Exhibit 99.1

CONTENTS
MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER	4
MESSAGE FROM OUR BOARD CHAIR	6
MANAGEMENT’S DISCUSSION AND ANALYSIS	7
CONSOLIDATED FINANCIAL STATEMENTS	82
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	92
SUPPLEMENTAL INFORMATION	156
ADVISORY	163
INFORMATION FOR SHAREHOLDERS	183

For additional information about forward-looking statements, specified financial measures and reserves contained in this Annual Report, see the Advisory on page 163.

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OUR FOCUS ON ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) TARGETS

At Cenovus, we believe striking the right balance among environmental, economic and social considerations creates long-term value.

Following our strategic combination with Husky Energy on January 1, 2021, we revised the company’s ESG focus areas and then established ambitious targets for each area: climate & greenhouse gas (GHG) emissions, water stewardship, biodiversity, Indigenous reconciliation and inclusion & diversity. These targets are embedded in our five-year business plan. They set out how we aim to improve our ESG performance and help our business remain resilient over the longer term while creating shareholder value. Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Always our top value, we’ve identified safety along with corporate governance as foundational to our business, providing the backbone for all of our operations.

Our ESG targets include:

	Reducing absolute GHG emissions by 35% by year-end 20351; a long-term ambition to achieve net zero emissions by 2050.
	Reducing fresh water intensity by 20% in oil sands and in thermal operations by year-end 2030.
	Reclaiming 3,000 decommissioned well sites by year-end 2025; restoring more habitat than we use in the Cold Lake caribou range by year-end 2030.
	Achieving a minimum of $1.2 billion of spending with Indigenous businesses between 2019 and year-end 2025; attaining Progressive Aboriginal Relations gold certification from the Canadian Council for Aboriginal Business by year-end 2025.
	Increasing women in leadership roles2 to 30% by year-end 2030; aspiring to have at least 40% representation from designated groups3 among non-management directors, including at least 30% women, by year-end 2025.

Note:  Targets include start year: 2019 for emissions, water intensity, well reclamation and Indigenous business spend; 2016 for caribou habitat restoration.

1 Emissions reductions are in reference to scope 1 and 2, on a net equity basis.

2 Leadership roles include Team Lead/Coordinator/Supervisor positions or above.

3 Designated groups are defined as women, Indigenous peoples, persons with disabilities and members of visible minorities.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  3

In 2021, we charted an exciting new course for Cenovus through our combination with Husky Energy.

The transaction built on the excellent work by our teams over the last few years to consolidate our position as an industry cost and sustainability leader. As a result of the combination, we have created an even stronger, more resilient international energy producer with a high-quality, diverse and integrated portfolio. We’ve been laser focused on integrating the assets of the two companies to capture significant synergy opportunities, drive more efficiencies across our operations, aggressively reduce debt and create value for our shareholders.

Last year was both rewarding and demanding for our staff, especially with the ongoing challenges of COVID-19. But thanks to their dedication and tireless work, we’ve made significant progress since the combination. Today, I believe Cenovus represents a compelling value proposition focused on our considerable operational strength, financial discipline, environmental, social, and governance (ESG) leadership and opportunities to sustainably grow shareholder returns over time.

At the heart of everything we do is our focus on health and safety as our top priority. We maintained safe and reliable operations in 2021 while navigating another year of the COVID-19 pandemic. This included managing public health directives across the various jurisdictions where we operate, and the introduction of our new Cenovus Operations Integrity Management System, an industry-leading program to help us safely, reliably and consistently plan and conduct our operations.

In 2021, we clearly demonstrated the operational strength of our Upstream and Canadian Manufacturing businesses. As we integrated the assets of both companies, we successfully unlocked and even exceeded the efficiencies we first envisioned when we announced the combination. For example, by applying the Cenovus oil sands operating model to Husky’s Lloydminster thermal assets, we increased production to reach record output without adding extra steam, which supports reduced emissions intensity. We also set production records at our Foster Creek and Christina Lake oil sands facilities and delivered strong volumes and free funds flow from our Asia Pacific operations. Our Canadian Manufacturing segment continued to deliver excellent

and reliable performance, and in 2022 we will be focused on building an equally strong executional track record in U.S. Manufacturing, showcasing the full value of that business to our shareholders.

With our strategic and disciplined approach to capital allocation, we significantly strengthened our balance sheet, surpassing our interim net debt target ahead of schedule. We more than achieved our planned $1.2 billion in annual run-rate synergies announced when we proposed the Husky transaction. We took advantage of low interest rates to restructure our long-term debt, resulting in significant interest rate savings and improved liability management. We optimized our asset portfolio, making strategic divestitures, and returned to full investment grade credit ratings, all with stable outlooks.

As a result of our improved financial performance and strengthened balance sheet, we were able to reintroduce our common share dividend in the first quarter and then double it in the fourth quarter. We also launched our first ever share buyback program for the purchase of up to 146.5 million Cenovus common shares. Share buybacks are something we view opportunistically, and repurchasing additional shares will continue to be considered as part of our commitment to increasing shareholder returns.

I’m happy to say that, with all the progress we made last year and the strong recovery in benchmark commodity prices, Cenovus’s share price doubled over the course of 2021. On a comparison of total shareholder return, Cenovus significantly outperformed both the S&P/TSX Composite and the S&P/TSX Energy indices in 2021. From the date of the Husky announcement on October 25, 2020 to the end of February 2022, our share price increased 308% compared with 228% for our broader peer group of upstream and integrated producers, 293% for our oil sands peers, and 206% for the S&P/TSX Capped Energy Index.

We took the opportunity last year to revisit who we are and how we want to show up as a company. We met with employees across the organization to develop our new Purpose and Values and have been putting them into action to guide our daily work. We also consulted with internal and external stakeholders to determine new ESG focus areas for the company and announced ambitious and achievable targets for each. This includes our climate & greenhouse gas (GHG) emissions target to reduce absolute scope 1 and 2 emissions¹ at

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our operations by 35% by year-end 2035, and our ambition to achieve net zero emissions from operations by 2050. Executive and employee compensation is tied directly to our ESG performance and assessed against several sustainability measures which are tracked through our annual corporate scorecard.

I’m particularly proud of our ground-breaking Indigenous

Housing Initiative, which supported the construction of more than 30 homes last year with 46 more planned for 2022. As a result of our efforts, we are making a significant contribution helping our Indigenous communities address their critical housing needs. As part of the program, we partnered with Portage College to launch a 24-week Construction and Trades Readiness Program, providing valuable skills training to 20 Indigenous students from the participating communities in the first year of operation.

Cenovus was also a founding member last June of the Oil Sands Pathways to Net Zero initiative. This unprecedented Alliance of the six largest oil sands producers is committed to working collectively, and with the federal and provincial governments, to achieve net zero GHG emissions from operations by 2050, helping Canada meet its climate goals. As the world transitions to a lower-carbon future, affordable and reliable energy will remain critical to our quality of life. And, as the geopolitical fallout from the recent Russian invasion of Ukraine has shown us, energy security is going to be increasingly important, today and in the future.

Many independent and reliable energy demand forecasts show the ongoing need for oil and natural gas – even in 2050. This gives Canada a significant opportunity to become a global supplier of choice for responsibly produced oil and I believe Cenovus is uniquely positioned to play a leading role. As a country, we have stringent regulation, open and transparent disclosure of our environmental performance, leading human rights practices and strong relationships with Indigenous communities. And at Cenovus, we have demonstrated leadership in innovation and continuous improvement and have among the lowest cost structures and GHG intensities in our industry.

In closing, I want to thank our staff for giving life to our Purpose and Values and continuing to make safety the most important thing we do every day. Our combined asset base, along with our reduced cash flow volatility, low cost structure and long-life reserves, provide a strategic advantage and position Cenovus to be extremely competitive on shareholder returns. I believe we have a great foundation, a plan that can continue to create significant shareholder value even in a low-price commodity environment and the right team to deliver results.

/s/ Alex Pourbaix

President & Chief Executive Officer

¹  Scope 1 & 2 GHG emissions on a net equity basis include Cenovus’s working interest in all assets, including the non-operated assets identified in the Reportable Segments section of this report. Working interest is estimated for Conventional facilities. Absolute value excludes drilling and completions emissions related to some onshore assets as well as Asia Pacific.

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Despite the persistence of COVID-19, the proliferation of vaccines and other public health measures helped re-energize global economic activity leading to a strong rebound in demand and pricing for oil and natural gas. Energy prices were also supported by discipline among OPEC and OPEC+ nations in observing production quotas, and by dwindling global supplies following years of underinvestment in exploration for new oil and gas reserves to offset declines. While still volatile, the economic recovery in 2021 buoyed equity values across many sectors, including energy, driving substantially improved shareholder returns.

At Cenovus, shareholder value has also been significantly enhanced by the combination with Husky Energy. Over the last 15 months, management has done an excellent job of integrating the assets of both companies and exceeded the expected synergies from the transaction. Together with higher commodity prices, our exceptional operating performance and disciplined capital program allowed Cenovus to generate increased free funds flow last year. This, along with proceeds received from asset sales, enabled the company to achieve its goal of reducing net debt in 2021, with further debt reduction expected this year. As a result, while continuing to deleverage the balance sheet, Cenovus is positioned to consider additional opportunities to enhance returns for our shareholders. In the first quarter of last year, the company reinstated its common share dividend, and in the fourth quarter the Board approved a doubling of the dividend as well as a share repurchase program for approximately 10% of Cenovus’s public float.

Our newly constituted Board is now fully integrated, with directors from both legacy companies bringing a wide diversity of skills and experience to the table. The Board spent time becoming familiar with the new asset mix, holding specific education sessions around environmental, social and governance (ESG) performance, cyber security, downstream operations and executive compensation.

During the year, the Board approved revised ESG focus areas and ambitious new targets for the combined company. These targets are embedded in Cenovus’s five-year business plan and set out how management will aim to help our business remain resilient over the long term while creating enhanced shareholder value.

As part of our ongoing renewal process, the Board revised its aspirational target to have at least 40% of independent directors self-identify as women, Indigenous peoples, persons with disabilities and visible minorities by year-end 2025, with at least 30% of independent directors being women. The Board has further committed to 30% female representation of its members by the end of our Annual Meeting of Shareholders in 2023. Mandates for the Board and its committees were also updated to clearly identify and allocate ESG risk oversight, including safety and health matters, the environment and climate change, human capital management, governance, our sustainability performance, reporting and disclosure.

Overall, with our excellent financial and operational performance last year, our strengthened balance sheet and our commitment to strong ESG performance, the Board is confident we are well positioned to deliver exceptional returns in the future. We believe Canadian oil and gas will play a major role in helping to meet the world’s growing energy demand and that Cenovus, through its commitment to providing reliable, low cost and ultimately low-carbon products, will be at the forefront.

With the Husky integration now largely complete, the company is more resilient than ever. We have world class assets across the full oil and gas value chain and the expertise and capability to operate them safely, reliably and profitably. Guided by the company’s new five-year plan, and our commitment to safety and the environment, I believe Cenovus will continue to deliver shareholder value for years to come.

I want to thank our shareholders and the Board for their continued support and look forward to working with you in the year ahead.

/s/ Keith MacPhail

Board Chair

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MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE YEAR ENDED DECEMBER 31, 2021

OVERVIEW OF CENOVUS	8
YEAR IN REVIEW	10
OPERATING AND FINANCIAL RESULTS	12
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS	19
REPORTABLE SEGMENTS	21
UPSTREAM	21
OIL SANDS	21
CONVENTIONAL	26
OFFSHORE	28
DOWNSTREAM	32
CANADIAN MANUFACTURING	32
U.S. MANUFACTURING	34
RETAIL	36
CORPORATE AND ELIMINATIONS	37
QUARTERLY RESULTS	40
OIL AND GAS RESERVES	42
LIQUIDITY AND CAPITAL RESOURCES	43
RISK MANAGEMENT AND RISK FACTORS	48
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES	72
CONTROL ENVIRONMENT	78
OUTLOOK	78

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 February 7, 2022, should be read in conjunction with our December 31, 2021, audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial Statements”). All of the information and statements contained in this MD&A are made as of February 7, 2022, unless otherwise indicated. This MD&A 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 Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and recommended the MD&A for approval by the Board, which occurred on February 7, 2022. 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.

On January 1, 2021, pursuant to a plan of arrangement under the Business Corporations Act (Alberta), Husky Energy Inc. (“Husky”) became a wholly-owned subsidiary of Cenovus. Husky was subsequently amalgamated with Cenovus on March 31, 2021, (the “amalgamation”) under the Canada Business Corporations Act and ceased to make separate filings as a reporting issuer. Unless the context requires otherwise, any reference herein to Husky refers to the business and operations of Husky prior to the amalgamation.

Basis of Presentation

This MD&A and the 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. Refer to the Advisory section for commonly used oil and gas terms.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  7

OVERVIEW OF CENOVUS

We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. We are the second largest Canadian-based crude oil and natural gas producer and the second largest Canadian-based refiner and upgrader, with operations in Canada, the United States (“U.S.”) and the Asia Pacific region.

Cenovus and Husky Arrangement

On January 1, 2021, Cenovus and Husky closed a transaction to combine the two companies through a plan of arrangement (the “Arrangement”) pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common shares and Cenovus Warrants. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms.

The Arrangement combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics infrastructure, and downstream assets, which creates opportunities to optimize the margin captured across the heavy oil value chain. With the combination of processing capacity and market access outside Alberta for the majority of the Company’s oil sands and heavy oil production, exposure to Alberta heavy oil price differentials is reduced while maintaining exposure to global commodity prices.

Our upstream operations include oil sands projects in northern Alberta, thermal and conventional crude oil, natural gas and natural gas liquids (“NGLs”) projects across Western Canada, crude oil production offshore Newfoundland and Labrador and natural gas and NGLs production offshore China and Indonesia. Our downstream business includes upgrading and refining operations in Canada and the U.S., and retail operations across Canada.

Our operations involve activities across the full value chain to develop, produce, transport and market crude oil and natural gas in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of volatility in light-heavy crude oil differentials and contribute to our bottom line by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels.

In 2021, crude oil production from our Oil Sands assets averaged 581.5 thousand barrels per day, which is generally aligned with our downstream crude oil throughput of 508.0 thousand barrels per day. Total upstream production averaged 791.5 thousand barrels of oil equivalent (“BOE”) per day. Refer to the Operating and Financial Results section of this MD&A for a summary of Oil Sands production and total upstream production by product type.

Our Strategy

Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. We aim to maximize shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and Environment, Social and Governance (“ESG”) leadership. The Company prioritizes Free Funds Flow generation which enables debt reduction, increased shareholder returns through dividend growth and share buybacks, reinvestment in the business and diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility. In 2021, we achieved and surpassed our interim Net Debt Target⁽¹⁾ of $10 billion and began purchasing shares under a normal course issuer bid (“NCIB”) program. Over the long term, our Net Debt Target is between $6 billion and $8 billion. This aligns with our Net Debt to Adjusted EBITDA Ratio Target⁽¹⁾ of between 1.0 and 1.5 times at the bottom of the cycle, which we see as approximately US$45 per barrel WTI.

On December 8, 2021, we announced our 2022 budget focused on our operational strength, capital discipline and ESG leadership. Free Funds Flow generation will be used to grow shareholder returns and further reduce debt. 2022 guidance dated December 7, 2021, is available on our website at cenovus.com.

(1) Specified financial measure. See the Advisory.

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Our Operations

The Company operates through the following reportable segments:

Upstream Segments

• Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

• Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob-Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported with additional third-party commodity trading volumes through access to capacity on third-party pipelines, export terminals and storage facilities, which provides flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

• Offshore, includes offshore operations, exploration and development activities in China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

• Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products. Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt and ancillary products.

• U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

• Retail, includes the marketing of our own and third-party volumes of refined petroleum products, including gasoline and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.

Corporate and Eliminations

Primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail segment. Eliminations are recorded based on current market prices.

To conform to the presentation adopted for the current period’s operating segments, market optimization activities, unrealized gains and losses on risk management and results previously reported under the Refining and Marketing segment have been reclassified.

The Arrangement was accounted for using the acquisition method pursuant to IFRS 3, “Business Combinations”. Under the acquisition method, assets and liabilities are measured at their estimated fair value on the date of acquisition with the exception of income tax, stock-based compensation, lease liabilities and right-of-use (“ROU”) assets. The total consideration was allocated to the tangible and intangible assets acquired and liabilities assumed. Comparative figures in this MD&A include Cenovus results prior to the closing of the Arrangement on January 1, 2021, and does not reflect any historical data from Husky.

The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect new information obtained between January 1, 2021, and December 31, 2021, about the conditions that existed at the date of the Arrangement. Total consideration, including non-controlling interest, was $6.9 billion. The fair value of the total identifiable net assets was $5.6 billion, resulting in $1.3 billion of goodwill generated from the transaction.

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YEAR IN REVIEW

Cenovus completed a very successful first year as a combined company following the closure of the Arrangement on January 1, 2021. We focused on health and safety as our top priority while maintaining our low operating and capital cost structures. The strong operational performance of our integrated asset base and the improving commodity price environment drove solid financial results. We significantly reduced our Net Debt and achieved our planned annual run rate synergy targets. We reintroduced our common share dividend in the first quarter and doubled it in the fourth quarter. In addition, we commenced a NCIB to further increase returns to shareholders. We also optimized our asset portfolio through numerous dispositions and restructured our interests in the Atlantic region.

Summary of Annual Results

($ millions, except where indicated)	2021	Percent   Change	2020	Percent   Change	2019
Production Volumes (1) (MBOE/d)	791.5	68	471.7	4	451.7
Crude Throughput (2) (Mbbls/d)	508.0	173	185.9	(16)	221.3
Revenues (3)	46,357	242	13,543	(34)	20,542
Netback (4) ($/bbl)	37.04	267	10.09	(61)	26.02
Operating Margin (4)	9,373	918	921	(79)	4,460
Cash From (Used in) Operating Activities	5,919	2,068	273	(92)	3,285
Adjusted Funds Flow (4)(5)	7,248	6,095	117	(97)	3,670
Capital Investment	2,563	205	841	(28)	1,176
Free Funds Flow (4)(5)	4,685	747	(724)	(129)	2,494
Net Earnings (Loss) (6)	587	125	(2,379)	(208)	2,194
Per Share - basic and diluted ($)	0.27	114	(1.94)	(209)	1.78
Total Assets	54,104	65	32,770	(7)	35,173
Total Long-Term Liabilities (4)	23,191	69	13,704	(2)	13,991
Long-Term Debt, Including Current Portion (7)	12,385	66	7,441	11	6,699
Net Debt (8)(9)	9,591	34	7,184	10	6,513
Net Debt to Capitalization Ratio (9) (percent)	29	(3)	30	20	25
Net Debt to Adjusted EBITDA Ratio (9) (times)	1.2	(90)	11.9	644	1.6
Cash Dividends
Common Shares	176	129	77	(70)	260
Per Common Share ($)	0.0875	40	0.0625	(71)	0.2125
Preferred Shares	34	—	—	—	—

(1) Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type.

(2) Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.

(3) Comparative figures have been re-presented for a portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.

(4) Non-GAAP financial measure. See the Advisory.

(5) Comparative figures have been restated to conform with the definition in this MD&A.

(6) Net earnings (loss) for the years ended December 31, 2021, 2020 and 2019 is equal to net earnings (loss) from continuing operations.

(7) The current portion of long-term debt was $nil as at December 31, 2021, 2020 and 2019.

(8) At December 31, 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash equivalents assumed at fair value of $735 million.

(9) Specified financial measure. See the Advisory.

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Operationally, items under Management’s control performed very well:

• We delivered safe operations.

• Upstream production averaged 791.5 thousand BOE per day in 2021, an increase of 319.8 thousand BOE per day compared with 2020. Assets acquired in the Arrangement averaged 290.4 thousand BOE per day in 2021. See the Operating and Financial Results section of this MD&A for a summary of upstream production by product type.

• Downstream crude throughput averaged 508.0 thousand barrels per day in 2021, an increase of 322.1 thousand barrels per day compared with 2020. Assets acquired in the Arrangement averaged 303.3 thousand barrels per day of crude throughput in 2021.

• We applied learnings from Cenovus’s operating model at our Lloydminster thermal assets which resulted in new production records and reduced steam-oil-ratios (“SORs”) at other Oil Sands assets acquired in the Arrangement.

• Achieved single-day production records at Foster Creek and Christina Lake.

We generated revenue of $46.4 billion and cash from operating activities of $5.9 billion. Adjusted Funds Flow was $7.2 billion and capital investment was $2.6 billion, resulting in Free Funds Flow of $4.7 billion. Operating Margin was $9.4 billion in 2021 compared with $921 million in 2020, primarily due to increased revenue from higher average realized crude oil, NGLs and natural gas sales prices, higher market crack spreads, sales volumes from assets acquired in the Arrangement and increased sales volumes from Foster Creek and Christina Lake.

We strengthened our balance sheet:

• Reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion following the closing of the Arrangement and surpassed our interim Net Debt Target of $10 billion, positioning us to increase our allocation of Free Funds Flow towards shareholder returns.

• Issued US$1.25 billion of 10-year and 30-year notes, used the proceeds and cash on hand to repurchase approximately US$2.2 billion in principal of our outstanding notes. These transactions will generate substantial interest expense savings going forward and extended the maturity profile of our debt.

• Achieved credit rating upgrades throughout the year.

• On January 10, 2022, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and 2024.

We achieved our planned total of $1.2 billion annual run-rate synergies by the end of 2021. In 2021, we incurred $402 million of Total Integration Costs⁽¹⁾, including capital of $53 million.

We optimized our asset portfolio:

• Announced dispositions with cash proceeds totaling $1.9 billion, of which approximately $430 million were received in 2021:

○ In May, we sold our gross-overriding royalty (“GORR”) interest in the Marten Hills area of Alberta for cash proceeds of $102 million.

○ In October, we sold assets from the Conventional segment in the East Clearwater and Kaybob areas of Alberta for combined gross proceeds of $103 million.

○ In October, we closed our bought deal secondary offering of an aggregate of 50 million common shares of Headwater Exploration Inc. (“Headwater”) for cash gross proceeds of $228 million.

○ On November 30, we announced an agreement to sell assets within the Conventional segment, primarily our Montney assets, in the Wembley area for cash proceeds of approximately $238 million. The sale is expected to close in the first quarter of 2022.

○ On November 30, we announced agreements to sell 337 gas stations from the Retail segment for aggregate cash proceeds of approximately $420 million. The sales are expected to close in mid-2022. We are retaining our commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.

○ On December 16, we announced an agreement to sell our Tucker asset within the Oil Sands segment for gross cash proceeds of $800 million. The sale closed on January 31, 2022.

• De-risked our Atlantic business by restructuring our interests.

○ We closed an agreement with our partners in the Terra Nova field to increase our working interest. The Terra Nova Asset Life Extension (“ALE”) project is proceeding, extending the life of the field to 2033. Production, which has been suspended since 2019, is expected to resume before the end of 2022.

○ We entered into an agreement with Suncor in the White Rose field to decrease our working interest. The working interest restructuring will not occur if the project does not proceed.

(1) Non-GAAP financial measure. See the Advisory.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  11

We increased our returns to shareholders:

• Commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares. In 2021, Cenovus purchased and cancelled 17 million common shares for $265 million. From January 1, 2022 to February 7, 2022, Cenovus purchased an additional 9 million common shares for $160 million.

• Doubled our dividend to $0.035 per common share for the fourth quarter, compared with $0.0175 per common share in each of the first three quarters.

We prioritize ongoing ESG leadership and integration of sustainability considerations into our business decisions. In June, we announced the Oil Sands Pathways to Net Zero initiative, an alliance of peers working collectively with the federal and provincial governments with a goal to achieve net zero greenhouse gas (“GHG”) emissions from oil sands operations by 2050. In December, we released ambitious targets for climate and GHG emissions, water stewardship, biodiversity, Indigenous reconciliation, and inclusion and diversity.

Cenovus remains committed to the health and safety of its workforce and the public while providing essential services. Physical distancing measures and other protocols continue to be in place to maintain the health and safety of our people and to help mitigate the risk of COVID-19 at our workplaces. We continue to monitor the changing COVID-19 situation and respond accordingly in a timely manner. Work-from-home measures remained in place through the majority of 2021 and continue to be in place for all non-essential staff at our combined offices and worksites in Alberta, Saskatchewan and Manitoba, pending further review. The full scope of our operations will continue to take direction from local health authorities regarding their COVID-19 workplace mandates. Staff levels at sites and offices have and will continue to follow guidance received from the applicable federal, provincial, state and local governments and public health officials.

OPERATING AND FINANCIAL RESULTS

Selected Operating Results - Upstream

	2021	Percent   Change	2020	Percent   Change	2019
Upstream Production Volumes by Segment
Oil Sands (Mbbls/d)
Foster Creek	179.9	10	163.2	2	159.6
Christina Lake	236.8	8	218.5	12	194.7
Sunrise (1)	25.9	—	—	—	—
Lloydminster Thermal	97.7	—	—	—	—
Tucker (2)	21.0	—	—	—	—
Lloydminster Conventional Heavy Oil (3)	20.2	—	—	—	—
Total Oil Sands Crude Oil (4)	581.5	52	381.7	8	354.3
Oil Sands Natural Gas (5) (MMcf/d)	12.6	—	—	—	—
Conventional (6) (MBOE/d)	133.6	49	89.9	(8)	97.4
Offshore (MBOE/d)
Asia Pacific (7)(8)	60.3	—	—	—	—
Atlantic (9)	14.1	—	—	—	—
Offshore Total	74.4	—	—	—	—
Total Production Volumes (MBOE/d)	791.5	68	471.7	4	451.7
Upstream Production Volumes by Product
Bitumen (Mbbls/d)	561.3	47	381.7	8	354.3
Heavy Crude Oil (3) (Mbbls/d)	20.2	648	2.7	—	—
Light Crude Oil (Mbbls/d)	22.5	400	4.5	(8)	4.9
NGLs (Mbbls/d)	38.3	96	19.5	(11)	21.8
Conventional Natural Gas (MMcf/d)	895.5	136	379.0	(11)	424.5
Total Production Volumes (MBOE/d)	791.5	68	471.7	4	451.7
Total Upstream Sales Volumes (10) (MBOE/d)	700.8	67	420.5	8	390.8
Oil and Gas Reserves (MMBOE)
Total Proved	6,077	21	5,030	(1)	5,103
Probable	2,201	33	1,656	(6)	1,768
Total Proved Plus Probable	8,278	24	6,686	(3)	6,871

(1) Represents Cenovus’s 50 percent interest in the Sunrise operations.

(2) Sale of the Tucker asset closed on January 31, 2022.

(3) The Lloydminster conventional heavy oil area was previously referred to as Lloydminster cold and enhanced oil recovery (“EOR”). During the year ended December 31, 2021, production comprised of medium crude oil in this area was reclassified to heavy crude oil.

(4) Oil Sands production is comprised of bitumen except for Lloydminster Conventional Heavy Oil, which includes heavy crude oil.

(5) Conventional natural gas product type.

(6) Refer to the Conventional Operating Results section of this MD&A for a summary of Conventional production by product type.

(7) Reported production volumes reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(8) Refer to the Asia Pacific Operating Results section of this MD&A for a summary of Asia Pacific production by product type.

(9) Refer to the Atlantic Operating Results section of this MD&A for a summary of Atlantic production by product type.

(10) Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 517 MMcf per day for the year ended December 31, 2021 (336 MMcf per day for the year ended December 31, 2020).

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Selected Operating Results - Downstream

	2021	Percent   Change	2020	Percent   Change		2019
Downstream Manufacturing Crude Throughput Canadian Manufacturing (Mbbls/d)
Lloydminster Upgrader	79.0	—	—	—		—
Lloydminster Refinery	27.5	—	—	—		—
Canadian Manufacturing Total	106.5	—	—	—		—
U.S. Manufacturing (Mbbls/d)
Lima Refinery	126.9	—	—	—		—
Toledo Refinery (1)	69.9	—	—	—		—
Wood River and Borger Refineries (1)	204.7	10	185.9	(16	)	221.3
U.S. Manufacturing Total	401.5	116	185.9	(16	)	221.3
Total Throughput (Mbbls/d)	508.0	173	185.9	(16	)	221.3
Retail (2) (millions of litres/d)
Fuel sales, including wholesale	6.9	—	—	—		—

(1) Represents Cenovus’s 50 percent interest in the Wood River, Borger and Toledo operations.

(2) Sale of a portion of our Retail assets expected to close in mid-2022.

Upstream Production Volumes

In 2021, our upstream assets performed well. Oil Sands production increased 199.8 thousand barrels per day compared with 2020 due to 164.8 thousand barrels per day from assets acquired in the Arrangement and higher production at Foster Creek and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online combined with our decision to operate at reduced levels at Christina Lake in 2020 in response to market conditions. The increase was partially offset by a planned turnaround and operational outages at Foster Creek in the second quarter of 2021. Production steadily increased during the year and we achieved several single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets. Our Lloydminster thermal assets performed well as we applied our operating strategy and production and well delivery techniques to the acquired assets.

Conventional production increased 43.8 thousand BOE per day primarily due to volumes from assets acquired in the Arrangement, which produced 51.2 thousand BOE per day during the year. The increase was partially offset by the disposition of assets in the East Clearwater and Kaybob areas in the second half of 2021. Prior to closing, these assets were producing approximately 11.0 thousand BOE per day.

Offshore production was relatively consistent throughout the year and is entirely from assets acquired in the Arrangement.

Oil and Gas Reserves

Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2021 total proved reserves and total proved plus probable reserves were approximately 6.1 billion BOE and 8.3 billion BOE, respectively, increasing 21 percent and 24 percent, respectively, compared with 2020.

Additional information about our reserves, including a summary of total upstream production by product type, is included in the Oil and Gas Reserves section of this MD&A.

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Downstream Manufacturing

Crude Throughput by Segment

U.S. Manufacturing throughput increased 215.6 thousand barrels per day compared with 2020. Throughput increased due to 196.8 thousand barrels per day from assets acquired in the Arrangement and higher throughput at the Wood River and Borger refineries as the market for refined products improved.

At the Wood River and Borger refineries, throughput was temporarily impacted by unplanned outages in 2021. We maintained high throughput rates at the Lima Refinery in the first nine months of 2021 before completing a turnaround in October and November and encountering subsequent unplanned equipment outages. The refinery returned to normal operations towards the end of January 2022. At the Toledo Refinery, throughput was optimized in-line with market demand in 2021.

In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery, both of which were acquired in the Arrangement, ran at or near capacity throughout 2021.

Selected Consolidated Financial Results

Operating Margin

Operating Margin is a non-GAAP financial measure 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.

($ millions)	2021		2020  (1)		2019 (1)
Gross Sales (2)		54,517		14,523		22,404
Less: Royalties		2,454		371		1,173
Revenues		52,063		14,152		21,231
Expenses
Purchased Product (2)		28,369		5,959		9,206
Transportation and Blending		7,930		4,764		5,234
Operating Expenses		5,499		2,261		2,324
Realized (Gain) Loss on Risk Management Activities		892		247		7
Operating Margin (3)		9,373		921		4,460

(1) Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

(2) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.

(3) Non-GAAP financial measure. See the Advisory.

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Operating Margin by Segment

Year Ended December 31, 2021

Operating Margin increased in 2021, primarily due to:

• Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.

• Upstream and refined products sales volumes from assets acquired in the Arrangement.

• Increased sales volumes at Foster Creek and Christina Lake.

• Higher market crack spreads in the U.S. Manufacturing segment.

These increases in Operating Margin were partially offset by:

• Increased blending costs due to higher condensate prices and volumes.

• Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.

• Increased fuel costs in the Oil Sands segment due to high natural gas benchmark pricing.

• Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management contract prices.

• Increased Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Adjusted Funds Flow is a non-GAAP financial 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.

($ millions)	2021			2020			2019
Cash From (Used in) Operating Activities		5,919			273			3,285
(Add) Deduct:
Settlement of Decommissioning Liabilities		(102	)		(42	)		(52	)
Net Change in Non-Cash Working Capital		(1,227	)		198			(333	)
Adjusted Funds Flow		7,248			117			3,670

Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to:

• Increased Operating Margin, as discussed above.

• Distributions of $137 million received from equity-accounted affiliates.

• Business interruption insurance proceeds of $120 million related to the Superior Refinery.

The increases were partially offset by:

• Integration costs of $349 million.

• Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.

• Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions related to reaching our synergy-focused incentive plan.

• Contingent payment of $242 million, of which $175 million was recognized as a reduction to Cash from Operating Activities and Adjusted Funds Flow in 2021.

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• Long-term incentives of $111 million paid in the first quarter of 2021, related to the accelerated payout to our employees in connection with the Arrangement.

The change in non-cash working capital in 2021 was primarily due to an increase in inventories and accounts receivable, partially offset by an increase in accounts payable on December 31, 2021, compared with December 31, 2020.

In 2021, the increase in accounts receivable was primarily due to higher crude oil pricing and sales volumes from the Oil Sands segment and higher refined product pricing in the U.S. Manufacturing segment. The increases were partially offset by timing of cash receipts from customers and the receipt of insurance proceeds from the Superior Refinery rebuild project. The increase in inventory compared with 2020 was primarily due to higher volumes from increased access to transportation and storage capacity and the addition of facilities in the Canadian Manufacturing and U.S. Manufacturing segment as a result of the Arrangement. The increase in accounts payable was primarily due to higher condensate prices in the Oil Sands segment, higher accrued royalties payable, long-term incentives payable, accrued contingent liability payable and income taxes payable. The increases were partially offset by the settlement of the integration costs, long-term incentive costs paid to Cenovus employees and the payment of long-term incentives liabilities assumed as part of the Arrangement.

Net Earnings (Loss)

($ millions)	2021      vs. 2020			2020 vs. 2019
Net Earnings (Loss), Comparative Year		(2,379	)		2,194
Increase (Decrease) due to:
Operating Margin		8,452			(3,539	)
Corporate and Eliminations:
Unrealized Foreign Exchange Gain (Loss)		181			(696	)
Re-measurement of Contingent Payment		(655	)		244
Integration Costs		(320	)		(29	)
General and Administrative		(557	)		39
Finance Costs		(546	)		(25	)
Other (1)		303			566
Unrealized Risk Management Gain (Loss)		36			37
Depreciation, Depletion and Amortization		(2,422	)		(1,215	)
Exploration Expense		73			(9	)
Income Tax Recovery (Expense)		(1,579	)		54
Net Earnings (Loss), Current Year		587			(2,379	)

(1) Includes interest income, realized foreign exchange (gains) losses, (gain) loss on divestiture of assets, other (income) loss, net, share of income (loss) from equity-accounted affiliates, and Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management.

Net earnings in 2021 improved significantly compared with the net loss in 2020 due to:

• Higher Operating Margin, as discussed above.

• Impairment charges of $1.1 billion in the Conventional and U.S. Manufacturing segments in 2020.

• Impairment reversals of $378 million in the Conventional segment in 2021, due to improved forward commodity prices.

• Higher other income due to business interruption insurance proceeds of $120 million related to the Superior Refinery and a settlement of a legal claim in favour of Cenovus in 2021, whereas we recognized a $100 million loss on the Keystone XL pipeline project in the fourth quarter of 2020.

• Increased unrealized foreign exchange gains.

• Higher gains on divestiture of assets in 2021, primarily related to the Marten Hills common share and GORR sales.

The increase was partially offset by:

• Income tax expense compared with a recovery in 2020.

• A loss on re-measurement of contingent payment of $575 million (2020 – $80 million gain).

• Integration costs of $349 million.

• Impairment charges of $1.9 billion in the U.S. Manufacturing segment in the fourth quarter of 2021 due to the forward prices impacting refined product margins.

• Realized foreign exchange losses on the repurchase of U.S. dollar denominated debt in 2021.

• Provisions related to reaching our synergy-focused incentive plan.

• Net premiums of $121 million on the redemption of long-term debt (2020 – $25 million net discount).

• Increased general and administrative costs, finance expenses, and depreciation, depletion and amortization (“DD&A”) expense as a result of the Arrangement.

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Net Debt

As at ($ millions)	December 31,   2021			January 1,     2021 (1)			December 31, 2020			December 31,     2019
Short-Term Borrowings		79			161			121			—
Current Portion of Long-Term Debt		—			—			—			—
Long-Term Debt		12,385			14,043			7,441			6,699
Total Debt (2)		12,464			14,204			7,562			6,699
Less: Cash and Cash Equivalents		(2,873	)		(1,113	)		(378	)		(186	)
Net Debt		9,591			13,091			7,184			6,513

(1) Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement.

(2) Non-GAAP financial measure. See the Advisory.

Net Debt on January 1, 2021, was $13.1 billion, including the fair value of $5.9 billion assumed from the Arrangement. Since the Arrangement, we have reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion.

Capital Investment ^{(1) (2)}

($ millions)	2021		2020		2019
Upstream
Oil Sands		1,019		427		656
Conventional		222		78		103
Offshore
Asia Pacific		21		—		—
Atlantic		154		—		—
		1,416		505		759
Downstream
Canadian Manufacturing		37		33		52
U.S. Manufacturing		995		243		228
Retail		31		—		—
		1,063		276		280
Corporate and Eliminations		84		60		137
Capital Investment		2,563		841		1,176

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

(2) Prior periods have been reclassified to conform with current period’s operating segments.

Oil Sands capital investment in 2021 was primarily focused on sustaining production at Christina Lake, Foster Creek and the Lloydminster thermal assets.

Conventional capital investment focused on short cycle, high return development wells which are expected to improve underlying cost structures through volume enhancement and offset natural declines.

Offshore capital investment in 2021 was primarily preservation capital for the West White Rose project in the Atlantic region. Major construction on the West White Rose project was suspended in March of 2020 and the project remains under review while we evaluate options with our partners.

U.S. Manufacturing capital investment focused primarily on the Superior Refinery rebuild, combined with refining reliability, maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the Toledo Refinery.

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Drilling Activity

	Gross Stratigraphic Test Wells and Observation Wells								Gross Production Wells (1)
	2021		2020		2019		2021		2020		2019
Foster Creek		17		38		14		6		—		—
Christina Lake (2)		25		117		30		18		—		11
Sunrise		—		—		—		2		—		—
Lloydminster Thermal		115		—		—		46		—		—
Lloydminster Conventional Heavy Oil		15		—		—		3		—		—
Other (3)		17		—		14		—		—		—
		189		155		58		75		—		11

(1) Steam-assisted gravity drainage (“SAGD”) well pairs in the Oil Sands segment are counted as a single producing well.

(2) Includes Narrows Lake.

(3) Includes new resource plays.

Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.

			2021						2020						2019
(net wells, unless otherwise stated)	Drilled		Completed		Tied-in		Drilled		Completed		Tied-in		Drilled		Completed		Tied-in
Conventional		27		19		18		6		1		3		11		2		3

In the Offshore segment, we drilled a planned exploration well in China in October 2021.

Future Capital Investment

Future Capital Investment is a Specified financial measure. See the Advisory. Our guidance dated December 7, 2021, is available on our website at cenovus.com.

Our Oil Sands capital investment for 2022 is forecast to be between $1.4 billion and $1.6 billion. The increase from 2021 is primarily related to additional sustaining capital activities. Our Oil Sands production is expected to range between 570.0 thousand barrels per day and 630.0 thousand barrels per day. Oil Sands production guidance is not adjusted for the Tucker asset sale which closed on January 31, 2022.

Our Conventional capital investment for 2022 is forecast to be between $150 million and $200 million, focused on sustaining drilling programs. Our Conventional production is expected to range between 118.0 thousand BOE per day and 134.0 thousand BOE per day.

Our Offshore capital investment for 2022 is expected to be between $200 million and $250 million. This capital spend is primarily directed towards the Terra Nova ALE project and preservation capital for the West White Rose project. Production from our Offshore segment is expected to range between 64.0 thousand BOE per day and 76.0 thousand BOE per day.

In 2022, we plan to invest between $850 million and $950 million in our downstream segments focused on refining operations and reliability and a debottlenecking project at the Lloydminster Refinery to increase throughput capacity. Downstream capital investment includes between $200 million and $250 million for the Superior Refinery rebuild project. The rebuild project is expected to further enhance our heavy oil value chain integration while further reducing the Company’s exposure to WTI-WCS location differentials. Downstream throughput is expected to be in the range of 530.0 thousand barrels per day to 580.0 thousand barrels per day.

We expect to invest between $50 million and $70 million of corporate capital across the Company.

Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. 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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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 and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.

Selected Benchmark Prices and Exchange Rates ⁽¹⁾

(Average US$/bbl, unless otherwise indicated)	2021		Percent       Change		2020		2019		Q4 2021		Q4 2020
Brent (2)		70.73		70		41.67		64.18		79.73		44.22
WTI		67.91		72		39.40		57.03		77.19		42.66
Differential Brent-WTI		2.82		24		2.27		7.15		2.54		1.56
WCS at Hardisty		54.87		105		26.80		44.27		62.55		33.36
Differential WTI-WCS		13.04		3		12.60		12.76		14.64		9.30
WCS (C$/bbl)		68.73		93		35.59		58.77		78.71		43.41
WCS at Nederland		64.09		79		35.86		55.56		71.62		40.36
Differential WTI-WCS at Nederland		3.82		8		3.54		1.47		5.57		2.30
Condensate (C5 @ Edmonton)		68.20		84		37.16		52.86		79.13		42.54
Differential WTI-Condensate (Premium)/Discount		(0.29)		(113)		2.24		4.17		(1.94)		0.12
Differential WCS-Condensate (Premium)/Discount		(13.33)		29		(10.36)		(8.59)		(16.58)		(9.18)
Average (C$/bbl)		85.47		73		49.44		70.15		99.64		55.36
Synthetic @ Edmonton		66.28		83		36.25		56.45		75.40		39.60
WTI-Synthetic (Premium)/Discount Differential		1.63		(48)		3.15		0.58		1.79		3.06
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)		85.07		88		45.24		70.55		91.84		47.31
Chicago Ultra-low Sulphur Diesel (“ULSD”)		86.37		72		50.08		77.97		96.53		54.21
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)		17.54		133		7.54		16.00		16.06		7.05
Group 3 3-2-1 Crack Spread (3)		17.82		106		8.67		16.67		15.82		7.57
RINs		6.76		173		2.48		1.21		6.11		3.48
Natural Gas Prices
AECO (C$/Mcf)		3.56		59		2.24		1.62		4.94		2.77
NYMEX (US$/Mcf)		3.84		85		2.08		2.63		5.83		2.66
Foreign Exchange Rate
US$ per C$1 - Average		0.798		7		0.746		0.754		0.794		0.768
US$ per C$1 - End of Period		0.789		1		0.785		0.770		0.789		0.785
RMB per C$1 - Average		5.147		—		5.147		5.207		5.073		5.084

(1) These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management results, refer to the Netback tables in the Reportable Segments section of this MD&A.

(2) Calendar month average of settled prices for Dated Brent.

(3) 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.

Crude Oil and Condensate Benchmarks

In 2021, Brent and WTI crude oil benchmarks improved significantly compared to 2020 as demand for crude oil outpaced supply due to increased global crude oil demand amid roll out efforts of COVID-19 vaccines, economic recovery and easing of restrictions. The Organization of the Petroleum Exporting Countries (“OPEC”) and a group of 10 non-OPEC members (collectively, “OPEC+”) continued to support global prices despite the gradual easing of production quotas that began in the second quarter. The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent.

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 2021, the Brent-WTI differential remained narrow compared to 2020 due to continued low crude oil exports 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 2021, the average WTI-WCS differential remained narrow due to takeaway capacity from the Western Canadian Sedimentary Basin (“WCSB”).

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WCS at Nederland is a heavy oil benchmark at the U.S. Gulf Coast (“USGC”) which is representative of pricing for our sales in the USGC. WCS at Nederland prices were strong in 2021 compared to 2020 consistent with increasing crude oil prices globally, as refiners increased crude runs to adjust to increased demand for products. In the second half of 2021, the WTI-WCS at Nederland differential widened compared with 2020, mainly attributed to high coking utilization in the USGC and the gradual return of some OPEC+ medium and heavy oil barrels into the market.

We upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.

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 23 percent to 31 percent. The WCS-Condensate differential is an important benchmark as a wider differential generally results in a decrease 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 Edmonton condensate benchmark prices were at a slight premium relative to WTI in 2021. The differential has narrowed compared with 2020 as a result of higher oil sands production leading to an increase in blending requirements.

Refining Benchmarks

RUL and 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.

The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3, 3-2-1 market crack spread, reflects the market for our Borger Refinery.

Average Chicago refined product prices increased in 2021 compared with 2020, due to a combination of the higher cost of RINs as a result of a tight biofuel market and uncertainty around policies that drive RINs demand, as well as higher refined product demand due to the deployment of COVID-19 vaccines, easing of restrictions and increasing travel and economic activity. Recovering refined product demand resulted in lower inventory levels which increased market crack spreads. As North American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices, the strength 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.

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(1) There are no forward prices for RINs.

Natural Gas Benchmarks

Average NYMEX natural gas prices increased significantly in 2021 compared to 2020 as hot summer weather, a rebound in U.S. domestic demand, record liquified natural gas exports coupled with a muted supply response and strong global pricing, supported the market. Average AECO prices improved alongside the NYMEX benchmark. The differential between AECO and NYMEX widened in 2021 as a function of increased supply. The price received for our Asia Pacific natural gas production is largely based on long-term contracts.

Foreign Exchange Benchmarks

A substantial amount of 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 revenue. In addition to our revenues being denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. In addition, changes in foreign exchange rates impact the translation of U.S. and Asia Pacific operations.

In 2021, the Canadian dollar on average strengthened relative to the U.S. dollar compared with 2020, negatively impacting our revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar at December 31, 2021 compared with December 31, 2020. Combined with the realization of foreign exchange losses of $173 million on the repayment of our unsecured notes, this resulted in unrealized foreign exchange gains of $230 million on the translation of our U.S. dollar debt.

A portion of our long-term sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar on average has remained relatively flat compared with RMB in 2021.

REPORTABLE SEGMENTS

UPSTREAM

OIL SANDS

On December 31, 2020, the Oil Sands segment included the Foster Creek, Christina Lake and Narrows Lake assets as well as other projects in the early stages of development. On January 1, 2021, as part of the Arrangement, we acquired:

• Sunrise, a SAGD oil sands project located in the Athabasca region of northern Alberta. The Cenovus operated project is a 50 percent partnership with BP Canada.

• Tucker, an oil sands project located 30 kilometres northwest of Cold Lake, Alberta.

• Lloydminster thermal projects, consisting of bitumen production from 11 thermal plants, in the Lloydminster region of Saskatchewan.

• Lloydminster conventional heavy oil, which produces heavy oil from the Lloydminster region of Alberta and Saskatchewan. This area was referred to as Lloydminster Cold/EOR in previous periods.

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• A 35 percent interest in HMLP, which owns 2,200 kilometres of pipeline in the Lloydminster region and 5.9 million barrels of storage at Hardisty and Lloydminster. Financial results from HMLP are reported on an equity-accounted basis.

In 2021, we:

• Delivered safe and reliable operations.

• Achieved numerous single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets.

• Produced 581.5 thousand barrels per day, compared with 381.7 thousand barrels per day in 2020.

• Increased production from 553.4 thousand barrels per day in the first quarter to 624.9 thousand barrels per day in the fourth quarter.

• Commenced tieback of the Narrows Lake field into the Christina Lake plant. First steam from Narrows Lake is expected in 2025.

• Reached an agreement to sell our Tucker asset for gross cash proceeds of $800 million. The transaction closed on January, 31, 2022.

• Earned revenues of $20.6 billion.

• Generated Operating Margin of $6.4 billion, an increase of $5.3 billion compared with 2020 primarily due to higher average realized sales prices, added volumes from assets acquired as part of the Arrangement and higher sales volumes at Foster Creek and Christina Lake.

• Invested capital of $1.0 billion primarily focused on sustaining production at Christina Lake, Foster Creek and the Lloydminster thermal assets.

• Achieved a Netback of $33.69 per BOE.

Financial Results

($ millions)	2021		2020 (1)		2019 (1)
Gross Sales (2)		22,827		8,804		13,101
Less: Royalties		2,196		331		1,143
Revenues		20,631		8,473		11,958
Expenses
Purchased Product (2)		3,188		1,262		2,231
Transportation and Blending		7,841		4,683		5,152
Operating		2,451		1,156		1,067
Realized (Gain) Loss on Risk Management		786		268		23
Operating Margin		6,365		1,104		3,485
Unrealized (Gain) Loss on Risk Management (3)		18		57		92
Depreciation, Depletion and Amortization		2,666		1,687		1,543
Exploration Expense		16		9		18
Share of (Income) Loss from Equity-Accounted Affiliates		(5)		—		—
Segment Income (Loss)		3,670		(649)		1,832

(1) Prior periods have been reclassified to conform with current period’s operating segments.

(2) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.

(3) Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.

Operating Margin Variance

(1) Prior periods have been reclassified to conform with current period’s operating segments.

(2) 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.

(3) Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

(4) Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.

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Operating Results

	2021		2020		2019
Total Sales Volumes (MBOE/d)		579.9		386.6		346.7
Total Realized Price per Unit Sold (1) ($/BOE)		62.82		28.64		53.78
Crude Oil Production by Asset (Mbbls/d)
Foster Creek		179.9		163.2		159.6
Christina Lake		236.8		218.5		194.7
Sunrise (2)		25.9		—		—
Lloydminster Thermal		97.7		—		—
Tucker		21.0		—		—
Lloydminster Conventional Heavy Oil		20.2		—		—
Total Daily Crude Oil Production (3)		581.5		381.7		354.3
Effective Royalty Rate (percent)		18.7		11.6		20.3
Per Unit Transportation and Blending Cost (1) ($/BOE)		7.23		8.70		8.94
Per Unit Operating Cost (1) ($/BOE)		11.52		7.84		8.15
Per Unit DD&A (1) ($/BOE)		11.28		10.40		11.15

(1) Specified financial measure. See the Advisory.

(2) Represents Cenovus’s 50 percent interest in the Sunrise operations.

(3) Oil Sands production is comprised of bitumen except for Lloydminster conventional heavy oil, which is comprised of heavy crude oil. During the year ended December 31, 2021, production comprised of medium crude oil in this area was reclassified to heavy crude oil.

Revenues

Price

Realized sales prices increased primarily due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. In 2021, we sold approximately 20 percent (2020 – 25 percent) of our production to U.S. destinations to improve our realized sales price.

During 2021, gross sales included $2.9 billion (2020 – $1.3 billion) from third-party sourced volumes which are not included in our per-unit pricing metrics or our Netbacks. Refer to “Netback Reconciliations – Oil Sands” in this MD&A for more detail.

In 2021, gross sales included $329 million (2020 – $9 million), which are not included in our per-unit pricing metrics or our Netbacks, as it relates to transportation, blending and construction activities. Refer to “Netback Reconciliations – Oil Sands” in this MD&A for more detail.

The heavy oil and bitumen produced by Cenovus must be blended with condensate to reduce its viscosity to transport it to market through pipelines. Our realized bitumen sales price does not include the sale of condensate; however, it is influenced by the price of condensate. As the cost of condensate increases relative to the price of blended crude oil, our realized heavy oil and bitumen sales price decreases. Up to three months may lapse from when we purchase condensate to when we sell our blended production.

Cenovus makes storage and transportation decisions about our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification, and to inventory physical positions. In order to price protect our inventories associated with storage or transport decisions, Cenovus employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows to improve cash flow stability to support financial priorities. Transactions typically span across periods and, as such, these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they will flow from unrealized to realized risk management gains and losses.

In the year ended December 31, 2021, we incurred a realized risk management loss due to the settlement of benchmark prices rising above our risk management contract prices; as physical inventory was sold we recognized an offsetting gain due to rising benchmark prices. In 2021, unrealized losses were recorded on our crude oil financial instruments primarily due to forward benchmark pricing rising above our risk management contract prices that related to future periods and the realization of settled positions.

