Exhibit 99.1

Cenovus delivers strong third-quarter operating results

Company generates free funds flow, reduces net debt

Calgary, Alberta (October 29, 2020) – Cenovus Energy Inc. (TSX: CVE) (NYSE: CVE) continued to deliver strong operational performance and further improved its financial resilience in the third quarter by remaining committed to disciplined capital investment, cost leadership and leveraging the flexibility of its assets and marketing strategy to generate positive free funds flow. The company took advantage of the higher commodity prices by ramping up production from its oil sands assets and selling barrels stored in the preceding quarter. Higher crude oil prices and increased sales volumes allowed the company to achieve free funds flow for the third quarter of $266 million, which contributed to a reduction in net debt to $7.5 billion at the end of the period.

“The third quarter clearly demonstrated the strength and reliability of our operations and our ability to effectively manage production and sales by storing barrels when prices declined and then capitalizing on a price recovery to optimize returns,” said Alex Pourbaix, Cenovus President & Chief Executive Officer. “We continue to find ways to optimize our cost structure, expand our market access, and strengthen the balance sheet. We believe the proposed transaction with Husky Energy, announced earlier this week, will address these priorities, positioning us to come through this period more resilient, with increased and stable free funds flow, supporting accelerated deleveraging and returns to shareholders.”

Cenovus Husky transaction

Cenovus’s planned transaction with Husky Energy Inc. will create a resilient integrated Canadian energy leader with an advantaged upstream and downstream portfolio that is expected to provide enhanced free funds flow generation and superior return opportunities for investors.

The companies are advancing the arrangement process, with regulatory filings being prepared and filed. The Joint Management Information Circular is being prepared for expected distribution by mid-November and key members of the combined integration teams have been identified.

“Teams from both Cenovus and Husky are moving the process along so that we can be in a position to implement the vision of the new company as soon as possible,” said Pourbaix, who will lead the combined entity as President & Chief Executive Officer following a closing anticipated in the first quarter of 2021. “We’re very excited about the opportunities that the combination of our two companies creates for all of our stakeholders.”

Business flexibility and financial discipline

In the third quarter of 2020, Cenovus increased crude oil production at its oil sands facilities and overall sales in response to higher commodity prices while remaining focused on maintaining its low operating and capital cost structure and deleveraging its balance sheet. The company was able to use the flexibility of its oil sands assets and available production curtailment credits to increase output above the Alberta government’s mandatory limits. Cenovus achieved average oil sands production of almost 386,000 barrels per day (bbls/d) in the third quarter, up from 373,000 bbls/d in the previous quarter and a 9% increase from the same period a year earlier.

The company also employed its suite of transportation and storage assets to capture increased value from the higher prices. During the quarter, Cenovus sold crude oil inventory built up from April to June when crude oil prices were significantly lower. The average benchmark price for Western Canadian Select (WCS) crude oil almost doubled to $42.41 per barrel (bbl) in the third quarter from $22.42/bbl in the second quarter of 2020 and significantly higher than the April benchmark price of $4.92/bbl.

These actions combined with continued capital spending and operating cost discipline contributed to significantly improved financial performance during the third quarter compared with the second quarter of this year. Third quarter capital investment in the company’s oil sands and conventional segments was flat compared with the second quarter of 2020 and approximately 50% lower on a year-over-year basis after the company took decisive action earlier this year to respond to lower commodity prices and the rapid weakening of the business environment.

“Our people in the field have done an excellent job of maintaining strong operating performance even as we reduced capital spending due to the lower price environment and the challenges brought on by COVID-19,” said Pourbaix. “Safe and reliable operations will continue to be a priority, along with a commitment to finding ways of further reducing our overall costs to help us maintain our competitive advantage and remain an attractive long-term investment.”

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Third-quarter financial results

Cenovus recorded cash from operating activities of $732 million in the third quarter compared with $834 million of cash used in operating activities in the second quarter of 2020. The company generated third-quarter adjusted funds flows of $414 million and free funds flow of $266 million driven by the recovery in benchmark commodity prices, the ramp-up of production in the quarter and increased sales of barrels that were stored in the second quarter and were withdrawn from storage and sold as prices recovered.

The company had a third-quarter operating loss of $452 million and a net loss of $194 million compared with operating earnings of $284 million and net earnings of $187 million in the same period in 2019. The operating loss was due to lower cash from operating activities and adjusted funds flow, and higher depreciation, depletion, and amortization that included an impairment charge of $450 million associated with a refinery Cenovus co-owns with the operator, Phillips 66, at Borger, Texas, partially offset by non-operating realized foreign exchange gains of $30 million. The net loss in the third quarter of this year was due to the operating loss, partially offset by unrealized risk management gains of $135 million, non-operating unrealized foreign exchange gains of $152 million compared with losses of $87 million, and a deferred income tax recovery of $177 million compared with a deferred income tax expense of $46 million in the third quarter of 2019. Overall financial results were negatively impacted compared with the third quarter of 2019 largely due to a one-third decline in benchmark crude oil prices driven by the COVID-19 pandemic.

