Cenovus Energy
Annual Report 2022

Plain-text annual report

C E N O V U S E N E R G Y 2 0 2 2 A N N U A L R E P O R T CENOVUS ENERGY INC. Cenovus Energy Inc. is an integrated energy company with 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. The company is focused on managing its assets in a safe, innovative and cost‑efficient manner, integrating environmental, social and governance considerations into its business plans. Cenovus common shares and warrants are listed on the Toronto and New York stock exchanges, and the company’s preferred shares are listed on the Toronto Stock Exchange. For more information, visit cenovus.com. cenovus.com 1‑877‑766‑2066 (Toll‑free in Canada & U.S.) 225 6 Ave SW PO Box 766 Calgary, AB T2P 0M5 Canada © Cenovus Energy Inc. 2023 2022 ANNUAL REPORT I E N P S E D I S N I INFORMATION FOR SHAREHOLDERS ANNUAL MEETING The meeting will be held virtually only. This allows a broader base of shareholders to participate regardless of their location. Holders of Cenovus common shares are invited to attend the virtual Annual Meeting of Shareholders to be held on Wednesday, April 26, 2023 at 11:00 a.m. MT via live webcast accessible online at https://web.lumiagm.com/422837892. Please see our Management Information Circular available on cenovus.com for additional information. REGISTRAR AND TRANSFER AGENT Computershare Investor Services Inc. 8th Floor, 100 University Avenue Toronto, Ontario M5J 2Y1 Canada https://www.cenovus.com/Investors/Shareholder-information 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/Our-company/Governance, 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, 2023) Alex Pourbaix, President & Chief Executive Officer Susan Anderson, SVP, People Services Keith Chiasson, EVP, Downstream Andrew Dahlin, EVP, Corporate & Operations Services Rho na DelFrari, Chief Sustainability Officer & EVP, 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, 2023) 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) Melanie A. Little, Alpharetta, Georgia (3,4) 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 a d a n a C n i d e t n i r P CONTENTS MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER MESSAGE FROM OUR BOARD CHAIR MANAGEMENT’S DISCUSSION AND ANALYSIS CONSOLIDATED FINANCIAL STATEMENTS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SUPPLEMENTAL INFORMATION ADVISORY INFORMATION FOR SHAREHOLDERS 4 6 7 77 88 155 163 183 For additional information about forward‑looking statements, specified financial measures and reserves contained in this Annual Report, see the Advisory on page 163. At Cenovus, our purpose is to energize the world to make people’s lives better. MAKING PROGRESS ON OUR COMMITMENT TO BIODIVERSITY Biodiversity has long been a focus for Cenovus. We are more than halfway to our target of reclaiming 3,000 decommissioned well sites by year-end 2025. We also have restored more than 200,000 acres of caribou habitat, contributing to our goal of restoring more habitat than we use in the Cold Lake caribou range by year-end 2030. In 2022, we received more than 500 reclamation certificates for well sites and associated facilities. We’ve also seen positive results from the restoration of old seismic lines in the Cold Lake area. Linear features such as seismic lines, roads and pipelines create highway-type corridors through the forest that can allow predators to hunt caribou faster and further. However, a multi-year study we conducted in collaboration with partners in government and academia found that treating areas for restoration through the use of trees, rough surfaces and woody material reduced travel speeds of caribou and predators like wolves and bears, making the chances of an encounter less likely. We continue to develop, test and refine evidence-based techniques for land restoration using studies such as these. CENOVUS ENERGY 2022 ANNUAL REPORT | 3 INCREASING OUR RESILIENCY BY GROWING AND OPTIMIZING OUR PORTFOLIO The targeted enhancement of our portfolio has been a key focus over the last two years as we shape a resilient Cenovus built for the future. This includes strategic divestitures and acquisitions, and disciplined investment in focused growth and optimization projects. During 2022, we closed the acquisition of Sunrise, giving us full ownership, having an immediate positive impact on production and cash flow. We’re now working to unlock further value by integrating the Cenovus operating model into that facility. We also rebalanced our Atlantic portfolio, reaching an agreement to restart the West White Rose project, which included a reduced interest of 12.5 percent transferred to our partner. First oil from West White Rose is expected in 2026. In a separate agreement, we exited our position in the undeveloped Bay du Nord field. In 2022, we closed the sale of more than 300 gas stations in our retail network, as well as a number of conventional oil and natural gas properties. We fully own and operate the Toledo Refinery in Ohio, providing an opportunity to further integrate our heavy oil production and refining capabilities, solidify our refining footprint in the U.S. Midwest and increase our ability to capture margin throughout the value chain. The transaction, announced in August 2022, closed in February 2023. We will continue our focus on disciplined investment in 2023 with further optimization including debottlenecking plans for Foster Creek and the Lloydminster Refinery, the Narrows Lake tie-in at Christina Lake, and preparing the Lloydminster Upgrader and Refinery to access feedstock from Foster Creek in addition to the current crude supply from the Lloydminster area. Our investments will also progress plans to reduce our carbon footprint, and we’re putting capital aside to do just that. Over the next five years, Cenovus plans to spend approximately $1 billion on initiatives that advance our emissions reductions goals. This includes advancing carbon capture projects at the Minnedosa Ethanol Plant, Elmworth gas plant, Lloydminster Upgrader and Christina Lake, as well as methane reduction initiatives across conventional operations. We will also continue our work with the Pathways Alliance, which we jointly founded, on the goal of net zero emissions from oil sands production by 2050. MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER 2021 was about establishing Cenovus as a resilient new energy leader and in 2022 we demonstrated what this new company can do. As I prepare to take on the role of Executive Chair of our Board of Directors, I know Cenovus is well positioned for long-term success. And I know our incoming President & CEO Jon McKenzie will continue to unlock additional opportunities over the coming year and beyond, entrenching our position as a leader in delivering total shareholder returns. The capital allocation framework we implemented in April 2022 is clear about how we maintain balance sheet strength while delivering returns to shareholders. We employed that framework to provide annual shareholder returns in 2022 of more than $3.4 billion, including share purchases, our first-ever variable dividend, and our base dividend, which we tripled. Our total shareholder returns continued to outperform the S&P/TSX composite and energy indices in 2022, while we also drove down net debt by more than $5.3 billion through the year, further fortifying our balance sheet. However, we can’t truly consider ourselves successful unless we can point to an equally strong safety record. Cenovus improved its safety performance year over year with notable improvements in our recordable injury frequency at Lima Refinery and in our well delivery group. However, some of the recent incidents at our non-operated assets are an important reminder that we must never become complacent or take our safety performance for granted. We will be unrelenting in our efforts to ensure that Cenovus’s strong safety culture is embedded at every site where we operate. network. We are now the sole owner of Sunrise, de-risked our Atlantic portfolio and in February 2023 closed the transaction to fully own and operate the Toledo Refinery. At Superior, the refinery is safely ramping up to full operations. We added new production at existing operations with the startup of our Spruce Lake North thermal project in Saskatchewan and first gas at the MBH and MDA fields offshore Indonesia, exiting the year with overall production of more than 800,000 barrels of oil equivalent per day. While our downstream throughput in 2022 was affected by turnarounds and unplanned outages, we expect stronger performance this year, bolstered in part by the addition of barrels from Superior and Toledo. Our reliable operating performance and disciplined capital allocation, combined with strong commodity prices, have helped us accelerate our debt reduction. During the year, we reduced our long-term debt including current portion by $8.7 billion from $12.4 billion at the end of 2021, and drove down net debt by more than half. In 2022, the company returned more than $2.5 billion in value through its share buyback program and delivered over $900 million to shareholders in both base and variable dividends. In November 2022, we received TSX approval to purchase up to approximately 137 million additional shares by November 2023 and will continue to view buybacks opportunistically. Cenovus remains focused on helping support economic self-sustainability in Indigenous communities as part of our environmental, social and governance (ESG) focus on Indigenous reconciliation. Last year we spent the equivalent of about $1 million a day on goods and services from Indigenous-owned businesses in Canada. And we’ve nearly achieved our minimum target of spending at least $1.2 billion between 2019 and year-end 2025. Jon and I have worked closely over the past few years to build our integrated strategy. In 2022, we further refined our portfolio with a focus on strategic growth and optimization, while also increasing the physical integration of our upstream and downstream businesses. We completed several asset sales, including the divestment of our Tucker and Wembley assets and our retail fuels A highlight of my tenure as CEO was getting to see first-hand the difference our Indigenous Housing Initiative is having for families. Since 2020, this program has funded 81 new homes in six First Nations and Métis communities near our Christina Lake and Foster Creek operations. It was gratifying and humbling to visit with some of the people living in these new homes and hear how we are making a 4 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 TOTAL SHAREHOLDER RETURN Cenovus Energy (TSX) S&P/TSX Composite Index S&P/TSX Energy Index $210 $200 $190 $180 $170 $160 $150 $140 $130 $120 $110 $100 $90 $80 December 31, 2021 March 31, 2022 June 30, 2022 September 30, 2022 December 31, 2022 Source: Bloomberg 2021 – 2022 NET DEBT REDUCTION Long-Term Debt, Including Current Portion Net Debt s n o i l l i b $ $16.0 $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 $- 14.0 13.1 13.4 12.4 12.4 9.6 11.2 7.5 8.7 4.3 2021-01-01 2021-06-30 2021-12-31 2022-06-30 2022-12-31 tangible difference in helping address the critical housing situation in Indigenous communities. We continue to progress another of our ESG targets, reducing our absolute emissions. Over the next five years, Cenovus plans to spend approximately $1 billion on initiatives that advance our emissions reduction goals, ranging from carbon capture projects, methane reduction initiatives and increasing energy efficiency. It is these efforts to decarbonize that will enable Canada to be the globally preferred barrel in a lower carbon future and allow us to continue to be a significant contributor to the Canadian economy. We know two things – that we must help address the challenge of climate change and also that oil and gas is going to play a significant role in meeting the world’s energy needs for decades to come. Canada is well positioned to continue to provide the reliable, affordable energy the world needs. It’s why we continue to work with our peers and all levels of government to meet Canada’s and our own net zero ambition. As a co-founder of the Pathways Alliance, we have an ambitious, actionable plan to reduce GHG emissions from the oil sands, in phases. While many different solutions will be needed, significant progress has been achieved on the early-stage work for the Pathways Alliance foundational carbon capture and storage project, including an agreement with the Government of Alberta that allows us to start a detailed evaluation of the proposed underground carbon dioxide storage hub. As other regulatory pieces advance at the federal and provincial levels, we’ll be able to progress the project further toward construction. I look forward to playing a leading role in these efforts. I want to thank all our staff and shareholders for their support over the last five plus years. I also want to extend my appreciation to our retiring Board Chair Keith MacPhail. Keith’s extensive business and energy sector expertise has been a great benefit to the Board and our company as we navigated through a period of significant transformation, accelerating our growth and developing a solid strategy, which we believe will support Cenovus’s continued success. We have a world-class suite of assets and a solid plan for further sustainable growth and optimization, carrying our existing momentum well into the future. /s/ Alex Pourbaix President & Chief Executive Officer CENOVUS ENERGY 2022 ANNUAL REPORT | 5 MESSAGE FROM OUR BOARD CHAIR As we went to print on last year’s annual report the world was reeling from the Russian invasion of Ukraine. Unfortunately, this conflict continues and became one of the dominant news and energy stories of 2022. This war has impacted commodity prices and highlights not only the continuing need for oil and gas, but the importance of secure, reliable sources of that energy. That narrative has continued as we enter 2023, with many analysts predicting another turbulent year for commodities. We are keenly aware that simply being a reliable supplier of oil and gas isn’t enough – Cenovus and Canada need to be leaders in providing lower carbon energy in order to help the country meet its climate goals and for our company to remain competitive in the longer term. As I retire as Board Chair and Alex steps into his new role as Executive Chair, he will remain focused on advancing policy that supports a competitive Canadian energy sector. Not only was our Board very engaged with our leadership team over the last year discussing methods of reducing our carbon footprint but also on advancing the company’s safety, financial and sustainability commitments. In April 2022, the Board approved a new shareholder returns framework which guides how we increase returns, and resulted in our first-ever variable dividend. Buoyed by strong commodity prices and our focused deleveraging of the balance sheet, we exited 2022 with significant reductions in our long-term debt and net debt, at the same time returning approximately $3.4 billion dollars to our shareholders through share buybacks and dividends. While we are mindful of our current operational and financial strengths, we recognize the need for continued investment to optimize opportunities across our portfolio. With that in mind, the Board approved increased capital spending as part of the company’s 2023 budget guidance. Over the next five years, we expect growth to come largely through the extension or expansion of our existing assets in addition to debottlenecking opportunities. company has undergone, and how the Husky acquisition and other strategic acquisitions and divestitures made us a more resilient, integrated company. I’m also proud of the steps we’ve taken to increase the diversity of experience on the Board. Melanie A. Little joined the Board on January 1, 2023, bringing a breadth of operations and regulatory experience in the midstream business, particularly in the U.S. We welcome her perspective and expertise as we unlock further value from our U.S.-based assets. Melanie’s addition to the Board, along with Alex’s new role as Executive Chair and Jon as a new Director nominee, supports our commitment to a strong and talented Board. This year we also achieved our goal of having at least 30% of our independent directors represented by women by the 2023 Annual Meeting of Shareholders. As Alex remains an employee and officer of the company in his Executive Chair role, the Board demonstrated its continued commitment to good governance best practices, choosing Claude Mongeau as Lead Director. This will ensure the Board will continue to operate independently with an Executive Chair. Claude will be available to engage with you and other stakeholders on behalf of the Board. I am confident the measures our management team has taken will ensure Cenovus is positioned for success at multiple commodity price points, and that the focus will remain on executing the strategic plan and disciplined capital allocation. I want to thank our shareholders and our Board for their support and confidence over the past five years. As a shareholder, I look forward to watching Alex, Claude, Jon and the rest of the Board and Management skillfully navigate the company into the future following the course that we’ve set out over the past few years. As I look back over my five years as a member of this Board, three as its Chair, I am reminded of the significant transformation the /s/ Keith MacPhail Board Chair 6 | CENOVUS ENERGY 2022 ANNUAL REPORT MANAGEMENT’S DISCUSSION AND ANALYSIS FOR THE YEAR ENDED DECEMBER 31, 2022 OVERVIEW OF CENOVUS YEAR IN REVEW OPERATING AND FINANCIAL RESULTS 8 10 13 COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS 19 OUTLOOK REPORTABLE SEGMENTS UPSTREAM OIL SANDS CONVENTIONAL OFFSHORE DOWNSTREAM CANADIAN MANUFACTURING U.S. MANUFACTURING CORPORATE AND ELIMINATIONS QUARTERLY RESULTS OIL AND GAS RESERVES LIQUIDITY AND CAPITAL RESOURCES RISK MANAGEMENT AND RISK FACTORS CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES CONTROL ENVIRONMENT 22 24 24 24 28 30 34 34 36 38 41 43 44 50 74 76 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 15, 2023 should be read in conjunction with our December 31, 2022 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 15, 2023 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 15, 2023. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not constitute part of this MD&A. BASIS OF PRESENTATION This MD&A and the 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. Production volumes are presented on a before royalties basis. Refer to the Advisory section for commonly used oil and gas terms. CENOVUS ENERGY 2022 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, with upstream operations in Canada and the Asia Pacific region, and the second largest Canadian-based refiner and upgrader, with downstream operations in Canada and the United States (“U.S.”). 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”). 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 operations include upgrading and refining operations in Canada and the U.S., and commercial fuel operations across Canada. Our operations involve activities across the full value chain to develop, produce, refine, 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 net earnings by capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels. Our Strategy Our strategy is focused on maximizing shareholder value through competitive cost structures and optimizing margins, while delivering top-tier safety performance and sustainability leadership. The Company prioritizes Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and share repurchases, reinvest in our business and diversify our portfolio. On December 6, 2022, we announced our 2023 budget focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. For further details see the Operating and Financial Results section of this MD&A. Shareholder Returns and Capital Allocation Framework Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout the commodity price cycle is a key element of Cenovus’s capital allocation framework. In April 2022, we announced our updated capital allocation framework to continue to strengthen our balance sheet, which enables flexibility in both high and low commodity price environments, and improves our shareholder value proposition. We have set an ultimate Net Debt Target of $4 billion, which serves as a floor on Net Debt. We plan to return incremental value to shareholders, through share buybacks and/or variable dividends, as follows: • When Net Debt is less than $9 billion and above $4 billion at quarter-end, we will target to allocate 50 percent of the Excess Free Funds Flow achieved in the following quarter to shareholder returns, while still continuing to deleverage the balance sheet until we reach the Net Debt Target of $4 billion. • When Net Debt is above $9 billion at quarter-end, we plan to allocate all of the following quarter’s Excess Free Funds Flow to deleveraging the balance sheet. • When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s Excess Free Funds Flow to shareholder returns. Excess Free Funds Flow for the quarter is defined as Free Funds Flow(1): • Minus base dividends paid on common shares. • Minus dividends paid on preferred shares. • Minus other uses of cash, including settlement of decommissioning liabilities and principal repayment of leases. • Minus any net acquisition costs from acquisition activities closing in the quarter. • Plus any proceeds from, or less any payments related to, divestiture activities closing in the quarter. The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to common shareholders, with lower leverage and a lower risk profile. Our $4 billion Net Debt Target represents a Net Debt to Adjusted Funds Flow Ratio Target of approximately 1.0 times at the bottom of the commodity price cycle. Share buybacks will continue to be executed opportunistically, driven by return thresholds. Where the value of share buybacks in a quarter is less than the targeted value of returns, the remainder will be delivered through a variable dividend payable for that quarter, if the remainder is greater than $50 million. Where the value of share buybacks in a quarter is greater than or equal to the targeted value of returns, no variable dividend will be paid for that quarter. (1) See the Liquidity and Capital Resources section of this MD&A for the calculation of Free Funds Flow. 8 | CENOVUS ENERGY 2022 ANNUAL REPORT On September 30, 2022, our long-term debt was $8.8 billion, resulting in a Net Debt position of $5.3 billion. Therefore, our returns to shareholders target for the three months ended December 31, 2022, was 50 percent of that quarter's Excess Free Funds Flow. During the three months ended December 31, 2022, we generated cash from operating activities of $3.0 billion, Excess Free Funds Flow of $786 million and returned $387 million to our shareholders through share buybacks. Returns to shareholders through share buybacks were within $50 million of our Target Return, as such no variable dividend was declared for the quarter. ($ millions) Excess Free Funds Flow (1) Target Return (2) Less: Purchase of Common Shares Under our Normal Course Issuer Bid (“NCIB”) Amount Available for Variable Dividend Three Months Ended December 31, 2022 786 393 (387) 6 (1) (2) Non-GAAP financial measure. See the Advisory. Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, being less than $9 billion and greater than $4 billion, target return was determined to be 50 percent of Excess Free Funds Flow for the three months ended December 31, 2022. On December 31, 2022, our Net Debt position was $4.3 billion and as a result our returns to shareholders target for the three months ended March 31, 2023, will be 50 percent of the first quarter’s Excess Free Funds Flow. 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, 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. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 9 Corporate and Eliminations 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, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change. YEAR IN REVIEW In 2022, we continued to focus on health and safety and drive competitive cost structures. High commodity prices in both our upstream and downstream businesses combined with solid upstream operating performance and good operating performance in our operated downstream assets drove strong financial results and allowed us to significantly reduce our total debt. We optimized our asset portfolio as we closed the acquisition of Sunrise and announced the acquisition of Toledo, which will provide us full ownership and operatorship of both assets. In addition, we completed the restructuring of our Atlantic assets and reached an agreement with our partners to restart the West White Rose project. We also sold our Tucker, Wembley and retail assets. These transactions enhanced Cenovus’s core strength in the oil sands and will further optimize margins through increased physical integration of our upstream and downstream assets. Lastly, we improved our shareholder value proposition through an updated shareholder returns and capital allocation framework. The framework returns incremental value back to shareholders through share buybacks and/or variable dividends. Summary of Annual Results ($ millions, except where indicated) Upstream Production Volumes (1) (MBOE/d) Downstream Crude Oil Throughput (2) (Mbbls/d) Revenues (3) Operating Margin (4) Cash From (Used In) Operating Activities Adjusted Funds Flow (4) Per Share – Basic (4) ($) Per Share – Diluted (4) ($) Capital Investment Free Funds Flow (4) Net Earnings (Loss) (5) Per Share – Basic ($) Per Share – Diluted ($) 2022 786.2 493.7 66,897 14,263 11,403 10,978 5.63 5.47 3,708 7,270 6,450 3.29 3.20 Percent Change (1) (3) 44 52 93 51 57 55 45 55 999 1,119 1,085 2021 791.5 508.0 46,357 9,373 5,919 7,248 3.59 3.54 2,563 4,685 587 0.27 0.27 Percent Change 68 173 242 918 2,068 6,095 3,490 3,440 205 N/A N/A N/A N/A 2020 471.7 185.9 13,543 921 273 117 0.10 0.10 841 (724) (2,379) (1.94) (1.94) (1) (2) (3) (4) (5) Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type. Represents Cenovus’s net interest in refining operations. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Non-GAAP financial measures or contains a non-GAAP financial measure. See the Advisory. Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations. 10 | CENOVUS ENERGY 2022 ANNUAL REPORT Summary of Annual Results ($ millions, except where indicated) Total Assets Total Long-Term Liabilities Long-Term Debt, Including Current Portion Net Debt Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Preferred Share Dividends Percent Change Percent Change 2022 55,869 20,259 8,691 4,282 682 0.350 219 0.114 2,530 26 2021 54,104 23,191 12,385 9,591 176 0.088 — — 265 34 3 (13) (30) (55) 288 298 N/A N/A 855 (24) 2020 32,770 13,704 7,441 7,184 77 0.063 — — — — 65 69 66 34 129 40 — — N/A N/A we: • • • • • • • In 2022, we delivered on our strategy through five key strategic objectives: Top Tier Safety Performance and Sustainability Leadership Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Safety, asset integrity and corporate governance are foundational to our business, and are the backbone for all of our operations. We promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind. In 2022, Delivered safe operations at our operated assets. Completed planned turnarounds at the operated Lloydminster Upgrader (the “Upgrader”) and Lloydminster Refinery in our downstream operations. In addition, we completed a planned turnaround at Christina Lake in our upstream Completed planned turnarounds at the non-operated Toledo, Wood River and Borger refineries in our downstream operations in the second quarter. operations. Continued our focus on achieving our targets in each of our five Environmental, Social and Governance (“ESG”) focus areas. Additional information on management’s efforts and performance across ESG topics, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report at cenovus.com. Actively participated in industry collaborations including the Pathways Alliance. We continue to work with our partners of our non-operated downstream assets to improve the safety performance. Competitive Cost Structures and Optimizing Margins In 2022, we: Targeted additional cost savings and margin enhancements through further physical integration of upstream assets with downstream assets, which shortened the value chain and reduced condensate costs associated with heavy oil Improved efficiencies across Cenovus to drive incremental capital, operating, and general and administrative cost transportation. reductions. Maintaining and Further Reducing Debt Levels substantially decrease Net Debt. In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, enabling us to • As at December 31, 2022, our long-term debt, including current portion, was $8.7 billion (December 31, 2021 – $12.4 billion) and our Net Debt position was $4.3 billion (December 31, 2021 – $9.6 billion). • We deleveraged our balance sheet by purchasing US$2.6 billion in principal of notes due between 2023 and 2043, and • Our Net Debt to Adjusted EBITDA Ratio was 0.3 times and our Net Debt to Adjusted Funds Flow Ratio was 0.4 times at $750 million in principal of notes due in 2025. December 31, 2022. Corporate and Eliminations 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, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change. YEAR IN REVIEW In 2022, we continued to focus on health and safety and drive competitive cost structures. High commodity prices in both our upstream and downstream businesses combined with solid upstream operating performance and good operating performance in our operated downstream assets drove strong financial results and allowed us to significantly reduce our total debt. We optimized our asset portfolio as we closed the acquisition of Sunrise and announced the acquisition of Toledo, which will provide us full ownership and operatorship of both assets. In addition, we completed the restructuring of our Atlantic assets and reached an agreement with our partners to restart the West White Rose project. We also sold our Tucker, Wembley and retail assets. These transactions enhanced Cenovus’s core strength in the oil sands and will further optimize margins through increased physical integration of our upstream and downstream assets. Lastly, we improved our shareholder value proposition through an updated shareholder returns and capital allocation framework. The framework returns incremental value back to shareholders through share buybacks and/or variable dividends. Summary of Annual Results ($ millions, except where indicated) Upstream Production Volumes (1) (MBOE/d) Downstream Crude Oil Throughput (2) (Mbbls/d) Cash From (Used In) Operating Activities Revenues (3) Operating Margin (4) Adjusted Funds Flow (4) Per Share – Basic (4) ($) Per Share – Diluted (4) ($) Capital Investment Free Funds Flow (4) Net Earnings (Loss) (5) Per Share – Basic ($) Per Share – Diluted ($) (1) (2) (3) (4) (5) further details. 2022 786.2 493.7 66,897 14,263 11,403 10,978 5.63 5.47 3,708 7,270 6,450 3.29 3.20 Percent Change (1) (3) 44 52 93 51 57 55 45 55 999 1,119 1,085 2021 791.5 508.0 46,357 9,373 5,919 7,248 3.59 3.54 2,563 4,685 587 0.27 0.27 Percent Change 68 173 242 918 2,068 6,095 3,490 3,440 205 N/A N/A N/A N/A 2020 471.7 185.9 13,543 921 273 117 0.10 0.10 841 (724) (2,379) (1.94) (1.94) Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type. Represents Cenovus’s net interest in refining operations. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for Non-GAAP financial measures or contains a non-GAAP financial measure. See the Advisory. Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations. Summary of Annual Results ($ millions, except where indicated) Total Assets Total Long-Term Liabilities Long-Term Debt, Including Current Portion Net Debt Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Preferred Share Dividends 2022 55,869 20,259 8,691 4,282 682 0.350 219 0.114 2,530 26 Percent Change 3 (13) (30) (55) 288 298 N/A N/A 855 (24) 2021 54,104 23,191 12,385 9,591 176 0.088 — — 265 34 Percent Change 65 69 66 34 129 40 — — N/A N/A 2020 32,770 13,704 7,441 7,184 77 0.063 — — — — In 2022, we delivered on our strategy through five key strategic objectives: Top Tier Safety Performance and Sustainability Leadership Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Safety, asset integrity and corporate governance are foundational to our business, and are the backbone for all of our operations. We promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind. In 2022, we: • • • • • Delivered safe operations at our operated assets. Completed planned turnarounds at the operated Lloydminster Upgrader (the “Upgrader”) and Lloydminster Refinery in our downstream operations. In addition, we completed a planned turnaround at Christina Lake in our upstream operations in the second quarter. Completed planned turnarounds at the non-operated Toledo, Wood River and Borger refineries in our downstream operations. Continued our focus on achieving our targets in each of our five Environmental, Social and Governance (“ESG”) focus areas. Additional information on management’s efforts and performance across ESG topics, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report at cenovus.com. Actively participated in industry collaborations including the Pathways Alliance. We continue to work with our partners of our non-operated downstream assets to improve the safety performance. Competitive Cost Structures and Optimizing Margins In 2022, we: • • Targeted additional cost savings and margin enhancements through further physical integration of upstream assets with downstream assets, which shortened the value chain and reduced condensate costs associated with heavy oil transportation. Improved efficiencies across Cenovus to drive incremental capital, operating, and general and administrative cost reductions. Maintaining and Further Reducing Debt Levels In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, enabling us to substantially decrease Net Debt. • As at December 31, 2022, our long-term debt, including current portion, was $8.7 billion (December 31, 2021 – $12.4 billion) and our Net Debt position was $4.3 billion (December 31, 2021 – $9.6 billion). • We deleveraged our balance sheet by purchasing US$2.6 billion in principal of notes due between 2023 and 2043, and • $750 million in principal of notes due in 2025. Our Net Debt to Adjusted EBITDA Ratio was 0.3 times and our Net Debt to Adjusted Funds Flow Ratio was 0.4 times at December 31, 2022. CENOVUS ENERGY 2022 ANNUAL REPORT | 11 Growing Free Funds Flow Through Pricing Cycles Our top-tier assets and low-cost structure 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 by leveraging pipelines, logistics and marketing to optimize the value chain. We are able to generate strong margins with modest capital investment. In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, primarily due to high commodity prices combined with solid upstream operating performance. WTI averaged approximately US$94 per barrel in 2022, the highest annual average since 2013, and an increase of approximately 40 percent from 2021. North American market crack spreads also reached historic highs during the year. In 2022, we continued to optimize our top-tier asset portfolio and grow Free Funds Flow. In our upstream business: • We sold our Tucker asset and our Wembley assets for total net proceeds of $951 million. • We reached an agreement with our partners to restart the West White Rose project in the Atlantic region offshore Newfoundland and Labrador. Major construction is expected to restart in the first quarter of 2023. • We acquired the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“BP Canada”) for net proceeds of $394 million, a variable payment with a maximum cumulative value of $600 million expiring in eight quarters subsequent to August 31, 2022, and our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. • We achieved first oil at our Spruce Lake North thermal plant in the third quarter of 2022. • • In Indonesia, we achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022. Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. In our downstream business: • We announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP (the “Toledo Acquisition”). The transaction is expected to close at the end of February 2023. • We closed the sale of 337 gas stations within our retail fuels network for net cash proceeds of $404 million. In addition, we sold our investment in Headwater Exploration Inc. for proceeds of $110 million. Returns-focused Capital Allocation The Company’s sustaining capital program and base dividend are sustainable at US$45 WTI per barrel and provide opportunities to sustainably grow shareholder returns. In 2022: • We renewed our NCIB, which expired on November 8, 2022. Under our new NCIB (the “2023 NCIB”), we are authorized to purchase up to 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. • We purchased and cancelled 112 million common shares for $2.5 billion through our NCIBs in 2022. • We returned $901 million to common shareholders through base dividends of $0.350 per common share and variable dividends of $0.114 per common share. We declared dividends for the first quarter of 2023: • • On February 15, 2023, the Board declared a first quarter base dividend of $0.105 per common share payable on March 31, 2023, to common shareholders of record as at March 15, 2023. On February 15, 2023, the Board declared first quarter dividends for our preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as at March 15, 2023. 12 | CENOVUS ENERGY 2022 ANNUAL REPORT OPERATING AND FINANCIAL RESULTS Selected Operating Results — Upstream Upstream Production Volumes by Segment (1) (MBOE/d) Oil Sands Conventional Offshore Total Production Volumes Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Upstream Production Volumes by Product Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Total Upstream Sales Volumes (2) (MBOE/d) Netback (3)(4) ($/BOE) Oil and Gas Reserves (MMBOE) Total Proved Probable Total Proved Plus Probable 2022 588.7 127.2 70.3 786.2 570.3 16.3 19.1 36.2 866.1 786.2 696.4 53.21 6,082 2,787 8,869 Percent Change Percent Change 2021 583.6 133.6 74.4 791.5 561.3 20.2 22.5 38.3 895.5 791.5 700.8 37.04 6,077 2,201 8,278 1 (5) (6) (1) 2 (19) (15) (5) (3) (1) (1) 44 — 27 7 2020 381.7 89.9 — 471.7 381.7 2.7 4.5 19.5 379.0 471.7 420.5 10.09 5,030 1,656 6,686 53 49 N/A 68 47 648 400 96 136 68 67 267 21 33 24 (1) (2) (3) Refer to the Oil Sands, Conventional or Offshore Operating Results section of this MD&A for a summary of production by product type. Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 520 MMcf per day for the year ended December 31, 2022 (517 MMcf per day for the year ended December 31, 2021). Upstream revenue as found in Note 1 of the Consolidated Financial Statements was $36.3 billion for the year ended December 31, 2022 ($25.4 billion for the year ended December 31, 2021). (4) Contains a non-GAAP financial measure. See the Advisory. 2022 compared with 2021: In 2022, total crude oil, NGLs and natural gas production was consistent with 2021. The factors below increased production in New wells coming online at Foster Creek and Christina Lake in 2022 and the second half of 2021. The Sunrise Acquisition on August 31, 2022. First oil at the Spruce Lake North thermal plant in the third quarter of 2022. A planned turnaround and operational outages at Foster Creek in the second quarter of 2021. First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. The factors below decreased production in 2022 compared with 2021: The disposition of the Tucker asset on January 31, 2022. Planned maintenance and an unplanned outage at Foster Creek in the third quarter of 2022. Planned turnaround activity at Christina Lake in the second quarter of 2022. The disposition of the Wembley asset on February 28, 2022, and the East Clearwater and Kaybob divestitures in the second half of 2021. As part of the decision to restart the West White Rose project, we transferred a 12.5 percent working interest in the White Rose field and satellite extensions to our partner on May 31, 2022. Oil and Gas Reserves Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total proved plus probable reserves at December 31, 2022 were approximately 6.1 billion BOE and 8.9 billion BOE, respectively. Total proved reserves were consistent with 2021, and proved plus probable reserves increased seven percent compared with 2021. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. • • • • • • • • • • Growing Free Funds Flow Through Pricing Cycles Our top-tier assets and low-cost structure 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 by leveraging pipelines, logistics and marketing to optimize the value chain. We are able to generate strong margins with modest capital investment. In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, primarily due to high commodity prices combined with solid upstream operating performance. WTI averaged approximately US$94 per barrel in 2022, the highest annual average since 2013, and an increase of approximately 40 percent from 2021. North American market crack spreads also reached historic highs during the year. In 2022, we continued to optimize our top-tier asset portfolio and grow Free Funds Flow. In our upstream business: • We sold our Tucker asset and our Wembley assets for total net proceeds of $951 million. • We reached an agreement with our partners to restart the West White Rose project in the Atlantic region offshore Newfoundland and Labrador. Major construction is expected to restart in the first quarter of 2023. • We acquired the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“BP Canada”) for net proceeds of $394 million, a variable payment with a maximum cumulative value of $600 million expiring in eight quarters subsequent to August 31, 2022, and our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. • We achieved first oil at our Spruce Lake North thermal plant in the third quarter of 2022. • • In Indonesia, we achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022. Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. In our downstream business: • We announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP (the “Toledo Acquisition”). The transaction is expected to close at the end of February 2023. • We closed the sale of 337 gas stations within our retail fuels network for net cash proceeds of $404 million. In addition, we sold our investment in Headwater Exploration Inc. for proceeds of $110 million. Returns-focused Capital Allocation to sustainably grow shareholder returns. In 2022: The Company’s sustaining capital program and base dividend are sustainable at US$45 WTI per barrel and provide opportunities • We renewed our NCIB, which expired on November 8, 2022. Under our new NCIB (the “2023 NCIB”), we are authorized to purchase up to 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. • We purchased and cancelled 112 million common shares for $2.5 billion through our NCIBs in 2022. • We returned $901 million to common shareholders through base dividends of $0.350 per common share and variable dividends of $0.114 per common share. We declared dividends for the first quarter of 2023: • • March 31, 2023, to common shareholders of record as at March 15, 2023. On February 15, 2023, the Board declared first quarter dividends for our preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as at March 15, 2023. OPERATING AND FINANCIAL RESULTS Selected Operating Results — Upstream Upstream Production Volumes by Segment (1) (MBOE/d) Oil Sands Conventional Offshore Total Production Volumes Upstream Production Volumes by Product Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Total Upstream Sales Volumes (2) (MBOE/d) Netback (3)(4) ($/BOE) Oil and Gas Reserves (MMBOE) Total Proved Probable Total Proved Plus Probable 2022 588.7 127.2 70.3 786.2 570.3 16.3 19.1 36.2 866.1 786.2 696.4 53.21 6,082 2,787 8,869 Percent Change 1 (5) (6) (1) 2 (19) (15) (5) (3) (1) (1) 44 — 27 7 2021 583.6 133.6 74.4 791.5 561.3 20.2 22.5 38.3 895.5 791.5 700.8 37.04 6,077 2,201 8,278 Percent Change 53 49 N/A 68 47 648 400 96 136 68 67 267 21 33 24 2020 381.7 89.9 — 471.7 381.7 2.7 4.5 19.5 379.0 471.7 420.5 10.09 5,030 1,656 6,686 (1) (2) (3) (4) Refer to the Oil Sands, Conventional or Offshore Operating Results section of this MD&A for a summary of production by product type. Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 520 MMcf per day for the year ended December 31, 2022 (517 MMcf per day for the year ended December 31, 2021). Upstream revenue as found in Note 1 of the Consolidated Financial Statements was $36.3 billion for the year ended December 31, 2022 ($25.4 billion for the year ended December 31, 2021). Contains a non-GAAP financial measure. See the Advisory. In 2022, total crude oil, NGLs and natural gas production was consistent with 2021. The factors below increased production in 2022 compared with 2021: • • • • • New wells coming online at Foster Creek and Christina Lake in 2022 and the second half of 2021. The Sunrise Acquisition on August 31, 2022. First oil at the Spruce Lake North thermal plant in the third quarter of 2022. A planned turnaround and operational outages at Foster Creek in the second quarter of 2021. First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. On February 15, 2023, the Board declared a first quarter base dividend of $0.105 per common share payable on The factors below decreased production in 2022 compared with 2021: • • • • • The disposition of the Tucker asset on January 31, 2022. Planned maintenance and an unplanned outage at Foster Creek in the third quarter of 2022. Planned turnaround activity at Christina Lake in the second quarter of 2022. The disposition of the Wembley asset on February 28, 2022, and the East Clearwater and Kaybob divestitures in the second half of 2021. As part of the decision to restart the West White Rose project, we transferred a 12.5 percent working interest in the White Rose field and satellite extensions to our partner on May 31, 2022. Oil and Gas Reserves Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total proved plus probable reserves at December 31, 2022 were approximately 6.1 billion BOE and 8.9 billion BOE, respectively. Total proved reserves were consistent with 2021, and proved plus probable reserves increased seven percent compared with 2021. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. CENOVUS ENERGY 2022 ANNUAL REPORT | 13 Selected Operating Results — Downstream Downstream Crude Oil Throughput (Mbbls/d) Canadian Manufacturing U.S. Manufacturing Total Throughput Fuel Sales (1) (millions of litres/d) 2022 92.9 400.8 493.7 6.2 Percent Change (13) — (3) (10) 2021 106.5 401.5 508.0 6.9 Percent Change N/A 116 173 N/A 2020 — 185.9 185.9 — (1) On September 13, 2022, we closed the sale of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes cardlock, bulk plant and travel centre locations. In the Canadian Manufacturing segment, throughput decreased 13.6 thousand barrels per day in 2022 compared with 2021. We completed planned turnarounds at both the Lloydminster Upgrader and Lloydminster Refinery in the second quarter of 2022. In addition, there were multiple temporary unplanned outages at the Upgrader in 2022. In 2021, the Upgrader and Lloydminster Refinery ran at or near capacity throughout the year. In the U.S. Manufacturing segment, total throughput was consistent in 2022 compared with 2021: • • The Lima Refinery had unplanned operational issues in the first quarter of 2022 coming out of the 2021 fourth quarter turnaround. The refinery performed well during the remainder of the year, achieving crude utilization of 90 percent in 2022. At the Toledo Refinery, we completed a significant planned turnaround from April to early August 2022. The refinery remains shut down in a safe state following an incident on September 20, 2022. • We completed two planned turnarounds at the Wood River Refinery in the second and fourth quarters of 2022. The second quarter turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. In early December, there was an incident at the Wood River Refinery that resulted in damage to one of the units and reduced throughput. • We completed a turnaround at the Borger Refinery in the first and second quarter of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022. • We commenced commissioning for the restart of the Superior Refinery in December 2022. Selected Consolidated Financial Results Operating Margin Operating Margin is a specified 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) Gross Sales Less: Royalties Revenues Expenses Purchased Product Transportation and Blending Operating Expenses Realized (Gain) Loss on Risk Management Activities Operating Margin 2022 79,229 4,868 74,361 39,334 12,194 6,839 1,731 14,263 2021 (1)(2) 54,102 2,454 51,648 27,170 8,714 5,499 892 9,373 2020 14,523 371 14,152 5,959 4,764 2,261 247 921 (1) (2) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no change to total Operating Margin. 14 | CENOVUS ENERGY 2022 ANNUAL REPORT Operating Margin by Segment Year Ended December 31, 2022 (1) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuel business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. Operating Margin increased in 2022, mainly due to higher average realized sales prices, resulting from higher benchmark pricing. In addition, realized refining margins almost doubled in our downstream business due to significantly higher market crack spreads from 2021. These increases in Operating Margin were partially offset by: Increased blending costs due to higher condensate prices. • • • • • • • • Higher royalties and fuel costs in our upstream operations, both resulting from significantly higher commodity pricing. Increased realized risk management losses on the settlement of benchmark prices relative to our risk management contract prices in 2022. In the second quarter of 2022, all WTI risk management contracts related to our crude oil sales price risk management activities were closed. Planned turnarounds and unplanned outages in our downstream operations in 2022, which impacted sales volumes In our realized margin, higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing Increased transportation costs due to increased tariffs combined with higher sales volumes at Foster Creek, Christina and operating expenses. segment. Lake and Sunrise. Higher operating expenses at the Superior Refinery. Costs increased compared with 2021 as we prepared for restart. Increased electricity and chemical costs in our upstream operations. 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. Cash From (Used in) Operating Activities ($ millions) (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow 2022 11,403 (150) 575 10,978 2021 5,919 (102) (1,227) 7,248 2020 273 (42) 198 117 Selected Operating Results — Downstream Downstream Crude Oil Throughput (Mbbls/d) Canadian Manufacturing U.S. Manufacturing Total Throughput Fuel Sales (1) (millions of litres/d) cardlock, bulk plant and travel centre locations. 2022 92.9 400.8 493.7 6.2 Percent Change (13) — (3) (10) 2021 106.5 401.5 508.0 6.9 Percent Change N/A 116 173 N/A 2020 — 185.9 185.9 — (1) On September 13, 2022, we closed the sale of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes In the Canadian Manufacturing segment, throughput decreased 13.6 thousand barrels per day in 2022 compared with 2021. We completed planned turnarounds at both the Lloydminster Upgrader and Lloydminster Refinery in the second quarter of 2022. In addition, there were multiple temporary unplanned outages at the Upgrader in 2022. In 2021, the Upgrader and Lloydminster Refinery ran at or near capacity throughout the year. In the U.S. Manufacturing segment, total throughput was consistent in 2022 compared with 2021: The Lima Refinery had unplanned operational issues in the first quarter of 2022 coming out of the 2021 fourth quarter turnaround. The refinery performed well during the remainder of the year, achieving crude utilization of 90 percent in At the Toledo Refinery, we completed a significant planned turnaround from April to early August 2022. The refinery remains shut down in a safe state following an incident on September 20, 2022. • We completed two planned turnarounds at the Wood River Refinery in the second and fourth quarters of 2022. The second quarter turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. In early December, there was an incident at the Wood River Refinery that resulted in damage to one of the units and reduced • We completed a turnaround at the Borger Refinery in the first and second quarter of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022. • We commenced commissioning for the restart of the Superior Refinery in December 2022. • • 2022. throughput. Operating Margin is a specified 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. Selected Consolidated Financial Results Operating Margin ($ millions) Gross Sales Less: Royalties Revenues Expenses Purchased Product Transportation and Blending Operating Expenses Operating Margin details. total Operating Margin. Realized (Gain) Loss on Risk Management Activities 2022 79,229 4,868 74,361 39,334 12,194 6,839 1,731 14,263 2021 (1)(2) 54,102 2,454 51,648 27,170 8,714 5,499 892 9,373 2020 14,523 371 14,152 5,959 4,764 2,261 247 921 (1) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (2) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no change to Operating Margin by Segment Year Ended December 31, 2022 (1) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuel business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. Operating Margin increased in 2022, mainly due to higher average realized sales prices, resulting from higher benchmark pricing. In addition, realized refining margins almost doubled in our downstream business due to significantly higher market crack spreads from 2021. These increases in Operating Margin were partially offset by: • • • • • • • • Increased blending costs due to higher condensate prices. Higher royalties and fuel costs in our upstream operations, both resulting from significantly higher commodity pricing. Increased realized risk management losses on the settlement of benchmark prices relative to our risk management contract prices in 2022. In the second quarter of 2022, all WTI risk management contracts related to our crude oil sales price risk management activities were closed. Planned turnarounds and unplanned outages in our downstream operations in 2022, which impacted sales volumes and operating expenses. In our realized margin, higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment. Increased transportation costs due to increased tariffs combined with higher sales volumes at Foster Creek, Christina Lake and Sunrise. Higher operating expenses at the Superior Refinery. Costs increased compared with 2021 as we prepared for restart. Increased electricity and chemical costs in our upstream operations. 