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Production Volumes

Oil Sands crude oil production was 581.5 thousand barrels per day in 2021, an increase of 199.8 thousand barrels per day compared with 2020. Production levels increased primarily due to the addition of 164.8 thousand barrels per day from assets acquired as part of the Arrangement, and increased production at Foster Creek and Christina Lake.

Production at Foster Creek increased 16.7 thousand barrels per day year-over-year due to new wells coming online in 2021, partially offset by reduced production due to a planned turnaround and operational outages in the second quarter.

Production at Christina Lake increased 18.3 thousand barrels per day year-over-year. In 2021, new wells were brought online, while in 2020 we chose to operate at reduced levels in April and completed a planned turnaround and maintenance activities in the third quarter.

Lloydminster thermal produced at high rates throughout the year as we applied our operating strategy and production and well delivery techniques. A planned turnaround was completed at Sunrise in the second quarter that impacted production. Tucker produced at stable rates.

Royalties

Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Saskatchewan.

Our Alberta oil sands royalty projects (Foster Creek, Christina Lake, Sunrise and Tucker) 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 percent 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 percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and transportation costs. Net revenues are a function of sales revenues less diluent costs, transportation costs, and allowed operating and capital costs.

Foster Creek, Christina Lake and Tucker are post-payout projects and Sunrise is a pre-payout project.

For our Saskatchewan properties, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, as well as each project’s Crown and freehold split. For Crown royalties, the pre-payout calculation is based on a one percent rate and the post-payout calculation is based on a 20 percent rate. The freehold calculation is limited to post-payout projects and is based on an eight percent rate.

Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates, partially offset by lower rates on Saskatchewan operations acquired in the Arrangement.

Royalties increased by $1.9 billion compared with 2020, mainly due to higher net revenue as a result of higher realized pricing combined with increased production.

Expenses

Transportation and Blending

Blending costs increased by $2.9 billion in 2021 compared with 2020. At Foster Creek and Christina Lake, blending costs increased due to higher condensate prices and volumes. Blending rates at Sunrise are comparable to Foster Creek and Christina Lake. Our Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets typically have lower blending rates due to lower crude oil viscosity.

Transportation costs were $1.5 billion in 2021, an increase of $299 million compared with 2020, primarily due to volumes from assets acquired in the Arrangement. In addition, costs rose as a result of volumes transported to U.S. destinations by pipeline due to increased capacity as a result of the Arrangement, partially offset by reduced volumes shipped by rail.

Per-unit Transportation Expenses

Per-unit transportation expenses were $7.23 per BOE in 2021 (2020 – $8.70 per BOE). The decrease was mainly a result of crude oil production from Foster Creek, Christina Lake and Sunrise shipped and sold to U.S. destinations via pipeline with less reliance on rail. Also contributing to the decrease were lower per-unit transportation costs at the Tucker, Lloydminster thermal, and Lloydminster conventional heavy oil properties acquired in the Arrangement, compared with Foster Creek, Christina Lake and Sunrise.

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At Foster Creek, per-unit transportation costs decreased five percent from 2020 to $10.51 per barrel as we reduced our reliance on shipping to the U.S. via rail while increasing our total volumes delivered to the U.S. via our pipeline capacity. We shipped 35 percent (2020 – 30 percent) of our volumes to U.S. destinations, of which 15 percent (2020 –30 percent) were via rail.

At Christina Lake, per-unit transportation costs decreased 11 percent from 2020 to $6.19 per barrel as less than two percent (2020 – 15 percent) of our volumes shipped to U.S. destinations were via rail.

Operating

Primary drivers of our operating expenses in 2021 were fuel, workforce, chemical costs, and repairs and maintenance. Total operating costs increased primarily due to costs on assets acquired from the Arrangement which have higher per barrel operating costs, and increased fuel costs due to higher natural gas prices, combined with the planned turnarounds at Foster Creek and Sunrise in the second quarter of 2021.

($/BOE) (1)	2021	Percent Change	2020	Percent Change		2019
Foster Creek
Fuel	4.07	44	2.83	15		2.47
Non-Fuel	6.67	4	6.41	(4	)	6.67
Total	10.74	16	9.24	1		9.14
Christina Lake
Fuel	3.52	61	2.18	6		2.06
Non-Fuel	4.72	2	4.61	(13	)	5.27
Total	8.24	21	6.79	(7	)	7.33
Other Oil Sands (2)
Fuel	5.01	—	—	—		—
Non-Fuel	11.97	—	—	—		—
Total	16.98	—	—	—		—
Total	11.52	47	7.84	(4	)	8.15

(1) Specified financial measure. See the Advisory.

(2) Includes Sunrise, Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

At both Foster Creek and Christina Lake, per barrel fuel costs increased primarily due to higher natural gas prices. Non-fuel costs were relatively flat at Foster Creek and Christina Lake as higher sales volumes offset increases due to higher electricity costs, chemical costs, the planned turnaround at Foster Creek in the second quarter of 2021, and reduced repairs and maintenance activity in 2020 due to COVID-19 safety measures.

Total unit operating costs increased $3.68 per BOE to $11.52 per BOE in 2021 compared with 2020. The increase was due to higher per-unit operating costs of the assets acquired in the Arrangement, increased Foster Creek and Christina Lake per-unit costs as discussed above, and the planned turnaround at Sunrise during the second quarter of 2021.

Netbacks

($/bbl)	2021	2020	2019
Sales Price (1)	62.82	28.64	53.78
Royalties (1)	10.38	2.34	8.97
Transportation (1) (2)	7.23	8.70	8.94
Operating Expenses (1) (2)	11.52	7.84	8.15
Netback (2) (3)	33.69	9.76	27.72

(1) Specified financial measure. See the Advisory.

(2) Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.

(3) Non-GAAP financial measure. See the Advisory.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate accounts for expenditures incurred to date, together with estimated 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 each 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.

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In 2021, DD&A increased $979 million compared with 2020 primarily as a result of the Arrangement. The average depletion rate for the year ended December 31, 2021 was $11.28 per BOE (2020 – $10.40 per BOE).

We depreciate our ROU assets on a straight-line or unit of production basis over the shorter of the estimated useful life or the lease term.

CONVENTIONAL

On December 31, 2020, the Conventional segment included assets primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, rich in natural gas, and NGLs. The assets are in Alberta and British Columbia and include interests in numerous natural gas processing facilities.

On January 1, 2021, as part of the Arrangement, we acquired assets primarily in the same areas mentioned above and the Rainbow Lake operating area located approximately 900 kilometres northwest of Edmonton. The acquired assets include interests in several natural gas processing facilities.

In 2021, we:

• Delivered safe and reliable operations.

• In the second half of the year, closed the sale of assets in the East Clearwater and Kaybob areas of Alberta for combined gross proceeds of $103 million. Prior to closing, the assets produced a total of approximately 11.0 thousand BOE per day. On November 30, we announced the sale of primarily our Montney assets in the Wembley area for cash proceeds of approximately $238 million. The transaction is expected to close in the first quarter of 2022.

• Earned revenue of $3.1 billion.

• Generated Operating Margin of $803 million, an increase of $608 million compared with 2020, due to higher average realized sales prices and increased volumes from assets acquired as part of the Arrangement, partially offset by higher per-unit operating expenses from assets acquired as part of the Arrangement.

• Invested capital of $222 million focused on short cycle, high return development wells which are expected to improve underlying cost structures through volume enhancement and offset natural declines.

• Completed numerous turnarounds involving field maintenance activities and safely shutting-in and reactivating production.

• Achieved a Netback of $15.95 per BOE.

Financial Results

($ millions)	2021		2020 (1)		2019 (1)
Gross Sales	3,235		904		935
Less: Royalties	150		40		30
Revenues	3,085		864		905
Expenses
Purchased Product	1,655		268		240
Transportation and Blending	74		81		82
Operating	551		320		339
Realized (Gain) Loss on Risk Management	2		—		—
Operating Margin	803		195		244
Unrealized (Gain) Loss on Risk Management (2)	1		—		—
Depreciation, Depletion and Amortization	3		880		319
Exploration Expense	(3	)	82		64
Segment Income (Loss)	802		(767	)	(139	)

⁽¹⁾  Prior periods have been reclassified to conform with current period’s operating segments.

⁽²⁾  Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.

Revenues

In 2021, gross sales included $1.7 billion (2020 – $269 million) relating to third-party sourced volumes, which are not included in our per-unit pricing metrics or our Netbacks.

In 2021, revenues included amounts relating to processing and transportation activities for third parties of $61 million, (2020 – $49 million), which are not included in our per-unit pricing metrics or our Netbacks.

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Operating Results

	2021		2020		2019
Total Sales Volumes (MBOE/d)		133.4		89.8		97.4
Total Realized Price per Unit Sold (1) ($/BOE)		31.20		17.84		17.95
Heavy Crude Oil ($/bbl)		—		31.45		—
Light Crude Oil ($/bbl)		76.32		42.78		65.70
NGLs ($/bbl)		42.93		22.04		26.36
Conventional Natural Gas ($/Mcf)		4.07		2.37		2.01
Production by Product
Heavy Crude Oil (Mbbls/d)		—		2.7		—
Light Crude Oil (Mbbls/d)		8.4		4.5		4.9
NGLs (Mbbls/d)		25.6		19.5		21.8
Conventional Natural Gas (MMcf/d)		597.6		379.0		424.5
Total Daily Production (MBOE/d)		133.6		89.9		97.4
Conventional Natural Gas Production (percentage of total)		75		70		73
Crude Oil and NGLs Production (percentage of total)		25		30		27
Effective Royalty Rate (percent)		10.3		7.9		5.1
Per Unit Transportation Cost (1) ($/BOE)		1.53		2.46		2.31
Per Unit Operating Cost (1) ($/BOE)		10.66		8.99		8.79
Per Unit DD&A (1) ($/BOE)		9.11		9.85		9.15

(1) Specified financial measure. See the Advisory.

Revenues

Price

Our total realized sales price increased in 2021 compared with 2020 primarily due to higher crude oil and natural gas benchmark prices.

Production Volumes

Production volumes increased in 2021, primarily due to 51.2 thousand BOE per day from assets acquired as part of the Arrangement. In addition, we brought 18 new net wells on production during the year ended December 31, 2021. The production increase is partially offset by asset dispositions during the year and natural declines.

Royalties

The Conventional assets are subject to royalty regimes in Alberta and British Columbia.

Effective royalty rates for the year ended December 31, 2021, increased primarily due to higher realized pricing and lower gas cost allowance credits.

Royalties increased $110 million in 2021, compared with 2020. The increase is primarily due to higher realized prices combined with increased production resulting from assets acquired as part of the Arrangement.

Expenses

Transportation

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. Transportation costs decreased by $7 million in 2021 compared with 2020. Per-unit transportation costs averaged $1.53 per BOE in the year ended December 31, 2021 (2020 – $2.46 per BOE).

Operating

Primary drivers of our operating expenses in 2021 were workforce, repairs and maintenance, property tax and lease costs, and electricity. Total operating costs increased $231 million in 2021 compared with 2020 primarily due to the assets acquired in the Arrangement.

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Operating costs increased $1.67 per BOE in 2021 compared with 2020 primarily due to operating expenses on assets acquired as part of the Arrangement. Per-unit operating costs in 2021, excluding assets acquired in the Arrangement, increased approximately seven percent year-over-year primarily due to volume declines, higher electricity, greenhouse gas and regulatory costs.

Netbacks

($/BOE)	2021	2020	2019
Sales Price (1)	31.20	17.84	17.95
Royalties (1)	3.06	1.23	0.83
Transportation and Blending (1)	1.53	2.46	2.31
Operating Expenses (1)	10.66	8.99	8.79
Netback (2) (3)	15.95	5.16	6.02

(1) Specified financial measure. See the Advisory.

(2) Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.

(3) Non-GAAP financial measure. See the Advisory.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate accounts for expenditures incurred to date, together with estimated 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 each 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 for 2021 was $9.11 per BOE (2020 – $9.85 per BOE). The average depletion rate excludes the impact of impairments and impairment reversals.

For the year ended December 31, 2021, total Conventional DD&A was $3 million (2020 – $880 million). The decrease was due to impairment write-downs of $555 million in 2020 resulting from decreases in forward commodity prices projected at the end of 2020 and impairment reversals of $378 million in 2021 due to improved forward commodity prices. The decrease was partially offset by DD&A on assets acquired in the Arrangement.

OFFSHORE

The Offshore segment was acquired as part of the Arrangement and includes offshore operations, exploration and development activities in China, the equity-accounted investment in the HCML joint venture in Indonesia and operations, exploration and development off the east coast of Canada.

In 2021, we:

• Delivered safe and reliable operations.

• Earned revenues of $1.7 billion.

• Generated Operating Margin of $1.4 billion.

• Achieved a Netback of $58.39 per BOE.

• Achieved single-day production records at our China and Indonesia assets.

• Invested capital of $175 million primarily on the West White Rose project in the Atlantic region.

• Entered into agreements with our partners to restructure our working interests on assets in the Atlantic region.

Financial Results

($ millions)	2021
Gross Sales	1,782
Less: Royalties	108
Revenues	1,674
Expenses
Transportation and Blending	15
Operating	239
Operating Margin	1,420
Depreciation, Depletion and Amortization	492
Exploration Expense	5
Share of (Income) Loss from Equity-Accounted Affiliates	(47)
Segment Income (Loss)	970

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Netbacks

		2021
($/BOE, except where indicated)	China	Indonesia (1)	Atlantic ($/bbl)	Total Offshore
Sales Price (2)	72.44	64.52	91.01	74.75
Royalties (2)	4.25	14.93	6.07	5.96
Transportation and Blending (2)	—	—	3.02	0.54
Operating Expenses (2)	5.10	9.55	28.34	9.86
Netback (3)	63.09	40.04	53.58	58.39
Total Sales Volumes (MBOE/d)	50.8	9.5	13.2	73.5
Per Unit DD&A (2)				25.62

(1) Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(2) Specified financial measure. See the Advisory.

(3) Non-GAAP financial measure. See the Advisory.

DD&A

In the Offshore segment, we deplete crude oil and natural gas properties using the unit-of-production method based on estimated proved developed producing reserves or total proved plus probable reserves, together with future development costs, determined using forward prices and costs. This rate, calculated at an area level, is then applied to our sales volume to determine DD&A each 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 developed producing or proved plus probable reserves. The average depletion rate for the year ended December 31, 2021 was $25.62 per BOE.

We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.

Asia Pacific

In China, the Liwan gas project includes working interests of 49 percent in natural gas developments at the Liwan 3-1 and Liuhua 34-2 producing fields and 75 percent in the Liuhua 29-1 producing field. We also have petroleum contracts in Blocks 15/33, 16/25 and 23/07, which are in the exploration phase. We drilled an exploration well in Block 15/33 in the South China Sea in October 2021. The well encountered and tested hydrocarbons and we are evaluating the results. Block 15/33 contains an existing discovery that was drilled in 2018. We also hold exploration rights in a block located offshore Taiwan.

In Indonesia, we hold a 40 percent share in HCML, which is a joint venture that is accounted for using the equity method. HCML is engaged in the exploration for and production of crude oil and natural gas resources offshore Indonesia in the Madura Strait production sharing contract (“PSC”) licence area. This area includes the producing BD field and ongoing developments at the MDA, MBH and MDK fields. The MDA and MBH fields are expected to start producing in mid-2022. A final investment decision was made in June 2021 by HCML for development of the MAC field with production expected by mid-2023. We signed a PSC in the fourth quarter of 2021 for the Liman contract area in East Java. In December 2021 we commenced the drilling of a development well in the MBH field which was completed by January 2022. We began drilling a second development well in the MBH field in the first quarter of 2022.

Financial Results

($ millions)	2021
Gross Sales	1,342
Less: Royalties	79
Revenues	1,263
Expenses
Operating	103
Operating Margin (1)	1,160

(1) Non-GAAP financial measure. See the Advisory.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  29

Operating Results

	2021
Total Sales Volumes (1)(2)(3) (MBOE/d)	60.3
NGLs (1)(2)(3) (Mbbls/d)	12.7
Conventional Natural Gas (1)(2)(3) (MMcf/d)	285.3
Total Realized Price per Unit Sold (3)(4) ($/BOE)	71.19
NGLs (3) ($/bbl)	79.83
Conventional Natural Gas (3) ($/Mcf)	11.48
Effective Royalty Rate (3) (percent)	8.4
Per Unit Operating Expense (3) (4) ($/BOE)	5.80

(1) Sales volumes approximates total daily production.

(2) Reported sales volumes include Cenovus’s working interest from the Liwan gas project.

(3) Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(4) Specified financial measure. See the Advisory.

Revenues

Price

The price we receive for natural gas in Asia is set under long-term contracts. The price we receive for NGLs is primarily driven by the price of Brent.

Production Volumes

Asia Pacific operations performed well. In 2021, daily production was relatively consistent during the year.

Royalties

Royalty rates are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments.

Expenses

Operating

Primary drivers of our operating expenses in 2021 were repairs and maintenance, insurance and workforce.

Atlantic

Our Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass located offshore Newfoundland and Labrador. The Jeanne d’Arc Basin includes the Terra Nova field, as well as the White Rose field and satellite extensions, including North Amethyst, West White Rose and South White Rose. In the Flemish Pass Basin, we hold a 35 percent non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. We are the operator of the White Rose field and satellite extensions and hold an ownership interest in the Terra Nova field, as well as several smaller undeveloped fields. We also hold exploration acreage offshore Newfoundland and Labrador.

Our production in 2021 was from the White Rose field and satellite extensions.

Production operations at the Terra Nova field have been suspended since December 2019. In the third quarter, Cenovus closed agreements with its partners to restructure its working interests in the Terra Nova field. Cenovus’s working interest increased to 34 percent, up from 13 percent. The Company received $78 million, before closing adjustments, from exiting partners as a contribution towards future decommissioning liabilities. The ALE project for the Terra Nova floating production, storage and offloading unit is underway in Spain for the dry dock portion of the project. Production is expected to resume before the end of 2022.

The West White Rose project remains deferred while we continue to evaluate options with our partners. In the third quarter of 2021, Cenovus entered into an agreement with Suncor to decrease our working interest in the White Rose field and satellite extensions. The working interest restructuring will not occur if the project does not proceed. Cenovus would reduce its working interest in the original field from 72.5 percent to 60.0 percent and in the satellite extensions from 68.875 percent to 56.375 percent. The decision whether to restart the West White Rose project is expected to be made by mid-2022.

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Financial Results

($ millions)	2021
Gross Sales		440
Less: Royalties		29
Revenues		411
Expenses
Transportation		15
Operating		136
Operating Margin (1)		260

(1) Non-GAAP financial measure. See the Advisory.

Operating Results

	2021
Total Sales Volumes
Light Crude Oil (Mbbls/d)		13.2
Total Realized Price per Unit Sold (1) ($/bbl)
Light Crude Oil ($/bbl)		91.01
Total Daily Production
Light Crude Oil (Mbbls/d)		14.1
Effective Royalty Rate (percent)		6.7
Per Unit Operating Expense (1) ($/bbl)		28.34

(1) Specified financial measure. See the Advisory.

Revenues

Price

The price we receive for light oil is primarily driven by the price of Brent.

Production and Sales Volumes

Atlantic operations performed well. Production was relatively steady with consistently high uptime in 2021. There were minor planned outages in the third quarter and a 15-day planned maintenance on the SeaRose floating production, storage and offloading unit (“SeaRose FPSO”), starting late in the third quarter and completed in October.

Light oil from production at the White Rose field is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers. The result is a timing difference between production and sales. Our sales volumes were 13.2 thousand barrels per day in 2021.

Royalties

Royalties at the White Rose field are based on an agreement between our working interest partners and the Government of Newfoundland and Labrador. We currently pay a basic royalty of 7.5 percent of gross sales at the White Rose field and 5.0 percent of gross sales at the satellite extensions.

Expenses

Operating

Primary drivers of our operating expenses in 2021 were repairs and maintenance, workforce, vessel costs and helicopter costs.

Transportation

Transportation includes the cost of transporting crude oil from the SeaRose FPSO to onshore via tankers, as well as storage costs.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  31

DOWNSTREAM

CANADIAN MANUFACTURING

On December 31, 2020, Canadian Manufacturing operations included the Bruderheim crude-by-rail terminal.

On January 1, 2021, as part of the Arrangement, we acquired:

• The Lloydminster Upgrader, which is designed to process blended heavy crude oil and bitumen feedstock, creating high quality, low-sulphur synthetic crude oil and ultra-low sulphur diesel. The Lloydminster Upgrader has crude oil throughput capacity of 81.5 thousand barrels per day.

• The Lloydminster Refinery, which processes heavy crude oil into asphalt products used in road construction and maintenance. The refinery also produces condensate, bulk distillates and industrial products. The Lloydminster Refinery has crude oil throughput capacity of 29.0 thousand barrels per day.

• Ethanol plants in Lloydminster, Saskatchewan and Minnedosa, Manitoba.

The Lloydminster Upgrader has the option to source crude oil feedstock from our Lloydminster thermal and Tucker production. The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production.

In 2021 we:

• Delivered safe and reliable operations.

• Averaged combined crude utilization of 96 percent at the Lloydminster Upgrader and Lloydminster Refinery.

• Achieved multiple single-day diesel production records at the Lloydminster Upgrader.

• Generated Operating Margin of $532 million, an increase of $487 million compared with 2020 due to assets acquired in the Arrangement.

• Invested capital of $37 million.

Financial Results

($ millions)	2021	2020	2019
Revenues	4,472	82	77
Purchased Product	3,552	—	—
Gross Margin (1)	920	82	77
Expenses
Operating	388	37	41
Operating Margin	532	45	36
Depreciation, Depletion and Amortization	167	8	7
Segment Income (Loss)	365	37	29

(1) Non-GAAP financial measure. See the Advisory.

32  |  CENOVUS ENERGY 2021 ANNUAL REPORT

Operating Results

	2021		2020		2019
Crude Oil Throughput Capacity (Mbbls/d)		110.5		—		—
Lloydminster Upgrader (Mbbls/d)		81.5		—		—
Lloydminster Refinery (Mbbls/d)		29.0		—		—
Crude Oil Throughput (Mbbls/d)		106.5		—		—
Lloydminster Upgrader (Mbbls/d)		79.0		—		—
Lloydminster Refinery (Mbbls/d)		27.5		—		—
Crude Utilization (1) (percent)		96		—		—
Refined Products Output (Mbbls/d)		107.9		—		—
Upgrading Differential (2)		16.83		—		—
Refining Margin (3) ($/bbl)
Lloydminster Upgrader ($/bbl)		17.99		—		—
Lloydminster Refinery ($/bbl)		15.64		—		—
Unit Operating Expense (4) ($/bbl)		9.97		—		—
Crude-by-Rail Operations
Volumes Loaded (5) (Mbbls/d)		12.1		30.4		53.3
Ethanol Production (thousands of litres/d)		661.0		—		—

(1) Based on crude throughput volumes and results of operations at the Lloydminster Upgrader and Refinery.

(2) Based on benchmark price differential between heavy oil feedstock and synthetic crude.

(3) Non-GAAP financial measure. See the Advisory.

(4) Specified financial measure. See the Advisory. Operating costs divided by crude oil throughput.

(5) Volumes transported outside of Alberta, Canada.

Revenues, Gross Margin and Refining Margin

Upgrading operations process blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur distillates. Revenues are dependent on the sales price of synthetic crude oil and diesel. Upgrading gross margin is primarily dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil feedstock.

Lloydminster Refinery operations process blended heavy crude oil into asphalt and industrial products. Revenues are dependent on market prices for asphalt and other industrial products. The gross margin is primarily dependent on revenues and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery increase during paving season, which typically runs from May through October each year.

For the year ended December 31, 2021, revenue includes approximately $55 million for a customer settlement of a take-or-pay contract related to Bruderheim crude-by-rail terminal operations. Revenues and gross margin decreased compared with 2020 due to minimal third-party volumes loaded and Cenovus’s reduced reliance on rail.

Operating Expense

Primary drivers of operating expenses in 2021, were workforce, repairs and maintenance, and energy costs. For the year ended December 31, 2021, unit operating expenses were $9.97 per barrel of crude throughput.

DD&A

Canadian Manufacturing assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. For the year ended December 31, 2021, Canadian Manufacturing DD&A was $167 million (2020 – $8 million) as a result of DD&A on assets acquired as part of the Arrangement.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  33

U.S. MANUFACTURING

On December 31, 2020, U.S. Manufacturing operations included our 50 percent interest in WRB Refining LP, which owns the Wood River and Borger refineries. WRB Refining LP is jointly owned with operator Phillips 66.

On January 1, 2021, as part of the Arrangement, we acquired:

• The Lima Refinery, which we wholly own, is located in Lima, Ohio. The refinery produces low sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products.

• The Toledo Refinery, with a 50 percent ownership interest and operated by BP Products North America Inc. (“BP”), through BP-Husky Refining LLC. Products from the refinery include low sulphur gasoline, ultra-low sulphur diesel, jet fuel and other by-products.

• The Superior Refinery, which we wholly own, is located in Superior, Wisconsin. On April 26, 2018, the refinery experienced an incident while preparing for a major turnaround and was taken out of operation. The refinery is being rebuilt and is expected to restart around the first quarter of 2023.

In 2021:

• At the Wood River and Borger refineries, throughput was negatively impacted by:

○ Planned turnarounds commenced in the first quarter and completed in the second quarter.

○ Temporary unplanned outages during the year.

• At the Lima Refinery, throughput was negatively impacted by:

○ A planned turnaround completed in October and November and subsequent unplanned equipment outages. The refinery returned to normal operations towards the end of January 2022.

○ Temporary unplanned outages in the first quarter.

○ A two-week disruption in the first quarter at the Mid-Valley pipeline, which transports feedstock to the Lima Refinery.

○ Third-party maintenance on feeder pipelines in the second quarter.

• At the Toledo Refinery, throughput was optimized in line with market demand.

• Increased crude utilization to 80 percent from 75 percent in 2020 as we ramped up throughput early in the first quarter as market crack spreads improved, partially offset by the factors discussed above.

• We invested capital of $995 million focused primarily on the Superior Refinery rebuild, combined with refining reliability, maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the Toledo Refinery.

Financial Results

($ millions)	2021			2020  (1)			2019  (1)
Revenues		20,043			4,733			8,291
Purchased Product		17,955			4,429			6,735
Gross Margin (2)		2,088			304			1,556
Expenses
Operating		1,772			748			877
Realized (Gain) Loss on Risk Management		104			(21	)		(16	)
Operating Margin		212			(423	)		695
Unrealized (Gain) Loss on Risk Management (3)		1			(1	)		1
Depreciation, Depletion and Amortization		2,381			728			273
Segment Income (Loss)		(2,170	)		(1,150	)		421

⁽¹⁾  Prior periods have been reclassified to conform with current period’s operating segments.

⁽²⁾  Non-GAAP financial measure. See the Advisory.

⁽³⁾  Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.

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Select Operating Results

	2021		2020		2019
Crude Oil Throughput Capacity (Mbbls/d)		502.5		247.5		241.0
Lima Refinery		175.0		—		—
Toledo Refinery (1)		80.0		—		—
Wood River and Borger Refineries (1)		247.5		247.5		241.0
Crude Oil Throughput (Mbbls/d)		401.5		185.9		221.3
Lima Refinery		126.9		—		—
Toledo Refinery (1)		69.9		—		—
Wood River and Borger Refineries (1)		204.7		185.9		221.3
Throughput by Product (Mbbls/d)
Heavy Crude Oil		138.7		74.6		88.3
Light and Medium Crude Oil		262.8		111.3		133.0
Crude Utilization (percent)		80		75		92
Refining Margin (2)(3) ($/bbl)		14.25		4.47		19.26
Unit Operating Expense (3)(4) ($/bbl)		12.09		11.00		10.86

(1) Represents Cenovus’s 50 percent interest in Wood River, Borger and Toledo refinery operations.

(2) Non-GAAP financial measure. See the Advisory.

(3) Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima and Toledo refineries.

(4) Specified financial measure. See the Advisory.

All refineries continue to optimize throughput as market conditions dictate. We began economic crude rate reductions late in the first quarter of 2020 in response to reduced demand for refined products resulting from COVID-19. Our refineries continued to run at reduced rates until early in the first quarter of 2021 as market crack spreads started to improve. Throughput was impacted in the second and third quarters due to planned and unplanned outages, and in the fourth quarter due to the planned turnaround at the Lima Refinery.

At the Lima Refinery, we had a temporary unplanned outage in the first quarter of 2021 due to an incident that shut down our fluid catalytic cracking unit. In addition, for two weeks in February, winter storm Uri disrupted the Mid-Valley pipeline that supplies the refinery’s feedstock, further impacting throughput. Throughput rates began ramping up in March as market conditions improved. In the second quarter, there was third-party maintenance on the Mid-Valley and West Texas Gulf pipelines, which reduced throughput. Throughput rates increased in late May and June after completion of the maintenance. Production slowed at the end of September as we prepared for a planned turnaround completed in October and November. We encountered unplanned equipment outages subsequent to the completion of the turnaround. As a result, crude utilization at the refinery in the fourth quarter was only 34 percent, compared with 85 percent in the first nine months of 2021.

At the Toledo Refinery, throughput was optimized in line with market demand in 2021.

At the Wood River and Borger refineries, planned turnarounds began in the first quarter and were completed by mid-May and early April, respectively. Throughput was further impacted, temporarily, by unplanned outages in 2021. In the fourth quarter, crude utilization at the refineries was 92 percent.

Revenues and Gross Margin

While market crack spreads are an indicator of margin from processing crude oil into refined products, 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. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis.

In 2021, revenues increased $15.3 billion due to volumes from assets acquired in the Arrangement and higher refined product pricing benchmarks.

In 2021, gross margin increased $1.8 billion compared with 2020 driven by improved market crack spreads combined with increased throughput from the Arrangement and the Wood River and Borger refineries, partially offset by higher RINs costs.

In 2021, the RINs costs were $880 million (2020 – $177 million) due to higher RINs pricing and assets acquired in the Arrangement. RINs prices were US$6.76 per barrel in the year ended December 31, 2021 (2020 – US$2.48 per barrel). RINs pricing was volatile during the year, ranging from below US$4.00 per barrel to almost US$10.00 per barrel.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  35

Operating Expenses

Primary drivers of operating expenses for the year ended December 31, 2021, were workforce costs, repairs, maintenance, services and energy costs. In 2021, operating costs increased $1.0 billion year-over-year. The increase was due to:

• Operating expenses on assets acquired in the Arrangement.

• Turnaround activities at the Wood River, Borger and Lima refineries.

• Higher utility pricing at the Lima and Borger refineries associated with the impacts of winter storm Uri in the first quarter of 2021.

DD&A

U.S. Manufacturing assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. U.S. Manufacturing DD&A was $2.4 billion in 2021 (2020 – $728 million). The increase is the result of DD&A on assets acquired in the Arrangement, and impairment charges of $1.9 billion in the Lima, Wood River and Borger cash-generating units (“CGU”). The increase is partially offset by an impairment charge of $450  million related to the Borger CGU in 2020.

RETAIL

Retail operations were acquired on January 1, 2021, as part of the Arrangement.

As of December 31, 2021, there were 531 independently operated Husky and Esso-branded petroleum product outlets. Our retail and commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban and rural markets across Canada, while our bulk distributors offer direct sales to commercial and agricultural markets in the prairie provinces.

On November 30, 2021, Cenovus announced agreements to sell 337 gas stations within our retail fuels network for total cash proceeds of $420 million before closing adjustments. The sales are expected to close in mid-2022. We are retaining our commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.

Financial Results

($ millions)	2021
Gross Sales	2,158
Purchased Product	2,019
Gross Margin (1)	139
Expenses
Operating	98
Operating Margin	41
Depreciation, Depletion and Amortization	59
Segment Income (Loss)	(18	)

(1) Non-GAAP financial measure. See the Advisory.

Select Operating Results

	2021
Fuel Sales Volume, including wholesale
Fuel Sales (millions of litres/d)	6.9
Fuel Sales per Retail Outlet (thousands of litres/d)	13.0

Gross Margin

Gross margin is primarily driven by gasoline and diesel prices and retail pricing for motor fuels.

Operating expenses

Primary drivers of our operating expenses for the year ended December 31, 2021, were repairs and maintenance, property tax, workforce and utilities.

36  |  CENOVUS ENERGY 2021 ANNUAL REPORT

DD&A

Retail assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which range from three to 30 years. The service lives of these assets are reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. For the year ended December 31, 2021, Retail DD&A was $59 million as a result of retail assets acquired in the Arrangement.

CORPORATE AND ELIMINATIONS

For the year ended December 31, 2021, our Corporate and Eliminations risk management activities resulted in realized risk management losses of $101 million (2020 – losses of $5 million) primarily due to the realization, in the first quarter of 2021, of WTI put and call option contracts acquired as part of the Arrangement.

Expenses

($ millions)	2021		2020		2019
General and Administrative	849		292		331
Finance Costs	1,082		536		511
Interest Income	(23	)	(9	)	(12	)
Integration Costs	349		29		—
Foreign Exchange (Gain) Loss, Net	(174	)	(181	)	(404	)
Re-measurement of Contingent Payment	575		(80	)	164
(Gain) Loss on Divestiture of Assets	(229	)	(81	)	(2	)
Other (Income) Loss, Net	(309	)	40		9
	2,120		546		597

General and Administrative

Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive costs, information technology costs and operating costs associated with our real estate portfolio. For the year ended December 31, 2021, general and administrative expenses increased compared with 2020 due to a larger workforce resulting from the Arrangement and a provision for incentive rewards related to reaching our synergy targets. In addition, in 2021 long-term incentive costs were higher than 2020 due to share price increases.

Finance Costs

In the year ended December 31, 2021, finance costs increased by $546 million due to:

• Interest expense on long-term debt assumed as part of the Arrangement.

• A $121 million net premium on the redemption of long-term debt in the third and fourth quarters of 2021.

• Increased unwinding of the discount on decommissioning liabilities as a result of the Arrangement.

• Interest expense on lease liabilities as result of liabilities assumed as part of the Arrangement.

The weighted average interest rate on outstanding debt for the year ended December 31, 2021, was 4.6 percent (2020 – 4.9 percent).

Integration Costs

For the year ended December 31, 2021, we incurred $349 million of costs as a result of the Arrangement, not including capital expenditures. Integration costs included $180 million of severance payments, $65 million of transaction costs and $104 million in other integration related costs in 2021.

Foreign Exchange

($ millions)	2021		2020		2019
Unrealized Foreign Exchange (Gain) Loss	(312	)	(131	)	(827	)
Realized Foreign Exchange (Gain) Loss	138		(50	)	423
	(174	)	(181	)	(404	)

In 2021, unrealized foreign exchange gains of $312 million were mainly as a result of the translation of our U.S. dollar denominated debt. Realized foreign exchange losses of $138 million were recorded primarily due to the recognition of a $173 million loss on the repurchase of U.S. dollar denominated debt in the third and fourth quarters of 2021.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  37

Re-measurement of Contingent Payment

Related to Foster Creek and Christina Lake production, Cenovus agreed to make quarterly payments to ConocoPhillips Company and certain of its subsidiaries (“ConocoPhillips”) during the five years subsequent to the closing date of the acquisition from ConocoPhillips of its 50 percent interest in the FCCL Partnership on May 17, 2017, for quarters in which the average WCS crude oil price exceeds $52 per barrel during the quarter. The quarterly payment is $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 agreement expires on May 17, 2022.

The contingent payment is accounted for as a financial option. The fair value of $236 million as at December 31, 2021, 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 year ended December 31, 2021, non-cash re-measurement losses of $575 million were recorded. As at December 31, 2021, $160 million is payable under this agreement. In 2021, we paid $242 million under this agreement, of which $175 million was recognized as cash flow from operating activities and reduced Adjusted Funds Flow. All future payments will be recognized as a reduction to cash flow from operating activities and Adjusted Funds Flow.

Average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately $77.35 per barrel and $78.39 per barrel.

Other (Income) Loss, Net

For the year ended December 31, 2021, other (income) loss increased by $349 million. The increase is primarily due to:

• Business interruption insurance proceeds related to the Superior Refinery of $120 million in 2021.

• A $100 million loss related to the Keystone XL pipeline project in 2020.

• The settlement of a legal claim in favour of Cenovus in 2021.

• Other income of $35 million in 2021 related to the Headwater warrants, which were exercised in December 2021.

DD&A

Corporate and Eliminations DD&A is in respect of corporate assets, such as computer equipment, leasehold improvements, office furniture and certain ROU assets. 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. ROU assets are depreciated on a straight-line basis over the estimated useful life of the asset or the lease term. DD&A for the year ended December 31, 2021, was $118 million (2020 – $161 million). The decrease in DD&A year-over-year was primarily due to $52 million of information technology assets that were written off in 2020 in anticipation of the Arrangement closing.

Income Tax

($ millions)	2021		2020			2019
Current Tax
Canada		104		(14	)		14
United States		—		1			3
Asia Pacific		171		—			—
Other International		1		—			—
Current Tax Expense (Recovery)		276		(13	)		17
Deferred Tax Expense (Recovery)		452		(838	)		(814	)
Total Tax Expense (Recovery)		728		(851	)		(797	)

38  |  CENOVUS ENERGY 2021 ANNUAL REPORT

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

($ millions, except tax rates)	2021	2020	2019
Earnings (Loss) From Operations Before Income Tax	1,315	(3,230)	1,397
Canadian Statutory Rate	23.7%	24.0%	26.5%
Expected Income Tax Expense (Recovery) From Operations	312	(775)	370
Effect on Taxes Resulting From:
Statutory and Other Rate Differences	3	19	(52)
Non-Taxable Capital (Gains) Losses	63	(42)	(38)
Non-Recognition of Capital (Gains) Losses	27	(42)	(39)
Adjustments Arising From Prior Year Tax Filings	(5)	(8)	4
Recognition of U.S. Tax Basis	—	—	(387)
U.S. Tax Attribute Limitation	217	—	—
Impact of Rate Changes	106	(7)	(671)
Other	5	4	16
Total Tax Expense (Recovery) From Operations	728	(851)	(797)
Effective Tax Rate	55.4%	26.3%	(57.1)%

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 with consideration of the current economic environment, 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.

For the year ended December 31, 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared with 2020. In the fourth quarter we recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with provincial allocations.

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.

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QUARTERLY RESULTS

	2021					2020
($ millions, except where indicated)	Q4		Q3	Q2	Q1	Q4		Q3		Q2		Q1
Average Commodity Prices (US$/bbl)
Brent (1)	79.73		73.47	68.83	60.90	44.22		42.99		29.20		50.26
WTI	77.19		70.56	66.07	57.84	42.66		40.93		27.85		46.17
WCS	62.55		56.98	54.58	45.37	33.36		31.84		16.38		25.64
Chicago 3-2-1 Crack Spread	16.06		20.67	20.50	12.93	7.05		7.89		6.44		8.79
RINs	6.11		7.32	8.12	5.49	3.48		2.64		2.21		1.58
Production Volumes (MBOE/d)	825.3		804.8	765.9	769.3	467.2		471.8		465.4		482.6
Bitumen (Mbbls/d)	606.0		576.5	528.6	532.9	380.7		386.0		373.2		387.0
Heavy Crude Oil (Mbbls/d) (2)	18.9		20.5	20.8	20.5	1.9		3.2		2.2		3.6
Light and Medium Crude Oil (Mbbls/d) (2)	17.8		22.6	24.4	25.6	4.3		4.3		4.3		5.1
NGLs (Mbbls/d)	35.6		35.5	41.1	41.1	18.4		18.3		20.3		21.1
Conventional Natural Gas (MMcf/d)	883.5		897.9	905.6	894.9	369.5		360.1		392.2		394.8
Crude Throughput (3) (Mbbls/d)	469.9		554.1	539.0	469.1	169.0		191.1		162.3		221.1
Revenues (4)	13,726		12,701	10,637	9,293	3,543		3,737		2,311		3,952
Operating Margin	2,600		2,710	2,184	1,879	625		594		291		(589	)
Cash From (Used in) Operating Activities	2,184		2,138	1,369	228	250		732		(834	)	125
Adjusted Funds Flow (5)	1,948		2,342	1,817	1,141	333		407		(469	)	(154	)
Capital Investment	835		647	534	547	242		148		147		304
Free Funds Flow	1,113		1,695	1,283	594	91		259		(616	)	(458	)
Net Earnings (Loss)	(408	)	551	224	220	(153	)	(194	)	(235	)	(1,797	)
Per Share - basic ($)	(0.21	)	0.27	0.11	0.10	(0.12	)	(0.16	)	(0.19	)	(1.46	)
Per Share - diluted ($)	(0.21	)	0.27	0.11	0.10	(0.12	)	(0.16	)	(0.19	)	(1.46	)
Long-Term Debt, Including Current Portion (6)	12,385		12,986	13,380	13,947	7,441		7,797		8,085		6,979
Net Debt (7)	9,591		11,024	12,390	13,340	7,184		7,530		8,232		7,421
Cash Dividends
Common Shares	70		35	36	35	—		—		—		77
Per Common Share ($)	0.0350		0.0175	0.0175	0.0175	—		—		—		0.0625
Preferred Shares	8		9	8	9	—		—		—		—

(1) Calendar month average of settled prices for Dated Brent.

(2) Medium crude oil production in the first three quarters of 2021 was reclassified to heavy oil production.

(3) Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.

(4) Comparative figures have been re-presented for portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.

(5) Comparative figures have been restated to conform with the definition in this MD&A.

(6) Includes current portion of long-term debt of $nil as at December 31, 2021, $545 million as at September 30, 2021 and $632 million as at June 30, 2021 (March 31, 2021, December 31, 2020, September 30, 2020, June 30, 2020 and March 31, 2020 – $nil).

(7) In 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash equivalents assumed of $735 million.

Fourth Quarter 2021 Results Compared with the Fourth Quarter 2020

The summary below compares financial results for the three months ended December 31, 2021 compared with 2020. Variances from the prior year reflect higher commodity prices, the impact of assets acquired in the Arrangement and strong performance from our upstream assets.

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Upstream Production Volumes

Production increased 358.1 thousand BOE per day compared with the fourth quarter of 2020, primarily due to 285.4 thousand BOE per day from assets acquired in the Arrangement and higher production at Foster Creek and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online in 2021 in contrast with a planned turnaround at Christina Lake and operational outages at Foster Creek in the fourth quarter of 2020.

In the fourth quarter of 2021, we sold approximately 20 percent (2020 – 20 percent) of our Oil Sands production to U.S. destinations to improve our realized sales prices.

Conventional production increased by 39.1 thousand BOE per day compared with the fourth quarter of 2020 primarily due to assets acquired in the Arrangement, partially offset by the disposition of assets in the East Clearwater and Kaybob areas in 2021.

Offshore production was 73.1 thousand BOE per day during the quarter and is entirely from assets acquired in the Arrangement.

Downstream Manufacturing

In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery ran at or near capacity throughout the fourth quarter of 2021.

U.S. Manufacturing throughput increased 192.6 thousand barrels per day compared with the fourth quarter of 2020 due to 134.3 thousand barrels per day of throughput from assets acquired in the Arrangement and significantly higher throughput at the Wood River and Borger refineries as the market for refined products improved. We completed a planned turnaround at the Lima Refinery in October and November and subsequently encountered unplanned equipment outages. At the Toledo Refinery, throughput was optimized in line with market demand throughout 2021. In the fourth quarter of 2021, the Toledo Refinery achieved a crude utilization rate of 94 percent.

Revenues

Total revenues increased $10.2 billion in the fourth quarter of 2021 compared with the same period of 2020. Downstream revenues increased $7.0 billion primarily due to higher refined product pricing consistent with the improved average refined product benchmark prices and higher refined product output due to increased throughput. Upstream revenues increased by $5.5 billion primarily due to higher realized sales prices of $70.02 per BOE compared with $38.37 per BOE in 2020, combined with increased sales volumes.

Operating Margin

Operating Margin increased in the fourth quarter of 2021, primarily due to:

• Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.

• Upstream and refined products sales volumes from assets acquired in the Arrangement.

• Increased sales at Foster Creek and Christina Lake.

• Higher market crack spreads in the U.S. Manufacturing segment.

These increases in Operating Margin were partially offset by:

• Increased blending costs due to higher condensate prices and volumes.

• Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.

• Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management contract prices.

• Increased RINs costs impacting our U.S. Manufacturing segment.

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to increased Operating Margin, as discussed above, and a $100 million loss on the Keystone XL pipeline project in the fourth quarter of 2020. The increase was partially offset by:

• Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.

• Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions related to reaching our synergy-focused incentive plan.

• Contingent payment of $119 million. In the fourth quarter of 2020, the contingent payment was recorded to cash from (used in) investing activities.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  41

The change in non-cash working capital in the fourth quarter of 2021 was primarily due to an increase in accounts payable and decrease in accounts receivable, partially offset by increase in inventories on December 31, 2021, compared with September 30, 2021. In the three months ended December 31, 2021, accounts receivable decreased primarily due to the timing of cash receipts from customers, wider heavy oil differentials to close the quarter compared to the third quarter and lower sales volumes in the U.S. Manufacturing segment. The decreases were partially offset by higher sales volumes in the Oil Sands segment to close the quarter. The increase in inventory was primarily due to a build of crude oil volumes held in inventory at Foster Creek and Christina Lake. The increase in accounts payable relates to higher accrued long-term incentives, higher accrued condensate purchases, higher accrued contingent liability payable and higher income taxes payable.

Net Earnings (Loss)

Net Loss in the fourth quarter of 2021 was higher than the Net Loss in 2020 due to:

• Impairment charges of $1.9 billion in the U.S. Manufacturing segment in 2021.

• Lower unrealized foreign exchange gains compared with 2020.

• Provisions related to reaching our synergy-focused incentive plan.

• Increased general and administrative costs, finance expenses and DD&A expense as a result of the Arrangement.

• Income tax expense compared with a recovery in 2020.

The increase was partially offset by:

• Higher Operating Margin, as discussed above.

• Impairment reversals of $378 million in the Conventional segment in the fourth quarter of 2021.

• Impairment charges of $240 million in the Conventional segment in the fourth quarter of 2020.

• Unrealized risk management gain of $222 million (2020 – $49 million loss).

• Higher other income due to business interruption insurance proceeds related to the Superior Refinery in 2021 and a $100 million loss on the Keystone XL pipeline project in the fourth quarter of 2020.

Capital Investment

Capital investment in the fourth quarter of 2021 was $835 million, compared with $242 million in the fourth quarter of 2020. The increase is primarily due to the reduction of our capital investment program in 2020 in response to COVID-19 and capital investment on assets acquired in the Arrangement.

OIL AND GAS RESERVES

As at December 31, 2021   (before royalties) (1)	Bitumen (2) (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional   Natural Gas (3) (Bcf)		Total   (MMBOE)
Total Proved		5,573		45		89		2,219		6,077
Probable		1,850		152		39		959		2,201
Total Proved Plus Probable		7,423		197		128		3,178		8,278
As at December 31, 2020   (before royalties)	Bitumen (MMbbls)		Light and Medium Oil (MMbbls)		NGLs (MMbbls)		Conventional Natural Gas (3) (Bcf)		Total   (MMBOE)
Total Proved		4,812		7		50		965		5,030
Probable		1,520		6		31		601		1,656
Total Proved Plus Probable		6,332		13		81		1,566		6,686

(1) Includes reserves associated with the Tucker asset sold on January 31, 2022, representing before royalties reserves of 123 million barrels and 145 million barrels on a total proved and total proved plus probable basis, respectively.

(2) Includes heavy crude oil reserves that are not material.

(3) Includes shale gas reserves that are not material.

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Developments in 2021 compared with 2020 include:

• Bitumen total proved and total proved plus probable reserves increased by 761 million barrels and 1.1 billion barrels, respectively, due to additions from the Arrangement, improved performance at Christina Lake and a regulatory approval at our Lloydminster thermal assets, partially offset by current year production.

• Light and medium oil total proved and total proved plus probable reserves increased by 38 million barrels and 184 million barrels, respectively, due to additions from the Arrangement, updates to the Conventional segment development plan, the Terra Nova restructuring, and economic factors due to increased product pricing. The increases were partially offset by dispositions in the Conventional segment and current year production.

• NGLs total proved and total proved plus probable reserves increased by 39 million barrels and 47 million barrels, respectively, due to additions from the Arrangement, updates to the Conventional segment development plan, and economic factors due to increased product pricing. The increases were partially offset by dispositions in the Conventional segment and current year production.

• Conventional natural gas total proved and total proved plus probable reserves increased by 1.3 trillion cubic feet and 1.6 trillion cubic feet, respectively, due to additions from the Arrangement, updates to the Conventional segment development plan, the sanctioning of the MAC field in Indonesia, and economic factors due to improved product pricing. The increases were partially offset by dispositions in the Conventional segment and current year production.

The reserves data is presented as at December 31, 2021 using an average of forecasts (“IQRE Average Forecast”) by McDaniel & Associates Consultants Ltd. (“McDaniel”), GLJ Ltd. (“GLJ”) and Sproule Associates Limited (“Sproule”). The IQRE Average Forecast prices and costs are dated January 1, 2022. Comparative information as at December 31, 2020 uses the January 1, 2021 IQRE Average Forecast prices and costs.

Additional information with respect to the evaluation and reporting of our reserves in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities” is contained in our AIF for the year ended December 31, 2021. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this MD&A in the Risk Management and Risk Factors section and the Advisory.

LIQUIDITY AND CAPITAL RESOURCES

($ millions)	2021			2020			2019
Cash From (Used In)
Operating Activities		5,919			273			3,285
Investing Activities		(942	)		(863	)		(1,432	)
Net Cash Provided (Used) Before Financing Activities		4,977			(590	)		1,853
Financing Activities		(2,507	)		837			(2,413	)
Foreign Currency		25			(55	)		(35	)
Increase (Decrease) in Cash and Cash Equivalents		2,495			192			(595	)
As at December 31, ($ millions)		2021			2020			2019
Cash and Cash Equivalents (1)		2,873			378			186
Total Debt (2)		12,464			7,562			6,699

(1) On January 1, 2021, we acquired cash and cash equivalents of $735 million on the closing of the Arrangement.

(2) On January 1, 2021, on the closing of the Arrangement, we acquired Total Debt with a fair value of $6.6 billion.

Cash From (Used in) Operating Activities

For the year ended December 31, 2021, cash generated from operating activities increased mainly due to higher Operating Margin combined with distributions received from equity-accounted affiliates. The increase was partially offset by changes in non-cash working capital, and higher finance costs, general and administrative costs, and integration costs as discussed in the Corporate and Eliminations section of this MD&A.

Excluding the current portion of the contingent payment and assets and liabilities held for sale, our adjusted working capital was $3.8 billion at December 31, 2021, compared with $653 million at December 31, 2020. The increase was primarily due to working capital acquired from the Arrangement and the improved commodity price environment as discussed in the Operating and Financial Results section of this MD&A. Working capital increased due to increased accounts receivable and inventories, partially offset by increased accounts payable.

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

CENOVUS ENERGY 2021 ANNUAL REPORT  |  43

Cash From (Used in) Investing Activities

Cash used in investing activities was lower in the year ended December 31, 2021 compared with 2020 primarily due to cash acquired through the Arrangement, proceeds from divestitures and changes in non-cash working capital. These cash inflows are partially offset by higher capital spending mainly as result of our larger asset base acquired through the Arrangement.

Cash From (Used in) Financing Activities

During the year ended December 31, 2021, we closed a public offering in the U.S. for US$1.25 billion of senior unsecured notes, consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior unsecured notes due February 15, 2052. We also paid US$2.3 billion to repurchase a portion of our unsecured notes with a principal amount of US$2.2 billion. In addition, we repaid $77 million in short-term borrowings and $350 million of revolving long-term debt.

For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB which allows the Company to purchase up to 146.5 million common shares between November 9, 2021 and November 8, 2022. The shares were purchased at an average price of $15.56 per common share for a total of $265 million. The common shares were subsequently cancelled.