The impairment charge taken on the Borger refinery reflects current market conditions surrounding reduced demand for refined products, and the expectation of continued lower market crack spreads in the market.

At the end of the third quarter, Cenovus’s net debt declined to approximately $7.5 billion from $8.2 billion at the end of the second quarter of 2020, in part due to directing positive free funds flow towards debt repayment. In July 2020, Cenovus issued US$1.0 billion in 5.375% senior unsecured notes due in 2025 with net proceeds used to repay borrowings on the company’s credit facilities.

Response to COVID-19

Earlier this year, Cenovus responded quickly to the COVID-19 pandemic and in the past several months has implemented special protocols and measures to protect the health and safety of its workforce and to ensure the continuity of its business. With these measures now well established, the company recently lifted its mandatory work from home order that had been in place for most staff since mid-March and is now implementing a gradual return to its Calgary office. Cenovus continues to closely monitor the COVID-19 situation and will not compromise on the health and safety of its workers or on its commitment to safe and reliable operations.

Operating highlights

Cenovus’s upstream and refining assets continued to deliver safe and reliable operational performance during the third quarter. Planned maintenance and repair work in the third quarter partially offset production increases at both of the company’s oil sands operations and contributed to lower output at its conventional properties. The work was deferred from earlier in the year due to reduced staffing at our operations as a result of COVID-19.

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Health and safety

Cenovus remains focused on delivering industry-leading safety performance through its focus on risk management and asset integrity, delivering very strong results through the first nine months of the year. The company has achieved noteworthy year-over-year improvements in focus areas of Significant Incident Frequency (SIF) and Process Safety Events. The company recorded a Significant Incident Frequency of zero compared with 0.12 in the third quarter of 2019 and no Process Safety Events compared with one in the same period a year earlier. Total Recordable Injury Frequency has largely remained flat compared with the same period in 2019 when Cenovus achieved its best ever performance in this area. These results included significant safety milestones for Drilling Operations as well as Completions and Well Services at our Christina Lake oil sands facility, with both groups achieving one year without a recordable incident during the third quarter. The company’s Conventional operations also continued to deliver strong safety performance, marking a one-year milestone in September since recording a significant process safety event.

Oil sands

For the third quarter, Christina Lake had average production of 220,983 bbls/d, and Foster Creek had average production of 164,954 bbls/d. The company achieved combined oil sands production of 385,937 bbls/d in the third quarter, compared with 354,595 bbls/d in the same period a year earlier. During the third quarter of 2020, Cenovus was able to produce additional barrels of oil, despite curtailment, due to the purchase of low-cost production curtailment credits from other companies.

Oil sands operating margin in the third quarter increased to $638 million from $125 million in the second quarter of 2020 due to higher average realized crude oil sales price and higher sales volumes, partially offset by increased transportation and blending costs and higher royalties. Non-fuel per-unit operating costs in the third quarter declined 5% at Christina Lake and were relatively flat at Foster Creek compared with the same period a year earlier. Overall, third-quarter oil sands per-unit operating costs were $7.53/bbl, up 9% from the same period a year earlier and 2% from the second quarter of 2020. The year-over-year increase in costs was primarily due to higher per-barrel fuel costs as a result of higher natural gas prices, partially offset by increased sales volumes. Transportation costs were lower due to the suspension of the company’s crude-by-rail program in response to unfavourable pricing fundamentals for shipping by rail.

Cenovus’s oil sands facilities continue to operate at industry-leading steam-to-oil ratios (SOR). At Christina Lake, the SOR was 2.1 in the third quarter, in line with both the second quarter of 2020 and the same period a year earlier. The SOR at Foster Creek was 2.7, level with the preceding quarter of 2020 and the third quarter a year earlier.

Conventional

Conventional production averaged approximately 85,862 barrels of oil equivalent per day (BOE/d) in the third quarter, a 9% decrease from the same period in 2019. The year-over-year decrease was due to natural declines from limited capital investment and increased downtime due to a planned turnaround at a non-operated natural gas plant, partially offset by the addition of Marten Hills heavy oil production starting in 2020.

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Capital investment in the company’s Conventional segment is forecast to range between $75 million and $85 million for full-year 2020. This includes an incremental $30 million of capital investment in the fourth quarter, relative to Deep Basin guidance, for a two-rig drilling program targeting low-risk, high-return development wells near natural gas plants owned and operated by Cenovus to take advantage of an expected strengthening in commodity prices during the winter heating season. We continue to take a disciplined approach to the development of our Conventional assets.

