natural gas production.

For the three and nine months ended September 30, 2018, our effective liquids royalty rate was 9.5 percent and 14.2 percent, respectively (2017 – 11.4 percent for the three and nine months ended September 30, 2017). The effective natural gas royalty rate was negative 4.7 percent for the third quarter, due to the GCA royalty credit being higher than the royalty expense as a result of low gas prices (2017 – 3.5 percent). On a year-to-date basis, the effective natural gas royalty rate was 1.9 percent (2017 – 3.7 percent).

Expenses

Transportation

Transportation costs averaged $1.85 per BOE and $1.99 per BOE for the three and nine months ended September 30, 2018, respectively (2017 – $1.96 per BOE for the three and nine months ended September 30, 2017). Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point of production to where the product is sold. The majority of Deep Basin production is sold into the Alberta market.

Operating

Primary drivers of our operating expenses were related to workforce, repairs and maintenance, third-party processing fee expenses, and property tax and lease costs. We have continued to focus on optimization of maintenance processes in 2018, resulting in increased runtimes and lower per BOE repairs and maintenance costs. As a result, we have maintained total operating expenses consistent with 2017 and decreased our costs on a per BOE basis as a result of increased production levels in 2018.

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	Q3 2018 Management’s Discussion and Analysis

Netbacks

	Three Months Ended September 30,					Nine Months Ended September 30,
($/BOE)	2018			2017		2018			2017
Sales Price		18.45			17.61		19.69			19.07
Royalties		0.95			1.28		1.80			1.34
Transportation and Blending		1.85			1.96		1.99			1.96
Operating Expenses		8.89			9.00		8.31			8.95
Production and Mineral Taxes		0.03			0.03		0.03			0.03
Netback Excluding Realized Risk Management		6.73			5.34		7.56			6.79
Realized Risk Management Gain (Loss)		(0.66	)		-		(0.77	)		-
Netback Including Realized Risk Management		6.07			5.34		6.79			6.79

Risk Management

Risk management activities in the three and nine months ended September 30, 2018 resulted in realized losses of $7 million and $26 million, respectively (2017 – $nil for the three and nine months ended September 30, 2017).

Deep Basin – Capital Investment

In 2018, capital investment was focused on developing all three operating areas. We completed the majority of our 2018 drilling program in the first three months of the year, and have invested $47 million this year on facilities and infrastructure to support production in our core development areas.

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Drilling and Completions		9		42		113		47
Facilities		2		9		47		11
Other		11		13		33		19
Capital Investment (1)		22		64		193		77

(1) Includes expenditures on PP&E, E&E assets and assets held for sale.

Drilling Activity

The following table summarizes Cenovus’s net well activity:

	Three Months Ended September 30, 2018						Nine Months Ended September 30, 2018
	Drilled		Completed		Tied-in		Drilled (1)		Completed		Tied-in
Elmworth-Wapiti		-		-		-		4		6		9
Kaybob-Edson		-		2		2		8		11		6
Clearwater		-		2		-		3		4		7
Total		-		4		2		15		21		22

(1) Includes 13 operated net horizontal wells and two non-operated net horizontal wells for the nine months ended September 30, 2018.

Future Capital Investment

Upon further review of our capital program, we have updated our 2018 guidance. Our Deep Basin capital investment is forecast to be between $195 million and $215 million in 2018. Updated guidance is available on our website at cenovus.com.

We continue to take a disciplined approach to the development of our Deep Basin assets. We plan to focus capital investment on drilling, completion and tie-in opportunities that have the potential to generate strong returns and increase throughput at underutilized facilities.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over 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 proved reserves. The average depletion rate was approximately $9.82 per BOE and $10.18 per BOE for the three and nine months ended September 30, 2018, respectively (2017 – $10.25 per BOE for the three and nine months ended September 30, 2017).

For the three and nine months ended September 30, 2018 total Deep Basin DD&A was $95 million and $406 million, respectively. On a year-to-date basis, DD&A also included an impairment loss of $100 million recorded in the first quarter associated with our Clearwater cash-generating unit (“CGU”).

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	Q3 2018 Management’s Discussion and Analysis

Assets and Liabilities Held for Sale

In the fourth quarter of 2017, we commenced marketing for sale certain non-core assets located primarily in the East Clearwater area. The properties currently produce approximately 15,000 BOE per day of natural gas and NGLs. These assets were reclassified as assets held for sale and are recorded at the lesser of their carrying amount and fair value less costs to sell.

REFINING AND MARKETING

Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated by our partner, Phillips 66. Our Refining and Marketing segment positions 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 the Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal operations located in Bruderheim, Alberta.

Highlights in the third quarter of 2018 include:

• Refining had a very good operational quarter, resulting in crude utilization rates averaging 107 percent;

• Benefiting from significantly wider WTI-WCS and WTI-WTS crude oil differentials compared with the third quarter of 2017, creating a feedstock cost advantage at both refineries;

• Increasing crude-by-rail shipments at the Bruderheim Energy Terminal, and executing rail agreements for capacity to move additional heavy crude oil from northern Alberta starting in the fourth quarter of 2018; and

• Generating Operating Margin of $436 million compared with $211 million in the third quarter of 2017.

Refinery Operations ⁽¹⁾

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Crude Oil Capacity (Mbbls/d)		460		460		460		460
Crude Oil Runs (Mbbls/d)		492		462		436		439
Heavy Crude Oil		204		213		190		205
Light/Medium		288		249		246		234
Refined Products(Mbbls/d)		518		490		459		467
Gasoline		251		239		225		230
Distillate		170		156		169		147
Other		97		95		65		90
Crude Utilization(percent)		107		100		95		95

(1) Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.

On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by the discount of WCS relative to WTI, and the discount of WTS relative to WTI. 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 optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in the Refineries relative to the total capacity.

Total crude oil runs and refined product output increased for the three months ended September 30, 2018 compared with 2017 due to strong reliability at both refineries, partially offset by planned fall maintenance and an unplanned outage in the third quarter of 2018. On a year-to-date basis, total crude oil runs and refined product output decreased slightly compared with 2017 due to the major planned turnarounds and maintenance at both refineries in the first quarter of 2018. However, in the third quarter and on a year-to-date basis, lower heavy crude oil volumes were processed due to the optimization of the total crude input slate, which resulted in increased volumes of WTS being processed in order to take advantage of the wider WTI-WTS crude oil differential.