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) Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow 2022 11,403 (150) 575 10,978 2021 5,919 (102) (1,227) 7,248 2020 273 (42) 198 117 CENOVUS ENERGY 2022 ANNUAL REPORT | 15 Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to: • • • Increased Operating Margin, as discussed above. Lower finance costs which decreased $262 million in 2022 compared with 2021, primarily due to long-term debt purchases in 2021 and 2022. Decreased integration and transaction costs, a decline of $243 million in 2022 compared with 2021. The integration of Cenovus and Husky is substantially complete. The increase was partially offset by higher cash taxes and higher quarterly contingent payments in 2022. Cash from operating activities also increased as the net change in non-cash working capital increased by $1.8 billion compared to 2021. The increase was due to higher income tax payable and lower accounts receivable, offset by higher inventory at December 31, 2022 compared with December 31, 2021. Net Earnings (Loss) ($ millions) Net Earnings (Loss), Comparative Year Increase (Decrease) due to: Operating Margin Corporate and Eliminations: General and Administrative Finance Costs Integration and Transaction Costs Unrealized Foreign Exchange Gain (Loss) Revaluation Gains Re-measurement of Contingent Payments Gain (Loss) on Divestiture of Assets Other Income (Loss), net Other (1) Unrealized Risk Management Gain (Loss) Depreciation, Depletion and Amortization Exploration Expense Income Tax Recovery (Expense) Net Earnings (Loss), Current Year 2022 vs. 2021 2021 vs. 2020 weakened relative to the U.S. dollar on December 31, 2022, impacting our U.S. dollar debt. 587 4,890 (16) 262 243 (677) 549 413 40 223 308 57 1,207 (83) (1,553) 6,450 (2,379) 8,452 (557) (546) (320) 181 — (655) 148 349 (194) 36 (2,422) 73 (1,579) 587 (1) Includes Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management; share of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses. Net earnings improved significantly compared with 2021 due to: • • • • • • • • Increased Operating Margin, as discussed above. Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021. Revaluation gains of $549 million related to the Sunrise Acquisition in the third quarter of 2022. A loss on re-measurement of the contingent payments of $162 million compared with $575 million in 2021. The final payment related to the FCCL Partnership was made in July 2022. Re-measurements related to the Sunrise Acquisition began in the third quarter of 2022. Finance costs of $820 million compared with $1.1 billion in 2021, mainly due to a lower average long-term debt balance in 2022. Integration and transaction costs of $106 million, compared with $349 million in 2021. Higher other income primarily due to insurance proceeds related to the Superior Refinery. A realized foreign exchange gain of $22 million in 2022 compared to realized foreign exchange losses of $138 million in 2021. The gains in 2022 related to working capital were partially offset by losses on the purchase of debt. The increase in net earnings in 2022 was partially offset by: • • Higher income tax expense. Unrealized foreign exchange losses as the Canadian dollar at December 31, 2022, weakened relative to the U.S. dollar. 16 | CENOVUS ENERGY 2022 ANNUAL REPORT Long-term debt decreased by $3.7 billion and Net Debt decreased by $5.3 billion from December 31, 2021. In 2022, we purchased US$2.6 billion of principal related to notes due between 2023 and 2043, and paid a premium on redemption of US$41 million, collectively. In addition, we paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 at par. The decrease in long-term debt was partially offset as the Canadian dollar Net Debt As at ($ millions) Short-Term Borrowings Current Portion of Long-Term Debt Long-Term Debt Total Debt Net Debt Less: Cash and Cash Equivalents Capital Investment (1) ($ millions) Upstream Oil Sands Conventional Offshore Total Upstream Downstream Canadian Manufacturing (2) U.S. Manufacturing Total Downstream Corporate and Eliminations Total Capital Investment December 31, 2022 December 31, 2021 115 — 8,691 8,806 (4,524) 4,282 2021 1,019 222 175 1,416 68 995 1,063 84 2,563 79 — 12,385 12,464 (2,873) 9,591 2020 427 78 — 505 33 243 276 60 841 2022 1,792 344 310 2,446 117 1,059 1,176 86 3,708 (1) Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in our equity-accounted investment in Indonesia. (2) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. Oil Sands capital investment in 2022 was primarily focused on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program. Conventional capital investment in 2022 focused on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development. Offshore capital investment in 2022 was primarily for the Terra Nova asset life extension (“ALE”) project and capital for the West White Rose project in the Atlantic region. On May 31, 2022, Cenovus and our partners announced the restart of the West White Rose project offshore Newfoundland and Labrador. U.S. Manufacturing capital investment in 2022 focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery. Drilling Activity Foster Creek (2) Christina Lake (3) Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Tucker (4) Net Stratigraphic Test Wells and Observation Wells 2022 2021 Net Production Wells (1) 2022 2021 2020 68 — 15 98 8 6 195 32 25 — 115 15 — 187 2020 38 117 — — — — 155 29 31 10 33 11 — 114 6 18 2 46 3 — 75 — — — — — — — SAGD well pairs in the Oil Sands segment are counted as a single producing well. (1) (2) (3) (4) Includes Ipiatik. Includes Narrows Lake. The Tucker asset was sold on January 31, 2022. ($ millions) Net Earnings (Loss), Comparative Year Increase (Decrease) due to: Operating Margin Corporate and Eliminations: General and Administrative Finance Costs Integration and Transaction Costs Unrealized Foreign Exchange Gain (Loss) Revaluation Gains Re-measurement of Contingent Payments Gain (Loss) on Divestiture of Assets Other Income (Loss), net Other (1) Unrealized Risk Management Gain (Loss) Depreciation, Depletion and Amortization Exploration Expense Income Tax Recovery (Expense) Net Earnings (Loss), Current Year • • • • • • • • • • • • • 587 4,890 (16) 262 243 (677) 549 413 40 223 308 57 1,207 (83) (1,553) 6,450 (2,379) 8,452 (557) (546) (320) 181 — (655) 148 349 (194) (2,422) 36 73 (1,579) 587 (1) Includes Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management; share of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses. Net earnings improved significantly compared with 2021 due to: Increased Operating Margin, as discussed above. Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021. Revaluation gains of $549 million related to the Sunrise Acquisition in the third quarter of 2022. A loss on re-measurement of the contingent payments of $162 million compared with $575 million in 2021. The final payment related to the FCCL Partnership was made in July 2022. Re-measurements related to the Sunrise Acquisition Finance costs of $820 million compared with $1.1 billion in 2021, mainly due to a lower average long-term debt began in the third quarter of 2022. balance in 2022. Integration and transaction costs of $106 million, compared with $349 million in 2021. Higher other income primarily due to insurance proceeds related to the Superior Refinery. A realized foreign exchange gain of $22 million in 2022 compared to realized foreign exchange losses of $138 million in 2021. The gains in 2022 related to working capital were partially offset by losses on the purchase of debt. The increase in net earnings in 2022 was partially offset by: Higher income tax expense. Unrealized foreign exchange losses as the Canadian dollar at December 31, 2022, weakened relative to the U.S. dollar. Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to: Lower finance costs which decreased $262 million in 2022 compared with 2021, primarily due to long-term debt Decreased integration and transaction costs, a decline of $243 million in 2022 compared with 2021. The integration of Increased Operating Margin, as discussed above. purchases in 2021 and 2022. Cenovus and Husky is substantially complete. The increase was partially offset by higher cash taxes and higher quarterly contingent payments in 2022. Cash from operating activities also increased as the net change in non-cash working capital increased by $1.8 billion compared to 2021. The increase was due to higher income tax payable and lower accounts receivable, offset by higher inventory at December 31, 2022 compared with December 31, 2021. Net Earnings (Loss) 2022 vs. 2021 2021 vs. 2020 Net Debt As at ($ millions) Short-Term Borrowings Current Portion of Long-Term Debt Long-Term Debt Total Debt Less: Cash and Cash Equivalents Net Debt December 31, 2022 December 31, 2021 115 — 8,691 8,806 (4,524) 4,282 79 — 12,385 12,464 (2,873) 9,591 Long-term debt decreased by $3.7 billion and Net Debt decreased by $5.3 billion from December 31, 2021. In 2022, we purchased US$2.6 billion of principal related to notes due between 2023 and 2043, and paid a premium on redemption of US$41 million, collectively. In addition, we paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 at par. The decrease in long-term debt was partially offset as the Canadian dollar weakened relative to the U.S. dollar on December 31, 2022, impacting our U.S. dollar debt. Capital Investment (1) ($ millions) Upstream Oil Sands Conventional Offshore Total Upstream Downstream Canadian Manufacturing (2) U.S. Manufacturing Total Downstream Corporate and Eliminations Total Capital Investment 2022 1,792 344 310 2,446 117 1,059 1,176 86 3,708 2021 1,019 222 175 1,416 68 995 1,063 84 2,563 2020 427 78 — 505 33 243 276 60 841 (1) (2) Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in our equity-accounted investment in Indonesia. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. Oil Sands capital investment in 2022 was primarily focused on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program. Conventional capital investment in 2022 focused on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development. Offshore capital investment in 2022 was primarily for the Terra Nova asset life extension (“ALE”) project and capital for the West White Rose project in the Atlantic region. On May 31, 2022, Cenovus and our partners announced the restart of the West White Rose project offshore Newfoundland and Labrador. U.S. Manufacturing capital investment in 2022 focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery. Drilling Activity Foster Creek (2) Christina Lake (3) Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Tucker (4) Net Stratigraphic Test Wells and Observation Wells Net Production Wells (1) 2022 68 — 15 98 8 6 195 2021 32 25 — 115 15 — 187 2020 38 117 — — — — 155 2022 29 31 10 33 11 — 114 2021 6 18 2 46 3 — 75 2020 — — — — — — — (1) (2) (3) (4) SAGD well pairs in the Oil Sands segment are counted as a single producing well. Includes Ipiatik. Includes Narrows Lake. The Tucker asset was sold on January 31, 2022. CENOVUS ENERGY 2022 ANNUAL REPORT | 17 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. COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS (net wells) Conventional Drilled 31 2022 Completed Tied-in Drilled 2021 Completed Tied-in Drilled 2020 Completed 35 36 27 19 18 6 1 Tied-in 3 In the Offshore segment, we drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia in 2022 (2021 — drilled one exploration well in China). We achieved first gas production at the MBH and MDA fields in the fourth quarter of 2022. Future Capital Investment Future Capital Investment is a specified financial measure. See the Advisory. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. The following table shows guidance for 2023: Upstream Oil Sands Conventional Offshore Downstream Corporate and Eliminations Capital Investment ($ millions) Production (MBOE/d) Crude Throughput (Mbbls/d) 2,200 - 2,400 350 - 450 600 - 700 800 - 900 40 - 50 582 - 642 125 - 140 65 - 78 610 - 660 2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital. Sustaining capital is mainly related to: • • • • Investment in the Oil Sands segment. Safety and reliability initiatives in the Canadian Manufacturing segment. The planned restart of the Superior Refinery. Offsetting natural declines and optimizing gas handling infrastructure in the Conventional segment. Optimization and growth capital including downstream initiatives that will further mitigate the Company’s exposure to light- heavy differentials. Optimization and growth capital is mainly related to: Construction of the West White Rose project and the completion of the Terra Nova ALE project. Progressing the Narrows Lake tie-back to Christina Lake. Continued optimization of Foster Creek and the Lloydminster thermal projects. Application of Cenovus’s operating model at Sunrise. • • • • • Margin expansion and debottlenecking opportunities in our downstream assets, which include feedstock replacement at the Lloydminster Refinery as part of the Company’s Rewire Alberta initiative. Increasing heavy crude oil conversion capacity and distillate output at the Wood River and Borger refineries. • Further information on the changes in our financial and operating results can be found in the Reportable Segments section of this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements. 18 | CENOVUS ENERGY 2022 ANNUAL REPORT Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results. Selected Benchmark Prices and Exchange Rates (1) (Average US$/bbl, unless otherwise indicated) Q4 2022 Q4 2021 Percent Change Dated Brent WTI Differential Dated Brent-WTI WCS at Hardisty Differential WTI-WCS WCS (C$/bbl) WCS at Nederland Differential WTI-WCS at Nederland Condensate (C5 @ Edmonton) Differential WTI-Condensate (Premium)/Discount Differential WCS-Condensate (Premium)/Discount Average (C$/bbl) Synthetic @ Edmonton Refined Product Prices Differential WTI-Synthetic (Premium)/Discount Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (2) Group 3 3-2-1 Crack Spread (2) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (C$/Mcf) NYMEX (US$/Mcf) Foreign Exchange Rates US$ per C$1 - Average US$ per C$1 - End of Period RMB per C$1 - Average 2022 101.19 94.23 6.96 76.01 18.22 98.51 85.77 8.46 93.78 0.45 (17.77) 121.78 98.66 (4.43) 120.63 143.85 34.15 33.21 7.72 5.56 6.64 0.769 0.738 5.170 43 39 147 39 40 43 34 121 38 N/A (33) 42 49 N/A 42 67 95 86 14 56 73 (4) (6) — 2021 70.73 67.91 2.82 54.87 13.04 68.73 64.09 3.82 68.20 (0.29) (13.33) 85.47 66.28 1.63 85.07 86.37 17.54 17.82 6.76 3.56 3.84 0.798 0.789 5.147 2020 41.67 39.40 2.27 26.80 12.60 35.59 35.86 3.54 37.16 2.24 (10.36) 49.44 36.25 3.15 7.54 8.67 2.48 2.24 2.08 0.746 0.785 5.147 88.71 82.65 6.06 56.99 25.66 77.42 67.65 15.00 83.40 (0.75) (26.41) 113.25 86.79 (4.14) 32.87 29.99 8.54 5.58 6.26 0.737 0.738 5.241 45.24 50.08 102.80 140.95 79.73 77.19 2.54 62.55 14.64 78.71 71.62 5.57 79.13 (1.94) (16.58) 99.64 75.40 1.79 91.84 96.53 16.06 15.82 6.11 4.94 5.83 0.794 0.789 5.073 (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) 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 2022, global crude oil prices improved significantly compared to 2021. Prices rose steadily through 2021 and during the first half of 2022 as global supply and demand balances remained tight, while inventories were low. Demand for crude oil and refined products continued to grow towards pre-pandemic levels despite macroeconomic challenges, weakness in Chinese consumption due to COVID-19 lockdowns, and geopolitical uncertainty around Russia’s invasion of Ukraine. Crude oil supply grew considerably in 2022 but struggled to match growing demand, with nearly all short-term supply sources accessed to meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). Global spare production capacity remains low. 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. The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential widened compared with 2021 due to higher shipping costs and supply disruptions as a result of Russia’s invasion of Ukraine. (net wells) Conventional Drilled Completed Tied-in Drilled Completed Tied-in Drilled Completed Tied-in 31 35 36 27 19 18 6 1 3 2022 2021 2020 In the Offshore segment, we drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia in 2022 (2021 — drilled one exploration well in China). We achieved first gas production at the MBH and MDA Future Capital Investment is a specified financial measure. See the Advisory. Our 2023 guidance dated December 5, 2022, fields in the fourth quarter of 2022. Future Capital Investment is available on our website at cenovus.com. The following table shows guidance for 2023: Upstream Oil Sands Conventional Offshore Downstream Corporate and Eliminations Capital Investment Production Crude Throughput ($ millions) (MBOE/d) (Mbbls/d) 2,200 - 2,400 350 - 450 600 - 700 800 - 900 40 - 50 582 - 642 125 - 140 65 - 78 610 - 660 2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital. • • • • • • • • • Sustaining capital is mainly related to: Investment in the Oil Sands segment. Safety and reliability initiatives in the Canadian Manufacturing segment. The planned restart of the Superior Refinery. Offsetting natural declines and optimizing gas handling infrastructure in the Conventional segment. Optimization and growth capital including downstream initiatives that will further mitigate the Company’s exposure to light- heavy differentials. Optimization and growth capital is mainly related to: Construction of the West White Rose project and the completion of the Terra Nova ALE project. Progressing the Narrows Lake tie-back to Christina Lake. Continued optimization of Foster Creek and the Lloydminster thermal projects. Application of Cenovus’s operating model at Sunrise. • Margin expansion and debottlenecking opportunities in our downstream assets, which include feedstock replacement at the Lloydminster Refinery as part of the Company’s Rewire Alberta initiative. Increasing heavy crude oil conversion capacity and distillate output at the Wood River and Borger refineries. 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. 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. 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) Dated Brent WTI Differential Dated Brent-WTI WCS at Hardisty Differential WTI-WCS WCS (C$/bbl) WCS at Nederland Differential WTI-WCS at Nederland Condensate (C5 @ Edmonton) Differential WTI-Condensate (Premium)/Discount Differential WCS-Condensate (Premium)/Discount Average (C$/bbl) Synthetic @ Edmonton Differential WTI-Synthetic (Premium)/Discount Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (2) Group 3 3-2-1 Crack Spread (2) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (C$/Mcf) NYMEX (US$/Mcf) Foreign Exchange Rates US$ per C$1 - Average US$ per C$1 - End of Period RMB per C$1 - Average 2022 101.19 94.23 6.96 76.01 18.22 98.51 85.77 8.46 93.78 0.45 (17.77) 121.78 98.66 (4.43) 120.63 143.85 34.15 33.21 7.72 5.56 6.64 0.769 0.738 5.170 Percent Change 43 39 147 39 40 43 34 121 38 N/A (33) 42 49 N/A 42 67 95 86 14 56 73 (4) (6) — 2021 70.73 67.91 2.82 54.87 13.04 68.73 64.09 3.82 68.20 (0.29) (13.33) 85.47 66.28 1.63 85.07 86.37 17.54 17.82 6.76 3.56 3.84 0.798 0.789 5.147 Q4 2022 Q4 2021 2020 41.67 39.40 2.27 26.80 12.60 35.59 35.86 3.54 37.16 2.24 (10.36) 49.44 36.25 3.15 88.71 82.65 6.06 56.99 25.66 77.42 67.65 15.00 83.40 (0.75) (26.41) 113.25 86.79 (4.14) 45.24 50.08 102.80 140.95 7.54 8.67 2.48 2.24 2.08 0.746 0.785 5.147 32.87 29.99 8.54 5.58 6.26 0.737 0.738 5.241 79.73 77.19 2.54 62.55 14.64 78.71 71.62 5.57 79.13 (1.94) (16.58) 99.64 75.40 1.79 91.84 96.53 16.06 15.82 6.11 4.94 5.83 0.794 0.789 5.073 (1) (2) 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. 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 2022, global crude oil prices improved significantly compared to 2021. Prices rose steadily through 2021 and during the first half of 2022 as global supply and demand balances remained tight, while inventories were low. Demand for crude oil and refined products continued to grow towards pre-pandemic levels despite macroeconomic challenges, weakness in Chinese consumption due to COVID-19 lockdowns, and geopolitical uncertainty around Russia’s invasion of Ukraine. Crude oil supply grew considerably in 2022 but struggled to match growing demand, with nearly all short-term supply sources accessed to meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). Global spare production capacity remains low. 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. The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI differential widened compared with 2021 due to higher shipping costs and supply disruptions as a result of Russia’s invasion of Ukraine. CENOVUS ENERGY 2022 ANNUAL REPORT | 19 WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. In 2022, the average WTI-WCS differential at Hardisty widened compared to 2021, primarily due to a wider quality differential at the U.S. Gulf Coast (“USGC”) outlined below, as well as higher production activity in Western Canada. WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil supply. The WTI-WCS at Nederland differential widened significantly compared with 2021, particularly in the second half of 2022. It is mainly attributed to reduced demand due to planned and unplanned refinery maintenance, high global refining utilization, volatile refined product pricing and increased supply due to some incremental medium and heavy oil barrels into the market from OPEC+, and from the release of volume from SPRs in the U.S. In Canada, 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. Synthetic crude at Edmonton strengthened significantly in 2022 compared with 2021 as a result of widespread upgrader maintenance in Western Canada and strong refinery demand for light crude oil. In 2022, the WTI-Synthetic differential was at a premium compared with a discount in 2021 as synthetic crudes continue to be supported by strong demand for refined products. Average Chicago refined product prices increased significantly in 2022 compared with 2021. While gasoline prices strengthened year-over-year, the increase in market crack spreads were primarily driven by a substantial rise in distillate prices. The strength in market crack spreads and refined product prices has also been driven by refinery rationalization since the beginning of the pandemic, leading to high refinery utilization globally, combined with low global inventories of refined products. RINs costs remain high as a result of a tight biofuel market, rising feedstock prices and uncertainty around policies that drive RINs demand. 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 generally reflects 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; where feedstocks are acquired and 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. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator. Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 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. The average Edmonton condensate benchmark remained near parity with WTI in 2022 as Alberta demand for condensate is strong and supply remains tight. 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 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 the Borger Refinery. 20 | CENOVUS ENERGY 2022 ANNUAL REPORT (1) There are no forward prices for RINs. Natural Gas Benchmarks Average NYMEX natural gas prices increased significantly in 2022, compared with 2021, due to a rebound in U.S. domestic demand and high liquified natural gas exports, coupled with a muted supply response and strong global pricing amid Russian supply concerns. Average AECO prices also increased significantly in 2022 compared with 2021 along with NYMEX prices, but the differentials between AECO and NYMEX widened slightly due to higher Western Canadian production as well as planned and unplanned pipeline maintenance limiting egress at points during 2022. The price received for our Asia Pacific natural gas production is largely based on long-term contracts. Foreign Exchange Benchmarks 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 our U.S. and Asia Pacific operations. In 2022, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2021, positively impacting our revenues year-over-year. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2022, compared with December 31, 2021, resulting in unrealized foreign exchange losses of $365 million on the translation of our U.S. dollar debt into Canadian dollars. revenues year-over-year. A portion of our long-term sales contracts in the 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. In 2022, the Canadian dollar on average was relatively flat compared with RMB, resulting in minimal impact on our WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. In 2022, the average WTI-WCS differential at Hardisty widened compared to 2021, primarily due to a wider quality differential at the U.S. Gulf Coast (“USGC”) outlined below, as well as higher production activity in Western Canada. WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil supply. The WTI-WCS at Nederland differential widened significantly compared with 2021, particularly in the second half of 2022. It is mainly attributed to reduced demand due to planned and unplanned refinery maintenance, high global refining utilization, volatile refined product pricing and increased supply due to some incremental medium and heavy oil barrels into the market from OPEC+, and from the release of volume from SPRs in the U.S. In Canada, 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. Synthetic crude at Edmonton strengthened significantly in 2022 compared with 2021 as a result of widespread upgrader maintenance in Western Canada and strong refinery demand for light crude oil. In 2022, the WTI-Synthetic differential was at a premium compared with a discount in 2021 as synthetic crudes continue to be supported by strong demand for refined products. Average Chicago refined product prices increased significantly in 2022 compared with 2021. While gasoline prices strengthened year-over-year, the increase in market crack spreads were primarily driven by a substantial rise in distillate prices. The strength in market crack spreads and refined product prices has also been driven by refinery rationalization since the beginning of the pandemic, leading to high refinery utilization globally, combined with low global inventories of refined products. RINs costs remain high as a result of a tight biofuel market, rising feedstock prices and uncertainty around policies that drive RINs demand. 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 generally reflects 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; where feedstocks are acquired and 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. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator. Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 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. The average Edmonton condensate benchmark remained near parity with WTI in 2022 as Alberta demand for condensate is strong and supply remains tight. 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 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 the Borger Refinery. (1) There are no forward prices for RINs. Natural Gas Benchmarks Average NYMEX natural gas prices increased significantly in 2022, compared with 2021, due to a rebound in U.S. domestic demand and high liquified natural gas exports, coupled with a muted supply response and strong global pricing amid Russian supply concerns. Average AECO prices also increased significantly in 2022 compared with 2021 along with NYMEX prices, but the differentials between AECO and NYMEX widened slightly due to higher Western Canadian production as well as planned and unplanned pipeline maintenance limiting egress at points during 2022. The price received for our Asia Pacific natural gas production is largely based on long-term contracts. Foreign Exchange Benchmarks 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 our U.S. and Asia Pacific operations. In 2022, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2021, positively impacting our revenues year-over-year. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2022, compared with December 31, 2021, resulting in unrealized foreign exchange losses of $365 million on the translation of our U.S. dollar debt into Canadian dollars. A portion of our long-term sales contracts in the 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. In 2022, the Canadian dollar on average was relatively flat compared with RMB, resulting in minimal impact on our revenues year-over-year. CENOVUS ENERGY 2022 ANNUAL REPORT | 21 Interest Rate Benchmarks Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how certain liabilities are measured, and could negatively impact our cash flow and financial results. As at December 31, 2022, the Bank of Canada’s Policy Interest Rate was 4.25 percent, an increase from 0.25 percent on December 31, 2021, due to concerns over inflation. On January 25, 2023, the rate increased a further 0.25 percent to 4.50 percent. OUTLOOK COMMODITY PRICE OUTLOOK Crude oil prices improved significantly in 2022, but waned in the second half of the year due to demand concerns amid a weakening macroeconomic environment and COVID-19 lockdowns in China. The geopolitical premium associated with Russian supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shifting global trade patterns. OPEC+ policy will continue to be a key driver of crude oil prices and the recent announcement of a cut to the group’s production quotas is supportive of pricing. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions, the timing and ability of producers and governments to replace reduced supply, the refilling or release of SPRs and OPEC+ policy. In addition, potential incremental COVID-19 outbreaks and variants, weakening global economic activity, inflation and rising interest rates, and the potential for a recession remain a risk to the pace of demand growth. In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following: • We expect that the WTI-WCS differential will remain largely tied to global supply factors and heavy crude oil processing capacity as long as supply stays within Canadian crude oil export capacity. • We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America. • We expect both NYMEX and AECO prices to remain strong but increasing supply and limited LNG export capacity from North America will put downward pressure on prices. Prices will continue to be impacted by weather. • 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. Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil price. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel, solvent and blending requirements at our Oil Sands operations. Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly. 22 | CENOVUS ENERGY 2022 ANNUAL REPORT Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our 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 differentials, which could be 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 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 – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil as well as from spreads on refined products. 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. • • • • All WTI contracts related to our crude oil sales price risk management activities closed by June 30, 2022. We continue to use financial instruments to mitigate our exposure to the prices of various commodities, including some WTI contracts for exposure management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy continues to focus on maximizing shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and sustainability leadership. We prioritize Free Funds Flow generation that enables debt reduction, shareholder returns through a combination of base dividend growth and flexible return mechanisms, reinvestment in the business and diversification of our and renewable power contracts. KEY PRIORITIES FOR 2023 portfolio. Our 2023 priorities will focus on: Top Tier Safety and Operational Performance Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, including top-tier health and safety performance. We will continue to target improved downstream operating performance, including the safe return of the Superior Refinery to full operations and, following the close of the Toledo Acquisition, integration of the Toledo Refinery with a focus on demonstrating consistent and reliable performance at our operated assets. Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five ESG focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are: Sustainability Leadership Climate & GHG Emissions. • Water Stewardship. Biodiversity. Indigenous reconciliation. Inclusion & diversity. • • • • Cost Leadership Additional information on management’s efforts and performance across ESG focus areas, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report on our website at cenovus.com. We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize our cost structure in all areas of our business, one of our focus areas will be to optimize infrastructure, reduce operating and capital costs, and reduce GHG emissions at our conventional assets. Financial Discipline and Free Funds Flow Growth We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder returns framework. Interest Rate Benchmarks Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how certain liabilities are measured, and could negatively impact our cash flow and financial results. As at December 31, 2022, the Bank of Canada’s Policy Interest Rate was 4.25 percent, an increase from 0.25 percent on December 31, 2021, due to concerns over inflation. On January 25, 2023, the rate increased a further 0.25 percent to 4.50 percent. OUTLOOK COMMODITY PRICE OUTLOOK Crude oil prices improved significantly in 2022, but waned in the second half of the year due to demand concerns amid a weakening macroeconomic environment and COVID-19 lockdowns in China. The geopolitical premium associated with Russian supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient. Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that will drive energy supply and shifting global trade patterns. OPEC+ policy will continue to be a key driver of crude oil prices and the recent announcement of a cut to the group’s production quotas is supportive of pricing. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions, the timing and ability of producers and governments to replace reduced supply, the refilling or release of SPRs and OPEC+ policy. In addition, potential incremental COVID-19 outbreaks and variants, weakening global economic activity, inflation and rising interest rates, and the potential for a recession remain a risk to the pace of demand growth. In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following: • We expect that the WTI-WCS differential will remain largely tied to global supply factors and heavy crude oil processing capacity as long as supply stays within Canadian crude oil export capacity. • We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America. • We expect both NYMEX and AECO prices to remain strong but increasing supply and limited LNG export capacity from North America will put downward pressure on prices. Prices will continue to be impacted by weather. • 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. Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil price. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel, solvent and blending requirements at our Oil Sands operations. Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at our refineries accordingly. Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our 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 differentials, which could be 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 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 – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian crude oil as well as from spreads on refined products. 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. All WTI contracts related to our crude oil sales price risk management activities closed by June 30, 2022. We continue to use financial instruments to mitigate our exposure to the prices of various commodities, including some WTI contracts for exposure management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity and renewable power contracts. KEY PRIORITIES FOR 2023 At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy continues to focus on maximizing shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and sustainability leadership. We prioritize Free Funds Flow generation that enables debt reduction, shareholder returns through a combination of base dividend growth and flexible return mechanisms, reinvestment in the business and diversification of our portfolio. Our 2023 priorities will focus on: Top Tier Safety and Operational Performance Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, including top-tier health and safety performance. We will continue to target improved downstream operating performance, including the safe return of the Superior Refinery to full operations and, following the close of the Toledo Acquisition, integration of the Toledo Refinery with a focus on demonstrating consistent and reliable performance at our operated assets. Sustainability Leadership Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five ESG focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are: Climate & GHG Emissions. • • Water Stewardship. • • • Biodiversity. Indigenous reconciliation. Inclusion & diversity. Additional information on management’s efforts and performance across ESG focus areas, including our ESG targets and plans to achieve them, are available in Cenovus’s 2021 ESG report on our website at cenovus.com. Cost Leadership We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize our cost structure in all areas of our business, one of our focus areas will be to optimize infrastructure, reduce operating and capital costs, and reduce GHG emissions at our conventional assets. Financial Discipline and Free Funds Flow Growth We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder returns framework. CENOVUS ENERGY 2022 ANNUAL REPORT | 23 Returns-Focused Capital Allocation We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle and provide opportunities to sustainably grow shareholder returns. We plan to materially progress the West White Rose project while remaining on track to deliver first oil in 2026. Operating Margin Variance Year Ended December 31, 2022 REPORTABLE SEGMENTS UPSTREAM Oil Sands In 2022, we: • • • • • • • • • Delivered safe and reliable operations. Produced 586.6 thousand barrels of crude oil per day. Generated Operating Margin of $9.0 billion, an increase of $2.6 billion compared with 2021 primarily due to higher average realized sales prices. Sold our Tucker asset for net proceeds of $730 million on January 31, 2022. Crude oil production at the time of sale was approximately 20 thousand barrels per day. Purchased the remaining 50 percent interest in Sunrise from BP Canada on August 31, 2022, giving Cenovus full ownership and further enhancing our core strength in oil sands. The Sunrise Acquisition immediately added over 20 thousand barrels per day of crude oil production, and more than offset lost production from the sold Tucker asset. Achieved first oil at our Spruce Lake North thermal plant in September. Production averaged approximately 12.0 thousand barrels per day in the fourth quarter. Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. This is expected to provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to begin in 2024 and we anticipate first steam in 2029. Invested capital of $1.8 billion primarily on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal assets and Sunrise. Achieved a Netback of $49.10 per BOE. Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss from Equity-Accounted Affiliates Segment Income (Loss) 2022 34,775 4,493 30,282 4,810 12,036 2,930 1,527 8,979 (68) 2,763 9 8 6,267 2021 (1) 22,827 2,196 20,631 2,404 8,625 2,451 786 6,365 18 2,666 16 (5) 3,670 2020 8,804 331 8,473 1,262 4,683 1,156 268 1,104 57 1,687 9 — (649) (1) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. 24 | CENOVUS ENERGY 2022 ANNUAL REPORT (1) Reported 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. (2) Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas. 2022 585.8 91.70 191.0 246.5 31.3 99.9 16.3 1.6 586.6 12.3 588.7 25.2 7.89 13.75 11.90 2021 579.9 62.82 179.9 236.8 25.9 97.7 20.2 21.0 581.5 12.6 583.6 18.7 7.23 11.52 11.28 2020 386.6 28.64 163.2 218.5 — — — — — 381.7 381.7 11.6 8.70 7.84 10.40 Operating Results Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Crude Oil Production by Asset (Mbbls/d) Foster Creek Christina Lake Sunrise (2) Lloydminster Thermal Lloydminster Conventional Heavy Oil Tucker (3) Total Crude Oil Production (4) (Mbbls/d) Natural Gas (5) (MMcf/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Transportation and Blending Cost (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) (1) (2) (3) (4) (5) Specified financial measure. See the Advisory. BP Canada. The Tucker asset was sold on January 31, 2022. Conventional natural gas product type. Revenues Price production. Represents Cenovus’s 50 percent interest in Sunrise up to August 31, 2022. On August 31, 2022, we acquired the remaining 50 percent interest from Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil. Our heavy oil and bitumen production 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 Our realized sales price averaged $91.70 per BOE in 2022 compared with $62.82 per BOE in 2021 due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. To improve our realized sales price, we sold approximately 20 percent (2021 – 20 percent) of our crude oil volumes at U.S. destinations. For the year ended December 31, 2022, gross sales included $4.5 billion (2021 – $2.1 billion), from third-party sourced volumes which are not included in our realized price or our Netbacks. Refer to the Advisory for more detail. REPORTABLE SEGMENTS UPSTREAM Oil Sands In 2022, we: • • • • • • • • • Delivered safe and reliable operations. Produced 586.6 thousand barrels of crude oil per day. realized sales prices. approximately 20 thousand barrels per day. Sold our Tucker asset for net proceeds of $730 million on January 31, 2022. Crude oil production at the time of sale was Purchased the remaining 50 percent interest in Sunrise from BP Canada on August 31, 2022, giving Cenovus full ownership and further enhancing our core strength in oil sands. The Sunrise Acquisition immediately added over 20 thousand barrels per day of crude oil production, and more than offset lost production from the sold Tucker asset. Achieved first oil at our Spruce Lake North thermal plant in September. Production averaged approximately 12.0 thousand Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. This is expected to provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to begin in 2024 and we Invested capital of $1.8 billion primarily on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal barrels per day in the fourth quarter. anticipate first steam in 2029. assets and Sunrise. Achieved a Netback of $49.10 per BOE. Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss from Equity-Accounted Affiliates Segment Income (Loss) details. 2022 34,775 4,493 30,282 4,810 12,036 2,930 1,527 8,979 (68) 2,763 9 8 6,267 2021 (1) 22,827 2,196 20,631 2,404 8,625 2,451 786 6,365 18 2,666 16 (5) 3,670 2020 8,804 331 8,473 1,262 4,683 1,156 268 1,104 57 1,687 9 — (649) (1) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further Returns-Focused Capital Allocation We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle and provide opportunities to sustainably grow shareholder returns. We plan to materially progress the West White Rose project while remaining on track to deliver first oil in 2026. Operating Margin Variance Year Ended December 31, 2022 Generated Operating Margin of $9.0 billion, an increase of $2.6 billion compared with 2021 primarily due to higher average Operating Results (1) (2) Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of condensate purchases. Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas. Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Crude Oil Production by Asset (Mbbls/d) Foster Creek Christina Lake Sunrise (2) Lloydminster Thermal Lloydminster Conventional Heavy Oil Tucker (3) Total Crude Oil Production (4) (Mbbls/d) Natural Gas (5) (MMcf/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Transportation and Blending Cost (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) 2022 585.8 91.70 191.0 246.5 31.3 99.9 16.3 1.6 586.6 12.3 588.7 25.2 7.89 13.75 11.90 2021 579.9 62.82 179.9 236.8 25.9 97.7 20.2 21.0 581.5 12.6 583.6 18.7 7.23 11.52 11.28 2020 386.6 28.64 163.2 218.5 — — — — 381.7 — 381.7 11.6 8.70 7.84 10.40 (1) (2) (3) (4) (5) Specified financial measure. See the Advisory. Represents Cenovus’s 50 percent interest in Sunrise up to August 31, 2022. On August 31, 2022, we acquired the remaining 50 percent interest from BP Canada. The Tucker asset was sold on January 31, 2022. Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil. Conventional natural gas product type. Revenues Price Our heavy oil and bitumen production 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. Our realized sales price averaged $91.70 per BOE in 2022 compared with $62.82 per BOE in 2021 due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. To improve our realized sales price, we sold approximately 20 percent (2021 – 20 percent) of our crude oil volumes at U.S. destinations. For the year ended December 31, 2022, gross sales included $4.5 billion (2021 – $2.1 billion), from third-party sourced volumes which are not included in our realized price or our Netbacks. Refer to the Advisory for more detail. CENOVUS ENERGY 2022 ANNUAL REPORT | 25 For the year ended December 31, 2022, gross sales included $358 million (2021 – $329 million), relating to construction, transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the Advisory for more detail. Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, and transportation commitments and customer diversification. 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 and improve cash flow stability. In 2022, we incurred realized risk management losses of $1.5 billion, of which $431 million related to the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized risk management gains of $68 million on our crude oil and condensate financial instruments. Production Volumes Oil Sands crude oil production increased slightly to 586.6 thousand barrels per day in 2022 compared with 581.5 thousand barrels per day in 2021. We sold the Tucker asset on January 31, 2022, resulting in decreased production of 19.4 thousand barrels per day in 2022 compared with 2021. Production at Foster Creek increased 11.1 thousand barrels per day to 191.0 thousand barrels per day in 2022 compared with 2021, due to new wells coming online in 2022 and the last half of 2021. In addition, we completed a planned turnaround in the second quarter of 2021. The increase was partially offset as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Also offsetting the increase was planned maintenance and an unplanned outage in the third quarter of 2022. Production at Christina Lake increased 9.7 thousand barrels per day to 246.5 thousand barrels per day in 2022 compared with 2021. We added incremental production from redevelopment wells drilled in 2022 and the last half of 2021. The increase was offset by a planned turnaround in the second quarter of 2022. The Sunrise Acquisition was completed on August 31, 2022 and added 5.4 thousand barrels per day of production in 2022 compared with 2021. The increase in production at Sunrise in 2022 was partially offset by base declines and wells taken offline in preparation for a redevelopment program. Production from our Lloydminster thermal assets increased slightly in 2022 compared with 2021. The Spruce Lake North thermal plant achieved first oil in August, and production averaged approximately 12.0 thousand barrels per day in the fourth quarter. The increase was partially offset by base declines at other thermal plants and wells taken offline in preparation for a redevelopment program in the fourth quarter of 2022 and into 2023. Lloydminster conventional heavy oil production decreased marginally in 2022 compared with 2021, as wells were shut-in to meet new emissions regulations in Alberta. 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 and Sunrise) 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 calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs. Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project. For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes 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. 26 | CENOVUS ENERGY 2022 ANNUAL REPORT Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates. For the year ended December 31, 2022, royalties were $4.5 billion (2021 – $2.2 billion). Expenses Transportation and Blending condensate prices. In 2022, blending costs rose $3.2 billion to $10.3 billion compared with 2021. The increases were largely due to higher Transportation costs increased $179 million to $1.7 billion in 2022 compared with 2021. The increases were primarily due to higher costs as discussed below combined with increased sales volumes at Foster Creek, Christina Lake and Sunrise. Per-unit Transportation Expenses Transportation costs were $7.89 per BOE in 2022 up slightly from $7.23 per BOE in 2021. At Foster Creek, per-unit transportation costs increased 12 percent to $11.78 per barrel in 2022 compared with 2021. The increase was mainly due to increased tariffs, partially offset by reduced reliance on rail. For the year ended December 31, 2022, we shipped 40 percent (2021 – 35 percent), of our volumes from Foster Creek to U.S. destinations. At Christina Lake, transportation costs were $6.51 per barrel in 2022, consistent with $6.19 per barrel in 2021. At Sunrise, transportation costs were $12.26 per barrel in 2022, consistent with $12.14 per barrel in 2021, as we shipped a similar percentage of our total volumes to the U.S. At our Other Oil Sands assets, transportation costs in 2022 were $3.49 per barrel, compared with $4.01 per barrel in 2021. In the first quarter of 2021, we stopped shipping volumes to U.S. destinations to optimize our pipeline capacity, reducing per-unit costs year-over-year. Operating mitigate future cost escalations. Unit Operating Expenses (1) Primary drivers of our operating expenses in 2022 were fuel, workforce, chemical, repairs and maintenance, and electricity costs. Total operating expenses increased largely due to higher fuel costs as a result of higher natural gas prices. AECO benchmark natural gas prices increased 56 percent in 2022 compared with 2021. In addition, total operating expenses increased due to higher electricity, repairs and maintenance and chemical costs. Chemical costs and electricity costs are also influenced by rising crude oil and natural gas benchmark prices. We have experienced minimal inflationary pressures on our costs, as we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to ($/BOE) Foster Creek Fuel Non-Fuel Total Fuel Non-Fuel Christina Lake Total Sunrise Fuel Other Oil Sands (2) Non-Fuel Total Fuel Non-Fuel Total Total (1) (2) 2022 6.07 6.52 12.59 5.07 4.87 9.94 7.01 10.48 17.49 7.35 15.10 22.45 13.75 Percent Change Percent Change 2021 4.07 6.67 10.74 3.52 4.72 8.24 5.58 11.57 17.15 4.91 11.73 16.64 11.52 49 (2) 17 44 3 21 26 (9) 2 50 29 35 19 2020 2.83 6.41 9.24 2.18 4.61 6.79 — — — — — — 7.84 44 4 16 61 2 21 — — — — — — 47 Specified financial measure. See the Advisory. Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022. Advisory for more detail. Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, and transportation commitments and customer diversification. 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 and improve cash flow stability. In 2022, we incurred realized risk management losses of $1.5 billion, of which $431 million related to the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized risk management gains of $68 million on our crude oil and condensate financial instruments. Production Volumes barrels per day in 2021. compared with 2021. Oil Sands crude oil production increased slightly to 586.6 thousand barrels per day in 2022 compared with 581.5 thousand We sold the Tucker asset on January 31, 2022, resulting in decreased production of 19.4 thousand barrels per day in 2022 Production at Foster Creek increased 11.1 thousand barrels per day to 191.0 thousand barrels per day in 2022 compared with 2021, due to new wells coming online in 2022 and the last half of 2021. In addition, we completed a planned turnaround in the second quarter of 2021. The increase was partially offset as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Also offsetting the increase was planned maintenance and an unplanned outage in the third quarter of 2022. offset by a planned turnaround in the second quarter of 2022. The Sunrise Acquisition was completed on August 31, 2022 and added 5.4 thousand barrels per day of production in 2022 compared with 2021. The increase in production at Sunrise in 2022 was partially offset by base declines and wells taken offline in preparation for a redevelopment program. Production from our Lloydminster thermal assets increased slightly in 2022 compared with 2021. The Spruce Lake North thermal plant achieved first oil in August, and production averaged approximately 12.0 thousand barrels per day in the fourth quarter. The increase was partially offset by base declines at other thermal plants and wells taken offline in preparation for a redevelopment program in the fourth quarter of 2022 and into 2023. Lloydminster conventional heavy oil production decreased marginally in 2022 compared with 2021, as wells were shut-in to meet new emissions regulations in Alberta. Royalties Saskatchewan. Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and Our Alberta oil sands royalty projects (Foster Creek, Christina Lake and Sunrise) 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 calculated as sales revenues less diluent costs, transportation costs, and allowed operating and capital costs. Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project. For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on an annual rate that is applied to each project, which includes 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. For the year ended December 31, 2022, gross sales included $358 million (2021 – $329 million), relating to construction, transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates. For the year ended December 31, 2022, royalties were $4.5 billion (2021 – $2.2 billion). Expenses Transportation and Blending In 2022, blending costs rose $3.2 billion to $10.3 billion compared with 2021. The increases were largely due to higher condensate prices. Transportation costs increased $179 million to $1.7 billion in 2022 compared with 2021. The increases were primarily due to higher costs as discussed below combined with increased sales volumes at Foster Creek, Christina Lake and Sunrise. Per-unit Transportation Expenses Transportation costs were $7.89 per BOE in 2022 up slightly from $7.23 per BOE in 2021. At Foster Creek, per-unit transportation costs increased 12 percent to $11.78 per barrel in 2022 compared with 2021. The increase was mainly due to increased tariffs, partially offset by reduced reliance on rail. For the year ended December 31, 2022, we shipped 40 percent (2021 – 35 percent), of our volumes from Foster Creek to U.S. destinations. At Christina Lake, transportation costs were $6.51 per barrel in 2022, consistent with $6.19 per barrel in 2021. At Sunrise, transportation costs were $12.26 per barrel in 2022, consistent with $12.14 per barrel in 2021, as we shipped a similar percentage of our total volumes to the U.S. At our Other Oil Sands assets, transportation costs in 2022 were $3.49 per barrel, compared with $4.01 per barrel in 2021. In the first quarter of 2021, we stopped shipping volumes to U.S. destinations to optimize our pipeline capacity, reducing per-unit costs year-over-year. Production at Christina Lake increased 9.7 thousand barrels per day to 246.5 thousand barrels per day in 2022 compared with 2021. We added incremental production from redevelopment wells drilled in 2022 and the last half of 2021. The increase was Operating Primary drivers of our operating expenses in 2022 were fuel, workforce, chemical, repairs and maintenance, and electricity costs. Total operating expenses increased largely due to higher fuel costs as a result of higher natural gas prices. AECO benchmark natural gas prices increased 56 percent in 2022 compared with 2021. In addition, total operating expenses increased due to higher electricity, repairs and maintenance and chemical costs. Chemical costs and electricity costs are also influenced by rising crude oil and natural gas benchmark prices. We have experienced minimal inflationary pressures on our costs, as we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations. Unit Operating Expenses (1) ($/BOE) Foster Creek Fuel Non-Fuel Total Christina Lake Fuel Non-Fuel Total Sunrise Fuel Non-Fuel Total Other Oil Sands (2) Fuel Non-Fuel Total Total 2022 6.07 6.52 12.59 5.07 4.87 9.94 7.01 10.48 17.49 7.35 15.10 22.45 13.75 Percent Change 49 (2) 17 44 3 21 26 (9) 2 50 29 35 19 2021 4.07 6.67 10.74 3.52 4.72 8.24 5.58 11.57 17.15 4.91 11.73 16.64 11.52 Percent Change 44 4 16 61 2 21 — — — — — — 47 2020 2.83 6.41 9.24 2.18 4.61 6.79 — — — — — — 7.84 (1) (2) Specified financial measure. See the Advisory. Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022. CENOVUS ENERGY 2022 ANNUAL REPORT | 27 Operating Margin Variance Year Ended December 31, 2022 (1) Reflects Operating Margin from processing facilities. Operating Results Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Heavy Crude Oil ($/bbl) Light Crude Oil ($/bbl) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production (MBOE/d) Conventional Natural Gas Production (percentage of total) Crude Oil and NGLs Production (percentage of total) Effective Royalty Rate (percent) Transportation Costs (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) (1) Specified financial measure. See the Advisory. Revenues Price 2022 127.2 48.15 — 118.64 63.22 6.50 — 7.5 23.8 576.1 127.2 75 25 15.4 3.16 11.18 8.23 2021 133.4 31.20 — 76.32 42.93 4.07 — 8.4 25.6 597.6 133.6 75 25 10.3 1.53 10.66 9.11 2020 89.8 17.84 31.45 42.78 22.04 2.37 2.7 4.5 19.5 379.0 89.9 70 30 7.9 2.46 8.99 9.85 Per-unit fuel prices increased largely due to higher natural gas prices as discussed above. Foster Creek per-unit non-fuel costs were consistent with 2021. Higher chemical, electricity and repairs and maintenance costs were offset by higher sales volumes. Christina Lake per unit non-fuel costs were consistent with 2021. Higher electricity and repairs and maintenance costs were offset by higher sales volumes in 2022. Sunrise per unit non-fuel costs decreased in 2022 compared with 2021. The decrease in non-fuel costs were primarily related to the planned turnaround costs in the second quarter of 2021, partially offset by higher electricity, chemical and workover costs in 2022. Per-unit non-fuel costs at our Other Oil Sands assets increased in 2022 compared with 2021, primarily due to higher chemical and workover costs. Netbacks ($/BOE) Sales Price (1) Royalties (1) Transportation (1) Operating Expenses (1) Netback (2) (1) (2) Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. DD&A 2022 91.70 20.96 7.89 13.75 49.10 2021 62.82 10.38 7.23 11.52 33.69 2020 28.64 2.34 8.70 7.84 9.76 In the year ended December 31, 2022, DD&A remained relatively consistent at $2.8 billion, compared with $2.7 billion in 2021. The average depletion rate for the year ended December 31, 2022, was $11.90 per BOE, compared with $11.28 per BOE in 2021. Conventional In 2022, we: • • • • • Delivered safe and reliable operations. Sold our assets in the Wembley area for net proceeds of $221 million on February 28, 2022. Generated Operating Margin of $1.2 billion, an increase of $432 million compared with 2021, largely due to higher average realized sales prices. Invested capital of $344 million focused on drilling, completion and tie-in activities, and infrastructure projects to support multi-year development. Achieved a Netback of $27.43 per BOE. Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) 28 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 4,332 298 4,034 2,023 143 541 92 1,235 13 370 1 851 2021 3,235 150 3,085 1,655 74 551 2 803 1 3 (3) 802 2020 904 40 864 268 81 320 — 195 — 880 82 (767) Our total realized sales price increased in 2022, due to higher crude oil and natural gas benchmark prices. For the year ended December 31, 2022, gross sales included $2.0 billion (2021 – $1.7 billion), relating to third-party sourced volumes, which are not included in our realized prices or our Netbacks. See the Advisory for more detail. For the year ended December 31, 2022, revenues included amounts relating to processing and transportation activities undertaken for third-parties of $71 million (2021 – $61 million), which are not included in our realized prices or our Netbacks. See the Advisory for more detail. Production Volumes Production volumes decreased 6.4 thousand BOE per day in 2022 compared with 2021, mainly due to asset sales in the first quarter of 2022 and the second half of 2021, and natural declines. The production decrease is partially offset by 36 net new wells (2021 – 18 net new wells) brought on production during the year, combined with production from well reactivations and workover activity. Per-unit fuel prices increased largely due to higher natural gas prices as discussed above. Foster Creek per-unit non-fuel costs were consistent with 2021. Higher chemical, electricity and repairs and maintenance costs Operating Margin Variance Year Ended December 31, 2022 were offset by higher sales volumes. offset by higher sales volumes in 2022. Christina Lake per unit non-fuel costs were consistent with 2021. Higher electricity and repairs and maintenance costs were Sunrise per unit non-fuel costs decreased in 2022 compared with 2021. The decrease in non-fuel costs were primarily related to the planned turnaround costs in the second quarter of 2021, partially offset by higher electricity, chemical and workover costs Per-unit non-fuel costs at our Other Oil Sands assets increased in 2022 compared with 2021, primarily due to higher chemical (1) Reflects Operating Margin from processing facilities. Operating Results Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Heavy Crude Oil ($/bbl) Light Crude Oil ($/bbl) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production (MBOE/d) Sold our assets in the Wembley area for net proceeds of $221 million on February 28, 2022. Generated Operating Margin of $1.2 billion, an increase of $432 million compared with 2021, largely due to higher Conventional Natural Gas Production (percentage of total) Crude Oil and NGLs Production (percentage of total) Effective Royalty Rate (percent) Transportation Costs (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) (1) Specified financial measure. See the Advisory. Revenues Price 2022 127.2 48.15 — 118.64 63.22 6.50 — 7.5 23.8 576.1 127.2 75 25 15.4 3.16 11.18 8.23 2021 133.4 31.20 — 76.32 42.93 4.07 — 8.4 25.6 597.6 133.6 75 25 10.3 1.53 10.66 9.11 2020 89.8 17.84 31.45 42.78 22.04 2.37 2.7 4.5 19.5 379.0 89.9 70 30 7.9 2.46 8.99 9.85 Our total realized sales price increased in 2022, due to higher crude oil and natural gas benchmark prices. For the year ended December 31, 2022, gross sales included $2.0 billion (2021 – $1.7 billion), relating to third-party sourced volumes, which are not included in our realized prices or our Netbacks. See the Advisory for more detail. For the year ended December 31, 2022, revenues included amounts relating to processing and transportation activities undertaken for third-parties of $71 million (2021 – $61 million), which are not included in our realized prices or our Netbacks. See the Advisory for more detail. Production Volumes Production volumes decreased 6.4 thousand BOE per day in 2022 compared with 2021, mainly due to asset sales in the first quarter of 2022 and the second half of 2021, and natural declines. The production decrease is partially offset by 36 net new wells (2021 – 18 net new wells) brought on production during the year, combined with production from well reactivations and workover activity. CENOVUS ENERGY 2022 ANNUAL REPORT | 29 and workover costs. in 2022. Netbacks ($/BOE) Sales Price (1) Royalties (1) Transportation (1) Operating Expenses (1) Netback (2) Conventional In 2022, we: (1) (2) DD&A 2021. • • • • • Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses 2022 91.70 20.96 7.89 13.75 49.10 2021 62.82 10.38 7.23 11.52 33.69 2020 28.64 2.34 8.70 7.84 9.76 Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. In the year ended December 31, 2022, DD&A remained relatively consistent at $2.8 billion, compared with $2.7 billion in 2021. The average depletion rate for the year ended December 31, 2022, was $11.90 per BOE, compared with $11.28 per BOE in Delivered safe and reliable operations. average realized sales prices. support multi-year development. Achieved a Netback of $27.43 per BOE. Invested capital of $344 million focused on drilling, completion and tie-in activities, and infrastructure projects to Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) 2022 4,332 298 4,034 2,023 1,235 143 541 92 13 370 1 851 2021 3,235 150 3,085 1,655 74 551 803 2 1 3 (3) 802 2020 904 40 864 268 81 320 — 195 — 880 82 (767) At our equity-accounted assets in Indonesia, we drilled and completed two MBH field development wells and five MDA field development wells planned for the year. We achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022. In Indonesia we also have the MAC and MDK fields under development. At the MAC field, we drilled and completed two development wells in the fourth quarter of 2022, of the three planned at the field. We expect first gas production from the MAC and MDK fields by 2023 and 2025, respectively. In China, we finalized an agreement in the second quarter that increases gas sales at Liuhua 29-1 for the duration of the contract. This partially offsets some of the reduction in contracted natural gas sales from Liwan 3-1, due to the conclusion of an amendment that temporarily increased sales volumes. In addition, in the first quarter we terminated the production sharing contract (“PSC”) at Block 23/07, which was in the exploration phase, and never produced or had drilling activity. Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin (1) Depreciation, Depletion and Amortization Exploration Expense (Income) Loss from Equity-Accounted Affiliates Segment Income (Loss) Operating Margin Variance Year Ended December 31, 2022 Asia Pacific Atlantic Offshore Asia Pacific Offshore 2021 Atlantic 440 29 411 15 136 260 1,342 79 1,263 — 103 1,160 2022 578 (3) 581 15 204 362 1,442 80 1,362 — 114 1,248 2,020 77 1,943 15 318 1,610 585 91 (23) 957 1,782 108 1,674 15 239 1,420 492 5 (47) 970 (1) Asia Pacific and Atlantic Operating Margin are non-GAAP financial measures. See the Advisory. Royalties The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Total royalties and effective royalty rates increased in 2022 compared with 2021, primarily due to higher realized pricing. 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 increased $69 million in 2022, compared with 2021. Per-unit transportation costs averaged $3.16 per BOE in 2022, compared with $1.53 per BOE in 2021. Operating Primary drivers of our operating expenses in 2022, were repairs and maintenance, workforce, electricity, property taxes and lease costs. Operating expenses per BOE in the year ended December 31, 2022, increased compared with 2021 primarily due to higher workover, energy and electricity costs, combined with lower sales volumes. Total operating expenses in 2022 were flat compared with 2021, due to the same factors that increased operating expenses per BOE, partially offset by asset sales in the first quarter of 2022 and the second half of 2021. Netbacks ($/BOE) Sales Price (1) Royalties (1) Transportation and Blending (1) Operating Expenses (1) Netback (2) (1) (2) Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. DD&A 2022 48.15 6.38 3.16 11.18 27.43 2021 31.20 3.06 1.53 10.66 15.95 2020 17.84 1.23 2.46 8.99 5.16 For the year ended December 31, 2022, total Conventional DD&A was $370 million (2021 – $3 million). The increase was due to impairment reversals of $378 million in 2021. The average depletion rate for 2022 was $8.23 per BOE (2021 – $9.11 per BOE). The average depletion rate excludes the impact of impairments and impairment reversals. Offshore In 2022, we: • • • • • • • Delivered safe and reliable operations. Completed the dry-dock portion of the Terra Nova ALE project. We expect the Terra Nova field to resume production in the second quarter of 2023. Announced our decision to proceed with the completion of the West White Rose project. Sold our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador as part of our consideration in the Sunrise Acquisition. Generated Operating Margin of $1.6 billion, an increase of $190 million compared with 2021, largely due to higher average realized sales prices, partially offset by increased operating expenses and lower sales volumes. Earned a Netback of $68.90 per BOE. Invested capital of $310 million mainly for the Terra Nova ALE and the West White Rose projects in the Atlantic region. In September 2021, Cenovus announced an agreement with its partners to restructure its working interest in the Atlantic region and proceed with the ALE project for Terra Nova. The agreement increased Cenovus’s working interest in Terra Nova to 34 percent from 13 percent and, pending a decision to restart the West White Rose Project, would decrease Cenovus’s working interest in the White Rose field and satellite extensions by 12.5 percent. On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project resulting in the reduction of our working interest in the White Rose field and satellite extensions. The West White Rose project is anticipated to have peak production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half of 2026. Total capital required to achieve first oil is expected to be approximately $2.0 billion to $2.3 billion net to Cenovus. At December 31, 2022, the project was around 65 percent complete. Since our decision to restart the project, we have invested approximately $85 million in 2022. 30 | CENOVUS ENERGY 2022 ANNUAL REPORT Royalties Expenses Transportation Operating Netbacks ($/BOE) Sales Price (1) Royalties (1) Netback (2) (1) (2) DD&A Offshore In 2022, we: • • • • • • • The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Total royalties and effective royalty rates increased in 2022 compared with 2021, primarily due to higher realized pricing. 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 increased $69 million in 2022, compared with 2021. Per-unit transportation costs averaged $3.16 per BOE in 2022, compared with $1.53 per BOE in 2021. Primary drivers of our operating expenses in 2022, were repairs and maintenance, workforce, electricity, property taxes and lease costs. Operating expenses per BOE in the year ended December 31, 2022, increased compared with 2021 primarily due to higher workover, energy and electricity costs, combined with lower sales volumes. Total operating expenses in 2022 were flat compared with 2021, due to the same factors that increased operating expenses per BOE, partially offset by asset sales in the first quarter of 2022 and the second half of 2021. Transportation and Blending (1) Operating Expenses (1) Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. 2022 48.15 6.38 3.16 11.18 27.43 2021 31.20 3.06 1.53 10.66 15.95 2020 17.84 1.23 2.46 8.99 5.16 For the year ended December 31, 2022, total Conventional DD&A was $370 million (2021 – $3 million). The increase was due to impairment reversals of $378 million in 2021. of impairments and impairment reversals. The average depletion rate for 2022 was $8.23 per BOE (2021 – $9.11 per BOE). The average depletion rate excludes the impact Delivered safe and reliable operations. in the second quarter of 2023. Completed the dry-dock portion of the Terra Nova ALE project. We expect the Terra Nova field to resume production Announced our decision to proceed with the completion of the West White Rose project. Sold our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador as part of our consideration in the Sunrise Acquisition. Generated Operating Margin of $1.6 billion, an increase of $190 million compared with 2021, largely due to higher average realized sales prices, partially offset by increased operating expenses and lower sales volumes. Earned a Netback of $68.90 per BOE. region. Invested capital of $310 million mainly for the Terra Nova ALE and the West White Rose projects in the Atlantic In September 2021, Cenovus announced an agreement with its partners to restructure its working interest in the Atlantic region and proceed with the ALE project for Terra Nova. The agreement increased Cenovus’s working interest in Terra Nova to 34 percent from 13 percent and, pending a decision to restart the West White Rose Project, would decrease Cenovus’s working interest in the White Rose field and satellite extensions by 12.5 percent. On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project resulting in the reduction of our working interest in the White Rose field and satellite extensions. The West White Rose project is anticipated to have peak production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half of 2026. Total capital required to achieve first oil is expected to be approximately $2.0 billion to $2.3 billion net to Cenovus. At December 31, 2022, the project was around 65 percent complete. Since our decision to restart the project, we have invested approximately $85 million in 2022. At our equity-accounted assets in Indonesia, we drilled and completed two MBH field development wells and five MDA field development wells planned for the year. We achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022. In Indonesia we also have the MAC and MDK fields under development. At the MAC field, we drilled and completed two development wells in the fourth quarter of 2022, of the three planned at the field. We expect first gas production from the MAC and MDK fields by 2023 and 2025, respectively. In China, we finalized an agreement in the second quarter that increases gas sales at Liuhua 29-1 for the duration of the contract. This partially offsets some of the reduction in contracted natural gas sales from Liwan 3-1, due to the conclusion of an amendment that temporarily increased sales volumes. In addition, in the first quarter we terminated the production sharing contract (“PSC”) at Block 23/07, which was in the exploration phase, and never produced or had drilling activity. Financial Results ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin (1) Depreciation, Depletion and Amortization Exploration Expense (Income) Loss from Equity-Accounted Affiliates Segment Income (Loss) 2022 Asia Pacific Atlantic Offshore Asia Pacific 2021 Atlantic Offshore 1,342 79 1,263 — 103 1,160 440 29 411 15 136 260 1,442 80 1,362 — 114 1,248 578 (3) 581 15 204 362 2,020 77 1,943 15 318 1,610 585 91 (23) 957 1,782 108 1,674 15 239 1,420 492 5 (47) 970 (1) Asia Pacific and Atlantic Operating Margin are non-GAAP financial measures. See the Advisory. Operating Margin Variance Year Ended December 31, 2022 CENOVUS ENERGY 2022 ANNUAL REPORT | 31 Operating Results Total Sales Volumes (MBOE/d) Atlantic Asia Pacific (1) Total Realized Price (2) ($/BOE) Atlantic - Light Crude Oil ($/bbl) Asia Pacific (1) ($/BOE) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Atlantic - Light Crude Oil (Mbbls/d) Asia Pacific (1) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Asia Pacific Total (MBOE/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Atlantic Asia Pacific (1) Operating Expense (2) ($/BOE) Atlantic Asia Pacific (1) Per Unit DD&A (2) ($/BOE) 2022 70.0 11.3 58.7 89.72 140.65 79.96 110.05 11.98 11.6 12.4 277.7 58.7 70.3 (0.5) 11.5 12.64 42.03 7.00 30.76 2021 73.5 13.2 60.3 74.75 91.01 71.19 79.83 11.48 14.1 12.7 285.3 60.3 74.4 6.7 8.4 9.86 28.34 5.80 25.62 (1) (2) Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Specified financial measure. See the Advisory. Revenues Price The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and NGLs increased in 2022 compared with 2021, primarily due to higher Brent benchmark pricing. Production Volumes Asia Pacific production decreased slightly in 2022 compared with 2021, due to changes to contracts at Liwan 3-1 and Liuhua 29-1 resulting in a net decrease in production. The decrease was partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. Atlantic production decreased slightly in 2022 compared with 2021, due to the decrease in Cenovus’s working interest at the White Rose field and satellite extensions in the second quarter of 2022. Light crude oil from production at the White Rose fields is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales. Royalties Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for 2022 was 11.5 percent (2021 – 8.4 percent). The increase in the effective royalty rates in 2022 are due to the full recovery of development costs at the Madura-BD gas project in the third quarter of 2021. Royalties at the White Rose fields are based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador. For 2022, retroactive to January 1, 2022, we paid a basic royalty of 1.0 percent of gross sales from the White Rose fields and 1.0 percent of gross sales from the satellite extensions. As a result, royalties were negative $3 million in 2022 (2021 – $29 million). 32 | CENOVUS ENERGY 2022 ANNUAL REPORT Expenses Operating Transportation Netbacks Sales Price (2) Royalties (2) Transportation and Blending (2) Operating Expenses (2) Netback (3) Sales Price (2) Royalties (2) Transportation and Blending (2) Operating Expenses (2) Netback (3) (1) (2) (3) DD&A (2021 – $25.62 per BOE). Exploration Expense Primary drivers of our Asia Pacific operating expenses in 2022 were repairs and maintenance, insurance and workforce. Total and per-unit operating expenses increased marginally year-over-year, primarily due to planned maintenance in China in the second and third quarter, combined with lower production in China. Also contributing to the increase in per-unit operating expenses were costs related to the MBH and MDA fields coming online in the fourth quarter of 2022. Primary drivers of our Atlantic operating expenses in 2022 were vessel and helicopter costs, repairs and maintenance, and workforce. Total operating expenses increased mainly due to continued preparations for the Terra Nova FPSO’s return to field and a higher working interest in the Terra Nova field. The increase was partially offset by the working interest restructuring on the White Rose fields in the second quarter of 2022. Per-unit operating expenses increased due to lower sales volumes, combined with increased costs at Terra Nova discussed above. Transportation in the Atlantic region remained consistent year-over-year and include the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs. ($/BOE, except where indicated) China Indonesia (1) Atlantic ($/bbl) Total Offshore 2022 2021 70.66 30.19 — 13.32 27.15 64.52 14.93 — 9.55 40.04 140.65 (0.74) 3.79 42.03 95.57 91.01 6.07 3.02 28.34 53.58 89.72 7.57 0.61 12.64 68.90 74.75 5.96 0.54 9.86 58.39 81.99 4.57 — 5.62 71.80 72.44 4.25 — 5.10 63.09 ($/BOE, except where indicated) China Indonesia (1) Atlantic ($/bbl) Total Offshore Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. In 2022, total Offshore DD&A was $585 million (2021 – $492 million). The average depletion rate in 2022 was $30.76 per BOE, In 2022, we recorded exploration expense of $91 million, primarily due to a $58 million write-off related to our decision not to pursue development at Block 15/33 in China, penalties related to terminating the PSC at Block 23/07 in China and spending at Bay du Nord in the Atlantic region prior to its divestiture. Operating Results Total Sales Volumes (MBOE/d) Atlantic Asia Pacific (1) Total Realized Price (2) ($/BOE) Atlantic - Light Crude Oil ($/bbl) Asia Pacific (1) ($/BOE) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Atlantic - Light Crude Oil (Mbbls/d) Asia Pacific (1) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Asia Pacific Total (MBOE/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Operating Expense (2) ($/BOE) Atlantic Asia Pacific (1) Atlantic Asia Pacific (1) Per Unit DD&A (2) ($/BOE) 2022 70.0 11.3 58.7 89.72 140.65 79.96 110.05 11.98 11.6 12.4 277.7 58.7 70.3 (0.5) 11.5 12.64 42.03 7.00 30.76 2021 73.5 13.2 60.3 74.75 91.01 71.19 79.83 11.48 14.1 12.7 285.3 60.3 74.4 6.7 8.4 9.86 28.34 5.80 25.62 (1) Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. (2) Specified financial measure. See the Advisory. Revenues Price Production Volumes Royalties quarter of 2021. The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and NGLs increased in 2022 compared with 2021, primarily due to higher Brent benchmark pricing. Asia Pacific production decreased slightly in 2022 compared with 2021, due to changes to contracts at Liwan 3-1 and Liuhua 29-1 resulting in a net decrease in production. The decrease was partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. Atlantic production decreased slightly in 2022 compared with 2021, due to the decrease in Cenovus’s working interest at the White Rose field and satellite extensions in the second quarter of 2022. Light crude oil from production at the White Rose fields is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a timing difference between production and sales. Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the Chinese and Indonesian governments. The effective royalty rate for 2022 was 11.5 percent (2021 – 8.4 percent). The increase in the effective royalty rates in 2022 are due to the full recovery of development costs at the Madura-BD gas project in the third Royalties at the White Rose fields are based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador. For 2022, retroactive to January 1, 2022, we paid a basic royalty of 1.0 percent of gross sales from the White Rose fields and 1.0 percent of gross sales from the satellite extensions. As a result, royalties were negative $3 million in 2022 (2021 – $29 million). Expenses Operating Primary drivers of our Asia Pacific operating expenses in 2022 were repairs and maintenance, insurance and workforce. Total and per-unit operating expenses increased marginally year-over-year, primarily due to planned maintenance in China in the second and third quarter, combined with lower production in China. Also contributing to the increase in per-unit operating expenses were costs related to the MBH and MDA fields coming online in the fourth quarter of 2022. Primary drivers of our Atlantic operating expenses in 2022 were vessel and helicopter costs, repairs and maintenance, and workforce. Total operating expenses increased mainly due to continued preparations for the Terra Nova FPSO’s return to field and a higher working interest in the Terra Nova field. The increase was partially offset by the working interest restructuring on the White Rose fields in the second quarter of 2022. Per-unit operating expenses increased due to lower sales volumes, combined with increased costs at Terra Nova discussed above. Transportation Transportation in the Atlantic region remained consistent year-over-year and include the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs. Netbacks ($/BOE, except where indicated) Sales Price (2) Royalties (2) Transportation and Blending (2) Operating Expenses (2) Netback (3) ($/BOE, except where indicated) Sales Price (2) Royalties (2) Transportation and Blending (2) Operating Expenses (2) Netback (3) China Indonesia (1) Atlantic ($/bbl) Total Offshore 2022 81.99 4.57 — 5.62 71.80 70.66 30.19 — 13.32 27.15 2021 140.65 (0.74) 3.79 42.03 95.57 89.72 7.57 0.61 12.64 68.90 China Indonesia (1) Atlantic ($/bbl) Total Offshore 72.44 4.25 — 5.10 63.09 64.52 14.93 — 9.55 40.04 91.01 6.07 3.02 28.34 53.58 74.75 5.96 0.54 9.86 58.39 (1) (2) (3) Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Specified financial measure. See the Advisory. Contains a non-GAAP financial measure. See the Advisory. DD&A In 2022, total Offshore DD&A was $585 million (2021 – $492 million). The average depletion rate in 2022 was $30.76 per BOE, (2021 – $25.62 per BOE). Exploration Expense In 2022, we recorded exploration expense of $91 million, primarily due to a $58 million write-off related to our decision not to pursue development at Block 15/33 in China, penalties related to terminating the PSC at Block 23/07 in China and spending at Bay du Nord in the Atlantic region prior to its divestiture. CENOVUS ENERGY 2022 ANNUAL REPORT | 33 DOWNSTREAM Canadian Manufacturing In 2022, we: • • • • Delivered safe operations. Completed planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter. Averaged combined crude utilization of 84 percent at the Upgrader and Lloydminster Refinery. There were several unplanned outages, primarily at the Upgrader in 2022. Generated Operating Margin of $699 million, an increase of $126 million compared with 2021, primarily due to a higher upgrading differential, and higher distillate and asphalt pricing, partially offset by the impact of turnaround activities and unplanned outages on sales volumes and operating expenses. • We closed the sales of 337 gas stations within our retail fuels network for net cash proceeds of $404 million. Following the sale of the retail business, we retained our commercial fuels business, which at December 31, 2022, includes 170 cardlock, bulk plant and travel center locations. The commercial fuels business and historical retail fuels business are aggregated into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Financial Results ($ millions) Revenues Purchased Product Gross Margin (2) Expenses Operating Operating Margin Depreciation, Depletion and Amortization Segment Income (Loss) 2022 7,792 6,389 1,403 704 699 208 491 2021 (1) 6,215 5,156 1,059 486 573 226 347 2020 82 — 82 37 45 8 37 (1) (2) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. Non-GAAP financial measure. See the Advisory. 34 | CENOVUS ENERGY 2022 ANNUAL REPORT Select Operating Results Heavy Crude Oil Throughput Capacity (Mbbls/d) Lloydminster Upgrader Lloydminster Refinery Heavy Crude Oil Throughput (Mbbls/d) Lloydminster Upgrader Lloydminster Refinery Crude Utilization (1) (percent) Refined Products Output (Mbbls/d) Upgrading Differential (2) Refining Margin (3)(4) ($/bbl) Lloydminster Upgrader (4) Lloydminster Refinery (4) Unit Operating Expense (5) ($/bbl) Ethanol Production (millions of litres/d) Volumes Loaded (6) (Mbbls/d) Rail Fuel Sales (7) Fuel Sales (millions of litres/d) Fuel Sales per Outlet (thousands of litres/d) 2022 110.5 81.5 29.0 92.9 68.7 24.2 84 93.4 32.84 33.92 36.04 27.91 13.91 0.8 1.8 6.2 15.0 2021 110.5 81.5 29.0 106.5 79.0 27.5 96 107.9 16.83 18.09 18.96 15.60 7.55 0.7 12.1 6.9 13.0 2020 — — — — — — — — — — — — — — — — 30.4 (1) (2) (3) (4) (5) (6) (7) Based on crude oil throughput volumes and results of operations at the Upgrader and Lloydminster Refinery. Based on benchmark price differential between heavy oil feedstock and synthetic crude. Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader for the year ended December 31, 2022, were $3.8 billion (2021 – $3.2 billion). Revenues from the Lloydminster Refinery for the year ended December 31, 2022, were $1.1 billion (2021 – $816 million). Comparative information has been re-presented to include marketing activities. Specified financial measure. See the Advisory. Comparative information has been re-presented to include only operating expenses and throughput at the Upgrader and Lloydminster Refinery. Volumes transported outside of Alberta, Canada. On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. Total fuel sales volumes include the historical retail business and the remaining commercial fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes. In 2022, crude oil throughput decreased 13.6 thousand barrels per day compared with 2021 due to planned turnarounds at the Lloydminster Upgrader and Lloydminster Refinery completed in the second quarter. Cold weather impacts and operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. In addition, there were temporary unplanned outages at the Upgrader in the first and third quarters of 2022. Revenues and Gross Margin feedstock. The Lloydminster Upgrader processes 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 The Lloydminster Refinery processes 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 largely dependent on asphalt and industrial products pricing 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. The Lloydminster Upgrader sources crude oil feedstock primarily from our Lloydminster thermal production. The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production. DOWNSTREAM Canadian Manufacturing In 2022, we: Delivered safe operations. • • • • Completed planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter. Averaged combined crude utilization of 84 percent at the Upgrader and Lloydminster Refinery. There were several unplanned outages, primarily at the Upgrader in 2022. Generated Operating Margin of $699 million, an increase of $126 million compared with 2021, primarily due to a higher upgrading differential, and higher distillate and asphalt pricing, partially offset by the impact of turnaround activities and unplanned outages on sales volumes and operating expenses. • We closed the sales of 337 gas stations within our retail fuels network for net cash proceeds of $404 million. Following the sale of the retail business, we retained our commercial fuels business, which at December 31, 2022, includes 170 cardlock, bulk plant and travel center locations. The commercial fuels business and historical retail fuels business are aggregated into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Financial Results ($ millions) Revenues Purchased Product Gross Margin (2) Expenses Operating Operating Margin Depreciation, Depletion and Amortization Segment Income (Loss) 2022 7,792 6,389 1,403 704 699 208 491 2021 (1) 6,215 5,156 1,059 486 573 226 347 2020 82 — 82 37 45 8 37 (1) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. (2) Non-GAAP financial measure. See the Advisory. Select Operating Results Heavy Crude Oil Throughput Capacity (Mbbls/d) Lloydminster Upgrader Lloydminster Refinery Heavy Crude Oil Throughput (Mbbls/d) Lloydminster Upgrader Lloydminster Refinery Crude Utilization (1) (percent) Refined Products Output (Mbbls/d) Upgrading Differential (2) Refining Margin (3)(4) ($/bbl) Lloydminster Upgrader (4) Lloydminster Refinery (4) Unit Operating Expense (5) ($/bbl) Ethanol Production (millions of litres/d) Rail Volumes Loaded (6) (Mbbls/d) Fuel Sales (7) Fuel Sales (millions of litres/d) Fuel Sales per Outlet (thousands of litres/d) 2022 110.5 81.5 29.0 92.9 68.7 24.2 84 93.4 32.84 33.92 36.04 27.91 13.91 0.8 1.8 6.2 15.0 2021 110.5 81.5 29.0 106.5 79.0 27.5 96 107.9 16.83 18.09 18.96 15.60 7.55 0.7 12.1 6.9 13.0 2020 — — — — — — — — — — — — — — 30.4 — — (1) (2) (3) (4) (5) (6) (7) Based on crude oil throughput volumes and results of operations at the Upgrader and Lloydminster Refinery. Based on benchmark price differential between heavy oil feedstock and synthetic crude. Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader for the year ended December 31, 2022, were $3.8 billion (2021 – $3.2 billion). Revenues from the Lloydminster Refinery for the year ended December 31, 2022, were $1.1 billion (2021 – $816 million). Comparative information has been re-presented to include marketing activities. Specified financial measure. See the Advisory. Comparative information has been re-presented to include only operating expenses and throughput at the Upgrader and Lloydminster Refinery. Volumes transported outside of Alberta, Canada. On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. Total fuel sales volumes include the historical retail business and the remaining commercial fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes. In 2022, crude oil throughput decreased 13.6 thousand barrels per day compared with 2021 due to planned turnarounds at the Lloydminster Upgrader and Lloydminster Refinery completed in the second quarter. Cold weather impacts and operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. In addition, there were temporary unplanned outages at the Upgrader in the first and third quarters of 2022. Revenues and Gross Margin The Lloydminster Upgrader processes 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. The Lloydminster Refinery processes 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 largely dependent on asphalt and industrial products pricing 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. The Lloydminster Upgrader sources crude oil feedstock primarily from our Lloydminster thermal production. The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production. CENOVUS ENERGY 2022 ANNUAL REPORT | 35 In 2022, revenues increased by $1.6 billion to $7.8 billion, mainly due to higher synthetic crude oil benchmark prices and higher asphalt and industrial products prices. In addition, revenues from our commercial fuels business and historical retail network increased due to significantly higher benchmark gasoline and diesel prices. The increase in total revenues year-over-year was partially offset by lower sales volumes. Gross margin increased $344 million in 2022 compared with 2021, due to a higher upgrading differential and higher margins on asphalt and industrial products. The year-over-year increase was offset by lower sales volumes, the 2021 settlement of a take- or-pay contract of $55 million and reduced activity at the Bruderheim crude-by-rail terminal. See the Advisory for revenue and gross margin by asset. Operating Expenses Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce and energy costs. Total operating costs increased in 2022 compared with 2021, primarily due to planned turnarounds and operational outages, combined with higher energy costs, maintenance, workforce and chemical costs. Per-unit operating expenses increased primarily due to the same factors discussed above, combined with lower crude oil throughput volumes. Per-unit operating costs apply only to operating costs and throughput at the Upgrader and Lloydminster Refinery. DD&A In 2022, Canadian Manufacturing DD&A was $208 million, compared with $226 million in 2021. U.S. Manufacturing In 2022, we: • • • • • • • • Delivered safe operations at our operated assets. Generated Operating Margin of $1.7 billion, an increase of $1.5 billion compared with 2021, largely due to significantly higher market crack spreads. Achieved crude utilization of 90 percent at the Lima Refinery. Completed a significant planned turnaround at the non-operated Toledo Refinery, from April and through to early August. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Completed planned turnarounds at the non-operated Wood River and Borger refineries in the first and second quarters, and an additional planned turnaround at the Wood River Refinery in September and October. Commenced commissioning activities for the Superior Refinery restart in December 2022 and will progress into the first quarter of 2023. The refinery remains on schedule to ramp up to full operations in the second quarter of 2023. Averaged crude utilization of 80 percent and crude oil throughput of 400.8 thousand barrels per day across all U.S. Manufacturing assets. Invested capital of $1.1 billion focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery. On August 8, 2022, we announced an agreement with BP to acquire their 50 percent interest in the Toledo Refinery in Ohio. The Toledo Acquisition will provide us full ownership and operatorship and further integrate our heavy oil production and refining capabilities. The transaction is expected to give us an additional 80.0 thousand barrels per day of downstream throughput capacity, including 45.0 thousand barrels per day of heavy oil refining capacity, with opportunities to further optimize our heavy oil value chain through integration with our upstream assets. The transaction is expected to close at the end of February 2023. Financial Results ($ millions) Revenues Purchased Product Gross Margin (1) Expenses Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Segment Income (Loss) (1) Non-GAAP financial measure. See the Advisory. 36 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 30,310 26,112 4,198 2,346 112 1,740 18 640 1,082 2021 20,043 17,955 2,088 1,772 104 212 1 2,381 (2,170) 2020 4,733 4,429 304 748 (21) (423) (1) 728 (1,150) Select Operating Results Crude Oil Throughput Capacity (Mbbls/d) Lima Refinery Superior Refinery (1) Toledo Refinery (2) Wood River and Borger Refineries (2) Crude Oil Throughput (Mbbls/d) Lima Refinery Superior Refinery (1) Toledo Refinery (2) Wood River and Borger Refineries (2) Throughput by Product (Mbbls/d) Heavy Crude Oil Light and Medium Crude Oil Crude Utilization (percent) Refining Margin (3)(4) ($/bbl) Unit Operating Expense (4)(5) ($/bbl) 2022 552.5 175.0 50.0 80.0 247.5 400.8 157.9 — 36.3 206.6 116.1 284.7 80 28.70 16.04 2021 502.5 175.0 — 80.0 247.5 401.5 126.9 — 69.9 204.7 138.7 262.8 80 14.25 12.09 2020 247.5 247.5 185.9 — — — — — — 185.9 74.6 111.3 75 4.47 11.00 The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization calculation. (1) (2) (3) (4) (5) Represents Cenovus’s 50 percent interest in the non-operated Wood River, Borger and Toledo refinery operations. Contains a non-GAAP financial measure. See the Advisory. Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries. Specified financial measure. See the Advisory. In 2022, total crude utilization across the segment was 80 percent (2021 – 80 percent): • The Lima Refinery had unplanned operational issues in the first quarter of the year following the turnaround completed in late 2021. The refinery performed well in the remainder of the year, until the winter storm Elliott events in December. Lima returned to normal rates in early January 2023. Crude utilization in 2022 was 90 percent (2021 – • At the Toledo Refinery, we completed a significant planned turnaround starting in April and ramped up to full rates by mid-August 2022. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Crude utilization in 2022 was 45 percent (2021 – 87 percent). • We completed two planned turnarounds at the Wood River Refinery in 2022. The spring turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. The second turnaround was completed in September and October. In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter 73 percent). of 2023. • We completed a turnaround at the Borger Refinery in the first and second quarters of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022. The refinery returned to full rates by January 2023. • Combined crude utilization for the Wood River and Borger refineries was 83 percent (2021 – 83 percent). Early in the year, we operated at reduced rates at the Toledo, Lima and Wood River refineries due to low market crack spreads. In December, throughput at all the U.S. Manufacturing sites was significantly impacted by extreme cold weather. Wood River and Borger were also impacted by outages on a third party pipeline that brings feedstock to the refineries. Cold weather also impacted Toledo delaying the start up of certain operational areas that could be restarted. The Superior Refinery commenced commissioning in December and will progress into the first quarter of 2023. The refinery is expected to ramp up to full operations in the second quarter of 2023. In 2022, revenues increased by $1.6 billion to $7.8 billion, mainly due to higher synthetic crude oil benchmark prices and higher asphalt and industrial products prices. In addition, revenues from our commercial fuels business and historical retail network increased due to significantly higher benchmark gasoline and diesel prices. The increase in total revenues year-over-year was partially offset by lower sales volumes. Gross margin increased $344 million in 2022 compared with 2021, due to a higher upgrading differential and higher margins on asphalt and industrial products. The year-over-year increase was offset by lower sales volumes, the 2021 settlement of a take- or-pay contract of $55 million and reduced activity at the Bruderheim crude-by-rail terminal. See the Advisory for revenue and gross margin by asset. Operating Expenses Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce and energy costs. Total operating costs increased in 2022 compared with 2021, primarily due to planned turnarounds and operational outages, combined with higher energy costs, maintenance, workforce and chemical costs. Per-unit operating expenses increased primarily due to the same factors discussed above, combined with lower crude oil throughput volumes. Per-unit operating costs apply only to operating costs and throughput at the Upgrader and Lloydminster In 2022, Canadian Manufacturing DD&A was $208 million, compared with $226 million in 2021. Refinery. DD&A U.S. Manufacturing In 2022, we: • • • • • • • • Generated Operating Margin of $1.7 billion, an increase of $1.5 billion compared with 2021, largely due to significantly Delivered safe operations at our operated assets. higher market crack spreads. Achieved crude utilization of 90 percent at the Lima Refinery. Completed a significant planned turnaround at the non-operated Toledo Refinery, from April and through to early August. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Completed planned turnarounds at the non-operated Wood River and Borger refineries in the first and second quarters, and an additional planned turnaround at the Wood River Refinery in September and October. Commenced commissioning activities for the Superior Refinery restart in December 2022 and will progress into the first quarter of 2023. The refinery remains on schedule to ramp up to full operations in the second quarter of 2023. Averaged crude utilization of 80 percent and crude oil throughput of 400.8 thousand barrels per day across all U.S. Manufacturing assets. Invested capital of $1.1 billion focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery. On August 8, 2022, we announced an agreement with BP to acquire their 50 percent interest in the Toledo Refinery in Ohio. The Toledo Acquisition will provide us full ownership and operatorship and further integrate our heavy oil production and refining capabilities. The transaction is expected to give us an additional 80.0 thousand barrels per day of downstream throughput capacity, including 45.0 thousand barrels per day of heavy oil refining capacity, with opportunities to further optimize our heavy oil value chain through integration with our upstream assets. The transaction is expected to close at the end of February 2023. Financial Results ($ millions) Revenues Purchased Product Gross Margin (1) Expenses Operating Operating Margin Realized (Gain) Loss on Risk Management Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Segment Income (Loss) (1) Non-GAAP financial measure. See the Advisory. 2022 30,310 26,112 4,198 2,346 112 1,740 18 640 1,082 2021 20,043 17,955 2,088 1,772 104 212 1 2,381 (2,170) 2020 4,733 4,429 304 748 (21) (423) (1) 728 (1,150) Select Operating Results Crude Oil Throughput Capacity (Mbbls/d) Lima Refinery Superior Refinery (1) Toledo Refinery (2) Wood River and Borger Refineries (2) Crude Oil Throughput (Mbbls/d) Lima Refinery Superior Refinery (1) Toledo Refinery (2) Wood River and Borger Refineries (2) Throughput by Product (Mbbls/d) Heavy Crude Oil Light and Medium Crude Oil Crude Utilization (percent) Refining Margin (3)(4) ($/bbl) Unit Operating Expense (4)(5) ($/bbl) 2022 552.5 175.0 50.0 80.0 247.5 400.8 157.9 — 36.3 206.6 116.1 284.7 80 28.70 16.04 2021 502.5 175.0 — 80.0 247.5 401.5 126.9 — 69.9 204.7 138.7 262.8 80 14.25 12.09 2020 247.5 — — — 247.5 185.9 — — — 185.9 74.6 111.3 75 4.47 11.00 The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization (1) calculation. (2) (3) (4) (5) In 2022, total crude utilization across the segment was 80 percent (2021 – 80 percent): Represents Cenovus’s 50 percent interest in the non-operated Wood River, Borger and Toledo refinery operations. Contains a non-GAAP financial measure. See the Advisory. Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries. Specified financial measure. See the Advisory. • • The Lima Refinery had unplanned operational issues in the first quarter of the year following the turnaround completed in late 2021. The refinery performed well in the remainder of the year, until the winter storm Elliott events in December. Lima returned to normal rates in early January 2023. Crude utilization in 2022 was 90 percent (2021 – 73 percent). At the Toledo Refinery, we completed a significant planned turnaround starting in April and ramped up to full rates by mid-August 2022. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state. Crude utilization in 2022 was 45 percent (2021 – 87 percent). • We completed two planned turnarounds at the Wood River Refinery in 2022. The spring turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. The second turnaround was completed in September and October. In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter of 2023. • We completed a turnaround at the Borger Refinery in the first and second quarters of 2022. In addition, the refinery had unplanned operational outages in the fourth quarter of 2022. The refinery returned to full rates by January 2023. Combined crude utilization for the Wood River and Borger refineries was 83 percent (2021 – 83 percent). • Early in the year, we operated at reduced rates at the Toledo, Lima and Wood River refineries due to low market crack spreads. In December, throughput at all the U.S. Manufacturing sites was significantly impacted by extreme cold weather. Wood River and Borger were also impacted by outages on a third party pipeline that brings feedstock to the refineries. Cold weather also impacted Toledo delaying the start up of certain operational areas that could be restarted. The Superior Refinery commenced commissioning in December and will progress into the first quarter of 2023. The refinery is expected to ramp up to full operations in the second quarter of 2023. CENOVUS ENERGY 2022 ANNUAL REPORT | 37 Revenues and Gross Margin General and Administrative Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator. 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. These factors include the type of crude oil feedstock 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. Revenues increased $10.3 billion to $30.3 billion in 2022 compared with 2021. The increase was primarily due to significantly higher refined product pricing. Gross margin increased $2.1 billion to $4.2 billion in 2022 compared with 2021, largely due to significantly improved market crack spreads. In 2022, RINs costs were $1.1 billion (2021 – $880 million). RINs prices averaged US$7.72 per barrel in 2022, compared with US$6.76 in 2021. In 2022, we incurred realized risk management losses of $112 million (2021 – $104 million), which included a $36 million loss on the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized losses of $18 million (2021 – $1 million) on our crude oil and refined products financial instruments. Operating Expenses Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce, and energy costs. Operating expenses increased $574 million in 2022, compared with 2021. The increase was mainly due to costs related to: $402 million). • • • • Planned turnarounds at the Toledo, Wood River and Borger refineries. Increased maintenance and preparation work at the Superior Refinery as we prepare for restart. Higher energy and utility pricing. Higher workforce and chemical costs. In 2022, per-unit operating expenses increased $3.95 per barrel of crude oil throughput in 2022, compared with 2021. The increase was primarily due to the same factors as discussed above. Superior Refinery operating expenses are included in per- unit operating expenses. DD&A U.S. Manufacturing DD&A was $640 million in 2022, compared with $2.4 billion in 2021. DD&A decreased compared with 2021 due to impairment charges of $1.9 billion recorded in the fourth quarter of 2021 related to the Lima, Wood River and Borger cash generating units (“CGUs”). In the fourth quarter of 2022, we recorded net impairment charges of $266 million. Refer to Note 11 of the Consolidated Financial Statements for further details. CORPORATE AND ELIMINATIONS In 2022, our corporate risk management activities resulted in: • • Unrealized risk management gains of $89 million (2021 – $18 million). Unrealized risk management gains in 2022 relate to renewable power contracts and foreign exchange risk management contracts. Realized risk management losses of $31 million related to foreign exchange risk management contracts. Losses of $101 million in 2021 were mainly due to the realization of WTI put and call option contracts acquired as part of the Arrangement. Primary drivers of our general and administrative expenses were employee long-term incentive costs, workforce costs and information technology costs. General and administrative expenses, excluding stock-based compensation expense, declined $198 million year-over-year, primarily due to the provision for incentive rewards related to reaching our synergy targets in 2021. Stock-based compensation expense increased significantly by $214 million due to changes in our share price in 2022. Our closing common share price on December 31, 2022, was $26.27, an increase from $15.51 on December 31, 2021. Finance Costs Finance costs decreased by $262 million in 2022 compared with 2021 primarily as a result of debt purchases that lowered the Company’s average long-term debt in 2022 compared with 2021. In addition, we recorded a net discount on the redemption of long-term debt of $29 million in 2022. Comparatively, we recorded a $121 million net premium on the redemption of long-term debt in 2021. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt. The weighted average interest rate of outstanding debt for the year ended December 31, 2022, was 4.7 percent (2021 – 4.6 percent). Integration and Transaction Costs We incurred $90 million of integration costs as a result of the Arrangement, not including capital expenditures, in 2022, compared with $349 million in 2021. The integration of Cenovus and Husky is substantially complete. In 2022, we incurred $95 million of Total Arrangement Integration Costs(1), which include capital expenditures (2021 – Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022 associated with the Sunrise Acquisition and the pending Toledo Acquisition. Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2022 365 (22) 343 2021 (312) 138 (174) 2020 (131) (50) (181) In 2022, unrealized foreign exchange losses of $365 million were mainly as a result of the translation of our U.S. dollar denominated debt. Realized foreign exchange gains of $22 million were recorded in 2022, related to net gains on working capital, offset by losses on the purchase of long-term debt. Revaluation Gains details. Cenovus recognized revaluation gains of $549 million in the third quarter of 2022 as part of the Sunrise Acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). Refer to Note 5 of the Consolidated Financial Statements for further Expenses ($ millions) General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net 38 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 865 820 (81) 106 343 (549) 162 (269) (532) 865 2021 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 2020 292 536 (9) 29 (181) — (80) (81) 40 546 (1) Non-GAAP financial measure. See the Advisory. Revenues and Gross Margin General and Administrative Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator. 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. These factors include the type of crude oil feedstock 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. Revenues increased $10.3 billion to $30.3 billion in 2022 compared with 2021. The increase was primarily due to significantly Gross margin increased $2.1 billion to $4.2 billion in 2022 compared with 2021, largely due to significantly improved market crack spreads. In 2022, RINs costs were $1.1 billion (2021 – $880 million). RINs prices averaged US$7.72 per barrel in 2022, In 2022, we incurred realized risk management losses of $112 million (2021 – $104 million), which included a $36 million loss on the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized losses of $18 million (2021 – $1 million) on our crude oil and refined products financial instruments. higher refined product pricing. compared with US$6.76 in 2021. Operating Expenses Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce, and energy costs. Operating expenses increased $574 million in 2022, compared with 2021. The increase was mainly due to costs related to: Planned turnarounds at the Toledo, Wood River and Borger refineries. Increased maintenance and preparation work at the Superior Refinery as we prepare for restart. • • • • Higher energy and utility pricing. Higher workforce and chemical costs. In 2022, per-unit operating expenses increased $3.95 per barrel of crude oil throughput in 2022, compared with 2021. The increase was primarily due to the same factors as discussed above. Superior Refinery operating expenses are included in per- unit operating expenses. DD&A U.S. Manufacturing DD&A was $640 million in 2022, compared with $2.4 billion in 2021. DD&A decreased compared with 2021 due to impairment charges of $1.9 billion recorded in the fourth quarter of 2021 related to the Lima, Wood River and Borger cash generating units (“CGUs”). In the fourth quarter of 2022, we recorded net impairment charges of $266 million. Refer to Note 11 of the Consolidated Financial Statements for further details. CORPORATE AND ELIMINATIONS In 2022, our corporate risk management activities resulted in: • • Unrealized risk management gains of $89 million (2021 – $18 million). Unrealized risk management gains in 2022 relate to renewable power contracts and foreign exchange risk management contracts. Realized risk management losses of $31 million related to foreign exchange risk management contracts. Losses of $101 million in 2021 were mainly due to the realization of WTI put and call option contracts acquired as part of the Arrangement. Expenses ($ millions) General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net 2022 865 820 (81) 106 343 (549) 162 (269) (532) 865 2021 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 2020 292 536 (9) 29 (181) — (80) (81) 40 546 Primary drivers of our general and administrative expenses were employee long-term incentive costs, workforce costs and information technology costs. General and administrative expenses, excluding stock-based compensation expense, declined $198 million year-over-year, primarily due to the provision for incentive rewards related to reaching our synergy targets in 2021. Stock-based compensation expense increased significantly by $214 million due to changes in our share price in 2022. Our closing common share price on December 31, 2022, was $26.27, an increase from $15.51 on December 31, 2021. Finance Costs Finance costs decreased by $262 million in 2022 compared with 2021 primarily as a result of debt purchases that lowered the Company’s average long-term debt in 2022 compared with 2021. In addition, we recorded a net discount on the redemption of long-term debt of $29 million in 2022. Comparatively, we recorded a $121 million net premium on the redemption of long-term debt in 2021. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt. The weighted average interest rate of outstanding debt for the year ended December 31, 2022, was 4.7 percent (2021 – 4.6 percent). Integration and Transaction Costs We incurred $90 million of integration costs as a result of the Arrangement, not including capital expenditures, in 2022, compared with $349 million in 2021. The integration of Cenovus and Husky is substantially complete. In 2022, we incurred $95 million of Total Arrangement Integration Costs(1), which include capital expenditures (2021 – $402 million). Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022 associated with the Sunrise Acquisition and the pending Toledo Acquisition. Foreign Exchange ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2022 365 (22) 343 2021 (312) 138 (174) 2020 (131) (50) (181) In 2022, unrealized foreign exchange losses of $365 million were mainly as a result of the translation of our U.S. dollar denominated debt. Realized foreign exchange gains of $22 million were recorded in 2022, related to net gains on working capital, offset by losses on the purchase of long-term debt. Revaluation Gains Cenovus recognized revaluation gains of $549 million in the third quarter of 2022 as part of the Sunrise Acquisition. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). Refer to Note 5 of the Consolidated Financial Statements for further details. (1) Non-GAAP financial measure. See the Advisory. CENOVUS ENERGY 2022 ANNUAL REPORT | 39 Re-measurement of Contingent Payments The contingent payment associated with the acquisition of a 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022, and the final payment was made in July 2022. In 2022, we paid $631 million under this agreement, which was recognized as cash flow from operating activities and reduced Adjusted Funds Flow. In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to BP Canada for up to eight quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment is $600 million. For accounting purposes, the variable payment will be re-measured at fair value at each reporting date until the earlier of the cumulative maximum $600 million is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss). The variable payment was recorded at a fair value of $600 million on the date of acquisition using an option pricing model. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million resulting in a non-cash re- measurement gain of $89 million. The first quarterly period ended on November 30, 2022. As at December 31, 2022, $92 million is payable under this agreement. As of December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is approximately $72.79 per barrel. (Gain) Loss on Divestiture of Assets In 2022, we recognized a gain on divestiture of assets of $269 million (2021 – $229 million), due to the closing of the sales of our Tucker and Wembley assets in the first quarter, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions in the second quarter, and the divestiture of 337 gas stations within our retail fuels network in the third quarter. Other (Income) Loss, Net In 2022, other income increased by $223 million compared with 2021, primarily due to insurance proceeds related to 2018 incidents at the Superior Refinery and in the Atlantic region and funding received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. The increase was partially offset by the settlement of a legal claim in favour of Cenovus in the third quarter of 2021. DD&A DD&A for year ended December 31, 2022, was $113 million (2021 – $118 million). Income Tax ($ millions) Current Tax Canada United States Asia Pacific Other International Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) 2022 1,252 104 262 21 1,639 642 2,281 2021 104 — 171 1 276 452 728 2020 (14) 1 — — (13) (838) (851) 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, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income. 40 | CENOVUS ENERGY 2022 ANNUAL REPORT QUARTERLY RESULTS ($ millions, except where indicated) Average Commodity Prices (US$/bbl) Dated Brent WTI WCS at Hardisty Chicago 3-2-1 Crack Spread RINs Upstream Production Volumes Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Downstream Crude Oil Throughput (1) (Mbbls/d) Revenues (2) Operating Margin (3) Adjusted Funds Flow (3) Per Share - Basic (3) ($) Per Share - Diluted (3) ($) Capital Investment Free Funds Flow (3) Excess Free Funds Flow (3)(4) Net Earnings (Loss) (5) Per Share - Basic ($) Per Share - Diluted ($) Total Assets Total Long-Term Liabilities 2022 Q3 Q2 Q1 Q4 Q2 Q1 2021 Q3 Q4 88.71 82.65 56.99 32.87 8.54 15.8 17.1 38.5 852.0 806.9 100.85 113.78 101.41 91.55 71.69 38.87 8.11 108.41 95.61 46.50 7.80 16.8 16.0 32.1 868.7 777.9 16.4 20.8 36.7 882.2 761.5 94.29 79.76 18.35 6.44 16.2 21.9 37.6 865.3 798.6 79.73 77.19 62.55 16.06 6.11 18.9 17.8 35.6 883.5 825.3 73.47 70.56 56.98 20.67 7.32 20.5 22.6 35.5 897.9 804.8 68.83 66.07 54.58 20.50 8.12 20.8 24.4 41.1 905.6 765.9 60.90 57.84 45.37 12.93 5.49 20.5 25.6 41.1 894.9 769.3 593.5 568.2 540.3 578.8 606.0 576.5 528.6 532.9 473.5 533.5 457.3 501.8 469.9 554.1 539.0 469.1 14,063 17,471 19,165 16,198 13,726 12,701 10,637 9,293 2,782 3,339 4,678 3,464 2,600 2,710 2,184 1,879 2,346 2,951 3,098 2,583 1,948 2,342 1,817 1,141 1.22 1.19 1,274 1.53 1.49 866 1.57 1.53 822 1.30 1.27 746 0.97 0.97 835 1.16 1.15 647 0.90 0.89 534 1,072 2,085 2,276 1,837 1,113 1,695 1,283 786 1,756 2,020 2,615 1,169 1,626 1,244 784 0.40 0.39 1,609 2,432 1,625 0.83 0.81 1.23 1.19 0.81 0.79 (408) (0.21) (0.21) 551 0.27 0.27 224 0.11 0.11 55,869 55,086 55,894 55,655 54,104 54,594 53,384 53,378 20,259 19,378 20,742 21,889 23,191 22,929 22,972 24,266 Cash From (Used in) Operating Activities 2,970 4,089 2,979 1,365 2,184 2,138 1,369 228 Long-Term Debt, Including Current Portion 8,691 8,774 11,228 11,744 12,385 12,986 13,380 13,947 Net Debt 4,282 5,280 7,535 8,407 9,591 11,024 12,390 13,340 Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Preferred Share Dividends (6) 201 0.105 219 0.114 387 — 205 0.105 — — 659 9 207 0.105 — — 8 1,018 69 0.035 — — 466 9 0.035 0.018 0.018 0.018 70 — — 265 8 35 — — — 9 36 — — — 8 Represents Cenovus’s net interest in refining operations. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. (1) (2) (3) (4) (5) (6) Non-GAAP financial measure or contains a non-GAAP financial measure. See the Advisory. New metric as of June 30, 2022, used to determine returns to shareholders. Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations. Preferred share dividends declared on November 1, 2022, were paid on January 3, 2023. 0.57 0.56 547 594 462 220 0.10 0.10 35 — — — 9 Re-measurement of Contingent Payments The contingent payment associated with the acquisition of a 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022, and the final payment was made in July 2022. In 2022, we paid $631 million under this agreement, which was recognized as cash flow from operating activities and reduced Adjusted Funds Flow. In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to BP Canada for up to eight quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment is $600 million. For accounting purposes, the variable payment will be re-measured at fair value at each reporting date until the earlier of the cumulative maximum $600 million is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss). The variable payment was recorded at a fair value of $600 million on the date of acquisition using an option pricing model. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million resulting in a non-cash re- measurement gain of $89 million. The first quarterly period ended on November 30, 2022. As at December 31, 2022, As of December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is approximately $92 million is payable under this agreement. $72.79 per barrel. (Gain) Loss on Divestiture of Assets In 2022, we recognized a gain on divestiture of assets of $269 million (2021 – $229 million), due to the closing of the sales of our Tucker and Wembley assets in the first quarter, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions in the second quarter, and the divestiture of 337 gas stations within our retail fuels network in the third In 2022, other income increased by $223 million compared with 2021, primarily due to insurance proceeds related to 2018 incidents at the Superior Refinery and in the Atlantic region and funding received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. The increase was partially offset by the settlement of a legal claim in favour of Cenovus in the third quarter of 2021. DD&A for year ended December 31, 2022, was $113 million (2021 – $118 million). 2022 1,252 104 262 21 1,639 642 2,281 2021 104 — 171 1 276 452 728 2020 (14) 1 — — (13) (838) (851) Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty. The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax legislation. For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income. quarter. Other (Income) Loss, Net DD&A Income Tax ($ millions) Current Tax Canada United States Asia Pacific Other International Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) Total Tax Expense (Recovery) QUARTERLY RESULTS ($ millions, except where indicated) Average Commodity Prices (US$/bbl) Dated Brent WTI WCS at Hardisty Chicago 3-2-1 Crack Spread RINs Upstream Production Volumes Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Downstream Crude Oil Throughput (1) (Mbbls/d) Revenues (2) Operating Margin (3) 2022 Q3 Q2 Q1 Q4 2021 Q3 Q2 Q1 100.85 113.78 101.41 91.55 71.69 38.87 8.11 108.41 95.61 46.50 7.80 94.29 79.76 18.35 6.44 79.73 77.19 62.55 16.06 6.11 73.47 70.56 56.98 20.67 7.32 68.83 66.07 54.58 20.50 8.12 60.90 57.84 45.37 12.93 5.49 Q4 88.71 82.65 56.99 32.87 8.54 593.5 568.2 540.3 578.8 606.0 576.5 528.6 532.9 15.8 17.1 38.5 852.0 806.9 16.8 16.0 32.1 868.7 777.9 16.4 20.8 36.7 882.2 761.5 16.2 21.9 37.6 865.3 798.6 18.9 17.8 35.6 883.5 825.3 20.5 22.6 35.5 897.9 804.8 20.8 24.4 41.1 905.6 765.9 20.5 25.6 41.1 894.9 769.3 473.5 533.5 457.3 501.8 469.9 554.1 539.0 469.1 14,063 17,471 19,165 16,198 13,726 12,701 10,637 9,293 2,782 3,339 4,678 3,464 2,600 2,710 2,184 1,879 Cash From (Used in) Operating Activities 2,970 4,089 2,979 1,365 2,184 2,138 1,369 228 Adjusted Funds Flow (3) Per Share - Basic (3) ($) Per Share - Diluted (3) ($) Capital Investment Free Funds Flow (3) Excess Free Funds Flow (3)(4) Net Earnings (Loss) (5) Per Share - Basic ($) Per Share - Diluted ($) Total Assets Total Long-Term Liabilities 2,346 2,951 3,098 2,583 1,948 2,342 1,817 1,141 1.22 1.19 1,274 1.53 1.49 866 1.57 1.53 822 1.30 1.27 746 0.97 0.97 835 1.16 1.15 647 0.90 0.89 534 1,072 2,085 2,276 1,837 1,113 1,695 1,283 786 1,756 2,020 2,615 1,169 1,626 1,244 784 0.40 0.39 1,609 2,432 1,625 0.83 0.81 1.23 1.19 0.81 0.79 (408) (0.21) (0.21) 551 0.27 0.27 224 0.11 0.11 0.57 0.56 547 594 462 220 0.10 0.10 55,869 55,086 55,894 55,655 54,104 54,594 53,384 53,378 20,259 19,378 20,742 21,889 23,191 22,929 22,972 24,266 Long-Term Debt, Including Current Portion 8,691 8,774 11,228 11,744 12,385 12,986 13,380 13,947 Net Debt 4,282 5,280 7,535 8,407 9,591 11,024 12,390 13,340 Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Preferred Share Dividends (6) 201 0.105 219 0.114 387 — 205 0.105 — — 659 9 207 0.105 — — 1,018 8 69 0.035 — — 466 9 70 35 36 35 0.035 0.018 0.018 0.018 — — 265 8 — — — 9 — — — 8 — — — 9 (1) (2) (3) (4) (5) (6) Represents Cenovus’s net interest in refining operations. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Advisory. New metric as of June 30, 2022, used to determine returns to shareholders. Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations. Preferred share dividends declared on November 1, 2022, were paid on January 3, 2023. CENOVUS ENERGY 2022 ANNUAL REPORT | 41 Fourth Quarter 2022 Results Compared with the Fourth Quarter 2021 Cash From (Used in) Operating Activities and Adjusted Funds Flow The summary below compares financial and operating results for the three months ended December 31, 2022 compared with the same period in 2021. Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to increased Operating Margin, as discussed above, and no quarterly contingent payments in 2022 (2021 – $119 million). The increase was partially offset by Upstream Production Volumes Total upstream production decreased 18.4 thousand BOE per day in the fourth quarter of 2022 compared with the same period in 2021. Oil Sands crude oil production decreased 15.6 thousand barrels per day to 609.3 thousand barrels per day in 2022 compared with 2021. The decrease was primarily due to the sale of the Tucker asset on January 31, 2022. Crude oil production at the time of sale was approximately 20 thousand barrels per day. In addition, production decreased at Foster Creek as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Offsetting the decrease was the Sunrise Acquisition on August 31, 2022, and production of approximately 12.0 thousand barrels per day from the Spruce Lake North thermal plant in the fourth quarter of 2022. In the fourth quarter of 2022, we sold approximately 25 percent (2021 – 20 percent) of our Oil Sands crude oil volumes at U.S. destinations, improving our realized sales prices. Conventional production was 125.5 thousand BOE per day in 2022, essentially unchanged from 125.3 thousand BOE per day in 2021. Production decreases from asset sales in the first quarter of 2022 were offset by 36 net new wells brought on production in the year-ended 2022, combined with production from well reactivations and workover activity. Offshore production was 70.2 thousand BOE per day in 2022, compared with 73.1 thousand BOE per day in 2021. The decrease was primarily due to the working interest restructuring on the White Rose fields in the second quarter of 2022, combined with contract amendments in China. These were partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. Downstream Manufacturing Throughput Total crude oil throughput was consistent in the fourth quarter of 2022 compared with the same period in 2021. Excess Free Funds Flow Canadian Manufacturing throughput decreased 14.0 thousand barrels per day to 94.3 thousand barrels per day in 2022. Cold weather impacts and unplanned operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. The Lloydminster Refinery had minor unplanned outages in the fourth quarter of 2022, but ran well in December and into 2023. U.S. Manufacturing throughput increased 17.6 thousand barrels per day to 379.2 thousand compared with 2021, primarily due to the completion of a planned turnaround in the fourth quarter of 2021 at the Lima Refinery. The increase was partially offset by unplanned operational issues, weather-related impacts and third-party outages impacting the Lima, Wood River and Borger refineries in December, in addition to the shutdown of the Toledo Refinery, and Wood River running at reduced rates in December due to an operational incident. Revenues Revenues increased $337 million to $14.1 billion in 2022 compared with 2021. Downstream revenues increased $370 million primarily due to higher refined product pricing. Upstream revenues were flat compared with 2021, as higher realized prices in the Conventional segment were offset by lower sales volumes in the Atlantic region. Oil Sands revenues were consistent with 2021, due to flat sales volumes and realized prices year-over year. Operating Margin Operating Margin increased in the fourth quarter of 2022, primarily due to increased refining margins from our downstream business resulting from higher market crack spreads. The increase was partially offset by: • • • Increased blending costs due to higher condensate prices impacting our Oil Sands segment. Higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment. Increased transportation costs from our upstream business, due to increased tariff rates and higher rail costs due to pipeline outages in the quarter. Cash from operating activities also increased as the change in non-cash working capital was $402 million greater than 2021. The increase was due to lower accounts receivable and higher income tax payable, partially offset by lower accounts payable on December 31, 2022, compared with September 30, 2022. Net earnings in the fourth quarter of 2022 was $784 million compared with a net loss of $408 million 2021 due to: Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021. Higher operating margin, as discussed above. The increase was partially offset by: Unrealized risk management losses of $37 million in 2022 (2021 – $222 million gain). Higher gain on divestiture of assets in 2021. higher cash taxes in 2022. Net Earnings (Loss) • • • • Capital Investment Capital investment in the fourth quarter of 2022 was $1.3 billion, compared with $835 million in 2021. The increase is primarily due to higher capital spending in our upstream operations, including higher investment in Sunrise following the closing of the Sunrise Acquisition, incremental capital at Foster Creek, Christina Lake and Lloydminster thermal assets, increased drilling in the Conventional segment and work on the West White Rose project. Excess Free Funds Flow was $786 million in the fourth quarter of 2022 (2021 – $1.2 billion). The decrease was due to higher capital spending and base dividends paid in 2022, partially offset by higher adjusted funds flow in 2022. OIL AND GAS RESERVES As at December 31, 2022 (before royalties) Total Proved Probable Total Proved Plus Probable As at December 31, 2021 (before royalties) Total Proved Probable Total Proved Plus Probable (1) (2) Includes heavy crude oil that is not material. Includes shale gas that is not material. Bitumen (1) (MMbbls) 5,592 2,448 8,040 Bitumen (1) (MMbbls) 5,573 1,850 7,423 Light and Medium Oil (MMbbls) 42 129 171 45 152 197 Light and Medium Oil (MMbbls) NGLs (MMbbls) 82 39 121 NGLs (MMbbls) 89 39 128 Conventional Natural Gas (2) (Bcf) 2,194 1,029 3,223 (Bcf) 2,219 959 3,178 Conventional Natural Gas (2) Total (MMBOE) 6,082 2,787 8,869 Total (MMBOE) 6,077 2,201 8,278 42 | CENOVUS ENERGY 2022 ANNUAL REPORT The summary below compares financial and operating results for the three months ended December 31, 2022 compared with the same period in 2021. Upstream Production Volumes in 2021. Total upstream production decreased 18.4 thousand BOE per day in the fourth quarter of 2022 compared with the same period Oil Sands crude oil production decreased 15.6 thousand barrels per day to 609.3 thousand barrels per day in 2022 compared with 2021. The decrease was primarily due to the sale of the Tucker asset on January 31, 2022. Crude oil production at the time of sale was approximately 20 thousand barrels per day. In addition, production decreased at Foster Creek as production reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Offsetting the decrease was the Sunrise Acquisition on August 31, 2022, and production of approximately 12.0 thousand barrels per day from the Spruce Lake North thermal plant in the fourth quarter of 2022. In the fourth quarter of 2022, we sold approximately 25 percent (2021 – 20 percent) of our Oil Sands crude oil volumes at U.S. destinations, improving our realized sales prices. Conventional production was 125.5 thousand BOE per day in 2022, essentially unchanged from 125.3 thousand BOE per day in 2021. Production decreases from asset sales in the first quarter of 2022 were offset by 36 net new wells brought on production in the year-ended 2022, combined with production from well reactivations and workover activity. Offshore production was 70.2 thousand BOE per day in 2022, compared with 73.1 thousand BOE per day in 2021. The decrease was primarily due to the working interest restructuring on the White Rose fields in the second quarter of 2022, combined with contract amendments in China. These were partially offset by first gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022. Downstream Manufacturing Throughput Canadian Manufacturing throughput decreased 14.0 thousand barrels per day to 94.3 thousand barrels per day in 2022. Cold weather impacts and unplanned operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of January 2023. The Lloydminster Refinery had minor unplanned outages in the fourth quarter of 2022, but ran well in December and into 2023. U.S. Manufacturing throughput increased 17.6 thousand barrels per day to 379.2 thousand compared with 2021, primarily due to the completion of a planned turnaround in the fourth quarter of 2021 at the Lima Refinery. The increase was partially offset by unplanned operational issues, weather-related impacts and third-party outages impacting the Lima, Wood River and Borger refineries in December, in addition to the shutdown of the Toledo Refinery, and Wood River running at reduced rates in December due to an operational incident. Revenues Revenues increased $337 million to $14.1 billion in 2022 compared with 2021. Downstream revenues increased $370 million primarily due to higher refined product pricing. Upstream revenues were flat compared with 2021, as higher realized prices in the Conventional segment were offset by lower sales volumes in the Atlantic region. Oil Sands revenues were consistent with 2021, due to flat sales volumes and realized prices year-over year. Operating Margin Operating Margin increased in the fourth quarter of 2022, primarily due to increased refining margins from our downstream business resulting from higher market crack spreads. The increase was partially offset by: • • • Increased blending costs due to higher condensate prices impacting our Oil Sands segment. Higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment. Increased transportation costs from our upstream business, due to increased tariff rates and higher rail costs due to pipeline outages in the quarter. Fourth Quarter 2022 Results Compared with the Fourth Quarter 2021 Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to increased Operating Margin, as discussed above, and no quarterly contingent payments in 2022 (2021 – $119 million). The increase was partially offset by higher cash taxes in 2022. Cash from operating activities also increased as the change in non-cash working capital was $402 million greater than 2021. The increase was due to lower accounts receivable and higher income tax payable, partially offset by lower accounts payable on December 31, 2022, compared with September 30, 2022. Net Earnings (Loss) Net earnings in the fourth quarter of 2022 was $784 million compared with a net loss of $408 million 2021 due to: • • Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of $1.6 billion in the fourth quarter of 2021. Higher operating margin, as discussed above. The increase was partially offset by: • • Unrealized risk management losses of $37 million in 2022 (2021 – $222 million gain). Higher gain on divestiture of assets in 2021. Capital Investment Capital investment in the fourth quarter of 2022 was $1.3 billion, compared with $835 million in 2021. The increase is primarily due to higher capital spending in our upstream operations, including higher investment in Sunrise following the closing of the Sunrise Acquisition, incremental capital at Foster Creek, Christina Lake and Lloydminster thermal assets, increased drilling in the Conventional segment and work on the West White Rose project. Total crude oil throughput was consistent in the fourth quarter of 2022 compared with the same period in 2021. Excess Free Funds Flow Excess Free Funds Flow was $786 million in the fourth quarter of 2022 (2021 – $1.2 billion). The decrease was due to higher capital spending and base dividends paid in 2022, partially offset by higher adjusted funds flow in 2022. OIL AND GAS RESERVES As at December 31, 2022 (before royalties) Total Proved Probable Total Proved Plus Probable As at December 31, 2021 (before royalties) Total Proved Probable Total Proved Plus Probable (1) (2) Includes heavy crude oil that is not material. Includes shale gas that is not material. Bitumen (1) (MMbbls) 5,592 2,448 8,040 Bitumen (1) (MMbbls) 5,573 1,850 7,423 Light and Medium Oil (MMbbls) 42 129 171 Light and Medium Oil (MMbbls) 45 152 197 NGLs (MMbbls) 82 39 121 NGLs (MMbbls) 89 39 128 Conventional Natural Gas (2) (Bcf) 2,194 1,029 3,223 Conventional Natural Gas (2) (Bcf) 2,219 959 3,178 Total (MMBOE) 6,082 2,787 8,869 Total (MMBOE) 6,077 2,201 8,278 CENOVUS ENERGY 2022 ANNUAL REPORT | 43 Developments in 2022 compared with 2021 include: Cash From (Used in) Operating Activities • • • • Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and 617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek, the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by the Tucker asset sale and current year production. Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year production, partially offset by additions from updates to the Atlantic region and Conventional segment development plans. NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to dispositions in the Conventional segment and current year production, partially offset by additions from updates to the development plan and economic factors related to increased product pricing for the Conventional segment. Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale and current year production, partially offset by updates to the development plans, improved recovery performance, and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley asset sale and current year production. The reserves data is presented as at December 31, 2022 using an average of forecasts (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast prices and costs are dated January 1, 2023. Comparative information as at December 31, 2021 uses the January 1, 2022 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, 2022. 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 section. LIQUIDITY AND CAPITAL RESOURCES During 2022, we further defined our capital allocation framework to ensure we continue to strengthen our balance sheet, enable flexibility in both high and low commodity price environments, and improve our shareholder value proposition. The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to shareholders with lower leverage and a lower risk profile. Our long-term Net Debt to Adjusted Funds Flow Target is approximately 1.0 times at the bottom of the commodity price cycle. We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents and other sources of liquidity. This includes draws on our committed credit facility, draws on our uncommitted demand facilities and other corporate and financial opportunities which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service, DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions. ($ millions) Cash From (Used In) Operating Activities Investing Activities Net Cash Provided (Used) Before Financing Activities Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents As at ($ millions) Cash and Cash Equivalents Total Debt 2022 11,403 (2,314) 9,089 (7,676) 238 1,651 2022 4,524 8,806 2021 5,919 (942) 4,977 (2,507) 25 2,495 2021 2,873 12,464 2020 273 (863) (590) 837 (55) 192 2020 378 7,562 44 | CENOVUS ENERGY 2022 ANNUAL REPORT For the year ended December 31, 2022, cash generated from operating activities increased compared with 2021 due to higher Operating Margin, changes in non-cash working capital, lower finance costs and lower integration and transaction costs. Excluding the contingent payment, our adjusted working capital was $4.7 billion at December 31, 2022. At December 31, 2021, adjusted working capital excluding the contingent payment and assets held for sale and liabilities related to assets held for sale was $3.8 billion. The increase was primarily due to the improved commodity price environment as discussed in the Operating and Financial Results section of this MD&A. Working capital increased due to higher cash and inventories, partially offset by higher income tax payable and lower accounts receivable. We anticipate that we will continue to meet our payment obligations as they come due. Cash used in investing activities was higher in 2022 compared with 2021 largely due to higher capital spending, cash paid on the Sunrise Acquisition in 2022 and cash acquired in the Arrangement in 2021. The increase was partially offset by higher proceeds Cash From (Used in) Investing Activities from divestitures in 2022. Cash From (Used in) Financing Activities As part of our overall deleveraging in 2022, we: Paid US$402 million to purchase the full amount of our 3.80 percent unsecured notes due in 2023 and 4.00 percent unsecured notes due in 2024, with principal amounts of US$115 million and US$269 million, respectively. We paid a premium on redemption of US$18 million. Paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 Paid US$2.2 billion to purchase unsecured notes due between 2025 and 2043, at a premium of US$23 million. During 2022, net short-term borrowings increased by $34 million, related to draws on the WRB Refining LP uncommitted • • • at par. demand facilities. In 2022, the Company purchased 112 million common shares through our NCIBs, at a volume weighted average price of $22.49 per common share for a total of $2.5 billion (December 31, 2021 – $265 million). The common shares were subsequently cancelled. During 2022, we paid base dividends of $682 million and variable dividends of $219 million on our common shares. Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns plan. Three Months Ended December 31, Year Ended December 31, ($ millions) (Add) Deduct: Cash From (Used in) Operating Activities Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Add (Deduct): Base Dividends Paid on Common Shares Dividends Paid on Preferred Shares Settlement of Decommissioning Liabilities Principal Repayment of Leases Acquisitions, Net of Cash Acquired Proceeds From Divestitures Excess Free Funds Flow 2022 11,403 (150) 575 10,978 3,708 7,270 2021 5,919 (102) (1,227) 7,248 2,563 4,685 2020 273 (42) 198 117 841 (724) 2022 2,970 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 786 2021 2,184 (35) 271 1,948 835 1,113 (70) (8) (35) (78) — 247 1,169 Developments in 2022 compared with 2021 include: Cash From (Used in) Operating Activities • Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and 617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek, the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by the Tucker asset sale and current year production. • Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year production, partially offset by additions from updates to the Atlantic region and Conventional segment development plans. • • NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to dispositions in the Conventional segment and current year production, partially offset by additions from updates to the development plan and economic factors related to increased product pricing for the Conventional segment. Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale and current year production, partially offset by updates to the development plans, improved recovery performance, and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley asset sale and current year production. The reserves data is presented as at December 31, 2022 using an average of forecasts (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast prices and costs are dated January 1, 2023. Comparative information as at December 31, 2021 uses the January 1, 2022 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, 2022. 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 section. LIQUIDITY AND CAPITAL RESOURCES During 2022, we further defined our capital allocation framework to ensure we continue to strengthen our balance sheet, enable flexibility in both high and low commodity price environments, and improve our shareholder value proposition. The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to shareholders with lower leverage and a lower risk profile. Our long-term Net Debt to Adjusted Funds Flow Target is approximately 1.0 times at the bottom of the commodity price cycle. We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and cash equivalents and other sources of liquidity. This includes draws on our committed credit facility, draws on our uncommitted demand facilities and other corporate and financial opportunities which provide timely access to funding to supplement cash flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service, DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are dependent on current credit ratings and market conditions. ($ millions) Cash From (Used In) Operating Activities Investing Activities Financing Activities Net Cash Provided (Used) Before Financing Activities Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency Increase (Decrease) in Cash and Cash Equivalents As at ($ millions) Cash and Cash Equivalents Total Debt 2022 11,403 (2,314) 9,089 (7,676) 238 1,651 2022 4,524 8,806 2021 5,919 (942) 4,977 (2,507) 25 2,495 2021 2,873 12,464 2020 273 (863) (590) 837 (55) 192 2020 378 7,562 For the year ended December 31, 2022, cash generated from operating activities increased compared with 2021 due to higher Operating Margin, changes in non-cash working capital, lower finance costs and lower integration and transaction costs. Excluding the contingent payment, our adjusted working capital was $4.7 billion at December 31, 2022. At December 31, 2021, adjusted working capital excluding the contingent payment and assets held for sale and liabilities related to assets held for sale was $3.8 billion. The increase was primarily due to the improved commodity price environment as discussed in the Operating and Financial Results section of this MD&A. Working capital increased due to higher cash and inventories, partially offset by higher income tax payable and lower accounts receivable. We anticipate that we will continue to meet our payment obligations as they come due. Cash From (Used in) Investing Activities Cash used in investing activities was higher in 2022 compared with 2021 largely due to higher capital spending, cash paid on the Sunrise Acquisition in 2022 and cash acquired in the Arrangement in 2021. The increase was partially offset by higher proceeds from divestitures in 2022. Cash From (Used in) Financing Activities As part of our overall deleveraging in 2022, we: • • • Paid US$402 million to purchase the full amount of our 3.80 percent unsecured notes due in 2023 and 4.00 percent unsecured notes due in 2024, with principal amounts of US$115 million and US$269 million, respectively. We paid a premium on redemption of US$18 million. Paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025 at par. Paid US$2.2 billion to purchase unsecured notes due between 2025 and 2043, at a premium of US$23 million. During 2022, net short-term borrowings increased by $34 million, related to draws on the WRB Refining LP uncommitted demand facilities. In 2022, the Company purchased 112 million common shares through our NCIBs, at a volume weighted average price of $22.49 per common share for a total of $2.5 billion (December 31, 2021 – $265 million). The common shares were subsequently cancelled. During 2022, we paid base dividends of $682 million and variable dividends of $219 million on our common shares. Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after financing its capital programs. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns plan. Three Months Ended December 31, Year Ended December 31, ($ millions) Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Add (Deduct): Base Dividends Paid on Common Shares Dividends Paid on Preferred Shares Settlement of Decommissioning Liabilities Principal Repayment of Leases Acquisitions, Net of Cash Acquired Proceeds From Divestitures Excess Free Funds Flow 2022 11,403 (150) 575 10,978 3,708 7,270 2021 5,919 (102) (1,227) 7,248 2,563 4,685 2020 273 (42) 198 117 841 (724) 2022 2,970 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 786 2021 2,184 (35) 271 1,948 835 1,113 (70) (8) (35) (78) — 247 1,169 CENOVUS ENERGY 2022 ANNUAL REPORT | 45 Returns to Shareholders Target ($ millions) Excess Free Funds Flow Target Return (1) Less: Purchase of Common Shares Under NCIBs Amount Available for Variable Dividend December 31, 2022 September 30, 2022 June 30, 2022 Three Months Ended 786 393 (387) 6 1,756 878 (659) 219 2,020 1,010 (1,018) (8) (1) Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, June 30, 2022 and March 31, 2022, being less than $9 billion and greater than $4 billion, Target Return was determined to be 50 percent of Excess Free Funds Flow. In the fourth quarter of 2022, we paid variable dividends of $219 million. Returns to shareholders through share buybacks were within $50 million of the fourth quarter Target Return, as such no variable dividend was declared for the quarter. Short-Term Borrowings As at December 31, 2022, US$170 million was drawn on the WRB uncommitted demand facility, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)). Long-Term Debt and Total Debt Total Debt as at December 31, 2022, was $8.8 billion (December 31, 2021 – $12.5 billion), which includes $8.7 billion of long- term debt (December 31, 2021 – $12.4 billion). The decrease in Total Debt and long-term debt was due to the purchase of US$2.6 billion and $750 million of principal related to outstanding unsecured notes in 2022. As at December 31, 2022, we were in compliance with all of the terms of our debt agreements. Available Sources of Liquidity The following sources of liquidity are available as at December 31, 2022: ($ millions) Cash and Cash Equivalents Committed Credit Facility (1) Revolving Credit Facility – Tranche A Revolving Credit Facility – Tranche B Uncommitted Demand Facilities (2) Cenovus Energy Inc. (3) WRB Refining LP (4) Maturity N/A Amount Available 4,524 November 10, 2026 November 10, 2025 N/A N/A 3,700 1,800 1,002 190 (1) (2) (3) (4) No amounts were drawn on the committed credit facility as at December 31, 2022 (December 31, 2021 - $nil). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility. Our uncommitted demand facilities includes $1.9 billion, 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, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings. Represents Cenovus's 50 percent share of US$450 million (our proportionate share – US$225 million) available to cover short-term working capital requirements. As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US $63 million (C$79 million)). On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates. 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. U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes At December 31, 2022, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$4.8 billion and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.0 billion. Unsecured Notes U.S. Dollar Canadian Dollar Denominated (US $ millions) Denominated ($ millions) 7,385 (2,558) 4,827 2,750 (750) 2,000 As at December 31, 2021 Purchases As at December 31, 2022 Base Shelf Prospectus Financial Metrics details. 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, 2022, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31, 2021 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability. We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 26 of the Consolidated Financial Statements for further We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow Ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA Ratio, as net earnings before finance costs, net of capitalized interest, interest income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, unrealized (gain) loss on risk management, foreign exchange (gain) loss, revaluation (gains), re-measurement of contingent payment, (gain) loss on divestiture of assets, other (income) loss, net and share of (income) loss from equity-accounted affiliates calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial strength. As at Net Debt to Capitalization Ratio (percent) Net Debt to Adjusted Funds Flow Ratio (times) Net Debt to Adjusted EBITDA Ratio (times) 2022 13 0.4 0.3 2021 29 1.3 1.2 2020 30 61.4 11.9 46 | CENOVUS ENERGY 2022 ANNUAL REPORT Returns to Shareholders Target ($ millions) Excess Free Funds Flow Target Return (1) Less: Purchase of Common Shares Under NCIBs Amount Available for Variable Dividend December 31, 2022 September 30, 2022 June 30, 2022 Three Months Ended 786 393 (387) 6 1,756 878 (659) 219 2,020 1,010 (1,018) (8) (1) Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, June 30, 2022 and March 31, 2022, being less than $9 billion and greater than $4 billion, Target Return was determined to be 50 percent of Excess Free Funds Flow. In the fourth quarter of 2022, we paid variable dividends of $219 million. Returns to shareholders through share buybacks were within $50 million of the fourth quarter Target Return, as such no variable dividend was declared for the quarter. Short-Term Borrowings As at December 31, 2022, US$170 million was drawn on the WRB uncommitted demand facility, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)). Long-Term Debt and Total Debt Total Debt as at December 31, 2022, was $8.8 billion (December 31, 2021 – $12.5 billion), which includes $8.7 billion of long- term debt (December 31, 2021 – $12.4 billion). The decrease in Total Debt and long-term debt was due to the purchase of US$2.6 billion and $750 million of principal related to outstanding unsecured notes in 2022. As at December 31, 2022, we were in compliance with all of the terms of our debt agreements. Available Sources of Liquidity The following sources of liquidity are available as at December 31, 2022: ($ millions) Cash and Cash Equivalents Committed Credit Facility (1) Revolving Credit Facility – Tranche A Revolving Credit Facility – Tranche B Uncommitted Demand Facilities (2) Cenovus Energy Inc. (3) WRB Refining LP (4) Maturity Amount Available November 10, 2026 November 10, 2025 N/A N/A N/A 4,524 3,700 1,800 1,002 190 No amounts were drawn on the committed credit facility as at December 31, 2022 (December 31, 2021 - $nil). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility. Our uncommitted demand facilities includes $1.9 billion, 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, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no (1) (2) (3) direct borrowings. (4) Represents Cenovus's 50 percent share of US$450 million (our proportionate share – US$225 million) available to cover short-term working capital requirements. As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US $63 million (C$79 million)). On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates. 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. U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes At December 31, 2022, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$4.8 billion and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.0 billion. As at December 31, 2021 Purchases As at December 31, 2022 Base Shelf Prospectus Unsecured Notes U.S. Dollar Denominated (US $ millions) Canadian Dollar Denominated ($ millions) 7,385 (2,558) 4,827 2,750 (750) 2,000 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, 2022, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31, 2021 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability. Financial Metrics We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 26 of the Consolidated Financial Statements for further details. 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, Adjusted Funds Flow and Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders Equity. We define Adjusted Funds Flow, as used in the Net Debt to Adjusted Funds Flow Ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA, as used in the Net Debt to Adjusted EBITDA Ratio, as net earnings before finance costs, net of capitalized interest, interest income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, unrealized (gain) loss on risk management, foreign exchange (gain) loss, revaluation (gains), re-measurement of contingent payment, (gain) loss on divestiture of assets, other (income) loss, net and share of (income) loss from equity-accounted affiliates calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial strength. As at Net Debt to Capitalization Ratio (percent) Net Debt to Adjusted Funds Flow Ratio (times) Net Debt to Adjusted EBITDA Ratio (times) 2022 13 0.4 0.3 2021 29 1.3 1.2 2020 30 61.4 11.9 CENOVUS ENERGY 2022 ANNUAL REPORT | 47 Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at the bottom of the commodity price cycle, which we believe is 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. Our Net Debt to Capitalization Ratio as at December 31, 2022 decreased compared with December 31, 2021, primarily due to higher net earnings and ongoing reductions in Net Debt. Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2022 decreased compared with December 31, 2021, as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt. Share Capital and Stock-Based Compensation Plans As at December 31, 2022, there were approximately 1,909 million common shares outstanding (December 31, 2021 – 2,001 million common shares) and 36 million preferred shares outstanding (December 31, 2021 – 36 million preferred shares). Refer to Note 32 of the Consolidated Financial Statements for further details. In November 2021, we commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares between November 9, 2021 and November 8, 2022. On November 7, 2022, we renewed the NCIB program to purchase up to an additional 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. In 2022, Cenovus purchased and cancelled 112 million common shares for $2.5 billion (year ended December 31, 2021 – 17 million common shares for $265 million), at a volume weighted average price of $22.49 per common share through our NCIBs. Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB. As at December 31, 2022, there were approximately 56 million Cenovus Warrants outstanding (December 31, 2021 – 65 million Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years (from the date of issue) at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 32 of the Consolidated Financial Statements for further details. Refer to Note 34 of the Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows: As at February 13, 2023 Common Shares Cenovus Warrants Series 1 First Preferred Shares Series 2 First Preferred Shares Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Stock Options Other Stock-Based Compensation Plans Common Share Dividends Units Outstanding (thousands) Units Exercisable (thousands) 1,907,867 55,691 10,740 1,260 10,000 8,000 6,000 17,373 16,891 N/A N/A N/A N/A N/A N/A N/A 8,312 1,581 In 2022, we paid base dividends of $682 million or $0.350 per common share (2021 – $176 million or $0.088 per common share) and variable dividends of $219 million or $0.114 per common share (2021 – $nil). The Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023. The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly. 48 | CENOVUS ENERGY 2022 ANNUAL REPORT Cumulative Redeemable Preferred Share Dividends In 2022, dividends of $26 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (December 31, 2021 — $34 million). The decrease from 2021 is related to timing differences between the declaration date and payment date. The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as of March 15, 2023. Capital Investment Decisions Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production to average between 800 thousand BOE per day and 840 thousand BOE per day and our downstream crude oil throughput average between 610 thousand barrels per day to 660 thousand barrels per day in 2023. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. Contractual Obligations and Commitments We have obligations for goods and services entered into in the normal course of business. Commitments are largely related to transportation agreements. Commitments that have original maturities of less than one year are excluded from the table below. For further information, see Note 40 to the Consolidated Financial Statements. Our total commitments were $33.0 billion as at December 31, 2022, of which $21.1 billion are for various transportation and storage commitments and $9.4 billion are for product purchase commitments. Transportation commitments include $9.1 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 and should help align with the Company’s future transportation requirements. Our commitments with HMLP at December 31, 2022, include $2.2 billion related to long-term transportation and storage commitments. As at December 31, 2022 ($ millions) Commitments (1) 2023 2024 2025 2026 2027 Thereafter Total Total Commitments 3,894 3,765 2,685 2,558 Transportation and Storage (2) Product Purchases (3) Real Estate (4) Obligation to Fund Equity-Accounted Affiliate (5) Other Long-Term Commitments Long-Term Debt (Principal and Interest) Decommissioning Liabilities Contingent Payments Lease Liabilities (Principal and Interest) (6) 1,747 1,626 48 92 381 401 263 271 426 2,011 1,509 50 105 90 401 254 167 407 1,542 1,416 1,360 13,005 21,081 922 50 96 75 582 249 — 339 922 50 96 74 392 248 — 320 922 54 91 65 2,492 1,622 247 — 276 3,457 604 143 395 17,604 11,196 5,979 — 2,889 37,668 9,358 856 623 1,080 32,998 14,594 7,240 438 4,657 59,927 Total Commitments and Obligations 5,255 4,994 3,855 3,518 4,637 Commitments are reflected at Cenovus’s proportionate share of the underlying contract. Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract. Prior to September 30, 2022, product purchases were included in Transportation and Storage. Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment. As at December 31, 2022, outstanding letters of credit issued as security for performance under certain contracts totaled (1) (2) (3) (4) (5) (6) which a provision has been provided. Relates to funding obligations for HCML. $490 million (December 31, 2021 – $565 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. Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at the bottom of the commodity price cycle, which we believe is 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. higher net earnings and ongoing reductions in Net Debt. Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2022 decreased compared with December 31, 2021, as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt. Share Capital and Stock-Based Compensation Plans As at December 31, 2022, there were approximately 1,909 million common shares outstanding (December 31, 2021 – 2,001 million common shares) and 36 million preferred shares outstanding (December 31, 2021 – 36 million preferred shares). Refer to Note 32 of the Consolidated Financial Statements for further details. In November 2021, we commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares between November 9, 2021 and November 8, 2022. On November 7, 2022, we renewed the NCIB program to purchase up to an additional 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. In 2022, Cenovus purchased and cancelled 112 million common shares for $2.5 billion (year ended December 31, 2021 – 17 million common shares for $265 million), at a volume weighted average price of $22.49 per common share through our NCIBs. Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB. As at December 31, 2022, there were approximately 56 million Cenovus Warrants outstanding (December 31, 2021 – 65 million Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years (from the date of issue) at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to Note 32 of the Consolidated Financial Statements for further details. Refer to Note 34 of the Consolidated Financial Statements for further details on our stock option plans and our performance share unit, restricted share unit and deferred share unit plans. Our outstanding share data is as follows: As at February 13, 2023 Common Shares Cenovus Warrants Series 1 First Preferred Shares Series 2 First Preferred Shares Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Stock Options Other Stock-Based Compensation Plans Common Share Dividends Units Outstanding Units Exercisable (thousands) (thousands) 1,907,867 55,691 10,740 1,260 10,000 8,000 6,000 17,373 16,891 N/A N/A N/A N/A N/A N/A N/A 8,312 1,581 In 2022, we paid base dividends of $682 million or $0.350 per common share (2021 – $176 million or $0.088 per common share) and variable dividends of $219 million or $0.114 per common share (2021 – $nil). The Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023. Our Net Debt to Capitalization Ratio as at December 31, 2022 decreased compared with December 31, 2021, primarily due to Capital Investment Decisions Cumulative Redeemable Preferred Share Dividends In 2022, dividends of $26 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (December 31, 2021 — $34 million). The decrease from 2021 is related to timing differences between the declaration date and payment date. The declaration of preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of record as of March 15, 2023. Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production to average between 800 thousand BOE per day and 840 thousand BOE per day and our downstream crude oil throughput average between 610 thousand barrels per day to 660 thousand barrels per day in 2023. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. Contractual Obligations and Commitments We have obligations for goods and services entered into in the normal course of business. Commitments are largely related to transportation agreements. Commitments that have original maturities of less than one year are excluded from the table below. For further information, see Note 40 to the Consolidated Financial Statements. Our total commitments were $33.0 billion as at December 31, 2022, of which $21.1 billion are for various transportation and storage commitments and $9.4 billion are for product purchase commitments. Transportation commitments include $9.1 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 and should help align with the Company’s future transportation requirements. Our commitments with HMLP at December 31, 2022, include $2.2 billion related to long-term transportation and storage commitments. As at December 31, 2022 ($ millions) Commitments (1) Transportation and Storage (2) Product Purchases (3) Real Estate (4) Obligation to Fund Equity-Accounted Affiliate (5) Other Long-Term Commitments 2023 2024 2025 2026 2027 Thereafter Total 1,542 1,416 1,360 13,005 21,081 1,747 1,626 48 92 381 2,011 1,509 50 105 90 922 50 96 75 922 50 96 74 Total Commitments 3,894 3,765 2,685 2,558 Long-Term Debt (Principal and Interest) Decommissioning Liabilities Contingent Payments Lease Liabilities (Principal and Interest) (6) 401 263 271 426 401 254 167 407 582 249 — 339 392 248 — 320 Total Commitments and Obligations 5,255 4,994 3,855 3,518 4,637 922 54 91 65 2,492 1,622 247 — 276 3,457 604 143 395 17,604 11,196 5,979 — 2,889 37,668 9,358 856 623 1,080 32,998 14,594 7,240 438 4,657 59,927 The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly. 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. (1) (2) (3) (4) (5) (6) Commitments are reflected at Cenovus’s proportionate share of the underlying contract. Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract. Prior to September 30, 2022, product purchases were included in Transportation and Storage. 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. Relates to funding obligations for HCML. Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment. As at December 31, 2022, outstanding letters of credit issued as security for performance under certain contracts totaled $490 million (December 31, 2021 – $565 million). CENOVUS ENERGY 2022 ANNUAL REPORT | 49 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, 2022, we charged HMLP $188 million for construction and management services (2021 – $243 million). 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, 2022, we incurred costs of $263 million for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million). 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, without limitation, 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, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities. 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, among other things, our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, and/or the market price of our securities. These factors should be considered when investing in securities of Cenovus. Pandemic Risk The COVID-19 pandemic remains a risk for the Company. While restrictions have ended or been relaxed in many parts of the world, other jurisdictions continue to impose measures to combat the virus. 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 have 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. The COVID-19 pandemic, or other pandemics, endemics or outbreaks, 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. The duration or extent of the impacts of the COVID-19 pandemic on 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, and include but are not limited to: the severity, duration, spread or resurgence of COVID-19 or its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or 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. 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. The COVID-19 pandemic and the corresponding measures we take to protect the health and safety of our staff and the continuity of our business may result in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and class action claims. 50 | CENOVUS ENERGY 2022 ANNUAL REPORT 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; the ability of producers and governments to replace reduced supply; processing and export capacity; global economic conditions; and activity; inflation and rising interest rates; the potential for a recession; market competitiveness; 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; the release of SPRs; developments related to the market for crude oil; levels of oil inventories; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions. The financial performance of our oil sands operations could also be 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; global economic conditions; market competitiveness; developments related to the market for liquefied natural gas; levels of natural gas and NGL inventories; export capacity; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; 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; the ability of producers and governments to replace reduced supply; global economic conditions and activity; inflation and rising interest rates; central bank policies; seasonal trends; the potential for a recession; market competitiveness; developments related to the market for refined products; 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, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; public sentiment towards the use of non-renewable resources, including refined products; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions. 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, 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 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. 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, 2022, we charged HMLP $188 million for construction and management services (2021 – $243 million). 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, 2022, we incurred costs of $263 million for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million). 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, without limitation, 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, repurchase our shares, pay dividends to our shareholders and fulfill our obligations (including debt servicing requirements) and/or may materially affect the market price of our securities. 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. 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 Risk Governance 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, among other things, our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, and/or the market price of our securities. These factors should be considered when investing in securities of Cenovus. Pandemic Risk The COVID-19 pandemic remains a risk for the Company. While restrictions have ended or been relaxed in many parts of the world, other jurisdictions continue to impose measures to combat the virus. 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 have 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. The COVID-19 pandemic, or other pandemics, endemics or outbreaks, 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. The duration or extent of the impacts of the COVID-19 pandemic on 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, and include but are not limited to: the severity, duration, spread or resurgence of COVID-19 or its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or 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. 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. The COVID-19 pandemic and the corresponding measures we take to protect the health and safety of our staff and the continuity of our business may result in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and 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; the ability of producers and governments to replace reduced supply; processing and export capacity; global economic conditions; and activity; inflation and rising interest rates; the potential for a recession; market competitiveness; 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; the release of SPRs; developments related to the market for crude oil; levels of oil inventories; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions. The financial performance of our oil sands operations could also be 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; global economic conditions; market competitiveness; developments related to the market for liquefied natural gas; levels of natural gas and NGL inventories; export capacity; current and potential future environmental regulations, including regulations pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; 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; the ability of producers and governments to replace reduced supply; global economic conditions and activity; inflation and rising interest rates; central bank policies; seasonal trends; the potential for a recession; market competitiveness; developments related to the market for refined products; 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, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets; prices and availability of alternate sources of energy; public sentiment towards the use of non-renewable resources, including refined products; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions. 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, 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 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 51 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, level of shareholder returns and our ability to maintain our business and fund projects. A substantial decline in these commodity prices or an 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 and reputation and may be considered indicators of impairment. Another potential indicator 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, NGLs, 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 increase, 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, and 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 37 and 38 of the Consolidated Financial Statements. 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 such as non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil and condensate prices and differentials, natural gas spreads, basis and prices, NGLs, electricity prices, 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 may 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; and the unenforceability of contracts. 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, 37 and 38 of the Consolidated Financial Statements. 52 | CENOVUS ENERGY 2022 ANNUAL REPORT Risks Associated with Derivative Financial Instruments Derivative financial instruments expose us to the risk that a counterparty may default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Board-approved Credit Policy. Derivative financial instruments also expose us to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These risks are managed through hedging limits authorized according to our Market Risk Management Policy. Although we have suspended our crude oil sales price risk management activities related to WTI, certain financial instruments related to our condensate, feedstock and refined product price risk management programs which include WTI, remain outstanding and will continue to be used, in addition to financial instruments related to natural gas, electricity, interest and exchange rates applicable to our business. As such, we will be exposed to the risk of a loss from adverse changes in the market value of any such financial instruments. These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change. Fluctuations in the price of WTI may have a larger impact on our financial condition, results of operations, cash flows, growth, access to capital, ability to fund share repurchases and/or dividends and cost of borrowing, compared to the periods prior to the suspension of our crude oil sales price risk management 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, 37 and 38 of the Consolidated Financial activities related to WTI. Statements. Impact of Financial Risk Management Activities Cenovus makes storage and transportation decisions, considering our marketing and transportation infrastructure including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. 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 and improve cash flow stability. In a rising commodity price environment, we expect to realize losses on our risk management activities but recognize gains on the underlying physical inventory sold in the period, and we expect the opposite to occur in a falling commodity price environment. In 2022, we incurred a realized loss on our risk management positions due to the settlement of benchmark prices relative to our risk management contract prices but recognized a gain on the underlying physical inventory sold during such period due to changing benchmark prices. Transactions typically span across periods, 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. 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, 2022 Sensitivity Range Increase Decrease Crude Oil Commodity Price ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges WCS and Condensate Differential Price(1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production WCS (Hardisty) Differential Price ± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production Refined Products Commodity Price ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges Natural Gas Basis Price Power Commodity Price ± US$0.50/MCF Applied to Natural Gas Basis Hedges ± C$20.00/Megawatt Hour Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± 0.05 in the U.S. to Canadian Dollar Exchange Rate 1 13 (1) (2) 1 113 14 (1) (13) 1 2 (1) (113) (17) For further information on our risk management positions, see Notes 37 and 38 of the Consolidated Financial Statements. (1) Excludes WCS (Hardisty) differential. Exposure to Counterparties In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders, customers and other counterparties for the provision and sale of goods and services and also in connection with our hedging activities, and in respect of asset or securities acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses or delays of our development plans, or we may have to forego other opportunities, all of which could materially impact our business, results of operations and financial condition. 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, level of shareholder returns and our ability to maintain our business and fund projects. A substantial decline in these commodity prices or an 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 and reputation and may be considered indicators of impairment. Another potential indicator 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, NGLs, 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 increase, 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, and 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 37 and 38 of the Consolidated Financial Statements. 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 such as non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil and condensate prices and differentials, natural gas spreads, basis and prices, NGLs, electricity prices, 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 may 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; and the unenforceability of contracts. 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, 37 and 38 of the Consolidated Financial Statements. Risks Associated with Derivative Financial Instruments Derivative financial instruments expose us to the risk that a counterparty may default on its contractual obligations. This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and netting arrangements, as outlined in our Board-approved Credit Policy. Derivative financial instruments also expose us to the risk of a loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These risks are managed through hedging limits authorized according to our Market Risk Management Policy. Although we have suspended our crude oil sales price risk management activities related to WTI, certain financial instruments related to our condensate, feedstock and refined product price risk management programs which include WTI, remain outstanding and will continue to be used, in addition to financial instruments related to natural gas, electricity, interest and exchange rates applicable to our business. As such, we will be exposed to the risk of a loss from adverse changes in the market value of any such financial instruments. These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change. Fluctuations in the price of WTI may have a larger impact on our financial condition, results of operations, cash flows, growth, access to capital, ability to fund share repurchases and/or dividends and cost of borrowing, compared to the periods prior to the suspension of our crude oil sales price risk management activities related to WTI. 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, 37 and 38 of the Consolidated Financial Statements. Impact of Financial Risk Management Activities Cenovus makes storage and transportation decisions, considering our marketing and transportation infrastructure including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. 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 and improve cash flow stability. In a rising commodity price environment, we expect to realize losses on our risk management activities but recognize gains on the underlying physical inventory sold in the period, and we expect the opposite to occur in a falling commodity price environment. In 2022, we incurred a realized loss on our risk management positions due to the settlement of benchmark prices relative to our risk management contract prices but recognized a gain on the underlying physical inventory sold during such period due to changing benchmark prices. Transactions typically span across periods, 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. 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, 2022 Sensitivity Range Increase Decrease Crude Oil Commodity Price ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges WCS and Condensate Differential Price(1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production WCS (Hardisty) Differential Price ± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production Refined Products Commodity Price ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges Natural Gas Basis Price Power Commodity Price ± US$0.50/MCF Applied to Natural Gas Basis Hedges ± C$20.00/Megawatt Hour Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± 0.05 in the U.S. to Canadian Dollar Exchange Rate 1 13 (1) (2) 1 113 14 (1) (13) 1 2 (1) (113) (17) (1) Excludes WCS (Hardisty) differential. For further information on our risk management positions, see Notes 37 and 38 of the Consolidated Financial Statements. Exposure to Counterparties In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders, customers and other counterparties for the provision and sale of goods and services and also in connection with our hedging activities, and in respect of asset or securities acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely basis or at all, we may suffer financial losses or delays of our development plans, or we may have to forego other opportunities, all of which could materially impact our business, results of operations and financial condition. CENOVUS ENERGY 2022 ANNUAL REPORT | 53 Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation. Interest rates have increased in response to inflation and additional rate increases may be implemented. Increases 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 Payments and Purchase of Securities The payment of dividends, whether base, variable or preferred, the 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 risks identified in the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation framework, the Company will target returns to shareholders as a percentage of Excess Free Funds Flow, through share buybacks or variable dividends, based on Net Debt at the preceding quarter-end, as described in this MD&A. The frequency and amount of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow, amount of share buybacks and other factors inherent with our capital allocation framework from time to time and our Net Debt and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above. Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of shareholders of Cenovus and on Cenovus’s earnings per share. 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 reputation. Credit, Liquidity and Availability of Future Financing Interest Rates 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 or significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing. Stakeholders are increasingly considering ESG matters, including climate-related targets, and failure to achieve our emissions reduction targets, or the perception that our targets are insufficient or will not be achieved, could adversely affect our ability to access cost- effective capital. 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 financial ratios 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, cash flows, 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 share repurchases and/or 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. 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 the transition to a lower-carbon economy, and the general 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, particularly a downgrade below investment grade ratings, or a negative change in the Company’s credit ratings outlook 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, particularly the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. 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, as a result of changing benchmark lending rates, macroeconomic factors or otherwise, 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 U.S. dollar interest expense, as expressed in Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. A change in the value of the Canadian dollar relative to RMB will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of natural gas and NGLs in the region. 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. 54 | CENOVUS ENERGY 2022 ANNUAL REPORT Credit, Liquidity and Availability of Future Financing Interest Rates 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 or significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing. Stakeholders are increasingly considering ESG matters, including climate-related targets, and failure to achieve our emissions reduction targets, or the perception that our targets are insufficient or will not be achieved, could adversely affect our ability to access cost- effective capital. 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 financial ratios 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, cash flows, 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 share repurchases and/or 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. 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 the transition to a lower-carbon economy, and the general 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, particularly a downgrade below investment grade ratings, or a negative change in the Company’s credit ratings outlook 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, particularly the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. 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, as a result of changing benchmark lending rates, macroeconomic factors or otherwise, 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 U.S. dollar interest expense, as expressed in Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. A change in the value of the Canadian dollar relative to RMB will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of natural gas and NGLs in the region. 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. Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation. Interest rates have increased in response to inflation and additional rate increases may be implemented. Increases 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 Payments and Purchase of Securities The payment of dividends, whether base, variable or preferred, the 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 risks identified in the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation framework, the Company will target returns to shareholders as a percentage of Excess Free Funds Flow, through share buybacks or variable dividends, based on Net Debt at the preceding quarter-end, as described in this MD&A. The frequency and amount of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow, amount of share buybacks and other factors inherent with our capital allocation framework from time to time and our Net Debt and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above. Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of shareholders of Cenovus and on Cenovus’s earnings per share. 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 reputation. CENOVUS ENERGY 2022 ANNUAL REPORT | 55 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, NGLs and other related products; (ii) drilling and completion of onshore 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, including at facilities operated by our partners or third-parties. 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; aviation, railcar or road transportation incidents; iceberg 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; planned or unplanned 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; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, adverse sea conditions, acts of activism, vandalism or terrorism, extreme weather events and natural disasters 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 and 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 policies and an associated system of standards, processes 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, not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, 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. Market Access Constraints and Transportation Restrictions Our production is transported through various pipelines, terminals and marine, rail and truck networks, and our refineries are reliant on various pipelines and marine, rail and truck 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, rail or truck 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, rail and truck 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 or marine, rail or truck 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. 56 | CENOVUS ENERGY 2022 ANNUAL REPORT 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, marine and truck shipments may be impacted by service delays, shortages of skilled labour, inclement weather, vessel, railcar or truck availability, railcar derailment or other rail, marine or truck 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, marine and trucking 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 shippers and may adversely affect our ability to transport by-rail, marine or truck transport or the economics associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third- party systems or refineries may limit our ability to deliver product with negative implications on our business, financial condition, results of operations and cash flows. 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: geological and engineering estimates; 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 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, reputation, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves. Cost Management and Inflation 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 steam-oil ratios in our Oil Sands operations; additional government or environmental regulations and supply chain disruptions, including access to skilled labour and critical third-party services. In addition, if our development, operating, construction 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. Further, there can be no assurance that any governmental action to mitigate inflationary cycles will be taken or will be effective. Central banks have increased interest rates in response to inflation and additional rate increases may be implemented. Governmental actions, such as the imposition of higher interest rates or wage controls may also negatively impact the Company’s costs and magnify the impacts of other risks identified in the Risk Management and Risk Factors section of this MD&A, including those set out under the “Financial Risk - Interest Rates” section above. 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, NGLs and other related products; (ii) drilling and completion of onshore 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, including at facilities operated by our partners or third-parties. 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; aviation, railcar or road transportation incidents; iceberg 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; planned or unplanned 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; loss of product; unavailability of feedstock; price and quality of feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, adverse sea conditions, acts of activism, vandalism or terrorism, extreme weather events and natural disasters 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 and 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 policies and an associated system of standards, processes 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, not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, 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. Market Access Constraints and Transportation Restrictions Our production is transported through various pipelines, terminals and marine, rail and truck networks, and our refineries are reliant on various pipelines and marine, rail and truck 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, rail or truck 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, rail and truck 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 or marine, rail or truck 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, marine and truck shipments may be impacted by service delays, shortages of skilled labour, inclement weather, vessel, railcar or truck availability, railcar derailment or other rail, marine or truck 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, marine and trucking 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 shippers and may adversely affect our ability to transport by-rail, marine or truck transport or the economics associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third- party systems or refineries may limit our ability to deliver product with negative implications on our business, financial condition, results of operations and cash flows. 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: geological and engineering estimates; 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 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, reputation, financial condition, results of operations and cash flows are highly dependent upon successfully producing current reserves and adding additional reserves. Cost Management and Inflation 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 steam-oil ratios in our Oil Sands operations; additional government or environmental regulations and supply chain disruptions, including access to skilled labour and critical third-party services. In addition, if our development, operating, construction 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. Further, there can be no assurance that any governmental action to mitigate inflationary cycles will be taken or will be effective. Central banks have increased interest rates in response to inflation and additional rate increases may be implemented. Governmental actions, such as the imposition of higher interest rates or wage controls may also negatively impact the Company’s costs and magnify the impacts of other risks identified in the Risk Management and Risk Factors section of this MD&A, including those set out under the “Financial Risk - Interest Rates” section above. CENOVUS ENERGY 2022 ANNUAL REPORT | 57 Continued inflation, any governmental response thereto, our inability to manage costs, or our inability to secure equipment, materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected timeline, or at all, could have a material adverse effect on our business, 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, refiners and marketers, some of which may have lower operating costs or greater resources than our Company does. Competitors 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. Cenovus may not be able to compete successfully against current and future competitors, and competitive pressures on Cenovus could have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows. 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 and the restart of the West White Rose Project. 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 including inflationary pressures; 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 affect our safety and environmental record and have a material adverse effect on our financial condition, results of operations and cash flows and reputation. 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 in areas where 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 development and 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, their management of operational issues and their reporting. 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. Failure to manage these partner risks could have a material adverse effect on our business, financial condition, results of operations, reputation, and cash flows. 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. 58 | CENOVUS ENERGY 2022 ANNUAL REPORT Technology, Information Systems and Data 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, cloud services and other technology systems and services. Such systems and services may be provided by third parties. In the event we are unable to access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the efficiency, resiliency 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 information, business information, and personal information. 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 disruptions from staff or third-party error or malfeasance, or natural disasters and acts of state or industrial espionage, activism, terrorism, or war. These risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic communications controls, impersonating internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators, or introducing ransomware into one or more systems or services to extract a payment, among others. Any such incident, breach, or disruption of our or our service providers’ technology systems or services, or other vendor technology systems or services (including where a threat actor is successful in bypassing our cyber-security measures and business process controls), could result in loss or the exposure of internal, confidential, financial, proprietary, personal or other sensitive information. These could result in financial losses, remediation and recovery costs, 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. Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in which we operate. We must comply with increasingly complex and rigorous, and sometimes conflicting, regulatory standards enacted to protect business and personal information in Canada, the United States, and elsewhere. These laws impose additional obligations on companies regarding the handling of personal information and provide certain individual privacy rights to persons whose information is collected, used, stored, processed or disclosed. Compliance with existing, proposed and recently enacted laws and regulations can be costly and time consuming, and any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition of fines by governmental authorities and damage to our reputation and credibility and could have a negative impact on financial condition. Compliance with such legislation may also result in increased operating costs. Failure to comply with such legislation may result in severe fines and penalties, which may adversely impact our reputation, 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 or trucking 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 business, financial condition, results of operations and cash flows. 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. Continued inflation, any governmental response thereto, our inability to manage costs, or our inability to secure equipment, materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected timeline, or at all, could have a material adverse effect on our business, financial condition, results of operations and cash flows. 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, refiners and marketers, some of which may have lower operating costs or greater resources than our Company does. Competitors 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. Cenovus may not be able to compete successfully against current and future competitors, and competitive pressures on Cenovus could have a material adverse effect on our business, reputation, financial condition, results of operations and cash Competition flows. 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 and the restart of the West White Rose Project. 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 including inflationary pressures; 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 affect our safety and environmental record and have a material adverse effect on our financial condition, results of operations and cash flows and reputation. 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 in areas where 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 development and 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, their management of operational issues and their reporting. 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. Failure to manage these partner risks could have a material adverse effect on our business, financial condition, results of operations, reputation, and cash flows. 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 Data 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, cloud services and other technology systems and services. Such systems and services may be provided by third parties. In the event we are unable to access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the efficiency, resiliency 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 information, business information, and personal information. 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 disruptions from staff or third-party error or malfeasance, or natural disasters and acts of state or industrial espionage, activism, terrorism, or war. These risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic communications controls, impersonating internal personnel or business partners to divert payments and financial assets to accounts controlled by the perpetrators, or introducing ransomware into one or more systems or services to extract a payment, among others. Any such incident, breach, or disruption of our or our service providers’ technology systems or services, or other vendor technology systems or services (including where a threat actor is successful in bypassing our cyber-security measures and business process controls), could result in loss or the exposure of internal, confidential, financial, proprietary, personal or other sensitive information. These could result in financial losses, remediation and recovery costs, 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. Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in which we operate. We must comply with increasingly complex and rigorous, and sometimes conflicting, regulatory standards enacted to protect business and personal information in Canada, the United States, and elsewhere. These laws impose additional obligations on companies regarding the handling of personal information and provide certain individual privacy rights to persons whose information is collected, used, stored, processed or disclosed. Compliance with existing, proposed and recently enacted laws and regulations can be costly and time consuming, and any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition of fines by governmental authorities and damage to our reputation and credibility and could have a negative impact on financial condition. Compliance with such legislation may also result in increased operating costs. Failure to comply with such legislation may result in severe fines and penalties, which may adversely impact our reputation, 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 or trucking 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 business, financial condition, results of operations and cash flows. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 59 Leadership and Talent Regulatory Risk Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our workforce. If we are unable to attract and retain key personnel and critical and diverse talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations, and our ability to meet our leadership related ESG targets. Litigation and Claims From time to time, we may be involved in demands, disputes, proceedings, arbitrations and/or litigation (“Claims”) arising out of or related to our operations and other contractual relationships. Claims may be material. Due to the nature of our operations we may be involved with various types of Claims including, but not limited to, failure to comply with applicable laws and regulations including potential claims that we have violated laws related to discrimination and harassment, health and safety, the environment, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy, employment, labour relations, personal injury and other Claims. We may be required to incur substantial expenses or devote significant resources in respect of any such Claims, which could result in unfavourable judgments, decisions, 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 business, reputation, financial condition and results of operations and cash flows. In addition, we may be subject to or impacted by climate change related litigation, including class actions. 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 rights and may have treaty rights to portions of Canada. There are outstanding Indigenous and treaty rights claims, which may include land 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 rights or affect 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 ongoing and 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. 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 we remain competitive and risks are understood, and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes in government policy which may adversely affect our business, results of operations, financial condition or reputation. 60 | CENOVUS ENERGY 2022 ANNUAL REPORT 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; cumulative effects and/or impacts from all types of industrial development; provincial and federal land and water use designations or management plans; 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, development 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 non- governmental organizations (“NGOs”) and citizen groups can also directly influence environmental regulations 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 requiring increased 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 quantity and quality, deep disposal 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 and maintain, or obtain and maintain on acceptable conditions, all necessary licenses, 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 or satisfactory terms could result in increased costs, project delays, abandonment and/or restructuring of projects. 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, ecological risks, acceleration of decommissioning timelines, and inflation, among other variables. For our Atlantic Canada 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 late 2030s. In Alberta and Saskatchewan, the A&R liability regimes include orphan well funds that are 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. The aggregate value of the A&R liabilities assumed has increased in recent years and will remain at elevated levels until a significant number of orphaned wells are decommissioned utilizing the orphan funds. The Alberta and Saskatchewan regulators may seek additional funding for such liabilities from industry participants, including Cenovus. The AER has discretion in the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R work. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset bases may be negatively impacted, 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 our abandonment of projects and transactions. We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased retail locations where we have retained environmental liability, 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. Leadership and Talent Regulatory Risk Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our workforce. If we are unable to attract and retain key personnel and critical and diverse talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations, and our ability to meet our leadership related ESG targets. Litigation and Claims From time to time, we may be involved in demands, disputes, proceedings, arbitrations and/or litigation (“Claims”) arising out of or related to our operations and other contractual relationships. Claims may be material. Due to the nature of our operations we may be involved with various types of Claims including, but not limited to, failure to comply with applicable laws and regulations including potential claims that we have violated laws related to discrimination and harassment, health and safety, the environment, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax, securities class actions, derivative actions, patent infringement, privacy, employment, labour relations, personal injury and other Claims. We may be required to incur substantial expenses or devote significant resources in respect of any such Claims, which could result in unfavourable judgments, decisions, 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 business, reputation, financial condition and results of operations and cash flows. In addition, we may be subject to or impacted by climate change related litigation, including class actions. 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 rights and may have treaty rights to portions of Canada. There are outstanding Indigenous and treaty rights claims, which may include land 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 rights or affect 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 ongoing and 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. 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 we remain competitive and risks are understood, and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes in government policy which may adversely affect our business, results of operations, financial condition or reputation. 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; cumulative effects and/or impacts from all types of industrial development; provincial and federal land and water use designations or management plans; 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, development 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 non- governmental organizations (“NGOs”) and citizen groups can also directly influence environmental regulations 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 requiring increased 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 quantity and quality, deep disposal 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 and maintain, or obtain and maintain on acceptable conditions, all necessary licenses, 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 or satisfactory terms could result in increased costs, project delays, abandonment and/or restructuring of projects. 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, ecological risks, acceleration of decommissioning timelines, and inflation, among other variables. For our Atlantic Canada 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 late 2030s. In Alberta and Saskatchewan, the A&R liability regimes include orphan well funds that are 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. The aggregate value of the A&R liabilities assumed has increased in recent years and will remain at elevated levels until a significant number of orphaned wells are decommissioned utilizing the orphan funds. The Alberta and Saskatchewan regulators may seek additional funding for such liabilities from industry participants, including Cenovus. The AER has discretion in the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R work. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within their asset bases may be negatively impacted, 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 our abandonment of projects and transactions. We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased retail locations where we have retained environmental liability, 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 61 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”). The investor-state dispute settlement provisions that were present within NAFTA will no longer be available in the CUSMA 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. However, starting July 1, 2023, such legacy disputes and disputes related to investments established or acquired on after July 1, 2020 will fall to the appropriate courts in the United States, or Cenovus may seek intervention of the Canadian government to pursue relief through state-to-state dispute resolution. 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 December 31, 2022, approximately 7 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 could occur. Any strike or work stoppage (for any reason, including a health and safety shutdown) may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows. During periods of contract negotiation or in the event of a strike or work stoppage, mitigation and emergency operation plans come with significant additional expenditures to ensure continuity of operations. 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. 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, increased tariffs and sanctions, 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. 62 | CENOVUS ENERGY 2022 ANNUAL REPORT 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. Increased tensions between the U.S. and China caused by escalated military exercises around Taiwan and the South China Sea could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, and ultimately affect our financial condition. 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, Canada-China and EU- China relations. 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. and Canadian sanctions and trade controls 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 and trade controls 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. In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for Cenovus personnel to be subject to an entry/exit ban in China. 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. 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. 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”). The investor-state dispute settlement provisions that were present within NAFTA will no longer be available in the CUSMA 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. However, starting July 1, 2023, such legacy disputes and disputes related to investments established or acquired on after July 1, 2020 will fall to the appropriate courts in the United States, or Cenovus may seek intervention of the Canadian government to pursue relief through state-to-state dispute resolution. 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 December 31, 2022, approximately 7 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 could occur. Any strike or work stoppage (for any reason, including a health and safety shutdown) may have a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows. During periods of contract negotiation or in the event of a strike or work stoppage, mitigation and emergency operation plans come with significant additional expenditures to ensure continuity of operations. 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. 