Total conventional operating costs increased 5% to $81 million in the third quarter of 2020 compared with the same period in the previous year and remained flat relative to the second quarter of 2020. Per-barrel operating costs averaged $9.55/BOE compared with $8.21/BOE in the third quarter of 2019 due to lower sales volumes, increased costs for planned repairs and maintenance related to turnaround activities and higher third-party processing fees.

Full-year guidance dated April 1, 2020 is available on our website at cenovus.com.

Refining and marketing

Cenovus’s Wood River, Illinois and Borger refineries, which are co-owned with the operator, Phillips 66, maintained safe and reliable performance in the third quarter of 2020. Crude oil runs at both refineries were reduced in response to the economic slowdown due to COVID-19. Crude runs averaged 382,000 bbls/d in the third quarter, an increase of 18% from the second quarter of 2020 and 18% lower from the same period in 2019.

Cenovus had a refining and marketing operating margin shortfall of $74 million in the third quarter compared with positive operating margin of $126 million in the same period of 2019, primarily due to reduced market crack spreads, lower crude oil runs and crude advantage, partially offset by lower operating costs.

Cenovus’s refining operating margin is calculated on a first-in, first-out (FIFO) inventory accounting basis. Using the last-in, first-out (LIFO) accounting method employed by most U.S. refiners, operating margin from refining and marketing would have been $39 million lower in the third quarter, compared with $8 million lower in the same period in 2019.

Sustainability

Cenovus is committed to maintaining world-class safety performance and environmental, social and governance (ESG) leadership, including robust ESG disclosure. The company will continue earning its position as a global energy supplier of choice by advancing clean technology and reducing emissions intensity, including maintaining its ambition of achieving net zero emissions by 2050. Advancing environmental stewardship and maintaining strong local community relationships, with a focus on Indigenous economic reconciliation, will continue to be a priority for the company following the close of the Husky transaction. Leading safety practices, strong governance and advancing diversity and inclusion will remain central to the company’s ESG commitments.

“Striking the right balance among environmental, economic and social considerations is core to our strategy of creating long-term value and business resilience for our company,” said Pourbaix. “We will demonstrate ongoing leadership through our support of local

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communities, caring for the environment and emissions reduction efforts to support the transition to a low-carbon energy future.”

The targets Cenovus released earlier this year for its key ESG focus areas involved a robust process to ensure alignment with the company’s business plan and strategy. The company remains committed to pursuing meaningful, measurable ESG targets and will undertake a thorough analysis of the most meaningful targets to pursue for its expanded portfolio. Once that work is complete in 2021 and approved by the Board, the new targets and plans to achieve them will be disclosed.

ADVISORY

Basis of Presentation

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

Barrels of Oil Equivalent

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

Non-GAAP Measures and Additional Subtotal

This news release contains references to adjusted earnings before interest, taxes, depreciation and amortization (EBITDA), adjusted funds flow, free funds flow, operating earnings (loss) and net debt, which are non-GAAP measures, and operating margin, which is an additional subtotal found in Note 1 of Cenovus's Interim Consolidated Financial Statements for the period ended September 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com). These measures do not have a standardized meaning as prescribed by IFRS. Readers should not consider these measures in isolation or as a substitute for analysis of the company's results as reported under IFRS. These measures are defined differently by different companies and therefore are not comparable to similar measures presented by other issuers. For definitions, as well as reconciliations to GAAP measures, and more information on these and other non-GAAP

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measures and additional subtotals, refer to “Non-GAAP Measures and Additional Subtotals” on page 1 of Cenovus's Management's Discussion & Analysis (MD&A) for the period ended September 30, 2020 (available on SEDAR at sedar.com, on EDGAR at sec.gov and Cenovus's website at cenovus.com).

Forward-looking Information

This news release 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 United States 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 Cenovus believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking information as actual results may differ materially from those expressed or implied.

Forward-looking information in this document is identified by words such as “achieve”, “advance”, “aim”, “ambition”, “anticipate”, “believe”, “commitment”, “continue”, “contribute”, “development”, “drive”, “ensure”, “expect”, “focus”, “forecast”, “goal”, “guidance”, “maintain”, “opportunity”, “plan”, “position”, “potential”, “priority”, “protect”, “realize”, “target” and “will” or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: our expectations regarding the volatility of commodity prices and our ability to withstand an extended period of low oil prices; the timing of distribution of the Joint Management Information Circular and completion of the plan of arrangement with Husky Energy Inc. (the “Husky Transaction”); the timing and anticipated receipt of required regulatory, court and securityholder approvals for the Husky Transaction and other customary closing conditions; anticipated benefits of the Husky Transaction; our ability to generate shareholder returns; the robust performance of our assets; finding ways to further reduce our overall costs; maintaining our low operating and capital cost structure and deleveraging our balance sheet to maintain our competitive advantage and remain an attractive investment; maintaining our priority of safe and reliable operations; delivering industry-leading safety performance through our focus on risk management and asset integrity; maintaining world-class ESG leadership and disclosure; maintaining our ambition of achieving net zero emissions by 2050; disclosing new ESG targets and priorities and plans to achieve them for our expanded portfolio; monitoring the COVID-19 situation and not compromising the health and safety of our workers; forecast capital investment in our Conventional segment; and maintaining a disciplined approach to development of our Conventional segment.