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	Q3 2018 Management’s Discussion and Analysis

Financial Results

	Three Months Ended September 30,					Nine Months Ended September 30,
($ millions)	2018			2017		2018		2017
Revenues		3,126			2,161		8,135		7,162
Purchased Product		2,483			1,782		6,664		6,295
Gross Margin		643			379		1,471		867
Expenses
Operating		209			168		724		579
(Gain) Loss on Risk Management		(2	)		-		2		4
Operating Margin		436			211		745		284
Capital Investment		59			38		147		124
Operating Margin Net of Related Capital Investment		377			173		598		160

Gross Margin

The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors, such as the variety of feedstock crude oil processed; 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 the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis.

In the third quarter of 2018, Refining and Marketing gross margin increased primarily due to wider crude oil differentials, creating a feedstock cost advantage, and improved crude utilization rates. In the third quarter of 2018, the Canadian dollar weakened relative to the U.S. dollar compared with the third quarter of 2017, which had a positive impact on our gross margin of approximately $26 million. On a year-to-date basis, wider crude oil price differentials and higher market crack spreads were partially offset by increased operating costs due to the planned turnarounds at both refineries in the first quarter of 2018. For the nine months ended September 30, 2018, the Canadian dollar strengthened relative to the U.S. dollar compared with 2017, which had a negative impact on our gross margin of approximately $21 million.

In the three and nine months ended September 30, 2018, the cost of RINs was $27 million and $108 million, respectively (2017 – $81 million and $208 million, respectively). The cost of RINs declined due primarily to the decrease in RINs benchmark prices.

Operating Expense

Primary drivers of operating expenses in 2018 were maintenance, labour, and utilities. In the third quarter and on a year-to-date basis, operating expenses increased primarily due to higher planned maintenance and turnaround costs compared with 2017.

Refining and Marketing – Capital Investment

	Three Months Ended September 30,				Nine Months Ended September 30,
($ millions)	2018		2017		2018		2017
Wood River Refinery		33		24		91		80
Borger Refinery		26		11		54		40
Marketing		-		3		2		4
		59		38		147		124

Capital expenditures in 2018 focused primarily on capital maintenance and reliability work.

In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and reliability work. Our guidance document dated October 30, 2018 is available on our website at cenovus.com.

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, which range from three to 40 years. The service lives of these assets are reviewed on an annual basis. For the three and nine months ended September 30, 2018, Refining and Marketing DD&A was $56 million and $165 million, respectively (2017 – $53 million and $162 million, respectively).

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	Q3 2018 Management’s Discussion and Analysis

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 including natural gas and crude oil sales and purchases. 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, power costs, interest rates, and foreign exchange rates, as well as realized risk management gains and losses, if any, on interest rate swaps and foreign exchange contracts. As financial instruments are settled, the realized gains and losses are recorded in the reportable segment to which the derivative instrument relates. The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, onerous contract provisions, finance costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.

In the three and nine months ended September 30, 2018, our risk management activities resulted in:

• Unrealized risk management gains of $247 million (2017 – losses of $486 million) and $508 million (2017 – losses of $75 million), respectively; and

• Realized risk management gains on foreign exchange contracts of $3 million (2017 – losses of $1 million) and $2 million (2017 – gains of $142 million), respectively. Risk management gains in 2017 related to hedging activity undertaken to support the Acquisition.

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
General and Administrative		78			114			304			211
Onerous Contract Provisions		630			2			692			6
Finance Costs		183			191			489			458
Interest Income		(5	)		(32	)		(11	)		(59	)
Foreign Exchange (Gain) Loss, Net		(182	)		(350	)		307			(836	)
Revaluation (Gain)		-			-			-			(2,555	)
Transaction Costs		-			1			-			56
Re-measurement of Contingent Payment		(83	)		(43	)		411			(109	)
Research Costs		4			6			23			15
(Gain) Loss on Divestiture of Assets		795			(1	)		794			-
Other (Income) Loss, Net		(11	)		(2	)		(11	)		(4	)
		1,409			(114	)		2,998			(2,817	)

Expenses

General and Administrative

Primary drivers of our general and administrative expenses were workforce costs and office rent. For the three months ended September 30, 2018, general and administrative expenses decreased by $36 million, primarily due to a reduction in long-term employee incentive costs, and $18 million of transition costs related to the Acquisition recorded in the third quarter of 2017. On a year-to-date basis, general and administrative costs increased by $93 million, primarily driven by $48 million in severance costs related to workforce reductions carried out in the first half of the year, higher rent costs, and an increase in long-term employee incentive costs related to a rise in our share price, partially offset by $28 million of transition costs related to the Acquisition that were recorded in the nine months ended September 30, 2017.

Onerous Contract Provisions

The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary, Alberta. The provision represents the present value of the difference between the future lease payments that we are obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at the credit-adjusted risk-free rate.For the three and nine months ended September 30, 2018, we recorded a non-cash provision for onerous contracts of $630 million and $692 million, respectively (2017 – $2 million and $6 million, respectively).

We are actively managing our real estate portfolio, and in the third quarter of 2018, we reached an agreement to sublease a portion of our Calgary office space that was in excess of our current and near-term requirements.

Finance Costs

Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding of the discount on decommissioning liabilities. On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due October 15, 2019, resulting in a redemption premium of US$21 million and associated unamortized discount and debt issue costs of $1 million that were recognized as finance costs in the third quarter of 2018.

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	Q3 2018 Management’s Discussion and Analysis

Finance costs decreased by $8 million in the three months ended September 30, 2018 compared with 2017 due a reduction in total debt, resulting in lower interest expense, partially offset by the premium on redemption of long‑term debt. In the third quarter of 2017, $2.7 billion was outstanding under a committed Bridge Facility in connection with the Acquisition. The full amount of the Bridge Facility was repaid prior to December 31, 2017. On a year-to-date basis, finance costs increased compared with 2017, primarily due to the premium on redemption of long-term debt, and an increase in the unwinding of the discount on decommissioning liabilities, partially offset by lower interest expense.

The weighted average interest rate on outstanding debt for the three and nine months ended September 30, 2018 was 5.1 percent (2017 – 4.7 percent and 4.9 percent, respectively).

Foreign Exchange

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018		2017
Unrealized Foreign Exchange (Gain) Loss		(196	)		(440	)		299		(908	)
Realized Foreign Exchange (Gain) Loss		14			90			8		72
		(182	)		(350	)		307		(836	)

In 2018, unrealized foreign exchange losses were recorded primarily as a result of the translation of our U.S. dollar denominated debt. At September 30, 2018, the Canadian dollar relative to the U.S. dollar was two percent stronger compared with June 30, 2018, creating unrealized gains for the third quarter, and three percent weaker compared with December 31, 2017, creating unrealized losses on a year-to-date basis.