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, increased tariffs and sanctions, 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. 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. Increased tensions between the U.S. and China caused by escalated military exercises around Taiwan and the South China Sea could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, and ultimately affect our financial condition. 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, Canada-China and EU- China relations. 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. and Canadian sanctions and trade controls 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 and trade controls 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. In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for Cenovus personnel to be subject to an entry/exit ban in China. 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. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 63 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, Canada-China and EU-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. The War in Ukraine Uncertainty regarding the duration and ultimate effects of the Russia – Ukraine war may result in major disruptions in oil and natural gas supply and continuing commodity price volatility. Further, Canada, the U.S. and other countries have imposed significant sanctions on Russia and many Russian officials, agencies, NGOs, companies and individuals some of whom are involved in the energy business or are significant buyers of crude oil or other hydrocarbons. Cenovus does not conduct business with sanctioned entities or persons and has no operations or significant business in Russia, Ukraine or other regions affected by these sanctions. Consequently, these sanctions have not had a material impact on Cenovus or our business. However, the scope and impact of the war, and any related international action, including any future sanctions, 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 a significant increase in focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, NGOs, environmental and governance organizations, institutional investors, social and environmental activists, shareholders, 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, making it difficult to accurately determine the cost impacts. 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 Canadian-based 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. In July 2022, the Government of Canada released an oil and gas emissions cap discussion document. The government is currently considering the form that any future regulation designed to meet the goals of the emission cap will take. The options proposed in the discussion document are a cap-and-trade system (under the Canadian Environmental Protection Act (“CEPA”) that sets a regulated limit on emissions from the sector or modifying the pollution pricing benchmark requirements to create price-driven limits on emissions from the oil and gas sector. The government is expected to release details on the form of the emissions cap in 2023. The Government has also committed to engaging provinces, territories, and Indigenous organizations in an interim review of the benchmark by 2026 after which, regulatory measures designed to meet the goals of the emissions cap could come into force. 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 came 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. In November 2022 the Government of Canada published for comment, a proposed regulatory framework to support their methane emissions reduction target. The proposal includes source by source requirements as well as additional performance-based requirements and is to be regulated under CEPA. 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 Renewable Fuel Standard (“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 expected that this target will be met largely through clean energy incentives introduced under the Inflation Reduction Act as opposed to regulatory measures. 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 published final regulations in 2022 for the Clean Fuel Standard under the Canadian Environmental Protection Act, 1999. The Clean Fuel Standard will 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 new regulatory framework will 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 become more stringent over time and are differentiated between different types of fuels to reflect the associated emissions reduction potential. Regulated parties have some flexibility with respect to how to achieve lower-carbon fuels in Canada. The cost of compliance will depend on a number of factors including, but not limited to, credit market supply and demand dynamics, development costs associated with low carbon fuels, and technology developments that could reduce demand for liquid transportation fuels. 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. 64 | CENOVUS ENERGY 2022 ANNUAL REPORT 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, Canada-China and EU-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. The War in Ukraine Uncertainty regarding the duration and ultimate effects of the Russia – Ukraine war may result in major disruptions in oil and natural gas supply and continuing commodity price volatility. Further, Canada, the U.S. and other countries have imposed significant sanctions on Russia and many Russian officials, agencies, NGOs, companies and individuals some of whom are involved in the energy business or are significant buyers of crude oil or other hydrocarbons. Cenovus does not conduct business with sanctioned entities or persons and has no operations or significant business in Russia, Ukraine or other regions affected by these sanctions. Consequently, these sanctions have not had a material impact on Cenovus or our business. However, the scope and impact of the war, and any related international action, including any future sanctions, 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 a significant increase in focus on the timing and pace of the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, NGOs, environmental and governance organizations, institutional investors, social and environmental activists, shareholders, 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, making it difficult to accurately determine the cost impacts. 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 Canadian-based 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. In July 2022, the Government of Canada released an oil and gas emissions cap discussion document. The government is currently considering the form that any future regulation designed to meet the goals of the emission cap will take. The options proposed in the discussion document are a cap-and-trade system (under the Canadian Environmental Protection Act (“CEPA”) that sets a regulated limit on emissions from the sector or modifying the pollution pricing benchmark requirements to create price-driven limits on emissions from the oil and gas sector. The government is expected to release details on the form of the emissions cap in 2023. The Government has also committed to engaging provinces, territories, and Indigenous organizations in an interim review of the benchmark by 2026 after which, regulatory measures designed to meet the goals of the emissions cap could come into force. 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 came 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. In November 2022 the Government of Canada published for comment, a proposed regulatory framework to support their methane emissions reduction target. The proposal includes source by source requirements as well as additional performance-based requirements and is to be regulated under CEPA. 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 Renewable Fuel Standard (“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 expected that this target will be met largely through clean energy incentives introduced under the Inflation Reduction Act as opposed to regulatory measures. 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 published final regulations in 2022 for the Clean Fuel Standard under the Canadian Environmental Protection Act, 1999. The Clean Fuel Standard will 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 new regulatory framework will 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 become more stringent over time and are differentiated between different types of fuels to reflect the associated emissions reduction potential. Regulated parties have some flexibility with respect to how to achieve lower-carbon fuels in Canada. The cost of compliance will depend on a number of factors including, but not limited to, credit market supply and demand dynamics, development costs associated with low carbon fuels, and technology developments that could reduce demand for liquid transportation fuels. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 65 Renewable Fuel Standards Market Access 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 renewable identification numbers (RINs) from other parties on the open market. RINs are credits used for compliance, and are the “currency” of the RFS program. 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 mandated federal GHG emissions standards applicable to automakers by setting fuel economy standards related to passenger cars and light trucks for Model Years 2023 through 2026. 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. In addition, the Canadian federal government has published proposed regulated sales targets for electric vehicles. 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, including as a result of climate change. 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, electricity and refined products. 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. 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 financial institutions, investors, credit rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. 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 and/or 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 in the energy industry, and investors may from time to time attempt to effect changes to our business, governance, or reporting practices 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. In the event such activist shareholders are successful, Cenovus may be required to incur costs and dedicate time to adopting new practices. 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. 66 | CENOVUS ENERGY 2022 ANNUAL REPORT Renewable Fuel Standards Market Access 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 renewable identification numbers (RINs) from other parties on the open market. RINs are credits used for compliance, and are the “currency” of the RFS program. 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 mandated federal GHG emissions standards applicable to automakers by setting fuel economy standards related to passenger cars and light trucks for Model Years 2023 through 2026. 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. In addition, the Canadian federal government has published proposed regulated sales targets for electric vehicles. 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. 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 – Technology 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, including as a result of climate change. 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, electricity and refined products. 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. 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 financial institutions, investors, credit rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. 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 and/or 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 in the energy industry, and investors may from time to time attempt to effect changes to our business, governance, or reporting practices 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. In the event such activist shareholders are successful, Cenovus may be required to incur costs and dedicate time to adopting new practices. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 67 Climate Change – Physical Risks Canadian Species at Risk Act Systemic climatic changes or extreme climatic conditions may also have material adverse effects on our business, reputation, financial condition, results of operations and cash flows. 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, refining, pipeline, 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, storms, extreme temperatures and other extreme weather events or natural disasters. This may result in cessation or diminishment of production or throughput, delay of exploration and development activities or delay of plant construction. Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations, business and financial results. For example, 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 as a result of severe weather conditions, has the potential to result in spills, asset damage, and production or refining 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 will 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, controls on land and resource access, 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 contaminants 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 have proposed that certain PFAS be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup liability at U.S. sites. See “Water Regulation” below. 68 | CENOVUS ENERGY 2022 ANNUAL REPORT 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 conservation agreements under the Species at Risk Act and the elaboration of sub-regional plans. 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. 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 necessitate 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 advanced 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. Climate Change – Physical Risks Canadian Species at Risk Act Systemic climatic changes or extreme climatic conditions may also have material adverse effects on our business, reputation, financial condition, results of operations and cash flows. 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, refining, pipeline, 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, storms, extreme temperatures and other extreme weather events or natural disasters. This may result in cessation or diminishment of production or throughput, delay of exploration and development activities or delay of plant construction. Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations, business and financial results. For example, 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 as a result of severe weather conditions, has the potential to result in spills, asset damage, and production or refining 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 will 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, controls on land and resource access, 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 contaminants 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 have proposed that certain PFAS be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup liability at U.S. sites. See “Water Regulation” below. 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 conservation agreements under the Species at Risk Act and the elaboration of sub-regional plans. 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. 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 necessitate 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 advanced 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 69 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 conjunction with horizontal drilling techniques in Western Canada, which has prompted legislative and regulatory initiatives intended to address these concerns. New laws, regulations or permitting requirements regarding hydraulic fracturing may 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 resulting in increased cost of doing business as well as impacting the amount of natural gas and oil that we are ultimately able to produce from our reserves. 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, decreasing freshwater intensity, 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, 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 Target and Ambition 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. If 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 planned timelines, or at all. 70 | CENOVUS ENERGY 2022 ANNUAL REPORT In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework, support from government, financial or otherwise, 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 business, financial condition, results of operations and cash flows. Water Stewardship Targets Our ability to reduce freshwater intensity by 20 percent in oil sands and in thermal operations from 2019 levels by year-end 2030 or maintain such improvements 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. Biodiversity Targets current timelines, or at all. Indigenous Reconciliation 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 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 as well as an aspiration for our Board to have at least 40 percent representation from women, Indigenous peoples, persons with disabilities and members of visible minorities among non-management directors. Efforts to meet and maintain such targets may increase the time and costs associated with appointing and replacing key personnel. Further, an inability to hire or promote qualified candidates or 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. 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 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. 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 conjunction with horizontal drilling techniques in Western Canada, which has prompted legislative and regulatory initiatives intended to address these concerns. New laws, regulations or permitting requirements regarding hydraulic fracturing may 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 resulting in increased cost of doing business as well as impacting the amount of natural gas and oil that we are ultimately able to produce from our reserves. 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, decreasing freshwater intensity, 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, 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 Target and Ambition 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. If 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 planned timelines, or at all. In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework, support from government, financial or otherwise, 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 business, financial condition, results of operations and cash flows. Water Stewardship Targets Our ability to reduce freshwater intensity by 20 percent in oil sands and in thermal operations from 2019 levels by year-end 2030 or maintain such improvements 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. 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 as well as an aspiration for our Board to have at least 40 percent representation from women, Indigenous peoples, persons with disabilities and members of visible minorities among non-management directors. Efforts to meet and maintain such targets may increase the time and costs associated with appointing and replacing key personnel. Further, an inability to hire or promote qualified candidates or 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. 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 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 71 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 our 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. Risks Relating to Acquisitions We have completed, and may complete in the future, one or more acquisitions for various strategic reasons. Our ability to achieve the benefits of any acquisition will depend upon the actions of our counterparties; our ability, and the ability of our counterparties, to obtain the necessary shareholder, regulatory and third-party approvals, as applicable, and satisfy all conditions to closing; the risks inherent in the operation of the assets being acquired prior or subsequent to closing; the effectiveness of our diligence investigations; the physical condition of the assets upon closing; our ability to obtain indemnities and/or fund ongoing maintenance, repair and operation costs of the assets acquired; our ability to assess the integrity and reliability of the assets being acquired; 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 their characteristics, including, among other things, estimated recoverable reserves, future production and throughput, 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 or require repair or other expenditures, the scope of which may be uncertain, result in increased costs and affect our ability, and timeline, to realize the benefits of the acquisition. Risks Relating to Dispositions We have completed, and may complete in the future, one or more dispositions for various strategic reasons. Various factors could materially affect our ability 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. 72 | CENOVUS ENERGY 2022 ANNUAL REPORT Risks Related to Significant Shareholders of Cenovus As of December 31, 2022, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments") owned 16.6 percent and 12.1 percent of our common shares, respectively. The sale into the market of Cenovus common shares held by either Hutchison or L.F. Investments, whether through open market trades on the TSX or NYSE, 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 has entered into with Cenovus, or market perception regarding Hutchison’s 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 Cenovus, each of Hutchison and L.F. Investments may be able to impact certain matters requiring Cenovus 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. Contingent Payments Payable relating to Sunrise Acquisition In connection with the Sunrise Acquisition, we agreed to make contingent payments to BP Canada under certain circumstances. The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the two-year period following the closing of the Sunrise Acquisition (August 31, 2022), and such payments are cumulatively capped at $600 million. This payment may be material in any given reporting period as the entire maximum payment could be reached in a single quarter and could have an adverse impact on our results of operations and financial condition. Tax Laws Income tax laws and regulations and other laws and 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 to the detriment of our 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 our shareholders. The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organisation for Economic Co-operation and Development (“OECD”). 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. In Canada, in the 2022 Fall Economic Statement released by the Department of Finance, a new tax on share buybacks by public corporations was proposed. Under the proposal, which would come into force on January 1, 2024, a two percent corporate- level tax would apply on the "net value" of all types of shares buybacks by public corporations in Canada. While there are few details available on the proposed tax, we will continue to monitor and assess any potential adverse impacts as more information becomes available. 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 at cenovus.com. 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 our 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. Risks Relating to Acquisitions We have completed, and may complete in the future, one or more acquisitions for various strategic reasons. Our ability to achieve the benefits of any acquisition will depend upon the actions of our counterparties; our ability, and the ability of our counterparties, to obtain the necessary shareholder, regulatory and third-party approvals, as applicable, and satisfy all conditions to closing; the risks inherent in the operation of the assets being acquired prior or subsequent to closing; the effectiveness of our diligence investigations; the physical condition of the assets upon closing; our ability to obtain indemnities and/or fund ongoing maintenance, repair and operation costs of the assets acquired; our ability to assess the integrity and reliability of the assets being acquired; 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 their characteristics, including, among other things, estimated recoverable reserves, future production and throughput, 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 or require repair or other expenditures, the scope of which may be uncertain, result in increased costs and affect our ability, and timeline, to realize the benefits of the acquisition. Risks Relating to Dispositions We have completed, and may complete in the future, one or more dispositions for various strategic reasons. Various factors could materially affect our ability 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 Significant Shareholders of Cenovus As of December 31, 2022, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments") owned 16.6 percent and 12.1 percent of our common shares, respectively. The sale into the market of Cenovus common shares held by either Hutchison or L.F. Investments, whether through open market trades on the TSX or NYSE, 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 has entered into with Cenovus, or market perception regarding Hutchison’s 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 Cenovus, each of Hutchison and L.F. Investments may be able to impact certain matters requiring Cenovus 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. Contingent Payments Payable relating to Sunrise Acquisition In connection with the Sunrise Acquisition, we agreed to make contingent payments to BP Canada under certain circumstances. The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the two-year period following the closing of the Sunrise Acquisition (August 31, 2022), and such payments are cumulatively capped at $600 million. This payment may be material in any given reporting period as the entire maximum payment could be reached in a single quarter and could have an adverse impact on our results of operations and financial condition. Tax Laws Income tax laws and regulations and other laws and 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 to the detriment of our 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 our shareholders. The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organisation for Economic Co-operation and Development (“OECD”). 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. In Canada, in the 2022 Fall Economic Statement released by the Department of Finance, a new tax on share buybacks by public corporations was proposed. Under the proposal, which would come into force on January 1, 2024, a two percent corporate- level tax would apply on the "net value" of all types of shares buybacks by public corporations in Canada. While there are few details available on the proposed tax, we will continue to monitor and assess any potential adverse impacts as more information becomes available. 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 at cenovus.com. CENOVUS ENERGY 2022 ANNUAL REPORT | 73 CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES Identification of Cash-Generating Units 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. 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. Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty Recoveries from Insurance Claims 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. 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. Joint Arrangements Key Sources of Estimation Uncertainty The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities: • WRB Refining LP (“WRB”). • BP-Husky Refining LLC (“Toledo”). It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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. Prior to August 31, 2022, Cenovus held a 50 percent interest in Sunrise, which was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls Sunrise, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, Sunrise was consolidated. 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 development of Sunrise, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans. • WRB has third-party debt facilities to cover short-term working capital requirements. Up until November 2022, • • • Sunrise also had third-party debt facilities. Sunrise was 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. 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. 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, 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. 74 | CENOVUS ENERGY 2022 ANNUAL REPORT Financial Statements. Joint Arrangements The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities: • WRB Refining LP (“WRB”). • BP-Husky Refining LLC (“Toledo”). It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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. Prior to August 31, 2022, Cenovus held a 50 percent interest in Sunrise, which was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls Sunrise, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, Sunrise was consolidated. 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 development of Sunrise, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes • WRB has third-party debt facilities to cover short-term working capital requirements. Up until November 2022, payable and loans. Sunrise also had third-party debt facilities. Sunrise was 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. CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES Identification of Cash-Generating Units 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 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. Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty Recoveries from Insurance Claims 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. 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. 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. 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, 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 75 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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, 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. Changes in Accounting Policies There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2022. 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, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business. CONTROL ENVIRONMENT Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2022. 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, 2022. The effectiveness of our ICFR was audited as at December 31, 2022 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, 2022. 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. 76 | CENOVUS ENERGY 2022 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2022 Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) REPORT OF MANAGEMENT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF EQUITY CONSOLIDATED STATEMENTS OF CASH FLOWS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES 2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE 78 79 83 84 85 86 87 88 88 95 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 95 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY 5. ACQUISITIONS 6. GENERAL AND ADMINISTRATIVE 7. FINANCE COSTS 8. INTEGRATION AND TRANSACTION COSTS 9. FOREIGN EXCHANGE (GAIN) LOSS, NET 10. DIVESTITURES 11. IMPAIRMENT CHARGES AND REVERSALS 12. OTHER (INCOME) LOSS, NET 13. INCOME TAXES 14. PER SHARE AMOUNTS 15. CASH AND CASH EQUIVALENTS 105 108 111 111 111 111 112 112 118 118 121 122 17. INVENTORIES 18. ASSETS HELD FOR SALE 19. EXPLORATION AND EVALUATION ASSETS, NET 20. PROPERTY, PLANT AND EQUIPMENT, NET 21. RIGHT-OF-USE ASSETS, NET 22. JOINT ARRANGEMENTS 23. OTHER ASSETS 24. GOODWILL 25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 26. DEBT AND CAPITAL STRUCTURE 27. LEASE LIABILITIES 28. CONTINGENT PAYMENTS 29. DECOMMISSIONING LIABILITIES 30. OTHER LIABILITIES 31. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS 32. SHARE CAPITAL AND WARRANTS 33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 34. STOCK-BASED COMPENSATION PLANS 35. EMPLOYEE SALARIES AND BENEFIT EXPENSES 36. RELATED PARTY TRANSACTIONS 37. FINANCIAL INSTRUMENTS 38. RISK MANAGEMENT 39. SUPPLEMENTARY CASH FLOW INFORMATION 16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 122 40. COMMITMENTS AND CONTINGENCIES 122 122 123 124 125 126 127 127 128 128 132 133 134 135 135 139 141 141 145 145 145 148 151 154 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. The fair value of assets acquired, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, 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. Changes in Accounting Policies There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2022. 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, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business. CONTROL ENVIRONMENT Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures (“DC&P”) as at December 31, 2022. 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, 2022. The effectiveness of our ICFR was audited as at December 31, 2022 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, 2022. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 77 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, 2022. 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, 2022. 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, 2022, as stated in their Report of Independent Registered Public Accounting Firm dated February 15, 2023. PricewaterhouseCoopers LLP has provided such opinions. /s/ Alexander J. Pourbaix Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 15, 2023 /s/ Jeffrey R. Hart Jeffrey R. Hart Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. 78 | CENOVUS ENERGY 2022 ANNUAL REPORT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Cenovus Energy Inc. Opinions on the 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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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. 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. 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, 2022. 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, 2022. 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, 2022, as stated in their Report of Independent Registered Public Accounting Firm dated February 15, 2023. PricewaterhouseCoopers LLP has provided such opinions. /s/ Alexander J. Pourbaix Alexander J. Pourbaix President & Chief Executive Officer Cenovus Energy Inc. February 15, 2023 /s/ Jeffrey R. Hart Jeffrey R. Hart Cenovus Energy Inc. Executive Vice-President & Chief Financial Officer REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of Cenovus Energy Inc. Opinions on the 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, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 79 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. Valuation of an Oil Sands Property Related to the Acquisition of the Remaining 50 Percent Interest in the Sunrise Oil Sands Partnership As described in Notes 3, 4, and 5 to the Consolidated Financial Statements, on August 31, 2022, the Company acquired the remaining 50 percent interest in the Sunrise Oil Sands Partnership (SOSP), a joint operation in the Oil Sands segment in an acquisition accounted for as a business combination using the acquisition method, 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. As the Company acquired control of SOSP in stages, Management remeasured the previously held interest in SOSP to fair value of $1.6 billion at the acquisition date and total consideration for the newly acquired 50 percent interest was $1.0 billion. The assets acquired included an oil sands property categorized as Property, Plant and Equipment (PP&E), which was valued at $3.2 billion on a 100 percent basis. Management estimated the fair value of the acquired oil sands property at the acquisition date using an after-tax discounted cash flow model. The fair value assessment required the use of significant estimates and judgments by Management including assumptions related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimate of reserves for the acquired oil sands property were developed by Management’s specialists, including internal geology and engineering professionals, and independent qualified reserves evaluators. The principal considerations for our determination that performing procedures relating to the valuation of the oil sands property related to the acquisition of the remaining 50 percent interest in SOSP is a critical audit matter are (i) the significant judgment by Management, including the use of Management’s specialists, as applicable, in developing the fair value of the acquired oil sands property; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted cash flow model used to value the acquired oil sands property related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate; 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 value of the acquired oil sands property. These procedures also included, among others, testing Management’s process for determining the fair value of the acquired oil sands property, which included (i) evaluating the appropriateness of the method used by Management in making this estimate; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the fair value and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and future development and operating expenditures for the acquired oil sands property. Evaluating the significant assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property 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 used to determine the fair value of the acquired oil sands property. 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 method and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. 80 | CENOVUS ENERGY 2022 ANNUAL REPORT Evaluating the significant assumptions used by Management’s specialists also involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property 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 value of the acquired oil sands property determined by Management, including the discount rate. Assessment of Impairment/Impairment Reversal of PP&E for Each of the Cash Generating Units (CGUs) in the U.S. Manufacturing Segment (the U.S. Manufacturing CGUs) As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment/impairment reversal 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) including net impairment losses, may exceed its recoverable amount or that a previously recorded impairment may have reversed. If indicators of impairment or impairment reversal exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less costs of disposal (FVLCOD). 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 CGU in prior periods. As of December 31, 2022, the Company had $4.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to its U.S. Manufacturing segment. Management identified indicators of impairment for the Superior and Toledo CGUs and performed impairment assessments for each of these CGUs as of December 31, 2022. The carrying amounts of these CGUs were determined to be greater than their recoverable amounts and an aggregate impairment charge of $1.5 billion was recorded as additional DD&A. Management also identified indicators of impairment reversal for the Wood River, Borger and Lima CGUs and performed impairment assessments for each CGU as of December 31, 2022. The recoverable amounts of these CGU’s were determined to be greater than their carrying amounts and an aggregate impairment reversal of $1.2 billion was recorded as a reduction to DD&A. Management determined the recoverable amounts of PP&E for the U.S. Manufacturing CGUs based on their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by Management related to throughput, forward crude oil prices, forward crack spreads, future operating costs, future capital expenditures and discount rates. The principal considerations for our determination that performing procedures relating to the assessment of impairment/ impairment reversal of PP&E for each of the CGUs in 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 U.S. Manufacturing CGUs; (ii) a 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, future operating costs 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 U.S. Manufacturing CGUs. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the U.S. Manufacturing 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 significant assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital expenditures and future operating costs. 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 U.S. Manufacturing CGUs, including the discount rates. Impact of Reserves Estimates on PP&E, Net of the Oil Sands and Offshore Segments As described in Notes 1, 3, 4, 11 and 20 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. Management calculates depletion for Oil Sands PP&E using the unit-of-production method based on estimated proved reserves. 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. Valuation of an Oil Sands Property Related to the Acquisition of the Remaining 50 Percent Interest in the Sunrise Oil Sands Partnership As described in Notes 3, 4, and 5 to the Consolidated Financial Statements, on August 31, 2022, the Company acquired the remaining 50 percent interest in the Sunrise Oil Sands Partnership (SOSP), a joint operation in the Oil Sands segment in an acquisition accounted for as a business combination using the acquisition method, 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. As the Company acquired control of SOSP in stages, Management remeasured the previously held interest in SOSP to fair value of $1.6 billion at the acquisition date and total consideration for the newly acquired 50 percent interest was $1.0 billion. The assets acquired included an oil sands property categorized as Property, Plant and Equipment (PP&E), which was valued at $3.2 billion on a 100 percent basis. Management estimated the fair value of the acquired oil sands property at the acquisition date using an after-tax discounted cash flow model. The fair value assessment required the use of significant estimates and judgments by Management including assumptions related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimate of reserves for the acquired oil sands property were developed by Management’s specialists, including internal geology and engineering professionals, and independent qualified reserves evaluators. The principal considerations for our determination that performing procedures relating to the valuation of the oil sands property related to the acquisition of the remaining 50 percent interest in SOSP is a critical audit matter are (i) the significant judgment by Management, including the use of Management’s specialists, as applicable, in developing the fair value of the acquired oil sands property; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in the discounted cash flow model used to value the acquired oil sands property related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate; 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 value of the acquired oil sands property. These procedures also included, among others, testing Management’s process for determining the fair value of the acquired oil sands property, which included (i) evaluating the appropriateness of the method used by Management in making this estimate; (ii) testing the completeness and accuracy of underlying data used in Management’s determination of the fair value and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and future development and operating expenditures for the acquired oil sands property. Evaluating the significant assumptions used by Management involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property 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 used to determine the fair value of the acquired oil sands property. 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 method and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by Management’s specialists also involved assessing whether the assumptions used were reasonable considering the current and past performance of the acquired oil sands property 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 value of the acquired oil sands property determined by Management, including the discount rate. Assessment of Impairment/Impairment Reversal of PP&E for Each of the Cash Generating Units (CGUs) in the U.S. Manufacturing Segment (the U.S. Manufacturing CGUs) As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators of impairment/impairment reversal 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) including net impairment losses, may exceed its recoverable amount or that a previously recorded impairment may have reversed. If indicators of impairment or impairment reversal exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less costs of disposal (FVLCOD). 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 CGU in prior periods. As of December 31, 2022, the Company had $4.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to its U.S. Manufacturing segment. Management identified indicators of impairment for the Superior and Toledo CGUs and performed impairment assessments for each of these CGUs as of December 31, 2022. The carrying amounts of these CGUs were determined to be greater than their recoverable amounts and an aggregate impairment charge of $1.5 billion was recorded as additional DD&A. Management also identified indicators of impairment reversal for the Wood River, Borger and Lima CGUs and performed impairment assessments for each CGU as of December 31, 2022. The recoverable amounts of these CGU’s were determined to be greater than their carrying amounts and an aggregate impairment reversal of $1.2 billion was recorded as a reduction to DD&A. Management determined the recoverable amounts of PP&E for the U.S. Manufacturing CGUs based on their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by Management related to throughput, forward crude oil prices, forward crack spreads, future operating costs, future capital expenditures and discount rates. The principal considerations for our determination that performing procedures relating to the assessment of impairment/ impairment reversal of PP&E for each of the CGUs in 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 U.S. Manufacturing CGUs; (ii) a 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, future operating costs 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 U.S. Manufacturing CGUs. These procedures also included, among others, testing Management’s process for determining the recoverable amounts of the U.S. Manufacturing 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 significant assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital expenditures and future operating costs. 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 U.S. Manufacturing CGUs, including the discount rates. Impact of Reserves Estimates on PP&E, Net of the Oil Sands and Offshore Segments As described in Notes 1, 3, 4, 11 and 20 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. Management calculates depletion for Oil Sands PP&E using the unit-of-production method based on estimated proved reserves. CENOVUS ENERGY 2022 ANNUAL REPORT | 81 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) For the years ended December 31, ($ millions, except per share amounts) Notes 2022 2021 (1) 2020 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Earnings (Loss) Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) Net Earnings (Loss) Per Common Share ($) Basic Diluted (1) See Note 3X for revisions to prior period results. See accompanying Notes to Consolidated Financial Statements. 11,20,21,23 1 1 37 22 6 7 8 9 5 28 10 12 13 14 71,765 4,868 66,897 33,801 11,530 5,569 1,636 4,679 101 (15) 865 820 (81) 106 343 (549) 162 (269) (532) 8,731 2,281 6,450 3.29 3.20 48,811 2,454 46,357 23,326 8,038 4,716 995 5,886 18 (57) 849 1,082 (23) 349 (174) — 575 (229) (309) 1,315 728 587 0.27 0.27 13,914 371 13,543 5,681 4,728 1,955 308 3,464 91 — 292 536 (9) 29 (181) — (80) (81) 40 (3,230) (851) (2,379) (1.94) (1.94) For Offshore PP&E, 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, 2022, the Company had $24.7 billion and $2.5 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.3 billion of DD&A expense and no impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2022. Management identified potential indicators of impairment for the Sunrise CGU as of December 31, 2022 and performed an impairment test. Management determined the recoverable amount of the Sunrise CGU (the recoverable amount) based on its fair value less costs of disposal using a discounted after-tax cash flow model. The determination of the recoverable amount required the use of significant assumptions and judgments by Management related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimates of reserves used for both the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments have been developed by Management’s specialists, specifically independent qualified reserves evaluators. The principal considerations for our determination that performing procedures relating to the impact of reserves estimates on PP&E, net of the Oil Sands and Offshore 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 the recoverable amount; (ii) there was a 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, future development and operating expenditures and the discount rate; 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 estimates of reserves, the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s process for determining the recoverable amount and DD&A expense for the Oil Sands and Offshore 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 amount; (iii) assessing the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and the recoverable amount, 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 used in the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore 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 significant assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by Management’s specialists 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 amount, including the discount rate used. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 15, 2023 We have served as the Company’s auditor since 2008. 82 | CENOVUS ENERGY 2022 ANNUAL REPORT For Offshore PP&E, 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, 2022, the Company had $24.7 billion and $2.5 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.3 billion of DD&A expense and no impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2022. Management identified potential indicators of impairment for the Sunrise CGU as of December 31, 2022 and performed an impairment test. Management determined the recoverable amount of the Sunrise CGU (the recoverable amount) based on its fair value less costs of disposal using a discounted after-tax cash flow model. The determination of the recoverable amount required the use of significant assumptions and judgments by Management related to forward commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the discount rate. Management’s estimates of reserves used for both the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments have been developed by Management’s specialists, specifically independent qualified reserves evaluators. The principal considerations for our determination that performing procedures relating to the impact of reserves estimates on PP&E, net of the Oil Sands and Offshore 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 the recoverable amount; (ii) there was a 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, future development and operating expenditures and the discount rate; 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 estimates of reserves, the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s process for determining the recoverable amount and DD&A expense for the Oil Sands and Offshore 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 amount; (iii) assessing the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and the recoverable amount, 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 used in the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and Offshore 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 significant assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions used by Management’s specialists 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 amount, including the discount rate used. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 15, 2023 We have served as the Company’s auditor since 2008. CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) For the years ended December 31, ($ millions, except per share amounts) Notes 2022 2021 (1) 2020 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Earnings (Loss) Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) Net Earnings (Loss) Per Common Share ($) Basic Diluted (1) See Note 3X for revisions to prior period results. See accompanying Notes to Consolidated Financial Statements. 