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 our forward-looking information is based include, but are not limited to: 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 2020 guidance (dated April 1, 2020), available at cenovus.com; the satisfaction of the conditions to closing of the Husky Transaction in a timely manner and complete the arrangement on the expected terms; the

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combined company's ability to successfully integrate the businesses of Cenovus and Husky; access to sufficient capital to pursue any development plans associated with full ownership of Husky; the combined company's ability to issue securities; the impacts the Husky Transaction may have on the current credit ratings of Cenovus and Husky and the credit rating of the combined company following closing; our ability to achieve our ambition of net zero emissions by 2050; our ability to set new ESG targets for our expanded portfolio; global demand for refined products will resume and prices will rise; continued access to short-term capital such as credit and demand facilities; continued impact of measures implemented to enhance the company’s resilience; 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 or continued narrowing of crude oil differentials; the ability of our refining capacity, dynamic storage, existing pipeline commitments and financial hedge transactions to partially mitigate a portion of our WCS crude oil volumes against wider differentials; our ability to adjust production while maintaining reservoir integrity; availability of new ways to get our products to new customers; opportunities to work with industry partners to find innovative market-based solutions aimed at refining more Canadian oil in Canada; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; accounting estimates and judgments; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects, development programs or stages thereof; our ability to generate sufficient liquidity to meet our current and future obligations; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; our ability to develop, access and implement all technology and equipment necessary to achieve expected future results, and that such results are realized.

2020 guidance, dated April 1, 2020, assumes: Brent prices of US$39.00/bbl, WTI prices of US$34.00/bbl; WCS prices of US$18.50/bbl; Differential WTI-WCS of US$15.50/bbl; AECO natural gas prices of $2.00/Mcf; Chicago 3-2-1 crack spread of US$8.30/bbl; and an exchange rate of $0.70 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially include, but are not limited to: volatility of and other assumptions regarding commodity prices, including the extent to which COVID-19 impacts the global economy and harms commodity prices; the satisfaction of the conditions to closing of the Husky Transaction in a timely manner and complete the arrangement on the expected terms; our ability to successfully integrate the businesses of Cenovus and Husky; access to sufficient capital to pursue any development plans associated with full ownership of Husky; our ability to issue securities after the Husky Transaction closes; the impacts the transaction may have on the current credit ratings of Cenovus and Husky and the credit rating of the company following closing; our ability to achieve our ambition of net zero emissions by 2050; our ability to set new ESG targets for our expanded portfolio; the extent to which COVID-19 and fluctuations in commodity prices associated with COVID-19 impacts our business, results of operations and financial condition, all of which will depend on future developments that are highly uncertain and difficult to predict, including, but not limited to, the duration and spread of the pandemic, its severity, the actions taken to contain COVID-19 or treat its impact and how quickly economic activity normalizes; a resurgence in cases of COVID-19, which has occurred in certain locations and the possibility of which in other locations remains high and

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creates ongoing uncertainty that could result in restrictions to contain the virus being re-imposed or imposed on a more strict basis, including restrictions on movement and businesses; the success of our COVID-19 protocols and safety measures to protect workers; maintaining sufficient liquidity to sustain operations through a prolonged market downturn; the duration of the market downturn; excessive widening of the WTI-WCS differential; unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the effectiveness of our risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; 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; our ability to maintain desirable ratios of net debt to adjusted EBITDA as well as 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 sustaining capital expenditures; changes in credit ratings applicable to us or any of our securities; accuracy of our reserves, future production and future net revenue estimates; accuracy of our accounting estimates and judgments; 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 relationships with our partners and to successfully manage and operate our integrated business; reliability of our assets including in order to meet production targets; our ability to access or implement some or all of the technology necessary to efficiently and effectively operate our assets and achieve expected future results; unexpected cost increases or potential disruption or unexpected technical difficulties in developing new products and manufacturing processes and in constructing or modifying manufacturing or refining facilities; refining and marketing margins; cost escalations; potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry reputation and litigation related thereto; unexpected difficulties in producing, transporting or refining of bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to our business, including potential cyberattacks; risks associated with climate change and our assumptions relating thereto; 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 or storage capacity; possible failure to obtain and retain qualified staff and equipment in a timely and cost efficient manner; 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; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political and economic conditions in the countries in which we operate or which we supply; the occurrence of unexpected events, such as pandemics, fires, severe weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events, and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.