Revaluation (Gain)

Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the definition of a joint operation under IFRS 11, “Joint Arrangements” and as such Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL, as defined under IFRS 10, “Consolidated Financial Statements” and accordingly, FCCL has been consolidated. As required by IFRS 3 when control is achieved in stages, the previously held interest in FCCL was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion, after-tax) was recorded in our 2017 net earnings.

Transaction Costs

For the nine months ended September 30, 2017, we expensed $56 million of transaction costs related to the Acquisition.

Re-measurement of Contingent Payment

Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce the amount of a contingent payment.

The contingent payment is accounted for as a financial option. The fair value of $493 million as at September 30, 2018 was estimated by calculating the present value of the future expected cash flows using an option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings. For the three and nine months ended September 30, 2018 a non-cash re‑measurement gain of $83 million and a loss of $411 million, respectively, was recorded. As at September 30, 2018, $59 million is payable under this agreement.

As at September 30, 2018, average WCS forward pricing for the remaining term of the contingent payment is C$53.06 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately C$45.20 per barrel and C$61.40 per barrel.

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 2018 was $14 million (2017 –$15 million) and $43 million on a year-to-date basis (2017 – $47 million).

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	Q3 2018 Management’s Discussion and Analysis

Income Tax

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
Current Tax
Canada		(15	)		(23	)		(108	)		(232	)
United States		5			(39	)		9			(40	)
Current Tax Expense (Recovery)		(10	)		(62	)		(99	)		(272	)
Deferred Tax Expense (Recovery)		(255	)		(55	)		(304	)		872
Total Tax Expense (Recovery) From Continuing    Operations		(265	)		(117	)		(403	)		600

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.

In the three and nine months ended September 30, 2018 and 2017, a current tax recovery from continuing operations was recorded due to the carryback of current and prior year losses.

Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and the actual amounts subsequently reported on the tax returns, and other permanent differences. Our effective tax rate differs from the statutory tax rate due to non-recognition of capital losses.

DISCONTINUED OPERATIONS

In 2017, Cenovus divested the majority of its Conventional segment which included its heavy oil assets at Pelican Lake, the CO₂ enhanced oil recovery project at Weyburn and conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The associated assets and liabilities were reclassified as held for sale and the results of operations reported as a discontinued operation.

On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of $344 million was recorded on the sale.

Financial Results

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
Gross Sales		-			331			15			1,091
Less: Royalties		1			45			2			145
Revenues		(1	)		286			13			946
Expenses
Transportation and Blending		-			44			1			149
Operating		(2	)		118			(29	)		343
Production and Mineral Taxes		-			4			1			14
(Gain) Loss on Risk Management		-			3			-			19
Operating Margin		1			117			40			421
Depreciation, Depletion and Amortization		-			-			-			190
Exploration Expense		-			-			-			2
Finance Costs		1			3			1			36
Earnings (Loss) From Discontinued Operations Before    Income Tax		-			114			39			193
Current Tax Expense (Recovery)		-			2			-			24
Deferred Tax Expense (Recovery)		1			29			11			27
After-tax Earnings (Loss) From Discontinued    Operations		(1	)		83			28			142
After-tax Gain (Loss) on Discontinuance (1)		2			(440	)		225			(440	)
Net Earnings (Loss) From Discontinued Operations		1			(357	)		253			(298	)

(1) Net of $nil and $83 million deferred tax expense in the three and nine months ended September 30, 2018, respectively (three and nine months ended September 30, 2017 – $163 million deferred tax recovery).

Cenovus Energy Inc.	30
	Q3 2018 Management’s Discussion and Analysis

LIQUIDITY AND CAPITAL RESOURCES

	Three Months Ended September 30,						Nine Months Ended September 30,
($ millions)	2018			2017			2018			2017
Cash From (Used In)
Operating Activities – Continuing Operations		1,258			481			1,630			1,778
Operating Activities – Discontinued Operations		1			111			39			381
Total Operating Activities		1,259			592			1,669			2,159
Investing Activities – Continuing Operations		305			(385	)		(649	)		(15,412	)
Investing Activities – Discontinued Operations		(5	)		897			409			759
Total Investing Activities		300			512			(240	)		(14,653	)
Net Cash Provided (Used) Before Financing Activities		1,559			1,104			1,429			(12,494	)
Financing Activities		(68	)		(1,009	)		(204	)		9,227
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents    Held in Foreign Currency		(2	)		48			30			179
Increase (Decrease) in Cash and Cash Equivalents		1,489			143			1,255			(3,088	)
				September 30, 2018						December31, 2017
Cash and Cash Equivalents								1,865			610
Committed and Undrawn Credit Facility								4,500			4,500

Cash From (Used In) Operating Activities

Cash from operating activities in the third quarter was $1,259 million, an increase of $667 million from the same period in 2017. The increase was primarily due the improvement in crude oil prices, increased production, a focus on cost efficiency, and changes in non-cash working capital, as discussed in the Financial Results section of this MD&A.

Cash from operating activities for the nine months ended September 30, 2018 was $1,669 million, a $490 million decline compared with 2017. Increased Operating Margin, as discussed in the Financial Results section of this MD&A, was offset by a lower current tax recovery and higher general and administrative costs, primarily due to $48 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk management gains of $142 million on foreign exchange contracts, partially offset by transaction costs of $56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital, as discussed in the Financial Results section of this MD&A.

In the three and nine months ended September 30, 2018, cash from operating activities related to discontinued operations was $1 million and $39 million, respectively (2017 – $111 million and $381 million, respectively).

Excluding risk management assets and liabilities, assets and liabilities held for sale, and the current portion of the contingent payment, our working capital was $1,582 million at September 30, 2018 compared with $1,133 million at December 31, 2017.

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

Cash From (Used In) Investing Activities

In the third quarter of 2018, cash from investing activities decreased compared with 2017. Proceeds from the divestiture of CPP in 2018 were less than cash proceeds from the divestitures completed in 2017. Capital investment in 2018 was lower than in 2017, reflecting our continued focus on capital discipline.

On a year-to-date basis, cash used in investing activities was lower in 2018 primarily due to the Acquisition in 2017.

Cash From (Used In) Financing Activities

Cash used in financing activities was lower in the third quarter of 2018 compared with 2017 due primarily to the repayment of a portion of the committed Bridge Facility during the third quarter of 2017. On a year-to-date basis, cash was used in financing activities primarily for dividends paid on common shares. In 2017, cash was generated by financing activities from the issuance of debt and common shares to finance the Acquisition.