1 1 37 11,20,21,23 22 6 7 8 9 5 28 10 12 13 14 71,765 4,868 66,897 33,801 11,530 5,569 1,636 4,679 101 (15) 865 820 (81) 106 343 (549) 162 (269) (532) 8,731 2,281 6,450 3.29 3.20 48,811 2,454 46,357 23,326 8,038 4,716 995 5,886 18 (57) 849 1,082 (23) 349 (174) — 575 (229) (309) 1,315 728 587 0.27 0.27 13,914 371 13,543 5,681 4,728 1,955 308 3,464 91 — 292 536 (9) 29 (181) — (80) (81) 40 (3,230) (851) (2,379) (1.94) (1.94) CENOVUS ENERGY 2022 ANNUAL REPORT | 83 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) CONSOLIDATED BALANCE SHEETS For the years ended December 31, ($ millions) Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Items That Will not be Reclassified to Profit or Loss: Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits Change in the Fair Value of Equity Instruments at FVOCI (1) Items That may be Reclassified to Profit or Loss: Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) (1) Fair value through other comprehensive income (loss) (“FVOCI”). See accompanying Notes to Consolidated Financial Statements. Notes 33 31 2022 6,450 71 2 713 786 7,236 2021 587 38 — (129) (91) 496 2020 (2,379) (8) — (44) (52) (2,431) As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Assets Held for Sale Total Current Assets Restricted Cash Exploration and Evaluation Assets, Net Property, Plant and Equipment, Net Right-of-Use Assets, Net Income Tax Receivable Investments in Equity-Accounted Affiliates Accounts Payable and Accrued Liabilities Liabilities Related to Assets Held for Sale Other Assets Deferred Income Taxes Goodwill Total Assets Liabilities and Equity Current Liabilities Short-Term Borrowings Lease Liabilities Contingent Payments Income Tax Payable Total Current Liabilities Long-Term Debt Lease Liabilities Contingent Payments Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity Non-Controlling Interest Total Liabilities and Equity [/s/ Keith A. MacPhail] Keith A. MacPhail Director Cenovus Energy Inc. February 15, 2023 Commitments and Contingencies See accompanying Notes to Consolidated Financial Statements. [/s/ Claude Mongeau] Claude Mongeau Director Cenovus Energy Inc. Notes 2022 2021 12,430 11,988 4,524 3,473 121 4,312 — 209 685 36,499 1,845 25 365 342 546 2,923 55,869 6,124 115 308 263 1,211 — 8,021 8,691 2,528 156 3,559 1,042 4,283 28,280 27,576 13 55,869 2,873 3,870 22 3,919 1,304 186 720 34,225 2,010 66 311 431 694 3,473 54,104 6,353 79 272 236 179 186 7,305 12,385 2,685 — 3,906 929 3,286 30,496 23,596 12 54,104 15 16 17 18 29 1,19 1,20 1,21 22 23 13 24 25 26 27 28 18 26 27 28 29 30 13 40 84 | CENOVUS ENERGY 2022 ANNUAL REPORT CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) CONSOLIDATED BALANCE SHEETS For the years ended December 31, ($ millions) Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Items That Will not be Reclassified to Profit or Loss: Actuarial Gain (Loss) Relating to Pension and Other Post-Employment Benefits Change in the Fair Value of Equity Instruments at FVOCI (1) Items That may be Reclassified to Profit or Loss: Foreign Currency Translation Adjustment Total Other Comprehensive Income (Loss), Net of Tax Comprehensive Income (Loss) (1) Fair value through other comprehensive income (loss) (“FVOCI”). See accompanying Notes to Consolidated Financial Statements. Notes 33 31 2022 6,450 71 2 713 786 7,236 2021 587 38 — (129) (91) 496 2020 (2,379) (8) — (44) (52) (2,431) As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Assets Held for Sale Total Current Assets Restricted Cash Exploration and Evaluation Assets, Net Property, Plant and Equipment, Net Right-of-Use Assets, Net Income Tax Receivable Investments in Equity-Accounted Affiliates Other Assets Deferred Income Taxes Goodwill Total Assets Liabilities and Equity Current Liabilities Accounts Payable and Accrued Liabilities Short-Term Borrowings Lease Liabilities Contingent Payments Income Tax Payable Liabilities Related to Assets Held for Sale Total Current Liabilities Long-Term Debt Lease Liabilities Contingent Payments Decommissioning Liabilities Other Liabilities Deferred Income Taxes Total Liabilities Shareholders’ Equity Non-Controlling Interest Total Liabilities and Equity Commitments and Contingencies See accompanying Notes to Consolidated Financial Statements. [/s/ Keith A. MacPhail] Keith A. MacPhail Director Cenovus Energy Inc. February 15, 2023 [/s/ Claude Mongeau] Claude Mongeau Director Cenovus Energy Inc. Notes 2022 2021 4,524 3,473 121 4,312 — 2,873 3,870 22 3,919 1,304 12,430 11,988 209 685 36,499 1,845 25 365 342 546 2,923 55,869 6,124 115 308 263 1,211 — 8,021 8,691 2,528 156 3,559 1,042 4,283 28,280 27,576 13 55,869 186 720 34,225 2,010 66 311 431 694 3,473 54,104 6,353 79 272 236 179 186 7,305 12,385 2,685 — 3,906 929 3,286 30,496 23,596 12 54,104 15 16 17 18 29 1,19 1,20 1,21 22 23 13 24 25 26 27 28 18 26 27 28 29 30 13 40 CENOVUS ENERGY 2022 ANNUAL REPORT | 85 CONSOLIDATED STATEMENTS OF EQUITY ($ millions) CONSOLIDATED STATEMENTS OF CASH FLOWS Shareholders' Equity Preferred Shares Warrants (Note 32) (Note 32) Paid in Surplus Retained Earnings AOCI (1) (Note 33) Common Shares (Note 32) 11,040 — — — — — 11,040 — — — 6,111 7 (145) — — 3 — — — — 17,016 — — — 170 (959) 93 — — — — — As at December 31, 2019 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Stock-Based Compensation Expense Base Dividends on Common Shares As at December 31, 2020 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Common Shares Issued (Note 5) Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs (2) (Note 32) Preferred Shares Issued (Note 5) Warrants Issued (Note 5) Warrants Exercised Stock-Based Compensation Expense Base Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest As at December 31, 2021 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs (2) (Note 32) Warrants Exercised Stock-Based Compensation Expense Base Dividends on Common Shares Variable Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest As at December 31, 2022 — — — — — — — — — — — — — 519 — — — — — — 519 — — — — — — — — — — — — — — — — — — — — — — — — — 216 (1) — — — — 215 — — — — — (31) — — — — — 4,377 — — — 14 — 4,391 — — — — (1) (120) — — — 14 — — — 4,284 — — — (32) (1,571) — 10 — — — — 2,957 (2,379) — (2,379) — (77) 501 587 — 587 — — — — — — — (176) (34) — 878 6,450 — 6,450 — — — — (682) (219) (35) — 6,392 Total 19,201 (2,379) (52) (2,431) 14 (77) 16,707 587 (91) 496 6,111 6 (265) 519 216 2 14 (176) (34) — 23,596 6,450 786 7,236 138 (2,530) 62 10 (682) (219) (35) — Non- Controlling Interest — — — — — — — — — — — — — — — — — — — 12 12 — — — — — — — — — — 1 13 827 — (52) (52) — — 775 — (91) (91) — — — — — — — — — — 684 — 786 786 — — — — — — — — 16,320 519 184 2,691 1,470 27,576 (1) (2) Accumulated other comprehensive income (loss) (“AOCI”). Normal course issuer bids (“NCIBs”). See accompanying Notes to Consolidated Financial Statements. 86 | CENOVUS ENERGY 2022 ANNUAL REPORT For the years ended December 31, ($ millions) Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization Inventory Write-Down (Reversal) Realization of Inventory Write-Downs Deferred Income Tax Expense (Recovery) Unrealized (Gain) Loss on Risk Management Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss on Non-Operating Items Revaluation (Gains) Re-measurement of Contingent Payments, Net of Cash Paid (Gain) Loss on Divestiture of Assets Unwinding of Discount on Decommissioning Liabilities (Income) Loss From Equity-Accounted Affiliates Distributions Received From Equity-Accounted Affiliates Other Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Cash From (Used in) Operating Activities Investing Activities Acquisitions, Net of Cash Acquired Capital Investment Proceeds From Divestitures Payment on Divestiture of Assets Net Change in Investments and Other Net Change in Non-Cash Working Capital Cash From (Used in) Investing Activities Net Cash Received on Assumption of Decommissioning Liabilities Net Cash Provided (Used) Before Financing Activities Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Issuance of Long-Term Debt (Repayment) of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Principal Repayment of Leases Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs Proceeds From Exercise of Warrants Base Dividends Paid on Common Shares Variable Dividends Paid on Common Shares Dividends Paid on Preferred Shares Other Cash From (Used in) Financing Activities Effect of Foreign Exchange on Cash and Cash Equivalents Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year See accompanying Notes to Consolidated Financial Statements. Notes 2022 2021 2020 11,20,21,23 19,20 13 37 9 5 10 29 22 22 39 5 10 10 5 39 39 27 32 14 14 6,450 4,679 — — 642 (126) 365 146 (549) (469) (269) 176 (15) 65 (117) (150) 575 11,403 (397) (3,708) 1,514 (50) — (211) 538 (2,314) 9,089 34 — — (4,149) (302) 138 (2,530) 62 (682) (219) (26) (2) 238 1,651 2,873 4,524 587 5,886 16 (31) 452 2 (312) 171 — 400 (229) 199 (57) 137 27 (102) (1,227) 5,919 735 (2,563) 435 — 75 17 359 (942) 4,977 (77) 1,557 (2,870) (350) (300) 6 2 (265) (176) — (34) — 25 2,495 378 2,873 (2,379) 3,464 555 (572) (838) 56 (131) (33) — (80) (81) 57 — — 99 (42) 198 273 — (859) 38 — — (4) (38) (863) (590) 117 1,326 (112) (220) (197) (77) — — — — — — 837 (55) 192 186 378 (7,676) (2,507) CONSOLIDATED STATEMENTS OF EQUITY ($ millions) Shareholders' Equity Common Preferred Shares Shares Warrants (Note 32) (Note 32) (Note 32) Paid in Surplus Retained Earnings AOCI (1) (Note 33) 11,040 4,377 Non- Controlling Interest Common Shares Issued (Note 5) 6,111 As at December 31, 2019 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Stock-Based Compensation Expense Base Dividends on Common Shares As at December 31, 2020 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs (2) (Note 32) Preferred Shares Issued (Note 5) Warrants Issued (Note 5) Warrants Exercised Stock-Based Compensation Expense Base Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest As at December 31, 2021 Net Earnings (Loss) Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs (2) (Note 32) Warrants Exercised Stock-Based Compensation Expense Base Dividends on Common Shares Variable Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest As at December 31, 2022 11,040 4,391 (145) — 519 (120) 17,016 519 — 215 — 4,284 170 (959) 93 (32) (1,571) (31) — — — — — — — — — — — — — — — — — — — — — — — — — — — — 216 (1) — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 7 — — 3 — — — — — — — — — — — — — — — 14 — — — — — (1) — — — 14 — — — — — — — 10 — — — — 2,957 (2,379) — (2,379) — (77) 501 587 — 587 — — — — — — — (176) (34) — 878 6,450 — 6,450 — — — — (682) (219) (35) — 6,392 Total 19,201 (2,379) (52) (2,431) 16,707 14 (77) 587 (91) 496 6,111 6 (265) 519 216 2 14 (176) (34) — 23,596 6,450 786 7,236 138 (2,530) 62 10 (682) (219) (35) — 827 — (52) (52) — — 775 — (91) (91) — — — — — — — — — — — — — — — — — — 684 — 786 786 — — — — — — — — — — — — — — — — — — — 12 12 — — — — — — — — — — 1 13 16,320 519 184 2,691 1,470 27,576 (1) (2) Accumulated other comprehensive income (loss) (“AOCI”). Normal course issuer bids (“NCIBs”). See accompanying Notes to Consolidated Financial Statements. CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, ($ millions) Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization Inventory Write-Down (Reversal) Realization of Inventory Write-Downs Deferred Income Tax Expense (Recovery) Unrealized (Gain) Loss on Risk Management Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss on Non-Operating Items Revaluation (Gains) Re-measurement of Contingent Payments, Net of Cash Paid (Gain) Loss on Divestiture of Assets Unwinding of Discount on Decommissioning Liabilities (Income) Loss From Equity-Accounted Affiliates Distributions Received From Equity-Accounted Affiliates Other Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Cash From (Used in) Operating Activities Investing Activities Acquisitions, Net of Cash Acquired Capital Investment Proceeds From Divestitures Payment on Divestiture of Assets Net Cash Received on Assumption of Decommissioning Liabilities Net Change in Investments and Other Net Change in Non-Cash Working Capital Cash From (Used in) Investing Activities Net Cash Provided (Used) Before Financing Activities Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Issuance of Long-Term Debt (Repayment) of Long-Term Debt Net Issuance (Repayment) of Revolving Long-Term Debt Principal Repayment of Leases Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIBs Proceeds From Exercise of Warrants Base Dividends Paid on Common Shares Variable Dividends Paid on Common Shares Dividends Paid on Preferred Shares Other Cash From (Used in) Financing Activities Effect of Foreign Exchange on Cash and Cash Equivalents Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year See accompanying Notes to Consolidated Financial Statements. Notes 2022 2021 2020 11,20,21,23 13 37 9 5 10 29 22 22 39 5 19,20 10 10 5 39 39 27 32 14 14 6,450 4,679 — — 642 (126) 365 146 (549) (469) (269) 176 (15) 65 (117) (150) 575 11,403 (397) (3,708) 1,514 (50) — (211) 538 (2,314) 9,089 34 — (4,149) — (302) 138 (2,530) 62 (682) (219) (26) (2) (7,676) 238 1,651 2,873 4,524 587 5,886 16 (31) 452 2 (312) 171 — 400 (229) 199 (57) 137 27 (102) (1,227) 5,919 735 (2,563) 435 — 75 17 359 (942) 4,977 (77) 1,557 (2,870) (350) (300) 6 (265) 2 (176) — (34) — (2,507) 25 2,495 378 2,873 (2,379) 3,464 555 (572) (838) 56 (131) (33) — (80) (81) 57 — — 99 (42) 198 273 — (859) 38 — — (4) (38) (863) (590) 117 1,326 (112) (220) (197) — — — (77) — — — 837 (55) 192 186 378 CENOVUS ENERGY 2022 ANNUAL REPORT | 87 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Corporate and Eliminations Corporate and Eliminations, 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, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices. A) Results of Operations – Segment and Operational Information Oil Sands 2022 2021 (1) Conventional Offshore Total 2020 2022 2021 2020 2022 2021 2020 2022 2021 (1) 2020 Upstream 34,775 22,827 8,804 4,332 3,235 2,020 1,782 — 41,127 27,844 9,708 4,493 2,196 331 298 150 77 108 — 4,868 2,454 371 30,282 20,631 8,473 4,034 3,085 1,943 1,674 — 36,259 25,390 9,337 4,810 2,404 1,262 2,023 1,655 268 — — — 6,833 4,059 1,530 For the years ended December 31, Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Risk Management (68) 18 57 — — (55) 19 57 6,365 1,104 1,235 803 1,610 1,420 — 11,824 8,588 1,299 Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on 12,036 2,930 8,625 2,451 4,683 1,156 786 268 1,527 8,979 Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity- Accounted Affiliates 2,763 2,666 1,687 9 8 16 (5) 9 — Segment Income (Loss) 6,267 3,670 (649) 143 541 92 13 370 1 — 851 74 551 2 1 3 (3) — 802 15 318 15 239 — 12,194 3,789 8,714 3,241 4,764 1,476 — — 1,619 788 268 585 91 (23) 957 492 5 (47) 970 3,718 3,161 2,567 101 18 (15) (52) 8,075 5,442 (1,416) 91 — — — — — — — — (1) Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X). 904 40 864 81 320 — 195 — 880 82 — (767) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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.”). 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 5C). The transaction included Husky's upstream assets, 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. Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. 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. 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 maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change (see Note 3X). 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, 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 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 additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value. 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. 88 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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.”). 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 5C). The transaction included Husky's upstream assets, 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. Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. 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. 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 maker. The Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on operating margin. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative periods have been re-presented to reflect this change (see Note 3X). 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, 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 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 additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export terminals and storage facilities. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity trading volumes in an effort to use its integrated network of assets to maximize value. • 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Corporate and Eliminations Corporate and Eliminations, 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, the sale of condensate extracted from blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in inventory. Eliminations are recorded based on current market prices. A) Results of Operations – Segment and Operational Information For the years ended December 31, Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity- Accounted Affiliates Oil Sands 2022 2021 (1) Upstream Conventional Offshore 2020 2022 2021 2020 2022 2021 2020 Total 2022 2021 (1) 2020 34,775 22,827 8,804 4,332 3,235 4,493 2,196 331 298 150 30,282 20,631 8,473 4,034 3,085 904 40 864 2,020 1,782 — 41,127 27,844 9,708 77 108 — 4,868 2,454 371 1,943 1,674 — 36,259 25,390 9,337 4,810 2,404 1,262 2,023 1,655 268 — — — 6,833 4,059 1,530 12,036 2,930 8,625 2,451 4,683 1,156 1,527 8,979 786 268 6,365 1,104 1,235 (68) 18 57 2,763 2,666 1,687 9 8 16 (5) 9 — 143 541 92 13 370 1 — 851 74 551 2 803 1 3 (3) 81 320 — 195 — 880 82 — 802 — (767) — 12,194 3,789 8,714 3,241 4,764 1,476 15 318 15 239 — — — — 1,619 788 268 1,610 1,420 — 11,824 8,588 1,299 — — 585 91 (23) 957 492 5 (47) 970 — — — — — (55) 19 57 3,718 3,161 2,567 101 18 (15) (52) 91 — 8,075 5,442 (1,416) Segment Income (Loss) 6,267 3,670 (649) (1) Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X). CENOVUS ENERGY 2022 ANNUAL REPORT | 89 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 For the years ended December 31, Corporate and Eliminations 2022 2021 (1) (2) Consolidated 2022 2021 (1) (2) 2020 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates Segment Income (Loss) General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payment (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Earnings (Loss) Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) (7,464) (5,291) — — (7,464) (5,291) (5,533) (664) (1,270) (3,844) (676) (783) 31 (89) 113 — — (52) 865 820 (81) 106 343 (549) 162 (269) (532) 865 101 (18) 118 — (5) (184) 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 2020 (609) — (609) (278) (36) (306) (155) 161 5 — — — 292 536 (9) 29 — (80) (81) 40 546 (181) 71,765 4,868 66,897 33,801 11,530 5,569 1,762 (126) 4,679 101 (15) 9,596 865 820 (81) 106 343 (549) 162 (269) (532) 865 8,731 2,281 6,450 48,811 2,454 46,357 23,326 8,038 4,716 993 2 5,886 18 (57) 3,435 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 1,315 728 587 13,914 371 13,543 (2,684) 5,681 4,728 1,955 252 56 3,464 91 — (181) 292 536 (9) 29 — (80) (81) 40 546 (3,230) (851) (2,379) (1) (2) Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X). Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). For the years ended December 31, Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates Segment Income (Loss) Canadian Manufacturing 2021 (1) 2022 2020 7,792 6,215 — — 7,792 6,215 6,389 5,156 — 704 — 699 — 208 — — 491 — 486 — 573 — 226 — — 347 82 — 82 — — 37 — 45 — 8 — — 37 Downstream U.S. Manufacturing 2022 2021 2020 2022 Total 2021 (1) 2020 30,310 20,043 4,733 38,102 26,258 4,815 — — — — — — 30,310 20,043 4,733 38,102 26,258 4,815 26,112 17,955 4,429 32,501 23,111 4,429 — — 2,346 1,772 112 1,740 18 640 — — 104 212 1 2,381 — — — 748 (21) (423) (1) 728 — — — 3,050 2,258 112 2,439 18 848 — — 104 785 1 2,607 — — — 785 (21) (378) (1) 736 — — 1,082 (2,170) (1,150) 1,573 (1,823) (1,113) (1) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). 90 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Canadian Manufacturing U.S. Manufacturing Total For the years ended December 31, Downstream For the years ended December 31, 2022 2021 (1) 2020 2022 2021 2020 2022 2021 (1) 2020 Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates Segment Income (Loss) 7,792 6,215 — — 7,792 6,215 30,310 20,043 4,733 38,102 26,258 4,815 — — — — — — 30,310 20,043 4,733 38,102 26,258 4,815 6,389 5,156 26,112 17,955 4,429 32,501 23,111 4,429 — 704 — 699 — 208 — — 491 — 486 — 573 — 226 — — 347 — — 2,346 1,772 112 1,740 104 212 18 640 — — 2,381 1 — — — 748 (21) (423) (1) 728 — — — 3,050 2,258 112 2,439 104 785 18 848 — — 2,607 1 — — — 785 (21) (378) (1) 736 — — 1,082 (2,170) (1,150) 1,573 (1,823) (1,113) 82 — 82 — — 37 — 45 — 8 — — 37 (1) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense (Income) Loss From Equity-Accounted Affiliates Segment Income (Loss) General and Administrative Finance Costs Interest Income Integration and Transaction Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payment (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Earnings (Loss) Before Income Tax Income Tax Expense (Recovery) Net Earnings (Loss) Corporate and Eliminations 2022 2021 (1) (2) (7,464) (5,291) — — (7,464) (5,291) (5,533) (664) (1,270) (3,844) (676) (783) 31 (89) 113 — — (52) 865 820 (81) 106 343 (549) 162 (269) (532) 865 101 (18) 118 — (5) (184) 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 2020 (609) — (609) (278) (36) (306) 5 — 161 — — (155) 292 536 (9) 29 (181) — (80) (81) 40 546 Consolidated 2021 (1) (2) 2022 71,765 4,868 66,897 33,801 11,530 5,569 1,762 (126) 4,679 101 (15) 9,596 865 820 (81) 106 343 (549) 162 (269) (532) 865 8,731 2,281 6,450 48,811 2,454 46,357 23,326 8,038 4,716 993 2 5,886 18 (57) 3,435 849 1,082 (23) 349 (174) — 575 (229) (309) 2,120 1,315 728 587 2020 13,914 371 13,543 5,681 4,728 1,955 252 56 3,464 91 — (2,684) 292 536 (9) 29 (181) — (80) (81) 40 546 (3,230) (851) (2,379) (1) (2) Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X). Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). CENOVUS ENERGY 2022 ANNUAL REPORT | 91 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 D) Assets by Segment As at December 31, Oil Sands Conventional Offshore Canadian Manufacturing (1) U.S. Manufacturing Corporate and Eliminations Consolidated As at December 31, Oil Sands Conventional Offshore Canadian Manufacturing (1) U.S. Manufacturing (3) Corporate and Eliminations (3) Consolidated E&E Assets PP&E ROU Assets 2022 674 6 5 — — — 685 2021 653 6 61 — — — 720 36,499 34,225 2022 24,657 2,020 2,549 2,466 4,482 325 Goodwill 2022 2,923 — — — — — 2021 22,535 2,174 2,822 2,558 3,745 391 2021 3,473 — — — — — 2022 638 2 152 252 329 472 1,845 2022 32,248 2,410 3,339 3,172 8,324 6,376 Total Assets 2021 754 2 160 388 252 454 2,010 2021 (2) 31,070 3,026 3,597 3,884 7,509 5,018 (1) Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels business have been aggregated with the Canadian Manufacturing segment. Total assets include assets held for sale $1.3 billion that were divested in 2022. (2) (3) and Eliminations segment. Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate 2,923 3,473 55,869 54,104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 B) Revenues by Product For the years ended December 31, Upstream Crude Oil (1) NGLs (1) Natural Gas Other Downstream Canadian Manufacturing Synthetic Crude Oil Asphalt Other Products and Services (2) U.S. Manufacturing Gasoline Diesel and Distillate Other Products Corporate and Eliminations (2) Consolidated 2022 2021 29,834 2,346 3,690 389 2,360 620 4,812 14,116 11,453 4,741 (7,464) 66,897 19,877 1,983 3,032 498 1,951 477 3,787 10,111 6,429 3,503 (5,291) 46,357 (1) (2) Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs. Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). C) Geographical Information For the years ended December 31, Canada United States China Consolidated (1) Revenues by country are classified based on where the operations are located. Revenues (1) 2021 23,768 21,326 1,263 46,357 2022 33,222 32,313 1,362 66,897 2020 8,017 727 535 58 — — 82 2,352 1,569 812 (609) 13,543 2020 8,715 4,828 — 13,543 As at December 31, Canada United States China Indonesia Consolidated Non-Current Assets (1) 2022 35,194 4,824 2,064 365 42,447 2021 (2) 33,981 4,093 2,583 311 40,968 (1) (2) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill. Canada excludes assets held for sale of $1.3 billion that were divested in 2022. Major Customers In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) 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 $16.1 billion and $9.1 billion, respectively (2021 – $8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the Company’s operating segments. 92 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 D) Assets by Segment As at December 31, Oil Sands Conventional Offshore Canadian Manufacturing (1) U.S. Manufacturing Corporate and Eliminations Consolidated As at December 31, Oil Sands Conventional Offshore Canadian Manufacturing (1) U.S. Manufacturing (3) Corporate and Eliminations (3) Consolidated E&E Assets PP&E ROU Assets 2022 674 6 5 — — — 685 2021 653 6 61 — — — 720 2022 24,657 2,020 2,549 2,466 4,482 325 2021 22,535 2,174 2,822 2,558 3,745 391 36,499 34,225 Goodwill 2022 2,923 — — — — — 2021 3,473 — — — — — 2022 638 2 152 252 329 472 1,845 Total Assets 2022 32,248 2,410 3,339 3,172 8,324 6,376 2021 754 2 160 388 252 454 2,010 2021 (2) 31,070 3,026 3,597 3,884 7,509 5,018 2,923 3,473 55,869 54,104 (1) (2) (3) Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels business have been aggregated with the Canadian Manufacturing segment. Total assets include assets held for sale $1.3 billion that were divested in 2022. Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate and Eliminations segment. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 B) Revenues by Product For the years ended December 31, 2022 2021 Upstream Crude Oil (1) NGLs (1) Natural Gas Other Downstream Canadian Manufacturing Synthetic Crude Oil Asphalt Other Products and Services (2) U.S. Manufacturing Gasoline Diesel and Distillate Other Products Corporate and Eliminations (2) Consolidated C) Geographical Information For the years ended December 31, Canada United States China Consolidated As at December 31, Canada United States China Indonesia Consolidated Major Customers 29,834 2,346 3,690 389 2,360 620 4,812 14,116 11,453 4,741 (7,464) 66,897 2022 33,222 32,313 1,362 66,897 19,877 1,983 3,032 498 1,951 477 3,787 10,111 6,429 3,503 (5,291) 46,357 2021 23,768 21,326 1,263 46,357 2022 35,194 4,824 2,064 365 42,447 Revenues (1) Non-Current Assets (1) 2020 8,017 727 535 58 — — 82 2,352 1,569 812 (609) 13,543 2020 8,715 4,828 — 13,543 2021 (2) 33,981 4,093 2,583 311 40,968 (1) (2) Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs. Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). (1) Revenues by country are classified based on where the operations are located. (1) Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in equity-accounted affiliates, precious metals, intangible assets and goodwill. (2) Canada excludes assets held for sale of $1.3 billion that were divested in 2022. In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) 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 $16.1 billion and $9.1 billion, respectively (2021 – $8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the Company’s operating segments. CENOVUS ENERGY 2022 ANNUAL REPORT | 93 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Conventional Offshore Asia Pacific Atlantic Total Upstream Canadian Manufacturing (2) U.S. Manufacturing Total Downstream Corporate and Eliminations Acquisitions (Note 5) Oil Sands (3) Conventional Offshore (4) Canadian Manufacturing (2) U.S. Manufacturing Corporate and Eliminations 2022 1,792 344 8 302 2,446 117 1,059 1,176 86 3,708 1,609 12 — — — — 2021 1,019 222 21 154 1,416 68 995 1,063 84 2,563 5,005 551 3,129 2,973 1,618 156 1,621 13,432 2020 427 78 — — 505 33 243 276 60 841 6 12 — — — — 18 Total Capital Expenditures 5,329 15,995 859 (1) (2) (3) (4) Includes expenditures on PP&E, E&E assets and capitalized interest. Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre- existing interest in SOSP of $1.6 billion. Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method. 94 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 IFRS as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee. 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 15, 2023. 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 Statements of Earnings (Loss). C) Revenue Recognition 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 reporting date. Any gains or losses are recorded in the Consolidated 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Conventional Offshore Asia Pacific Atlantic Total Upstream Canadian Manufacturing (2) U.S. Manufacturing Total Downstream Corporate and Eliminations Acquisitions (Note 5) Oil Sands (3) Conventional Offshore (4) Canadian Manufacturing (2) U.S. Manufacturing Corporate and Eliminations 2022 1,792 344 8 302 2,446 117 1,059 1,176 86 3,708 1,609 12 — — — — 2021 1,019 222 21 154 1,416 68 995 1,063 84 2,563 5,005 551 3,129 2,973 1,618 156 1,621 13,432 2020 427 78 — — 505 33 243 276 60 841 6 12 — — — — 18 Total Capital Expenditures 5,329 15,995 859 (1) (2) (3) Includes expenditures on PP&E, E&E assets and capitalized interest. Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X). Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre- existing interest in SOSP of $1.6 billion. (4) Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 IFRS as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee. 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 15, 2023. 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 reporting 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 2022 ANNUAL REPORT | 95 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Cenovus recognizes revenue from the following major products and services: Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: • • • • • • 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 the storage of crude oil, diluent and natural gas. Fee-for-service hydrocarbon transloading 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 transloading 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 transloading 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) Purchased Product The cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market are recorded as purchased product. E) Transportation and Blending The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold. F) 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. G) 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. 96 | CENOVUS ENERGY 2022 ANNUAL REPORT 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. • Re-measurements, 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. Re-measurements 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. H) 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. I) Income Taxes Sheet date. 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 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. J) 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. K) 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 • • • • • • Sale of crude oil, NGLs and natural gas. Sale of petroleum and refined products. Crude oil and natural gas processing services. Fee-for-service hydrocarbon transloading services. Construction services. Pipeline transportation, the blending of crude oil and the storage of crude oil, diluent and natural gas. 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 transloading 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 transloading 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. The cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting refined products to market are recorded as purchased product. The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of diluent used in blending, are recognized when the product is sold. 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. The Company provides employees with a pension plan that includes either a defined contribution or defined benefit 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. D) Purchased Product E) Transportation and Blending F) Exploration Expense incurred as exploration expense. G) Employee Benefit Plans component. Cenovus recognizes revenue from the following major products and services: Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 • • • 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. Re-measurements, 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. Re-measurements 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. H) 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. I) 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. Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are J) 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. K) 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 97 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 L) 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. 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. M) 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. N) 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. annually. Any gains or losses from the divestiture of E&E assets are recognized in net earnings. O) 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 enhancements 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 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 and upgrading 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, Commercial Fuels Business 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 The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a for use by the Company. prospective basis, if appropriate. P) 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 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. 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. 98 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 L) Cash and Cash Equivalents maturity of three months or less. be used within twelve months, it is classified as a non-current asset. M) Inventories Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a 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. N) 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. O) 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 enhancements 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 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. Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to Manufacturing Assets NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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. 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 and upgrading 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, Commercial Fuels Business 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. P) 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. 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 99 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Q) 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 re-measured 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 re-measured, 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 re-measurements 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 re-measure 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. 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. 100 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 R) 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. Impairment losses are recognized in the Consolidated Statements of Earnings(Loss) as DD&A. S) 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. any accumulated impairment losses. At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less 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. T) Provisions 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). Renewable Fuel Obligations The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Q) Leases As Lessee term. 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. 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 The lease liability is measured at amortized cost using the effective interest method. It is re-measured 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 re-measured, 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 re-measurements 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 re-measure 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. 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 R) 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. Impairment losses are recognized in the Consolidated Statements of Earnings(Loss) as DD&A. S) 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. T) Provisions 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). Renewable Fuel Obligations The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. CENOVUS ENERGY 2022 ANNUAL REPORT | 101 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 U) 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. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative. 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. V) 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. W) 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 payments, 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. 102 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 re-measured based on the new cash flows and a gain or loss is recorded in net earnings. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 U) 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. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common shares shall apply. The preferred share dividends are cumulative. 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. V) 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. W) 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 payments, 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 re-measured based on the new cash flows and a gain or loss is recorded in net earnings. CENOVUS ENERGY 2022 ANNUAL REPORT | 103 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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. X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and Corporate and Eliminations segment was revised. During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows. The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts: Year Ended December 31, 2021 Oil Sands Segment Purchased Product Transportation and Blending Canadian Manufacturing Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Retail Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Previously Reported 3,188 7,841 11,029 Previously Reported 4,472 3,552 388 167 365 Revisions (784) 784 — Revisions — — — — — Segment Aggregation — — — Segment Aggregation 1,743 1,604 98 59 (18) Previously Reported Revisions Segment Aggregation 2,158 2,019 98 59 (18) — — — — — (2,158) (2,019) (98) (59) 18 Revised 2,404 8,625 11,029 Revised 6,215 5,156 486 226 347 Revised — — — — — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Consolidated Purchased Product Transportation and Blending Previously Reported (5,706) (4,888) (47) (771) Previously Reported 23,481 7,883 31,364 Revisions Aggregation Segment Segment Revision Aggregation — 629 (629) — (155) 155 — 415 415 — — — — — Revised (5,291) (3,844) (676) (771) Revised 23,326 8,038 31,364 Y) 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, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business. 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. The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities: Joint Arrangements • WRB Refining LP (“WRB”). • BP-Husky Refining LLC (“Toledo”). It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August 31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, SOSP was consolidated. 104 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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. X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures Corporate and Eliminations segment was revised. During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows. The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the corresponding revised amounts: Year Ended December 31, 2021 Oil Sands Segment Purchased Product Transportation and Blending Canadian Manufacturing Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Retail Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Previously Reported 3,188 7,841 11,029 Previously Reported Previously Reported 4,472 3,552 388 167 365 2,158 2,019 98 59 (18) Revisions Aggregation Segment Revisions Aggregation Segment (784) 784 — — — — — — — — — — — — — — 1,743 1,604 98 59 (18) Segment (2,158) (2,019) (98) (59) 18 Revised 2,404 8,625 11,029 Revised 6,215 5,156 486 226 347 — — — — — Revisions Aggregation Revised NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Consolidated Purchased Product Transportation and Blending Previously Reported (5,706) (4,888) (47) (771) Previously Reported 23,481 7,883 31,364 Revisions — 629 (629) — Revision (155) 155 — Segment Aggregation 415 415 — — Segment Aggregation — — — Revised (5,291) (3,844) (676) (771) Revised 23,326 8,038 31,364 Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and Y) 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, 2023, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the Company’s Consolidated Financial Statements or the Company's business. 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. Joint Arrangements The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires judgment. Cenovus has a 50 percent interest in the following jointly controlled entities: • WRB Refining LP (“WRB”). • BP-Husky Refining LLC (“Toledo”). It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August 31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, SOSP was consolidated. CENOVUS ENERGY 2022 ANNUAL REPORT | 105 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 In determining the classification of its joint arrangements under IFRS 11, the Company considered the following: Crude Oil and Natural Gas Reserves • • 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 development of SOSP, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans. • WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt • • • facility until November 2022. SOSP was 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. B) Key Sources of Estimation Uncertainty Income Tax Provisions 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. 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. 106 | CENOVUS ENERGY 2022 ANNUAL REPORT 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 value of the related assets. Decommissioning Costs 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, 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 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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. 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. • • • • 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 development of SOSP, and the past and future development of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans. facility until November 2022. • WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt SOSP was 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. 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. 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 In determining the classification of its joint arrangements under IFRS 11, the Company considered the following: 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, 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. 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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. B) Key Sources of Estimation Uncertainty 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 2022 ANNUAL REPORT | 107 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 5. ACQUISITIONS A) Sunrise Oil Sands Partnership i) Summary of the Acquisition On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP, previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands. The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill. ii) Identifiable Assets Acquired and Liabilities Acquired The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on decommissioning liabilities) as a result of the measurement period adjustments was not material. As at 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed August 31, 2022 Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities Cash Accounts Receivable and Accrued Revenues Inventories Property, Plant and Equipment Accounts Payable and Accrued Liabilities Income Tax Payable Decommissioning Liabilities Deferred Income Tax Liabilities Total Identifiable Net Assets 9 164 88 3,218 (313) (39) (48) (486) 2,593 The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which was collected. v) Revenue and Profit Contribution iii) Total Consideration Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value of total consideration: As at Cash, Net of Closing Adjustments Bay Du Nord Variable Payment Total Consideration August 31, 2022 The consequential tax effects. 394 40 600 1,034 Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated fair value and recognized a non-cash revaluation gain of $40 million. 108 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the contract term is $600 million. The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28). Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership iv) Goodwill As at Total Purchase Consideration Fair Value of Identifiable Net Assets Goodwill assumed, and their tax basis. August 31, 2022 1,034 1,559 (2,593) — Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value. The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively. These amounts have been calculated using results from the acquired business, adjusting them for: Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022. This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition January 1, 2022. • • • had actually occurred on January 1, 2022. B) BP-Husky Refining LLC On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the “Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of February 2023. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 5. ACQUISITIONS A) Sunrise Oil Sands Partnership i) Summary of the Acquisition On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP, previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands. The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is recorded as goodwill. ii) Identifiable Assets Acquired and Liabilities Acquired The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on decommissioning liabilities) as a result of the measurement period adjustments was not material. 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed As at Cash Accounts Receivable and Accrued Revenues Inventories Property, Plant and Equipment Accounts Payable and Accrued Liabilities Income Tax Payable Decommissioning Liabilities Deferred Income Tax Liabilities Total Identifiable Net Assets was collected. iii) Total Consideration of total consideration: As at Cash, Net of Closing Adjustments Bay Du Nord Variable Payment Total Consideration The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s 35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated fair value and recognized a non-cash revaluation gain of $40 million. August 31, 2022 9 164 88 3,218 (313) (39) (48) (486) 2,593 August 31, 2022 394 40 600 1,034 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the contract term is $600 million. The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28). iv) Goodwill As at Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership Fair Value of Identifiable Net Assets Goodwill August 31, 2022 1,034 1,559 (2,593) — Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities assumed, and their tax basis. Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value. v) Revenue and Profit Contribution The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively. These amounts have been calculated using results from the acquired business, adjusting them for: • • • Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from January 1, 2022. Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022. The consequential tax effects. This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition had actually occurred on January 1, 2022. B) BP-Husky Refining LLC On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the “Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of February 2023. CENOVUS ENERGY 2022 ANNUAL REPORT | 109 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 C) Husky Energy Inc. On January 1, 2021, Cenovus and Husky closed the Arrangement. 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 Consideration Common Shares Preferred Shares Share Purchase Warrants Replacement Stock Options Other Non-Controlling Interest Total Consideration and Non-Controlling Interest Identifiable Assets Acquired and Liabilities Assumed Cash Restricted Cash Accounts Receivable and Accrued Revenues Inventories Exploration and Evaluation Assets Property, Plant and Equipment Right-of-Use Assets Long-Term Income Tax Receivable Other Assets Investment in Equity-Accounted Affiliates Deferred Income Tax Assets, Net Accounts Payable and Accrued Liabilities Income Tax Payable Short-Term Borrowings Long-Term Debt Lease Liabilities Decommissioning Liabilities Other Liabilities Total Identifiable Net Assets Goodwill January 1, 2021 6,111 519 216 9 17 11 6,883 735 164 1,307 1,133 45 13,296 1,132 66 230 363 1,062 (2,283) (94) (40) (6,602) (1,441) (2,697) (782) 5,594 1,289 Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million; and the Tucker asset of $88 million, within the Oil Sands segment. D) Terra Nova 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 6. GENERAL AND ADMINISTRATIVE For the years ended December 31, Salaries and Benefits Administrative and Other Stock-Based Compensation Expense (Recovery) (Note 34) Other Incentive Benefits Expense (Recovery) 7. FINANCE COSTS For the years ended December 31, Interest Expense – Short-Term Borrowings and Long-Term Debt Net Premium (Discount) on Redemption of Long-Term Debt (1) Interest Expense – Lease Liabilities (Note 27) Unwinding of Discount on Decommissioning Liabilities (Note 29) Other Capitalized Interest 9. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada Other Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2022 204 297 373 (9) 865 2022 478 (29) 163 176 37 825 (5) 820 2022 365 — 365 (22) 343 2021 264 225 159 201 849 2021 557 121 171 199 34 1,082 — 1,082 2021 (230) (82) (312) 138 (174) 2020 145 102 49 (4) 292 2020 392 (25) 87 57 25 536 — 536 2020 (194) 63 (131) (50) (181) (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. 8. INTEGRATION AND TRANSACTION COSTS Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022 (2021 – $349 million; 2020 – $29 million). Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with the Sunrise Acquisition and the pending Toledo Acquisition. 110 | CENOVUS ENERGY 2022 ANNUAL REPORT On January 1, 2021, Cenovus and Husky closed the Arrangement. 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. January 1, 2021 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 C) Husky Energy Inc. As at Consideration Common Shares Preferred Shares Share Purchase Warrants Replacement Stock Options Other Non-Controlling Interest Total Consideration and Non-Controlling Interest Identifiable Assets Acquired and Liabilities Assumed Cash Restricted Cash Inventories Accounts Receivable and Accrued Revenues Exploration and Evaluation Assets Property, Plant and Equipment Right-of-Use Assets Long-Term Income Tax Receivable Other Assets Investment in Equity-Accounted Affiliates Deferred Income Tax Assets, Net Accounts Payable and Accrued Liabilities Income Tax Payable Short-Term Borrowings Long-Term Debt Lease Liabilities Decommissioning Liabilities Other Liabilities Total Identifiable Net Assets Goodwill D) Terra Nova Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million; and the Tucker asset of $88 million, within the Oil Sands segment. 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. 6,111 519 216 9 17 11 6,883 735 164 1,307 1,133 45 13,296 1,132 66 230 363 1,062 (2,283) (94) (40) (6,602) (1,441) (2,697) (782) 5,594 1,289 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 6. GENERAL AND ADMINISTRATIVE For the years ended December 31, Salaries and Benefits Administrative and Other Stock-Based Compensation Expense (Recovery) (Note 34) Other Incentive Benefits Expense (Recovery) 7. FINANCE COSTS For the years ended December 31, Interest Expense – Short-Term Borrowings and Long-Term Debt Net Premium (Discount) on Redemption of Long-Term Debt (1) Interest Expense – Lease Liabilities (Note 27) Unwinding of Discount on Decommissioning Liabilities (Note 29) Other Capitalized Interest 2022 204 297 373 (9) 865 2022 478 (29) 163 176 37 825 (5) 820 2021 264 225 159 201 849 2021 557 121 171 199 34 1,082 — 1,082 2020 145 102 49 (4) 292 2020 392 (25) 87 57 25 536 — 536 (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. 8. INTEGRATION AND TRANSACTION COSTS Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022 (2021 – $349 million; 2020 – $29 million). Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with the Sunrise Acquisition and the pending Toledo Acquisition. 9. FOREIGN EXCHANGE (GAIN) LOSS, NET For the years ended December 31, Unrealized Foreign Exchange (Gain) Loss on Translation of: U.S. Dollar Debt Issued From Canada Other Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2022 365 — 365 (22) 343 2021 (230) (82) (312) 138 (174) 2020 (194) 63 (131) (50) (181) CENOVUS ENERGY 2022 ANNUAL REPORT | 111 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 10. DIVESTITURES A) 2022 Divestitures On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million and recorded a before-tax gain of $165 million (after-tax gain – $126 million). On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of $221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million). In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting in a before-tax gain of $62 million (after-tax gain – $47 million). On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million, with no gain or loss recognized as the investment was recorded at fair value prior to the sale. On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss – $56 million). B) 2021 Divestitures Effective May 1, 2021, the Company closed the sale of 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). The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain – $13 million) was recorded on the dispositions. In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million). C) 2020 Divestitures 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. 11. IMPAIRMENT CHARGES AND REVERSALS At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed the 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. For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. A) Upstream Cash-Generating Units i) 2022 Impairment Charges and Reversals The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. 112 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs. Crude Oil, NGLs and Natural Gas Prices were: The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Condensate at Edmonton (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) 2023 80.33 76.54 106.22 4.23 2024 78.50 77.75 101.35 4.40 2025 76.95 77.55 98.94 4.21 2026 77.61 80.07 100.19 4.27 2027 79.16 81.89 101.74 4.34 (1) Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”). Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs with associated goodwill. ii) 2021 Impairment Charges and Reversals As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. 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, Discount Rates Sensitivities 2021, by CGU: Clearwater Elmworth-Wapiti Kaybob-Edson Reversal of Impairment Recoverable Amount 145 115 118 427 747 837 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 10. DIVESTITURES A) 2022 Divestitures On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million and recorded a before-tax gain of $165 million (after-tax gain – $126 million). On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of $221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million). In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting in a before-tax gain of $62 million (after-tax gain – $47 million). On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million, with no gain or loss recognized as the investment was recorded at fair value prior to the sale. On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss – $56 million). B) 2021 Divestitures $47 million). C) 2020 Divestitures $13 million) was recorded on the dispositions. In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million). 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. 