Long-Term Debt and Total Debt

Total Debt as at December 31, 2021 was $12.5 billion (December 31, 2020 – $7.6 billion), which includes $12.4 billion of long-term debt. The increase in Total Debt was primarily due to the assumption of Total Debt with a fair value of $6.6 billion at closing of the Arrangement. The principal amount of debt assumed from Husky that is owed to lenders between 2024 and 2037 is $4.5 billion. We have reduced our Total Debt by $1.7 billion since the closing of the Arrangement as described in the cash used in financing activities above.

Subsequent to year-end, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and 2024 on February 9, 2022.

As at December 31, 2021, we were in compliance with all of the terms of our debt agreements.

Available Sources of Liquidity

The following sources of liquidity are available as at December 31, 2021:

($ millions)	Term	Amount Available
Cash and Cash Equivalents	Not applicable	2,873
Committed Credit Facilities
Revolving Credit Facility – Tranche A	August 2025	4,000
Revolving Credit Facility – Tranche B	August 2024	2,000
Uncommitted Demand Facilities
Cenovus Energy Inc.	Not applicable	1,015
WRB Refining LP (Cenovus’s proportionate share)	Not applicable	111
Sunrise Oil Sands Partnership (Cenovus’s proportionate share)	Not applicable	5

We expect to fund our near-term cash requirements through cash from operating activities and prudent use of our balance sheet capacity including draws on our committed credit facilities and our uncommitted demand facilities and other corporate and financial opportunities that may be available to us. During 2021, we were upgraded by Fitch Ratings to investment grade. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service, DBRS Limited and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital is dependent on current credit ratings and market conditions.

Under the terms of our committed credit facility, we are required to maintain a debt to capitalization ratio, as defined in the debt agreements, not to exceed 65 percent. We are well below this limit.

Committed Credit Facilities

As at December 31, 2021, Cenovus had a total committed credit facility of $6.0 billion that consists of a $2.0 billion tranche maturing on August 18, 2024 and a $4.0 billion tranche maturing on August 18, 2025. As at December 31, 2021, no amount was drawn on the committed credit facility (December 31, 2020 – $nil).

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Uncommitted Demand Facilities

In the fourth quarter, we cancelled and replaced all uncommitted demand facilities with new uncommitted demand facilities. We have uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes or the full amount can be available to issue letters of credit. As at December 31, 2021, there were no direct borrowings drawn on these facilities (December 31, 2020 – $nil) and there were outstanding letters of credit aggregating to $565 million (December 31, 2020 – $441 million).

WRB Refining LP has uncommitted demand facilities of US$300 million (our proportionate share – US$150 million) available to cover short-term working capital requirements. As at December 31, 2021, US$125 million was drawn on these facilities, of which US$63 million ($79 million) was our proportionate share (December 31, 2020 – $121 million). Subsequent to December 31, 2021, WRB added an incremental US$150 million demand facility (our proportionate share - US$75 million).

Sunrise Oil Sands Partnership has an uncommitted demand credit facility of $10 million available for general purposes. Our proportionate share is $5 million. There were no amounts drawn on this demand credit facility on December 31, 2021 (December 31, 2020 – $nil).

Canadian Dollar Unsecured Notes and U.S. Dollar Denominated Unsecured Notes

At December 31, 2021, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$7.4 billion and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.8 billion.

Effective March 31, 2021, Cenovus Energy Inc., as a result of the Arrangement and subsequent amalgamation of Husky Energy Inc. into Cenovus Energy Inc., became the direct obligor under the existing US$500 million 3.95 percent notes due 2022, US$750 million 4.00 percent notes due 2024, $750 million 3.55 percent notes due 2025, $750 million 3.60 percent notes due 2027, $1.25 billion 3.50 percent notes due 2028, US$750 million 4.40 percent notes due 2029, US$387 million 6.80 percent notes due 2037 and other direct obligations of Husky Energy Inc.

The Company closed a public offering in the U.S. on September 13, 2021 for US$1.25 billion of senior unsecured notes, consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior unsecured notes due February 15, 2052.

As noted earlier, in September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured notes with a principal amount of US$2.2 billion. A net premium on redemption of $121 million was recorded in finance costs. The following principal amounts of Cenovus’s unsecured notes were repurchased:

• 3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).

• 3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).

• 3.80 percent unsecured notes due 2023 – US$335 million.

• 4.00 percent unsecured notes due 2024 – US$481 million.

• 5.38 percent unsecured notes due 2025 – US$334 million.

Subsequent to year-end, we announced our intent to repurchase the remaining principal of US$384 million of the outstanding notes due in 2023 and 2024 on February 9, 2022.

Base Shelf Prospectus

We have a base shelf prospectus that allows us to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere, where permitted by law. The base shelf prospectus will expire in November 2023. As at December 31, 2021, US$4.7 billion remained available under the base shelf prospectus for permitted offerings.

Financial Metrics

We monitor our capital structure and financing requirements using, among other things, specified financial measures consisting of the Net Debt to Adjusted EBITDA Ratio and Net Debt to Capitalization Ratio. We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. The components of the ratios include Capitalization and Adjusted EBITDA. We define Capitalization as Net Debt plus Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense (recovery), DD&A, exploration expense, goodwill impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated on a trailing 12-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial strength.

See the Advisory for specified financial measure details.

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	2021		2020		2019
Net Debt to Capitalization Ratio (percent)		29		30		25
Net Debt to Adjusted EBITDA Ratio (times)		1.2x		11.9x		1.6x

Our Net Debt to Adjusted EBITDA Ratio Target is between 1.0 to 1.5 times at the bottom of the cycle, which we see as approximately US$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares.

On December 31, 2020, before the Arrangement, our Net Debt to Capitalization Ratio was 30 percent. Our Net Debt to Capitalization Ratio increased as a result of the Arrangement. Ongoing reductions in Net Debt, described in the Cash From (Used In) Financing Activities above, lowered our Net Debt to Capitalization Ratio to 29 percent on December 31, 2021.

As at December 31, 2021, our Net Debt to Adjusted EBITDA Ratio was 1.2 times. Our Net Debt to Adjusted EBITDA Ratio decreased compared with December 31, 2020 as a result of higher Operating Margin in 2021, partially offset by an increase in our Net Debt acquired as part of the Arrangement. See the Operating and Financial Results section of this MD&A for more information on Net Debt.

We are in compliance with all of the terms of our debt agreements. Under the terms of our committed credit facility, we are required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. We are well below this limit. Additional information regarding our financial measures and capital structure can be found in the notes to the Consolidated Financial Statements.

Share Capital and Stock-Based Compensation Plans

Under the Arrangement, we acquired all the issued and outstanding Husky common shares in consideration for the issuance of 0.7845 Cenovus common shares plus 0.0651 Cenovus Warrants for each Husky common share. We issued 788.5 million Cenovus common shares with a fair value of $6.1 billion, based on the December 31, 2020, closing share price of $7.75, as reported on the TSX. In addition, 65.4 million Cenovus Warrants were issued. Each whole warrant entitles the holder to acquire one Cenovus common share for a period of five years at an exercise price of $6.54 per share. The fair value of the warrants was estimated to be $216 million. We also acquired all the issued and outstanding Husky preferred shares in exchange for 36.0 million Cenovus first preferred shares with substantially identical terms and a fair value of $519 million.

We have a number of stock-based compensation plans which include stock options with associated net settlement rights, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). In connection with the Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were replaced by Cenovus replacement stock options (“Cenovus Replacement Stock Options”). Each Cenovus Replacement Stock Option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845. The fair value of the replacement stock options was estimated to be $9 million.

As at December 31, 2021, there were approximately 2,001 million common shares outstanding (December 31, 2020 — 1,229 million common shares). Refer to Note 30 of the Consolidated Financial Statements for more details.

Refer to Note 32 of the Consolidated Financial Statements for more details on our stock option plans and our PSU, RSU and DSU Plans.

Our outstanding share data is as follows:

As at February 4, 2022	Units Outstanding   (thousands)		Units Exercisable   (thousands)
Common Shares (1)		1,995,284		N/A
Common Share Warrants		63,750		N/A
Series 1 Preferred Shares		10,740		N/A
Series 2 Preferred Shares		1,260		N/A
Series 3 Preferred Shares		10,000		N/A
Series 5 Preferred Shares		8,000		N/A
Series 7 Preferred Shares		6,000		N/A
Stock Options (1)		37,559		23,414
Other Stock-Based Compensation Plans		14,515		1,371

(1) Includes Cenovus Replacement Stock Options (defined above) issued pursuant to the Arrangement in replacement of all issued and outstanding Husky stock options.

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Common Share Dividends

In 2021, we paid dividends of $176 million or $0.0875 per common share (2020 – $77 million or $0.0625 per common share). The declaration of dividends is at the sole discretion of Cenovus’s Board and is considered quarterly. The Board declared a first quarter dividend of $0.035 per common share, payable on March 31, 2022 to common shareholders of record as of March 15, 2022.

Cumulative Redeemable Preferred Share Dividends

In 2021, dividends of $34 million, were paid on the series 1, 2, 3, 5 and 7 preferred shares. The declaration of preferred share dividends is at the sole discretion of Cenovus’s Board and is considered quarterly. The Board declared a first quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares, payable on March 31, 2022, in the amount of $9 million.

Capital Investment Decisions

Our 2022 capital program is forecast to be between $2.6 billion and $3.0 billion. Our Future Capital Investment is focused on maintaining safe and reliable operations, while positioning the Company to drive enhanced shareholder value to deliver upstream production of approximately 800.0 thousand BOE per day and downstream throughput of approximately 555.0 thousand barrels per day.

Adjusted Funds Flow and Free Funds Flow

Adjusted Funds Flow is a non-GAAP financial 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 and is the starting point for calculating Free Funds Flow. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs.

($ millions)	2021		2020		2019
Cash From (Used in) Operating Activities		5,919		273		3,285
Adjusted Funds Flow (1)		7,248		117		3,670
Total Capital Investment		2,563		841		1,176
Free Funds Flow (1)		4,685		(724)		2,494
Cash Dividends		210		77		260
		4,475		(801)		2,234

(1) Non-GAAP financial measure. See the Advisory. Comparative figures have been restated to conform with the definition in this MD&A.

Our approach on the financial framework remains consistent. We will continue to evaluate all opportunities based on a US$45 per barrel WTI price with the objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics. This approach positions us to be financially resilient in times of lower cash flows. Balance sheet strength continues to be a top priority and we plan to continue to allocate our Free Funds Flow towards debt reduction, and further increase returns to shareholders as Net Debt targets are reached.

Contractual Obligations and Commitments

We have obligations for goods and services entered into in the normal course of business. Commitments are primarily related to transportation agreements and obligations that have original maturities of less than one year are excluded. For further information, see the Consolidated Financial Statements.

The Arrangement resulted in the assumption of non-cancellable contracts and other commercial commitments. On January 1, 2021, we assumed total commitments of $17.6 billion, of which $7.4 billion were for various transportation commitments. Transportation commitments include $1.7 billion that are subject to regulatory approval or have been approved but are not yet in service.

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As at December 31, 2021 ($ millions)	2022	2023	2024	2025	2026	Thereafter	Total
Commitments
Transportation and Storage (1)	3,288	3,567	3,373	2,146	2,012	16,600	30,986
Real Estate (2)	44	43	52	54	57	658	908
Obligation to Fund Equity- Accounted Affiliate (3)	68	85	99	90	90	210	642
Other Long-Term Commitments	509	156	145	136	150	1,214	2,310
Total Commitments (4)	3,909	3,851	3,669	2,426	2,309	18,682	34,846
Other Obligations
Long-term Debt (Principal and Interest) (5)	561	713	895	2,128	475	14,892	19,664
Decommissioning Liabilities	231	329	569	678	426	4,629	6,862
Contingent Payment	238	—	—	—	—	—	238
Lease Liabilities (Principal and Interest) (6)	453	410	384	322	312	3,192	5,073
Total Commitments and Obligations	5,392	5,303	5,517	5,554	3,522	41,395	66,683

(1) Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement.

(2) Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3) Relates to funding obligations to HCML.

(4) Commitments are reflected at Cenovus’s proportionate share of the underlying contract.

(5) On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured notes on February 9, 2022. Long-term debt maturities above have not been adjusted for this redemption.

(6) Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.

Our total commitments were $34.8 billion as at December 31, 2021, of which $31.0 billion are for various transportation and storage commitments. Terms are up to 20 years subsequent to the date of commencement and should help align with the Company’s future transportation requirements.

Our commitments with HMLP at December 31, 2021, include $2.6 billion related to transportation, storage and other long-term contracts.

As at December 31, 2021, outstanding letters of credit issued as security for performance under certain contracts totaled $565 million (December 31, 2020 – $441 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.

Transactions with Related Parties

Transactions with HMLP are related party transactions as we have a 35 percent ownership interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs. We are also the contractor for HMLP and construct its assets on a cost recovery basis with certain restrictions. For the year ended December 31, 2021, we charged HMLP $243 million for construction and management services.

We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for transportation and storage services. For the year ended December 31, 2021, we incurred costs of $284 million for the use of HMLP’s pipeline systems, as well as transportation and storage services.

RISK MANAGEMENT AND RISK FACTORS

We are exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact the energy 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, our business, reputation, financial condition, results of operations and cash flows, which may reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions, respond to changes in our operating environment, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and may materially affect the market price of our securities.

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Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of our risks and is integrated with the Cenovus Operations Integrity Management System (“COIMS”). In addition, we continuously monitor our risk profile as well as industry best practices.

Risk Governance

The ERM Policy, approved by our Board, outlines our risk management principles and expectations, as well as the roles and responsibilities of all staff. Building on the ERM Policy, we have established risk management standards, a risk management framework and risk assessment tools, including the Cenovus risk matrix. Our risk management framework contains the key attributes recommended by the International Organization for Standardization (“ISO”) in its ISO 31000 – Risk Management Guidelines. The results of our ERM program are documented in semi-annual risk reports presented to our Board as well as through regular updates.

Risk Factors

The following discussion describes the financial, operational, regulatory, environmental, reputational and other risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks, have a material impact on our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund dividend payments and/or business plans and the market price of our securities. These factors should be considered when investing in securities of Cenovus.

Pandemic Risk

The COVID-19 pandemic (including the emergence of variant strains of COVID-19), and measures taken in response by governments and health authorities around the world has created ongoing uncertainty that has resulted in, and may continue to result in restrictions on movement and businesses being maintained, re-imposed or imposed on a stricter basis, which could negatively impact our business, results of operations and financial condition. It is impossible at this point to predict precisely the duration or extent of the impacts of the COVID-19 pandemic on our employees, customers, partners and business or when economic activity will normalize.

The COVID-19 pandemic may increase our exposure to, and the magnitude of, each of the risks identified in this Risk Management and Risk Factors section of this MD&A and identified in other documents we file with securities regulators from time to time. Our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund dividend payments and/or business plans may, in particular, be adversely impacted as a result of the pandemic and/or a decline in commodity prices as a result of:

• The shut-down of facilities or the delay or suspension of work on major capital projects due to circumstances including, but not limited to: workforce disruptions or labour shortages caused by workers becoming infected with COVID-19; challenges to COVID-19 safety protocols implemented by Cenovus; government or health authority mandated restrictions on travel by workers, which may impact cross-border business travel and travel to remote worksites; closure of our facilities, workforce camps or worksites, or those on which we rely; increased worker attrition and health-related leaves and absences from work impacting operations.

• Disruptions to global supply chains, such as suppliers and third-party vendors experiencing similar workforce disruptions or being ordered to cease operations.

• Reduced cash flows resulting in less funds from operations being available to fund our capital expenditure program;

• Reduced demand for commodities and reduced commodity prices resulting in reductions in the volumes and value of our reserves (see “Commodity Prices” below).

• Commodity storage and transportation constraints resulting in the curtailment or shutting-in of production.

• A decrease in refined product volumes, the demand for refined products or refinery utilization rates.

• Counterparties being unable to fulfill their contractual obligations to us on a timely basis or at all.

• The inability to deliver products to customers or to otherwise get crude oil, refined products or natural gas to market caused by border restrictions, road or port closures or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being unable to continue to operate.

• The capabilities of our information technology systems and the potential heightened threat of a cyber-security or privacy breach arising from the number of employees, customers and partners working and accessing our systems remotely.

• Our ability to obtain additional capital, including, but not limited to, debt and equity financing, being adversely impacted as a result of unpredictable financial markets or commodity prices and/or a change in market fundamentals.

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The extent to which the COVID-19 pandemic impacts our business, results of operations and financial condition will depend on future developments, which are highly uncertain and are difficult to predict with any degree of precision, including, but not limited to: the severity, duration, spread or resurgence of COVID-19 and its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 and its variants, including the availability, distribution rate, effectiveness and public uptake of any vaccines or boosters; and the speed at which, and extent to which, normal economic and operating conditions resume. The potential impacts of the COVID-19 pandemic to our business, results of operations and financial condition could be more significant in the current year as compared with 2020 and 2021. The COVID-19 pandemic has resulted in, and may continue to result in, significant market uncertainty, including substantial fluctuations in commodity prices, currency exchange rates, inflation, interest rates, counterparty credit and performance risk, and general levels of investing and consumption. Even after the COVID-19 pandemic has subsided, we may continue to experience materially adverse impacts to our business as a result of the pandemic’s global economic impact.

There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and, as a result, the ultimate impact of the COVID-19 pandemic is highly uncertain and subject to change. Management does not yet know the full extent of the impact on our business, operations and financial condition or on the global economy as a whole.

We have taken proactive steps to protect the health and safety of our staff and the continuity of our business in response to the COVID-19 pandemic. We continue to follow guidance received from federal, provincial, territorial, state, regional and municipal governments and public health officials and have implemented COVID-19 testing protocols for staff accessing our high occupancy worksites and workforce camps. We also have a comprehensive Business Continuity Plan to ensure continued safe and reliable operations in the event of a COVID-19 outbreak at any of our workplaces. Despite our best efforts, the COVID-19 pandemic and the corresponding measures we take, may result in new legal challenges and disputes, including, but not limited to, class action claims.

Financial Risk

Commodity Prices

Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and NGLs. Crude oil prices are impacted by a number of factors, including, but not limited to: global and regional supply of and demand for crude oil; global economic conditions including factors impacting global trade; the actions of OPEC and other oil exporting nations, including, but not limited to, compliance or non-compliance with quotas agreed upon by OPEC members and decisions by OPEC not to impose production quotas on its members; prices and availability of alternate sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources, including crude oil; political stability and social conditions in oil-producing countries; market access constraints and transportation interruptions (pipeline, marine or rail); economic conditions; outbreak of war; outbreak or continuation of a pandemic; terrorist threats; technological developments; the occurrence of natural disasters; and weather conditions.

The financial performance of our oil sands operations is also impacted by discounted or reduced commodity prices for our oil sands production relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell products to domestic and international markets and the quality of oil produced. Of particular importance to us are diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the market price for light to medium crude oil and heavy crude oil which, along with higher diluent costs, can adversely affect our financial condition.

Our natural gas and NGL production is currently located in Western Canada and Asia Pacific. Natural gas and NGL prices are impacted by a number of factors, including, but not limited to: global and regional supply and demand for natural gas and NGLs; market competitiveness; developments related to the market for liquefied natural gas; prices and availability of alternate sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources, including natural gas and NGLs; political stability and social conditions in natural gas and NGL-producing countries; market access constraints and transportation interruptions (pipeline, marine or rail); economic conditions; technological developments; outbreak or continuation of a pandemic; terrorist threats; the occurrence of natural disasters; and weather conditions.

Refined product prices are impacted by a number of factors, including, but not limited to: global and regional supply and demand for refined products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned refinery maintenance; current and potential future environmental regulations, including the United States Renewable Fuel Standard (“RFS”) and other regulations pertaining to the production and use of refined products and non-renewable resources; emissions, including carbon, market pricing and the accessibility and liquidity of such markets; prices and availability of alternate sources of energy; public sentiment towards the use of refined products; prices and the availability of alternate fuel sources; technological developments; outbreak or continuation of a pandemic; the occurrence of natural disasters; and weather conditions.

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The financial performance of our refining operations is also impacted by the relationship, or margin, between refined product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production levels change to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact on our business, results of operations, cash flows and financial condition.

In addition, and relating to the level of future demand (and corresponding price levels) for each of crude oil, refined products, natural gas and NGLs, there has been a significant increase in focus recently on the timing for and pace of the transition to a lower-carbon economy. See “Climate Change Transition – Demand and Commodity Prices” below. All of these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. See “Foreign Exchange Rates” below.

Fluctuations in the commodity prices, associated price differentials and refining margins may impact our ability to meet guidance targets, the value of our assets, our cash flows and our ability to maintain our business and fund projects. A substantial decline in these commodity prices or extended period of low commodity prices may result in an inability to meet all of our financial obligations as they come due, a delay or cancellation of existing or future drilling, development or construction programs, curtailment in production, unutilized long-term transportation commitments and/or low utilization levels at our refineries. Fluctuations in commodity prices, associated price differentials and refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost of borrowing.

The commodity price risks noted above, as well as other risks such as market access constraints and transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully described herein, may have a material impact on our business, financial condition, results of operations, cash flows or reputation and may be considered to be indicators of impairment. Another indication of impairment is the comparison of the carrying value of our assets to our market capitalization.

As discussed in this MD&A, we conduct an assessment, at each reporting date, of the carrying value of our assets in accordance with IFRS. If crude oil, refined product and natural gas prices decline significantly and remain at low levels for an extended period of time, or if the costs of our development of such resources significantly increases, the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.

We partially mitigate our exposure to commodity price risk through the integration of our business, financial instruments, physical contracts, market access commitments and generally through our access to our committed credit facility. In certain instances, we will use derivative instruments to manage exposure to price volatility on a portion of our refined product, oil and gas production, inventory or volumes in long-distance transit. 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 35 and 36 of the Consolidated Financial Statements and “Hedging Activities” below.

Hedging Activities

Our Market Risk Management Policy, which has been approved by our Board, allows Management to use derivative instruments including exchange-traded futures contracts, commodity put and call options and other approved instruments, including non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil, condensate prices and differentials, natural gas spreads, basis and prices, NGLs, refined product and crack spread margins, as well as fluctuations in foreign exchange rates and interest rates. We may also use fixed-price commitments for the purchase or sale of crude oil, natural gas, NGLs and refined products. We also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production.

These hedging activities may expose us to risks which may cause significant loss. These risks include, but are not limited to: changes in the valuation of the hedge instrument being poorly correlated to the change in the valuation of the underlying exposures being hedged; change in price of the underlying commodity or market value of the instrument; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the unenforceability of contracts.

There is risk that the consequences of hedging to protect against the possibility of unfavourable market conditions may limit the benefit to us of changes in commodity prices, interest rates and foreign exchange rates. We may also suffer financial loss due to hedging arrangements if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These risks are managed through hedging limits authorized under our Market Risk Management Policy.

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 3, 35 and 36 of the Consolidated Financial Statements.

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Impact of Financial Risk Management Activities

In 2021, for cash flow derivatives, we incurred a realized loss due to the settlement of benchmark prices relative to our risk management contract prices. For optimization derivatives, the realized loss was from our decisions to transport and store rather than sell our physical crude oil and condensate volumes as well as hedging activity related to the transportation of crude and condensate. We use our marketing and transportation initiatives, including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification, and to inventory physical positions. At the time we make the decision to store crude oil and condensate volumes, the prices available for future periods we plan to sell in can be locked in and the improved margin realized in the future periods, which are superior to short-term prices. The risk management gains and losses offset corresponding fluctuations in revenues generated from the underlying physical sales.

Unrealized losses were recorded on our crude oil financial instruments for the year ended December 31, 2021 primarily due to changes in commodity prices compared with prices at the end of the year and the realization of settled positions.

Transactions typically span across periods in order to execute the optimization strategy, and these transactions reside across both realized and unrealized risk management.

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

As at December 31, 2021	Sensitivity Range	Increase	Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges	(225)	225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production	4	(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges	(2)	2
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate	11	(12)

For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.

Exposure to Counterparties

In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders and other counterparties for the provision and sale of goods and services and also in connection with our hedging activities, acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses, delays of our development plans or we may have to forego other opportunities which could materially impact our business, results of operations or financial condition.

Credit, Liquidity and Availability of Future Financing

The future development of our business may be dependent on our ability to obtain additional capital including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn, significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations, or investor or lender sentiment or policy may impede our ability to secure and maintain cost-effective financing. An inability to access capital, on terms acceptable to us or at all, could affect our ability to make future capital expenditures, to maintain desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization and to meet all of our financial obligations as they come due, potentially resulting in a material adverse effect on our business, financial condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and reputation.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic, business, regulatory, market and other conditions, some of which are beyond our control. If our operating and financial results are not sufficient to service current or future indebtedness, we may take actions such as reducing or suspending dividends, reducing or delaying business activities, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional capital that could have less favourable terms.

Our liquidity risk is mitigated through actively managing cash and cash equivalents, cash flow provided by operating activities, available credit facility capacity, and accessing the capital markets.

We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. We routinely review our covenants to ensure compliance. In the event that we do not comply with such covenants, our access to capital could be restricted or repayment could be accelerated.

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Credit Ratings

Our company and our capital structure are regularly evaluated by credit rating agencies. Credit ratings are based on our financial and operational strength and a number of factors not entirely within our control, including but not limited to, conditions affecting the oil and gas industry generally, industry risks associated with climate change and an energy transition and the state of the economy. There can be no assurance that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.

A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to sources of liquidity and capital. A failure to maintain our current credit ratings could affect our business relationships with counterparties, operating partners and suppliers.

If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post collateral in the form of cash, letters of credit or other financial instruments in order to establish or maintain business arrangements. Additional collateral may be required due to further downgrades below certain ratings thresholds. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated.

Foreign Exchange Rates

Fluctuations in foreign exchange rates between various currencies may affect our results. Global prices for crude oil, refined products, and natural gas are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas sales. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. However, the fluctuations in exchange rates are beyond our control and could have a material adverse effect on our cash flows, results of operations and financial condition. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region.

Interest Rates

Fluctuations in interest rates as a result of the use of floating rate securities or borrowings may affect our cash flow and financial results. An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded, both of which could negatively impact our cash flow and financial results. Additionally, we are exposed to interest rate fluctuations upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates.

We may periodically enter into transactions to manage our exposure to interest rate fluctuations.

Dividend Payment and Purchase of Securities

The payment of dividends, continuation of our dividend reinvestment plan and any potential purchase by Cenovus of our securities is at the discretion of our Board, and is dependent upon, among other things, financial performance, debt covenants, satisfying solvency tests, our ability to meet financial obligations as they come due, working capital requirements, future tax obligations, future capital requirements, commodity prices and other business and risk factors set forth in this MD&A.

Disclosure Controls and Procedures and Internal Control Over Financial Reporting (“ICFR”)

Based on their inherent limitations, disclosure controls and procedures and ICFR may not prevent or detect misstatements, and even those controls determined to be effective can only provide reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on our business, financial condition, results of operations, cash flows, and our reputation.

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Operational Risk

Operational Considerations (Safety, Environment and Reliability)

Our operations are subject to risks generally affecting the energy industry and normally incidental to: (i) the storing, transporting, processing, and marketing of crude oil, refined products, natural gas and other related products; (ii) drilling and completion of on and offshore crude oil and natural gas wells; (iii) the operation and development of crude oil and natural gas properties ; and (iv) the operation of refineries, terminals, pipelines and other transportation and distribution facilities in the jurisdictions in which we conduct our business. These risks include but are not limited to: the effects of government actions or regulations, policies and initiatives; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; fires; explosions; blowouts; loss of containment; gaseous leaks; power outages; migration of harmful substances into water systems; releases or spills, including releases or spills from offshore operations, shipping vessels or other marine transport incidents; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or operate within established operating parameters; adverse weather conditions; corrosion; pollution; freeze-ups and other similar events; the breakdown or failure of equipment, pipelines and facilities, information technology and systems and processes; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; railcar incidents or derailments; failure to maintain adequate supplies of spare parts; the compromise of information technology and control systems and related data; operator error; labour disputes; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of such party’s facilities and pipelines; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances onto trucks; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, iceberg incidents, acts of vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites.

If any such risks materialize, they may interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology and control systems, related data, cause environmental damage that may include polluting water, land or air, and may result in regulatory action, fines, penalties, civil suits, or criminal or regulatory charges against us, any of which may have a material adverse effect on our business, financial condition, results of operations, cash flows, and reputation.

In addition, our oil sands operations are susceptible to reduced production, slowdowns, shutdowns, or restrictions on our ability to produce higher value products due to the interdependence of our component systems. Delineation of the resources, the costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production.

To partially mitigate our risks, we have a system of standards, practices and procedures to identify, assess and mitigate safety, operational and environmental risk across our operations. In addition, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and operations. However, we do not insure against all potential occurrences and disruptions in respect of our assets or operations, and it cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may arise from such occurrences or disruptions. The occurrence of an event that is not fully covered by our insurance program could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Aviation Incidents

Our Offshore operations rely on regular travel by helicopter. A helicopter incident resulting in injury, loss of life, facility shutdown or regulatory action could have a material adverse effect on our operations and reputation. This risk is managed through an aviation management process. Aviation Safety Reviews are conducted by third-party specialist contractors to verify that helicopter service providers meet our internal and industry standards with respect to aviation safety. Additional measures specific to our challenging operating environments are specified in our design requirements and pilot training is aligned with industry best practices.

Ice Management

Although extensive measures are in place to prevent incidents related to sea ice and icebergs, our Atlantic operations offshore Newfoundland and Labrador are at risk of incidents caused by icebergs which may interrupt operations, impact our reputation, cause loss of life, personal injury, or damage to equipment or the environment, and may result in regulatory action or litigation against us. Our Atlantic operations have a robust ice management program. We have policies in place to protect people, equipment and the environment in the event of extreme weather conditions and adverse ice conditions, including Adverse Weather Guidelines for the SeaRose FPSO. We continue to manage physical risk through engineering for extreme weather events.

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Market Access Constraints and Transportation Restrictions

Our production is transported through various pipelines, terminals, marine and rail networks and our refineries are reliant on various pipelines and rail networks to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil, refined products, natural gas and NGLs sales, projected production growth, upstream or refining operations and cash flows.

Interruptions or restrictions in the availability of these pipeline, terminals, marine and rail systems may also limit the ability to deliver production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our products. These interruptions and restrictions may be caused by, among other things, the inability of the pipeline, marine or rail networks to operate, or may be related to capacity constraints if supply into the system exceeds the infrastructure capacity. There can be no certainty that investments in new pipeline projects will be made by applicable third-party pipeline providers, that any applications to expand capacity will receive the required regulatory approvals, or that any such approvals will result in the construction of the pipeline project, or that such projects would provide sufficient transportation capacity.

There is no certainty that rail, marine transport and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In addition, our rail and marine shipments may be impacted by service delays, inclement weather, railcar availability, railcar derailment or other rail or marine transport incidents and could adversely impact sales volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal injury, loss of equipment or property, or environmental damage. In addition, rail and marine regulations are constantly being reviewed to ensure the safe operation of the supply chain. Should regulations change, the costs of complying with those regulations will likely be passed on to rail and/or marine shippers and may adversely affect our ability to transport by-rail and/or marine transport or the economics associated with rail or marine transportation. Finally, planned or unplanned shutdowns or closures of our refineries or of our refinery customers may limit our ability to deliver product with negative implications on sales and cash from operating activities.

Reserves Replacement and Reserve Estimates

If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon successfully producing from current reserves and acquiring, discovering or developing additional reserves. Exploring for, developing or acquiring reserves is capital intensive. To the extent our cash flow is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our crude oil and natural gas reserves will be impaired. In addition, we may be unable to find and develop or acquire additional reserves to replace our crude oil and natural gas production at acceptable costs.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including, but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including royalty payments and taxes, and environmental and emissions related regulations and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary materially from estimated results.

All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material.

Estimates with respect to reserves that may be developed and produced in the future are often based on volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Subsequent evaluation of the same reserves based on production history will result in variations, which may be material, in the estimated reserves.

The production rate of oil and gas properties tends to decline as reserves are depleted while the associated operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on schedule; and the application of successful exploitation techniques on mature properties. Our business, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves.

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Cost Management

Development, operating and construction costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies; inflationary price pressure; changes in regulatory compliance costs; scheduling delays; interruptions to existing market access infrastructure; failure to maintain quality construction and manufacturing standards; equipment limitations, including the cost or availability of oil and gas field equipment, commodity prices, higher SORs in our Oil Sands operations, additional government or environmental regulations and supply chain disruptions, including access to skilled labour. While we do not believe that inflation has had a material effect on our business, financial condition or results of operations to date; if our development, operation or labour costs were to become subject to significant inflationary pressures, we may not be able to fully offset such higher costs through corresponding increases in commodity prices. Our inability to manage costs or to secure equipment, materials or skilled labour necessary to our exploration, development, construction and operations for the expected price, on the expected timeline, or at all, could have a material adverse effect on our financial condition, results of operations and cash flows.

Competition

The Canadian and international energy industry is highly competitive in all aspects, including accessing capital, the exploration for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of oil and gas products. We compete with other producers and refiners, some of which may have lower operating costs or greater resources than our company does. Competing producers and refiners may develop and implement technologies which are superior to those we employ. The oil and gas industry also competes with other industries in supplying energy, fuel and related products to consumers, including renewable energy sources which may become more prevalent in the future.

Project Execution

We manage a variety of oil, natural gas and refining projects across our global portfolio of assets, including the current rebuild of our Superior Refinery. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of our projects. These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory approvals; our ability to obtain favourable terms or to be granted access within land-use agreements; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of supply chain disruptions; the impact of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy of project cost estimates; our ability to finance capital expenditures and expenses; our ability to source or complete strategic transactions; the effect of the COVID-19 pandemic on project execution and timelines; and the effect of changing government regulation and public expectations in relation to the impacts of oil and gas operations on the environment. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving performance targets and objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of operations and cash flows and may affect our safety and environmental record thereby negatively affecting our reputation and social licence to operate.

Partner Risks

Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures. Therefore, our results of operations and cash flows may be affected by the actions of third-party operators or partners and our ability to control and manage risks may be reduced. We rely on the judgment and operating expertise of our partners in respect of the operation of such assets and to provide information on the status of such assets and related results of operations; however, we are, at times, dependent upon our partners for the successful execution of various projects.

Our partners may have objectives and interests that do not align with or may conflict with our interests. No assurance can be provided that our future demands or expectations relating to such assets will be satisfactorily met in a timely manner or at all. If a dispute with a partner or partners were to occur over the development and operation of a project or if a partner or partners were unable to fund their contractual share of the capital expenditures, a project could be delayed and we could be partially or totally liable for our partner’s share of the project. Should one of our partners become insolvent, we may similarly be directed by applicable regulators to carry out obligations on behalf of our partner and may not be able to obtain reimbursement for these costs, which could have a material adverse effect on our financial condition, results of operations, reputation and cash flows.

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SAGD Technology

Current technologies used for the recovery of bitumen is energy intensive, including SAGD which requires significant consumption of natural gas in the production of steam used in the recovery process. The amount of steam required in the recovery process varies and therefore impacts costs. The performance of the reservoir affects the timing and levels of production using SAGD technology. A large increase in recovery costs could cause certain projects that rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial condition, results of operations and cash flows. There are risks associated with growth and other capital projects that rely largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. The success of projects incorporating new technologies cannot be assured.

Technology, Information Systems and Privacy

We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This may include on premise systems, (such as networks, computer hardware and software), networks and telecommunications systems, mobile applications, and cloud services. Such systems and services may be provided by third parties. In the event we are unable to regularly and effectively access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the efficiency and efficacy of such systems and services, the operation of such systems and services could be interrupted, resulting in operational interruptions or the loss, corruption, or release of data.

In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary and business information and personal information, including the information of third parties. Despite our security measures, our technology systems and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties) or to disruption due to staff or third-party error or malfeasance or to other disruptions, including as a result of natural disasters and acts of state or industrial espionage, activism, terrorism or war. Any such incident could compromise information used or stored on our systems or services and result in the loss, theft, inability to access, use or rely upon, the unauthorized access, disclosure, copying, use, modification, disposal or destruction of, or the exposure of, internal, confidential, personal or other sensitive information including information related to our assets and operations, technology, intellectual property, corporate or retail credit card information, customer personal information, employee personal information, exploration activities, corporate actions, executive officer communications and financial results. These could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative consequences, including damage to our reputation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Without limiting the foregoing, these risks include the risk of cyber-related fraud or attacks whereby threat actors attempt to circumvent electronic communications controls or attempt to impersonate internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators or to introduce ransomware into one or more systems or services in an effort to extract a payment. If a threat actor is successful in bypassing our cyber-security measures and business process controls, such cyber-related risks could result in financial losses, remediation and recovery costs, and an adverse reputational impact.

Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in which we operate. Such legislation applies to a wide range of data processing activities including, but not limited to, processing personal information. For example, effective November 1, 2021, the Personal Information Protection Law (“PIPL”) became effective in the People’s Republic of China. PIPL is China’s first comprehensive law designed to regulate online data and protect personal information. In addition, on September 1, 2021, the Data Security Law went into effect in the People’s Republic of China. Such legislation applies to a wide range of data processing activities including, but not limited to, processing personal information. With extraterritorial scope and severe fines and penalties, these evolving laws impose an increasingly complex and comprehensive legal framework for the collection, use and processing of personal information. Compliance with such legislation may result in increased operating costs and failure to comply with such legislation may result in severe fines and penalties, each of which may adversely impact our financial condition, results of operations and cash flows.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact our personnel, or those of partners, customers, and suppliers, and could result in situations of injury, loss of life, extortion, hostage situations and/or kidnapping or unlawful confinement, destruction or damage to property of Cenovus or others, impact to the environment, and business interruption. A security threat, terrorist attack or activist incident targeted at a facility, terminal, pipeline, rail network, office or offshore vessel/ installation owned or operated by Cenovus or any of our systems, services, infrastructure, market access routes, or partnerships could result in the interruption or cessation of key elements of our operations. Outcomes of such incidents could have a material adverse effect on our results of operations, financial condition and business strategy. The potential for detention and/ or incarceration of our employees/contractors entering or working in China remains, and as a result, review and reconsideration for travel into China has become a business/corporate process.

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Activism and Disruptions to Operations

Increasing public engagement and activism generally, and in connection with the energy industry and the continued development of fossil fuel-based energy, has, from time to time, resulted in temporary disruptions to oil and gas development, operations and transportation. Such opposition has not yet materially impacted our facilities directly; however, activist groups and individuals may engage in protests, demonstrations or blockades that may disrupt our facilities or operations, or to facilities or operations on which we rely. Any such disruptions may have an adverse impact on our business, operations, financial condition or reputation.

While we have systems, policies and procedures designed to prevent or limit the effects of such disruptive events, there can be no assurance that these measures will be sufficient and that such disruptions will not occur or, if they do occur, that they will be adequately addressed in a timely manner.

Leadership and Talent

Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our talent. If we are unable to retain key personnel and critical talent or attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition and results of operations.

Litigation

From time to time, we may be involved in demands, disputes and litigation arising out of or related to our operations. Claims and related litigation may be material. Due to the nature of our operations we may experience various types of claims including, but not limited to, failure to comply with applicable laws and regulations, environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy and employment-related matters. We may be required to incur significant expenses or devote significant resources in defending against any such litigation, which could result in an unfavourable decision, including fines, sanctions, monetary damages, temporary or permanent suspensions of operations, or the inability to engage in certain transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on our reputation, financial condition and results of operations. In addition, we may be subject to or impacted by climate change related litigation. See “Climate Change Related Litigation” below.

Indigenous Land and Rights Claims

Opposition by Indigenous people to our company, our operations, development or exploration in the jurisdictions in which we conduct business may adversely impact us. Such impacts include impacts to our reputation, relationship with host governments, local communities and other Indigenous communities, diversion of Management’s time and resources, increased legal, regulatory and other advisory expenses, and could adversely impact our progress and ability to explore, develop and continue to operate properties.

Some Indigenous groups have established or asserted Indigenous and treaty rights to portions of Canada. There are outstanding Indigenous and treaty rights claims, which may include Indigenous title claims, on lands where we operate, and such claims, if successful, could have a material adverse impact on our operations or pace of growth. No certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Some Indigenous groups have also brought private nuisance claims against project operators for infringement of Indigenous rights. Such claims, if successful, could adversely affect our business, results of operations, financial condition or reputation.

The Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect the asserted or proven Indigenous or treaty rights and, in certain circumstances, accommodate their interests. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult Indigenous people and any associated accommodations may adversely affect our ability to, or increase the timeline to, obtain or renew, permits, leases, licences and other approvals, or to meet the terms and conditions of those approvals.

In addition, the Canadian federal government passed legislation which requires it to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). Other Canadian jurisdictions have also introduced or passed similar legislation, or begun considering the principles and objectives of UNDRIP, or may do so in the future. The means and timelines associated with UNDRIP’s implementation by government is uncertain; additional processes have been and are expected to continue to be created or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements.

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Governmental Risk

Shifts in government policy by existing administrations or following changes in government in jurisdictions in which we operate or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-border economic activity, and development of new infrastructure can impact our opportunities for continued growth. We are committed to working with all levels of government in the jurisdictions in which we operate to ensure our business benefits and risks are understood, and mitigation strategies are implemented; however, changes in government policy are largely out of our control and may adversely affect our business, results of operations, financial condition or reputation.

Regulatory Risk

The oil and gas industry and refining industry in general and our operations in particular are subject to regulation and intervention under international, federal, provincial, territorial, state, regional and municipal legislation in the countries in which we conduct operations, development or exploration in matters such as, but not limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government fees; production rates; environmental protection; protection of certain species or lands; provincial and federal land use designations; the reduction of GHG and other emissions; the export of crude oil, natural gas and other products; the transportation of crude-by-rail, pipeline or marine transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding or acquisition of exploration and production rights, oil sands or other interests; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possibly expropriation or cancellation of contract rights. The petroleum refining sector in the U.S. has been and continues to be subject to intensive environmental regulations, oversight, and enforcement from both federal and state governments. Third-party NGOs and citizen groups can also directly enforce environmental regulations in the U.S. and have been active against the U.S. refinery sector for many years. Any changes to the regulatory regime, including the implementation of new regulations or the modification or changed interpretation of existing regulations could impact our existing and planned projects or increase capital investment, operating expenses or compliance costs, which could adversely impact our financial condition, results of operations, cash flows and reputation. To mitigate these risks, we have regulatory programs that cover stakeholder engagement, air emissions, water discharges, deep well operations, solid and hazardous waste management, spills, and legacy contamination issues.

Regulatory Approvals

Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that we will be able to obtain or obtain on acceptable conditions all necessary licences, permits and other approvals that may be required to carry out certain exploration, development and operating activities on our properties. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation, consensus seeking and collaboration, environmental impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments or obligations. Failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.

Abandonment and Reclamation Cost Risk

We are subject to oil and gas asset abandonment, remediation and reclamation (“A&R”) liabilities for our operations, development and exploration, including those imposed by regulation under federal, provincial, territorial, state, regional and municipal legislation in the jurisdictions in which we conduct operations, development or exploration.

We maintain estimates of our A&R liabilities; however, it is possible that these costs may change materially before decommissioning due to regulatory changes, technological changes, acceleration of decommissioning timelines, and inflation, among other variables. For our Atlantic offshore operations, the present value cost for decommissioning and abandonment of the offshore wells and facilities is estimated based on known regulations, procedures and costs today for undertaking the decommissioning, the majority of which is projected to be incurred in the 2030s.

In Alberta, the A&R liability regime includes the Orphan Well Fund, which is administered by the Orphan Well Association (“OWA”) . The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based on the licensees’ proportionate share of deemed A&R liabilities for oil and gas facilities, wells and unreclaimed sites in Alberta. The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years and will remain at elevated levels until a significant number of orphaned wells are decommissioned by the OWA. The OWA may seek additional funding for such liabilities from industry participants, including Cenovus.

In 2021, the AER introduced a new holistic licensee capability assessment which provides the AER additional discretion and criteria for the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R work. In January 2022, the AER introduced requirements for licensees to spend minimum amounts annually on A&R work based on each licensee’s portion of inactive well liability. A similar program is anticipated to be implemented in Saskatchewan in 2023.

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Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset bases may be negatively affected by these new requirements, including our potential counterparties. This may result in future insolvencies and additional orphaned assets. In addition, this may impact our ability to transfer our licences, approvals or permits, and may result in increased costs and delays or require changes to or abandonment of projects and transactions.

We have an ongoing environmental monitoring program of owned and leased retail locations and perform remediation where required to comply with contractual and legal obligations. The costs of such remediation depend on a number of uncertain factors such as the extent and type of remediation required. Due to uncertainties inherent in the estimation process, it is possible that existing estimates may need to be revised and that conditions may exist at various retail locations that require future expenditures. Such future costs may not be determinable due to the unknown timing and extent of corrective actions that may be required.

The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows.

Royalty Regimes

Our cash flows may be directly affected by changes to royalty regimes. The governments of the jurisdictions where we have producing assets receive royalties on the production of hydrocarbons from lands in which they respectively own the mineral rights and which we produce under agreement with each respective government. Government regulation of royalties is subject to change for a number of reasons, including, among other things, political factors. In Canada, there are certain provincial mineral taxes payable on hydrocarbon production from lands other than Crown lands. The potential for changes in the royalty and mineral tax regimes applicable in the jurisdictions in which we operate, or changes to how existing royalty regimes are interpreted and applied by the applicable governments, creates uncertainty relating to the ability to accurately estimate future royalty rates or mineral taxes and could have a significant impact on our business, financial condition, results of operations and cash flows. An increase in the royalty rates or mineral taxes in jurisdictions where we have producing assets would reduce our earnings and could make, in the respective jurisdiction, future capital expenditures or existing operations uneconomic and may reduce the value of our associated assets.

Canada-United States-Mexico Agreement (“CUSMA”)

On July 1, 2020, the new CUSMA entered into force, which is known in the United States as the United States-Mexico-Canada Agreement (or “USMCA”), replacing the North American Free Trade Agreement (“NAFTA”). Under CUSMA, the rule of origin applicable to heavy oil containing diluent has been relaxed to allow up to 40 percent of non-originating diluent that is added for the purpose of transportation in pipelines without affecting the originating status of the product, which allows Canadian products to more easily qualify for duty-free treatment under the CUSMA when imported into the U.S. The related CUSMA side letter on energy between Canada and the U.S. also promotes regulatory transparency and non-discrimination in access to or use of energy infrastructure, which may potentially benefit the Canadian heavy oil industry. While some uncertainty relating to the origin certification process remains as the required documentation is determined on a case-by-case basis, this is a promising improvement to the NAFTA origin rule.

The investor-state dispute settlement provisions will no longer be available to protect future investments of Canadians in the U.S. or U.S. investments in Canada. For three years after the termination of NAFTA, existing legacy investments will maintain their access to the investor-state dispute settlement under NAFTA Chapter 11.

Labour Risk

We depend on unionized labour for the operation of certain facilities and may be subject to adverse employee relations and labour disputes, which may disrupt operations at such facilities. As of January 1, 2022, approximately 7.2 percent of our employees are represented by unions under collective bargaining agreements, which includes just over 50 percent of our U.S. workforce. At unionized worksites, there is risk that strikes or work stoppages can occur. Any strike or work stoppage may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.

During periods of contract negotiation, work stoppage mitigation and emergency operation plans come with significant additional expenditure to ensure continuity of operations in the event of a strike or work stoppage. In addition, we may not be able to renew or renegotiate collective bargaining agreements on satisfactory terms or at all and a failure to do so may increase our costs. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to us, which may materially and adversely affect our financial condition, results of operations and cash flows.

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Moreover, employees who are not currently represented by unions may seek union representation in the future and efforts may be made from time to time to unionize other portions of our workforce. Future unionization efforts or changes in legislation and regulations may result in labour shortages, higher labour costs, as well as wage, benefit, and other employment consequences, especially during critical maintenance and construction periods, all of which may increase our costs, reduce our revenues or limit our operational flexibility.

International Developments and Geopolitical Risk

We are exposed to the financial and operational risks associated with uncertain international relations. Our business includes Asia Pacific assets in the South China Sea and the Madura Strait offshore Indonesia, and includes cooperation agreements with China National Offshore Oil Corporation or its subsidiaries (collectively, “CNOOC”), which also operates certain of these assets.

Political developments impacting international trade, including trade disputes and increased tariffs, particularly between the U.S. and China and Canada and China, may negatively impact markets and cause weaker macroeconomic conditions or drive political or national sentiment, weakening demand for crude oil, natural gas and refined products. For example, U.S. government trade policy has resulted in, and could result in more, U.S. trading partners adopting responsive trade policy and may make it more difficult or costly for us to operate in and export our products to those countries.

Moreover, our operations may be materially adversely affected by political, economic or social instability or events, including the renegotiation or nullification of agreements and treaties, the imposition of onerous regulations, embargoes, sanctions, and fiscal policy, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and the behaviour of international public officials, joint venture partners or third-party representatives. Specifically, our Asia Pacific assets expose us to the effects of the changing U.S.-China and Canada-China relations, including escalating tensions and possible retaliations.

In response to foreign sanctions, China has enacted multiple blocking laws intended to diminish the effectiveness and impact of foreign trade sanctions. Specifically, China has enacted regulations granting itself the ability to unilaterally nullify the effects of certain foreign restrictions that are deemed to be unjustified to Chinese nationals and entities, which came into force on January 9, 2021. Additionally, on June 10, 2021, China enacted the Anti-Foreign Sanctions Law. The Anti-Foreign Sanctions Law grants the right to take corresponding countermeasures if a foreign country violates international law and basic norms of international relations or adopts discriminatory restrictive measures against Chinese nationals and entities, and interferes in China’s internal affairs. The language of the Anti-Foreign Sanctions Law is very broad, and beyond the laws themselves, little guidance has been provided regarding how the blocking laws will be enforced by the Chinese government and effectuated through the private rights of action created by these laws. The breadth and lack of specificity of such laws create additional risk and uncertainty for foreign companies operating in China, as they may result in conflicting rules and regulations in home and host countries.

Although formal export restrictions imposed against China and Chinese entities (including the placement of CNOOC on the U.S. Department of Commerce’s Entity List) have not so far had a material impact on our business activities in Asia, increased export restrictions on China and Chinese entities may limit the range of certain supplies to our operations in Asia and have an adverse effect on operational efficiency, results of operations, financial condition or reputation.

It is possible that additional related actions taken by the U.S. (and its trading partners and allies), Canada, China and other nations may limit or restrict foreign companies’ ability to participate in projects and operate in certain sectors of the Chinese economy, including the energy sector. The nature, extent and magnitude of the effect of dynamic trade relations cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, and results of operations, cash flows, and reputation.

U.S. sanctions related to China do not currently prevent or significantly impair our offshore operations in Asia, but they could do so in the future, particularly if U.S. sanctions against CNOOC were to be expanded. We cannot accurately predict the implementation of U.S. or Canadian policy affecting any current or future activities by CNOOC, Cenovus’s other international partners or Cenovus. Similarly, we cannot accurately predict whether U.S. restrictions will be further tightened or the impact of government action on Cenovus’s offshore operations in Asia. It is possible that the U.S. or Canadian government may subject CNOOC or Cenovus’s other international partners to restrictions or sanctions that may adversely impact our offshore operations in Asia.

Moreover, it is possible that, as a result of our partnership with CNOOC, we may be subject to negative media attention which may affect investors’ perception of Cenovus in Canada, the U.S. and globally, and which may negatively affect our share price and reputation.

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In addition, we may be affected by changes to bilateral relationships, the frameworks and global norms that govern international trade, and other geopolitical developments. This includes acute shocks (such as civil unrest or sanctions) and chronic stresses (such as political or business disputes and other forms of conflict, including military conflict) that may pose longer-term threats to our business. Unilateral action by, or changes in relations between, countries in which we operate, including the U.S. and China, and such countries’ approach to multilateralism and trade protectionism can impact our ability to access markets, technology, talent and capital. Disruptions or unanticipated changes of this nature may affect our ability to sell our products for optimum value or access inputs required for effective operations and has the potential to adversely affect our financial condition.