Total debt as at September 30, 2018 was $9,824 million (December 31, 2017 – $9,513 million). On September 27, 2018, we initiated the process of redeeming US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. The principal amount of debt outstanding in U.S. dollars remained unchanged since December 31, 2017 (US$7,650 million), with the increase in total debt due to the weakening of the Canadian dollar relative to the U.S. dollar. Upon closing of the debt redemption, the principal amount outstanding will be reduced to US$6,850 million.

As at September 30, 2018, we were in compliance with all of the terms of our debt agreements.

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	Q3 2018 Management’s Discussion and Analysis

Dividends

In the three and nine months ended September 30, 2018, we paid dividends of $0.05 per share or $61 million and $0.15 per share or $183 million, respectively (2017 – $0.05 per share or $62 million and $0.15 per share or $164 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Available Sources of Liquidity

We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2018. Any potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit facility, management of our asset portfolio and other corporate and financial opportunities that may be available to us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and Fitch Ratings.

The following sources of liquidity are available at September 30, 2018:

($ millions)	Term	Amount
Cash and Cash Equivalents	Not applicable		1,865
Committed Credit Facility – Tranche A (1)	November 2021		3,300
Committed Credit Facility – Tranche B (2)	November 2020		1,200

(1) Extended to November 30, 2022, effective October 17, 2018.

(2) Extended to November 30, 2021, effective October 17, 2018

Committed Credit Facility

We have a committed credit facility in place that consists of a $1.2 billion tranche and $3.3 billion tranche. Effective October 17, 2018, we amended the committed credit facility to extend the maturity date of the $1.2 billion tranche to November 30, 2021 and the $3.3 billion tranche to November 30, 2022. As of September 30, 2018, no amounts were drawn on our committed credit facility.

Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed 65 percent; we are well below this limit.

Base Shelf Prospectus

Cenovus has in place a base shelf prospectus which expires in November 2019. As at September 30, 2018, US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market conditions.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, non-GAAP financial metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents. We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense, DD&A, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, and other income (loss), net, calculated on a trailing 12-month basis. These measures are used to steward our overall debt position and as measures of our overall financial strength.

As at	September 30, 2018			December 31, 2017
Net Debt to Capitalization (percent)			30		31
Net Debt to Adjusted EBITDA		3.5x		2.8x

Over the long-term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on our credit facility or repay existing debt, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new debt, or issue new shares.

On October 29, 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. A redemption premium of US$21 million and associated unamortized discount and debt issue cost of $1 million were recognized in the third quarter of 2018.

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

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	Q3 2018 Management’s Discussion and Analysis

Share Capital and Stock-Based Compensation Plans

As at September 30, 2018, there were approximately 1,229 million common shares outstanding (December 31, 2017 – 1,229 million common shares). In the second quarter of 2017, Cenovus closed a bought‑deal common share financing for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance costs).

In addition, Cenovus issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor agreement, and a registration rights agreement which, among other things, restricted ConocoPhillips from selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also restricted from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of the then outstanding common shares of Cenovus. As at September 30, 2018, ConocoPhillips continued to hold these common shares.

Refer to Note 21 of the interim Consolidated Financial Statements for more details on our Stock Option Plan and our Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans.

As at September 30, 2018	Units Outstanding (thousands)		Units Exercisable (thousands)
Common Shares		1,228,790	N/A
Stock Options		35,563		28,271
Other Stock-Based Compensation Plans		14,651		1,526

Contractual Obligations and Commitments

Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations are primarily related to transportation agreements, operating leases on buildings, our risk management program and an obligation to fund our defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less than one year are excluded. For further information, see the notes to the December 31, 2017 Consolidated Financial Statements.

We have total commitments of $20 billion, of which $18 billion are for various transportation commitments, including $553 million in new contracts primarily related to expanded freight and rail terminal and tank contracts. Transportation commitments include $9 billion that are subject to regulatory approval or have been approved but are not yet in service (December 31, 2017 – $9 billion). These agreements are for terms up to 20 years subsequent to the date of commencement and should help align our future transportation requirements with anticipated production growth.  

We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. We continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil.

As at September 30, 2018, there were outstanding letters of credit aggregating $324 million issued as security for performance under certain contracts (December 31, 2017 – $376 million).

Legal Proceedings

We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements.

Contingent Payment

In connection with the Acquisition and related to oil sands production, we agreed to make quarterly payments to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. As at September 30, 2018, the estimated fair value of the
contingent payment was $493 million. See the Corporate and Eliminations section of this MD&A for more details.

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	Q3 2018 Management’s Discussion and Analysis

RISK MANAGEMENT AND RISK FACTORS

For a full understanding of the risks that impact Cenovus, the following discussion should be read in conjunction with the Risk Management and Risk Factors section of our 2017 annual MD&A.

Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pay a dividend to our shareholders and may materially affect the market price of our securities.

The following provides an update on our risks related to commodity prices.

Commodity Prices

Fluctuations in commodity prices and refined product prices impact our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts and market access commitments. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily for purchased product. For 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 Notes 23 and 24 to the interim Consolidated Financial Statements.

Risks Associated with Derivative Financial Instruments

Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Credit Policy.

Financial instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. Financial instruments may limit the benefit to Cenovus if commodity prices increase. These risks are managed through hedging limits that are reviewed annually by the Board, as required by our Market Risk Mitigation Policy.

Impact of Financial Risk Management Activities

	Three Months Ended September 30,
	2018									2017
($ millions)	Realized			Unrealized			Total			Realized			Unrealized			Total
Crude Oil (1)		330			(237	)		93			9			483			492
Refining		(2	)		5			3			-			2			2
Interest Rate		-			(15	)		(15	)		-			1			1
Foreign Exchange		(3	)		-			(3	)		1			-			1
(Gain) Loss on Risk Management		325			(247	)		78			10			486			496
Income Tax Expense (Recovery)		(87	)		65			(22	)		(18	)		(132	)		(150	)
(Gain) Loss on Risk Management, After Tax		238			(182	)		56			(8	)		354			346

(1) 2017 excludes $3 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a discontinued operation.

	Nine Months Ended September 30,
	2018									2017
($ millions)	Realized			Unrealized			Total			Realized			Unrealized			Total
Crude Oil (1)		1,491			(457	)		1,034			72			66			138
Refining		2			(1	)		1			4			(1	)		3
Interest Rate		-			(50	)		(50	)		-			10			10
Foreign Exchange		(2	)		-			(2	)		(142	)		-			(142	)
(Gain) Loss on Risk Management		1,491			(508	)		983			(66	)		75			9
Income Tax Expense (Recovery)		(404	)		135			(269	)		-			(20	)		(20	)
(Gain) Loss on Risk Management, After Tax		1,087			(373	)		714			(66	)		55			(11	)

(1) 2017 excludes $19 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a discontinued operation.