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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 Cenovus’s material risk factors, refer to “Risk Management and Risk Factors” in the Corporation’s annual 2019 MD&A and the MD&A for the period ended September 30, 2020, and to the risk factors described in other documents Cenovus files from time to time with securities regulatory authorities in Canada, available on SEDAR at sedar.com, and with the U.S. Securities and Exchange Commission on EDGAR at sec.gov, and on the Corporation’s website at cenovus.com.

Cenovus Energy Inc.

Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It is committed to maximizing value by sustainably developing its assets in a safe, innovative and cost-efficient manner, integrating environmental, social and governance considerations into its business plans. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and British Columbia. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE and are listed on the Toronto and New York stock exchanges. For more information, visit cenovus.com.

Find Cenovus on Facebook, Twitter, LinkedIn, YouTube and Instagram.

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Exhibit 99.2

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 28, 2020, should be read in conjunction with our September 30, 2020 unaudited interim Consolidated Financial Statements and accompanying notes (“interim Consolidated Financial Statements”), the December 31, 2019 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”) and the December 31, 2019 MD&A (“annual MD&A”). All of the information and statements contained in this MD&A are made as of October 28, 2020, 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 and the annual MD&A are reviewed by the Audit Committee and recommended for approval by the Cenovus Board of Directors (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, (which includes references to “dollar” or “$”), 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, 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 Note 1 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 and Financial Results, Liquidity and Capital Resources, or Advisory sections of this MD&A.

OVERVIEW OF CENOVUS

We are a Canadian integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares listed on the Toronto and New York stock exchanges. 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 approximately 472,000 BOE per day for the three months ended September 30, 2020. We also conduct marketing activities and have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of 382,000 gross barrels per day of crude oil feedstock into an average of 397,000 gross barrels per day of refined products in the three months ended September 30, 2020.

For a description of our operations, refer to the Reportable Segments section of this MD&A.

On October 25, 2020, Cenovus and Husky Energy Inc. (“Husky”) announced that they have entered into a definitive agreement to combine the two companies in an all-stock transaction to create a new integrated Canadian oil and natural gas company (the “Husky Transaction”). Upon completion of the Husky Transaction, which will require shareholder and regulatory approval, the combined entity will operate as Cenovus and trade under the Cenovus name and remain headquartered in Calgary, Alberta.

Our Strategy

Our overall strategy remains unchanged and continues to be focused on maximizing shareholder value through cost leadership and realizing the best margins for our products. We have flexibility in our business plan that allows us to focus on maintaining liquidity and preserving a resilient balance sheet by reducing spending, while maintaining safe and reliable operations. This is particularly important in the current economic environment. Our longer-term plan remains focused on sustainably growing shareholder returns and reducing Net Debt as well as continuing to integrate Environmental, Social and Governance (“ESG”) considerations into our business plan. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility. We aim to evaluate disciplined investment in our portfolio against dividends, share repurchases and achieving and maintaining the optimal debt level while targeting investment grade status. Our investment focus will be on areas where we believe we have the greatest competitive advantage. We plan to achieve our strategy by leveraging our strategic focus areas including our oil sands, conventional oil and natural gas assets, marketing, transportation and refining portfolio, and our people.

RESPONDING TO LOW OIL PRICES AND THE NOVEL CORONAVIRUS (”COVID-19”)

During the first quarter, there was significant crude oil demand reduction as a result of measures taken by governments around the world to contain the COVID-19 pandemic. At the same time, overall global crude oil supply increased as efforts between the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC members, primarily Saudi Arabia and Russia, to manage global crude oil production levels broke down and each party increased their daily crude production. The combination of these events resulted in a collapse of crude oil benchmark prices, dropping to US$10.01 per barrel, excluding a historic one-day low of negative US$37.63 per barrel on April 20, 2020.

In April, the agreement between OPEC and a group of 10 non-OPEC members (collectively, “OPEC+”) to cut crude oil output, and several other countries announcing similar production cuts decreased the global supply of crude oil. At the same time, as governments began to ease off on some of the measures taken to contain the pandemic there was an increase in demand for crude oil which helped increase crude oil prices. During the third quarter, crude oil prices improved from the second quarter, however prices continued to be volatile due to market responses to COVID-19 and OPEC crude oil production output decisions. The duration of the current lower commodity price environment continues to be uncertain, especially with the second wave of COVID-19 infections driving concerns.

We believe our reduced 2020 capital investment plan, operating cost reductions and general and administrative (“G&A”) reductions, announced on April 2, 2020, enhances our financial resilience and financial capability to maintain our base business and to deliver safe and reliable operations. We will continue to challenge our cost structure in the face of these unprecedented conditions.