Geopolitical events, such as a shift in the relationship, an escalation or imposition of sanctions, tariffs or other trade tensions between the U.S. and China and Canada and China, may affect the supply, demand and price of crude oil, natural gas and refined products and therefore our financial condition. The timing, extent and fallout of the ongoing tensions between the U.S. and China, as well as Canada and China remain uncertain and the impact on our business is unknown.

Shifts in global power relations may also introduce greater uncertainty with respect to issues requiring global co-ordination (such as climate change, trade agreements, tax regulation, freedom of navigation and technology regulation), as well as raise questions on the efficacy of and trust in international institutions, including those that underpin international trade. These types of changes may cause restrictions or impose costs on our business, and may inhibit our future opportunities or affect our financial condition.

Our financial condition, operations and business may be adversely affected by any of the foregoing risks associated with international relations and specifically those risks arising from evolving U.S.-China and Canada-China relations. The nature, extent and magnitude of the effect of dynamic trade relations on us cannot be accurately predicted and may have a material adverse impact on our business, prospects, financial condition, results of operations, cash flows, and reputation.

Climate-Related Risks

There is growing international concern regarding climate change and there has recently been a significant increase in focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, environmental and governance organizations, institutional investors, social and environmental activists, and individuals, are increasingly seeking to implement, among other things, regulatory and policy changes, changes in investment patterns, and modifications in energy consumption habits and trends which, individually and collectively are intended to or have the effect of accelerating the reduction in the global consumption of fossil fuel-based energy, the conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from fossil fuel-based forms of energy.

Climate change and its associated impacts may increase our exposure to, and magnitude of, each of the risks identified in the Risk Management and Risk Factors section of this MD&A. Overall, we are not able to estimate at this time the degree to which climate change related regulatory, climatic conditions, and climate-related transition risks could impact our business, financial condition and results of operations. Our business, financial condition, results of operations, cash flows, reputation, access to capital and insurance, cost of borrowing, ability to fund dividend payments and/or business plans may, in particular, without limitation, be adversely impacted as a result of climate change and its associated impacts.

Transition Risks – Policy & Legal

Climate Change Regulation

We operate in several jurisdictions that regulate or have proposed to regulate GHG emissions, often with a view to transitioning to a lower-carbon economy. Some of these regulations are in effect while others remain in various phases of review, discussion or implementation. Uncertainties exist relating to the timing and effects of these emerging regulations and other contemplated legislation, including how they may be harmonized, make it difficult to accurately determine the cost impacts and effects on our suppliers. Additional changes to climate change legislation may adversely affect our business, financial condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time.

The Government of Canada has announced the carbon tax will increase to $170/tonne CO₂e by 2030. To reach that level, the price imposed on carbon will rise from the 2022 rate of $50/tonne CO₂e by $15/tonne CO₂e each year until 2030. To the extent a province’s carbon pricing system does not meet the federal stringency requirements, the federal “backstop” regulations apply. Most of our large emitting facilities operate in British Columbia, Alberta, Saskatchewan, or Newfoundland and Labrador where provincial carbon pricing regulations apply. These provincial programs are expected to continue to be deemed equivalent to the federal carbon pricing system.

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The Government of Canada has implemented regulation to enable the reduction of methane emissions from the crude oil and natural gas sector by 40 percent to 45 percent from 2012 levels by 2025. Regulatory requirements for fugitive equipment leaks and venting from well completion and compressors came into force on January 1, 2020. Further restrictions on facility production venting restrictions and venting limits for pneumatic equipment are expected to come into force on January 1, 2023. Certain provinces have since implemented provincial methane regulations that have been found to be equivalent with federal requirements. The Government of Canada has announced an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. More details on the specific actions that enable this level of emissions reduction are expected in the coming year.

The U.S. does not have federal legislation establishing targets for the reduction of, or setting individualized limits on, GHG emissions from our U.S. facilities. The RFS was created to reduce GHG emissions and risks from that program are described below. Additionally, the federal Environmental Protection Agency (“EPA”) has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (GHGRP) requires any facility releasing more than 25,000 tonnes of CO₂e emissions per year to report those emissions on an annual basis. In addition to reporting direct CO₂e emissions, the GHGRP requires refineries to estimate the CO₂e emissions from the potential subsequent combustion of the refinery’s products. In early 2021, the U.S. rejoined the Paris Agreement and subsequently announced a 2030 target to reduce GHG emissions by 50 percent to 52 percent from 2005 levels. It is too early to assess what impact these actions may have on our business, financial condition or results of operations.

Negative consequences which could arise as a result of changes to the current regulatory environment include, but are not limited to, changes in environmental and emissions regulation of current and future projects by governmental authorities, which could result in changes to facility design and operating requirements, potentially increasing the cost of construction, operation and abandonment. Other possible effects from emerging regulations may also include, but are not limited to: increased compliance costs; permitting delays; and substantial costs to generate or purchase emission credits or allowances, all of which may increase operating expenses. Further, emission allowances or offset credits may not be available for acquisition or may not be available on an economic basis, required emissions reductions may not be technically or economically feasible to implement, in whole or in part, and failure to have access to resources or technology to meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.

The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part because specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the additional measures being considered and the timeframes for compliance. Consequently, no assurances can be given that the effect of future climate change regulations will not be significant to us.

Low Carbon Fuel Standards

Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces and territories, the Canadian federal government and members of the European Union, regulating carbon fuel standards could result in increased costs and reduced revenue for us. The potential regulation may negatively affect the marketing of our bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to effect sales in such jurisdictions.

Environment and Climate Change Canada is expected to publish final regulations for the Clean Fuel Standard under the Canadian Environmental Protection Act, 1999, in the spring of 2022, with new regulations targeted to come into force in December 2022. The federal government has indicated that over time, the Clean Fuel Standard would replace the current Renewable Fuels Regulations, which requires producers and importers of transportation fuels to acquire a certain number of compliance units commensurate with the volumes of fuel they produce or import. The proposed new regulatory framework would impose lifecycle carbon intensity requirements for certain liquid fuels and establish rules relating to the trading of compliance credits. Carbon intensity requirements under the Clean Fuel Standard regulation would become more stringent over time and would be differentiated between different types of fuels to reflect the associated emissions reduction potential. Regulated parties, which may include fuel producers and importers, would have some flexibility with respect to how to achieve lower-carbon fuels in Canada. The Clean Fuel Standard regulation has the potential to impact our business, financial condition, results of operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.

Renewable Fuel Standards

Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into transportation fuel, or by purchasing RINs from other parties on the open market.

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Cenovus and our refinery operating partners comply with the RFS by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market, where prices fluctuate. We cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. Our financial position, results of operations and cash flows may be materially impacted if we are required to pay significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards. We have an RFS program to help mitigate risk related to fluctuating RINs pricing.

Light-Duty Vehicle Greenhouse Gas Emission Standards

The U.S. EPA has finalized new fuel economy standards applicable to automakers. The rule mandates new federal GHG emissions standards for passenger cars and light trucks by setting fuel economy standards for Model Years 2023 through 2026. These standards are expected to result in average fuel economy label values of 40 miles per gallon. The EPA’s stated intention for the rule is to prompt automakers to produce more electric vehicles and set a path to a zero-emissions transportation future. The EPA stated that it intends to initiate future rulemaking to establish multi-pollutant emissions standards for Model Year 2027 and beyond. The impact these standards may have on the future demand (and corresponding price levels) for our products is unknown and dependent upon a number of factors. See “Climate Change Transition – Demand and Commodity Prices” below.

Climate Change Related Litigation

In recent years there has been an increase in climate change related demands, disputes, and litigation in various jurisdictions including the U.S. and Canada, asserting various claims, including that energy producers contribute to climate change, that such entities are not reasonably managing business risks associated with climate change, and that such entities have not adequately disclosed business risks of climate change. While many of the climate change related actions are in preliminary stages of litigation, and in some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and political developments will not increase the likelihood of successful climate change related litigation against energy producers, including Cenovus. The outcome of any such litigation is uncertain and may materially impact our business, financial condition or results of operations. We may also be subject to adverse publicity associated with such matters, which may negatively affect public perception and our reputation, regardless of whether we are ultimately found responsible. We may be required to incur significant expenses or devote significant resources in defense against any such litigation.

Transition Risks – Technology

We depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals, including our ESG targets. Limitations related to the development, adoption and success of these technologies or the development of disruptive technologies could have a negative impact on our long-term business resilience.

Transition Risks – Market

Demand and Commodity Prices

The recent increase in focus on the timing and pace of the transition to a lower-carbon economy and resulting trends will likely affect global energy demand and usage, including the composition of the types of energy generally used by industry and individual consumers. Under certain aggressive low-carbon scenarios, potential demand erosion could contribute to commodity price fluctuations and structural commodity price declines. However, it is not currently possible to predict the timelines for and precise effects of this transition to a potential lower-carbon economy, which will depend on a multitude of factors including increased decarbonization policies, the ability to develop adequate alternative sources of energy, technology development and adaptation including in the area of transportation electrification, the ability to conceptualize, develop and commercialize technologies for the production, storage and distribution of adequate supplies of alternative energy, consumption patterns, global growth, industrial activity, weather patterns and climate conditions. All of these factors are beyond our control and could result in a high degree of price volatility for each of crude oil, natural gas, NGLs and refined products.

Market Access

Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about GHG emissions associated with fossil fuel-based energy development and end-use combustion of fuels. Additional concerns about pipeline spills can create opposition to pipeline projects at a local level. Our inability to optimize market access for either the delivery of our production or refining feedstock may negatively impact our business, financial condition, cash flows and results of operations.

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Access to Capital and Insurance

Capital markets are adjusting to the risks that climate change poses and as a result, our ability to access capital and secure adequate or prudent insurance coverage may also be adversely affected in the event that investors, credit rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies or through the general stigmatization of the oil and gas industry. Certain insurance companies have taken actions or announced policies to limit available coverage for companies which derive some or all of their revenue from the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our insurance policies could increase substantially. In some instances, coverage may be reduced or become unavailable. As a result, we may not be able to renew our existing policies, or procure other desirable insurance coverage, either on commercially reasonable terms, or at all. Additionally, certain financial institutions have taken actions or announced policies related to decarbonization of their loan portfolios. As a result, costs of financing could increase over time and we may not be able to refinance our debt, renew or extend credit facilities or procure additional financing at reasonable costs and interest rates, or at all. The future development of our business may be dependent upon our ability to obtain additional capital, including debt and equity financing. See “Credit, Liquidity and Availability of Future Financing” above.

Accuracy of Climate Scenarios and Assumptions

We integrate the potential impact of GHG regulations and the cost of carbon at various price levels into our business planning processes. To mitigate uncertainty surrounding future emissions regulation, we evaluate our development plans under a range of carbon-constrained scenarios. We have considered the International Energy Agency (“IEA”) scenarios in our strategic planning for several years and also conduct ongoing assessments of both public and private scenarios. Although management believes that our climate-related estimates are reasonable, aligned with current, pending and potential future regulations, and informed by the IEA’s climate scenarios, they are based on numerous assumptions that, if false, may have a material adverse effect on our business, financial condition and results of operations. Specifically, climate-related estimates influence our financial planning and investment decisions. Since we plan and evaluate opportunities partially on the basis of climate-related estimates, variations between actual outcomes and our expectations may have a material adverse effect on our business, financial condition, results of operations, reputation and cash flows.

Shareholder Activism

Shareholder activism has been increasing generally and in the energy industry, and investors may from time to time attempt to effect changes to our business or governance, with respect to climate change or otherwise, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our Board and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in significant fluctuation in the market price of our securities.

Transition Risks – Reputation and Public Perception of the Oil and Gas Sector

Development of fossil fuel-based energy, and in particular the Alberta oil sands, has received considerable attention on the subjects of environmental impact, climate change, GHG emissions and Indigenous reconciliation. Concerns about oil sands may, directly or indirectly, impair the profitability of our current oil sands projects, and the viability of future oil sands projects, by creating significant regulatory, economic and operating uncertainty. Increased public opposition to and stigmatization of the oil and gas sector, and in particular the oil sands industry, could lead to constrained access to insurance, liquidity and capital and changes in demand for our products, which may adversely impact our business, financial condition or results of operations.

For example, legislation or policies that limit the purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in stranded assets or an inability to further develop oil resources. See “Reputation Risk” below.

Climate Change – Physical Risks

Extreme climatic conditions may also have material adverse effects on our financial condition and results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, our exploration, production and construction operations, and the operations of major customers and suppliers, can be affected by acute physical climate risks, such as floods, forest fires, earthquakes, hurricanes, and other extreme weather events or natural disasters. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction.

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Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations, business and financial results. Specifically, our Atlantic operations may be impacted by severe weather conditions, including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased creation of icebergs. Icebergs off the coast of Newfoundland and Labrador pose a risk to Atlantic oil production facilities. An operational incident involving an iceberg has the potential to result in spills, asset damage, and production disruption. Climate change may result in an increased level of risk resulting in increased or additional mitigation requirements.

Our other operations are also subject to chronic physical risks such as a shorter timeframe for our winter drilling program, changes in the water table and reduced access to water due to drought conditions. A systemic change in temperature or precipitation patterns could result in more challenging conditions for the construction of ice roads, execution of our winter drilling program and reclamation activities and could reduce the availability of water due to the increasing likelihood of drought conditions.

Environmental Regulation Risks

All phases of our operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial, state, regional and municipal laws and regulations in the jurisdictions in which we operate (collectively, the “environmental regulations”). Environmental regulations provide that exploration areas, wells, facility sites, refineries and other properties and practices associated with our operations be constructed, operated, maintained, abandoned, reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications.

We anticipate that further changes in environmental legislation could occur, which may result in approval delays for critical licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and increased costs for closure, reclamation and ecological restoration. The complexities of changes in environmental regulations make it difficult to predict the potential future impact to our business.

Compliance with environmental regulations requires significant expenditures. Our future capital expenditures and operating expenses could continue to increase as a result of, among other things, developments in our business, operations, plans and objectives and changes to existing, or implementation of new, environmental regulations. Failure to comply with environmental regulations may result in, among other things, the imposition of fines, penalties, environmental protection orders, suspension of operations, prosecution, and could adversely affect our reputation. The costs of complying with environmental regulations and remedying noncompliance issues may have a material adverse effect on our business, financial condition, results of operations and cash flows. The implementation of new environmental regulations or changes in interpretation or the modification of existing environmental regulations affecting the crude oil, natural gas, NGL and refining industry generally could reduce demand for our products as well as shift hydrocarbon demand toward relatively lower-carbon sources and affect our long-term prospects.

U.S. environmental regulations and aggressive enforcement from regulators present challenges and risks to our U.S. operations. New emission standards, more stringent water quality standards, and regulation of emerging containments such as Per- and Polyfluoroalkyl Substances (“PFAS”) can increase compliance costs, require capital projects, lengthen project implementation times, and have an adverse effect on our business, financial condition, results of operations and cash flows. U.S. regulators currently are assessing whether PFAS should be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup liability at U.S. sites. See “Water Regulation ”below.

Canadian Species at Risk Act

The Canadian federal Species at Risk Act, as well as provincial regulation regarding threatened or endangered species and their habitat may limit the pace and the amount of development or activity in areas identified as critical habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal government in relation to their obligations under the Species at Risk Act have raised issues associated with the protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of initiatives has been undertaken to support caribou recovery, including the Draft Provincial Woodland Caribou Range Plan, which was released in 2017 but has not yet been finalized. Other initiatives include negotiation of conservation agreements under Section 11 of the Species at Risk Act (which codifies concrete measures to support the conservation of the species and the protection of its critical habitat), and the elaboration of sub-regional plans for the Cold Lake, Bistcho and Upper Smokey areas, to address recovery outcomes for certain caribou ranges. If plans and actions undertaken by the provinces are deemed insufficient to support caribou recovery, the federal legislation includes the ability to implement measures that would preclude further development or modification of existing operations. The extent and magnitude of any potential adverse impacts of legislation on in situ oil sands project development and operations cannot be estimated, as uncertainty exists as to whether plans and actions undertaken by the provinces will be sufficient to support caribou recovery.

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Canadian Federal Air Quality Management System

The Multi Sector Air Pollutants Regulations (“MSAPR”), issued under the Canadian Environmental Protection Act, 1999, seek to protect the environment and health of Canadians by setting mandatory, nationally-consistent air pollutant emission standards. The MSAPR are aimed at equipment-specific Base-Level Industrial Emissions Requirements (“BLIERs”). Nitrogen oxide BLIERs from our non-utility boilers, heaters and stationary engines are regulated in accordance with specified performance standards. We anticipate that the MSAPR will result in adverse impacts to Cenovus including but not limited to capital investment required to retrofit existing equipment and increased operating costs.

Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter and ozone were introduced as part of a national Air Quality Management System. Provinces may implement the CAAQS at the regional air zone level and air zone management actions may include more stringent emissions standards applicable to industrial sources from approval holders in regions where we operate that may result in adverse impacts including but not limited to capital investment related to retrofitting existing facilities and increased operating costs.

Review of Environmental and Regulatory Processes

Increased environmental assessment obligations imposed by federal, provincial, territorial, state and municipal governments in the jurisdictions in which we conduct operations, development or exploration may create risk of increased costs and project development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving and changing and may become more onerous or costly which may impede our ability to economically develop our resources. The extent and magnitude of any adverse impacts of changes to the regulatory framework on project development and operations cannot be estimated at this time.

The Impact Assessment Agency of Canada leads and coordinates federal impact assessments for all designated projects within Canada. Assessment considerations beyond the environment expressly include health, economic, social, and gender impacts, as well as considerations related to sustainability and Canada’s climate change commitments. For as long as the Alberta provincial government maintains the cap on oil sands emissions in Alberta and the cap has not been reached, our in situ oil sands projects should be exempted from the application of the federal impact assessment system, provided a number of additional conditions are met. However, other types of projects would undergo a federal assessment, including those within our Atlantic operations.

Water Regulation

We utilize fresh water in certain operations, which is obtained under licenses issued within each respective jurisdiction’s regulations. If water use fees increase, the terms of the licences change or there are reductions in the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial condition. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted on favourable terms. This may adversely affect our business, including the ability to operate our assets and execute development plans.

Our U.S. refineries are subject to water discharge requirements that require treatment of wastewater prior to discharging. Permits for discharging water are renewed from time to time to incorporate new water quality standards and may require modifications and expansion of water treatment facilities at the sites. Pollutants such as selenium, total dissolved solids, arsenic, mercury and others may require advance wastewater treatment, and discharge levels will depend on the types of crude processed at our refineries. Non-compliance with permit limits can lead to enforcement actions by regulators including issuance of fines, orders to upgrade treatment plants, and suspension of operations. Federal and state regulators in the U.S. are currently addressing the emerging pollutant PFAS in water discharge permits by requiring installation of additional wastewater treatment units and requiring monitoring of PFAS in discharges.

Hydraulic Fracturing

Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and suggest that additional federal, provincial, territorial, state, regional and/or municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

In addition, some areas of British Columbia and Alberta have experienced increased localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been correlated with hydraulic fracturing in Western Canada, which has prompted legislative and regulatory initiatives intended to address these concerns.

Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or restrictions to oil and gas development activities, operational delays, increased compliance costs, additional operating requirements, or increased third-party or governmental claims that could increase our cost of doing business as well as reduce the amount of natural gas and oil that we are ultimately able to produce from our reserves.

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Cenovus ESG Focus Areas, Targets and Ambitions

We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our absolute emissions, using less water, reclaiming more land, supporting Indigenous reconciliation and increasing the number of women in leadership positions. To achieve these goals and to respond to changing market demand, we may incur additional costs and invest in new technologies and innovation. It is possible that the return on these investments may be less than we expect, which may have an adverse effect on our business, financial condition and reputation.

Generally speaking, our ESG targets and ambitions depend significantly on our ability to execute our current business strategy, which can be impacted by the numerous risks and uncertainties associated with our business and the industry in which we operate, as outlined in the Risk Management and Risk Factors section of this MD&A. We recognize that our ability to adapt to and succeed in a lower-carbon economy will be compared against our peers. Investors and stakeholders increasingly compare companies based on ESG-related performance, including climate-related performance. Failure to achieve our ESG targets and ambitions, or a perception among key stakeholders that our ESG targets and ambitions are insufficient or unattainable, could adversely affect our reputation and our ability to attract capital and insurance coverage.

There is also a risk that some or all of the expected benefits and opportunities of achieving the various ESG targets and ambitions may fail to materialize, may cost more to achieve or may not occur within the anticipated time periods. In addition, there are risks that the actions we take in implementing targets and ambitions relating to our ESG focus areas may have a negative impact on our existing business and increase capital expenditures, which could have a negative impact on our future operating and financial results.

Climate and GHG Emissions Targets and Ambitions

We have set a target to reduce our absolute scope 1 and 2 GHG emissions by 35 percent by year-end 2035 from 2019 levels and have a long-term ambition to achieve net zero emissions from our operations by 2050. Our ability to meet our 2035 GHG reduction target and 2050 net zero ambition are subject to numerous risks and uncertainties and our actions taken in implementing such target and ambition may also expose us to certain additional and/or heightened financial and operational risks. Furthermore, our long-term ambition of reaching net zero emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary for us to achieve this long-term ambition.

A reduction in GHG emissions relies on, among other things, our ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technology and products. In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emission targets and goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification initiatives in our Conventional segment; the purchase of renewable electricity; the unavailability of, or limited benefits from, technology that is expected to be commercially viable in the near term and its associated future benefits, including SAGD enhancement technologies, such as solvent-aided process and solvent-driven process technologies, carbon capture, utilization and storage technology and downhole technology improvements; and a failure to capture the anticipated benefits of continued technological development, and industry collaboration and innovation to find solutions to reduce costs and GHG emissions. In the event that we are unable to implement these strategies and technologies as planned without negatively impacting our expected operations or cost structure, or such strategies or technologies do not perform as expected, we may be unable to meet our 2035 GHG reduction target or 2050 net zero emissions ambition on the current timelines, or at all.

In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework and will require capital expenditures and company resources, with the potential that actual costs may differ from our original estimates and the differences may be material. Furthermore, the cost of investing in emissions-reduction technologies, and the resultant change in the deployment of resources and focus, could have a negative impact on our future operating and financial results.

Water Stewardship Target

Our ability to reduce fresh water intensity by 20 percent in oil sands and in thermal operations by year-end 2030 will depend on the commercial viability and scalability of relevant water reduction strategies and related steam and water usage technology and products. There are risks associated with relying largely or partly on new technologies, the incorporation of such technologies into new or existing operations and acceptance of new technologies in the market. In the event we are unable to effectively and efficiently deploy the necessary technology, or such strategies or technologies do not perform as expected, achieving our stated target of reducing our water intensity could be interrupted, delayed or abandoned.

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Biodiversity Targets

Our biodiversity targets include the goal to reclaim 3,000 decommissioned well sites by year-end 2025 and to restore more habitat than we use within the Cold Lake caribou range by year-end 2030. Our ability to meet these targets is subject to various environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See “Abandonment and Reclamation Cost Risk” above. In addition, an increase in operating costs, changes to market conditions and access to additional capital, if needed, could result in our inability to fund, and ultimately meet, our biodiversity targets on the current timelines, or at all.

Indigenous Reconciliation Targets

Our Indigenous reconciliation targets to spend a minimum of $1.2 billion with Indigenous owned or operated businesses between 2019 and year-end 2025 and attain Progressive Aboriginal Relations gold certification from the Canadian Council for Aboriginal Business by year-end 2025 are subject to a number of financial, operational and efficiency risks relating to actions taken in implementing such targets.

In addition, a failure or delay in achieving our Indigenous reconciliation targets may adversely affect our relationship with neighboring Indigenous businesses and communities and our broader reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate properties in line with our current business and operational strategies may be adversely impacted.

Inclusion and Diversity Targets

Our inclusion and diversity focus area includes a target of women in leadership roles of at least 30 percent by year-end 2030 and an aspiration for our Board to have at least 40 percent representation from women, Aboriginal peoples, persons with disabilities and members of visible minorities among non-management directors, including at least 30 percent women by year-end 2025. Efforts to meet such targets may increase the time and costs associated with appointing and replacing key personnel. Further, a failure or delay in achieving our targets may influence our reputation with our stakeholders, attract litigation and impact recruitment initiatives. There are also risks associated with the collection of certain personal data in furtherance of these targets, which is governed by federal, provincial and state privacy legislation.

Reputation Risk

We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to recruit and retain staff, and to be a credible, trusted company. Any actions we take that influence public or key stakeholder opinions have the potential to impact our reputation which may adversely affect our share price, development plans and our ability to continue operations. There is increasing opposition from climate change activist organizations and the public towards oil and gas operations. See “Transition Risks – Reputation and Public Perception of the Oil and Gas Sector” above.

Other Risks

Dilutive Effect

We are authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on terms and conditions as established by our Board without the approval of our shareholders in certain instances. Any future issuances of Cenovus common shares or other securities exercisable or convertible into, or exchangeable for, Cenovus common shares may result in dilution to present and prospective Cenovus shareholders. The issuance of additional Cenovus common shares upon exercise, from time to time, of securities convertible into Cenovus common shares will have a further dilutive effect on the ownership interest of shareholders of Cenovus. Such issuances will have a dilutive effect on Cenovus’s earnings per share, which could adversely affect the market price of Cenovus common shares and may adversely impact the value of Cenovus shareholders’ investments.

It is also expected that, from time to time, we will grant additional equity awards to our employees and directors under our compensation plans. These additional equity awards will have a further dilutive effect on our earnings per share, which could also negatively affect the market price of Cenovus common shares and may adversely impact the value of our shareholders’ investments.

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Risks Relating to Acquisitions

We have completed, and may complete in the future, one or more acquisitions for various strategic reasons including to strengthen our position and to create the opportunity to realize certain benefits. In order to achieve the benefits of any future acquisitions, we will be dependent upon our ability to successfully consolidate functions and integrate operations, procedures and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with our existing assets and operations. The integration of acquired assets and operations requires the dedication of management effort, time and resources, which may divert management’s focus and resources from other strategic opportunities and from operational matters during the process. The integration process may result in the disruption of ongoing business and customer relationships that may adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires the assessment of reservoir and infrastructure characteristics, including estimated recoverable reserves, future production, commodity prices, revenues, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to increased costs and liabilities. Although the acquired assets are reviewed prior to completion of an acquisition, such reviews are not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired assets are in geographic areas where we have not historically operated. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition and we may be required to assume the risk of the physical condition of the properties that may not perform in accordance with its expectations. See “Risks Related to the Arrangement” below.

Risks Relating to Dispositions

We have identified, and may identify in the future, certain assets for disposition. Specifically, we have entered into agreements to sell our Husky retail fuel network, our Tucker asset and our Wembley assets. Various factors could materially affect our ability to complete these announced transactions or to dispose of assets in the future, including stock exchange, regulatory, third-party and corporate approvals, counterparties’ ability to fulfill their obligations under agreements to affect dispositions, commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to us, associated asset retirement obligations, due diligence, favourable market conditions, and the assignability of joint venture, partnership or other arrangements. These factors may also reduce the proceeds or value to our business. We may also retain certain liabilities for or agree to indemnification obligations in a sale transaction. The magnitude of any such retained liabilities or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material. Further, certain third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after the sale of certain assets, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations. Should any of the risk associated with dispositions materialize, it could have an adverse effect on our business, financial condition or reputation.

Risks Related to the Arrangement

Our Ability to Realize the Anticipated Benefits of the Arrangement by Integrating the Legacy Husky Operations

The process of integrating the legacy Husky operations into our business is ongoing. While much has been accomplished, the process is not yet complete and these efforts could result in disruption of existing relationships with suppliers, employees, customers and other stakeholders. There can be no assurance that management will be able to achieve all of the benefits that are expected to result from the Arrangement on the expected timelines, or at all.

The ongoing integration process involves numerous operational, strategic, financial, accounting, legal, tax and other risks and uncertainties associated with our business and operations, including the legacy Husky business. Difficulties in integrating our businesses may result in variations in expected performance, operational challenges or the failure to realize anticipated efficiencies on the expected timelines or at all.

The ongoing integration process to realize all of the benefits of the Arrangement requires substantial management effort, time and resources which may divert Management’s focus and resources from other strategic opportunities and operational matters and may result in increased attrition rates in the workforce (including the loss of key employees), the disruption of ongoing business and employee relationships, and increased employment-related claims and litigation, all of which may adversely affect our ability to achieve all of the anticipated benefits of the Arrangement.

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Potential difficulties that may be encountered in the integration process include but are not limited to: (i) the inability to successfully integrate the businesses in a manner that permits us to achieve all of the anticipated revenue and cost savings on the expected timelines; (ii) complexities associated with managing a larger, more complex, multinational integrated business; (iii) integrating personnel at all levels of the company over multiple jurisdictions, effectively and efficiently; (iv) difficulties integrating and maintaining relationships with industry contacts and existing business partners associated with the legacy Husky operations, including the termination or modification of existing contractual relationships; and (v) the disruption of, or the loss of momentum in our business, including the legacy Husky business. Such challenges may prohibit us from successfully integrating the legacy Husky business or may materially delay the integration process. A failure to integrate the business on the expected timeline, may have an adverse effect on our financial condition, results of operations, and ability to realize the anticipated benefits of the Arrangement.

It is possible that the ongoing integration process could result in increased attrition levels generally or the loss of key employees to assist in the integration and operation of our businesses, which may exacerbate integration challenges. Difficulties or delays in the integration process or the inability to fully integrate the legacy Husky business could have a material adverse effect on our business, cash flow, operating results, financial condition, reputation and share price.

Costs Associated with the Integration of the Legacy Husky Operations

We may incur significant costs related to implementing ongoing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs and additional unanticipated costs may be incurred in connection with the integration of the businesses. While we have accounted for a certain level of expenses, many factors beyond our control may affect the total amount or the timing of expenses associated with the integration process. Any unanticipated costs and expenses related to the integration may have an adverse effect on our business, financial condition, results of operations and share price.

Potential Unforeseen Liabilities Associated with the Arrangement

The Arrangement and the operation of the legacy Husky operations may subject us to unforeseen or underestimated liabilities, including environmental and regulatory liabilities in Canada and other foreign jurisdictions. We may now be subject to or inherit claims related to the legacy Husky operations, including actions by former directors and employees. We may also be subject to adverse publicity associated with such matters, regardless of whether we are ultimately found responsible and may be required to incur significant expenses or devote significant resources in defense against any litigation of such claims. The outcome of any such claims, and any associated litigation or regulatory proceedings, is uncertain and may negatively impact our financial condition, results of operations and reputation.

Risks Related to Significant Shareholders of Cenovus

As of December 31, 2021, Hutchison Whampoa Europe Investments S.à r.l. (“Hutchison”) and L.F. Investments S.à r.l (“L.F. Investments”) own 15.8 percent and 11.6 percent of our common shares, respectively. Although each of Hutchison and L.F. Investments are subject to restrictions from selling or transferring Cenovus common shares through July 1, 2022 pursuant to the terms of their respective standstill agreement with Cenovus, the sale of Cenovus common shares held by any of Hutchison or L.F. Investments into the market, either through open market trades on the TSX and NYSE stock exchanges, through privately arranged block trades, or pursuant to prospectus offerings made in accordance with the respective registration rights agreement that each of Hutchison and L.F. Investments have entered into with Cenovus, or market perception regarding Hutchison or L.F. Investments’ intention to sell Cenovus common shares, could adversely affect market prices for our common shares.

While Hutchison and L.F. Investments are each subject to certain voting covenants pursuant to the terms of a standstill agreement they each entered into with us in connection with the Arrangement, each of Hutchison and L.F. Investments may be able to impact certain matters requiring shareholder approval.

Market for Cenovus Warrants

There can be no assurance that an active public market for Cenovus Warrants will be sustained. If such a market is sustained, the market price of the Cenovus Warrants may be adversely affected by a variety of factors relating to Cenovus’s business, including, but not limited to, fluctuations in our operating and financial results, the results of any public announcements made by us and our failure to meet analysts’ expectations. In addition, the market price of the Cenovus common shares will significantly affect the market price of the Cenovus Warrants. This may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants.

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Contingent Payments Payable to ConocoPhillips

In connection with the Conoco Acquisition, we agreed to make contingent payments to ConocoPhillips under certain circumstances. The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the five-year period following the closing of the Conoco Acquisition (May 17, 2017), and such payments may be significant. In addition, in the event that such further payments are made, this could have an adverse impact on our business, results of operations and financial condition.

Tax Laws

Income tax laws, regulations, and other laws or government incentive programs may in the future be changed or interpreted in a manner that adversely affects us, our financial results and our shareholders. Tax authorities having jurisdiction over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders.

The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration related to the Organisation for Economic Co-operation and Development’s (“OECD”) Base Erosion and Profit Shifting (“BEPS”) project. Although the timing and methods of implementation vary, numerous countries including Canada have responded to the BEPS project by implementing, or proposing to implement, changes to tax laws and tax treaties, at a rapid pace. These changes may increase our cost of tax compliance and affect our business, financial condition and results of operations in a manner that is difficult to quantify. We will continue to monitor and assess potential adverse impacts on our global tax situation as a result of the BEPS project.

U.S. Tax Risk

On November 19, 2021, the U.S. House of Representatives passed the Build Back Better Act (the “Act”). The Act contains a number of social and environmental initiatives with a combined estimated cost of USD $1.75 trillion. The initiatives were primarily funded through various federal tax changes. On December 19, 2021, West Virginia’s Senator Manchin formally voiced his opposition to the bill, thereby effectively stopping it before it was brought to a vote in the Senate. There is a possibility that portions of the Act will be resurrected in some form in a new bill and any tax changes contained therein could result in increased levels of U.S. taxation on our U.S. operations.

A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business, prospects, financial condition, results of operations and cash flows, and in some cases our reputation, can be found in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING

POLICIES

Management is required to make estimates and assumptions, as well as 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.

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 Consolidated Financial Statements.

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint operations held by the Company are as follows:

• 50 percent interest in WRB Refining LP (“WRB LP”).

• 50 percent interest in Sunrise Oil Sands Partnership (“SOSP”).

• 50 percent interest in BP-Husky Refining LLC (“Toledo”).

It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB LP, SOSP and Toledo. As a result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

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In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the following:

• The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

• The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past and future development of WRB LP, SOSP and Toledo is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

• WRB LP and SOSP have third-party debt facilities to cover short-term working capital requirements.

• SOSP is operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. WRB LP and Toledo have very similar structures modified to account for the operating environment of the refining business.

• Cenovus, Phillips 66 and BP, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage, on the partners’ behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangements do not have employees and, as such, are not capable of performing these roles.

• In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and reversals.

Recoveries from Insurance Claims

The Company uses estimates and assumptions on the amount recorded for insurance proceeds expected to be received. Accordingly, actual results may differ from these estimated recoveries.

Functional Currency

The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the primary economic environment in which the subsidiary operates.

Fair Value of Related Party Transactions

The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such relationships can have an effect on the financial results of the Company and may lead to differences in the transactions between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be obtained to confirm the estimated fair value of proceeds.

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. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

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In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of COVID-19. The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to prepare the Consolidated Financial Statements, particularly related to recoverable amounts.

In addition, the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions.

The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities.Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, GHG and emissions targets, water stewardship targets, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands and Conventional segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s refining assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, market crack spreads, operating expenses, transportation capacity, future capital expenditures, supply and demand conditions and the terminal values used. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

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Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions such as forward commodity prices, quantity of reserves and resources, production costs, Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value of the net assets.

Income Tax Provisions

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdiction. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

Changes in Accounting Policies

In 2021, as a result of the close of the Arrangement, the Company updated its significant accounting policies including those around principles of consolidation, revenue recognition, employee benefit plans, related party transactions, cash and cash equivalents, PP&E, share capital and warrants and stock based compensation.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the affiliate’s profit or loss and other comprehensive income (“OCI”).

Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

Cenovus recognizes revenue from the following major products and services:

• Sale of crude oil, NGLs and natural gas.

• Sale of petroleum and refined products.

• Crude oil and natural gas processing services.

• Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.

• Fee-for-service hydrocarbon trans-loading services.

• Construction services.

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The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and trans-loading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with natural gas processing, transportation services and trans-loading services are generally based on fixed price contracts.

Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed.

The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with the exception of certain construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.

Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component.

Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement.

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:

• Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

• Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

• Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a one-time incentive program was introduced whereby a cash award equivalent to the employee’s base salary was payable if Cenovus achieved, prior to February 12, 2024, a target share price of $20 per share for a period of 20 consecutive trading days on the TSX (the “Plan”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is recognized as general and administrative expense over the estimated time until payout is achieved.

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Related Party Transactions

The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.

Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans.

Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset.

Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on total proved reserves or total proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and natural gas properties are depleted using a unit-of-production method.

Manufacturing Assets

The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

• Land improvements and buildings: 15 to 40 years.

• Office improvements and buildings: 3 to 15 years.

• Refining equipment: 10 to 60 years.

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Processing, Transportation and Storage Assets, Retail and Other

Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available for use by the Company.

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The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

Share Capital and Warrants

Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased.

Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are recorded as share capital.

Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, PSUs, RSUs and DSUs. Stock-based compensation costs are recorded in general and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2022, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements.

CONTROL ENVIRONMENT

Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2021. In making its assessment, Management used the Committee of Sponsoring Organizations of the Treadway Commission Framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of ICFR. Based on our evaluation, Management has concluded that both ICFR and DC&P were effective as at December 31, 2021.

The effectiveness of our ICFR was audited as at December 31, 2021 by PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, as stated in their Report of Independent Registered Public Accounting Firm, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2021.

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.

OUTLOOK

Energy markets have improved significantly in 2021. Successful global COVID-19 vaccine rollouts and solid economic growth have resulted in demand growth for crude oil and refined products, while generally the supply response has lagged. However, in the fourth quarter of 2021, the rapid rise of the Omicron variant and concerns that near-term supply could outpace demand has introduced crude oil and refined products market volatility. Early indications are that the Omicron variant is a milder variant that may not impact demand recovery significantly in the first quarter of 2022. The scale of resurgence and variants of COVID-19 is unpredictable and likely to result in market volatility into 2022. OPEC+ policy continues to support balancing the market. The group began to gradually unwind supply curtailments and is expected to increase production into 2022.

Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. We aim to maximize shareholder value through premium cost structures and optimizing margins while delivering top-tier safety performance and ESG leadership. The Company prioritizes Free Funds Flow generation which enables debt reduction, increased shareholder returns through dividend growth and share buybacks, reinvestment in the business and diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price volatility.

The following outlook commentary is focused on the next 12 months.

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Commodity Prices Underlying our Financial Results

Our commodity pricing outlook is influenced by the following:

• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns and effectiveness of COVID-19 vaccines.

• The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they decide to increase production and the degree to which spare capacity exists to meet quotas.

• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.

• Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America.

Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather throughout the year.

Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel, solvent and blending requirements at our Oil Sands operations.

We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board and the Bank of Canada raise or lower benchmark lending rates relative to each other and emerging macro-economic factors.

Our upstream crude oil production and most of our downstream refined products are exposed to movements in the WTI crude oil price. With the closing of the Arrangement, our exposure has grown on both the upstream and downstream sides of our business.

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Our refining capacity is now focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spread in all of these markets.

Our WTI exposure to crude differentials includes light-heavy and light-medium price differentials. Light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have refining capacity, and to a lesser degree in the USGC and Alberta. Our exposure to light-heavy crude oil price differentials is composed of a global light-heavy component, a regional component in markets we transport barrels to, as well as the Alberta differential, which is subject to transportation constraints. While we expect to see volatility in crude oil prices, we have the ability to partially mitigate the impact of crude oil and refined product prices and differentials through the following:

• Transportation commitments and arrangements – using our existing firm service commitments for takeaway capacity and supporting transportation projects that move crude oil from our production areas to consuming markets, including tidewater markets.

• 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 as well as from spreads on refined products.

• 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.

• 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 rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil price differentials.

• Traditional crude oil storage tanks in various geographic locations.

• Financial hedge transactions – limiting the impact of fluctuations in crude oil and refined product prices by entering into financial transactions related to our inventory price exposures.

Key Priorities for 2022

Our five key strategic objectives include delivering top-tier safety performance and ESG leadership; maximizing shareholder value through competitive cost structures and optimizing margins; maintaining and further reducing debt levels; a returns-focused capital allocation, incorporating increased shareholder returns that complement our business; and growing Free Funds Flow through pricing cycles.

Top Tier Safety Performance and ESG Leadership

Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. We’ve identified safety along with corporate governance as our top value and foundational to our business, providing the backbone for all our operations. We will continue to promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind.

We are committed to demonstrating ESG leadership and continue to take concrete steps to earn our position as a global energy supplier of choice. In December 2021, Cenovus released targets representing our five ESG focus areas:

• Climate & GHG emissions.

• Water stewardship.

• Biodiversity.

• Indigenous reconciliation.

• Inclusion & diversity.

A path and program for achieving each target has been established, including identifying the levers and resources that will be required. These commitments are embedded in the five-year business plan to ensure business decisions are aligned with the targets. Additional information on management’s efforts and performance across environmental, social and governance topics, including our ESG targets and plans to achieve them, are available in Cenovus’s 2020 ESG report at cenovus.com.

As part of the integration of Cenovus and Husky we completed a policy harmonization initiative in 2021. Our updated Sustainability Policy, together with our revised Code of Business Conduct & Ethics, guides our actions and outlines our commitment to embedding environmental, economic and social considerations in our business decisions. We also formalized and published Human Rights and Indigenous Relations policies that reinforce our commitments, values and behaviours. Our directors, management and employees are annually required to complete policy training to review and commit to our Sustainability Policy, Code of Business Conduct & Ethics and a number of other key policies and standards.

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Competitive Cost Structures and Optimizing Margins

We delivered our planned target of $1.2 billion in annual run-rate synergies by the end of 2021. Over the longer-term, we anticipate additional cost savings and margin enhancements based on further physical integration of upstream assets with downstream assets, which is expected to shorten the value chain and reduce condensate costs associated with heavy oil transportation. We continue to look for ways to improve efficiencies across Cenovus to drive incremental capital, operating and general and administrative cost reductions.

Maintaining and Further Reducing Debt Levels

Cenovus achieved its interim Net Debt Target of $10 billion in 2021. As at December 31, 2021, our Net Debt position was $9.6 billion. At December 31, 2021, long-term debt was $12.4 billion, and cash and cash equivalents was $2.9 billion. Through a combination of cash on hand and available capacity on our committed credit facility and demand facilities, we have approximately $10.0 billion of liquidity as at year end 2021. Our long-term Net Debt Target is between $6 billion and $8 billion. We aim for a Net Debt to Adjusted EBITDA ratio of between 1.0 to 1.5 times at the bottom of the cycle, which we see as approximately US$45 WTI per barrel.

Returns-focused Capital Allocation

The Company’s capital program and current base dividend are sustainable at US$45 WTI per barrel, with the opportunity to grow shareholder returns over the life of the plan as Net Debt is further reduced. Once Cenovus achieves Net Debt below $8 billion we expect to have further expanded capacity for increasing shareholder returns, including share purchases and increasing the common share dividend.

We anticipate our total capital expenditures to be between $2.6 billion and $3.0 billion, including $200 million to $250 million (excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2022 guidance data dated December 7, 2021, is available on our website at cenovus.com.

Growing Free Funds Flow Through Pricing Cycles

Our top-tier assets and cost structures position us to grow Free Funds Flow through pricing cycles. Cenovus’s diversified asset and product mix generates predictable and stable Free Funds Flow, and reduces risk and cash flow volatility through the optimization of the value chain through pipelines, logistics and marketing. We are able to generate strong margins with modest capital investment.

Cenovus has a track record of operational reliability and expects our annual upstream production to average between 780 thousand BOE per day and 820 thousand BOE per day and total downstream crude throughput of 530 thousand barrels per day to 580 thousand barrels per day in 2022. We continue to monitor the overall market dynamics to assess how we manage our upstream production levels. Our assets can respond to market signals and ramp production up or down accordingly. Our decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our products.

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 CONSOLIDATED FINANCIAL STATEMENTS

  FOR THE YEAR ENDED DECEMBER 31, 2021

REPORT OF MANAGEMENT		83
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM		84
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)		88
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)		88
CONSOLIDATED BALANCE SHEETS		89
CONSOLIDATED STATEMENTS OF EQUITY		90
CONSOLIDATED STATEMENTS OF CASH FLOWS		91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		92
1.	DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES	92
2.	BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE	99
3.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	99
4.	CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY	108
5.	ACQUISITIONS	112
6.	GENERAL AND ADMINISTRATIVE	114
7.	FINANCE COST	114
8.	FOREIGN EXCHANGE (GAIN) LOSS, NET	114
9.	DIVESTITURES	114
10.	IMPAIRMENT CHARGES AND REVERSALS	115
11.	INCOME TAXES	119
12.	PER SHARE AMOUNTS	122
13.	CASH AND CASH EQUIVALENTS	123
14.	ACCOUNTS RECEIVABLE AND ACCRUED REVENUES	123

15.	INVENTORIES	123
16.	ASSETS HELD FOR SALE	124
17.	EXPLORATION AND EVALUATION ASSETS, NET	124
18.	PROPERTY, PLANT AND EQUIPMENT, NET	125
19.	RIGHT-OF-USE ASSETS, NET	126
20.	JOINT ARRANGEMENTS AND ASSOCIATE	126
21.	OTHER ASSETS	128
22.	GOODWILL	128
23.	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES	129
24.	CONTINGENT PAYMENT	129
25.	DEBT AND CAPITAL STRUCTURE	129
26.	LEASE LIABILITIES	134
27.	DECOMMISSIONING LIABILITIES	134
28.	OTHER LIABILITIES	135
29.	PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS	135
30.	SHARE CAPITAL AND WARRANTS	139
31.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	141
32.	STOCK-BASED COMPENSATION PLANS	142
33.	EMPLOYEE SALARIES AND BENEFIT EXPENSES	145
34.	RELATED PARTY TRANSACTIONS	145
35.	FINANCIAL INSTRUMENTS	146
36.	RISK MANAGEMENT	148
37.	SUPPLEMENTARY CASH FLOW INFORMATION	152
38.	COMMITMENTS AND CONTINGENCIES	154

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REPORT OF MANAGEMENT

Management’s Responsibility for the Consolidated Financial Statements

The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect Management’s best judgments.

The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is made up of five independent directors. The Audit Committee has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee met with Management and the independent auditors on at least a quarterly basis to review and recommend the approval of the interim Consolidated Financial Statements and Management’s Discussion and Analysis to the Board of Directors prior to their public release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion and Analysis and recommend their approval to the Board of Directors.

Management’s Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The internal control system was designed to provide reasonable assurance to Management regarding the preparation and presentation of the Consolidated Financial Statements.

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.

Management has assessed the design and effectiveness of internal control over financial reporting as at December 31, 2021. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2021.

PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed to audit and provide independent opinions on both the Consolidated Financial Statements and internal control over financial reporting as at December 31, 2021, as stated in their Report of Independent Registered Public Accounting Firm dated February 7, 2022.

PricewaterhouseCoopers LLP has provided such opinions.

/s/ Alexander J. Pourbaix	/s/ Jeffrey R. Hart
Alexander J. Pourbaix	Jeffrey R. Hart
President & Chief Executive Officer	Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.	Cenovus Energy Inc.

February 7, 2022

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Cenovus Energy Inc.

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of earnings (loss), comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by Management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial Statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the Consolidated Financial Statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the Consolidated Financial Statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impact of Reserves and Resource Estimates on Property, Plant and Equipment (“PP&E”), Net and any Allocated Goodwill of the Oil Sands, Conventional and Offshore Segments (collectively, the “Upstream Segments”)

As described in Notes 1, 3, 4, 10, 18 and 22 to the Consolidated Financial Statements, Management assesses its cash generating units (“CGUs”) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated Depreciation, Depletion and Amortization (“DD&A”) and net impairment losses, may exceed its recoverable amount. Management also assesses on a quarterly basis whether facts and circumstances suggest that the recoverable amount of a previously impaired CGU may exceed its carrying amount. Goodwill is tested for impairment at least annually. Management calculates depletion for Oil Sands and Conventional assets using the unit-of-production method based on estimated proved reserves. For Offshore assets, Management calculates depletion using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves. Costs subject to depletion include estimated future development costs to be incurred in developing proved or proved plus probable reserves. As of December 31, 2021, the Company had $22.5 billion, $2.2 billion and $2.8 billion in Oil Sands, Conventional and Offshore PP&E, net, respectively. Goodwill related to the Oil Sands segment amounted to $3.5 billion as of December 31, 2021. In aggregate, the Company recognized $3.2 billion of DD&A expense for the Upstream Segments, which is net of impairment reversals of $378 million for the Conventional CGUs, for the year ended December 31, 2021. No impairment indicators were identified for the Offshore CGUs. Management determined the recoverable amounts of the Oil Sands and Conventional CGUs (the “recoverable amounts”) based on their fair values less costs of disposal using discounted after-tax cash flow models. The determination of the recoverable amounts required the use of significant estimates and judgments by Management related to forward commodity prices, expected production volumes, estimated reserves and resources, future development and operating expenditures and discount rates. Management’s estimates of reserves and resources used for both the determination of the recoverable amounts and the calculation of DD&A expense for the Upstream Segments have been developed by Management’s specialists, specifically independent qualified reserve evaluators.

The principal considerations for our determination that performing procedures relating to the impact of reserves and resource estimates on PP&E, net and any allocated goodwill of the Upstream Segments is a critical audit matter are (i) the significant amount of judgment required by Management, including the use of Management’s specialists, when developing the estimates of reserves and resources and the recoverable amounts; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates related to forward commodity prices, expected production volumes, estimated reserves and resources, future development and operating expenditures and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

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Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimates of reserves and resources, the determination of the recoverable amounts and the calculation of DD&A expense for the Upstream Segments. These procedures also included, among others, testing Management’s process for determining the recoverable amounts and DD&A expense for the Upstream Segments, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the recoverable amounts; (iii) assessing the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and resources and the recoverable amounts, related to forward commodity prices, expected production volumes, as well as future development and operating expenditures; and (iv) testing the unit-of-production rates used to calculate DD&A expense. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated reserves and resources used in the determination of the recoverable amounts and DD&A expense for the Upstream Segments. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the assumptions related to forward commodity prices, expected production volumes, as well as future development and operating expenditures involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of the recoverable amounts, including the discount rates used.

Acquisition of Husky Energy Inc. - Valuation of Acquired Oil and Gas Properties and Manufacturing Assets

As described in Notes 4, 5 and 18 to the Consolidated Financial Statements, on January 1, 2021 the Company acquired Husky Energy Inc. (“Husky”) in an acquisition accounted for as a business combination, which requires that assets acquired and liabilities assumed be measured at fair value on the acquisition date, with any excess of the purchase price over the estimated fair value of the net assets acquired recorded as goodwill. The purchase price of the transaction was for net consideration of $6.9 billion. The assets acquired included oil and gas properties and manufacturing assets categorized as PP&E which were valued at $8.5 billion and $3.9 billion, respectively. Management estimated the fair values of the acquired oil and gas properties and manufacturing assets at the acquisition date using after-tax discounted cash flow models. These fair value assessments required the use of significant estimates and judgments by Management including assumptions related to forward commodity prices, expected production volumes, estimated reserves and resources, future development and operating expenditures and discount rates for the oil and gas properties acquired and assumptions related to throughput, forward commodity prices, forward crack spreads, future capital and operating expenditures and discount rates for the manufacturing assets acquired. Management’s estimates of reserves and resources for the acquired oil and gas properties have been developed by Management’s specialists, including internal geology and engineering professionals and independent qualified reserve evaluators.