In the three and nine months ended September 30, 2018, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our contract prices. The hedging contracts were established to provide downside protection and support financial resilience following the Acquisition. The majority of these hedging contracts have now expired.

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	Q3 2018 Management’s Discussion and Analysis

Unrealized gains were recorded on our crude oil financial instruments in the three and nine months ended September30,2018 primarily due to the realization of settled positions, while partially offset by losses due to WTI and Brent benchmark price increases.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATion Uncertainties AND ACCOUNTING POLICIES

Management is required to make estimates and assumptions, and use judgment in the application of accounting policies that could have a significant impact on our financial results. Actual results may differ from 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 the interim Consolidated Financial Statements.

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, 2018. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2017.

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, 2018. Further information can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2017.

Changes in Accounting Policies

Effective January 1, 2018, Cenovus adopted IFRS 9, “Financial Instruments” (“IFRS 9”) replacing IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). The adoption of IFRS 9 did not have a material impact on our Consolidated Financial Statements.

Effective January 1, 2018, Cenovus adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. The adoption of IFRS 15 did not have a material impact on our Consolidated Financial Statements.

Further information about changes to our accounting policies resulting from the adoption of IFRS 9 and IFRS 15 can be found in Note 3 to the interim Consolidated Financial Statements.

New Accounting Standards and Interpretations not yet Adopted

A description of additional accounting standards and interpretations that will be adopted in future periods can be found in the notes to the annual Consolidated Financial Statements for the year ended December 31, 2017. The following provides an update to the disclosure in the annual Consolidated Financial Statements for the year ended December 31, 2017.

Leases

On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than twelve months) and leases of low-value assets (as defined in the standard) are exempt from the requirements, and may continue to be treated as operating leases.

Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. We plan to use the modified retrospective approach in our adoption of IFRS 16.

We have completed an initial assessment of the potential impact on our consolidated financial statements. The actual impact of applying IFRS 16 on the consolidated financial statements in the period of initial adoption will

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	Q3 2018 Management’s Discussion and Analysis

depend on future economic conditions, including our borrowing rate at January 1, 2019, the composition of our lease portfolio at the date of adoption, our assessment of whether we will exercise any lease renewal options and the extent we apply the practical expedients available in the standard.

We anticipate that the most significant impact of adopting IFRS 16 will be the recognition of right-of-use (“ROU”) assets and corresponding lease obligations on our operating leases for office space. In addition, the nature of the expenses related to these leases will change as IFRS 16 replaces the straight-line operating lease expense with depreciation expense on the ROU asset and a finance charge on the lease obligation.

On adoption of IFRS 16, we will recognize lease liabilities in relation to leases under the principles of the new standard. These liabilities will be measured at the present value of the remaining lease payments, discounted using our incremental borrowing rate as at January 1, 2019. The associated ROU asset will initially be measured at the amount equal to the lease liability on January 1, 2019 with no impact on retained earnings.

On initial adoption, we intend to use the following practical expedients permitted under the standard. Certain of these expedients are on a lease-by-lease basis and others are applicable by class of underlying assets. Management is still evaluating whether certain leases or classes of assets will not be subject to these elections.

• Apply a single discount rate to a portfolio of leases with similar characteristics;

• Account for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term leases;

• Account for lease payments as an expense and not recognize a ROU asset if the underlying asset is of a low dollar value;

• The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the lease; and

• Use our previous assessment of impairment under IAS 37 for onerous contracts instead of re-assessing the ROU asset for impairment on January 1, 2019.

We do not currently intend to apply any grandfathering practical expedients.

We have assembled a multi-disciplinary transition team and have developed a detailed project plan. A process for identifying contracts in order to identify potential leases has been established and we are in the process of performing detailed evaluations of our contracts that are potentially leases under IFRS 16. Implementation is underway for a software solution that will capture and provide the necessary accounting and disclosure requirements of the new standard. Contract assessments, implementation of changes to policies, internal controls, information systems, and business and accounting processes, will continue throughout 2018. In addition, we are evaluating the impact of the new standard on our non-GAAP measures.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements.

The Company previously limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin Assets, acquired by the Company through a business combination on May 17, 2017. During the second quarter of 2018, the Company completed the evaluation and integration of the controls, policies and procedures of the Deep Basin Assets. No material weaknesses or significant deficiencies were noted during the integration. There have been no other changes to the Company’s ICFR during the three months ended September 30, 2018 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.

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	Q3 2018 Management’s Discussion and Analysis

OUTLOOK

We expect the remainder of 2018 will see continued commodity price volatility and market access constraints for heavy oil exiting Alberta. We continue to look for ways to increase our margins through operating performance and cost leadership, while focusing on safe and reliable operations. Proactively managing our market access commitments and opportunities should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids production.

During the third quarter, we signed rail agreements for capacity to transport approximately 100,000 barrels per day of heavy crude oil to various destinations on the U.S. Gulf Coast, providing a means to move our volumes out of Alberta and to a customer base in other market centers, as well as mitigating some of the price impact of pipeline congestion on those barrels. We expect that transportation challenges faced by our industry will continue to negatively impact heavy oil prices, demonstrating the need for increased utilization of rail within the industry, and approved pipeline projects in North America to proceed as soon as possible.

Through a continued focus on capital discipline and cost reductions, we have reduced the amount of capital needed to sustain our base business and expand our projects, which we believe will further help support our financial resilience.

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

Commodity Prices Underlying our Financial Results

Our crude oil pricing outlook is influenced by the following:

• We expect the general outlook for light crude oil prices to remain constructive and largely tied to the extent to which the U.S. enforces export sanctions on Iranian crude oil, the ability of Saudi Arabia and Russia to increase supply in order to compensate for reduced Iranian oil, and the broader demand reaction to higher prices;

• Overall, crude oil price volatility is expected to increase as inventories return to historical levels;

• We anticipate the Brent-WTI and the WTI-WTS differentials will narrow once additional pipeline capacity out of the Permian basin becomes available in the second half of 2019;

• We expect that the WTI-WCS differential will remain wider than historical averages until additional takeaway capabilities alleviate some of the expected production growth; and

• We anticipate that the pending International Maritime Organization (IMO) regulations will cause light-heavy crude oil price differentials to widen, although the magnitude of the widening remains uncertain.

Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result of U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to remain wide as increasing supply is anticipated to exceed the limits of existing pipeline capacity.

Refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow once the Brent-WTI price differential narrows. The wide WTI‑WCS and Brent-WTI differentials should provide an incentive for U.S. Midwest and Midcontinent refiners to process additional heavy crude oil volumes from Canada or light sweet crude oil from west Texas. In addition, the WTI-WTS differential is expected to narrow as additional pipeline capacity out of west Texas becomes operational.

We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each other, and emerging macro‑economic factors. The Bank of Canada raised its benchmark lending rate twice in 2017 and twice again thus far in 2018, marking a notable shift for Canada towards a tighter monetary policy.

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	Q3 2018 Management’s Discussion and Analysis

Our exposure to the light-heavy crude oil price differentials is composed of both a global light-heavy component as well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of light-heavy crude oil price differentials through the following:

• Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value perspective, our refining business positions us to capture value from both the WTI-WCS differential for Canadian crude oil and the Brent-WTI differential from the sale of refined products;

• Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets, as well as utilizing our crude-by-rail terminal and entering into agreements with third parties to move additional rail volumes to alleviate a portion of near-term takeaway capacity constraints;

• Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into physical supply transactions with fixed price components directly with refiners; and

• Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us flexibility on timing of production and sales of our inventory. We will continue to manage our production well rates in response to pipeline capacity constraints, crude-by-rail export capacity and crude oil price differentials; and

• Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into financial transactions that fix the WTI-WCS differential.

Natural gas and NGLs production associated with our Deep Basin Assets provide improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations.

Key Priorities For the Remainder of 2018

Cost Reductions and Deleveraging

Our focus in 2018 has been to maintain capital discipline and deleverage our balance sheet in an effort to position for increased returns to shareholders. Maintaining our financial resilience and flexibility while continuing to deliver safe and reliable operations remains a top priority.

Over the past three years, we have achieved significant improvements in our operating and sustaining capital costs. In 2018, we continue to see improved efficiencies across Cenovus that are expected to drive additional capital, operating and general and administrative cost reductions. We expect to realize additional savings through improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our business plan, financial resilience and our ability to generate shareholder value.

As at September 30, 2018, our net debt position was less than $8.0 billion, down from $9.6 billion as at June 30, 2018 as a result of strong financial performance, capital discipline and the divestiture of CPP. Through a combination of cash on hand and available capacity on our committed credit facility, we have approximately $6.4 billion of liquidity as at September 30, 2018. On October 29, 2018, our cash position allowed us to redeem US$800 million of our US$1,300 million unsecured notes due October 15, 2019.

We continue to market for sale a package of non-core Deep Basin assets with production of approximately 15,000 BOE per day, and will look for further opportunities to streamline and high-grade our current portfolio of assets. We believe growth in cash flows, proceeds from additional asset divestitures and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than 2.0 times.

Disciplined Capital Investment

As a result of our continued focus on capital discipline and cost efficiencies identified, we have updated our 2018 guidance and anticipate capital investment to be between $1.3 billion and $1.4 billion, a 16 percent decline from our guidance dated December 13, 2017. The majority of our 2018 capital budget is directed towards sustaining oil sands production, while supporting ongoing construction at the Christina Lake phase G expansion and a targeted

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	Q3 2018 Management’s Discussion and Analysis

drilling program in the Deep Basin. With integration remaining an important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability work at the Refineries.

Market Access

Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain firm transportation commitments through a combination of pipelines, rail and marine access to support our growth plans, but leave capacity for optimization. During the third quarter, we signed rail agreements to transport additional volumes of heavy crude oil from northern Alberta to various destinations on the U.S. Gulf Coast starting in the fourth quarter of 2018. While we remain confident that new pipeline capacity will be constructed, these rail agreements will help get our oil to higher-price markets. We expect to supplement firm capacity with active blending, storage, sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.

Advance Focused Technology and Innovation to Achieve Margin Improvement

We have always believed that technology and innovation are differentiating factors in our industry. We focus our innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant improvements and game-changing developments that are implemented to generate value. We aim to complement our internal technology development efforts with external collaboration in an effort to leverage our technology spend.

ADVISORY

Oil and Gas Information

The estimates of reserves were prepared effective December 31, 2017 by independent qualified reserves evaluators, based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. Estimates are presented using an average of three independent qualified reserves evaluators January 1, 2018 price forecasts. For additional information about our reserves and other oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended December 31, 2017.

Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six 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 with 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.

Forward-looking Information

This document contains certain forward-looking statements and forward-looking information (collectively referred to as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future, based on certain assumptions made by us in light of our experience and perception of historical trends. Although we believe that the expectations represented by such forward looking information are reasonable, there can be no assurance that such expectations will prove to be correct.

Forward-looking information in this document is identified by words such as “aim”, “anticipate”, “believe”, “can be”, “capacity”, “committed”, “commitment”, “could”, “expect”, “estimate”, “focus”, “forecast”, “forward”, “future”, “guidance”, “may”, “on track”, “outlook”, “plan”, “position”, “potential”, “priority”, “project”, “pursue”, “schedule”, “strategy”, “should”, “target”, “will”, or similar expressions and includes suggestions of future outcomes, including statements about: all statements about our strategy and related milestones, schedules and planned tactics in furtherance of them, including focus on maximizing shareholder value through cost leadership and realizing the best margins for our products, and our plans to maintain and demonstrate financial discipline while balancing growth and shareholder return, continuing to advance our operational performance and upholding our trusted reputation; expected timing for oil sands expansion phases and associated expected production capacities; projections for 2018 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; our future opportunities for oil and natural gas development; forecast operating and financial results, including forecast sales prices, costs and cash flows; our commitment to continue reducing debt, including our long-term target Net Debt to Adjusted EBITDA ratio; our ability to satisfy payment obligations as they become due; priorities for and approach to capital investment decisions or capital allocation; planned capital expenditures, including the amount, timing and funding sources thereof; all statements with respect to our 2018 guidance estimates; expected future production, including the timing, stability or growth thereof; our expectation that our capital investment and any cash dividends for 2018 will be funded from internally generated cash flows and cash balance on hand; expected reserves; capacities, including for projects, transportation and refining; all statements