The Company has available $5.6 billion in committed credit facilities, with $1.1 billion maturing in April 2021, $1.2 billion maturing in late 2022, and $3.3 billion maturing in late 2023. A further $1.6 billion of uncommitted demand lines to issue letters of credit or in some cases draw up to $600 million for general purposes are available, and the Company has no bond maturities until late 2022. We believe that we have ample liquidity and runway to sustain our operations through a prolonged market downturn. Under the terms of Cenovus’s committed credit facilities, the Company is required to maintain a debt to capitalization ratio, as defined in the agreement, not to exceed 65 percent. As at September 30, 2020, the Company was well below this limit.

The Provincial and Federal governments have recognized the serious economic impacts of the spread of COVID‑19 and have taken steps to provide various programs, such as the Canada Emergency Wage Subsidy (“CEWS”)

program. During the third quarter we continued to benefit from the assistance of the CEWS program to help protect jobs during the pandemic.

The Company remains committed to the health and safety of its workforce and the public while providing essential services. Physical distancing measures continue to be taken to maintain the health and safety of our people and to help prevent the spread of COVID-19. We continue to monitor the changing COVID-19 situation. Earlier this month we lifted our mandatory work from home measure to open our modified workspaces in the Calgary offices to staff again, with workplace safety plans and protocols in place. Increases in staff levels at sites and offices has been and will continue to be achieved in accordance with guidance received from the Federal and Provincial governments and public health officials.

QUARTERLY OVERVIEW

Crude oil demand, which continues to be negatively impacted by the effects of COVID-19, showed signs of gradual recovery throughout the summer months with the easing of some of the restrictions imposed by governments to limit the spread of the virus combined with the commitment by OPEC and non-OPEC members to reduce crude oil production levels in response to lower demand and low prices. COVID-19 infection rates, global economic performance and political development will continue to impact the pace of demand recovery.

Brent and WTI crude oil benchmark prices averaged US$43.37 per barrel and US$40.93 per barrel, respectively, for the third quarter. Average crude oil prices have improved significantly from the very low levels in the second quarter (Brent – US$33.27 per barrel; WTI – US$27.85 per barrel), as the market stabilized and the volatility in prices decreased. Even with the improvement, crude oil benchmark prices remain more than 25 percent lower than the third quarter of last year. Western Canadian Select (“WCS”) benchmark prices rose 94 percent from an average low of US$16.38 per barrel in the second quarter to an average of US$31.84 per barrel in the third quarter. However, the average WCS benchmark crude oil prices fell along with the entire crude market, averaging 28 percent lower than US$44.21 per barrel in the same period of 2019. The impact of falling crude prices was partially offset by a narrower differential between WTI and WCS as industry-wide production shut-ins resulted in excess pipeline capacity.

Operationally, our upstream assets performed well. We continued to deliver good health and safety performance in light of the health and wellness challenges presented to staff by the pandemic. In response to increasing crude oil prices we accessed additional production curtailment credits available in the market, which allowed us to produce above our curtailment limit. Our upstream production in the quarter averaged 471,799 BOE per day, five percent higher than the third quarter of 2019, when production was in line with the Government of Alberta’s mandatory production curtailment restrictions. The increase was partially offset by planned turnaround and maintenance activities in the third quarter of 2020. Sales volumes in the quarter were higher than the second quarter as we sold crude oil inventory that had built up from April through June, when the average WTI prices were significantly lower (April – US$16.70 per barrel, May – US$28.53 per barrel and June – US$38.31 per barrel), in July when the average WTI price was US$40.77 per barrel. When the decision was made to store barrels due to those low crude oil prices, we entered into risk management contracts to fix the margin we would receive in the future periods. Although risk management losses were realized, as settlement prices were higher than the contract prices, the corresponding increase in the sales price for the barrels of crude oil offset that and we were able to lock in an improved margin as a result of our decision to store in low pricing months and sell in future periods when prices were higher.

Our Wood River and Borger refineries (the “Refineries”) demonstrated reliable operational performance while continuing to operate below capacity due to economic crude rate reductions in response to lower refined product demand and weak pricing as a result of COVID‑19.

Upstream operating margin of $668 million in the third quarter increased to more than four times that of $157 million in the second quarter due to higher average realized crude oil sales price and higher sales volumes, partially offset by increased transportation and blending costs and higher royalties. Upstream operating margin in the third quarter of 2020 decreased compared with $954 million in 2019, due to a lower average realized crude oil sales price and realized risk management losses compared with gains in 2019, partially offset by higher sales volumes and lower royalties.

Our average realized crude oil sales price of $39.77 per barrel increased significantly compared with $12.83 per barrel in the second quarter due to the improved crude oil prices. However, our average realized crude oil sales price was lower compared with $55.13 per barrel in the third quarter of 2019 reflecting the declining benchmark WTI prices, partially offset by the narrower WTI-WCS differential and lower priced condensate used for blending.