The principal considerations for our determination that performing procedures relating to the valuation of acquired oil and gas properties and manufacturing assets relating to the acquisition of Husky Energy Inc. is a critical audit matter are (i) the significant judgment by Management, including the use of Management’s specialists, as applicable, when developing the estimates of reserves and resources and the fair values of acquired oil and gas properties and manufacturing assets; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted cash flow models related to throughput, forward commodity prices, forward crack spreads, expected production volumes, estimated reserves and resources, future capital, development and operating expenditures and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimated fair values of acquired oil and gas properties and manufacturing assets. These procedures also included, among others, testing Management’s process for determining the fair values of the acquired oil and gas properties and manufacturing assets, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the fair values and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and resources and future development and operating expenditures for the acquired oil and gas properties and related to throughput, forward commodity prices, forward crack spreads and future

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capital and operating expenditures for the acquired manufacturing assets. Evaluating the assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of Husky and the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated reserves and resources used to determine the fair value of the acquired oil and gas properties. As a basis for using this work, the specialists’ qualifications were understood, and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. Evaluating the assumptions used by Management’s specialists also involved assessing whether the assumptions used were reasonable considering the current and past performance of Husky and the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the fair values of the acquired oil and gas properties and manufacturing assets determined by Management, including discount rates.

Impairment Assessment of PP&E for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing Segment

As described in Notes 1, 3, 4, 10 and 18 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated DD&A and net impairment losses, may exceed its recoverable amount. As of December 31, 2021, the Company had $3.7 billion of PP&E assets net of accumulated DD&A and net impairment losses relating to its U.S. Manufacturing segment. For the year ended December 31, 2021, the carrying amounts of the Borger, Wood River and Lima CGUs were determined to be greater than their recoverable amounts and an impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. Management determined the recoverable amounts of PP&E for the Borger, Wood River and Lima CGUs based on their fair values less costs of disposal using discounted after-tax cash flows models requiring the use of significant estimates and judgments by Management related to throughput, forward crude oil prices, forward crack spreads, future capital expenditures, operating expenses and discount rates.

The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing segment is a critical audit matter are (i) the significant amount of judgment required by Management when developing the recoverable amounts of the Borger, Wood River and Lima CGUs; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates including throughput, forward crude oil prices, forward crack spreads, future capital expenditures, operating expenses and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s determination of the recoverable amounts of the Borger, Wood River and Lima CGUs. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the Borger, Wood River and Lima CGUs, which included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii) testing the completeness and accuracy of underlying data used in these models; and (iii) assessing the reasonability of the assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital expenditures and operating expenses. Evaluating the assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the recoverable amounts of the Borger, Wood River and Lima CGUs, including the discount rates used.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Alberta, Canada

February 7, 2022

We have served as the Company’s auditor since 2008.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  87

CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

For the years ended December 31,

($ millions, except per share amounts)

	Notes		2021		2020  (1)		2019  (1)
Revenues		1
Gross Sales				48,811		13,914		21,715
Less: Royalties				2,454		371		1,173
				46,357		13,543		20,542
Expenses		1
Purchased Product				23,481		5,681		8,789
Transportation and Blending				7,883		4,728		5,184
Operating				4,716		1,955		2,088
(Gain) Loss on Risk Management		35		995		308		156
Depreciation, Depletion and Amortization		10,17,18,19		5,886		3,464		2,249
Exploration Expense		17		18		91		82
General and Administrative		6		849		292		331
Finance Costs		7		1,082		536		511
Interest Income				(23)		(9)		(12)
Integration Costs		5A		349		29		—
Foreign Exchange (Gain) Loss, Net		8		(174)		(181)		(404)
Re-measurement of Contingent Payment		24		575		(80)		164
(Gain) Loss on Divestiture of Assets		9		(229)		(81)		(2)
Other (Income) Loss, Net				(309)		40		9
(Income) Loss From Equity-Accounted Affiliates		20		(57)		—		—
Earnings (Loss) Before Income Tax				1,315		(3,230)		1,397
Income Tax Expense (Recovery)		11		728		(851)		(797)
Net Earnings (Loss)				587		(2,379)		2,194
Net Earnings (Loss) Per Common Share ($)		12
Basic				0.27		(1.94)		1.78
Diluted				0.27		(1.94)		1.78

(1) See Note 3(w) for revisions to comparative results.

See accompanying Notes to Consolidated Financial Statements.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

For the years ended December 31,

($ millions)

	Notes	2021	2020	2019
Net Earnings (Loss)		587	(2,379)	2,194
Other Comprehensive Income (Loss), Net of Tax	31
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Benefits	29	38	(8)	5
Change in the Fair Value of Equity Instruments at FVOCI (1)		—	—	12
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment		(129)	(44)	(228)
Total Other Comprehensive Income (Loss), Net of Tax		(91)	(52)	(211)
Comprehensive Income (Loss)		496	(2,431)	1,983

(1) Fair value through other comprehensive income (loss) (“FVOCI”).

See accompanying Notes to Consolidated Financial Statements.

88  |  CENOVUS ENERGY 2021 ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31,

($ millions)

	Notes		2021		2020
Assets
Current Assets
Cash and Cash Equivalents		13		2,873		378
Accounts Receivable and Accrued Revenues		14		3,870		1,488
Income Tax Receivable				22		21
Inventories		15		3,919		1,089
Assets Held for Sale		16		1,304		—
Total Current Assets				11,988		2,976
Restricted Cash		27		186		—
Exploration and Evaluation Assets, Net		1,17		720		623
Property, Plant and Equipment, Net		1,18		34,225		25,411
Right-of-Use Assets, Net		1,19		2,010		1,139
Income Tax Receivable				66		—
Investments in Equity-Accounted Affiliates		20		311		97
Other Assets		21		431		216
Deferred Income Taxes		11		694		36
Goodwill		22		3,473		2,272
Total Assets				54,104		32,770
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities		23		6,353		2,018
Short-Term Borrowings		25		79		121
Lease Liabilities		26		272		184
Contingent Payment		24		236		36
Income Tax Payable				179		—
Liabilities Related to Assets Held for Sale		16		186		—
Total Current Liabilities				7,305		2,359
Long-Term Debt		25		12,385		7,441
Lease Liabilities		26		2,685		1,573
Contingent Payment		24		—		27
Decommissioning Liabilities		27		3,906		1,248
Other Liabilities		28		929		181
Deferred Income Taxes		11		3,286		3,234
Total Liabilities				30,496		16,063
Shareholders’ Equity				23,596		16,707
Non-Controlling Interest				12		—
Total Liabilities and Equity				54,104		32,770
Commitments and Contingencies		38

See accompanying Notes to Consolidated Financial Statements.

/s/ Keith A. MacPhail	/s/ Claude Mongeau
Keith A. MacPhail	Claude Mongeau
Director	Director
Cenovus Energy Inc.	Cenovus Energy Inc.

February 7, 2022

CENOVUS ENERGY 2021 ANNUAL REPORT  |  89

CONSOLIDATED STATEMENTS OF EQUITY

($ millions)

	Shareholders’ Equity
															Non-
	Common		Preferred				Paid in		Retained		AOCI (1)				Controlling
	Shares		Shares		Warrants		Surplus		Earnings				Total		Interest
	(Note 30)		(Note 30)		(Note 30)						(Note 31)
As at December 31, 2018		11,040		—		—		4,367		1,023		1,038		17,468		—
Net Earnings (Loss)		—		—		—		—		2,194		—		2,194		—
Other Comprehensive Income (Loss), Net of Tax		—		—		—		—		—		(211)		(211)		—
Total Comprehensive Income (Loss)		—		—		—		—		2,194		(211)		1,983		—
Stock-Based Compensation Expense		—		—		—		10		—		—		10		—
Dividends on Common Shares		—		—		—		—		(260)		—		(260)		—
As at December 31, 2019		11,040		—		—		4,377		2,957		827		19,201		—
Net Earnings (Loss)		—		—		—		—		(2,379)		—		(2,379)		—
Other Comprehensive Income (Loss), Net of Tax		—		—		—		—		—		(52)		(52)		—
Total Comprehensive Income (Loss)		—		—		—		—		(2,379)		(52)		(2,431)		—
Stock-Based Compensation Expense		—		—		—		14		—		—		14		—
Dividends on Common Shares		—		—		—		—		(77)		—		(77)		—
As at December 31, 2020		11,040		—		—		4,391		501		775		16,707		—
Net Earnings (Loss)		—		—		—		—		587		—		587		—
Other Comprehensive Income (Loss), Net of Tax		—		—		—		—		—		(91)		(91)		—
Total Comprehensive Income (Loss)		—		—		—		—		587		(91)		496		—
Common Shares Issued (Note 5A)		6,111		—		—		—		—		—		6,111		—
Common Shares Issued on Exercise of Stock Options		7		—		—		(1)		—		—		6		—
Purchase of Common Shares Under NCIB (2) (Note 30)		(145)		—		—		(120)		—		—		(265)		—
Preferred Shares Issued (Note 5A)		—		519		—		—		—		—		519		—
Warrants Issued (Note 5A)		—		—		216		—		—		—		216		—
Warrants Exercised		3		—		(1)		—		—		—		2		—
Stock-Based Compensation Expense		—		—		—		14		—		—		14		—
Dividends on Common Shares		—		—		—		—		(176)		—		(176)		—
Dividends on Preferred Shares		—		—		—		—		(34)		—		(34)		—
Non-Controlling Interest		—		—		—		—		—		—		—		12
As at December 31, 2021		17,016		519		215		4,284		878		684		23,596		12

(1) Accumulated other comprehensive income (loss) (“AOCI”).

(2) Normal course issuer bid (“NCIB”).

See accompanying Notes to Consolidated Financial Statements.

90  |  CENOVUS ENERGY 2021 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,

($ millions)

	Notes		2021		2020		2019
Operating Activities
Net Earnings (Loss)				587		(2,379)		2,194
Depreciation, Depletion and Amortization		10,17,18,19		5,886		3,464		2,249
Exploration Expense		17		9		91		82
Inventory Write-Down (Reversal)				16		555		49
Realization of Inventory Write-Downs				(31)		(572)		(71)
Deferred Income Tax Expense (Recovery)		11		452		(838)		(814)
Unrealized (Gain) Loss on Risk Management		35		2		56		149
Unrealized Foreign Exchange (Gain) Loss		8		(312)		(131)		(827)
Realized Foreign Exchange (Gain) Loss on Non-Operating Items				171		(33)		401
Re-measurement of Contingent Payment, Net of Cash Paid				400		(80)		164
(Gain) Loss on Divestiture of Assets		9		(229)		(81)		(2)
Unwinding of Discount on Decommissioning Liabilities		27		199		57		58
(Income) Loss From Equity-Accounted Affiliates		20		(57)		—		—
Distributions Received From Equity-Accounted Affiliates		20		137		—		—
Other				18		8		38
Settlement of Decommissioning Liabilities				(102)		(42)		(52)
Net Change in Non-Cash Working Capital		37		(1,227)		198		(333)
Cash From (Used in) Operating Activities				5,919		273		3,285
Investing Activities
Capital Expenditures		17,18		(2,563)		(859)		(1,183)
Proceeds From Divestitures		9		435		38		1
Cash Acquired Through Business Combination		5A		735		—		—
Net Cash Received on Assumption of Decommissioning Liabilities		5B		75		—		—
Net Change in Investments and Other				17		(4)		(133)
Net Change in Non-Cash Working Capital		37		359		(38)		(117)
Cash From (Used in) Investing Activities				(942)		(863)		(1,432)
Net Cash Provided (Used) Before Financing Activities				4,977		(590)		1,853
Financing Activities		37
Net Issuance (Repayment) of Short-Term Borrowings				(77)		117		—
Issuance of Long-Term Debt				1,557		1,326		—
(Repayment) of Long-Term Debt				(2,870)		(112)		(2,279)
Net Issuance (Repayment) of Revolving Long-Term Debt				(350)		(220)		276
Principal Repayment of Leases		26		(300)		(197)		(150)
Purchase of Common Shares Under NCIB		30		(265)		—		—
Dividends Paid on Common Shares		12		(176)		(77)		(260)
Dividends Paid on Preferred Shares		12		(34)		—		—
Other				8		—		—
Cash From (Used in) Financing Activities				(2,507)		837		(2,413)
Effect of Foreign Exchange on Cash and Cash Equivalents				25		(55)		(35)
Increase (Decrease) in Cash and Cash Equivalents				2,495		192		(595)
Cash and Cash Equivalents, Beginning of Year				378		186		781
Cash and Cash Equivalents, End of Year				2,873		378		186

See accompanying Notes to Consolidated Financial Statements.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc., including its subsidiaries, (together “Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”).

Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants (“Cenovus Warrants”) are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”). Cenovus’s cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. The executive and registered office is located at 4100, 225 6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these Consolidated Financial Statements is found in Note 2.

On January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a plan of arrangement (the “Arrangement”) (see Note 5A). The transaction included Husky’s oil sands, conventional, offshore and retail segments. The transaction also included extensive transportation, storage and logistics and downstream infrastructure. Comparative figures include Cenovus’s results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.

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

Upstream Segments

• Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan. Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery points, transportation commitments and customer diversification.

• Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti, Kaybob-Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia, and interests in numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported with other third-party commodity trading volumes through access to capacity on third-party pipelines, export terminals and storage facilities which provides flexibility for market access to optimize product mix, delivery points, transportation commitments and customer diversification.

• Offshore, includes offshore operations, exploration and development activities in China and the east coast of Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.

Downstream Segments

• Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products. Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt and ancillary products.

• U.S. Manufacturing, includes the refining of crude oil to produce diesel, gasoline, jet fuel, asphalt and other products at the wholly-owned Lima Refinery and Superior Refinery, the jointly owned Wood River and Borger refineries (jointly owned with operator Phillips 66) and the jointly owned Toledo Refinery (jointly owned with operator BP Products North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum products including gasoline, diesel and jet fuel.

• Retail, includes the marketing of its own and third-party volumes of refined petroleum products, including gasoline and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.

Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and

92  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail segment.

Eliminations are recorded based on current market prices.

To conform to the presentation adopted for the current period’s operating segments, the following comparatives prior to January 1, 2021, have been reclassified:

• The Company’s market optimization activities, previously reported in the Refining and Marketing segment, have been reclassified to the Oil Sands and Conventional segments.

• The Bruderheim crude-by-rail terminal results, previously reported under the Refining and Marketing segment, have been reclassified to the Canadian Manufacturing segment.

• The refining activities in the U.S. with operator Phillips 66, previously reported in the Refining and Marketing segment, have been reclassified to the U.S. Manufacturing segment.

• The Company’s unrealized gain and loss on risk management, previously reported in Corporate and Eliminations, have been reclassified to the reportable segment to which the derivative instrument relates.

The following tabular financial information presents the segmented information first by segment, then by product and geographic location. Prior period results have been re-presented.

A) Results of Operations – Segment and Operational Information ⁽¹⁾

	Upstream
	Oil Sands								Conventional									Offshore							Total
For the years ended   December 31,	2021			2020 (2)			2019 (2)		2021			2020			2019			2021			2020		2019		2021			2020 (2)			2019 (2)
Revenues
Gross Sales		22,827			8,804			13,101		3,235			904			935			1,782			—		—		27,844			9,708			14,036
Less: Royalties (3)		2,196			331			1,143		150			40			30			108			—		—		2,454			371			1,173
		20,631			8,473			11,958		3,085			864			905			1,674			—		—		25,390			9,337			12,863
Expenses
Purchased Product (3)		3,188			1,262			2,231		1,655			268			240			—			—		—		4,843			1,530			2,471
Transportation and Blending (3)		7,841			4,683			5,152		74			81			82			15			—		—		7,930			4,764			5,234
Operating (3)		2,451			1,156			1,067		551			320			339			239			—		—		3,241			1,476			1,406
Realized (Gain) Loss on Risk Management		786			268			23		2			—			—			—			—		—		788			268			23
Operating Margin		6,365			1,104			3,485		803			195			244			1,420			—		—		8,588			1,299			3,729
Unrealized (Gain) Loss on Risk Management		18			57			92		1			—			—			—			—		—		19			57			92
Depreciation, Depletion and Amortization		2,666			1,687			1,543		3			880			319			492			—		—		3,161			2,567			1,862
Exploration Expense		16			9			18		(3	)		82			64			5			—		—		18			91			82
(Income) Loss From Equity- Accounted Affiliates		(5	)		—			—		—			—			—			(47	)		—		—		(52	)		—			—
Segment Income (Loss)		3,670			(649	)		1,832		802			(767	)		(139	)		970			—		—		5,442			(1,416	)		1,693

⁽¹⁾  Prior period results have been reclassified to conform with the current period’s operating segments.

⁽²⁾  Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities (see Note 3(w)).

⁽³⁾  Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

	Downstream
For the years ended  December 31,	Canadian Manufacturing						U.S. Manufacturing									Retail							Total
	2021		2020		2019		2021			2020			2019			2021			2020		2019		2021			2020			2019
Revenues
Gross Sales		4,472		82		77		20,043			4,733			8,291			2,158			—		—		26,673			4,815			8,368
Less: Royalties (1)		—		—		—		—			—			—			—			—		—		—			—			—
		4,472		82		77		20,043			4,733			8,291			2,158			—		—		26,673			4,815			8,368
Expenses																				—		—
Purchased Product (1)		3,552		—		—		17,955			4,429			6,735			2,019			—		—		23,526			4,429			6,735
Transportation and Blending (1)		—		—		—		—			—			—			—			—		—		—			—			—
Operating (1)		388		37		41		1,772			748			877			98			—		—		2,258			785			918
Realized (Gain) Loss on Risk Management		—		—		—		104			(21	)		(16	)		—			—		—		104			(21	)		(16	)
Operating Margin		532		45		36		212			(423	)		695			41			—		—		785			(378	)		731
Unrealized (Gain) Loss on Risk Management		—		—		—		1			(1	)		1			—			—		—		1			(1	)		1
Depreciation, Depletion and Amortization		167		8		7		2,381			728			273			59			—		—		2,607			736			280
Exploration Expense		—		—		—		—			—			—			—			—		—		—			—			—
(Income) Loss From Equity- Accounted Affiliates		—		—		—		—			—			—			—			—		—		—			—			—
Segment Income (Loss)		365		37		29		(2,170	)		(1,150	)		421			(18	)		—		—		(1,823	)		(1,113	)		450

⁽¹⁾  Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

94  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

	Corporate and Eliminations									Consolidated
For the years ended December 31,	2021			2020			2019			2021			2020 (1)			2019 (1)
Revenues
Gross Sales		(5,706	)		(609	)		(689	)		48,811			13,914			21,715
Less: Royalties (2)		—			—			—			2,454			371			1,173
		(5,706	)		(609	)		(689	)		46,357			13,543			20,542
Expenses
Purchased Product (2)		(4,888	)		(278	)		(417	)		23,481			5,681			8,789
Transportation and Blending (2)		(47	)		(36	)		(50	)		7,883			4,728			5,184
Operating (2)		(783	)		(306	)		(236	)		4,716			1,955			2,088
Realized (Gain) Loss on Risk Management		101			5			—			993			252			7
Unrealized (Gain) Loss on Risk Management		(18	)		—			56			2			56			149
Depreciation, Depletion and Amortization		118			161			107			5,886			3,464			2,249
Exploration Expense		—			—			—			18			91			82
(Income) Loss From Equity-Accounted Affiliates		(5	)		—			—			(57	)		—			—
Segment Income (Loss)		(184	)		(155	)		(149	)		3,435			(2,684	)		1,994
General and Administrative		849			292			331			849			292			331
Finance Costs		1,082			536			511			1,082			536			511
Interest Income		(23	)		(9	)		(12	)		(23	)		(9	)		(12	)
Integration Costs		349			29			—			349			29			—
Foreign Exchange (Gain) Loss, Net		(174	)		(181	)		(404	)		(174	)		(181	)		(404	)
Re-measurement of Contingent Payment		575			(80	)		164			575			(80	)		164
(Gain) Loss on Divestiture of Assets		(229	)		(81	)		(2	)		(229	)		(81	)		(2	)
Other (Income) Loss, Net		(309	)		40			9			(309	)		40			9
		2,120			546			597			2,120			546			597
Earnings (Loss) Before Income Tax											1,315			(3,230	)		1,397
Income Tax Expense (Recovery)											728			(851	)		(797	)
Net Earnings (Loss)											587			(2,379	)		2,194

⁽¹⁾ Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities (see Note 3(w)).

⁽²⁾ Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) Revenues by Product ⁽¹⁾

For the years ended December 31,	2021			2020			2019
Upstream (2)
Crude Oil		19,051			8,557			12,091
NGLs		2,809			186			227
Natural Gas		3,032			535			480
Other		498			58			65
Downstream
Canadian Manufacturing
Synthetic Crude Oil		1,951			—			—
Diesel and Distillate		407			—			—
Asphalt		477			—			—
Other Products and Services		1,637			82			77
U.S. Manufacturing
Gasoline		10,111			2,352			3,880
Diesel and Distillate		6,429			1,569			3,127
Other Products		3,503			813			1,284
Retail		2,158			—			—
Corporate and Eliminations		(5,706	)		(609	)		(689	)
Consolidated		46,357			13,543			20,542

⁽¹⁾ Prior period results have been reclassified to conform with the current period’s operating segments.

⁽²⁾  Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities (see Note 3(w)).

C) Geographical Information

			Revenues (1)
For the years ended December 31,	2021		2020		2019
Canada (2)		23,768		8,715		12,160
United States		21,326		4,828		8,382
China		1,263		—		—
Consolidated		46,357		13,543		20,542

⁽¹⁾  Revenues by country are classified based on where the operations are located.

⁽²⁾  Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities (see Note 3(w)).

	Non-Current Assets (1)
As at December 31,	2021		2020
Canada (2)		33,915		26,041
United States		4,093		3,590
China		2,583		—
Indonesia		311		—
Consolidated		40,902		29,631

⁽¹⁾  Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill.

⁽²⁾  Excludes assets of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional segment that have been reclassified as held for sale in current assets.

Major Customers

In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and downstream products for the year ended December 31, 2021, Cenovus had two customers (2020 – three; 2019 – two) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $8.5 billion and $6.8 billion, respectively (2020 – $4.3 billion, $1.8 billion and $1.5 billion; 2019 – $6.9 billion and $2.3 billion) and are reported across all of the Company’s operating segments.

96  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

D) Assets by Segment ⁽¹⁾

	E&E Assets				PP&E				ROU Assets
As at December 31,	2021		2020		2021		2020		2021		2020
Oil Sands		653		617		22,535		19,748		754		196
Conventional		6		6		2,174		1,758		2		3
Offshore		61		—		2,822		—		160		—
Canadian Manufacturing		—		—		2,353		176		339		392
U.S. Manufacturing		—		—		3,745		3,476		252		114
Retail		—		—		205		—		49		—
Corporate and Eliminations		—		—		391		253		454		434
Consolidated		720		623		34,225		25,411		2,010		1,139
					Goodwill				Total Assets
As at December 31,					2021		2020		2021		2020
Oil Sands (2)						3,473		2,272		31,070		24,641
Conventional (2)						—		—		3,026		1,978
Offshore						—		—		3,597		—
Canadian Manufacturing						—		—		2,918		578
U.S. Manufacturing						—		—		7,777		4,363
Retail (2)						—		—		966		—
Corporate and Eliminations						—		—		4,750		1,210
Consolidated						3,473		2,272		54,104		32,770

⁽¹⁾  Prior period results have been reclassified to conform with the current period’s operating segments.

⁽²⁾  Total assets include assets held for sale of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional segment.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  97

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

E) Capital Expenditures ^{(1) (2)}

For the years ended December 31,	2021		2020		2019
Capital Investment
Oil Sands		1,019		427		656
Conventional		222		78		103
Offshore
Asia Pacific		21		—		—
Atlantic		154		—		—
Total Upstream		1,416		505		759
Canadian Manufacturing		37		33		52
U.S. Manufacturing		995		243		228
Retail		31		—		—
Total Downstream		1,063		276		280
Corporate and Eliminations		84		60		137
		2,563		841		1,176
Acquisition Capital
Oil Sands		3		6		2
Conventional		4		12		7
Canadian Manufacturing		—		—		4
		7		18		13
Acquisitions (Note 5)
Oil Sands		5,002		—		—
Conventional		547		—		—
Offshore		3,129		—		—
Canadian Manufacturing		2,283		—		—
U.S. Manufacturing		1,618		—		—
Retail		690		—		—
Corporate and Eliminations		156		—		—
		13,425		—		—
Total Capital Expenditures		15,995		859		1,189

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

(2) Prior period results have been reclassified to conform with the current period’s operating segments.

98  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE

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

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee.

Certain information provided for prior years has been reclassified to conform to the presentation adopted for the year ended December 31, 2021.

These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the Company’s accounting policies disclosed in Note 3.

These Consolidated Financial Statements were approved by the Board of Directors effective February 7, 2022.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) Principles of Consolidation

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company’s accounts reflect its share of the assets, liabilities, revenues and expenses from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s activities relate to joint ventures, which are accounted for using the equity method of accounting.

An associate is an entity for which the Company has significant influence over but does not control or jointly control the affiliate. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter to recognize the Company’s share of the affiliate’s profit or loss and other comprehensive income (“OCI”).

B) Foreign Currency Translation

Functional and Presentation Currency

The Company’s functional and presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period-end exchange rates for assets and liabilities, and using average rates over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in OCI as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses accumulated in OCI is allocated between controlling and non-controlling interests.

Transactions and Balances

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings (Loss).

C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from the Company to its customer.

Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are provided.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  99

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Cenovus recognizes revenue from the following major products and services:

• Sale of crude oil, NGLs and natural gas.

• Sale of petroleum and refined products.

• Crude oil and natural gas processing services.

• Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.

• Fee-for-service hydrocarbon trans-loading services.

• Construction services.

The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs, natural gas, and petroleum and refined products, which is generally at a point in time. Performance obligations for crude oil and natural gas processing revenue, transportation services and trans-loading services are satisfied over time as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas, and petroleum and refined products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. Revenue associated with natural gas processing, transportation services and trans-loading services are generally based on fixed price contracts.

Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and revenue from cost-plus contracts are recognized as services are performed.

The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date, the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered or the deferral provision can no longer be extended.

Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component when the period between the transfer of the promised goods or services to the customer and payment by the customer is less than one year. The Company does not disclose or quantify information about remaining performance obligations that have an original expected duration of one year or less and it does not have any long-term contracts with the exception of certain construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.

D) Transportation and Blending

The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending, are recognized when the product is sold.

E) Exploration Expense

Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are incurred as exploration expense.

Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/ project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.

F) Employee Benefit Plans

The Company provides employees with a pension plan that includes either a defined contribution or defined benefit component.

Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans, benefits are not funded before retirement.

Pension expense for the defined contribution pension is recorded as the benefits are earned.

The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans.

100  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:

• Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs.

• Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.

• Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling (excluding interest) and the return on plan assets (excluding interest income), are charged or credited to equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in subsequent periods.

Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E assets, corresponding to where the associated salaries of the employees rendering the service are recorded.

From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a one-time incentive program was introduced whereby a cash award equivalent to the employee’s base salary was payable if Cenovus achieved, prior to February 12, 2024, a target share price of $20 per share for a period of 20 consecutive trading days on the TSX (the “Plan”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is recognized as general and administrative expense over the estimated time until payout is achieved.

G) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the services have been performed.

H) Income Taxes

Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the Consolidated Balance Sheet date.

Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI, respectively.

Deferred income tax is recognized on temporary differences arising from investments in subsidiaries except in the case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable that the temporary difference will not reverse in the foreseeable future or when distributions can be made without incurring income taxes.

Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

I) Related Party Transactions

The Company enters into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value. Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  101

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

J) Net Earnings per Share Amounts

Basic net earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to purchase common shares at the average market price. For those contracts that may be settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

K) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a maturity of three months or less. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans.

Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset.

L) Inventories

Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory is still on hand.

M) Exploration and Evaluation Assets

Certain costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and commercial viability of the field/project/area have been established, are capitalized as E&E assets. E&E assets are carried forward until technical feasibility and commercial viability of the field/project/area is established or the assets are determined to be impaired or the future economic value has decreased. E&E assets are subject to regular technical, commercial and Management review to confirm the continued intent to develop the resources.

Assets classified as E&E may have sales of crude oil, NGLs or natural gas prior to the reclassification to PP&E. These operating results are recognized in the Consolidated Statements of Earnings (Loss). A depletion charge, recorded as depreciation, depletion and amortization (“DD&A”), is recognized on this production using a unit-of-production method based on estimated proved reserves determined using forward prices and costs and considering any estimated future costs to be incurred in developing the proved reserves. Natural gas reserves are converted on an energy equivalent basis.

Non-producing assets classified as E&E are not depleted.

Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

N) Property, Plant and Equipment

General

PP&E is stated at cost less accumulated DD&A, and net of any impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.

Any gains or losses from the divestiture of PP&E are recognized in net earnings.

Crude Oil and Natural Gas Properties

Development and production assets are capitalized on an area-by-area basis and include all costs associated with the development and production of crude oil and natural gas properties and related infrastructure facilities, as well as any E&E expenditures incurred in finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.

102  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations, natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to be incurred in developing those reserves.

Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance or the fair value of either the asset received, or the asset given up, cannot be reliably measured. When fair value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.

Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and natural gas properties are depleted using a unit-of-production method.

Manufacturing Assets

The initial costs of refining and upgrading PP&E are capitalized when incurred. Costs include the cost of constructing or otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended use, the associated decommissioning costs and, for qualifying assets, borrowing costs.

Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the refinery. The major components are depreciated as follows:

• Land improvements and buildings: 15 to 40 years.

• Office improvements and buildings: 3 to 15 years.

• Refining equipment: 10 to 60 years.

The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a prospective basis, if appropriate.

Processing, Transportation and Storage Assets, Retail and Other

Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets, which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available for use by the Company.

The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a prospective basis, if appropriate.

O) Impairment and Impairment Reversals of Non-Financial Assets

PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.

If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. For Cenovus’s upstream assets, FVLCOD is estimated based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), costs to develop and the discount rate, and may consider an evaluation of comparable asset transactions.

E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill is allocated to the CGUs to which it contributes to the future cash flows.

If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  103

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net earnings.

P) Leases

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company has elected not to separate non-lease components.

As Lessee

Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, costs to be incurred by the lessee in dismantling, removing and restoring the underlying asset, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with reasonably similar characteristics.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company.

When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date.

The ROU asset is depreciated, on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or using the unit-of-production method. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment losses.

Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating, transportation or general and administrative expense.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will remeasure the lease liability using the Company’s incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

As Lessor

As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments received under operating leases as income on a straight-line basis over the lease term as other income.

104  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the sublease is classified as an operating lease.

Q) Intangible Assets

Intangible assets acquired separately are initially measured at cost. Following initial recognition, intangible assets are recognized at cost less any accumulated amortization and accumulated impairment losses. Intangible assets with finite lives are amortized over the useful life and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets is recognized in the Consolidated Statements of Earnings (Loss) in the expense category consistent with the function of the intangible asset.

R) Business Combinations and Goodwill

Business combinations are accounted for using the acquisition method of accounting in which the identifiable assets acquired, liabilities assumed and non-controlling interest, if any, are recognized and measured at their fair value at the date of acquisition, with the exception of income taxes, stock-based compensation, lease liabilities and ROU assets. Any excess of the purchase price plus any non-controlling interest over the value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the value of the net assets acquired is credited to net earnings. Acquisition costs are expensed as incurred.

At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less any accumulated impairment losses.

Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition and classified as a financial liability or equity in accordance with the terms of the agreement. Contingent consideration classified as a liability is re-measured at fair value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability. Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities. Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.

When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.

S) Provisions

General

A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive, that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the Consolidated Statements of Earnings (Loss).

Decommissioning Liabilities

Decommissioning liabilities include those legal or constructive obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, upstream processing facilities, surface and subsea plant and equipment, refining facilities and the crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting from revisions to expected timing or future decommissioning costs are recognized as a change in the decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the useful life of the related asset.

Actual expenditures incurred are charged against the accumulated liability.

Onerous Contract Provisions

Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of Earnings (Loss).

CENOVUS ENERGY 2021 ANNUAL REPORT  |  105

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

T) Share Capital and Warrants

Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s paid in surplus. Common shares are cancelled subsequent to being purchased.

Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are recorded as share capital.

U) Stock-Based Compensation

Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights (“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.

Stock Options With Associated Net Settlement Rights

NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-based compensation over the vesting period, with a corresponding increase recorded as paid in surplus in shareholders’ equity. On exercise, the cash consideration received by the Company and the associated paid in surplus are recorded as share capital.

Cenovus Replacement Stock Options

Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are settled for common shares, the cash consideration received by the Company and the previously recorded liability associated with the stock option is recorded as share capital.

Performance, Restricted and Deferred Share Units

PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.

V) Financial Instruments

The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets, net investment in finance leases, investments in the equity of companies and long-term receivables. The Company’s financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payment, risk management liabilities and long-term debt.

Financial instruments are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously.

The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

• Level 1 inputs are quoted prices in active markets for identical assets and liabilities.

• Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly.

• Level 3 inputs are unobservable inputs for the asset or liability.

106  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Classification and Measurement of Financial Assets

The initial classification of a financial asset depends upon the Company’s business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Company classified its financial assets:

• Amortized Cost: Includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

• FVOCI: Includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest.

• Fair Value through Profit or Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial assets.

On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes to earnings following the derecognition of the investment. However, dividends that reflect a return on investment continue to be recognized in net earnings. This election is made on an investment-by-investment basis.

At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset. Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.

Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been transferred and the Company has transferred substantially all the risks and rewards of ownership.

Impairment of Financial Assets

The Company recognizes loss allowances for expected credit losses (“ECLs”) on its financial assets measured at amortized cost. Due to the nature of its financial assets, Cenovus measures loss allowances at an amount equal to expected lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e. the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Company expects to receive). ECLs are discounted at the effective interest rate of the related financial asset. The Company does not have any financial assets that contain a financing component.

Classification and Measurement of Financial Liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The classification of a financial liability is irrevocable.

Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are initially measured at fair value less directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.

A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial liability is replaced by another from the same counterparty with substantially different terms, or the terms of an existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows and a gain or loss is recorded in net earnings.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  107

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Derivatives

Derivative financial instruments are primarily used to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.

Derivative financial instruments are measured at FVTPL unless designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a gain or loss on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party market indications and forecasts.

W) Adjustments to the Consolidated Statements of Earnings (Loss)

Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment, has been revised. During the three months ended December 31, 2021, the Company made adjustments to more appropriately record certain third-party purchases used for blending and optimization activities. A portion of third-party purchases and sales were previously recorded on a net basis in gross sales. It was determined that the purchases were more appropriately reported as purchased product. These amounts have now been re-presented as purchased product to be consistent with similar transactions. In addition, the Company identified the inconsistent treatment of product swaps, which were being recorded appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses on product swaps will be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing revenues and purchased product, with no impact to net earnings (loss), segment income (loss), cash flows or financial position.

The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts:

2020 and 2019 Revisions to the Oil Sands Segment

	2020						2019
	Previously						Previously
For the years ended December 31,	Reported		Revision		Revised		Reported		Revision		Revised
Gross Sales		8,481		323		8,804		12,739		362		13,101
Purchased Product		939		323		1,262		1,869		362		2,231
		7,542		—		7,542		10,870		—		10,870

X) Recent Accounting Pronouncements

New Accounting Standards and Interpretations not yet Adopted

There are new accounting standards, amendments to accounting standards and interpretations that are effective for annual periods beginning on or after January 1, 2022, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements.

4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

A) 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 the Company’s Consolidated Financial Statements.

108  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Joint Arrangements

The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint operations held by the Company are as follows:

• 50 percent interest in WRB Refining LP (“WRB”).

• 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).

• 50 percent interest in BP-Husky Refining LLC (“Toledo”).

It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB, Sunrise and Toledo. As a result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.

In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the following:

• The original intention of the joint arrangements was to form an integrated North American heavy oil business. Partnerships are “flow-through” entities.

• The agreements require the partners to make contributions if funds are insufficient to meet the obligations or liabilities of the corporation and partnerships. The past and future development of WRB, Sunrise and Toledo is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.

• WRB and Sunrise have third-party debt facilities to cover short-term working capital requirements.

• Sunrise is operated like most typical western Canadian working interest relationships where the operating partner takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very similar structures modified to account for the operating environment of the refining business.

• Cenovus, Phillips 66 and BP, as operators, either directly or through wholly-owned subsidiaries, provide marketing services, purchase necessary feedstock, and arrange for transportation and storage, on the partners’ behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangements do not have employees and, as such, are not capable of performing these roles.

• In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic benefits of the assets and the obligation for funding the liabilities of the arrangements.

Exploration and Evaluation Assets

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are considered, including the existence of reserves, and whether the appropriate approvals have been received from regulatory bodies and the Company’s internal approval process.

Identification of Cash-Generating Units

CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure, and the manner in which Management monitors and makes decisions about its operations. The recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses and impairment reversals.

Recoveries from Insurance Claims

The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to be received. Accordingly, actual results may differ from these estimated recoveries.

Functional Currency

The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the primary economic environment in which the subsidiary operates.

Fair Value of Related Party Transactions

The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such relationships can have an effect on the financial results of the Company and may lead to differences in the transactions between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be obtained to confirm the estimated fair value of proceeds.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) 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. The following are the key assumptions about the future and other key sources of estimation at the end of the reporting period that, if changed, could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus (“COVID-19”). The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by Management in the preparation of its financial results.

The outbreak and current market conditions have increased the complexity of estimates and assumptions used to prepare the annual Consolidated Financial Statements, particularly related to recoverable amounts.

In addition, the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels could change assumptions used to determine the recoverable amount of the Company’s PP&E and E&E assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects, may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for energy.

Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year.

Crude Oil and Natural Gas Reserves

There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the reserves estimates which would affect the impairment test recoverable amount and DD&A expense of the Company’s crude oil and natural gas assets in the Oil Sands, Conventional and Offshore segments. The Company’s reserves are evaluated annually and reported to the Company by its IQREs.

Recoverable Amounts

Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions, which are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Recoverable amounts for the Company’s manufacturing assets, crude-by-rail terminal and related ROU assets use assumptions such as throughput, forward commodity prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Recoverable amounts for the Company’s real estate ROU assets use assumptions such as real estate market conditions which includes market vacancy rates and sublease market conditions, price per square footage, real estate space availability and borrowing costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets.

110  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence of liabilities and estimate the future value. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors.

Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination

The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are applied for measuring fair value including market comparables and discounted cash flows. For the Company’s upstream assets, key assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal geology and engineering professionals and independent qualified reserve engineers. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, forward market crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.

Income Tax Provisions

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty.

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

5. ACQUISITIONS

A) Husky

i) Summary of the Acquisition

On October 25, 2020, Cenovus announced that it had entered into a definitive agreement to combine with Husky. The transaction was accomplished through the Arrangement pursuant to which Cenovus acquired all the issued and outstanding common shares of Husky in exchange for common shares and Cenovus Warrants. In addition, all of the issued and outstanding Husky preferred shares were exchanged for Cenovus preferred shares with substantially identical terms. The Arrangement closed on January 1, 2021.

The Arrangement combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics infrastructure, and downstream assets, which creates opportunities to optimize the margin captured across the heavy oil value chain. With the combination of processing capacity and market access outside Alberta for the majority of the Company’s oil sands and heavy oil production, exposure to Alberta heavy oil price differentials is reduced while maintaining exposure to global commodity prices.

The Arrangement was accounted for using the acquisition method pursuant to IFRS 3, “Business Combinations”. Under the acquisition method, assets and liabilities are measured at their estimated fair value on the date of acquisition with the exception of income tax, stock-based compensation, lease liabilities and ROU assets. The total consideration was allocated to the tangible and intangible assets acquired and liabilities assumed, with any excess recorded as goodwill.

ii) Purchase Price Allocation

Cenovus acquired all the issued and outstanding Husky common shares in consideration for the issuance of 0.7845 Cenovus common shares plus 0.0651 Cenovus Warrants for each Husky common share. Cenovus issued 788.5 million Cenovus common shares with a fair value of $6.1 billion, based on the December 31, 2020, closing share price of $7.75, as reported on the TSX. In addition, 65.4 million Cenovus Warrants were issued. Each whole warrant entitles the holder to acquire one Cenovus common share for a period of five years at an exercise price of $6.54 per share. The fair value of the warrants was estimated to be $216 million. Cenovus also acquired all the issued and outstanding Husky preferred shares in exchange for 36.0 million Cenovus first preferred shares with substantially identical terms and a fair value of $519 million. The outstanding Husky stock options were also exchanged for Cenovus replacement stock options. Each replacement stock option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845. The fair value of the replacement stock options was estimated to be $9 million. Cenovus also recognized the one percent non-controlling interest of Husky Energy Inc. in Husky Canada Group Finance Ltd., which had an estimated fair value of $11 million.

The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, new information obtained about the conditions that existed at the date of the Arrangement and a better understanding of the assets acquired between January 1, 2021 and December 31, 2021. Changes to identifiable assets acquired and liabilities assumed includes increases of $24 million to accounts receivable and accrued revenues, $45 million to E&E assets, $32 million to other assets, $18 million to accounts payable and accrued liabilities, $137 million to decommissioning liabilities and $37 million to other liabilities offset by decreases of $136 million to long-term income tax receivable, $365 million to PP&E, $94 million to investment in equity-accounted affiliates and $6 million to income tax payable. These adjustments resulted in an increase to the deferred income tax asset, net of $120 million. Total identifiable net assets decreased by $560 million, increasing goodwill by $577 million. The impact to DD&A, income (loss) from equity-accounted affiliates, interest income and general and administrative expense as a result of these adjustments was not material and prior quarters have not been restated to reflect the impact of the measurement period adjustments.

112  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

The following table summarizes the details of the consideration and the recognized amounts of assets acquired and liabilities assumed at the date of the acquisition.

As at	January 1, 2021
Consideration
Common Shares		6,111
Preferred Shares		519
Share Purchase Warrants		216
Replacement Stock Options		9
Other		17
Non-Controlling Interest		11
Total Consideration and Non-Controlling Interest		6,883
Identifiable Assets Acquired and Liabilities Assumed
Cash		735
Restricted Cash		164
Accounts Receivable and Accrued Revenues		1,307
Inventories		1,133
Exploration and Evaluation Assets		45
Property, Plant and Equipment		13,296
Right-of-Use Assets		1,132
Long-Term Income Tax Receivable		66
Other Assets		230
Investment in Equity-Accounted Affiliates		363
Deferred Income Tax Assets, Net		1,062
Accounts Payable and Accrued Liabilities		(2,283)
Income Tax Payable		(94)
Short-Term Borrowings		(40)
Long-Term Debt		(6,602)
Lease Liabilities		(1,441)
Decommissioning Liabilities		(2,697)
Other Liabilities		(782)
Total Identifiable Net Assets		5,594
Goodwill		1,289

The fair value of trade and other receivables acquired as part of the acquisition was $1.1 billion, with a gross contractual amount of $1.2 billion. As of the acquisition date, the best estimate of the contractual cash flows not expected to be collected was $45 million.

Goodwill was recognized due to the appreciation of Cenovus’s common share price at the close of the acquisition. Goodwill of $1.3 billion was attributable to the Lloydminster thermal ($651 million), Sunrise ($550 million) and Tucker ($88 million) assets, within the Oil Sands segment, where significant operating synergies are expected to be achieved.

iii) Integration Costs

Transaction costs from the Arrangement exclude share issuance costs related to common shares, preferred shares and warrants. Integration costs recognized in the Consolidated Statements of Earnings (Loss) include the following:

For the year ended December 31, 2021
Transaction Costs	65
Integration Related Costs	104
Severance Payments	180
	349

CENOVUS ENERGY 2021 ANNUAL REPORT  |  113

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

iv) Revenue and Profit Contribution

The acquired business contributed revenues of $21.2 billion, as well as consolidated segment income of $2.0 billion, for the year ended December 31, 2021.

B) Other

On September 8, 2021, the Company acquired an additional working interest of 21 percent of the Terra Nova field in Atlantic Canada. Cenovus’s working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed decommissioning liabilities of $159 million.

6. GENERAL AND ADMINISTRATIVE

For the years ended December 31,	2021		2020		2019
Salaries and Benefits		264		145		143
Administrative and Other		225		102		90
Stock-Based Compensation Expense (Recovery) (Note 32)		159		49		67
Other Incentive Benefits Expense (Recovery)		201		(4)		31
		849		292		331

7. FINANCE COSTS

For the years ended December 31,	2021		2020		2019
Interest Expense – Short-Term Borrowings and Long-Term Debt		557		392		407
Net Premium (Discount) on Redemption of Long-Term Debt (Note 25)		121		(25)		(63)
Interest Expense – Lease Liabilities (Note 26)		171		87		82
Unwinding of Discount on Decommissioning Liabilities (Note 27)		199		57		58
Other		34		25		27
		1,082		536		511

8. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,	2021		2020		2019
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada		(230)		(194)		(800)
Other		(82)		63		(27)
Unrealized Foreign Exchange (Gain) Loss		(312)		(131)		(827)
Realized Foreign Exchange (Gain) Loss		138		(50)		423
		(174)		(181)		(404)

9. DIVESTITURES

On October 14, 2021, the Company sold 50 million common shares of Headwater Exploration Inc. (“Headwater”) for gross proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million). Effective May 1, 2021, the Company sold its GORR in the Marten Hills area of Alberta relating to the Conventional segment. Cenovus received cash proceeds of $102 million and recorded a before-tax gain of $60 million (after-tax gain – $47 million). In 2021, the Company sold Conventional segment assets in the Kaybob area and East Clearwater area for combined gross proceeds of approximately $103 million. For the year ended December 31, 2021, a before-tax gain of $34 million (after-tax gain – $25 million) was recorded on the dispositions.

114  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to Headwater for total consideration of $138 million, excluding the retained GORR. A before-tax gain of $79 million was recorded on the sale (after-tax gain – $65 million). Total consideration was $33 million in cash, 50 million common shares valued at $97 million and 15 million share purchase warrants valued at $8 million at the date of close.

10. IMPAIRMENT CHARGES AND REVERSALS

On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed its recoverable amount. Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. Goodwill is tested for impairment at least annually.

A) Upstream Cash-Generating Units

As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates.

2021 Impairment Reversals

As at December 31, 2021, there were indicators of impairment reversals for the Company’s upstream CGUs due to an increase in forward commodity prices. An assessment was performed and indicated the recoverable amount was greater than the carrying value.

As at December 31, 2021, the recoverable amount of the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs was estimated to be $2.0 billion. In 2020, the Company recorded a total impairment charge of $555 million in the Conventional segment due to a decline in forward commodity prices and changes in future development plans. As at December 31, 2021, the Company reversed the full amount of impairment losses of $378 million, net of dispositions and the DD&A that would have been recorded had no impairment been recorded. The reversal was primarily due to improved forward commodity prices.

The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31, 2021, by CGU:

	Reversal of		Recoverable
Cash-Generating Unit	Impairment		Amount
Clearwater		145		427
Elmworth-Wapiti		115		747
Kaybob-Edson		118		837

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves include forward prices and costs, consistent with Cenovus’s independent IQREs, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2021. All reserves have been evaluated as at December 31, 2021, by the Company’s IQREs.

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

											Average
											Annual
											Increase
	2022		2023		2024		2025		2026		Thereafter
West Texas Intermediate (US$/barrel)		72.83		68.78		66.76		68.09		69.45		2.00 %
Western Canadian Select (C$/barrel)		74.43		69.17		66.54		67.87		69.23		2.00 %
Edmonton C5+ (C$/barrel)		91.85		85.53		82.98		84.63		86.33		2.00 %
Alberta Energy Company Natural Gas (C$/Mcf) (1)		3.56		3.20		3.05		3.10		3.17		2.00 %

(1)    Assumes gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).

CENOVUS ENERGY 2021 ANNUAL REPORT  |  115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Discount and Inflation Rates

Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at approximately two percent.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at December 31, 2021, for the following CGUs:

	Increase (Decrease) to Recoverable Amount (1)
Cash-Generating Unit	One Percent   Increase in   the Discount   Rate		One Percent   Decrease in   the Discount   Rate		Five Percent   Increase in   the Forward   Price   Estimates		Five Percent   Decrease in   the Forward   Price   Estimates
Clearwater		(13)		13		55		(54)
Elmworth-Wapiti		(27)		28		84		(81)
Kaybob-Edson		(26)		26		98		(97)

(1) The Company reversed the full amount of impairment losses at December 31, 2021. The changes to the recoverable amount noted in the sensitivities above would not have resulted in a change in the amount of the impairment reversal.

2020 Impairments

During the three months ended March 31, 2020, the Company tested its upstream CGUs and CGUs with associated goodwill for impairment. As a result, the Company recorded an impairment loss of $315 million as additional DD&A in the Conventional segment due to the decline in forward crude oil and natural gas prices. As at March 31, 2020, there was no impairment of goodwill or Oil Sands CGUs.

As at December 31, 2020, indicators of impairment were noted for the Company’s Conventional assets due to a change in future development plans since the Company last tested for impairment as at March 31, 2020. Therefore, the Company tested its Conventional CGUs for impairment and determined that the carrying amount was greater than the recoverable amount for certain CGUs and recorded an additional impairment loss of $240 million as additional DD&A.

The following table summarizes impairment reversals recorded in 2020 and estimated recoverable amounts as at December 31, 2020, by CGU:

Cash-Generating Unit	Impairment		Recoverable   Amount
Clearwater		260		160
Elmworth-Wapiti		120		259
Kaybob-Edson		175		384

Key Assumptions

The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates at December 31, 2020. All reserves were evaluated as at December 31, 2020, by the Company’s IQREs.

116  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Crude Oil, NGLs and Natural Gas Prices

The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves were:

	2021	2022	2023	2024	2025	Average     Annual     Increase     Thereafter
West Texas Intermediate (US$/barrel)	47.17	50.17	53.17	54.97	56.07		2.00	%
Western Canadian Select (C$/barrel)	44.63	48.18	52.10	54.10	55.19		2.00	%
Edmonton C5+ (C$/barrel)	59.24	63.19	67.34	69.77	71.18		2.00	%
Alberta Energy Company Natural Gas (C$/Mcf) (1)	2.88	2.80	2.71	2.75	2.80		2.00	%

(1) Assumes gas heating value of one million British thermal units per Mcf.

Discount and Inflation Rates

Discounted future cash flows were determined by applying a discount rate between 10 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Inflation was estimated at approximately two percent.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at December 31, 2020 for the following CGUs:

	Increase (Decrease) to Recoverable Amount
	One Percent       Increase in       Discount Rate			One Percent       Decrease in            Discount Rate		Five Percent           Increase in the        Forward Price       Estimates		Five Percent        Decrease in the    Forward Price     Estimates
Clearwater		(5	)		6		52		(97)
Elmworth-Wapiti		(7	)		8		54		(96)
Kaybob-Edson		(13	)		14		54		(106)

As at December 31, 2020, there was no impairment of goodwill.

2019 Impairments

As at December 31, 2019, the Company tested its Conventional CGUs for impairment as there were indicators of impairment due to a decline in forward natural gas prices. As at December 31, 2019, there were no impairments of goodwill or the Company’s CGUs.

B) Downstream Cash-Generating Units

2021 Impairments

As at December 31, 2021, lower forward pricing that will result in lower margins on refined products, was identified as an indicator of impairment for the Borger, Wood River, Lima and Toledo CGUs. As at December 31, 2021, the total carrying amounts of the Borger, Wood River and Lima CGUs were greater than the recoverable amount ($2.5 billion) and an impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, no impairment of the Toledo CGU was recorded.

Key Assumptions

The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, operating costs and the discount rates. Forward crack spreads were based on third-party consultant average forecasts.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021, the forward prices used to determine future cash flows were:

	2022 to 2023				2024 to 2026
	Low		High		Low		High
West Texas Intermediate (US$/barrel)		68.78		72.83		66.76		69.45
Differential WTI-WTS (US$/barrel)		—		0.01		(0.06)		(0.06)
Differential WTI-WCS (US$/barrel)		13.54		13.67		13.75		14.30
Chicago 3-2-1 Crack Spreads (WTI) (US$/barrel)		14.87		18.44		14.68		16.81
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)		15.33		18.97		14.82		16.98

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent to 12 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the following CGUs:

	Increase (Decrease) to Recoverable Amount
	One Percent Increase in Discount Rate		One Percent Decrease in Discount Rate		Five Percent Increase in the Forward Price Estimates		Five Percent   Decrease in the   Forward Price   Estimates
Borger, Wood River and Lima CGUs		(190)		214		749		(754)

2021 ROU Asset Impairments

As at December 31, 2021, lower forward pricing, which will result in lower margins on refined products was identified as an indicator of impairment for the U.S. Manufacturing ROU assets. As a result, these assets were tested for impairment and an impairment charge of $11 million was recorded as additional DD&A in the U.S. Manufacturing segment.