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	Q3 2018 Management’s Discussion and Analysis

related to government royalty regimes applicable to Cenovus, which regimes are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect thereto; forecast cost reductions and sustainability thereof; our priorities, including for 2018; future impact of regulatory measures; forecast commodity prices, differentials and trends and expected impact to Cenovus; potential impacts to Cenovus of various risks, including those related to commodity prices; the potential effectiveness of our risk management strategies; new accounting standards, the timing for the adoption thereof by Cenovus, and anticipated impact on the Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales; expected impacts of the contingent payment; future use and development of technology and associated future outcomes; our ability to access and implement all technology necessary to efficiently and effectively operate our assets and achieve expected future cost reductions; and projected growth and projected shareholder return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The factors or assumptions on which the forward-looking information is based include: forecast oil and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials and other assumptions identified in Cenovus’s 2018 guidance, available at cenovus.com; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability thereof; expected condensate prices; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to our share price and market capitalization over the long-term; future narrowing of crude oil differentials; realization of expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates when pipeline capacity has improved and crude oil differentials have narrowed; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgements; future use and development of technology and associated expected future results; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; achievement of expected impacts of the Acquisition; successful completion of the integration of the Deep Basin Assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development plans; our ability to complete asset sales, including with desired transaction metrics and the timelines we expect; forecast bitumen, crude oil, natural gas liquids, condensate and refined products prices, forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized Western Canadian Select (“WCS”) prices and WCS prices used to calculate the contingent payment to ConocoPhillips; our ability to access and implement all technology necessary to achieve expected future results; our ability to implement capital projects or stages thereof in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2018 guidance, as updated October 30, 2018, assumes: Brent prices of US$74.70/bbl, WTI prices of US$68.00/bbl; WCS of US$41.60/bbl; NYMEX natural gas prices of US$2.95/MMBtu; AECO natural gas prices of $1.50/GJ; Chicago 3-2-1 crack spread of US$16.30/bbl; and an exchange rate of $0.78 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially, include: possible failure by us to realize the anticipated benefits of and synergies from the Acquisition; possible failure to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; possible failure to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline capacity and crude oil differentials have improved; the effectiveness of our risk management program, including the impact of derivative financial instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost estimates; commodity prices, currency and interest rates; possible lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; accuracy of our share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; exposure to counterparties and partners, including ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of our crude-by-rail terminal, including health, safety and environmental risks; maintaining desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; accuracy of our accounting estimates and judgements; our ability to replace and expand oil and gas reserves; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of our assets or goodwill from time to time; our ability to maintain our relationship with our partners and to successfully manage and operate our integrated business;

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	Q3 2018 Management’s Discussion and Analysis

reliability of our assets including in order to meet production targets; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing margins; inflationary pressures on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and its application to our business; risks associated with climate change; the timing and the costs of well and pipeline construction; our ability to secure adequate and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; changes in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on our business, our financial results and our Consolidated Financial Statements; changes in general economic, market and business conditions; the political and economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits and regulatory actions against us.

Statements relating to “reserves” are deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of our material risk factors, see “Risk Management and Risk Factors” in our MD&A for the period ended December 31, 2017, available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com and the updates under “Risk Management and Risk Factors” in this MD&A.

ABBREVIATIONS

The following abbreviations have been used in this document:

Crude Oil		Natural Gas
bbl	Barrel	Mcf	thousand cubic feet
Mbbls/d	thousand barrels per day	MMcf	million cubic feet
MMbbls	million barrels	Bcf	billion cubic feet
BOE	barrel of oil equivalent	MMBtu	million British thermal units
MMBOE	million barrel of oil equivalent	GJ	gigajoule
WTI	West Texas Intermediate	AECO	Alberta Energy Company
WCS	Western Canadian Select	NYMEX	New York Mercantile Exchange
CDB	Christina Dilbit Blend
MSW	Mixed Sweet Blend West
WTS	West Texas Sour

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	Q3 2018 Management’s Discussion and Analysis

NETBACK RECONCILIATIONS

The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our interim Consolidated Financial Statements.

Total Production From Continuing Operations

Continuing Upstream Financial Results

	Per Interim Consolidated Financial Statements						Adjustments											Basis of Netback Calculation
Three Months Ended September 30, 2018 ($ millions)	Oil Sands(1)		Deep Basin(1)		Continuing Operations		Condensate			Inventory		Internal Usage(2)			Other			Continuing Operations
Gross Sales		2,992		214		3,206		(1,268	)		-		(34	)		(15	)		1,889
Royalties		275		11		286		-			-		-			-			286
Transportation and Blending		1,482		20		1,502		(1,268	)		-		-			-			234
Operating		230		103		333		-			-		(34	)		(7	)		292
Netback		1,005		80		1,085		-			-		-			(8	)		1,077
(Gain) Loss on Risk Management		323		7		330		-			-		-			-			330
Operating Margin		682		73		755		-			-		-			(8	)		747

	Per Interim Consolidated Financial Statements						Adjustments											Basis of Netback Calculation
Three Months Ended September 30, 2017 ($ millions)	Oil Sands(1)		Deep Basin(1)		Continuing Operations		Condensate			Inventory			Internal Usage(2)		Other			Continuing Operations
Gross Sales		2,210		200		2,410		(863	)		-			-		(19	)		1,528
Royalties		54		13		67		-			-			-		-			67
Transportation and Blending		1,066		22		1,088		(863	)		1			-		(1	)		225
Operating		259		101		360		-			-			-		(9	)		351
Netback		831		64		895		-			(1	)		-		(9	)		885
(Gain) Loss on Risk Management		9		-		9		-			-			-		-			9
Operating Margin		822		64		886		-			(1	)		-		(9	)		876

	Per Interim Consolidated Financial Statements						Adjustments											Basis of Netback Calculation
Nine Months Ended September 30, 2018 ($ millions)	Oil Sands(1)		Deep Basin(1)		Continuing Operations		Condensate			Inventory		Internal Usage(2)			Other			Continuing Operations
Gross Sales		8,646		714		9,360		(3,967	)		-		(131	)		(49	)		5,213
Royalties		512		62		574		-			-		-			-			574
Transportation and Blending		4,616		72		4,688		(3,967	)		-		-			(4	)		717
Operating		789		303		1,092		-			-		(131	)		(28	)		933
Production and Mineral Taxes		-		1		1		-			-		-			-			1
Netback		2,729		276		3,005		-			-		-			(17	)		2,988
(Gain) Loss on Risk Management		1,465		26		1,491		-			-		-			-			1,491
Operating Margin		1,264		250		1,514		-			-		-			(17	)		1,497

	Per Interim Consolidated Financial Statements						Adjustments											Basis of Netback Calculation
Nine Months Ended September 30, 2017 ($ millions)	Oil Sands(1)		Deep Basin(1)		Continuing Operations		Condensate			Inventory			Internal Usage(2)		Other			Continuing Operations
Gross Sales		4,938		324		5,262		(2,060	)		-			-		(30	)		3,172
Royalties		117		21		138		-			-			-		-			138
Transportation and Blending		2,511		32		2,543		(2,060	)		1			-		(3	)		481
Operating		663		156		819		-			-			-		(62	)		757
Netback		1,647		115		1,762		-			(1	)		-		35			1,796
(Gain) Loss on Risk Management		72		-		72		-			-			-		-			72
Operating Margin		1,575		115		1,690		-			(1	)		-		35			1,724

(1) Found in Note 1 of the interim Consolidated Financial Statements.