Operating margin for our Refining and Marketing segment was negative $74 million in the third quarter, a decline of $208 million from the second quarter. Refining and Marketing operating margin decreased $200 million compared with the third quarter of 2019 primarily due to decreased market crack spreads, reduced crude oil runs and lower crude advantage, partially offset by lower operating costs.

In the third quarter of 2020, we:

Upstream Production Volumes

Oil Sands production for the three and nine months ended September 30, 2020 reflects increased production above our curtailment limit achieved by purchasing additional production curtailment credits compared with 2019, where production was in line with the Government of Alberta’s mandatory production curtailment program. In the third quarter of 2020, production was reduced by 8,528 barrels per day due to a planned turnaround and maintenance at Christina Lake, which began late September and ran until mid-October 2020, and planned maintenance at Foster Creek. In 2019, production was impacted by a planned turnaround at Christina Lake during the second quarter of 2019.

Conventional production in the three months ended September 30, 2020 decreased compared with the third quarter of 2019, due to natural well declines and downtime due to a planned turnaround at a non-operated natural gas plant in the Elmworth-Wapiti area, partially offset by Marten Hills heavy oil production starting in 2020. In the

third quarter of 2019, production was impacted by temporary shut-ins from low natural gas prices. Production in the nine months ended September 30, 2020 decreased due to natural well declines, partially offset by Marten Hills heavy oil production, as well as fewer shut-ins for low commodity pricing.

Refining and Marketing

Crude oil runs and refined product output decreased in the third quarter and on a year-to-date basis compared with the same periods in 2019 as both Refineries implemented crude rate reductions in response to reduced demand and weak pricing for refined products as a result of COVID-19. In 2019, both Refineries were impacted by planned turnarounds and unplanned maintenance. For the three and nine months ended September 30, 2020, the economic crude rate reductions had a greater impact than planned and unplanned maintenance in 2019.

Further information on the changes in our financial and operating 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.

Operating Margin is an additional subtotal found in Note 1 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, inventory write-downs, net of reversals, 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, 2020 Compared With September 30, 2019

Operating Margin Variance

Operating Margin decreased in the three months ended September 30, 2020 compared with 2019 primarily due to:

These decreases in Operating Margin were partially offset by:

Nine Months Ended September 30, 2020 Compared With September 30, 2019

Operating Margin Variance

Operating Margin decreased in 2020 compared with 2019 primarily due to:

These decreases in Operating Margin were partially offset by:

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

Cash From (Used in) 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 (used in) 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 accounts receivable, inventories (excluding non-cash inventory write-downs and reversals), income tax receivable, accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration costs and pension funding.

Cash From Operating Activities and Adjusted Funds Flow decreased for the three months ended September 30, 2020 compared with 2019, primarily due to lower Operating Margin, as discussed above, partially offset by lower current taxes. The change in non-cash working capital as presented in the interim Consolidated Statements of Cash Flows for the third quarter of 2020 was primarily due to a decrease in accounts receivable and an increase in accounts payable, partially offset by an increase in inventory. For the three months ended September 30, 2019, the change in non-cash working capital was due to higher inventories and a decrease in accounts payable, partially offset by a decrease in accounts receivable and income tax receivable.

Cash From Operating Activities and Adjusted Funds Flow decreased for the nine months ended September 30, 2020 compared with 2019, primarily due to lower Operating Margin, as discussed above, partially offset by higher other income due to funding from the CEWS program, and lower current taxes. The change in non-cash working capital for the nine months ended September 30, 2020 was primarily due to a decrease in inventory and accounts receivable, partially offset by a decrease in accounts payable and income taxes payable. In 2019, the change in non-cash working capital was primarily due to an increase in inventory and accounts receivable, partially offset by a decrease in income tax receivable and an increase in accounts payable.

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, 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 income tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.

In the third quarter of 2020, we had an Operating Loss compared with Operating Earnings in 2019 primarily due to lower Cash From Operating Activities and Adjusted Funds Flow, as discussed above, and higher depreciation, depletion, and amortization (“DD&A”) that included an impairment charge of $450 million for the Borger CGU, partially offset by non-operating realized foreign exchange gains of $30 million.

We had an Operating Loss for the nine months ended September 30, 2020, relative to Operating Earnings in 2019 primarily due to lower Cash Used in Operating Activities and Adjusted Funds Flow, as discussed above, higher DD&A that included impairment charges of $814 million, and operating unrealized foreign exchange losses of $65 million compared with gains of $18 million in 2019. The increase in our Operating Loss was partially offset by non-operating realized foreign exchange gains of $33 million compared with realized losses of $279 million in 2019 on our unsecured notes, a re‑measurement gain of $97 million on the contingent payment compared with a loss of $137 million in 2019, and lower non-cash employee long-term incentive costs.