2020 Downstream Impairments

As at September 30, 2020, the recovery in demand for refined products from the impact of the novel coronavirus lagged expectations and resulted in higher than anticipated inventory levels. These factors, along with low market crack spreads and crude oil processing runs for North American refineries, were identified as indicators of impairment for the Wood River and Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was greater than the recoverable amount and an impairment charge of $450 million was recorded as additional DD&A in the U.S. Manufacturing segment. The recoverable amount of the Borger CGU was estimated at $692 million. As at September 30, 2020, no impairment of the Wood River CGU was identified. As at December 31, 2020, there were no further indicators of impairment noted.

Key Assumptions

The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, terminal values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts.

118  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Crude Oil and Forward Crack Spreads

Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were:

	2021 to 2022				2023 to 2025
	Low		High		Low		High
West Texas Intermediate (US$/barrel)		36.36		50.84		49.66		58.74
Differential WTI-WTS (US$/barrel)		0.37		1.73		1.21		1.81
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)		11.56		13.23		11.79		16.58

Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.

Discount Rates

Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors.

Sensitivities

The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated recoverable amount used in the impairment testing completed as at September 30, 2020 for the following CGU:

	Increase (Decrease) to Recoverable Amount
					Five Percent		Five Percent
	One Percent		One Percent		Increase in the		Decrease in the
	Increase in		Decrease in		Forward Price		Forward Price
	Discount Rate		Discount Rate		Estimates		Estimates
Borger		(71)		81		263		(264)

2020 ROU Asset Impairments

As at March 31, 2020, the temporary suspension of the Company’s crude-by-rail program was considered to be an indicator of impairment for the railcar CGU. As a result, the CGU was tested for impairment and an impairment charge of $3 million was recorded as additional DD&A in the U.S. Manufacturing segment.

11. INCOME TAXES

The provision for income taxes is:

For the years ended December 31,	2021		2020		2019
Current Tax
Canada		104		(14)		14
United States		—		1		3
Asia Pacific		171		—		—
Other International		1		—		—
Total Current Tax Expense (Recovery)		276		(13)		17
Deferred Tax Expense (Recovery)		452		(838)		(814)
		728		(851)		(797)

In 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared to 2020. In the fourth quarter of 2021, the Company recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with provincial allocations.

In 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairments in the Conventional segment and current period operating losses that will be carried forward, excluding unrealized foreign exchange gains and losses on long-term debt. In 2020, the Government of Alberta accelerated the reduction in the provincial corporate tax rate from 12 percent to eight percent.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  119

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to eight percent over four years. As a result, the Company recorded a deferred income tax recovery of $671 million for the year ended December 31, 2019. In addition, the Company recorded a deferred income tax recovery of $387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis of the Company’s refining assets.

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

For the years ended December 31,	2021		2020		2019
Earnings (Loss) From Operations Before Income Tax		1,315		(3,230)		1,397
Canadian Statutory Rate		23.7%		24.0%		26.5%
Expected Income Tax Expense (Recovery) From Operations		312		(775)		370
Effect on Taxes Resulting From:
Statutory and Other Rate Differences		3		19		(52)
Non-Taxable Capital (Gains) Losses		63		(42)		(38)
Non-Recognition of Capital (Gains) Losses		27		(42)		(39)
Adjustments Arising From Prior Year Tax Filings		(5)		(8)		4
Recognition of U.S. Tax Basis		—		—		(387)
U.S. Tax Attribute Limitation		217		—		—
Impact of Rate Changes		106		(7)		(671)
Other		5		4		16
Total Tax Expense (Recovery) From Operations		728		(851)		(797)
Effective Tax Rate		55.4 %		26.3 %		(57.1)%

The final purchase price allocation of the Arrangement includes net deferred tax assets of $1.1 billion as at January 1, 2021. The net deferred tax assets consists of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S. operations, offset by a tax liability of $444 million related to Asia Pacific activities. The Canadian deferred tax asset has been offset against the Canadian deferred tax liability.

The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is as follows:

For the years ended December 31,	2021	2020
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months	4,046	4,146
	4,046	4,146
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months	(556)	(88)
Deferred Income Tax Assets to be Settled After More Than Twelve Months	(898)	(860)
	(1,454)	(948)
Net Deferred Income Tax Liability	2,592	3,198

The deferred income tax assets and liabilities to be settled within twelve months represents Management’s estimate of the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the subsequent year.

The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within the same tax jurisdiction, is:

Deferred Income Tax Liabilities	PP&E		Risk       Management		Other		Total
As at December 31, 2019		4,498		1		44		4,543
Charged (Credited) to Earnings		(367)		(1)		(22)		(390)
Charged (Credited) to OCI		(7)		—		—		(7)
As at December 31, 2020		4,124		—		22		4,146
Charged (Credited) to Earnings		(234)		—		75		(159)
Charged (Credited) to Purchase Price Allocation		59		—		—		59
As at December 31, 2021		3,949		—		97		4,046

120  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

	Unused Tax		Risk
Deferred Income Tax Assets	Losses		Management		Other		Total
As at December 31, 2019		(225)		(1)		(285)		(511)
Charged (Credited) to Earnings		(448)		(12)		12		(448)
Charged (Credited) to OCI		14		—		(3)		11
As at December 31, 2020		(659)		(13)		(276)		(948)
Charged (Credited) to Earnings		668		1		(58)		611
Charged (Credited) to Purchase Price Allocation		(656)		1		(466)		(1,121)
Charged (Credited) to OCI		(8)		—		12		4
As at December 31, 2021		(655)		(11)		(788)		(1,454)

Net Deferred Income Tax Liabilities	Total
As at December 31, 2019		4,032
Charged (Credited) to Earnings		(838)
Charged (Credited) to OCI		4
As at December 31, 2020		3,198
Charged (Credited) to Earnings		452
Charged (Credited) to Purchase Price Allocation		(1,062)
Charged (Credited) to OCI		4
As at December 31, 2021		2,592

The deferred income tax asset of $694 million (2020 – $36 million) represents net deductible temporary differences in the U.S. jurisdiction which has been fully recognized, as the probability of realization is expected due to a forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2021 and 2020 on temporary differences associated with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal of the temporary difference and the reversal is not probable in the foreseeable future.

The approximate amounts of tax pools available, including tax losses, are:

As at December 31,	2021		2020
Canada		11,167		6,540
United States		5,915		3,117
Asia Pacific		600		—
		17,682		9,657

As at December 31, 2021, the above tax pools included $1.5 billion (2020 – $1.7 billion) of Canadian federal non-capital losses and $775 million (2020 – $1.1 billion) of U.S. federal net operating losses. These losses expire no earlier than 2036.

As at December 31, 2021, the Company had Canadian net capital losses totaling $102 million (2020 – $85 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $102 million (2020 – $254 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

12. PER SHARE AMOUNTS

A) Net Earnings (Loss) Per Common Share – Basic and Diluted

For the years ended December 31,	2021		2020		2019
Net Earnings (Loss)		587		(2,379)		2,194
Effect of Cumulative Dividends on Preferred Shares		(34)		—		—
Net Earnings (Loss) – Basic and Diluted		553		(2,379)		2,194
Basic – Weighted Average Number of Shares		2,016.2		1,228.9		1,228.8
Dilutive Effect of Warrants		27.6		—		—
Dilutive Effect of Net Settlement Rights		1.3		—		0.6
Diluted – Weighted Average Number of Shares		2,045.1		1,228.9		1,229.4
Net Earnings (Loss) Per Common Share – Basic ($)		0.27		(1.94)		1.78
Net Earnings (Loss) Per Common Share – Diluted ($)		0.27		(1.94)		1.78

As at December 31, 2021, $22 million of net earnings and 1.9 million of potential ordinary shares related to the assumed exercise of Cenovus replacement stock options were excluded from the diluted net earnings per share calculation as the impact was anti-dilutive. These instruments could potentially dilute earnings per share in the future. For further information on the Company’s stock-based compensation plans, see Note 32.

As at December 31, 2021, 18 million NSRs (2020 — 31 million; 2019 — 32 million) were excluded from the calculation of diluted weighted average number of shares as their effect would have been anti-dilutive or their exercise prices exceeded the market price of Cenovus’s common shares.

B) Common Share Dividends

For the year ended December 31, 2021, the Company paid dividends of $176 million or $0.0875 per common share (2020 – $77 million or $0.0625 per common share; 2019 – $260 million or $0.2125 per common share). The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 7, 2022, the Company’s Board of Directors declared a first quarter dividend of $0.0350 per common share, payable on March 31, 2022, to common shareholders of record as at March 15, 2022.

C) Preferred Share Dividends

For the year ended December 31, 2021	Total
Series 1 First Preferred Shares		7
Series 2 First Preferred Shares		1
Series 3 First Preferred Shares		12
Series 5 First Preferred Shares		9
Series 7 First Preferred Shares		5
Total Declared and Paid Preferred Share Dividends		34

The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. If a dividend is not paid in full on any preferred shares on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative. On February 7, 2022, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2022, in the amount of $9 million, to preferred shareholders of record as at March 15, 2022.

122  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

13. CASH AND CASH EQUIVALENTS

As at December 31,	2021		2020
Cash		2,366		368
Short-Term Investments		507		10
		2,873		378

14. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,	2021		2020
Trade and Accruals		2,548		1,149
Prepaids and Deposits		486		121
Partner Advances		371		175
Joint Operations Receivables		225		35
Other (1)		240		8
		3,870		1,488

(1) As at December 31, 2021, insurance proceeds receivable related to the 2018 Superior Refinery incident was $135 million. During the twelve months ended December 31, 2021, $120 million of insurance proceeds were recorded to other (income) loss, net.

15. INVENTORIES

As at December 31,	2021		2020  (1)
Product
Oil Sands		1,419		382
Conventional		78		1
Offshore		39		—
Canadian Manufacturing		88		—
U.S. Manufacturing		2,001		613
Retail		26		—
Parts and Supplies		268		93
		3,919		1,089

(1) Prior period results have been reclassified to conform with the current period’s operating segments.

During the year ended December 31, 2021, approximately $34 billion of produced and purchased inventory was recorded as an expense (2020 – approximately $10 billion).

As at December 31, 2021, the Company had no inventory write downs. During the twelve months ended December 31, 2021, the Company had $16 million of inventory write-downs.

As at March 31, 2020, the Company recorded $588 million in non-cash inventory write-downs of its crude oil blend, condensate and refined product inventory. Subsequently, $547 million of inventory that was written down at the end of March was sold and the loss was realized. For the year ended December 31, 2020, the Company reversed $39 million of the inventory write-downs related to March product inventory that was still on hand due to improved refined product and crude oil prices. As at December 31, 2020, the Company recorded a $6 million write-down in refined product inventory.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  123

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

16. ASSETS HELD FOR SALE

In 2021, the Company entered into agreements to sell 337 gas stations in Cenovus’s retail fuels network, in the Retail segment, located across Western Canada and Ontario for gross proceeds of $420 million. The sales are expected to close in mid-2022. Operating margin associated with the retail assets held for sale for the year ended December 31, 2021 was $64 million.

The Company also entered into agreements to sell its Tucker asset in the Oil Sands segment and its Conventional segment assets located in the Wembley area in 2021. The sale of the Tucker asset closed on January 31, 2022, for gross cash proceeds of $800 million and the sale of the Wembley assets is expected to close during first three months of 2022 for gross proceeds of $238 million.

These assets were recorded at the lesser of their carrying amount and their fair value less cost to sell. No impairments were recorded on the assets held for sale as at December 31, 2021.

As at December 31, 2021	PPE           (Note 18)		ROU Assets   (Note 19)		Goodwill   (Note 22)		Lease         Liabilities (Note 26)			Decommissioning Liabilities (Note 27)
Retail		498		54		—		(58	)		(86	)
Tucker		505		—		88		—			(33	)
Wembley		159		—		—		—			(9	)
		1,162		54		88		(58	)		(128	)

17. EXPLORATION AND EVALUATION ASSETS, NET

	Total
As at December 31, 2019		787
Additions		48
Transfers to PP&E (Note 18)		(47)
Exploration Expense		(91)
Depletion		(18)
Change in Decommissioning Liabilities		5
Divestitures (Note 9)		(61)
As at December 31, 2020		623
Acquisition (Note 5A)		45
Additions		55
Exploration Expense		(9)
Change in Decommissioning Liabilities		6
As at December 31, 2021		720

124  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

18. PROPERTY, PLANT AND EQUIPMENT, NET

	Oil and Gas   Properties		Processing,   Transportation   and Storage   Assets		Manufacturing   Assets		Retail and   Other (1)		Total
COST
As at December 31, 2019 (2)		29,365		183		5,577		1,231		36,356
Additions		475		33		243		60		811
Transfers from E&E Assets (Note 17)		47		—		—		—		47
Change in Decommissioning Liabilities		(11)		2		3		—		(6)
Exchange Rate Movements and Other		(6)		—		(152)		(1)		(159)
Divestitures		(3)		—		—		—		(3)
As at December 31, 2020 (2)		29,867		218		5,671		1,290		37,046
Acquisitions (Note 5)		8,633		—		3,901		846		13,380
Additions		1,368		9		1,023		115		2,515
Change in Decommissioning Liabilities		(63)		1		40		24		2
Exchange Rate Movements and Other		22		—		(140)		(18)		(136)
Divestitures		(630)		—		—		—		(630)
Transfers to Assets Held for Sale (Note 16)		(754)		—		—		(522)		(1,276)
As at December 31, 2021		38,443		228		10,495		1,735		50,901
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2019 (2)		6,008		33		1,596		885		8,522
Depreciation, Depletion and Amortization (3)		1,820		9		242		152		2,223
Impairment Charges (Note 10) (3)		555		—		450		—		1,005
Exchange Rate Movements and Other		(22)		—		(93)		—		(115)
As at December 31, 2020 (2)		8,361		42		2,195		1,037		11,635
Depreciation, Depletion and Amortization		3,335		10		526		128		3,999
Impairment Charges (Note 10)		—		—		1,931		—		1,931
Impairment Reversals (Note 10)		(378)		—		—		—		(378)
Exchange Rate Movements and Other		61		1		(80)		(2)		(20)
Divestitures		(377)		—		—		—		(377)
Transfers to Assets Held for Sale (Note 16)		(90)		—		—		(24)		(114)
As at December 31, 2021		10,912		53		4,572		1,139		16,676
CARRYING VALUE
As at December 31, 2019 (2)		23,357		150		3,981		346		27,834
As at December 31, 2020 (2)		21,506		176		3,476		253		25,411
As at December 31, 2021		27,531		175		5,923		596		34,225

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

(2) Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.

(3) Asset write-downs have been reclassified to DD&A to conform with the current presentation of impairment charges.

Assets Under Construction

PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:

As at December 31,	2021		2020
Development and Production		2,415		1,807
Downstream		943		226
		3,358		2,033

CENOVUS ENERGY 2021 ANNUAL REPORT  |  125

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

19. RIGHT-OF-USE ASSETS, NET

	Real Estate		Transportation and Storage Assets (1)		Manufacturing Assets		Retail and Other		Total
COST
As at December 31, 2019 (2)		509		959		10		14		1,492
Additions		1		40		5		7		53
Terminations		—		(1)		—		—		(1)
Modifications		—		1		—		(3)		(2)
Reclassifications		(14)		—		—		—		(14)
Re-measurements		—		(1)		—		(1)		(2)
Exchange Rate Movements and Other		(1)		(21)		—		(2)		(24)
As at December 31, 2020 (2)		495		977		15		15		1,502
Acquisition (Note 5A)		99		765		138		130		1,132
Additions		4		96		7		3		110
Modifications		1		20		1		—		22
Re-measurements		(2)		1		—		(3)		(4)
Exchange Rate Movements and Other		(5)		(18)		—		(5)		(28)
Transfers to Assets Held for Sale (Note 16)		—		—		—		(78)		(78)
As at December 31, 2021		592		1,841		161		62		2,656
ACCUMULATED DEPRECIATION
As at December 31, 2019 (2)		32		128		3		4		167
Depreciation		27		181		2		5		215
Impairment Charges (Note 10)		—		3		—		—		3
Terminations		—		(1)		—		—		(1)
Exchange Rate Movements and Other		(1)		(18)		—		(2)		(21)
As at December 31, 2020 (2)		58		293		5		7		363
Depreciation		38		239		23		23		323
Impairment Charges (Note 10)		—		5		5		1		11
Terminations		—		(3)		—		—		(3)
Exchange Rate Movements and Other		(4)		(14)		—		(6)		(24)
Transfers to Assets Held for Sale (Note 16)		—		—		—		(24)		(24)
As at December 31, 2021		92		520		33		1		646
CARRYING VALUE
As at December 31, 2019 (2)		477		831		7		10		1,325
As at December 31, 2020 (2)		437		684		10		8		1,139
As at December 31, 2021		500		1,321		128		61		2,010

(1) Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.

(2) Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.

20. JOINT ARRANGEMENTS AND ASSOCIATE

A) Joint Operations

BP-Husky Refining LLC

Cenovus holds a 50 percent interest in Toledo with BP, who operates the Toledo Refinery in Ohio.

Sunrise Oil Sands Partnership

Cenovus, as the operator, holds a 50 percent interest in Sunrise, an oil sands project in northern Alberta, with BP Canada who holds the remaining interest.

126  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

WRB Refining LP

Cenovus holds a 50 percent interest in WRB with Phillips 66, who holds the remaining interest and operates the Wood River Refinery in Illinois and the Borger Refinery in Texas.

B) Joint Ventures

Husky-CNOOC Madura Ltd.

The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and production of natural gas resources in offshore Indonesia. The Company’s share of equity investment income (loss) related to the joint venture is included in the Consolidated Statements of Earnings (Loss) in the Offshore segment.

Summarized below is the financial information for HCML accounted for using the equity method.

Results of Operations

For the year ended December 31,	2021
Revenue		439
Expenses		395
Net Earnings (Loss)		44

Balance Sheet

As at December 31,	2021
Current Assets (1)		167
Non-Current Assets		1,433
Current Liabilities		62
Non-Current Liabilities		896
Net Assets		642

(1) Includes cash and cash equivalents of $46 million.

For the year ended December 31, 2021, the Company’s share of income from the equity-accounted affiliate was $47 million. As at December 31, 2021, the carrying amount of the Company’s share of net assets was $311 million. These amounts do not equal the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the investment and accounting policies between the joint venture and the Company. For the year ended December 31, 2021, the difference was primarily related to the fair value associated with the purchase price allocation.

For the year ended December 31, 2021, the Company received $100 million of distributions from HCML.

Husky Midstream Limited Partnership

The Company holds a 35 percent interest in HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. Power Assets Holdings Ltd. holds a 49 percent interest and CK Infrastructure Holdings Ltd. holds a 16 percent interest in HMLP.

For the year ended December 31, 2021, HMLP had net earnings of $134 million. The Company’s share of (income) loss from the equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing arrangement as defined in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain income thresholds. For the year ended December 31, 2021, the Company did not record its pre-tax net income relating to HMLP of $18 million as the carrying value of the Company’s interest is $nil.

Due to the decline in forecasted distributions from the partnership profit structure, as at December 31, 2021, the Company had $17 million in cumulative unrecognized losses and OCI, net of tax. The Company records its share of equity investment income related to the joint venture only in excess of the cumulated unrecognized loss and is included in the Consolidated Statements of Earnings (Loss) in the Oil Sands segment.

For the twelve months ended December 31, 2021, the Company received $37 million in distributions and paid $32 million in contributions to HMLP. The net amount of the distributions received and contributions paid are recorded in (income) loss from equity-accounted affiliates.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  127

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

C) Associate

Headwater Exploration Inc.

On October 14, 2021, the Company sold its 25 percent interest in Headwater (see Note 9). The proportionate share of the income from the Headwater equity investment prior to the sale was $5 million and was recorded to (income) loss from equity-accounted affiliates.

21. OTHER ASSETS

As at December 31,	2021		2020
Intangible Assets		78		89
Private Equity Investments (Note 35)		53		52
Other Equity Investments		77		12
Net Investment in Finance Leases		60		52
Long-Term Receivables and Prepaids		77		11
Precious Metals		85		—
Other		1		—
		431		216

On December 2, 2020, Cenovus sold its Marten Hills assets in Northern Alberta to Headwater. Part of the consideration received included 15 million share purchase warrants with a fair value of $8 million at the date of close. The share purchase warrants had a three-year term and an exercise price of $2.00 per share. On December 23, 2021, all of the outstanding share purchase warrants were exercised for a total cost of $30 million. At December 31, 2021, the fair value of the Headwater investment was $77 million included in other equity investments above. The investment is carried at FVTPL.

22. GOODWILL

	2021		2020
Carrying Value, Beginning of Year		2,272		2,272
Goodwill Recognized (Note 5A)		1,289		—
Goodwill Reclassified to Assets Held for Sale (Note 16)		(88)		—
Carrying Value, End of Year		3,473		2,272
The carrying amount of goodwill allocated to the Company’s CGUs is:
As at December 31,	2021		2020
Primrose (Foster Creek)		1,171		1,171
Christina Lake		1,101		1,101
Lloydminster Thermal		651		—
Sunrise		550		—
		3,473		2,272

For the purposes of impairment testing, goodwill is allocated to the CGUs to which it relates. The assumptions used to test Cenovus’s goodwill for impairment as at December 31, 2021, are consistent to those disclosed in Note 10. There was no impairment of goodwill as at December 31, 2021.

128  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

23. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,	2021		2020
Accruals		2,722		912
Trade		2,554		608
Interest		128		77
Partner Advances		371		175
Employee Long-Term Incentives		317		130
Joint Operations Payable		28		6
Risk Management		116		58
Provisions for Onerous and Unfavourable Contracts		31		26
Other		86		26
		6,353		2,018

24. CONTINGENT PAYMENT

	2021		2020
Contingent Payment, Beginning of Year		63		143
Re-measurement (1)		575		(80)
Liabilities Settled or Payable		(402)		—
Contingent Payment, End of Year		236		63

(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).

In connection with the acquisition in 2017 from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”), Cenovus agreed to make quarterly payments to ConocoPhillips during the five years ending May 17, 2022, for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. 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. There are no maximum payment terms.

The contingent payment is accounted for as a financial option. The fair value is estimated by calculating the present value of the future expected cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate. The contingent payment is re-measured at fair value at each reporting date with changes in fair value recognized in net earnings (loss). As at December 31, 2021, $160 million is payable under this agreement (December 31, 2020 – $nil).

25. DEBT AND CAPITAL STRUCTURE

A) Short-Term Borrowings

As at December 31,	Notes		2021		2020
Uncommitted Demand Facilities		i		—		—
WRB Uncommitted Demand Facilities		ii		79		121
Sunrise Uncommitted Demand Credit Facility		iii		—		—
Total Debt Principal				79		121

i) Uncommitted Demand Facilities

At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s uncommitted demand facilities of $975 million. As at January 1, 2021, $40 million in direct borrowings were outstanding and $427 million letters of credit were outstanding under these facilities.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  129

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

In the three months ended December 31, 2021, the Company cancelled and replaced all uncommitted demand facilities, which included those assumed in the Arrangement, and entered into new uncommitted demand facilities. As at December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion (December 31, 2020 – $1.6 billion) in place, of which $1.4 billion (December 31, 2020 – $600 million) may be drawn for general purposes, or the full amount can be available to issue letters of credit. As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31, 2020 – $441 million) and no direct borrowings.

ii) WRB Uncommitted Demand Facilities

WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million), which may be used to cover short-term working capital requirements. Subsequent to December 31, 2021, WRB added an incremental US$150 million in demand facilities (the Company’s proportionate share – US$75 million).

iii) Sunrise Uncommitted Demand Credit Facility

Sunrise has an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million), which is available for general purposes.

B) Long-Term Debt

As at December 31,	Notes		2021		2020
Revolving Term Debt (1)		i		—		—
U.S. Dollar Denominated Unsecured Notes		ii		9,363		7,510
Canadian Dollar Unsecured Notes		ii		2,750		—
Total Debt Principal				12,113		7,510
Net Debt Premiums (Discounts) and Transaction Costs (2)				272		(69)
Long-Term Debt				12,385		7,441

(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.

(2) Includes $353 million net debt premiums related to the Canadian and U.S. dollar denominated unsecured notes assumed at fair value in the Arrangement.

In 2021, pledges of intercompany obligations owing to Cenovus Energy Inc., made in favour of the holders of select previously issued Husky notes were terminated in accordance with their respective terms. The pledge terminations ensured all bond holders were ranked equally in right of payment with all of Cenovus’s other unsecured and unsubordinated indebtedness.

For the year ended December 31, 2021, the weighted average interest rate on outstanding debt, including the Company’s proportionate share of the WRB and Sunrise uncommitted demand facilities, was 4.6 percent (2020 – 4.9 percent).

i) Committed Credit Facilities

At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s committed credit facilities of $4.0 billion. As at January 1, 2021, $350 million was outstanding.

On August 18, 2021, $8.5 billion of committed credit facilities, which included those assumed in the Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility. The committed revolving credit facility consists of a $2.0 billion tranche maturing on August 18, 2024, and a $4.0 billion tranche maturing on August 18, 2025. As at December 31, 2021, no amount was drawn on the credit facility.

ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes

At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s 3.55 percent 3.60 percent and 3.50 percent Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and 3.95 percent 4.00 percent, 4.40 percent and 6.80 percent U.S. dollar denominated unsecured notes with a fair value of $3.4 billion (notional value – US$2.4 billion or C$3.0 billion).

On March 31, 2021, Cenovus Energy Inc. and Husky Energy Inc. amalgamated and Cenovus Energy Inc. became the direct obligor on all of Husky’s unsecured notes.

The Company closed a public offering in the U.S. on September 13, 2021, for US$1.25 billion of senior unsecured notes, consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032, and US$750 million 3.75 percent senior unsecured notes due February 15, 2052.

130  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

In September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured notes with a principal amount of US$2.2 billion. A net premium on the redemption of $121 million was recorded in finance costs. The following principal amounts of Cenovus’s unsecured notes were repurchased:

• 3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).

• 3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).

• 3.80 percent unsecured notes due 2023 – US$335 million.

• 4.00 percent unsecured notes due 2024 – US$481 million.

• 5.38 percent unsecured notes due 2025 – US$334 million.

The principal amounts of the Company’s unsecured notes are:

	2021				2020
As at December 31,	US$ Principal		C$ Principal and   Equivalent		US$ Principal		C$ Principal and   Equivalent
U.S. Dollar Denominated Unsecured Notes
3.00% due August 15, 2022		—		—		500		637
3.80% due September 15, 2023		115		146		450		573
4.00% due April 15, 2024		269		341		—		—
5.38% due July 15, 2025		666		844		1,000		1,273
4.25% due April 15, 2027		962		1,220		962		1,225
4.40% due April 15, 2029		750		951		—		—
2.65% due January 15, 2032		500		634		—		—
5.25% due June 15, 2037		583		739		583		742
6.80% due September 15, 2037		387		490		—		—
6.75% due November 15, 2039		1,390		1,763		1,390		1,770
4.45% due September 15, 2042		155		197		155		198
5.20% due September 15, 2043		58		73		58		74
5.40% due June 15, 2047		800		1,014		800		1,018
3.75% due February 15, 2052		750		951		—		—
		7,385		9,363		5,898		7,510
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025		—		750		—		—
3.60% due March 10, 2027		—		750		—		—
3.50% due February 7, 2028		—		1,250		—		—
		—		2,750		—		—
Total Unsecured Notes		7,385		12,113		5,898		7,510

As at December 31, 2021, the Company is in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit.

On January 10, 2022, the Company announced that it intends to redeem the entire US$384 million balance of its outstanding 3.80 percent unsecured notes and 4.00 percent unsecured notes on February 9, 2022.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  131

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

C) Mandatory Debt Payments

	U.S. Dollar Denominated Unsecured				Canadian Dollar   Unsecured
	Notes				Notes		Total (1)
As at December 31, 2021	US$ Principal		C$ Principal   Equivalent		C$ Principal		C$ Principal and   Equivalent
2023		115		146		—		146
2024		269		341		—		341
2025		666		844		750		1,594
Thereafter		6,335		8,032		2,000		10,032
		7,385		9,363		2,750		12,113

(1) On January 10, 2022, the Company announced that it intends to redeem its outstanding 3.80 percent unsecured notes and 4.00 percent unsecured notes on February 9, 2022. The total amount of mandatory debt payments has not been adjusted for this redemption.

D) Capital Structure

Cenovus’s capital structure consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments, and is used in managing the Company’s capital. The Company’s objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may, among other actions, adjust capital and operating spending, draw down on its credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase the Company’s common shares or preferred shares for cancellation, issue new debt, or issue new shares.

Cenovus monitors its capital structure and financing requirements using, among other things, specified financial measures consisting of net debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength.

Cenovus targets a Net Debt to Adjusted EBITDA ratio between 1.0 and 1.5 times and Net Debt between $6 billion to $8 billion over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to factors such as persistently high or low commodity prices.

On October 7, 2021, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where permitted by law. The base shelf prospectus will expire in November 2023. Offerings under the base shelf prospectus are subject to market conditions. As at December 31, 2021, US$4.7 billion remained available under Cenovus’s base shelf prospectus for permitted offerings.

132  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Net Debt to Adjusted EBITDA

As at December 31,	2021		2020 (1)		2019 (1)
Short-Term Borrowings		79		121		—
Long-Term Portion of Long-Term Debt		12,385		7,441		6,699
Less: Cash and Cash Equivalents		(2,873)		(378)		(186)
Net Debt		9,591		7,184		6,513
Net Earnings (Loss)		587		(2,379)		2,194
Add (Deduct):
Finance Costs		1,082		536		511
Interest Income		(23)		(9)		(12)
Income Tax Expense (Recovery)		728		(851)		(797)
Depreciation, Depletion and Amortization		5,886		3,464		2,249
Exploration Expense		18		91		82
Unrealized (Gain) Loss on Risk Management		2		56		149
Foreign Exchange (Gain) Loss, Net		(174)		(181)		(404)
Re-measurement of Contingent Payment		575		(80)		164
(Gain) Loss on Divestitures of Assets		(229)		(81)		(2)
Other (Income) Loss, Net		(309)		40		9
(Income) Loss From Equity-Accounted Affiliates		(57)		—		—
Adjusted EBITDA (2)		8,086		606		4,143
Net Debt to Adjusted EBITDA		1.2x		11.9x		1.6x

(1) Comparative figures include Cenovus’s results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.

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

Net Debt to Capitalization

As at December 31,	2021		2020 (1)		2019 (1)
Net Debt		9,591		7,184		6,513
Shareholders’ Equity		23,596		16,707		19,201
Capitalization		33,187		23,891		25,714
Net Debt to Capitalization		29 %		30 %		25 %

(1) Comparative figures include Cenovus‘s results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  133

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

26. LEASE LIABILITIES

	2021		2020
Lease Liabilities, Beginning of Year		1,757		1,916
Acquisition (Note 5A)		1,441		—
Additions		110		49
Interest Expense (Note 7)		171		87
Lease Payments		(471)		(284)
Terminations		(1)		(1)
Modifications		22		(2)
Re-measurements		(4)		(2)
Exchange Rate Movements and Other		(10)		(6)
Transfers to Liabilities Related to Assets Held for Sale (Note 16)		(58)		—
Lease Liabilities, End of Year		2,957		1,757
Less: Current Portion		272		184
Long-Term Portion		2,685		1,573

The Company has lease liabilities for contracts related to office space, transportation and storage assets, which includes barges, vessels, pipelines, caverns, railcars and storage tanks, retail assets and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions.

The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are leases with terms of twelve months or less.

The Company has included extension options in the calculation of lease liabilities where the Company has the right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company does not have any significant termination options and the residual amounts are not material.

27. DECOMMISSIONING LIABILITIES

The decommissioning provision represents the present value of the expected future costs associated with the retirement of producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, retail and the crude-by-rail terminal.

The aggregate carrying amount of the obligation is:

	2021		2020
Decommissioning Liabilities, Beginning of Year		1,248		1,235
Acquisitions (Note 5)		2,856		—
Liabilities Incurred		30		14
Liabilities Settled		(144)		(42)
Liabilities Disposed		(140)		(2)
Transfers to Liabilities Related to Assets Held for Sale (Note 16)		(128)		—
Change in Estimated Future Cash Flows		(472)		13
Change in Discount Rates		450		(28)
Unwinding of Discount on Decommissioning Liabilities (Note 7)		199		57
Foreign Currency Translation		7		1
Decommissioning Liabilities, End of Year		3,906		1,248

As at December 31, 2021, the undiscounted amount of estimated future cash flows required to settle the obligation is $14 billion (2020 – $5 billion), which has been discounted using a credit-adjusted risk-free rate of 4.4 percent (2020 – 5.0 percent) and an inflation rate of two percent (2020 – two percent). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company expects to settle approximately $230 million of decommissioning liabilities over the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning liabilities over the estimated life of the reserves and an increase in cost estimates.

The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2021, the Company had $186 million in restricted cash (2020 – $nil).

134  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Sensitivities

Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities:

	Sensitivity	2021				2020
As at December 31,	Range	Increase		Decrease		Increase		Decrease
Credit-Adjusted Risk Free Rate	± one percent		(623)		875		(228)		313
Inflation Rate	± one percent		873		(625)		321		(235)

28. OTHER LIABILITIES

As at December 31,	2021		2020
Pension and Other Post-Employment Benefit Plans		288		91
Provision for West White Rose Expansion Project (1)		259		—
Provisions for Onerous and Unfavourable Contracts		99		39
Employee Long-Term Incentives		74		33
Drilling Provisions		56		—
Deferred Revenue		41		—
Other		112		18
		929		181

(1) Relates to the long-term liability related to the 69 percent working interest in the West White Rose Expansion Project acquired through the Arrangement.

Deferred Revenue

Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes in Asia Pacific, not taken by the purchaser. In accordance with the terms of the agreement, the purchaser has until the end of the agreement to take these volumes.

	Total
As at December 31, 2020		—
Acquisition		37
Take-or-Pay Payments Received		4
As at December 31, 2021		41

29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS

The Company provides the majority of employees with a defined contribution pension plan. The Company also provides OPEB plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”).

The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada, future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The Company’s OPEB plans provides certain retired employees with health care and dental benefits.

The Company is required to file an actuarial valuation of its registered defined benefit pension with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2019, and the next required actuarial valuation will be as at December 31, 2022. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2021, and the next required actuarial valuation will be as at January 1, 2022.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  135

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

A) Defined Benefit and OPEB Plan Obligation and Funded Status

Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:

	Pension Benefits				OPEB
	2021		2020		2021		2020
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year		188		158		20		22
Plan Acquisition Upon the Arrangement (1)		41		—		224		—
Current Service Costs		16		13		9		1
Past Service Costs - Curtailment and Plan Amendments		(1)		—		(3)		—
Interest Costs (2)		6		5		6		—
Benefits Paid		(17)		(6)		(8)		(2)
Plan Participant Contributions		2		2		—		—
Re-measurements:
(Gains) Losses From Experience Adjustments		4		1		10		(2)
(Gains) Losses From Changes in Demographic Assumptions		(1)		—		(3)		—
(Gains) Losses From Changes in Financial Assumptions		(18)		15		(30)		1
Defined Benefit Obligation, End of Year		220		188		225		20
Plan Assets
Fair Value of Plan Assets, Beginning of Year		117		107		—		—
Plan Acquisition Upon the Arrangement (1)		32		—		—		—
Employer Contributions		9		6		3		—
Plan Participant Contributions		2		2		—		—
Benefits Paid		(13)		(5)		(3)		—
Interest Income (2)		3		2		—		—
Re-measurements:
Return on Plan Assets (Excluding Interest Income)		9		5		—		—
Fair Value of Plan Assets, End of Year		159		117		—		—
Pension and OPEB (Liability) (3)		(61)		(71)		(225)		(20)

(1) The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5A.

(2) Based on the discount rate of the defined benefit obligation at the beginning of the year.

(3) Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.

The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 14 years, respectively.

136  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) Pension and OPEB Costs

	Pension Benefits						OPEB
As at December 31,	2021		2020		2019		2021		2020		2019
Defined Benefit Plan Cost
Current Service Costs		16		13		11		9		1		1
Past Service Costs - Curtailments and Plan Amendments		(1)		—		—		(3)		—		—
Net Interest Costs		3		3		3		6		—		1
Re-measurements:
Return on Plan Assets (Excluding Interest Income)		(9)		(5)		(15)		—		—		—
(Gains) Losses From Experience Adjustments		4		1		(4)		10		(2)		—
(Gains) Losses From Changes in Demographic Assumptions		(1)		—		—		(3)		—		—
(Gains) Losses From Changes in Financial Assumptions		(18)		15		12		(30)		1		1
Defined Benefit Plan Cost (Recovery)		(6)		27		7		(11)		—		3
Defined Contribution Plan Cost		68		22		21		—		—		—
Total Plan Cost		62		49		28		(11)		—		3

C) Investment Objectives and Fair Value of Plan Assets

The objective of the asset allocation is to manage the funded status of the DB Pension Plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investment and credit rating categories.

The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced monthly, as necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of each other and, accordingly, the target asset allocation is reflective of their different liability profiles.

2021 Target Allocation (percent)	Canadian Plan		U.S. Plan
Equity Funds		25% - 70%		21% - 51%
Income Funds		25% - 35%		55% - 74%
Real Estate Funds		—% - 15%		—
Listed Infrastructure Funds		—% - 10%		—
Emerging Market Debt Funds		—% - 10%		—
Cash and Cash Equivalents		—% - 10%		—

The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods.

The fair value of the DB Pension Plan assets is:

As at December 31,	2021	2020
Equity Funds	77	58
Fixed Income Funds	54	35
Real Estate Funds	9	6
Listed Infrastructure Funds	8	8
Emerging Market Debt Funds	8	7
Cash and Cash Equivalents	2	2
Non-Invested Assets	1	1
Total Fair Value of DB Pension Plan Assets (1)	159	117

(1) The Company acquired Husky’s U.S. defined benefit pension obligations in connection with the Arrangement (see Note 5A). The U.S. defined benefit pension plan assets were valued at $32 million on January 1, 2021.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  137

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Fair value of the cash and cash equivalents, equity, income and listed infrastructure assets are based on the trading price of the underlying funds (Level 1). The fair value of the real estate funds reflects the appraisal valuation for each property investment (Level 2). The fair value of the non-invested assets is the discounted value of the expected future payments (Level 3).

The DB Pension Plan does not hold any direct investment in Cenovus common shares.

D) Funding

The DB Pension Plan’s are funded in accordance with applicable pension legislation. Contributions are made to trust funds administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent actuarial valuations, and direction of the Management Pension Committee and Human Resources and Compensation Committee of the Board of Directors.

Employees participating in the Canadian defined benefit pension are required to contribute four percent of their pensionable earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure benefits will be fully provided for at retirement. The Company’s expected contributions for the year ended December 31, 2022, are $11 million for the DB Pension Plan.

The OPEB plans are funded on an as required basis. The Company’s expected contributions for the year ended December 31, 2022, are $8 million for the OPEB plans.

E) Actuarial Assumptions and Sensitivities

Actuarial Assumptions

The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:

	Pension Benefits						OPEB
For the years ended December 31,	2021		2020		2019		2021		2020		2019
Discount Rate		2.95 %		2.50 %		3.00 %		2.98 %		2.50 %		3.00 %
Future Salary Growth Rate		4.03 %		3.97 %		3.94 %		4.94 %		4.94 %		5.08 %
Average Longevity (years)		88.3		88.3		88.2		88.3		88.2		88.2
Health Care Cost Trend Rate		N/A		N/A		N/A		5.64 %		6.00 %		6.00 %

Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations.

Sensitivities

Of the most significant actuarial assumptions, a change in discount rates and health care costs have the largest potential impact on the obligations for the DB Pension Plan and OPEB plans, with sensitivity to change as follows:

	2021				2020
As at December 31,	Increase		Decrease		Increase		Decrease
One Percent Change:
Discount Rate		(79)		102		(31)		40
Future Salary Growth Rate		4		(4)		4		(4)
Health Care Cost Trend Rate		26		(20)		1		(1)
One Year Change in Assumed Life Expectancy		4		(4)		4		(4)

The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however, the changes in some assumptions may be correlated. The same methodologies have been used to calculate the sensitivity of the DB Pension Plan obligation to significant actuarial assumptions as have been applied when calculating the liability for the DB Pension Plan recorded on the Consolidated Balance Sheets.

F) Risks

Through its DB Pension Plan and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate risk, investment risk and salary risk.

Longevity Risk

The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality of plan participants both during and after their employment. An increase in the life expectancy of participants will increase the defined benefit plan obligation.

138  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Interest Rate Risk

A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an increase in the return on debt holdings.

Investment Risk

The present value of the DB Pension Plan obligation is calculated using a discount rate determined by reference to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than in debt instruments and real estate.

Salary Risk

The present value of the DB Pension Plan obligation is, in part, calculated by reference to the future salaries of plan participants and the obligation of the OPEB plans is, in part, calculated by reference to the future health care cost trend rate. As such, an increase in the salary of the plan participants and increase in the future cost of health care claims will increase the defined benefit obligation.

30. SHARE CAPITAL AND WARRANTS

A) Authorized

Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles. Prior to the close of the Arrangement, Cenovus’s articles were amended to create the Cenovus series 1, 2, 3, 4, 5, 6, 7 and 8 first preferred shares.

B) Issued and Outstanding – Common Shares

	2021				2020
	Number of   Common   Shares   (thousands)		Amount		Number of   Common   Shares   (thousands)		Amount
Outstanding, Beginning of Year		1,228,870		11,040		1,228,828		11,040
Issued Under the Arrangement, Net of Issuance Costs (Note 5A)		788,518		6,111		—		—
Issued Upon Exercise of Warrants		314		3		—		—
Issued Under Stock Option Plans		535		7		42		—
Purchase of Common Shares under NCIB		(17,026)		(145)		—		—
Outstanding, End of Year		2,001,211		17,016		1,228,870		11,040

As at December 31, 2021, there were 30 million (December 31, 2020 – 27 million) common shares available for future issuance under the stock option plan.

C) Normal Course Issuer Bid

On November 4, 2021, the TSX accepted the Company’s implementation of a NCIB to purchase up to 146.5 million common shares during the twelve-month period commencing November 9, 2021, and ending November 8, 2022.

For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB. The shares were purchased at a weighted average price of $15.56 per common share for a total of $265 million. Paid in surplus was reduced by $120 million, representing the excess of the purchase price of common shares over their average carrying value. The shares were subsequently cancelled. As of February 7, 2022, Cenovus purchased an additional 9 million common shares for $160 million.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  139

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

D) Issued and Outstanding – Preferred Shares

As at December 31, 2021	Number of   Preferred   Shares   (thousands)		Amount
Outstanding, Beginning of Year		—		—
Issued Under the Arrangement (Note 5A)		36,000		519
Outstanding, End of Year		36,000		519

As at December 31, 2021	Dividend Reset Date		Dividend Rate		Number of   Preferred   Shares   (thousands)
Series 1 First Preferred Shares		March 31, 2026		2.58 %		10,740
Series 2 First Preferred Shares		March 31, 2026		1.86 %		1,260
Series 3 First Preferred Shares		December 31, 2024		4.69 %		10,000
Series 5 First Preferred Shares		March 31, 2025		4.59 %		8,000
Series 7 First Preferred Shares		June 30, 2025		3.94 %		6,000

Series 1 First Preferred Shares

In March 2021, 274 thousand series 1 first preferred shares were tendered for conversion into series 2 first preferred shares. The new annual fixed-rate dividend applicable to the series 1 first preferred shares for the five-year period commencing March 31, 2021, to March 30, 2026, is 2.58 percent, being equal to the sum of the Government of Canada five-year bond yield of 0.85 percent plus 1.73 percent in accordance with the terms of the series 1 first preferred shares. Holders of series 1 first preferred shares will have the right, at their option, to convert their shares into series 2 first preferred shares, subject to certain conditions, on March 31, 2026, and on March 31 every five years thereafter. The annual fixed-rate dividend was 2.40 percent for the previous period ending March 30, 2021.

Series 2 First Preferred Shares

In March 2021, 578 thousand series 2 first preferred shares were tendered for conversion into series 1 first preferred shares. Holders of the series 2 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 1.73 percent. Holders of series 2 first preferred shares will have the right, at their option, to convert their shares into series 1 first preferred shares, subject to certain conditions, on March 31, 2026, and on March 31 every five years thereafter. The floating-rate dividend was 1.92 percent for the previous period ending December 30, 2021. The new quarterly floating-rate dividend applicable for the period commencing December 31, 2021, to March 30, 2022, is 1.86 percent.

Series 3 First Preferred Shares

The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.13 percent. Holders of series 3 first preferred shares will have the right, at their option, to convert their shares into series 4 first preferred shares, subject to certain conditions, on December 31, 2024, and on December 31 every five years thereafter. Holders of the series 4 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13 percent.

Series 5 First Preferred Shares

The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.57 percent. Holders of series 5 first preferred shares will have the right, at their option, to convert their shares into series 6 first preferred shares, subject to certain conditions, on March 31, 2025, and on March 31 every five years thereafter. Holders of the series 6 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent.

Series 7 First Preferred Shares

The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.52 percent. Holders of series 7 first preferred shares will have the right, at their option, to convert their shares into series 8 first preferred shares, subject to certain conditions, on June 30, 2025, and on June 30 every five years thereafter. Holders of the series 8 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent.

140  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Second Preferred Shares

There were no second preferred shares outstanding as at December 31, 2021 (December 31, 2020 – nil).

E) Issued and Outstanding – Warrants

As at December 31, 2021	Number of   Warrants   (thousands)		Amount
Outstanding, Beginning of Year		—		—
Issued Under the Arrangement (Note 5A)		65,433		216
Exercised		(314)		(1)
Outstanding, End of Year		65,119		215

The exercise price of the Cenovus Warrants issued under the Arrangement is $6.54 per share.

F) Paid in Surplus

Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”) under the plan of arrangement into two independent energy companies, Encana (now known as Ovintiv Inc.) and Cenovus (earnings prior to Encana split). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 32 and the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIB.

	Earnings Prior
	to Encana		Stock-Based		Common
	Split		Compensation		Shares		Total
As at December 31, 2019		4,086		291		—		4,377
Stock-Based Compensation Expense		—		14		—		14
As at December 31, 2020		4,086		305		—		4,391
Stock-Based Compensation Expense		—		14		—		14
Purchase of Common Shares Under NCIB		—		—		(120)		(120)
Common Shares Issued on Exercise of Stock Options		—		(1)		—		(1)
As at December 31, 2021		4,086		318		(120)		4,284
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	Pension and				Foreign
	Other Post-				Currency
	Retirement		Private Equity		Translation
	Benefits		Instruments		Adjustment		Total
As at December 31, 2019		(2)		27		802		827
Other Comprehensive Income (Loss), Before Tax		(10)		—		(44)		(54)
Income Tax (Expense) Recovery		2		—		—		2
As at December 31, 2020		(10)		27		758		775
Other Comprehensive Income (Loss), Before Tax		47		—		(129)		(82)
Income Tax (Expense) Recovery		(9)		—		—		(9)
As at December 31, 2021		28		27		629		684

CENOVUS ENERGY 2021 ANNUAL REPORT  |  141

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

32. STOCK-BASED COMPENSATION PLANS

A) Employee Stock Options

Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.

Options issued by the Company have associated NSRs. The NSRs, in lieu of exercising the option, gives the option holder the right to receive the number of common shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess of the market price received from the sale of the common shares over the exercise price of the option.

The NSRs vest and expire under the same terms and conditions as the underlying options.

Stock Options With Associated Net Settlement Rights

The weighted average unit fair value of NSRs granted during the year ended December 31, 2021, was $3.27 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate	0.67 %
Expected Dividend Yield	0.76 %
Expected Volatility (1)	38.98 %
Expected Life (years)	5.76

(1) Expected volatility has been based on historical share volatility of the Company.

The following tables summarize information related to the NSRs:

							Number of
							Stock Options		Weighted
							with Associated		Average
							Net Settlement		Exercise
							Rights		Price
For the year ended December 31, 2021							(thousands)		($)
Outstanding, Beginning of Year								30,597		18.52
Granted								6,345		8.89
Exercised								(529)		10.51
Forfeited								(66)		15.17
Expired								(9,114)		28.61
Outstanding, End of Year								27,233		13.06
	Outstanding						Exercisable
	Number of		Weighted				Number of
	Stock Options		Average		Weighted		Stock Options		Weighted
	with Associated		Remaining		Average		with Associated		Average
	Net Settlement		Contractual		Exercise		Net Settlement		Exercise
As at December 31, 2021	Rights		Life		Price		Rights		Price
Range of Exercise Price ($)	(thousands)		(Years)		($)		(thousands)		($)
5.00 to 9.99		8,365		5.26		8.92		2,478		9.48
10.00 to 14.99		13,126		4.29		12.26		8,729		12.54
15.00 to 19.99		2,680		1.31		19.47		2,680		19.47
20.00 to 24.99		3,062		0.15		22.25		3,062		22.25
		27,233		3.83		13.06		16,949		14.94

The Arrangement on January 1, 2021, resulted in the accelerated vesting of outstanding NSRs held by non-executive employees and certain non-executive officers of the Company. In accordance with their terms, 2.7 million NSRs vested and were exercisable as a result of the accelerated vesting on January 1, 2021.

142  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Cenovus Replacement Stock Options

In connection with the Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were replaced by Cenovus replacement stock options. Each Cenovus replacement stock option entitles the holder to acquire 0.7845 of a Cenovus common share at an exercise price per share of a Husky stock option divided by 0.7845.

In the year ended December 31, 2021, eight thousand Cenovus replacement stock options were exercised and settled for six thousand common shares (see Note 30) and 782 thousand Cenovus replacement stock options, with a weighted average exercise price of $3.64, were exercised and net settled for cash.

The following tables summarize the information related to the Cenovus replacement stock options held by Cenovus employees:

For the year ended December 31, 2021							Number of   Cenovus   Replacement   Stock Options   (thousands)		Weighted   Average   Exercise   Price   ($)
Outstanding, Beginning of Year								—		—
Granted								18,882		15.31
Exercised								(790)		3.64
Forfeited								(3,582)		14.08
Expired								(2,254)		20.07
Outstanding, End of Year								12,256		15.21
	Outstanding						Exercisable
As at December 31, 2021   Range of Exercise Price ($)	Number of   Cenovus   Replacement   Stock Options   (thousands)		Weighted   Average   Remaining       Contractual   Life   (Years)		Weighted   Average   Exercise   Price   ($)		Number of   Cenovus   Replacement   Stock Options   (thousands)		Weighted   Average   Exercise   Price   ($)
3.00 to 4.99		3,602		2.68		3.54		772		3.54
5.00 to 9.99		164		3.20		6.03		34		5.95
10.00 to 14.99		58		2.67		12.66		41		12.62
15.00 to 19.99		2,896		1.77		18.43		2,012		18.47
20.00 to 24.99		5,384		0.68		21.23		5,384		21.23
25.00 to 29.99		152		1.58		27.88		152		27.88
		12,256		1.58		15.21		8,395		18.96

B) Performance Share Units

Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs are time-vested whole-share units that entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment equal to the value of a Cenovus common share. The number of PSUs eligible to vest is determined by a multiplier that ranges from zero percent to 200 percent and is based on the Company achieving key pre-determined performance measures. PSUs vest after three years.

The Company has recorded a liability of $61 million as at December 31, 2021, (2020 – $65 million) in the Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting and as a result, the intrinsic value was $nil as at December 31, 2021.