(2) Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.

Cenovus Energy Inc.	42
	Q3 2018 Management’s Discussion and Analysis

Oil Sands

	Basis of Netback Calculation									Adjustments						Per Interim Consolidated Financial Statements(1)
Three Months Ended September 30, 2018 ($ millions)	Foster Creek		Christina Lake		Total Crude Oil		Natural Gas			Condensate		Inventory		Other		Total Oil Sands
Gross Sales		845		876		1,721		-			1,268		-		3		2,992
Royalties		187		88		275		-			-		-		-		275
Transportation and Blending		106		108		214		-			1,268		-		-		1,482
Operating		118		112		230		(1	)		-		-		1		230
Netback		434		568		1,002		1			-		-		2		1,005
(Gain) Loss on Risk Management		134		189		323		-			-		-		-		323
Operating Margin		300		379		679		1			-		-		2		682

	Basis of Netback Calculation								Adjustments								Per Interim Consolidated Financial Statements(1)
Three Months Ended September 30, 2017 ($ millions)	Foster Creek		Christina Lake		Total Crude Oil		Natural Gas		Condensate		Inventory			Other			Total Oil Sands
Gross Sales		603		737		1,340		1		863		-			6			2,210
Royalties		43		11		54		-		-		-			-			54
Transportation and Blending		126		79		205		-		863		(1	)		(1	)		1,066
Operating		138		116		254		1		-		-			4			259
Netback		296		531		827		-		-		1			3			831
(Gain) Loss on Risk Management		2		7		9		-		-		-			-			9
Operating Margin		294		524		818		-		-		1			3			822

	Basis of Netback Calculation								Adjustments							Per Interim Consolidated Financial Statements(1)
Nine Months Ended September 30, 2018 ($ millions)	Foster Creek		Christina Lake		Total Crude Oil		Natural Gas		Condensate		Inventory		Other			Total Oil Sands
Gross Sales		2,266		2,405		4,671		1		3,967		-		7			8,646
Royalties		376		136		512		-		-		-		-			512
Transportation and Blending		354		295		649		-		3,967		-		-			4,616
Operating		409		371		780		1		-		-		8			789
Netback		1,127		1,603		2,730		-		-		-		(1	)		2,729
(Gain) Loss on Risk Management		638		827		1,465		-		-		-		-			1,465
Operating Margin		489		776		1,265		-		-		-		(1	)		1,264

	Basis of Netback Calculation								Adjustments								Per Interim Consolidated Financial Statements(1)
Nine Months Ended September 30, 2017 ($ millions)	Foster Creek		Christina Lake		Total Crude Oil		Natural Gas		Condensate		Inventory			Other			Total Oil Sands
Gross Sales		1,319		1,541		2,860		7		2,060		-			11			4,938
Royalties		87		30		117		-		-		-			-			117
Transportation and Blending		281		170		451		-		2,060		(1	)		1			2,511
Operating		328		280		608		6		-		-			49			663
Netback		623		1,061		1,684		1		-		1			(39	)		1,647
(Gain) Loss on Risk Management		33		39		72		-		-		-			-			72
Operating Margin		590		1,022		1,612		1		-		1			(39	)		1,575

(1) Found in Note 1 of the interim Consolidated Financial Statements.

Cenovus Energy Inc.	43
	Q3 2018 Management’s Discussion and Analysis

Deep Basin

	Basis of Netback Calculation		Adjustments		Per Interim Consolidated Financial Statements(1)
Three Months Ended September 30, 2018 ($ millions)	Total		Other(2)		Total Deep Basin
Gross Sales		202		12		214
Royalties		11		-		11
Transportation and Blending		20		-		20
Operating		97		6		103
Netback		74		6		80
(Gain) Loss on Risk Management		7		-		7
Operating Margin		67		6		73

	Basis of Netback Calculation		Adjustments		Per Interim Consolidated Financial Statements(1)
Three Months Ended September 30, 2017 ($ millions)	Total		Other(2)		Total Deep Basin
Gross Sales		187		13		200
Royalties		13		-		13
Transportation and Blending		20		2		22
Operating		96		5		101
Netback		58		6		64
(Gain) Loss on Risk Management		-		-		-
Operating Margin		58		6		64

	Basis of Netback Calculation		Adjustments		Per Interim Consolidated Financial Statements(1)
Nine Months Ended September 30, 2018 ($ millions)	Total		Other(2)		Total Deep Basin
Gross Sales		672		42		714
Royalties		62		-		62
Transportation and Blending		68		4		72
Operating		283		20		303
Production and Mineral Taxes		1		-		1
Netback		258		18		276
(Gain) Loss on Risk Management		26		-		26
Operating Margin		232		18		250

	Basis of Netback Calculation		Adjustments		Per Interim Consolidated Financial Statements(1)
Nine Months Ended September 30, 2017 ($ millions)	Total		Other(2)		Total Deep Basin
Gross Sales		305		19		324
Royalties		21		-		21
Transportation and Blending		30		2		32
Operating		143		13		156
Netback		111		4		115
(Gain) Loss on Risk Management		-		-		-
Operating Margin		111		4		115

(1) Found in Note 1 of the interim Consolidated Financial Statements.

(2) Reflects operating margin from processing facility.

Cenovus Energy Inc.	44
	Q3 2018 Management’s Discussion and Analysis

The following table provides the sales volumes used to calculate Netback.

Sales Volumes

	Three Months Ended September 30,					Nine Months Ended September 30,
(barrels per day, unless otherwise stated)	2018			2017		2018			2017
Oil Sands
Foster Creek		171,936			157,850		169,006			114,466
Christina Lake		206,688			206,338		209,909			150,656
Total Oil Sands Crude Oil		378,624			364,188		378,915			265,122
Natural Gas (MMcf per day)		-			6		2			11
Total Oil Sands (BOE per day)		378,625			365,210		379,189			266,940
Deep Basin
Total Liquids		32,269			32,864		33,918			16,706
Natural Gas(MMcf per day)		520			495		546			251
Total Deep Basin (BOE per day)		118,920			115,301		124,984			58,516
Less: Internal Consumption (1)(MMcf per day)		(293	)		-		(305	)		-
Sales From Continuing Operations (1) (BOE per day)		448,712			480,512		453,340			325,457

(1) Less natural gas volumes used for internal consumption by the Oil Sands segment.