Our Net Loss of $194 million in the third quarter of 2020 was lower than Net Earnings of $187 million in the third quarter of 2019 primarily due to lower Operating Earnings, as discussed above. The decrease to Net Earnings was partially offset by:

On a year-to-date basis, Net Loss of $2,226 million was significantly lower than Net Earnings of $2,081 million in 2019 due to:

Capital investment in 2020 decreased compared with 2019, reflecting our reduced capital investment program and revised budget announced in April.

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

COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Key performance drivers for our financial results include commodity prices, quality and location 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.

Crude Oil and Condensate Benchmarks

Through the quarter, crude oil benchmarks improved relative to the second quarter with the average Brent and WTI crude oil benchmark prices rising 30 percent and 47 percent, respectively. While global demand for crude oil in the third quarter improved from the second quarter lows and significant production shut-ins globally helped in stabilizing the market, demand for crude oil was still under pressure due to the resurgence of COVID-19 cases.

Year-over-year, the impacts of the global demand reduction have resulted in the average Brent and WTI crude oil benchmark prices being lower.

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 royalty rates for a number of our crude oil properties. In the third quarter of 2020, the Brent-WTI differential narrowed compared with 2019 due to lower exports of crude oil from North America and reduced U.S. crude oil supply.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In the second quarter of 2020, Alberta production cuts due to demand concerns from COVID-19 resulted in reduced Western Canadian Select Basin (“WCSB”) supply causing heavy oil differentials to significantly narrow. As a result, the WCSB crude supply was able to clear volumes from Alberta by way of pipeline versus more expensive rail. In the third quarter of 2020, the WTI-WCS at Hardisty differential narrowed further from the second quarter as marginal transportation costs remained low and heavy crude benchmarks in the U.S. Gulf Coast (“USGC”) also strengthened relative to WTI due to decreased global supply.

WCS at Nederland is a heavy oil benchmark at the USGC which is representative of pricing for our sales in the USGC. WCS at Nederland crude oil benchmark prices weakened in 2020 compared with 2019, consistent with falling crude oil prices globally as refiners lowered crude runs to adjust to reduced demand for products. In the third quarter of 2020, WCS at Nederland benchmark prices relative to WTI strengthened compared with the second quarter of 2020, benefitting from the lower supply of heavy and medium sour grades from Canadian and OPEC+ producers.

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 average differential between WTI and WTS benchmark prices narrowed in 2020 compared with 2019 as debottlenecking of transportation constraints resulted in WTS trading in a narrow range around parity with WTI pricing since early 2019.

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 USGC condensate prices plus the cost to transport the condensate to Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be available for use in blending as well as timing of sales of blended product.

Average condensate benchmark prices were at a narrower discount relative to WTI in Alberta in the third quarter of 2020 compared with 2019. The benefit of weaker diluent demand in 2020 due to shut-in heavy oil production has been offset by lower imported barrels from the U.S. On a year-to-date basis, average condensate differentials to WTI narrowed compared with 2019.

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 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 decreased in the third quarter and on a year-to-date basis compared with the same periods in 2019, primarily due to lower refined product demand as a result of COVID-19. Weaker refined product demand resulted in higher inventory levels which put pressure on market crack spreads. As North American refining crack spreads are expressed on a WTI basis, while refined products are set by global prices, the weakening of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and WTI benchmark prices.

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 strengthened during the three and nine months ended September 30, 2020 compared with 2019 as the differential between AECO and NYMEX narrowed significantly due to lower than expected supply, ample access to domestic storage injections and lower pipeline utilization in the WCSB. Average NYMEX prices decreased compared with 2019 due to lower demand and a large decrease in liquid natural gas exports.

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 weakening Canadian dollar, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars.

The Canadian dollar on average weakened relative to the U.S. dollar in 2020, compared with 2019, resulting in a positive impact of approximately $170 million on our revenues in the nine months ended September 30, 2020. The weakening of the Canadian dollar relative to the U.S. dollar as at September 30, 2020 compared with December 31, 2019, resulted in unrealized foreign exchange losses of $164 million on the translation of our U.S. dollar debt.

REPORTABLE SEGMENTS

Our reportable segments are as follows:

Oil Sands, which includes the development and production of bitumen 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.

Conventional, which includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, and Clearwater operating areas in Alberta and British Columbia and the exploration for heavy oil in the Marten Hills area. The assets include interests in numerous natural gas processing facilities. We renamed our Deep Basin segment to Conventional in the first quarter of 2020 and our new resource play, Marten Hills, was reclassified from the Oil Sands segment to the Conventional segment. Comparative periods have been reclassified.

Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an unrelated U.S. public company. 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, transloading services provided to the Oil Sands segment by the Company’s rail terminal, 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.