The Arrangement on January 1, 2021, resulted in the accelerated vesting of outstanding PSUs held by non-executive employees and certain non-executive officers of the Company. As a result, the intrinsic value was $51 million as at December 31, 2020. In accordance with their terms, 7.1 million PSUs were settled, in cash, subsequent to December 31, 2020, based on the 30-day volume weighted average trading price prior to the date of closing.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  143

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

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

For the year ended December 31, 2021	Number of   Performance   Share Units   (thousands)
Outstanding, Beginning of Year		9,284
Granted		6,175
Vested and Paid Out		(8,085)
Cancelled		(261)
Units in Lieu of Dividends		50
Outstanding, End of Year		7,163

C) Restricted Share Units

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

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

The Company has recorded a liability of $53 million as at December 31, 2021, (2020 – $61 million) in the Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year.

As RSUs are paid out upon vesting and as a result, the intrinsic value of vested RSUs was $nil as at December 31, 2021. The intrinsic value was $60 million as at December 31, 2020, due to the accelerated vesting of outstanding RSUs held by employees and certain non-executive officers of the Company as a result from the Arrangement. In accordance with their terms, 8.2 million RSUs were settled in cash in 2021 based on the 30-day volume weighted average trading price prior to the date of closing.

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

For the year ended December 31, 2021	Number of   Restricted   Share Units   (thousands)
Outstanding, Beginning of Year		8,430
Granted		6,435
Vested and Paid Out		(8,420)
Cancelled		(463)
Units in Lieu of Dividends		43
Outstanding, End of Year		6,025

D) Deferred Share Units

Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which are equivalent in value to a common share of the Company. Eligible employees have the option to convert either zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of directorship or employment.

The Company has recorded a liability of $20 million as at December 31, 2021, (2020 – $10 million) in the Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant. In connection with the Arrangement, the termination of a DSU holder that is a Cenovus director or employee will result in the settlement and redemption of DSUs, in cash based on the five day volume weighted average trading price prior to the date of redemption, in accordance with the terms of the related DSU Plan.

144  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

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

		Number of   Deferred   Share Units
For the year ended December 31, 2021	(thousands)
Outstanding, Beginning of Year		1,333
Granted to Directors		273
Granted		80
Units in Lieu of Dividends		10
Redeemed		(440)
Outstanding, End of Year		1,256

E) Total Stock-Based Compensation

For the years ended December 31,	2021		2020		2019
Stock Options With Associated Net Settlement Rights		14		11		9
Cenovus Replacement Stock Options		26		—		—
Performance Share Units		56		19		15
Restricted Share Units		48		23		34
Deferred Share Units		15		(4)		9
Stock-Based Compensation Expense (Recovery)		159		49		67
Stock-Based Compensation Costs Capitalized		8		16		20
Total Stock-Based Compensation		167		65		87

33. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,	2021		2020		2019
Salaries, Bonuses and Other Short-Term Employee Benefits		1,327		605		567
Post-Employment Benefits		89		33		29
Stock-Based Compensation (Note 32)		159		49		67
Other Incentive Benefits		201		(4)		31
Termination Benefits		180		9		6
		1,956		692		700

Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs.

34. RELATED PARTY TRANSACTIONS

A) Key Management Compensation

Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and Vice- Presidents. The compensation paid or payable to key management is:

For the years ended December 31,	2021		2020		2019
Salaries, Director Fees and Other Short-Term Benefits		69		21		24
Post-Employment Benefits		4		3		2
Stock-Based Compensation		72		15		22
Other Incentive Benefits		4		1		1
Termination Benefits		3		6		—
		152		46		49

Post-employment benefits represent the present value of future pension benefits earned during the year.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  145

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) Other Related Party Transactions

Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 20). As the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.

The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or a cost recovery basis with certain restrictions. For the year ended December 31, 2021, the Company charged HMLP $243 million for construction costs and management services.

The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2021, the Company incurred costs of $284 million for the use of HMLP’s pipeline systems, as well as transportation and storage services.

35. FINANCIAL INSTRUMENTS

Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, net investment in finance leases, accounts payable and accrued liabilities, risk management assets and liabilities, investments in the equity of companies, long-term receivables, lease liabilities, contingent payment, short-term borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial instruments.

A) Fair Value of Non-Derivative Financial Instruments

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

The fair values of restricted cash, long-term receivables and net investment in finance leases approximate their carrying amount due to the specific non-tradeable nature of these instruments.

Long-term debt is carried at amortized cost. The estimated fair value of long-term borrowings has been determined based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2021, the carrying value of Cenovus’s long-term debt was $12.4 billion and the fair value was $13.7 billion (December 31, 2020 carrying value – $7.4 billion, fair value – $8.6 billion).

Equity investments classified as FVOCI comprise equity investments in private companies. The Company classifies certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available.

The following table provides a reconciliation of changes in the fair value of private equity instruments classified at FVOCI:

	2021		2020
Fair Value, Beginning of Year		52		52
Acquisition (Note 5A)		1		—
Fair Value, End of Year		53		52

Equity investments classified as FVTPL comprise equity investments in public companies. These assets are carried at fair value on the Consolidated Balance Sheets in other assets. Fair value is determined based on quoted prices in active markets (Level 1).

B) Fair Value of Risk Management Assets and Liabilities

The Company’s risk management assets and liabilities consist of crude oil, natural gas and refined product swaps, futures, and if entered into, forwards, options, as well as condensate futures and swaps, foreign exchange and interest rate swaps. Crude oil, condensate, natural gas and refined product contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and the fair value of interest rate swaps are calculated using external valuation models which incorporate observable market data, including interest rate yield curves (Level 2). The fair value of cross currency interest rate swaps are calculated using external valuation models which incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2).

146  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Summary of Unrealized Risk Management Positions

	2021						2020
	Risk Management						Risk Management
As at December 31,	Asset		Liability		Net		Asset		Liability		Net
Crude Oil, Natural Gas, Condensate and
Refined Products		46		116		(70)		5		58		(53)
Exchange Rate Contracts		2		—		2		—		—		—
		48		116		(68)		5		58		(53)

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

As at December 31,	2021		2020
Level 2 – Prices Sourced From Observable Data or Market Corroboration		(68)		(53)

Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.

The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities from January 1 to December 31:

	2021		2020
Fair Value of Contracts, Beginning of Year		(53)		3
Acquisition (Note 5A)		(14)		—
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the Year		(995)		(308)
Fair Value of Contracts Realized During the Year		993		252
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts		1		—
Fair Value of Contracts, End of Year		(68)		(53)

Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk management positions are subject to an enforceable master netting arrangement or similar agreement that are not otherwise offset.

	2021						2020
	Risk Management						Risk Management
As at December 31,	Asset		Liability		Net		Asset		Liability		Net
Recognized Risk Management Positions
Gross Amount		263		331		(68)		70		123		(53)
Amount Offset		(215)		(215)		—		(65)		(65)		—
Net Amount		48		116		(68)		5		58		(53)

The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to changes in the credit risk of financial liabilities is immaterial.

Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk management payables exceed risk management receivables on a particular day. As at December 31, 2021, $114 million was pledged as cash collateral (2020 – $59 million).

C) Fair Value of Contingent Payment

The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by calculating the present value of the expected future cash flows using an option pricing model (Level 3), which assumes the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2021, the fair value of the contingent payment was estimated to be $236 million (December 31, 2020 – $63 million).

CENOVUS ENERGY 2021 ANNUAL REPORT  |  147

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

As at December 31, 2021, average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel. The average implied volatility of WTI options and the Canadian-U.S. dollar foreign exchange rate options used to value the contingent payment were 39.5 percent and 6.4 percent, respectively.

Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses) impacting earnings before income tax as follows:

As at December 31, 2021	Sensitivity Range	Increase		Decrease
WCS Forward Prices	± $5.00 per barrel		(45)		45

As at December 31, 2020	Sensitivity Range	Increase		Decrease
WCS Forward Prices	± $5.00 per barrel		(41)		32
WTI Option Implied Volatility	± five percent		(18)		17
Canadian to U.S. Dollar Foreign Exchange Rate Option Implied Volatility	± five percent		7		(10)

The impact of a five percent increase or decrease in WTI option price volatility and the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income tax.

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

For the years ended December 31,	2021		2020		2019
Realized (Gain) Loss		993		252		7
Unrealized (Gain) Loss		2		56		149
(Gain) Loss on Risk Management		995		308		156

Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates.

36. RISK MANAGEMENT

Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates as well as credit risk and liquidity risk.

To manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus, the Company may periodically enter into financial positions as a part of ongoing operations to market the Company’s production and physical inventory positions of crude oil and condensate volumes. The Company has entered into risk management positions to both help capture incremental margin expected to be received in future periods at the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and physical sales. Mitigation of commodity price volatility may utilize financial positions to protect both near-term and future cash flows. As at December 31, 2021, the fair value of financial positions was a net liability of $68 million and primarily consisted of crude oil, condensate, natural gas and foreign exchange rate instruments.

To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2021, there were foreign exchange contracts with a notional value of US$144 million outstanding and no interest rate or cross currency interest rate swap contracts outstanding.

148  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

Net Fair Value of Risk Management Positions

As at December 31, 2021	Notional Volumes (1) (2)		Terms (3)		Weighted Average Price (1) (2)		Fair Value   Asset   (Liability)
Crude Oil and Condensate Contracts
WTI Fixed – Sell		61.8 MMbbls		January 2022 - June 2023		US$72.19/bbl		(188)
WTI Fixed – Buy		25.3 MMbbls		January 2022 - June 2023		US$71.55/bbl		94
Other Financial Positions (4)								24
Foreign Exchange Contracts								2
Total Fair Value								(68)

(1) Million barrels (“MMbbls”). Barrel (“bbl”).

(2) Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may fluctuate from month to month as it represents the averages for various individual contracts with different terms.

(3) Contract terms represent various individual contracts with different terms, and range from one to eighteen months.

(4) Other financial positions consists of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, and the Company’s U.S. Manufacturing and Marketing activities.

A) Commodity Price Risk

Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments.

The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.

Crude Oil – The Company has used commodity futures and swaps, basis price risk management contracts, and options contracts to partially mitigate its exposure to the commodity price risk on its crude oil sales and to protect both near-term and future cash flows. Cenovus has entered into a number of transactions to help protect against widening light/heavy crude oil price differentials and to manage exposure to commodity price movements between when products are produced or purchased and when sold to the customer or used by Cenovus. In addition, the Company has entered into risk management positions to help mitigate the risk to incremental margin expected to be received in future periods at the time products will be sold.

Condensate – The Company has used commodity futures and swaps, as well as basis price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions.

Natural Gas – The Company has used fixed price and basis instruments to partially mitigate its natural gas commodity price risk.

Sensitivities

The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent fluctuations in commodity prices and foreign exchange rates, with all other variables held constant. Management believes the fluctuations identified in the table below are a reasonable measure of volatility.

The impact of fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:

As at December 31, 2021	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges		(225)		225
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production		4		(4)
Refined Products Commodity Price	± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges		(2)		2
U.S. to Canadian Dollar Exchange Rate	± 0.05 in the U.S. to Canadian Dollar Exchange Rate		11		(12)
As at December 31, 2020	Sensitivity Range	Increase		Decrease
Crude Oil Commodity Price	± US$5.00/bbl Applied to WTI, Condensate and Related Hedges		(44)		44
WCS and Condensate Differential Price	± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production		(2)		2

CENOVUS ENERGY 2021 ANNUAL REPORT  |  149

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) Foreign Exchange Risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on reported results.

As disclosed in Note 8, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2021, Cenovus had US$7.4 billion in U.S. dollar debt issued from Canada (2020 – US$5.9 billion). In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change to the foreign exchange (gain) loss as follows:

As at December 31,	2021		2020
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate		372		300
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate		(372)		(300)

Management believes the fluctuations identified in the table above are a reasonable measure of volatility.

C) Interest Rate Risk

Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations. Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt. To manage exposure to interest rate volatility, the Company periodically enters into interest rate swap contracts. As at December 31, 2021, Cenovus had no interest rate swap contracts outstanding (2020 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2021, Cenovus had no cross currency interest rate swap contracts outstanding (2020 – $nil).

As at December 31, 2021, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (2020 – $1 million). This assumes the amount of fixed and floating debt remains unchanged from respective balance sheet dates.

D) Credit Risk

Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in place a Credit Policy approved by the Audit Committee and the Board of Directors designed to ensure that its credit exposures are within an acceptable risk level. The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.

Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, net investment in finance leases, risk management assets and long-term receivables is the total carrying value.

As at December 31, 2021, approximately 97 percent of the Company’s accruals, receivables related to Cenovus’s joint ventures and joint operations, trade receivables and net investment in finance leases were investment grade, and substantially all of the Company’s accounts receivable were outstanding for less than 60 days. The average expected credit loss on the Company’s accruals, receivables related to Cenovus’s joint ventures and joint operations, trade receivables and net investment in finance leases was 0.1 percent as at December 31, 2021 (2020 – 0.5 percent).

150  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

E) Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 25, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA between 1.0 to 1.5 times to manage the Company’s overall debt position.

Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn capacity on its committed credit facility and uncommitted demand facilities as well as availability under its base shelf prospectus. As at December 31, 2021, the Company’s sources of capital included:

• 2.9 billion in cash and cash equivalents.

• $6.0 billion available on its committed credit facility.

• $1.9 billion available on its uncommitted demand facilities, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit.

• US$88 million and $5 million available on the Company’s proportionate share of the uncommitted demand facilities from WRB and Sunrise, respectively.

• US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market conditions.

Undiscounted cash outflows relating to financial liabilities are:

As at December 31, 2021	1 Year		Years 2 and 3		Years 4 and 5		Thereafter		Total
Accounts Payable and Accrued Liabilities		6,353		—		—		—		6,353
Short-Term Borrowings (1)		79		—		—		—		79
Long-Term Debt (1)(2)		561		1,608		2,603		14,892		19,664
Contingent Payment		238		—		—		—		238
Lease Liabilities (1)		453		794		634		3,192		5,073
As at December 31, 2020	1 Year		Years 2 and 3		Years 4 and 5		Thereafter		Total
Accounts Payable and Accrued Liabilities		2,018		—		—		—		2,018
Short-Term Borrowings (1)		121		—		—		—		121
Long-Term Debt (1)		385		1,965		1,966		8,627		12,943
Contingent Payment		36		28		—		—		64
Lease Liabilities (1)		254		445		365		1,412		2,476

(1) Principal and interest, including current portion if applicable.

(2) On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured notes on February 9, 2022. Long-term debt maturities above have not been adjusted for this redemption.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  151

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

37. SUPPLEMENTARY CASH FLOW INFORMATION

A) Working Capital

Working capital is calculated as follows:

As at December 31,	2021		2020
Total Current Assets		11,988		2,976
Total Current Liabilities		7,305		2,359
Working Capital		4,683		617

At December 31, 2021, adjusted working capital was $3.8 billion (December 31, 2020 – $653 million), excluding assets held for sale of $1.3 billion (December 31, 2020 – $nil), the current portion of the contingent payment of $236 million (December 31, 2020 – $36 million) and liabilities related to assets held for sale of $186 million (December 31, 2020 – $nil).

Changes in non-cash working capital is as follows:

For the years ended December 31,	2021		2020		2019
Accounts Receivable and Accrued Revenues		(953)		77		(475)
Income Tax Receivable		(1)		(12)		150
Inventories		(1,646)		450		(408)
Accounts Payable and Accrued Liabilities		1,645		(338)		283
Income Tax Payable		87		(17)		—
Total Non-Cash Working Capital		(868)		160		(450)
Cash From (Used in) Operating		(1,227)		198		(333)
Cash From (Used in) Investing		359		(38)		(117)
Total Non-Cash Working Capital		(868)		160		(450)
For the years ended December 31,	2021		2020		2019
Interest Paid		811		381		457
Interest Received		24		5		12
Income Taxes Paid		209		18		17

152  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

B) Reconciliation of Liabilities

The following table provides a reconciliation of liabilities to cash flows arising from financing activities:

	Dividends Payable		Short-Term         Borrowings		Long-Term Debt		Lease Liabilities
As at December 31, 2018		—		—		9,164		—
Adjustment for Change in Accounting Policy (1)		—		—		—		1,494
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt		—		—		(2,279)		—
Net Issuance (Repayment) of Revolving Long-Term Debt		—		—		276		—
Common Share Dividends Paid		(260)		—		—		—
Principal Repayment of Leases		—		—		—		(150)
Non-Cash Changes:
Common Share Dividends Declared		260		—		—		—
Foreign Exchange (Gain) Loss		—		—		(399)		(23)
Net Premium (Discount) on Redemption of Long-Term Debt		—		—		(63)		—
Lease Additions		—		—		—		590
Lease Terminations		—		—		—		(11)
Lease Re-measurements		—		—		—		15
Other		—		—		—		1
As at December 31, 2019		—		—		6,699		1,916
Changes From Financing Cash Flows:
Common Share Dividends Paid		(77)		—		—		—
Net Issuance (Repayment) of Short-Term Borrowings		—		117		—		—
Issuance of Long-Term Debt		—		—		1,326		—
(Repayment) of Long-Term Debt		—		—		(112)		—
(Repayment) of Revolving Long-Term Debt		—		—		(220)		—
Principal Repayment of Leases		—		—		—		(197)
Non-Cash Changes:
Common Share Dividends Declared		77		—		—		—
Foreign Exchange (Gain) Loss, Net		—		4		(231)		(6)
Net Premium (Discount) on Redemption of Long-Term Debt		—		—		(25)		—
Finance Costs		—		—		5		—
Lease Additions		—		—		—		49
Lease Terminations		—		—		—		(1)
Lease Modifications		—		—		—		(2)
Lease Re-measurements		—		—		—		(2)
Other		—		—		(1)		—
As at December 31, 2020		—		121		7,441		1,757

(1) Effective January 1, 2019, the Company adopted International Financial Reporting Standard 16, “Leases”.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  153

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

(Continued)	Dividends Payable		Short-Term         Borrowings		Long-Term Debt		Lease Liabilities
Acquisition (see Note 5A)		—		40		6,602		1,441
Changes From Financing Cash Flows:
Common Share Dividends Paid		(176)		—		—		—
Preferred Share Dividends Paid		(34)		—		—		—
Net Issuance (Repayment) of Short-Term Borrowings		—		(77)		—		—
Net Issuance (Repayment) of Revolving Long-Term Debt		—		—		(350)		—
Issuance of Long-Term Debt		—		—		1,557		—
(Repayment) of Long-Term Debt		—		—		(2,870)		—
Principal Repayment of Leases		—		—		—		(300)
Non-Cash Changes:
Common Share Dividends Declared		176		—		—		—
Preferred Share Dividends Declared		34		—		—		—
Foreign Exchange (Gain) Loss, Net		—		(5)		(57)		(10)
Net Premium (Discount) on Redemption of Long-Term Debt		—		—		121		—
Finance Costs		—		—		(59)		—
Lease Additions		—		—		—		110
Lease Terminations		—		—		—		(1)
Lease Modifications		—		—		—		22
Lease Re-Measurements		—		—		—		(4)
Transfers to Liabilities Related to Assets Held for Sale		—		—		—		(58)
As at December 31, 2021		—		79		12,385		2,957

38. COMMITMENTS AND CONTINGENCIES

A) Commitments

Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements. In addition, the Company has commitments related to its risk management program.

Future payments for the Company’s commitments are below:

As at December 31, 2021	1 Year		2 Years		3 Years		4 Years		5 Years		Thereafter		Total
Transportation and Storage (1)		3,288		3,567		3,373		2,146		2,012		16,600		30,986
Real Estate (2)		44		43		52		54		57		658		908
Obligation to Fund Equity-Accounted Affiliate (3)		68		85		99		90		90		210		642
Other Long-Term Commitments		509		156		145		136		150		1,214		2,310
Total Payments (4)		3,909		3,851		3,669		2,426		2,309		18,682		34,846
As at December 31, 2020	1 Year		2 Years		3 Years		4 Years		5 Years		Thereafter		Total
Transportation and Storage (1)		1,014		954		1,341		1,444		1,107		15,537		21,397
Real Estate (2)		34		36		38		41		44		604		797
Other Long-Term Commitments		105		47		32		32		24		85		325
Total Payments (4)		1,153		1,037		1,411		1,517		1,175		16,226		22,519

(1) Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement.

(2) Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for which a provision has been provided.

(3) Relates to funding obligations to HCML.

(4) Commitments are reflected at Cenovus’s proportionate share of the underlying contract.

154  |  CENOVUS ENERGY 2021 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All amounts in $ millions, unless otherwise indicated

For the year ended December 31, 2021

The Arrangement resulted in the assumption of Husky’s non-cancellable contracts and other commercial commitments. As at January 1, 2021, total commitments assumed by Cenovus were $17.6 billion, of which $7.4 billion were for various transportation and storage commitments. Transportation commitments include $1.7 billion that are subject to regulatory approval or have been approved, but are not yet in service.

As at December 31, 2021, the transportation and storage commitments did not include any amounts related to the Keystone XL pipeline due to the cancellation of the Company’s transportation services agreement (December 31, 2020 – $7.0 billion).

As at December 31, 2021, the Company had commitments with HMLP that include $2.6 billion related to transportation, storage and other long-term commitments.

As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31, 2020 – $441 million) issued as security for financial and performance conditions under certain contracts.

B) Contingencies

Legal Proceedings

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

Decommissioning Liabilities

Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of $3.9 billion, based on current legislation and estimated costs, related to its producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, retail and the crude-by-rail terminal. Actual costs may differ from those estimated due to changes in legislation and changes in costs.

Income Tax Matters

The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  155

 SUPPLEMENTAL INFORMATION (unaudited)

 Financial Statistics

	Three months ended															Twelve months ended
($ millions, except per share amounts)	Dec. 31, 2021			Sept. 30, 2021			Jun. 30, 2021			Mar. 31, 2021			Dec. 31, 2020			Dec. 31, 2021			Dec. 31, 2020
Revenues (1)
Upstream (2)		7,422			6,621			5,595			5,752			2,606			25,390			9,337
Downstream		8,135			7,530			6,318			4,690			1,124			26,673			4,815
Corporate and Eliminations		(1,831	)		(1,450	)		(1,276	)		(1,149	)		(187	)		(5,706	)		(609	)
Total Revenues		13,726			12,701			10,637			9,293			3,543			46,357			13,543
Operating Margin  (3) (6)
Upstream
Oil Sands		1,890			1,923			1,411			1,141			612			6,365			1,104
Conventional		260			191			142			210			82			803			195
Offshore (4)		408			328			340			344			—			1,420			—
Total Upstream Operating Margin (5)		2,558			2,442			1,893			1,695			694			8,588			1,299
Downstream
Canadian Manufacturing		131			130			189			82			16			532			45
U.S. Manufacturing		(97	)		122			96			91			(85	)		212			(423	)
Retail		8			16			6			11			—			41			—
Total Downstream Operating Margin (5)		42			268			291			184			(69	)		785			(378	)
Total Operating Margin (6)		2,600			2,710			2,184			1,879			625			9,373			921
Cash from Operating Activities and Adjusted Funds Flow
Total Cash from Operating Activities		2,184			2,138			1,369			228			250			5,919			273
Deduct (Add Back):
Settlement of Decommissioning Liabilities		(35	)		(38	)		(18	)		(11	)		(6	)		(102	)		(42	)
Net Change in Non-Cash Working Capital		271			(166	)		(430	)		(902	)		(77	)		(1,227	)		198
Total Adjusted Funds Flow (6)		1,948			2,342			1,817			1,141			333			7,248			117
Total Per Share Basic		0.97			1.16			0.90			0.57			0.27			3.59			0.10
Total Per Share Diluted		0.97			1.15			0.89			0.56			0.27			3.54			0.10
Net Earnings
Net Earnings (Loss)		(408	)		551			224			220			(153	)		587			(2,379	)
Per Share - Basic		(0.21	)		0.27			0.11			0.10			(0.12	)		0.27			(1.94	)
Per Share - Diluted		(0.21	)		0.27			0.11			0.10			(0.12	)		0.27			(1.94	)
Total Capital Investment
Oil Sands		402			198			201			218			90			1,019			427
Offshore																				—
Asia Pacific		—			18			1			2			—			21			—
Atlantic		45			51			34			24			—			154			—
Total Offshore		45			69			35			26			—			175			—
Conventional		87			41			28			66			39			222			78
Manufacturing
Canadian Manufacturing		14			9			10			4			11			37			33
U.S. Manufacturing		252			301			237			205			93			995			243
Total Manufacturing		266			310			247			209			104			1,032			276
Retail		9			16			5			1			—			31			—
Corporate		26			13			18			27			9			84			60
Total Capital Investment		835			647			534			547			242			2,563			841
Free Funds Flow (6)		1,113			1,695			1,283			594			91			4,685			(724	)

(1) Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending and operating expenses to conform with current treatment of inventory write-downs.

(2) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.

(3) Prior periods have been reclassified to conform with current period’s operating segments.

(4) Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture (“HCML”), which is accounted for using the equity method.

(5) Specified Financial Measure. See the Advisory.

(6) Non-GAAP Financial Measure. See the Advisory.

156  |  CENOVUS ENERGY 2021 ANNUAL REPORT

SUPPLEMENTAL INFORMATION (unaudited)

 Financial Statistics (continued)

	Three months ended										Twelve months ended
Financial Metrics	Dec. 31, 2021		Sept. 30, 2021		Jun. 30, 2021		Mar. 31, 2021		Dec. 31, 2020		Dec. 31, 2021		Dec. 31, 2020
Net Debt to Adjusted EBITDA (1)		1.2x		1.7x		2.8x		5.2x		11.9x		1.2x		11.9x
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings		(173.8)%										55.4%		26.3%
Foreign Exchange Rates
US$ per C$1
Average		0.794		0.794		0.814		0.790		0.768		0.798		0.746
Period End		0.789		0.785		0.807		0.795		0.785		0.789		0.785
RMB per C$1
Average		5.073		5.136		5.259		5.120		5.084		5.147		5.147
Common Share Information
Commons Shares Outstanding (millions)
Period End		2,001.2		2,017.6		2,017.6		2,017.5		1,228.9		2,001.2		1,228.9
Average - Basic		2,012.3		2,017.6		2,017.5		2,017.4		1,228.9		2,016.2		1,228.9
Average - Diluted		2,012.3		2,043.5		2,042.1		2,034.7		1,228.9		2,045.1		1,228.9
Dividends ($ per share)		0.0350		0.0175		0.0175		0.0175		—		0.0875		0.0625
Closing Price
TSX (C$ per share)		15.51		12.77		11.86		9.44		7.75		15.51		7.75
NYSE (US$ per share)		12.28		10.06		9.58		7.52		6.04		12.28		6.04
Share Volume Traded (millions)		1,485.7		1,243.6		1,341.4		1,618.4		1,419.0		5,689.1		5,644.5
Selected Average Benchmark Prices
Crude Oil Prices
US$/bbl
Brent (2)		79.73		73.47		68.83		60.90		44.22		70.73		41.67
West Texas Intermediate (“WTI”)		77.19		70.56		66.07		57.84		42.66		67.91		39.40
Differential Brent - WTI		2.54		2.91		2.76		3.06		1.56		2.82		2.27
Western Canadian Select at Hardisty (“WCS”)		62.55		56.98		54.58		45.37		33.36		54.87		26.80
Differential WTI - WCS		14.64		13.58		11.49		12.47		9.30		13.04		12.60
Mixed Sweet Blend		74.09		66.49		62.96		52.60		38.59		64.03		34.07
Condensate (C5 @ Edmonton)		79.13		69.24		66.40		58.04		42.54		68.20		37.16
Differential WTI - Condensate (Premium)/Discount		(1.94)		1.32		(0.33)		(0.20)		0.12		(0.29)		2.24
Synthetic @ Edmonton		75.40		68.98		66.41		54.32		39.60		66.28		36.25
Differential WTI - Synthetic (Premium)/Discount		1.79		1.58		(0.34)		3.52		3.06		1.63		3.15
C$/bbl
WCS		78.71		71.80		66.99		57.44		43.41		68.73		35.59
Synthetic @ Edmonton		94.94		86.92		81.53		68.77		51.59		83.04		48.59
Mixed Sweet Blend		93.29		83.77		77.28		66.59		50.23		80.23		45.33
Refining Benchmarks (US$/bbl)
Chicago 3-2-1 Crack Spreads (3)		16.06		20.67		20.50		12.93		7.05		17.54		7.54
Group 3 3-2-1 Crack Spreads (3)		15.82		20.35		19.44		15.67		7.57		17.82		8.67
Renewable Identification Numbers (“RINs”)		6.11		7.32		8.12		5.49		3.48		6.76		2.48
Natural Gas Prices
AECO 7A Monthly Index (C$/Mcf) (4)		4.94		3.54		2.85		2.92		2.77		3.56		2.24
NYMEX (US$/Mcf)		5.83		4.01		2.83		2.69		2.66		3.84		2.08
Differential NYMEX - AECO (US$/Mcf)		1.91		1.18		0.51		0.39		0.56		1.00		0.40

(1) Specified financial measure. See the Advisory.

(2) Calendar month average of settled prices for Dated Brent.

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

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

CENOVUS ENERGY 2021 ANNUAL REPORT  |  157

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Before Royalties

	Three months ended										Twelve months ended
Upstream Production Volumes	Dec. 31, 2021		Sept. 30, 2021		Jun. 30, 2021		Mar. 31, 2021		Dec. 31, 2020		Dec. 31, 2021		Dec. 31, 2020
Crude Oil and Natural Gas Liquids (Mbbls/d)
Oil Sands Bitumen
Foster Creek		211.8		187.1		156.8		163.1		158.1		179.9		163.2
Christina Lake		250.9		242.5		230.5		222.9		222.6		236.8		218.5
Sunrise		25.2		28.3		22.4		27.8		—		25.9		—
Lloydminster Thermal		99.0		98.0		97.7		96.0		—		97.7		—
Tucker		19.1		20.6		21.2		23.1		—		21.0		—
Oil Sands Heavy Crude Oil
Lloydminster Conventional Heavy Oil (1) (2)		18.9		20.5		20.8		20.5		—		20.2		—
Total Oil Sands		624.9		597.0		549.4		553.4		380.7		581.5		381.7
Conventional
Heavy Crude Oil		—		—		—		—		1.9		—		2.7
Light Crude Oil		7.2		8.7		9.2		8.7		4.3		8.4		4.5
Natural Gas Liquids (3)		22.5		22.8		29.0		28.2		18.4		25.6		19.5
Total Conventional		29.7		31.5		38.2		36.9		24.6		34.0		26.7
Offshore Natural Gas Liquids
Asia Pacific - China		10.4		9.9		9.6		10.2		—		10.0		—
Asia Pacific - Indonesia (4)		2.7		2.8		2.5		2.7		—		2.7		—
Offshore Light Crude Oil
Atlantic		10.6		13.9		15.2		16.9		—		14.1		—
Total Offshore		23.7		26.6		27.3		29.8		—		26.8		—
Total Liquids Production		678.3		655.1		614.9		620.1		405.3		642.3		408.4
Conventional Natural Gas (MMcf/d)
Oil Sands		12.4		11.9		13.1		13.0		—		12.6		—
Conventional (5)		574.3		603.2		618.4		594.5		369.5		597.6		379.0
Offshore
Asia Pacific - China		254.2		239.3		236.1		246.8		—		244.1		—
Asia Pacific - Indonesia (4)		42.6		43.5		38.0		40.6		—		41.2		—
Total Conventional Natural Gas Production		883.5		897.9		905.6		894.9		369.5		895.5		379.0
Total Production (5) (6) (MBOE/d)		825.3		804.8		765.9		769.3		467.2		791.5		471.7
Effective Royalty Rates(Excluding Realized Gain (Loss) on Risk Management) (7)
Oil Sands (8)
Foster Creek		24.5%		21.0%		20.4%		15.9%		5.9%		21.0%		7.9%
Christina Lake		26.4%		25.3%		21.4%		19.5%		16.6%		23.6%		14.4%
Sunrise		5.3%		5.6%		3.4%		2.3%		—		4.1%		—
Lloydminster Thermal		10.1%		11.0%		8.9%		5.4%		—		9.1%		—
Tucker		23.5%		22.4%		27.5%		16.8%		—		22.6%		—
Lloydminster Conventional Heavy Oil (1)		10.0%		6.9%		9.4%		7.3%		—		8.7%		—
Conventional		10.7%		11.2%		12.7%		6.9%		8.4%		10.3%		7.9%
Offshore
Asia Pacific - China		6.6%		6.0%		5.4%		5.3%		—		5.9%		—
Asia Pacific - Indonesia (4)		45.3%		19.5%		9.4%		13.6%		—		23.1%		—
Atlantic		6.0%		5.9%		7.6%		7.0%		—		6.7%		—

(1) This area was previously referred to as Lloydminster Cold/EOR.

(2) Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy oil production.

(3) Natural gas liquids include condensate volumes.

(4) Production volumes and associated royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

(5) Includes production used for internal consumption by the Oil Sands segment of 533 MMcf/d and 517 MMcf/d for the three months and twelve months ended December 31, 2021, respectively (344 MMcf/d and 336 MMcf/d for the three and twelve months ended December 31, 2020, respectively).

(6) Natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of six thousand cubic feet (“Mcf”) to one barrel (“bbl”). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

(7) Effective royalty rate is equal to royalty expense divided by product revenue net of transportation.

(8) Q4 2020 effective royalty rate for Christina Lake and Foster Creek reflects the annual weighted average unit price adjustments and audit adjustments related to prior periods. The Q4 2020 effective royalty rate, before the adjustments would be 14.4% and 6.8% for Christina Lake and Foster Creek, respectively.

158  |  CENOVUS ENERGY 2021 ANNUAL REPORT

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Netbacks

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is defined as gross sales less royalties, transportation and blending and operating expenses divided by sales volumes. Netbacks do not reflect the non-cash write-downs or reversals of product inventory until the product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The financial components of each netback are Specified Financial Measures.

The Oil Sands and Conventional netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Conventional segment and used as fuel by the Oil Sands segment. The consolidated netback is calculated on a net basis, after adjustments for natural gas produced by the Conventional segment and used as fuel by the Oil Sands segment.

	Three months ended										Twelve months ended
Oil Sands (1) (2)	Dec. 31, 2021		Sept. 30, 2021		Jun. 30, 2021		Mar. 31, 2021		Dec. 31, 2020		Dec. 31, 2021		Dec. 31, 2020
Foster Creek (3)
Bitumen ($/bbl)
Sales Price		72.86		69.79		67.98		54.10		41.52		66.50		30.80
Royalties		15.67		12.52		11.22		6.79		1.89		11.75		1.57
Transportation and Blending		9.27		10.14		12.25		10.98		9.74		10.51		11.05
Operating		10.31		10.20		12.18		10.73		10.34		10.74		9.24
Netback (4)		37.61		36.93		32.33		25.60		19.55		33.50		8.94
Christina Lake (3)
Bitumen ($/bbl)
Sales Price		65.49		64.15		59.38		50.84		37.20		60.22		27.04
Royalties		15.67		14.81		11.26		8.53		5.07		12.69		2.90
Transportation and Blending		6.32		5.74		6.10		6.65		6.55		6.19		6.95
Operating		8.82		7.83		7.95		8.38		7.50		8.24		6.79
Netback (4)		34.68		35.77		34.07		27.28		18.08		33.10		10.40
Sunrise (5)
Bitumen ($/bbl)
Sales Price		68.62		74.06		68.42		56.55		—		67.10		—
Royalties		3.06		2.64		2.03		0.92		—		2.23		—
Transportation and Blending		10.36		14.01		13.66		11.02		—		12.14		—
Operating		14.03		14.45		28.41		14.18		—		17.15		—
Netback (4)		41.17		42.96		24.32		30.43		—		35.58		—
Other Oil Sands (6) (7)
Bitumen & Heavy Crude Oil ($/bbl)
Sales Price		70.23		67.44		56.78		54.40		—		62.20		—
Royalties		7.95		7.65		6.33		3.71		—		6.40		—
Transportation and Blending		3.31		3.80		2.78		6.33		—		4.01		—
Operating		18.02		16.07		15.78		16.32		—		16.64		—
Netback (4)		40.95		39.92		31.89		28.04		—		35.15		—
Total Oil Sands (5) (8) ($/BOE)
Sales Price		69.00		67.08		61.16		52.86		39.02		62.82		28.64
Royalties		13.22		11.84		9.55		6.41		3.73		10.38		2.34
Transportation and Blending		6.76		7.09		7.08		8.06		7.90		7.23		8.70
Operating		11.76		10.90		12.00		11.49		8.70		11.52		7.84
Netback (4)		37.26		37.25		32.53		26.90		18.69		33.69		9.76

(1) Netbacks exclude risk management activities.

(2) The netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until the product is sold.

(3) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.

(4) Netback is a non-GAAP financial measure. The financial components of each netback are Specified Financial Measures. See the Advisory.

(5) Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have been represented to reflect a change in classification of marketing activities for the first, second, and third quarters of 2021.

(6) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil.

(7) Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy oil production.

(8) Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  159

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Netbacks (continued 1)

	Three months ended										Twelve months ended
	Dec. 31,		Sept. 30,		Jun. 30,		Mar. 31,		Dec. 31,		Dec. 31,		Dec. 31,
Conventional (1) (2)	2021		2021		2021		2021		2020		2021		2020
Total Conventional ($/BOE)
Sales Price		39.07		31.28		24.90		30.32		21.63		31.20		17.84
Royalties		4.01		3.32		2.98		2.00		1.65		3.06		1.23
Transportation and Blending		1.50		1.64		1.51		1.43		2.28		1.53		2.46
Operating		10.96		10.41		10.41		11.09		8.34		10.66		8.99
Netback (3)		22.60		15.91		10.00		15.80		9.36		15.95		5.16
Offshore (1)
Asia Pacific - China (4)
Natural Gas Liquids ($/bbl)
Sales Price		90.71		78.32		69.02		67.15		—		76.51		—
Royalties		5.30		4.46		3.92		3.79		—		4.38		—
Operating		5.19		5.86		4.96		4.71		—		5.18		—
Conventional Natural Gas ($/mcf)
Sales Price		12.39		12.01		11.51		11.67		—		11.90		—
Royalties		0.85		0.73		0.61		0.61		—		0.70		—
Operating		0.80		0.98		0.83		0.78		—		0.85		—
Asia Pacific - China Total (2) ($/BOE)
Sales Price		77.57		73.32		69.04		69.44		—		72.44		—
Royalties		5.15		4.39		3.71		3.70		—		4.25		—
Operating		4.88		5.87		4.96		4.71		—		5.10		—
Netback (3)		67.54		63.06		60.37		61.03		—		63.09		—
Asia Pacific - Indonesia (5)
Natural Gas Liquids ($/bbl)
Sales Price		108.68		94.39		86.14		79.28		—		92.36		—
Royalties		68.21		28.63		13.05		12.17		—		30.99		—
Operating		12.23		9.49		8.87		7.51		—		9.55		—
Conventional Natural Gas ($/mcf)
Sales Price		9.16		9.05		8.70		8.89		—		8.96		—
Royalties		2.95		1.12		0.49		1.12		—		1.45		—
Operating		2.01		1.60		1.48		1.25		—		1.59		—
Asia Pacific - Indonesia Total (2) ($/BOE)
Sales Price		69.72		65.39		61.79		60.68		—		64.52		—
Royalties		31.58		12.78		5.81		8.26		—		14.93		—
Operating		12.08		9.55		8.87		7.51		—		9.55		—
Netback (3)		26.06		43.06		47.11		44.91		—		40.04		—
Asia Pacific - Total (4) (5)
Natural Gas Liquids ($/bbl)
Sales Price		94.41		81.82		72.55		69.66		—		79.83		—
Royalties		18.25		9.73		5.80		5.53		—		9.95		—
Operating		6.64		6.65		5.77		5.29		—		6.10		—
Conventional Natural Gas ($/mcf)
Sales Price		11.93		11.56		11.12		11.28		—		11.48		—
Royalties		1.15		0.79		0.59		0.69		—		0.81		—
Operating		0.97		1.07		0.92		0.85		—		0.95		—
Asia Pacific - Total (2) ($/BOE)
Sales Price		76.34		71.99		67.93		68.08		—		71.19		—
Royalties		9.28		5.79		4.03		4.41		—		5.94		—
Operating		6.01		6.49		5.56		5.14		—		5.80		—
Netback (3)		61.05		59.71		58.34		58.53		—		59.45		—

(1) Netbacks exclude risk management activities.

(2) Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

(3) Non-GAAP financial measure. See the Advisory.

(4) Reported sales volumes include Cenovus’s working interest production from the Liwan gas project.

(5) Per unit values reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

160  |  CENOVUS ENERGY 2021 ANNUAL REPORT

SUPPLEMENTAL INFORMATION (unaudited)

Operating Statistics - Netbacks (continued 2)

	Three months ended										Twelve months ended
Offshore (continued)	Dec. 31,   2021		Sept. 30,   2021		Jun. 30,   2021		Mar. 31,   2021		Dec. 31,   2020		Dec. 31,   2021		Dec. 31,   2020
Atlantic (1)
Light Crude Oil ($/bbl)
Sales Price		103.63		94.26		86.07		81.37		—		91.01		—
Royalties		6.20		5.60		6.56		5.70		—		6.07		—
Transportation and Blending		3.62		3.99		2.10		2.84		—		3.02		—
Operating		32.61		29.44		25.24		26.56		—		28.34		—
Netback (2)		61.20		55.23		52.17		46.27		—		53.58		—
Total Operations (1) (3)  (4) (5) (6) (7) ($/BOE)
Total Operations
Sales Price		70.02		66.44		60.03		54.62		38.37		62.99		28.23
Royalties		12.76		11.10		8.83		6.15		3.81		9.80		2.41
Transportation and Blending		6.02		6.31		6.08		6.94		7.82		6.33		8.52
Operating		9.36		9.29		10.54		10.17		7.41		9.82		7.21
Netback (2)		41.88		39.74		34.58		31.36		19.33		37.04		10.09

(1) Netbacks exclude risk management activities.

(2) Non-GAAP financial measure. See the Advisory.

(3) Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

(4) Reported sales volumes include Cenovus’s working interest production from the Liwan gas project.

(5) Per unit values reflect Cenovus’s 40 percent interest in the Madura-Bd gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements.

(6) The netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until the product is sold.

(7) Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have been represented to reflect a change in classification of marketing activities for the first, second, and third quarters of 2021.

Downstream

	Three months ended										Twelve months ended
Canadian Manufacturing	Dec. 31,   2021		Sept. 30,   2021		Jun. 30,   2021		Mar. 31,   2021		Dec. 31,   2020		Dec. 31,   2021		Dec. 31,   2020
Total
Heavy Crude Oil processed (Mbbls/d)		108.3		108.3		103.5		106.2		—		106.5		—
Crude throughput capacity (Mbbls/d)		110.5		110.5		110.5		110.5		—		110.5		—
Utilization of Crude oil capacity (%) (1)		98%		98%		94%		96%		—		96%		—
Refining margin ($/bbl) (2)		23.60		22.89		29.78		18.40		—		23.64		—
Unit operating expense ($/bbl) (3)		10.44		9.83		9.89		9.69		—		9.97		—
Upgrader
Production (Mbbs/d)		81.7		82.0		77.3		79.7		—		80.2		—
Throughput (Mbbls/d) (4)		80.4		81.2		76.1		78.4		—		79.0		—
Upgrading differential ($/bbl)		19.71		17.00		16.53		14.01		—		16.83		—
Refining margin ($/bbl) (2)		21.05		16.93		16.90		16.64		—		17.99		—
Unit operating expense ($/bbl) (3)		7.44		7.43		7.44		7.53		—		7.28		—
Lloydminster Refinery
Production (Mbbls/d)		27.9		27.2		27.4		27.8		—		27.6		—
Throughput (Mbbls/d) (5)		27.9		27.1		27.4		27.8		—		27.5		—
Refining margin ($/bbl) (2)		13.25		19.29		18.03		12.43		—		15.64		—
Unit operating expense ($/bbl) (3)		9.81		7.86		7.93		7.75		—		8.35		—
Ethanol
Ethanol production (thousands of litres/d)		820.3		774.0		649.0		396.5		—		661.0		—
Rail Operations
Volumes loaded (Mbbls/d) (6)		9.6		14.3		3.1		21.6		20.4		12.1		30.4
Sales at U.S. Locations (Mbbls/d) (7)		8.1		13.9		2.2		25.1		14.7		12.3		33.9

(1) Based on crude oil name plate capacity.

(2) Non-GAAP financial measure. See the Advisory.

(3) Specified financial measure. See the Advisory.

(4) Upgrader throughput includes diluent returned to the field.

(5) Represents crude feedstock used in refinery.

(6) Volumes loaded and transported outside of Alberta.

(7) Includes sales volumes from third-party purchases.

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SUPPLEMENTAL INFORMATION (unaudited)

Downstream (continued)  

	Three months ended										Twelve months ended
U.S. Manufacturing	Dec. 31,   2021		Sept. 30,   2021		Jun. 30,   2021		Mar. 31,   2021		Dec. 31,   2020		Dec. 31,   2021		Dec. 31,   2020
Total
Crude Oil processed (Mbbls/d)		361.6		445.8		435.5		362.9		169.0		401.5		185.9
Heavy Crude Oil		155.8		143.8		136.7		119.6		66.6		138.7		74.6
Light/Medium Crude Oil		205.8		302.0		298.8		243.3		102.4		262.8		111.3
Crude throughput capacity (Mbbls/d)		502.5		502.5		502.5		502.5		247.5		502.5		247.5
Utilization of Crude oil capacity (%) (1)		72%		89%		87%		72%		68%		80%		75%
Refining margin ($/bbl) (2)		15.63		13.45		12.59		15.84		5.40		14.25		4.47
Unit operating expense ($/bbl) (3)		16.88		10.03		9.96		12.40		11.83		12.09		11.00
Refining  (4)
Lima Refinery throughput (Mbbs/d)		59.5		163.1		160.9		124.7		—		126.9		—
Superior Refinery throughput (Mbbls/d) (5)		—		—		—		—		—		—		—
WRB throughput (Mbbls/d) (6)		227.3		211.7		208.9		170.1		169.0		204.7		185.9
Toledo Refinery throughput (Mbbls/d) (6)		74.8		71.0		65.7		68.1		—		69.9		—
Retail
Number of fuel outlets		522		527		535		540		—		531		—
Fuel sales volume (millions of litres/d)		7.1		7.3		6.7		6.5		—		6.9		—
Fuel sales per retail outlet (thousands of  litres/d)		13.5		13.9		12.5		12.0		—		13.0		—
Production (Mbbls/d)
Canada
Transportation fuels
Distillate		10.8		10.6		9.5		9.0		—		10.0		—
Total Transportation fuels		10.8		10.6		9.5		9.0		—		10.0		—
Synthetic Crude Oil		55.3		56.4		53.0		54.8		—		54.9		—
Asphalt		15.6		15.5		15.4		15.4		—		15.5		—
Other		28.0		26.7		26.8		28.2		—		27.5		—
Total refined production		109.7		109.2		104.7		107.4		—		107.9		—
Ethanol		5.2		4.9		4.1		2.5		—		4.2		—
Total Canada		114.9		114.1		108.8		109.9		—		112.1		—
United States
Transportation fuels
Gasoline		192.1		230.1		213.5		188.2		95.9		205.3		97.3
Distillate		131.4		155.7		158.6		137.4		57.9		145.3		63.3
Total Transportation Fuels		323.5		385.8		372.1		325.6		153.8		350.6		160.6
Other		56.4		77.0		76.1		62.9		21.0		68.0		31.8
Total United States		379.9		462.8		448.2		388.5		174.8		418.6		192.4
Total		494.8		576.9		557.0		498.4		174.8		530.7		192.4

(1) Based on crude oil name plate capacity.

(2) Non-GAAP financial measure. See the Advisory.

(3) Specified financial measure. See the Advisory.

(4) Represents crude feedstock used in refinery.

(5) On April 26, 2018, the refinery experienced an incident while preparing for a major turnaround and was taken out of operation. The refinery is expected to restart around the first quarter of 2023.

(6) Represents Cenovus’s 50 percent interest in Wood River, Borger and Toledo refinery operations.

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ADVISORY

Oil and Gas Information

Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. 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 forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company 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.

This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress’, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil differentials; capturing value from crude oil and natural gas production; providing reliable, low-cost and ultimately low-carbon products; building an executional track record in U.S. manufacturing; being a leader in supplying responsibly produced oil; optimizing margin captured across the heavy oil value chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering value over the long-term; safety environmental performance; ESG leadership; Cenovus’s Indigenous Housing Initiative; free funds flow generation; debt reduction; shareholder value and returns; reinvestment in the business and diversification; maintaining a strong balance sheet; the Company’s longer-term Net Debt target; repurchasing outstanding notes; resuming projects; integrating sustainability considerations into the Company’s business decisions; achieving net zero greenhouse GHG emissions from oil sands operations by 2050; working collectively, through the Oil Sands pathways to Net Zero initiative, with the federal and provincial governments, to achieve net zero emissions by 2050 and help Canada meet its climate goals; energy security; the health and safety of the Company’s workforce and the public; short cycle, high return development wells; forecast capital investment; forecast production; first steam from Narrows Lake; initial production and exploration of new fields or projects; resumption or production of curtailed fields or projects; evaluating and making decisions regarding deferred projects; restart of Superior Refinery and West White Rose; near-term funding; maintaining the Company’s investment grade credit ratings; Net Debt to adjusted EBITDA ratio; risk reduction; maintaining capital discipline; adjusting capital and operating spending, drawing down on credit facilities or repaying existing debt, adjusting dividends paid to shareholders, repurchasing the Company’s common shares for cancellation, issuing new debt, or issuing new shares; evaluating all opportunities based on a US$45 per barrel WTI price; maintaining a prudent and flexible capital structure and strong balance sheet metrics; restructuring working interests in Atlantic Canada; financial resilience; liabilities from legal proceedings; delivering value; generating strong margins; the Company’s outlook for commodities and the Canadian dollar; upstream integration; mitigating the impact of crude oil and refined product prices and differentials; the Company’s five key strategic objectives and five ESG focus areas; embedding environmental, economic and social considerations in business decisions; cost savings, underlying cost structure and margin enhancements; improving efficiencies; sustaining the current dividend at US$45 WTI; and ramping production up or down. Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied.

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 term reserves life index may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not reflect the actual life of the reserves.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions on which the 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; the Company’s ability to realize the anticipated benefits and anticipated cost synergies of Arrangement ; the Company’s ability to successfully integrate the legacy Husky business with its own and any costs associated therewith; the accuracy of any assessments undertaken in connection with the Arrangement; forecast production volumes; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding; the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change), Indigenous relations, interest rates, inflation, foreign exchange rates, competitive conditions and the supply and demand for crude oil and natural gas, NGLs, condensate and refined products; the political, economic and social stability of jurisdictions in which the

CENOVUS ENERGY 2021 ANNUAL REPORT  |  163

Company operates; the absence of significant disruption of operations, including as a result of harsh weather, natural disaster, accident, civil unrest or other similar events; the prevailing climatic conditions in the Company’s operating locations; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product transportation capacity; increase to the Company’s share price and market capitalization over the long term; opportunities to purchase shares for cancellation at prices acceptable to the Company; the sufficiency of cash balances, internally generated cash flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue and fund future investments, sustainability and development plans and dividends, including any increase thereto; production from the Company’s Conventional segment providing an economic hedge for the natural gas required as a fuel source at both the Company’s oil sands and refining operations; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet produced, including that the Company will be able to time production and sales of our inventory at later dates when demand has increased, pipeline and/or storage capacity has improved and future crude oil differentials have narrowed; the WTI-WCS differential in Alberta remains largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of the Enbridge Inc.’s Line 3 Replacement Program, the completion of Trans Mountain Expansion project, and the level of crude-by-rail activity; the ability of the Company’s refining capacity, dynamic storage, existing pipeline commitments, crude-by-rail loading capacity and financial hedge transactions to partially mitigate a portion of the Company’s WCS crude oil volumes against wider differentials; the Company’s ability to produce from oil sands facilities on an unconstrained basis; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; the accuracy of accounting estimates and judgments; the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation of capital projects, development projects or stages thereof; the Company’s ability to generate sufficient cash flow to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability to complete acquisitions and dispositions, including with desired transaction metrics and within expected timelines; the accuracy of climate scenarios and assumptions, including third party data on which the Company relies; ability to access and implement all technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; continuing collaboration with the government, Oil Sands Pathways to Net Zero and other industry organizations; expected impacts of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment to ConocoPhillips; market and business conditions; forecast inflation and other assumptions inherent in Cenovus’s 2022 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and Cenovus’s ability to retain them; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.

2022 guidance, as updated December 7, 2021 and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices of US$71.00 per barrel; WCS of US$55.00 per barrel; Differential WTI-WCS of US$16.00 per barrel; AECO natural gas prices of $3.70 per thousand cubic feet; Chicago 3-2-1 crack spread of US$18.00 per barrel; and an exchange rate of $0.79 US$/C$.

The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking information, include, but are not limited to: the effect of the COVID-19 pandemic, including any variants thereof, on the Company’s business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the jurisdictions in which the Company operates; the success of the Company’s new COVID-19 workplace policies and the return of people to the Company’s workplace; the Company’s ability to realize the anticipated benefits of the Arrangement in a timely manner or at all; the Company’s ability to successfully integrate the legacy Husky business with its own in a timely and cost effective manner; unforeseen or underestimated liabilities associated with the Arrangement; risks associated with acquisitions and dispositions; the Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and achieve expected future results including in respect of climate and GHG emissions targets and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions; the effect of the Company’s increased indebtedness; the effect of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn; foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s continued liquidity is sufficient to sustain operations through a prolonged market downturn; WTI-WCS differential in Alberta does not remain largely tied to the extent to which voluntary economically driven supply cuts are made, the potential start-up of Enbridge Inc.’s Line 3 Replacement Program, the completion of the Trans Mountain Expansion project, and the level of crude-by-rail activity; the Company’s ability to achieve lower transportation costs as a result of temporarily suspending the crude-by-rail program; the Company’s ability to realize the expected impacts of its capacity to store within its oil sands reservoirs barrels not yet produced, including possible inability to time production and sales at later dates when pipeline and/or storage capacity and crude oil differentials have improved; the effectiveness of the Company’s risk management program, including the impact of derivative financial instruments, the success of the Company’s hedging strategies and the sufficiency of its liquidity positions; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to calculate the contingent payment

164  |  CENOVUS ENERGY 2021 ANNUAL REPORT

to ConocoPhillips; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions; market competition, including from alternative energy sources; risks inherent in the Company’s marketing operations, including credit risks, exposure to counterparties and partners, including the ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the operation of the Company’s crude-by-rail terminal, including health, safety and environmental risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; the Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to finance growth and sustaining capital expenditures; changes in credit ratings applicable to the Company or any of its securities; changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; the accuracy of the Company’s reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements; the Company’s ability to replace and expand crude oil and natural gas reserves; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project developments; potential requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of some or all of the Company’s assets or goodwill from time to time; the Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations and business; reliability of the Company’s 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 resulting in operational interruptions, including blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, gaseous leaks, migration of harmful substances, loss of containment, releases or spills, including releases or spills from offshore facilities and shipping vessels at terminals or hubs and as a result of pipeline or other leaks, corrosion, epidemics or pandemics, and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, iceberg incidents, acts of vandalism and terrorism, and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites and other accidents or similar events; refining and marketing margins; cost escalations, including inflationary pressures on operating costs, such as labour, materials, natural gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; the cost and availability of equipment necessary to the Company’s operations; potential failure of products to achieve or maintain acceptance in the market; risks associated with the energy industry’s and the Company’s reputation, social license to operate and litigation related thereto; unexpected cost increases or technical difficulties in operating, constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining bitumen and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its application to the Company’s business, including potential cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s ability to access markets and 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; availability of, and the Company’s ability to attract and retain, critical talent; possible failure to obtain and retain qualified leadership and personnel, and equipment in a timely and cost efficient manner; changes in labour demographics and relationships, including with any unionized workforces; unexpected abandonment and reclamation costs; changes in the regulatory frameworks, permits and approvals in any of the locations in which the Company operates or to any of the infrastructure upon which it relies; government actions or regulatory initiatives to curtail energy operations or pursue broader climate change agendas; changes to regulatory approval processes and land use designations, royalty, tax, environmental, GHG, 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 the Company’s business, its financial results and Consolidated Financial Statements; changes in general economic, market and business conditions; the impact of production agreements among OPEC and non-OPEC members; the political, social and economic conditions in the jurisdictions in which the Company operates or supplies; the status of the Company’s relationships with the communities in which it operates, including with Indigenous communicates; the occurrence of unexpected events such as protests, pandemics, war, terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against the Company. In addition, there are risks that the effect of actions taken by us in implementing targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations.

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 the Company’s material risk factors, see Risk Management and Risk Factors in the MD&A, and to the risk factors described in other documents the Company 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 Company’s website at cenovus.com.

Information on or connected to the Company’s website at cenovus.com does not form part of the MD&A unless expressly incorporated by reference herein.

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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 barrels of oil equivalent	GJ	gigajoule
WTI	West Texas Intermediate	AECO	Alberta Energy Company
WCS	Western Canadian Select	NYMEX	New York Mercantile Exchange
HSB	Husky Synthetic Blend

DEFINITIONS

Scope 1 emissions are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross operatorship basis. This includes fuel combustion, venting, flaring and fugitive emissions. It does not include emissions from the 50 percent non-operated ownership in the Company’s refineries or emissions from non-operated Conventional assets.

Scope 2 emissions are indirect emissions from the generation of purchased energy for the Company’s operated facilities. For Cenovus, this is limited to electricity imports.

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SPECIFIED FINANCIAL MEASURES

Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS including Operating Margin, Operating Margin for the Upstream or Downstream segment, Operating Margin by asset, Total Integration Costs, Adjusted Funds Flow, Free Funds Flow, Net Debt, Total Debt, Net Debt to Adjusted EBITDA Ratio, Net Debt to Capitalization ratio, Net Debt Target, Long-Term Financial Liabilities, Capital Investment by Asset, Gross Margin, Refining Margin, Unit Operating Costs, Forward-looking Operating Costs per Barrel, Forward-looking Capital Investment, Forward-looking Integration Costs, Per Unit DD&A and Netbacks (including the per BOE components of netbacks and total netbacks per BOE).

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 financial measure or specified financial measure is presented in this Advisory and may also be presented in the Operating and Financial Results or Liquidity and Capital Resources sections of the MD&A.

Operating Margin

Operating Margin and Operating Margin by asset are non-GAAP financial measures used to provide a consistent measure of the cash generating performance of our operations and assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses, plus realized gains less realized losses on risk management activities. Items within Corporate and Eliminations are excluded from the calculation of Operating Margin.

	Upstream						Downstream										Total
Year ended December 31, ($ millions)		2021		2020		2019		2021		2020			2019			2021		2020		2019
Revenues
Gross Sales (1)		27,844		9,708		14,036		26,673		4,815			8,368			54,517		14,523		22,404
Less: Royalties (2)		2,454		371		1,173		—		—			—			2,454		371		1,173
	25,390		9,337		12,863		26,673		4,815			8,368			52,063		14,152		21,231
Expenses
Purchased Product (1)(2)		4,843		1,530		2,471		23,526		4,429			6,735			28,369		5,959		9,206
Transportation and Blending (2)		7,930		4,764		5,234		—		—			—			7,930		4,764		5,234
Operating (2)		3,241		1,476		1,406		2,258		785			918			5,499		2,261		2,324
Realized (Gain) Loss on Risk Management		788		268		23		104		(21	)		(16	)		892		247		7
Operating Margin		8,588		1,299		3,729		785		(378	)		731			9,373		921		4,460

(1) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

(2) Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

								2021
	Upstream					Downstream						Total
($ millions)		Q4	Q3	Q2	Q1		Q4		Q3	Q2	Q1		Q4	Q3	Q2	Q1
Revenues
Gross Sales (1)		8,237	7,354	6,128	6,125		8,135		7,530	6,318	4,690		16,372	14,884	12,446	10,815
Less: Royalties		815	733	533	373		—		—	—	—		815	733	533	373
		7,422	6,621	5,595	5,752		8,135		7,530	6,318	4,690		15,557	14,151	11,913	10,442
Expenses
Purchased Product (1)		1,410	1,270	921	1,242		7,348		6,708	5,502	3,968		8,758	7,978	6,423	5,210
Transportation and Blending		2,387	1,941	1,802	1,800		—		—	—	—		2,387	1,941	1,802	1,800
Operating		865	800	791	785		689		537	515	517		1,554	1,337	1,306	1,302
Realized (Gain) Loss on Risk
Management		202	168	188	230		56		17	10	21		258	185	198	251
Operating Margin		2,558	2,442	1,893	1,695		42		268	291	184		2,600	2,710	2,184	1,879

(1) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  167

	2020
	Upstream									Downstream												Total
($ millions)	Q4		Q3		Q2		Q1			Q4			Q3			Q2			Q1			Q4		Q3		Q2		Q1
Revenues
Gross Sales (1)		2,749		2,746		1,566		2,647			1,124			1,252			857			1,582			3,873		3,998		2,423		4,229
Less: Royalties (2)		143		153		21		54			—			—			—			—			143		153		21		54
Expenses		2,606		2,593		1,545		2,593			1,124			1,252			857			1,582			3,730		3,845		2,402		4,175
Purchased Product (1) (2)		334		389		350		457			1,016			1,133			549			1,731			1,350		1,522		899		2,188
Transportation and Blending (2)		1,149		1,036		651		1,928			—			—			—			—			1,149		1,036		651		1,928
Operating (2)		389		367		316		404			192			187			186			220			581		554		502		624
Realized (Gain) Loss on Risk Management		40		137		66		25			(15	)		2			(7	)		(1	)		25		139		59		24
Operating Margin		694		664		162		(221	)		(69	)		(70	)		129			(368	)		625		594		291		(589	)

(1) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

(2) Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current presentation of inventory write-downs.

Operating Margin by Asset

	2021
Year ended December 31, ($ millions)	Asia Pacific		Atlantic		Offshore (1)
Revenues
Gross Sales		1,342		440		1,782
Less: Royalties		79		29		108
		1,263		411		1,674
Expenses
Transportation and Blending		—		15		15
Operating		103		136		239
Operating Margin		1,160		260		1,420

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

	2021
	Asia Pacific								Atlantic								Offshore (1)
($ millions)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Revenues
Gross Sales		377		336		308		321		143		68		119		110		520		404		427		431
Less: Royalties		26		20		16		17		8		4		9		8		34		24		25		25
		351		316		292		304		135		64		110		102		486		380		402		406
Expenses
Transportation and Blending		—		—		—		—		5		3		3		4		5		3		3		4
Operating		29		28		24		22		44		21		35		36		73		49		59		58
Operating Margin		322		288		268		282		86		40		72		62		408		328		340		344

(1) Found in Note 1 of the interim consolidated financial statements.

Total Integration Costs

Total Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Arrangement, excluding share issuance costs.

			2021
($ millions)	2021		Q4		Q3		Q2		Q1
Integration Costs (1)		349		47		45		34		223
Capitalized Integration Costs (2)		53		4		15		12		22
Total Integration Costs		402		51		60		46		245

(1) Per the Consolidated Statements of Earnings (Loss) and interim consolidated financial statements.

(2) Included in Capital Expenditures on the Consolidated Statements of Cash Flows.

168  |  CENOVUS ENERGY 2021 ANNUAL REPORT

Adjusted Funds Flow and Free Funds Flow

Adjusted Funds Flow is a non-GAAP financial 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 settlement of decommissioning liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable.

Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of decommissioning liabilities and net change in non-cash working capital minus capital investment.

Year ended December 31, ($ millions)	2021			2020			2019
Cash From (Used in) Operating Activities		5,919			273			3,285
(Add) Deduct:
Settlement of Decommissioning Liabilities		(102	)		(42	)		(52	)
Net Change in Non-Cash Working Capital		(1,227	)		198			(333	)
Adjusted Funds Flow (2)		7,248			117			3,670
Capital Investment		2,563			841			1,176
Free Funds Flow (2)		4,685			(724	)		2,494

(1) Comparative figures have been restated to conform with the definition in the MD&A.

	2021												2020
($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Cash From (Used in) Operating Activities		2,184			2,138			1,369			228			250			732			(834	)		125
(Add) Deduct:
Settlement of Decommissioning Liabilities		(35	)		(38	)		(18	)		(11	)		(6	)		(3	)		(2	)		(31	)
Net Change in Non-Cash Working Capital		271			(166	)		(430	)		(902	)		(77	)		328			(363	)		310
Adjusted Funds Flow (1)		1,948			2,342			1,817			1,141			333			407			(469	)		(154	)
Capital Investment		835			647			534			547			242			148			147			304
Free Funds Flow (1)		1,113			1,695			1,283			594			91			259			(616	)		(458	)

(1) Comparative figures have been restated to conform with the definition in the MD&A.

Net Debt, Total Debt, Net Debt Target, Net Debt to Capitalization Ratio, Net Debt to Adjusted EBITDA Ratio and Net Debt to Adjusted EBITDA Ratio Target

These measures are used to steward our overall debt position and as measures of our overall financial strength.

Net Debt is a specified financial measure used to monitor our capital structure. Our forward-looking Net Debt Target is the desired amount of Net Debt that the Company strives to achieve and maintain. Net Debt is defined as Total Debt net of cash and cash equivalents and short-term investments. Total Debt is defined as short-term borrowings plus the current and long-term portions of long-term debt.

We define Capitalization as Net Debt plus Shareholders’ Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense (recovery), DD&A, exploration expense, goodwill impairments, unrealized gains (losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated on a trailing 12-month basis.

Our forward-looking Net Debt to Adjusted EBITDA Ratio Target is the desired Net Debt to Adjusted EBITDA Ratio that the Company strives to achieve and maintain.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  169

As at ($ millions)	December 31,       2021			January 1,     2021 (1)			December 31,       2020			December 31,       2019
Short-Term Borrowings		79			161			121			—
Current Portion of Long-Term Debt		—			—			—			—
Long-Term Debt		12,385			14,043			7,441			6,699
Total Debt		12,464			14,204			7,562			6,699
Less: Cash and Cash Equivalents		(2,873	)		(1,113	)		(378	)		(186	)
Net Debt		9,591			13,091			7,184			6,513
Shareholders’ Equity		23,596						16,707			19,201
Capitalization		33,187						23,891			25,714
Net Debt to Capitalization Ratio (percent)		29						30			25
Adjusted EBITDA		8,086						606			4,143
Net Debt to Adjusted EBITDA Ratio (times)		1.2						11.9			1.6

(1) Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement. The fair value of amounts assumed from the Arrangement are short-term borrowings of $40 million, long-term debt of $6.6 billion, and cash and cash equivalents of $735 million.

	2021												2020
As at ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Short-Term Borrowings		79			48			65			266			121			137			299			602
Current Portion of Long-Term Debt		—			545			632			—			—			—			—			—
Long-Term Debt		12,385			12,441			12,748			13,947			7,441			7,797			8,085			6,979
Total Debt		12,464			13,034			13,445			14,213			7,562			7,934			8,384			7,581
Less: Cash and Cash Equivalents		(2,873	)		(2,010	)		(1,055	)		(873	)		(378	)		(404	)		(152	)		(160	)
Net Debt		9,591			11,024			12,390			13,340			7,184			7,530			8,232			7,421
Shareholders’ Equity		23,596			24,373			23,629			23,618			16,707			17,032			17,311			17,734
Capitalization		33,187			35,397			36,019			36,958			23,891			24,562			25,543			25,155
Net Debt to Capitalization Ratio (percent)		29			31			34			36			30			31			32			30
Adjusted EBITDA		8,086			6,327			4,369			2,584			606			900			1,360			2,386
Net Debt to Adjusted EBITDA Ratio (times)		1.2			1.7			2.8			5.2			11.9			8.4			6.1			3.1

Total Long-Term Liabilities

Total Long-Term Liabilities is a non-GAAP financial measure. The measure is disclosed to fulfill the requirements of National Instrument 51-102, “Continuous Disclosure Obligations” and is defined as total liabilities less total current liabilities.

As at December 31, ($ millions)	2021		2020		2019
Long-Term Debt		12,385		7,441		6,699
Lease Liabilities		2,685		1,573		1,720
Contingent Payment		—		27		64
Decommissioning Liabilities		3,906		1,248		1,235
Other Liabilities		929		181		241
Deferred Income Taxes		3,286		3,234		4,032
Total Long-Term Liabilities		23,191		13,704		13,991

Capital Investment by Asset and Forward-Looking Capital Investment

Capital Investment by asset is a specified financial measure that represents historical capital expenditures for the assets identified. Forward-looking capital investment is a specified financial measure representing anticipated future capital expenditures.

Gross Margin, Refining Margin and Unit Operating Expense

Gross Margin, Refining Margin and Unit Operating Expense are specified financial measures used to evaluate performance of our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross Margin divided by barrels of crude throughput. We define Unit Operating Expense as operating expenses divided by barrels of crude throughput.

170  |  CENOVUS ENERGY 2021 ANNUAL REPORT

Canadian Manufacturing

	2021
Year ended December 31, ($ millions)	Lloydminster    Upgrader		Lloydminster    Refinery		Other (1)		Per Consolidated     Financial Statements
Revenues		2,559		817		1,096		4,472
Purchased Product		2,041		659		852		3,552
Gross Margin		518		158		244		920
	Operating Statistics
	Lloydminster    Upgrader		Lloydminster    Refinery				Consolidated
Crude Throughput (Mbbls/d)		79.0		27.5				106.5
Refining Margin ($/bbl)		17.99		15.64				23.64

(1) Includes ethanol and crude-by-rail operations, and marketing activities.

	2021
	Lloydminster Upgrader								Lloydminster Refinery								Other (1)								Per Consolidated Interim   Financial Statements
($ millions)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Revenues		748		684		601		526		206		278		197		136		409		253		290		144		1,363		1,215		1,088		806
Purchased Product		592		556		484		409		172		230		152		105		364		200		171		117		1,128		986		807		631
Gross Margin		156		128		117		117		34		48		45		31		45		53		119		27		235		229		281		175
	Operating Statistics
	Lloydminster Upgrader								Lloydminster Refinery																Consolidated
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1										Q4		Q3		Q2		Q1
Crude Throughput (Mbbls/d)		80.4		81.2		76.1		78.4		27.9		27.1		27.4		27.8										108.3		108.3		103.5		106.2
Refining Margin ($/bbl)		21.05		16.93		16.90		16.64		13.25		19.29		18.03		12.43										23.60		22.89		29.78		18.40

(1) Includes ethanol and crude-by-rail operations, and marketing activities.

U.S. Manufacturing

Year ended December 31, ($ millions)	2021		2020 (1)		2019 (1)
Revenues (2)		20,043		4,733		8,291
Purchased Product (2)		17,955		4,429		6,735
Gross Margin		2,088		304		1,556
Crude Throughput (Mbbls/d)		401.5		185.9		221.3
Refining Margin ($/bbl)		14.25		4.47		19.26

(1) Prior periods have been reclassified to conform with current period’s operating segments.

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

CENOVUS ENERGY 2021 ANNUAL REPORT  |  171

	2021								2020 (1)
($ millions)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Revenues (2)		6,154		5,723		4,729		3,437		1,100		1,237		841		1,555
Purchased Product (2)		5,635		5,171		4,229		2,920		1,016		1,133		549		1,731
Gross Margin		519		552		500		517		84		104		292		(176	)
Crude Throughput (Mbbls/d)		361.6		445.8		435.5		362.9		169.0		191.1		162.3		221.1
Refining Margin ($/bbl)		15.63		13.45		12.59		15.84		5.40		5.91		19.77		(8.75	)

(1) Prior periods have been reclassified to conform with current period’s operating segments.

(2) Found in Note 1 of the interim consolidated financial statements.

Retail ⁽¹⁾

($ millions)	Three Months Ended   December 31, 2021		Year Ended   December 31, 2021
Revenues		618		2,158
Purchased Product		585		2,019
Gross Margin		33		139

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

Per Unit DD&A

Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit of production basis. We define Per Unit DD&A as DD&A divided by production.

Year Ended   December 31, 2021 ($ millions)	Per Consolidated   Financial   Statements  (1)		(Impairments) Reversals		Equity Adjustment (2)		Other			Basis of DD&A per   BOE calculation
Oil Sands		2,666		—		—		(263	)		2,403
Conventional		3		378		—		63			444
Offshore		492		—		70		134			696

Year Ended   December 31, 2020 ($ millions)	Per Consolidated   Financial   Statements (1)		(Impairments) Reversals			Other			Basis of DD&A per   BOE calculation
Oil Sands		1,687		—			(238	)		1,449
Conventional		880		(555	)		(2	)		323

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

(2) Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

172  |  CENOVUS ENERGY 2021 ANNUAL REPORT

Netback Reconciliations

Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Our Netback calculation is aligned with the definition found 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 and operating expenses divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.

The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated Financial Statements. Netback reconciliations for the first, second and third quarters of 2021 can be found in the respective quarters’ MD&A, with the exception of Upstream and Oil Sands results which have been represented below.

Total Production

Upstream Financial Results

	Per       Consolidated Financial Statements		Adjustments															Basis of   Netback         Calculation
Year Ended   December 31, 2021 ($ millions)	Total Upstream (1)		Condensate			Third-party Sourced			Internal Consumption (2)			Equity Adjustment (3)			Other (4)			Total   Upstream
Gross Sales		27,844		(6,311	)		(4,545	)		(710	)		224			(390	)		16,112
Royalties		2,454		—			—			—			52			—			2,506
Purchased Product		4,843		—			(4,545	)		—			—			(298	)		—
Transportation and Blending		7,930		(6,311	)		—			—			—			—			1,619
Operating		3,241		—			(8	)		(710	)		25			(36	)		2,512
Netback		9,376		—			8			—			147			(56	)		9,475
Realized (Gain) Loss on Risk Management		788		—			(2	)		—			—			—			786
Operating Margin		8,588		—			10			—			147			(56	)		8,689
	Per Consolidated Financial Statements		Adjustments															Basis of Netback Calculation
Year Ended   December 31, 2020 ($ millions) (6)	Total Upstream (1)		Condensate			Third-party Sourced (5)			Inventory Write- Down  (7)			Internal Consumption  (2)			Other (4)			Total Upstream
Gross Sales (5)		9,708		(3,452	)		(1,559	)		—			(295	)		(58	)		4,344
Royalties		371		—			—			(1	)		—			—			370
Purchased Product (5)		1,530		—			(1,559	)		—			—			29			—
Transportation and Blending		4,764		(3,452	)		—			1			—			—			1,313
Operating		1,476		—			—			—			(295	)		(72	)		1,109
Netback		1,567		—			—			—			—			(15	)		1,552
Realized (Gain) Loss on Risk Management		268		—			—			—			—			—			268
Operating Margin		1,299		—			—			—			—			(15	)		1,284
			Per Consolidated Financial Statements															Basis of Netback Calculation
Year Ended   December 31, 2019 ($ millions) (6)			Total Upstream (1)			Condensate			Third-party Sourced (5)			Internal Consumption (2)			Other (4)			Total Upstream
Gross Sales (5)				14,036			(4,021	)		(2,507	)		(222	)		(64	)		7,222
Royalties				1,173			—			—			—			(7	)		1,166
Purchased Product (5)				2,471			—			(2,507	)		—			36			—
Transportation and Blending				5,234			(4,021	)		—			—			1			1,214
Operating				1,406			—			—			(222	)		(63	)		1,121
Netback				3,752			—			—			—			(31	)		3,721
Realized (Gain) Loss on Risk Management				23			—			—			—			—			23
Operating Margin				3,729			—			—			—			(31	)		3,698

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

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

(3) Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(4) Other includes construction, transportation and blending and third-party processing margin.

(5) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

(6) Prior periods have been reclassified to conform with current period’s operating segments.

(7) Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  173

	Per Interim        Consolidated        Financial        Statements		Adjustments														Basis of        Netback              Calculation
Three Months Ended   December 31, 2021 ($ millions)	Total        Upstream  (1)		Condensate			Third-Party Sourced			Internal Consumption (2)			Equity Adjustment (3)		Other (4)(7)			Total        Upstream
Gross Sales		8,237		(1,989	)		(1,291	)		(241	)		62		(146	)		4,632
Royalties		815		—			—			—			29		—			844
Purchased Product		1,410		—			(1,291	)		—			—		(119	)		—
Transportation and Blending		2,387		(1,989	)		—			—			—		—			398
Operating		865		—			(8	)		(241	)		7		(3	)		620
Netback		2,760		—			8			—			26		(24	)		2,770
Realized (Gain) Loss on Risk Management		202		—			—			—			—		—			202
Operating Margin		2,558		—			8			—			26		(24	)		2,568

	Per Interim Consolidated Financial Statements		Adjustments												Basis of Netback Calculation
Three Months Ended December 31, 2020 ($ millions) (5)	Total Upstream  (1)		Condensate			Third-party Sourced			Internal Consumption  (2)			Other (4)			Total Upstream
Gross Sales (8)		2,749		(853	)		(339	)		(92	)		(16	)		1,449
Royalties		143		—			—			—			—			143
Purchased Product (8)		334		—			(339	)		—			5			—
Transportation and Blending		1,149		(853	)		—			—			—			296
Operating		389		—			—			(92	)		(18	)		279
Netback		734		—			—			—			(3	)		731
Realized (Gain) Loss on Risk Management		40		—			—			—			—			40
Operating Margin		694		—			—			—			(3	)		691

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

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

(3) Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(4) Other includes construction, transportation and blending and third-party processing margin.

(5) Prior periods have been reclassified to conform with current period’s operating segments.

(6) Realization of prior period inventory write-down reversals.

(7) Sunrise gross sales, transportation and blending and operating costs have been represented to reflect a change in classification of marketing activities for the third quarter of 2021.

(8) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

Oil Sands

	Basis of Netback Calculation
Year Ended   December 31, 2021 ($ millions)	Foster Creek		Christina Lake		Sunrise		Other Oil Sands (2)		Total Bitumen and Heavy Oil		Natural Gas			Total Oil Sands
Gross Sales		4,341		5,115		616		3,212		13,284		13			13,297
Royalties		767		1,078		20		330		2,195		1			2,196
Purchased Product		—		—		—		—		—		—			—
Transportation and Blending		686		526		111		207		1,530		—			1,530
Operating		701		700		157		858		2,416		21			2,437
Netback		2,187		2,811		328		1,817		7,143		(9	)		7,134
Realized (Gain) Loss on Risk Management															786
Operating Margin															6,348

	Basis of Netback Calculation		Adjustments						Per Consolidated Financial Statements (1)
Year Ended   December 31, 2021 ($ millions)	Total Oil Sands		Condensate		Third-party Sourced		Other (3)		Total Oil Sands
Gross Sales		13,297		6,311		2,890		329		22,827
Royalties		2,196		—		—		—		2,196
Purchased Product		—		—		2,890		298		3,188
Transportation and Blending		1,530		6,311		—				7,841
Operating		2,437		—		—		14		2,451
Netback		7,134		—		—		17		7,151
Realized (Gain) Loss on Risk Management		786		—		—		—		786
Operating Margin		6,348		—		—		17		6,365

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

(2) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

(3) Other includes construction, transportation and blending margin.

174  |  CENOVUS ENERGY 2021 ANNUAL REPORT

	Basis of Netback Calculation
Year Ended December 31, 2020 ($ millions)	Foster Creek		Christina Lake		Total Oil Sands
Gross Sales		1,859		2,194		4,053
Royalties		95		235		330
Purchased Product		—		—		—
Transportation and Blending		667		565		1,232
Operating		558		551		1,109
Netback		539		843		1,382
Realized (Gain) Loss on Risk Management						268
Operating Margin						1,114

	Basis of Netback Calculation		Adjustments										Per Consolidated      Financial Statements (1)
Year Ended   December 31, 2020 ($ millions) (3)	Total Oil Sands		Condensate		Third-party Sourced		Inventory Write- down (5)			Other			Total Oil Sands
Gross Sales (6)		4,053		3,452		1,290		—			9		8,804
Royalties		330		—		—		1			—		331
Purchased Product (6)		—		—		1,290		—			(28	)	1,262
Transportation and Blending		1,232		3,452		—		(1	)		—		4,683
Operating		1,109		—		—		—			47		1,156
Netback		1,382		—		—		—			(10	)	1,372
Realized (Gain) Loss on Risk Management		268		—		—		—			—		268
Operating Margin		1,114		—		—		—			(10	)	1,104

	Basis of Netback Calculation
Year Ended   December 31, 2019 ($ millions)	Foster Creek		Christina Lake		Total Oil Sands
Gross Sales		3,295		3,511		6,806
Royalties		486		650		1,136
Purchased Product		—		—		—
Transportation and Blending		674		458		1,132
Operating		526		505		1,031
Netback		1,609		1,898		3,507
Realized (Gain) Loss on Risk Management						23
Operating Margin						3,484

	Basis of Netback     Calculation	Adjustments							Per Consolidated   Financial Statements (1)
Year Ended   December 31, 2019 ($ millions)	Total Oil Sands	Condensate		Third-party Sourced		Other (3)			Total Oil Sands
Gross Sales (6)	6,806		4,021		2,263		11			13,101
Royalties	1,136		—		—		7			1,143
Purchased Product (6)	—		—		2,263		(32	)		2,231
Transportation and Blending	1,132		4,021		—		(1	)		5,152
Operating	1,031		—		—		36			1,067
Netback	3,507		—		—		1			3,508
Realized (Gain) Loss on Risk Management	23		—		—		—			23
Operating Margin	3,484		—		—		1			3,485

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

(2) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

(3) Other includes construction, transportation and blending margin.

(4) Prior periods have been reclassified to conform with current period’s operating segments.

(5) Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.

(6) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  175

	Basis of Netback Calculation
Three Months Ended   December 31, 2021 ($ millions)	Foster Creek		Christina Lake		Sunrise(6)		Other Oil Sands (2)		Total Bitumen   and Heavy Oil		Natural Gas			Total Oil sands
Gross Sales		1,304		1,441		189		903		3,837		4			3,841
Royalties		280		345		7		102		734		—			734
Purchased Product		—		—		—		—		—		—			—
Transportation and Blending		166		140		28		42		376		—			376
Operating		184		194		39		230		647		6			653
Netback		674		762		115		529		2,080		(2	)		2,078
Realized (Gain) Loss on Risk Management															202
Operating Margin															1,876

	Basis of Netback   Calculation		Adjustments						Per Consolidated      Financial Statements  (1)
Three Months Ended   December 31, 2021 ($ millions)	Total Oil Sands		Condensate		Third-party Sourced		Other (3)(6)		Total Oil Sands
Gross Sales		3,841		1,989		749		138		6,717
Royalties		734		—		—		—		734
Purchased Product		—		—		749		119		868
Transportation and Blending		376		1,989		—		—		2,365
Operating		653		—		—		5		658
Netback		2,078		—		—		14		2,092
Realized (Gain) Loss on Risk Management		202		—		—		—		202
Operating Margin		1,876		—		—		14		1,890

	Basis of Netback Calculation
Three Months Ended   December 31, 2020 ($ millions)	Foster Creek		Christina Lake		Total Bitumen  and Heavy Oil		Total Oil Sands
Gross Sales		615		756		1,371		1,371
Royalties		28		103		131		131
Purchased Product		—		—		—		—
Transportation and Blending		144		134		278		278
Operating		154		152		306		306
Netback		289		367		656		656
Realized (Gain) Loss on Risk Management								40
Operating Margin								616

	Basis of Netback  Calculation		Adjustments							Per Consolidated  Financial Statements  (1)
Three Months Ended   December 31, 2020 ($ millions) (4)	Total Oil Sands		Condensate		Third-party Sourced		Other			Total Oil Sands
Gross Sales (7)		1,371		853		256		1			2,481
Royalties		131		—		—		—			131
Purchased Product (7)		—		—		256		(6	)		250
Transportation and Blending		278		853		—		—			1,131
Operating		306		—		—		11			317
Netback		656		—		—		(4	)		652
Realized (Gain) Loss on Risk Management		40		—		—		—			40
Operating Margin		616		—		—		(4	)		612

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

⁽²⁾  Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

⁽³⁾  Other includes construction, transportation and blending margin.

⁽⁴⁾  Prior periods have been reclassified to conform with current period’s operating segments.

⁽⁵⁾  Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.

(6) Sunrise gross sales, transportation and blending and operating expenses have been re-presented to reflect a change in classification of marketing activities for the third quarter of 2021.

(7) Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.

176  |  CENOVUS ENERGY 2021 ANNUAL REPORT

Conventional

	Basis of Netback Calculation		Adjustments						Per Consolidated Financial  Statements (1)
Year Ended   December 31, 2021 ($ millions)	Conventional		Third-party Sourced			Other (2)			Conventional
Gross Sales		1,519		1,655			61			3,235
Royalties		150		—			—			150
Purchased Product		—		1,655			—			1,655
Transportation and Blending		74		—			—			74
Operating		521		8			22			551
Netback		774		(8	)		39			805
Realized (Gain) Loss on Risk Management		—		2			—			2
Operating Margin		774		(10	)		39			803
	Basis of Netback Calculation		Adjustments						Per Consolidated Financial  Statements (1)
Year Ended   December 31, 2020 ($ millions) (3)	Conventional		Third-party Sourced			Other (2)			Conventional
Gross Sales		586		269			49			904
Royalties		40		—			—			40
Purchased Product		—		269			(1	)		268
Transportation and Blending		81		—						81
Operating		295		—			25			320
Netback		170		—			25			195
Realized (Gain) Loss on Risk Management		—		—			—			—
Operating Margin		170		—			25			195
	Basis of Netback Calculation		Adjustments						Per Consolidated Financial  Statements (1)
Year Ended   December 31, 2019 ($ millions) (3)	Conventional		Third-party Sourced			Other (2)			Conventional
Gross Sales		638		244			53			935
Royalties		30		—			—			30
Purchased Product		—		244			(4	)		240
Transportation and Blending		82		—						82
Operating		312		—			27			339
Netback		214		—			30			244
Realized (Gain) Loss on Risk Management		—		—			—			—
Operating Margin		214		—			30			244
	Basis of Netback Calculation		Adjustments						Per Consolidated Financial  Statements (1)
Three Months Ended   December 31, 2021 ($ millions)	Conventional		Third-party Sourced			Other (2)			Conventional
Gross Sales		450		542			8			1,000
Royalties		47		—			—			47
Purchased Product		—		542			—			542
Transportation and Blending		17		—			—			17
Operating		128		8			(2	)		134
Netback		258		(8	)		10			260
Realized (Gain) Loss on Risk Management		—		—			—			—
Operating Margin		258		(8	)		10			260
	Basis of Netback Calculation		Adjustments						Per Consolidated Financial  Statements (1)
Three Months Ended   December 31, 2020 ($ millions) (3)	Conventional		Third-party Sourced			Other (2)			Conventional
Gross Sales		170		83			15			268
Royalties		12		—			—			12
Purchased Product		—		83			1			84
Transportation and Blending		18		—			—			18
Operating		65		—			7			72
Netback		75		—			7			82
Realized (Gain) Loss on Risk Management		—		—			—			—
Operating Margin		75		—			7			82

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

(2) Reflects operating margin from processing facility.

(3) Prior periods have been reclassified to conform with current period’s operating segments.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  177

Offshore

	Basis of Netback Calculation										Adjustment		Per Consolidated Financial Statements (2)
Year Ended   December 31,2021 ($ millions)	China		Indonesia (1)		Asia Pacific		Atlantic		Total Offshore		Equity Adjustment (1)		Total Offshore
Gross Sales		1,342		224		1,566		440		2,006		(224)		1,782
Royalties		79		52		131		29		160		(52)		108
Purchased Product		—		—		—		—		—		—		—
Transportation and Blending		—		—		—		15		15		—		15
Operating		94		33		127		137		264		(25)		239
Netback		1,169		139		1,308		259		1,567		(147)		1,420
Realized (Gain) Loss on Risk Management										—		—		—
Operating Margin										1,567		(147)		1,420

	Basis of Netback Calculation										Adjustment		Per Consolidated Financial Statements (2)
Three Months   Ended December 31, 2021 ($ millions)	China		Indonesia (1)		Asia Pacific		Atlantic		Total Offshore		Equity Adjustment (1)		Total Offshore
Gross Sales		377		62		439		143		582		(62)		520
Royalties		26		29		55		8		63		(29)		34
Purchased Product		—		—		—		—		—		—		—
Transportation and Blending		—		—		—		5		5		—		5
Operating		23		12		35		45		80		(7)		73
Netback		328		21		349		85		434		(26)		408
Realized (Gain) Loss on Risk Management										—		—		—
Operating Margin										434		(26)		408

(1)     Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

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

Sales Volumes ⁽¹⁾

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

	Three Months Ended December 31,									Year Ended December 31,
(MBOE/d, unless otherwise stated)	2021			2020			2021			2020			2019
Oil Sands
Foster Creek		194.5			161.1			178.8			164.9			157.8
Christina Lake		239.1			220.7			232.7			221.7			188.9
Sunrise		29.9			—			25.2			—			—
Other Oil Sands		141.2			—			143.2			—			—
Total Oil Sands		604.7			381.8			579.9			386.6			346.7
Conventional		125.3			86.1			133.4			89.8			97.4
Sales before Internal Consumption		730.0			467.9			713.3			476.4			444.1
Less: Internal Consumption (2)		(88.8	)		(57.0	)		(86.0	)		(55.9	)		(53.3	)
Sales after Internal Consumption		641.2			410.9			627.3			420.5			390.8
Offshore
Asia Pacific - China		52.7			—			50.8			—			—
Asia Pacific - Indonesia		9.8			—			9.5			—			—
Asia Pacific - Total		62.5			—			60.3			—			—
Atlantic		15.0			—			13.2			—			—
Total Offshore		77.5			—			73.5			—			—
Total Sales		718.7			410.9			700.8			420.5			390.8

(1)     Presented on dry bitumen basis.

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

178  |  CENOVUS ENERGY 2021 ANNUAL REPORT

The following tables have been represented for the first, second and third quarters of 2021 for a change in the presentation of product swaps and certain third-party purchases used in blending and optimization activities, and the classification of marketing activities at Sunrise. Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have been represented to reflect a change in the classification of marketing activities for the first, second and third quarters of 2021. See Adjustments to the Consolidated Statements of Earnings (Loss) below for additional details about the changes in product swaps and third-party purchases.

Upstream Financial Results

	Per Interim Consolidated Financial Statements		Adjustments														Basis of     Netback     Calculation
Three Months Ended   September 30, 2021 ($ millions)	Total Upstream (1)		Condensate			Third-Party Sourced			Internal Consumption (2)			Equity Adjustment (3)		Other (4)			Total     Upstream
Gross Sales		7,354		(1,538	)		(1,203	)		(175	)		60		(49	)		4,449
Royalties		733		—			—			—			11		—			744
Purchased Product		1,270		—			(1,203	)		—			—		(67	)		—
Transportation and Blending		1,941		(1,538	)		—			—			—		20			423
Operating		800		—			—			(175	)		6		(11	)		620
Netback		2,610		—			—			—			43		9			2,662
Realized (Gain) Loss on Risk Management		168		—			(2	)		—			—		—			166
Operating Margin		2,442		—			2			—			43		9			2,496

	Per Interim Consolidated Financial Statements		Adjustments														Basis of     Netback     Calculation
Three Months Ended   June 30, 2021 ($ millions)	Total Upstream (1)		Condensate			Third-Party Sourced			Internal Consumption (2)			Equity Adjustment (3)		Other (4)			Total     Upstream
Gross Sales		6,128		(1,416	)		(855	)		(145	)		50		(105	)		3,657
Royalties		533		—			—			—			5		—			538
Purchased Product		921		—			(855	)		—			—		(66	)		—
Transportation and Blending		1,802		(1,416	)		—			—			—		(17	)		369
Operating		791		—			—			(145	)		7		(11	)		642
Netback		2,081		—			—			—			38		(11	)		2,108
Realized (Gain) Loss on Risk Management		188		—			—			—			—		—			188
Operating Margin		1,893		—			—			—			38		(11	)		1,920

	Per Interim Consolidated Financial Statements			Adjustments														Basis of     Netback     Calculation
Three Months Ended   March 31, 2021 ($ millions)	Total Upstream (1)			Condensate			Third-Party Sourced			Internal Consumption (2)			Equity Adjustment (3)		Other (4)			Total     Upstream
Gross Sales		6,125			(1,368	)		(1,196	)		(149	)		52		(90	)		3,374
Royalties		373			—			—			—			7		—			380
Purchased Product		1,242			—			(1,196	)		—			—		(46	)		—
Transportation and Blending		1,800			(1,368	)		—			—			—		(3	)		429
Operating		785			—			—			(149	)		5		(11	)		630
Netback		1,925			—			—			—			40		(30	)		1,935
Realized (Gain) Loss on Risk Management		230			—			—			—			—		—			230
Operating Margin		1,695	–		—			—			—			40		(30	)		1,705

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

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

(3) Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.

(4) Other includes construction, transportation and blending and third-party processing margin.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  179

Oil Sands

	Basis of Netback Calculation
Three Months Ended   September 30, 2021 ($ millions)	Foster Creek		Christina Lake		Sunrise		Other Oil Sands (2)		Total Bitumen and Heavy Oil		Natural Gas			Total Oil sands
Gross Sales		1,325		1,405		173		876		3,779		3			3,782
Royalties		238		324		8		98		668		1			669
Purchased Product		—		—		—		—		—		—			—
Transportation and Blending		192		125		33		50		400		—			400
Operating		194		171		33		212		610		5			615
Netback		701		785		99		516		2,101		(3	)		2,098
Realized (Gain) Loss on Risk Management															166
Operating Margin															1,932

	Basis of Netback Calculation		Adjustments							Per Interim Consolidated Financial Statements (1)
Three Months Ended   September 30, 2021 ($ millions)	Total Oil Sands		Condensate		Third-party Sourced		Other (3)			Total Oil Sands
Gross Sales		3,782		1,538		758		39			6,117
Royalties		669		—		—		—			669
Purchased Product		—		—		758		67			825
Transportation and Blending		400		1,538		—		(20	)		1,918
Operating		615		—		—		1			616
Netback		2,098		—		—		(9	)		2,089
Realized (Gain) Loss on Risk Management		166		—		—		—			166
Operating Margin		1,932		—		—		(9	)		1,923

	Basis of Netback Calculation
Three Months Ended   June 30, 2021 ($ millions)	Foster Creek		Christina Lake		Sunrise		Other Oil Sands (2)		Total Bitumen and Heavy Oil		Natural Gas			Total Oil sands
Gross Sales		860		1,274		131		737		3,002		3			3,005
Royalties		142		242		2		83		469		—			469
Purchased Product		—		—		—		—		—		—			—
Transportation and Blending		155		131		26		35		347		—			347
Operating		154		171		54		205		584		5			589
Netback		409		730		49		414		1,602		(2	)		1,600
Realized (Gain) Loss on Risk Management															189
Operating Margin															1,411

	Basis of Netback Calculation		Adjustments						Per Interim Consolidated Financial Statements (1)
Three Months Ended   June 30, 2021 ($ millions)	Total Oil Sands		Condensate		Third-party Sourced		Other  (3)		Total Oil Sands
Gross Sales		3,005		1,416		568		86		5,075
Royalties		469		—		—		—		469
Purchased Product		—		—		568		66		634
Transportation and Blending		347		1,416		—		17		1,780
Operating		589		—		—		3		592
Netback		1,600		—		—		—		1,600
Realized (Gain) Loss on Risk Management		189		—		—		—		189
Operating Margin		1,411		—		—		—		1,411

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

(2) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

(3) Other includes construction, transportation and blending margin.

180  |  CENOVUS ENERGY 2021 ANNUAL REPORT

	Basis of Netback Calculation
Three Months Ended   March 31, 2021 ($ millions)	Foster Creek		Christina Lake		Sunrise		Other Oil Sands (2)		Total Bitumen and Heavy Oil		Natural Gas			Total Oil sands
Gross Sales		852		995		123		696		2,666		3			2,669
Royalties		107		167		3		47		324		—			324
Purchased Product		—		—		—		—		—		—			—
Transportation and Blending		173		130		24		80		407		—			407
Operating		169		164		31		211		575		5			580
Netback		403		534		65		358		1,360		(2	)		1,358
Realized (Gain) Loss on Risk Management															229
Operating Margin															1,129

	Basis of Netback Calculation		Adjustments						Per Interim Consolidated Financial Statements (1)
Three Months Ended   March 31, 2021 ($ millions)	Total Oil Sands		Condensate		Third-party Sourced		Other  (3)		Total Oil Sands
Gross Sales		2,669		1,368		815		66		4,918
Royalties		324		—		—		—		324
Purchased Product		—		—		815		46		861
Transportation and Blending		407		1,368		—		3		1,778
Operating		580		—		—		5		585
Netback		1,358		—		—		12		1,370
Realized (Gain) Loss on Risk Management		229		—		—		—		229
Operating Margin		1,129		—		—		12		1,141

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

(2) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.

(3) Other includes construction, transportation and blending margin.

CENOVUS ENERGY 2021 ANNUAL REPORT  |  181

Adjustments to the Consolidated Statements of Earnings (Loss)

Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment, has been revised. During the three and twelve months ended December 31, 2021, the Company made adjustments to more appropriately record certain third-party purchases used for blending and optimization activities. A portion of third-party purchases and sales were previously recorded on a net basis in gross sales. It was determined that the purchases were more appropriately reported as as purchased product. These amounts have now been re-presented as purchased product to be consistent with similar transactions. In addition, the Company identified the inconsistent treatment of product swaps, which were being recorded appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses on product swaps will be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing revenues and purchased product, with no impact to net earnings (loss), segment income (loss), netbacks, cash flows or financial position.

The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts:

2021 Revisions

	Three Months Ended March 31, 2021						Three Months Ended June 30, 2021						Three Months Ended September 30, 2021
Oil Sands Segment	Previously Reported		Revision		Revised		Previously Reported		Revision		Revised		Previously Reported		Revision		Revised
Gross Sales		4,775		143		4,918		5,015		60		5,075		6,114		3		6,117
Purchased Product		718		143		861		574		60		634		822		3		825

2020 Revisions

	Three Months Ended March 31, 2020						Three Months Ended June 30, 2020						Three Months Ended September 30, 2020
Oil Sands Segment	Previously Reported		Revision		Revised		Previously Reported		Revision		Revised		Previously Reported		Revision		Revised
Gross Sales		2,434		(9)		2,425		1,247		137		1,384		2,436		78		2,514
Purchased Product		405		(9)		396		166		137		303		235		78		313

	Three Months Ended December 31, 2020						Twelve Months Ended December 31, 2020
Oil Sands Segment	Previously Reported		Revision		Revised		Previously Reported		Revision		Revised
Gross Sales		2,364		117		2,481		8,481		323		8,804
Purchased Product		133		117		250		939		323		1,262

2019 Revisions

	Twelve Months Ended December 31, 2019
Oil Sands Segment	Previously Reported		Revision		Revised
Gross Sales		12,739		362		13,101
Purchased Product		1,869		362		2,231

182    |    CENOVUS ENERGY 2021 ANNUAL REPORT

INFORMATION FOR SHAREHOLDERS

ANNUAL MEETING

Cenovus will hold its Annual Meeting of Shareholders in a virtual format again this year to help mitigate health and safety risks to our community, shareholders, employees and other stakeholders. Holders of Cenovus common shares are invited to attend the virtual Annual Meeting of Shareholders to be held on Wednesday, April 27, 2022 at 1 p.m. MT via live webcast accessible online at https://web.lumiagm.com/427952573. Please see our Management Information Circular available on cenovus.com for additional information.

TRANSFER AGENT & REGISTRAR

Computershare Investor Services Inc.

8th Floor, 100 University Avenue

Toronto, Ontario M5J 2Y1 Canada

www.investorcentre.com/cenovus

Shareholder inquiries by phone:

North America 1.866.332.8898 (English and French)

Outside North America 1.514.982.8717 (English and French)

SHAREHOLDER ACCOUNT MATTERS

For information regarding your shareholdings or to change your address, transfer shares, eliminate duplicate mailings, directly deposit dividends, etc., please contact Computershare Investor Services Inc. If your shares are held by a broker, please contact your broker.

STOCK EXCHANGES

Cenovus common shares trade on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol CVE. Cenovus warrants trade on the TSX and the NYSE under the symbols TSX: CVE.WT and NYSE: CVE WS. Cenovus preferred shares Series 1, Series 2, Series 3, Series 5 and Series 7 trade on the TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G.

ANNUAL INFORMATION FORM/FORM 40 - F

Our Annual Information Form is filed with the Canadian Securities Administrators in Canada on SEDAR at sedar.com and with the

U.S. Securities and Exchange Commission under the Multi-Jurisdictional Disclosure System as an Annual Report on Form 40-F on EDGAR at sec.gov.

NYSE CORPORATE GOVERNANCE STANDARDS

As a Canadian company listed on the NYSE, we are not required to comply with most of the NYSE corporate governance standards and instead may comply with Canadian corporate governance requirements. We are, however, required to disclose the significant differences between our corporate governance practices and those required to be followed by U.S. domestic companies under the NYSE corporate governance standards. Except as summarized on https://www.cenovus.com/about/governance/

key-governance-documents.html, we are in compliance with the NYSE corporate governance standards in all significant respects.

INVESTOR RELATIONS

Please visit the Investors section at cenovus.com for investor information.

Investor inquiries should be directed to:

403.766.7711, investor.relations@cenovus.com

Media inquiries should be directed to:

403.766.7751, media.relations@cenovus.com

CENOVUS HEAD OFFICE

Cenovus Energy Inc.

225 6 Avenue SW

PO Box 766

Calgary, Alberta T2P 0M5 Canada

Phone: 403.766.2000

cenovus.com

CENOVUS’S LEADERSHIP TEAM

(as at March 1, 2022)

Alex Pourbaix, President & Chief Executive Officer

Susan Anderson, SVP, People Services

Keith Chiasson, EVP, Downstream

Andrew Dahlin, EVP, Corporate & Operations Services

Rhona DelFrari, Chief Sustainability Officer & SVP,

Stakeholder Engagement

Jeff Hart, EVP & Chief Financial Officer

Jon McKenzie, EVP & Chief Operating Officer

Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary

Norrie Ramsay, EVP, Upstream – Thermal, Major Projects & Offshore

Kam Sandhar, EVP, Strategy & Corporate Development

Drew Zieglgansberger, EVP, Natural Gas & Technical Services

CENOVUS’S BOARD OF DIRECTORS

(as at March 1, 2022)

Keith A. MacPhail, Board Chair, Calgary, Alberta ^(2,6)

Keith M. Casey, San Antonio, Texas ^(3,4)

Canning K.N. Fok, Hong Kong Special Administrative Region

Jane E. Kinney, Toronto, Ontario ^(1,4)

Harold N. Kvisle, Calgary, Alberta ^(2,3)

Eva L. Kwok, Vancouver, British Columbia ^(2,3)

Richard J. Marcogliese, Alamo, California ^(1,4)

Claude Mongeau, Montréal, Québec ^(1,4)

Alex J. Pourbaix, Calgary, Alberta ⁽⁵⁾

Wayne E. Shaw, Toronto, Ontario ^(1,4)

Frank J. Sixt, Hong Kong Special Administrative Region ⁽²⁾

Rhonda I. Zygocki, Friday Harbor, Washington ^(2,3)

⁽¹⁾  Member of the Audit Committee ⁽²⁾  Member of the Governance Committee ⁽³⁾  Member of the Human Resources and Compensation (“HRC”) Committee ⁽⁴⁾  Member of the Safety, Sustainability and Reserves (“SSR”) Committee ⁽⁵⁾  As an officer and a non-independent director, Mr. Pourbaix is not a member of any of the committees of Cenovus’s Board ⁽⁶⁾  An ex officio non-voting member of the Audit Committee, HRC Committee and SSR Committee         

CENOVUS ENERGY 2021 ANNUAL REPORT  |  183