11. IMPAIRMENT CHARGES AND REVERSALS At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest the carrying amount may exceed the 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. For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. A) Upstream Cash-Generating Units i) 2022 Impairment Charges and Reversals The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs. Crude Oil, NGLs and Natural Gas Prices The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Condensate at Edmonton (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) 2023 80.33 76.54 106.22 4.23 2024 78.50 77.75 101.35 4.40 2025 76.95 77.55 98.94 4.21 2026 77.61 80.07 100.19 4.27 2027 79.16 81.89 101.74 4.34 (1) Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”). Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Effective May 1, 2021, the Company closed the sale of 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 – Discount Rates Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the individual characteristics of the CGU, and other economic and operating factors. The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain – Sensitivities For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs with associated goodwill. ii) 2021 Impairment Charges and Reversals As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. 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: Clearwater Elmworth-Wapiti Kaybob-Edson Reversal of Impairment Recoverable Amount 145 115 118 427 747 837 CENOVUS ENERGY 2022 ANNUAL REPORT | 113 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 included forward prices and costs, consistent with Cenovus’s IQREs, costs to develop and the discount rates. 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 were 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: West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Edmonton C5+ (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) 2022 72.83 74.43 91.85 3.56 2023 68.78 69.17 85.53 3.20 2024 66.76 66.54 82.98 3.05 2025 68.09 67.87 84.63 3.10 2026 69.45 69.23 86.33 3.17 (1) Assumes natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf"). Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Discount 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. Sensitivities A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021. A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill. iii) 2020 Impairment Charges and Reversals As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of $240 million in the Conventional CGU due to a change in future development plans. The following table summarizes December 31, 2020, by CGU: impairment losses recorded in 2020 and estimated recoverable amounts as at Clearwater Elmworth-Wapiti Kaybob-Edson Key Assumptions Impairment 260 120 175 Recoverable Amount 160 259 384 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 included 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. 114 | CENOVUS ENERGY 2022 ANNUAL REPORT Discount Rates Sensitivities CGUs: Clearwater Elmworth-Wapiti Kaybob-Edson NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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: West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Edmonton C5+ (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) (1) Assumes gas heating value of one million British thermal units per Mcf. 2021 47.17 44.63 59.24 2.88 2022 50.17 48.18 63.19 2.80 2023 53.17 52.10 67.34 2.71 2024 54.97 54.10 69.77 2.75 2025 56.07 55.19 71.18 2.80 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. The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had on the calculated impairment amount used in the impairment testing completed as at December 31, 2020, for the following Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Increase (Decrease) to Impairment Amount One Percent Increase in the Discount One Percent Decrease in the Discount Five Percent Five Percent Increase in the Decrease in the Forward Price Forward Price Estimates Estimates Rate 7 10 17 Rate (7) (10) (19) (68) (71) (71) 128 126 140 A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill. B) Downstream Cash-Generating Units i) 2022 Impairment Charges and Reversals As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December 31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion. impairment been recorded. Key Assumptions The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. 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, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 included forward prices and costs, consistent with Cenovus’s IQREs, costs to develop and the discount rates. 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 were 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 Thereafter 2.00 % 2.00 % 2.00 % 2.00 % West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Edmonton C5+ (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) 2022 72.83 74.43 91.85 3.56 2023 68.78 69.17 85.53 3.20 2024 66.76 66.54 82.98 3.05 2025 68.09 67.87 84.63 3.10 2026 69.45 69.23 86.33 3.17 (1) Assumes natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf"). 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. A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021. A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill. iii) 2020 Impairment Charges and Reversals As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of $240 million in the Conventional CGU due to a change in future development plans. The following table summarizes impairment losses recorded in 2020 and estimated recoverable amounts as at December 31, 2020, by CGU: Discount Rates Sensitivities Clearwater Elmworth-Wapiti Kaybob-Edson Key Assumptions Impairment Recoverable Amount 260 120 175 160 259 384 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 included 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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: West Texas Intermediate (US$/barrel) Western Canadian Select (C$/barrel) Edmonton C5+ (C$/barrel) Alberta Energy Company Natural Gas (C$/Mcf) (1) 2021 47.17 44.63 59.24 2.88 2022 50.17 48.18 63.19 2.80 2023 53.17 52.10 67.34 2.71 2024 54.97 54.10 69.77 2.75 2025 56.07 55.19 71.18 2.80 (1) Assumes gas heating value of one million British thermal units per Mcf. Discount Rates Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % 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. 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 impairment amount used in the impairment testing completed as at December 31, 2020, for the following CGUs: Clearwater Elmworth-Wapiti Kaybob-Edson Increase (Decrease) to Impairment Amount One Percent Increase in the Discount Rate 7 10 17 One Percent Decrease in the Discount Rate (7) Five Percent Increase in the Forward Price Estimates (68) (10) (19) (71) (71) Five Percent Decrease in the Forward Price Estimates 128 126 140 A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the results of the impairment tests performed on CGUs with associated goodwill. B) Downstream Cash-Generating Units i) 2022 Impairment Charges and Reversals As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December 31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no impairment been recorded. As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion. Key Assumptions The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. 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, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts. CENOVUS ENERGY 2022 ANNUAL REPORT | 115 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Crude Oil and Crack Spreads NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Crude Oil and Crack Spreads Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: 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: (US$/barrel) West Texas Intermediate Differential WTI-WTS Differential WTI-WCS Chicago 3-2-1 Crack Spreads (WTI) 2023 80.33 (0.56) (23.32) 29.37 2024 78.50 (0.56) (19.09) 24.10 2025 76.95 (0.56) (17.42) 22.12 2026 77.61 (0.56) (15.87) 21.70 2027 79.16 (0.56) (15.74) 21.67 Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032. Discount Rates Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 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 crude oil and crack spreads would have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs: Increase (Decrease) to Impairment Amount One Percent Increase in the Discount Rate 69 One Percent Decrease in the Discount Rate (65) Five Percent Increase in the Forward Price Estimates (268) Five Percent Decrease in the Forward Price Estimates 268 Increase (Decrease) to Impairment Reversal Amount One Percent Increase in the Discount Rate (72) One Percent Decrease in the Discount Rate 14 Five Percent Increase in the Forward Price Estimates 168 Five Percent Decrease in the Forward Price Estimates (342) U.S. Manufacturing U.S. Manufacturing ii) 2021 Impairment Charges and Reversals As at December 31, 2021, lower forward pricing that would result in lower margins for 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 of $2.5 billion. An impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was no impairment of the Toledo CGU. Key Assumptions The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party consultant forecasts. 116 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 to 2023 2024 to 2026 Low 68.78 — 13.54 14.87 High 72.83 0.01 13.67 18.44 Low 66.76 (0.06) 13.75 14.68 High 69.45 (0.06) 14.30 16.81 (US$/barrel) West Texas Intermediate Differential WTI-WTS Differential WTI-WCS Chicago 3-2-1 Crack Spreads (WTI) Discount Rates Sensitivities following CGUs: Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037. 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. The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the Increase (Decrease) to Impairment Amount One Percent Increase in the Discount One Percent Decrease in the Discount Five Percent Five Percent Increase in the Decrease in the Forward Price Forward Price Rate 251 Rate (283) Estimates (990) Estimates 996 Borger, Wood River and Lima iii) 2020 Impairment Charges and Reversals 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 $692 million. As at September 30, 2020, no impairment of the Wood River CGU The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts. Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were: 2021 to 2022 2023 to 2025 Low 36.36 0.37 11.56 High 50.84 1.73 13.23 Low 49.66 1.21 11.79 High 58.74 1.81 16.58 Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035. Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics of the CGU, and other economic and operating factors. was identified. Key Assumptions Crude Oil and Crack Spreads (US$/barrel) West Texas Intermediate Differential WTI-WTS Group 3 3-2-1 Crack Spreads (WTI) Discount Rates NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Crude Oil and Crack Spreads NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Crude Oil and Crack Spreads Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: 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: (US$/barrel) West Texas Intermediate Differential WTI-WTS Differential WTI-WCS Chicago 3-2-1 Crack Spreads (WTI) 2023 80.33 (0.56) (23.32) 29.37 2024 78.50 (0.56) (19.09) 24.10 2025 76.95 (0.56) (17.42) 22.12 2026 77.61 (0.56) (15.87) 21.70 2027 79.16 (0.56) (15.74) 21.67 Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032. Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 percent based on the individual characteristics of the CGU, and other economic and operating factors. The sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs: Discount Rates Sensitivities U.S. Manufacturing Increase (Decrease) to Impairment Amount One Percent Increase in the Discount One Percent Decrease in the Discount Five Percent Five Percent Increase in the Decrease in the Forward Price Forward Price Rate (65) Estimates (268) Estimates 268 Increase (Decrease) to Impairment Reversal Amount One Percent Increase in the Discount One Percent Decrease in the Discount Five Percent Five Percent Increase in the Decrease in the Forward Price Forward Price Rate 14 Estimates 168 Estimates (342) Rate 69 Rate (72) U.S. Manufacturing ii) 2021 Impairment Charges and Reversals no impairment of the Toledo CGU. Key Assumptions As at December 31, 2021, lower forward pricing that would result in lower margins for 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 of $2.5 billion. An impairment charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party consultant forecasts. (US$/barrel) West Texas Intermediate Differential WTI-WTS Differential WTI-WCS Chicago 3-2-1 Crack Spreads (WTI) 2022 to 2023 2024 to 2026 Low 68.78 — 13.54 14.87 High 72.83 0.01 13.67 18.44 Low 66.76 (0.06) 13.75 14.68 High 69.45 (0.06) 14.30 16.81 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 crude oil and crack spreads 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 Impairment Amount One Percent Increase in the Discount Rate 251 One Percent Decrease in the Discount Rate (283) Five Percent Increase in the Forward Price Estimates (990) Five Percent Decrease in the Forward Price Estimates 996 Borger, Wood River and Lima iii) 2020 Impairment Charges and Reversals 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 $692 million. As at September 30, 2020, no impairment of the Wood River CGU was identified. Key Assumptions The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts. Crude Oil and Crack Spreads Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020, the forward prices used to determine future cash flows were: (US$/barrel) West Texas Intermediate Differential WTI-WTS Group 3 3-2-1 Crack Spreads (WTI) 2021 to 2022 2023 to 2025 Low 36.36 0.37 11.56 High 50.84 1.73 13.23 Low 49.66 1.21 11.79 High 58.74 1.81 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 117 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 Impairment Amount One Percent Increase in the Discount Rate 89 One Percent Decrease in the Discount Rate (110) Five Percent Increase in the Forward Price Estimates Five Percent Decrease in the Forward Price Estimates (348) 342 Borger 12. OTHER INCOME (LOSS), NET For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil). For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 For the years ended December 31, Earnings (Loss) From Operations Before Income Tax Canadian Statutory Rate Expected Income Tax Expense (Recovery) From Operations Effect on Taxes Resulting From: Statutory and Other Rate Differences Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings U.S. Tax Attribute Limitation Impact of Rate Changes Other Total Tax Expense (Recovery) From Operations Effective Tax Rate B) Deferred Income Tax Assets and Liabilities 13. INCOME TAXES A) Income Tax Expense (Recovery) For the years ended December 31, Current Tax Canada United States Asia Pacific Other International Total Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) 2022 1,252 104 262 21 1,639 642 2,281 2021 104 — 171 1 276 452 728 2020 (14) 1 — — (13) (838) (851) For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income. 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 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. 118 | CENOVUS ENERGY 2022 ANNUAL REPORT The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: 2022 8,731 23.7% 2,069 17 84 84 15 — — 12 2,281 26.1 % 55.4 % 2021 1,315 23.7% 312 3 63 27 (5) 217 106 5 728 2022 55 4,460 4,515 (31) (747) (778) 3,737 22 75 — 97 — 44 (53) 2020 (3,230) 24.0% (775) 19 (42) (42) (8) — (7) 4 (851) 26.3 % 2021 — 4,046 4,046 (556) (898) (1,454) 2,592 Total 4,146 (159) 59 4,046 (17) 486 4,515 Management Other PP&E 4,124 (234) 59 3,949 25 486 4,460 Risk — — — — 11 — 11 For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the liabilities assumed, and their tax basis. On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S. operations, offset by a deferred 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, Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within Twelve Months Deferred Income Tax Liabilities to be Settled After More Than Twelve Months Deferred Income Tax Assets Deferred Income Tax Assets to be Settled Within Twelve Months Deferred Income Tax Assets to be Settled After More Than Twelve Months Net Deferred Income Tax Liability year. the same tax jurisdiction, is: Deferred Income Tax Liabilities As at December 31, 2020 Charged (Credited) to Earnings As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation Charged (Credited) to Sunrise Purchase Price Allocation As at December 31, 2022 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 The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within Sensitivities CGU: Borger gas sites. 13. INCOME TAXES A) Income Tax Expense (Recovery) For the years ended December 31, Current Tax Canada United States Asia Pacific Other International Total Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) 2022 1,252 104 262 21 1,639 642 2,281 2021 104 — 171 1 276 452 728 2020 (14) 1 — — (13) (838) (851) For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate taxable income and losses available to offset that taxable income. 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 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: 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 Increase (Decrease) to Impairment Amount One Percent Increase in the Discount One Percent Decrease in the Discount Five Percent Five Percent Increase in the Decrease in the Forward Price Forward Price Rate 89 Rate (110) Estimates (348) Estimates 342 12. OTHER INCOME (LOSS), NET For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil). For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and For the years ended December 31, Earnings (Loss) From Operations Before Income Tax Canadian Statutory Rate Expected Income Tax Expense (Recovery) From Operations Effect on Taxes Resulting From: Statutory and Other Rate Differences Non-Taxable Capital (Gains) Losses Non-Recognition of Capital (Gains) Losses Adjustments Arising From Prior Year Tax Filings U.S. Tax Attribute Limitation Impact of Rate Changes Other Total Tax Expense (Recovery) From Operations Effective Tax Rate B) Deferred Income Tax Assets and Liabilities 2022 8,731 23.7% 2,069 17 84 84 15 — — 12 2,281 26.1 % 2021 1,315 23.7% 312 3 63 27 (5) 217 106 5 728 55.4 % 2020 (3,230) 24.0% (775) 19 (42) (42) (8) — (7) 4 (851) 26.3 % For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the liabilities assumed, and their tax basis. On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S. operations, offset by a deferred 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, Deferred Income Tax Liabilities Deferred Income Tax Liabilities to be Settled Within Twelve Months Deferred Income Tax Liabilities to be Settled After More Than Twelve Months Deferred Income Tax Assets Deferred Income Tax Assets to be Settled Within Twelve Months Deferred Income Tax Assets to be Settled After More Than Twelve Months Net Deferred Income Tax Liability 2022 55 4,460 4,515 (31) (747) (778) 3,737 2021 — 4,046 4,046 (556) (898) (1,454) 2,592 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 As at December 31, 2020 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation As at December 31, 2022 PP&E 4,124 (234) 59 3,949 25 486 4,460 Risk Management — — — — 11 — 11 Other 22 75 — 97 (53) — 44 Total 4,146 (159) 59 4,046 (17) 486 4,515 CENOVUS ENERGY 2022 ANNUAL REPORT | 119 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Deferred Income Tax Assets As at December 31, 2020 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2022 Net Deferred Income Tax Liabilities As at December 31, 2020 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2022 Unused Tax Losses Risk Management (659) 668 (656) (8) (655) 490 — 9 (156) (13) 1 1 — (11) 11 — — — Other (276) (58) (466) 12 (788) 158 — 8 (622) Total (948) 611 (1,121) 4 (1,454) 659 — 17 (778) Total 3,198 452 (1,062) 4 2,592 642 486 17 3,737 The deferred income tax asset of $546 million (2021 – $694 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 forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2022 and 2021 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. C) Tax Pools The approximate amounts of tax pools available, including tax losses, are: As at December 31, Canada United States Asia Pacific 2022 8,505 6,477 457 15,439 2021 11,167 5,915 600 17,682 As at December 31, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no earlier than 2035. As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 – $102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 14. PER SHARE AMOUNTS A) Net Earnings (Loss) Per Common Share – Basic and Diluted For the years ended December 31, Net Earnings (Loss) Effect of Cumulative Dividends on Preferred Shares Net Earnings (Loss) – Basic and Diluted Basic – Weighted Average Number of Shares Dilutive Effect of Warrants Dilutive Effect of Net Settlement Rights Diluted – Weighted Average Number of Shares Net Earnings (Loss) Per Common Share – Basic ($) Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2022 6,450 (35) 6,415 44.8 10.0 3.29 3.20 1,951.3 2,016.2 1,228.9 2,006.1 2,045.1 1,228.9 2021 587 (34) 553 27.6 1.3 0.27 0.27 12 7 1 9 6 35 2020 (2,379) — (2,379) — — (1.94) (1.94) 77 — 77 12 7 1 9 5 34 (1) For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020 – nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share. For further information on the Company’s stock-based compensation plans, see Note 34. (2) For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, 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 For the years ended December 31, Per Share Amount Per Share Amount Per Share Amount 2022 2021 2020 0.350 0.114 0.464 682 219 901 0.088 — 0.088 176 — 176 0.063 — 0.063 The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023. 2022 2021 shares. B) Common Share Dividends Total Common Share Dividends Declared and Paid Base Dividends Variable Dividends quarterly. C) Preferred Share Dividends For the years ended December 31, Series 1 First Preferred Shares Series 2 First Preferred Shares Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Total Preferred Share Dividends Declared quarterly. The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022. On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023. 120 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Deferred Income Tax Assets As at December 31, 2020 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2022 Net Deferred Income Tax Liabilities As at December 31, 2020 Charged (Credited) to Earnings Charged (Credited) to Husky Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation Charged (Credited) to Other Comprehensive Income As at December 31, 2022 C) Tax Pools As at December 31, Canada United States Asia Pacific earlier than 2035. Unused Tax Losses Management Risk (13) (11) 1 1 — 11 — — — Other (276) (58) (466) 12 (788) 158 — 8 (622) (659) 668 (656) (8) (655) 490 — 9 (156) Total (948) 611 (1,121) 4 (1,454) 659 — 17 (778) Total 3,198 452 (1,062) 4 2,592 642 486 17 3,737 2022 8,505 6,477 457 15,439 2021 11,167 5,915 600 17,682 The deferred income tax asset of $546 million (2021 – $694 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 forecasted taxable income. No deferred tax liability has been recognized as at December 31, 2022 and 2021 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, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 – $102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 14. PER SHARE AMOUNTS A) Net Earnings (Loss) Per Common Share – Basic and Diluted For the years ended December 31, Net Earnings (Loss) Effect of Cumulative Dividends on Preferred Shares Net Earnings (Loss) – Basic and Diluted Basic – Weighted Average Number of Shares Dilutive Effect of Warrants Dilutive Effect of Net Settlement Rights Diluted – Weighted Average Number of Shares Net Earnings (Loss) Per Common Share – Basic ($) Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2022 6,450 (35) 6,415 2021 587 (34) 553 2020 (2,379) — (2,379) 1,951.3 2,016.2 1,228.9 44.8 10.0 27.6 1.3 — — 2,006.1 2,045.1 1,228.9 3.29 3.20 0.27 0.27 (1.94) (1.94) (1) (2) For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020 – nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share. For further information on the Company’s stock-based compensation plans, see Note 34. For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, 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 years ended December 31, Per Share Amount Per Share Amount Per Share Amount Base Dividends Variable Dividends Total Common Share Dividends Declared and Paid 0.350 0.114 0.464 682 219 901 0.088 — 0.088 176 — 176 0.063 — 0.063 77 — 77 2022 2021 2020 The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common shareholders of record as at March 15, 2023. C) Preferred Share Dividends For the years ended December 31, Series 1 First Preferred Shares Series 2 First Preferred Shares Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Total Preferred Share Dividends Declared 2022 2021 7 1 12 9 6 35 7 1 12 9 5 34 The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022. On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares, payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023. CENOVUS ENERGY 2022 ANNUAL REPORT | 121 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 15. CASH AND CASH EQUIVALENTS As at December 31, Cash Short-Term Investments 16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES As at December 31, Trade and Accruals Prepaids and Deposits Partner Advances Joint Operations Receivables Other (1) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 19. EXPLORATION AND EVALUATION ASSETS, NET As at December 31, 2020 Acquisitions (Note 5) Additions Write-downs Change in Decommissioning Liabilities As at December 31, 2021 Additions Write-downs Change in Decommissioning Liabilities Exchange Rate Movements and Other (1) As at December 31, 2022 recognized a revaluation gain of $40 million. 2022 3,195 1,329 4,524 2022 2,962 402 — 51 58 3,473 2021 2,366 507 2,873 2021 2,548 486 371 225 240 3,870 (1) As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million). (1) Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment), as the carrying value was not considered to be recoverable. Total 623 45 55 (9) 6 720 37 (64) (12) 4 685 17. INVENTORIES As at December 31, Product Crude Oil Diluent Natural Gas and NGLs Refined Products Total Product Parts and Supplies 2022 2,424 366 50 1,169 4,009 303 4,312 2021 2,060 515 33 1,043 3,651 268 3,919 For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an expense (2021 – approximately $34 billion). 18. ASSETS HELD FOR SALE The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10): Retail Gas Stations Tucker Wembley PP&E ROU Assets Goodwill Lease Liabilities 498 505 159 1,162 54 — — 54 — 88 — 88 (58) — — (58) Decommissioning Liabilities (86) (33) (9) (128) 122 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 19. EXPLORATION AND EVALUATION ASSETS, NET As at December 31, 2020 Acquisitions (Note 5) Additions Write-downs Change in Decommissioning Liabilities As at December 31, 2021 Additions Write-downs Change in Decommissioning Liabilities Exchange Rate Movements and Other (1) As at December 31, 2022 Total 623 45 55 (9) 6 720 37 (64) (12) 4 685 (1) As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million). (1) Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and recognized a revaluation gain of $40 million. For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment), as the carrying value was not considered to be recoverable. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 15. CASH AND CASH EQUIVALENTS 16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES As at December 31, Cash Short-Term Investments As at December 31, Trade and Accruals Prepaids and Deposits Partner Advances Joint Operations Receivables Other (1) 17. INVENTORIES As at December 31, Product Crude Oil Diluent Natural Gas and NGLs Refined Products Total Product Parts and Supplies For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an expense (2021 – approximately $34 billion). 18. ASSETS HELD FOR SALE Retail Gas Stations Tucker Wembley The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10): PP&E ROU Assets Goodwill Lease Liabilities Liabilities Decommissioning 498 505 159 1,162 54 — — 54 — 88 — 88 (58) — — (58) 2022 3,195 1,329 4,524 2022 2,962 402 — 51 58 3,473 2022 2,424 366 50 1,169 4,009 303 4,312 2021 2,366 507 2,873 2021 2,548 486 371 225 240 3,870 2021 2,060 515 33 1,043 3,651 268 3,919 (86) (33) (9) (128) CENOVUS ENERGY 2022 ANNUAL REPORT | 123 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 20. PROPERTY, PLANT AND EQUIPMENT, NET Crude Oil and Natural Gas Properties Processing, Transportation and Storage Assets Manufacturing Assets Other Assets (1) COST As at December 31, 2020 Acquisitions (Note 5) Additions Change in Decommissioning Liabilities Divestitures (Note 10) Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Acquisitions (Note 5) (2) Additions Change in Decommissioning Liabilities Divestitures (Note 5) (2) Exchange Rate Movements and Other As at December 31, 2022 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2020 Depreciation, Depletion and Amortization Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Note 10) Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Depreciation, Depletion and Amortization (3) Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Note 5) (2) Exchange Rate Movements and Other As at December 31, 2022 CARRYING VALUE As at December 31, 2020 As at December 31, 2021 As at December 31, 2022 29,867 8,633 1,368 (63) (630) (754) 22 38,443 3,230 2,409 (186) (557) 189 43,528 8,361 3,335 — (378) (377) (90) 61 10,912 3,461 — — (84) 13 14,302 21,506 27,531 29,226 218 — 9 1 — — — 228 — 11 (6) — 21 254 42 10 — — — — 1 53 37 — — — 16 106 176 175 148 5,671 3,901 1,023 40 — — (140) 10,495 — 1,143 (29) — 523 12,132 2,195 526 1,931 — — — (80) 4,572 466 1,499 (1,233) — 243 5,547 3,476 5,923 6,585 1,290 846 115 24 — (522) (18) 1,735 — 108 (32) — 14 1,825 1,037 128 — — — (24) (2) 1,139 103 — — — 43 1,285 253 596 540 Total 37,046 13,380 2,515 2 (630) (1,276) (136) 50,901 3,230 3,671 (253) (557) 747 57,739 11,635 3,999 1,931 (378) (377) (114) (20) 16,676 4,067 1,499 (1,233) (84) 315 21,240 25,411 34,225 36,499 (1) (2) (3) Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft. In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million. DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A: Assets Under Construction As at December 31, Development and Production Downstream 21. RIGHT-OF-USE ASSETS, NET COST As at December 31, 2020 Acquisitions (Note 5) Additions Modifications Re-measurements Additions Modifications Re-measurements Terminations Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Exchange Rate Movements and Other As at December 31, 2022 ACCUMULATED DEPRECIATION As at December 31, 2020 Depreciation Terminations Impairment Charges (Note 11) Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Depreciation Terminations Exchange Rate Movements and Other As at December 31, 2022 CARRYING VALUE As at December 31, 2020 As at December 31, 2021 As at December 31, 2022 2022 2,142 137 2,279 15 130 3 — (3) (78) (5) 62 2 2 1 (1) 8 74 7 23 1 — (6) 1 14 — (3) 12 8 61 62 (24) 2021 2,415 943 3,358 Total 1,502 1,132 110 22 (4) (78) (28) 25 83 7 2,656 (10) (74) 2,687 363 323 11 (3) (24) (24) 646 297 (6) (95) 842 1,139 2,010 1,845 Transportation and Storage Manufacturing Real Estate Assets (1) Assets Other Assets (2) 495 99 4 1 (2) — (5) 592 — 9 1 (1) (2) 599 58 38 — — — (4) 92 36 — (1) 127 437 500 472 977 765 96 20 1 — (18) 1,841 22 69 3 (6) (89) 1,840 293 239 5 (3) — (14) 520 226 (6) (95) 645 684 1,321 1,195 15 138 7 1 — — — 161 1 3 2 9 (2) 174 5 23 5 — — — 33 21 — 4 58 10 128 116 (1) (2) Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks. Includes assets within the commercial fuels business, fleet vehicles and other equipment. 124 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 20. PROPERTY, PLANT AND EQUIPMENT, NET COST As at December 31, 2020 Acquisitions (Note 5) Additions Change in Decommissioning Liabilities Divestitures (Note 10) Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Acquisitions (Note 5) (2) Additions Change in Decommissioning Liabilities Divestitures (Note 5) (2) Exchange Rate Movements and Other As at December 31, 2022 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2020 Depreciation, Depletion and Amortization Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Note 10) Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Depreciation, Depletion and Amortization (3) Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Note 5) (2) Exchange Rate Movements and Other As at December 31, 2022 CARRYING VALUE As at December 31, 2020 As at December 31, 2021 As at December 31, 2022 29,867 8,633 1,368 (63) (630) (754) 22 3,230 2,409 (186) (557) 189 38,443 43,528 8,361 3,335 — (378) (377) (90) 61 10,912 3,461 — — (84) 13 14,302 21,506 27,531 29,226 Crude Oil and Transportation Processing, Natural Gas and Storage Manufacturing Properties Assets Assets Other Assets (1) 12,132 1,825 57,739 218 — 9 1 — — — 228 — 11 (6) — 21 254 42 10 — — — — 1 53 37 — — — 16 106 176 175 148 5,671 3,901 1,023 40 — — (140) 10,495 — 1,143 (29) — 523 2,195 526 1,931 — — — (80) 4,572 466 1,499 (1,233) — 243 5,547 3,476 5,923 6,585 Total 37,046 13,380 2,515 2 (630) (1,276) (136) 50,901 3,230 3,671 (253) (557) 747 11,635 3,999 1,931 (378) (377) (114) (20) 16,676 4,067 1,499 (1,233) (84) 315 21,240 25,411 34,225 36,499 1,290 846 115 24 — (522) (18) 1,735 — 108 (32) — 14 1,037 128 — — — (24) (2) 1,139 103 — — — 43 1,285 253 596 540 (1) (2) Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft. In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million. (3) DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Assets Under Construction PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A: As at December 31, Development and Production Downstream 21. RIGHT-OF-USE ASSETS, NET COST As at December 31, 2020 Acquisitions (Note 5) Additions Modifications Re-measurements Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Additions Modifications Re-measurements Terminations Exchange Rate Movements and Other As at December 31, 2022 ACCUMULATED DEPRECIATION As at December 31, 2020 Depreciation Impairment Charges (Note 11) Terminations Transfers to Assets Held for Sale (Note 18) Exchange Rate Movements and Other As at December 31, 2021 Depreciation Terminations Exchange Rate Movements and Other As at December 31, 2022 CARRYING VALUE As at December 31, 2020 As at December 31, 2021 As at December 31, 2022 2022 2,142 137 2,279 Transportation and Storage Assets (1) Real Estate Manufacturing Assets Other Assets (2) 495 99 4 1 (2) — (5) 592 — 9 1 (1) (2) 599 58 38 — — — (4) 92 36 — (1) 127 437 500 472 977 765 96 20 1 — (18) 1,841 22 69 3 (6) (89) 1,840 293 239 5 (3) — (14) 520 226 (6) (95) 645 684 1,321 1,195 15 138 7 1 — — — 161 1 3 2 (2) 9 174 5 23 5 — — — 33 21 — 4 58 10 128 116 15 130 3 — (3) (78) (5) 62 2 2 1 (1) 8 74 7 23 1 — (24) (6) 1 14 — (3) 12 8 61 62 (1) (2) Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks. Includes assets within the commercial fuels business, fleet vehicles and other equipment. 2021 2,415 943 3,358 Total 1,502 1,132 110 22 (4) (78) (28) 2,656 25 83 7 (10) (74) 2,687 363 323 11 (3) (24) (24) 646 297 (6) (95) 842 1,139 2,010 1,845 CENOVUS ENERGY 2022 ANNUAL REPORT | 125 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 22. JOINT ARRANGEMENTS A) Joint Operations Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held in separate entities in the U.S. Manufacturing segment. and December 31, 2021. BP-Husky Refining LLC Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest. See Note 5 for further details. WRB Refining LP Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining 50 percent interest and is the operator of 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 and NGLs 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 years ended December 31, Revenue Expenses Net Earnings (Loss) Balance Sheet As at December 31, Current Assets (1) Non-Current Assets Current Liabilities Non-Current Liabilities Net Assets 2022 383 350 33 2022 247 1,926 160 1,293 720 2021 439 395 44 2021 167 1,433 62 896 642 (1) Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million). For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million (2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million (December 31, 2021 – $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, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million) and paid $54 million in contributions (2021 – $18 million). Husky Midstream Limited Partnership The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP. 126 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $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 of HMLP. For the year ended December 31, 2022, the Company did not record its share of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022 As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31, 2021 – $17 million). 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 year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions paid are recorded in earnings from equity-accounted affiliates. 23. OTHER ASSETS As at December 31, Intangible Assets (1) Private Equity Investments (Note 37) Other Equity Investments Net Investment in Finance Leases Long-Term Receivables and Prepaids Precious Metals Other 24. GOODWILL Carrying Value, Beginning of Year Goodwill Recognized (Note 5) Carrying Value, End of Year As at December 31, Primrose (Foster Creek) Christina Lake Lloydminster Thermal Sunrise (Note 5) (1) For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands segment as the carrying value was not considered to be recoverable. In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to Headwater 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 was carried at FVTPL. On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million. Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18) The carrying amount of goodwill is allocated to the following CGUs: 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, 2022, are consistent with those disclosed in Note 11. There was no impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil). 2022 2021 19 55 — 62 120 86 — 342 2022 3,473 — (550) 2,923 2022 1,171 1,101 651 — 2,923 78 53 77 60 77 85 1 431 2021 2,272 1,289 (88) 3,473 2021 1,171 1,101 651 550 3,473 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 22. JOINT ARRANGEMENTS A) Joint Operations in separate entities in the U.S. Manufacturing segment. BP-Husky Refining LLC 50 percent interest. See Note 5 for further details. WRB Refining LP Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining 50 percent interest and is the operator of the Wood River Refinery in Illinois and the Borger Refinery in Texas. 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 and NGLs 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. B) Joint Ventures Husky-CNOOC Madura Ltd. Results of Operations For the years ended December 31, Revenue Expenses Net Earnings (Loss) Balance Sheet As at December 31, Current Assets (1) Non-Current Assets Current Liabilities Non-Current Liabilities Net Assets 2022 383 350 33 2022 247 1,926 160 1,293 720 2021 439 395 44 2021 167 1,433 62 896 642 (1) Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million). For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million (2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million (December 31, 2021 – $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, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million) and paid $54 million in contributions (2021 – $18 million). Husky Midstream Limited Partnership The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $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 of HMLP. For the year ended December 31, 2022, the Company did not record its share of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022 and December 31, 2021. As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31, 2021 – $17 million). 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 year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions paid are recorded in earnings from equity-accounted affiliates. 23. OTHER ASSETS As at December 31, Intangible Assets (1) Private Equity Investments (Note 37) Other Equity Investments Net Investment in Finance Leases Long-Term Receivables and Prepaids Precious Metals Other 2022 2021 19 55 — 62 120 86 — 342 78 53 77 60 77 85 1 431 (1) For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands segment as the carrying value was not considered to be recoverable. In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to Headwater 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 was carried at FVTPL. On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million. 24. GOODWILL Carrying Value, Beginning of Year Goodwill Recognized (Note 5) Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18) Carrying Value, End of Year The carrying amount of goodwill is allocated to the following CGUs: As at December 31, Primrose (Foster Creek) Christina Lake Lloydminster Thermal Sunrise (Note 5) 2022 3,473 — (550) 2,923 2022 1,171 1,101 651 — 2,923 2021 2,272 1,289 (88) 3,473 2021 1,171 1,101 651 550 3,473 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, 2022, are consistent with those disclosed in Note 11. There was no impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil). CENOVUS ENERGY 2022 ANNUAL REPORT | 127 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 B) Long-Term Debt As at December 31, Committed Credit Facility (1) U.S. Dollar Denominated Unsecured Notes Canadian Dollar Unsecured Notes Total Debt Principal Debt Premiums (Discounts), Net, and Transaction Costs Long-Term Debt i) Committed Credit Facility Notes i ii ii 2022 — 6,537 2,000 8,537 154 8,691 2021 — 9,363 2,750 12,113 272 12,385 (1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans. At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion, with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022, no amounts were drawn on the credit facility (December 31, 2021 – $nil). ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the following unsecured notes: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Partner Advances Employee Long-Term Incentives Joint Operations Payable Risk Management Provisions for Onerous and Unfavourable Contracts Other 26. DEBT AND CAPITAL STRUCTURE 2022 3,412 2,331 80 — 162 66 39 25 9 2021 2,722 2,554 128 371 317 28 116 31 86 6,124 6,353 Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility. For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent). A) Short-Term Borrowings As at December 31, Uncommitted Demand Facilities WRB Uncommitted Demand Facilities Total Debt Principal i) Uncommitted Demand Facilities Notes i ii 2022 — 115 115 2021 — 79 79 As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings. As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility. ii) WRB Uncommitted Demand Facilities As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share – US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million (the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)). U.S. Dollar Unsecured Notes 3.95% due April 15, 2022 3.00% due August 15, 2022 3.80% due September 15, 2023 4.00% due April 15, 2024 5.38% due July 15, 2025 4.25% due April 15, 2027 4.40% due April 15, 2029 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 Canadian Dollar Unsecured Notes 3.55% due March 12, 2025 2022 2021 US$ Principal US$ Principal — — 115 269 533 589 510 455 58 29 500 500 335 481 334 — — — — — 2,558 2,150 C$ Principal C$ Principal 750 — 128 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Partner Advances Employee Long-Term Incentives Joint Operations Payable Risk Management Provisions for Onerous and Unfavourable Contracts Other 26. DEBT AND CAPITAL STRUCTURE A) Short-Term Borrowings As at December 31, Uncommitted Demand Facilities WRB Uncommitted Demand Facilities Total Debt Principal i) Uncommitted Demand Facilities 2022 3,412 2,331 80 — 162 66 39 25 9 2021 2,722 2,554 128 371 317 28 116 31 86 6,124 6,353 Notes i ii 2022 — 115 115 2021 — 79 79 For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent). NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 B) Long-Term Debt As at December 31, Committed Credit Facility (1) U.S. Dollar Denominated Unsecured Notes Canadian Dollar Unsecured Notes Total Debt Principal Debt Premiums (Discounts), Net, and Transaction Costs Long-Term Debt Notes i ii ii 2022 — 6,537 2,000 8,537 154 8,691 2021 — 9,363 2,750 12,113 272 12,385 (1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans. i) Committed Credit Facility At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion, with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility. On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to $5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022, no amounts were drawn on the credit facility (December 31, 2021 – $nil). ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the following unsecured notes: As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no direct borrowings. As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility. ii) WRB Uncommitted Demand Facilities As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share – US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million (the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US$63 million (C$79 million)). U.S. Dollar Unsecured Notes 3.95% due April 15, 2022 3.00% due August 15, 2022 3.80% due September 15, 2023 4.00% due April 15, 2024 5.38% due July 15, 2025 4.25% due April 15, 2027 4.40% due April 15, 2029 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 Canadian Dollar Unsecured Notes 3.55% due March 12, 2025 2022 2021 US$ Principal US$ Principal — — 115 269 533 589 510 455 58 29 500 500 335 481 334 — — — — — 2,558 2,150 C$ Principal C$ Principal 750 — CENOVUS ENERGY 2022 ANNUAL REPORT | 129 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The principal amounts of the Company’s outstanding unsecured notes are: D) Capital Structure As at December 31, U.S. Dollar Denominated Unsecured Notes 3.80% due September 15, 2023 4.00% due April 15, 2024 5.38% due July 15, 2025 4.25% due April 15, 2027 4.40% due April 15, 2029 2.65% due January 15, 2032 5.25% due June 15, 2037 6.80% due September 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 3.75% due February 15, 2052 Canadian Dollar Unsecured Notes 3.55% due March 12, 2025 3.60% due March 10, 2027 3.50% due February 7, 2028 Total Unsecured Notes 2022 2021 US$ Principal C$ Principal and Equivalent US$ Principal C$ Principal and Equivalent — — 133 373 240 500 583 387 935 97 29 800 750 4,827 — — 181 505 324 677 790 524 1,267 131 39 1,083 1,016 6,537 — 750 1,250 2,000 8,537 115 269 666 962 750 500 583 387 1,390 155 58 800 750 7,385 146 341 844 1,220 951 634 739 490 1,763 197 73 1,014 951 9,363 750 750 1,250 2,750 12,113 At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value – US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052. As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit. C) Mandatory Debt Payments As at December 31, 2022 2023 2024 2025 2026 2027 Thereafter U.S. Dollar Unsecured Notes Canadian Dollar Unsecured Notes US$ Principal C$ Principal Equivalent C$ Principal Total C$ Principal and Equivalent — — 133 — 373 4,321 4,827 — — 181 — 505 5,851 6,537 — — — — 750 1,250 2,000 — — 181 — 1,255 7,101 8,537 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. Net Debt is used in managing the Company’s capital structure. 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 Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022. Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4 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, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings. Net Debt to Adjusted EBITDA As at December 31, Short-Term Borrowings Current Portion of Long-Term Debt Long-Term Portion of Long-Term Debt Total Debt Net Debt Less: Cash and Cash Equivalents Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income Income Tax Expense (Recovery) Depreciation, Depletion and Amortization E&E Asset Write-downs (Income) Loss From Equity-Accounted Affiliates Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA (1) Calculated on a trailing twelve-month basis. 587 (2,379) 2022 115 — 8,691 8,806 (4,524) 4,282 6,450 820 (81) 2,281 4,679 64 (15) (126) 343 (549) 162 (269) (532) 13,227 0.3x 2021 79 — 12,385 12,464 (2,873) 9,591 1,082 (23) 728 5,886 18 (57) 2 (174) — 575 (229) (309) 8,086 1.2x 2020 121 — 7,441 7,562 (378) 7,184 536 (9) (851) 3,464 91 — 56 (181) — (80) (81) 40 606 11.9x 130 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The principal amounts of the Company’s outstanding unsecured notes are: D) Capital Structure As at December 31, U.S. Dollar Denominated Unsecured Notes 3.80% due September 15, 2023 4.00% due April 15, 2024 5.38% due July 15, 2025 4.25% due April 15, 2027 4.40% due April 15, 2029 2.65% due January 15, 2032 5.25% due June 15, 2037 6.80% due September 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 3.75% due February 15, 2052 Canadian Dollar Unsecured Notes 3.55% due March 12, 2025 3.60% due March 10, 2027 3.50% due February 7, 2028 Total Unsecured Notes C) Mandatory Debt Payments As at December 31, 2022 2023 2024 2025 2026 2027 Thereafter 2022 2021 C$ Principal and C$ Principal and US$ Principal Equivalent US$ Principal Equivalent — — 133 373 240 500 583 387 935 97 29 800 750 4,827 — — 133 — 373 4,321 4,827 — — 181 505 324 677 790 524 1,267 131 39 1,083 1,016 6,537 — 750 1,250 2,000 8,537 — — 181 — 505 5,851 6,537 115 269 666 962 750 500 583 387 155 58 800 750 1,390 7,385 — — — — 750 1,250 2,000 1,220 146 341 844 951 634 739 490 1,763 197 73 1,014 951 9,363 750 750 1,250 2,750 12,113 Total — — 181 — 1,255 7,101 8,537 At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value – US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052. As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. The Company is well below this limit. U.S. Dollar Unsecured Notes Canadian Dollar Unsecured Notes US$ Principal C$ Principal Equivalent C$ Principal and C$ Principal Equivalent 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. Net Debt is used in managing the Company’s capital structure. 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 Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022. Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times and Net Debt at or below $4 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, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings. Net Debt to Adjusted EBITDA As at December 31, Short-Term Borrowings Current Portion of Long-Term Debt Long-Term Portion of Long-Term Debt Total Debt Less: Cash and Cash Equivalents Net Debt Net Earnings (Loss) Add (Deduct): Finance Costs Interest Income Income Tax Expense (Recovery) Depreciation, Depletion and Amortization E&E Asset Write-downs (Income) Loss From Equity-Accounted Affiliates Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gains) Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA (1) Calculated on a trailing twelve-month basis. 2022 115 — 8,691 8,806 (4,524) 4,282 6,450 820 (81) 2,281 4,679 64 (15) (126) 343 (549) 162 (269) (532) 13,227 0.3x 2021 79 — 12,385 12,464 (2,873) 9,591 2020 121 — 7,441 7,562 (378) 7,184 587 (2,379) 1,082 (23) 728 5,886 18 (57) 2 (174) — 575 (229) (309) 8,086 1.2x 536 (9) (851) 3,464 91 — 56 (181) — (80) (81) 40 606 11.9x CENOVUS ENERGY 2022 ANNUAL REPORT | 131 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 28. CONTINGENT PAYMENTS A) Sunrise Oil Sands Partnership In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the term of the contract is $600 million. The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023. earnings (loss). As at December 31, 2021 Initial Recognition Liabilities Settled or Payable Re-measurement (1) As at December 31, 2022 Less: Current Portion Long-Term Portion B) FCCL Partnership Total — 600 (92) (89) 419 263 156 2021 63 575 (402) 236 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Net Debt to Adjusted Funds Flow As at December 31, Net Debt Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (1) Net Debt to Adjusted Funds Flow (1) Calculated on a trailing twelve-month basis. Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Capitalization 2022 4,282 11,403 (150) 575 10,978 0.4x 2022 4,282 27,576 31,858 2021 9,591 5,919 (102) (1,227) 7,248 2020 7,184 273 (42) 198 117 1.3x 61.4x 2021 9,591 23,596 33,187 2020 7,184 16,707 23,891 Net Debt to Capitalization 13 % 29 % 30 % 27. LEASE LIABILITIES Lease Liabilities, Beginning of Year Acquisitions (Note 5) Additions Interest Expense (Note 7) Lease Payments Modifications Re-measurements Terminations Transfers to Liabilities Related to Assets Held for Sale (Note 18) Exchange Rate Movements and Other Lease Liabilities, End of Year Less: Current Portion Long-Term Portion 2022 2,957 — 25 163 (465) 83 7 (5) — 71 2,836 308 2,528 2021 1,757 1,441 110 171 (471) 22 (4) (1) (10) (58) 2,957 272 2,685 (1) The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss). On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel. Contingent Payment, Beginning of Year Re-measurement (1) Liabilities Settled Contingent Payment, End of Year (1) The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss). 2022 236 251 (487) — 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, commercial fuel 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 includes extension options in the calculation of lease liabilities when 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. 132 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Net Debt to Adjusted Funds Flow As at December 31, Net Debt Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (1) Net Debt to Adjusted Funds Flow (1) Calculated on a trailing twelve-month basis. Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Capitalization 27. LEASE LIABILITIES Lease Liabilities, Beginning of Year Acquisitions (Note 5) Additions Interest Expense (Note 7) Lease Payments Modifications Re-measurements Terminations Lease Liabilities, End of Year Less: Current Portion Long-Term Portion Transfers to Liabilities Related to Assets Held for Sale (Note 18) Exchange Rate Movements and Other 2022 4,282 11,403 (150) 575 10,978 0.4x 2022 4,282 27,576 31,858 1.3x 61.4x 2021 9,591 5,919 (102) (1,227) 7,248 2021 9,591 23,596 33,187 2022 2,957 — 25 163 (465) 83 7 (5) — 71 2,836 308 2,528 2020 7,184 273 (42) 198 117 2020 7,184 16,707 23,891 2021 1,757 1,441 110 171 (471) 22 (4) (1) (10) (58) 2,957 272 2,685 Net Debt to Capitalization 13 % 29 % 30 % 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, commercial fuel 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 includes extension options in the calculation of lease liabilities when 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 28. CONTINGENT PAYMENTS A) Sunrise Oil Sands Partnership In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment over the term of the contract is $600 million. The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum $600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net earnings (loss). The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023. As at December 31, 2021 Initial Recognition Liabilities Settled or Payable Re-measurement (1) As at December 31, 2022 Less: Current Portion Long-Term Portion Total — 600 (92) (89) 419 263 156 (1) The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss). B) FCCL Partnership On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel. Contingent Payment, Beginning of Year Re-measurement (1) Liabilities Settled Contingent Payment, End of Year (1) The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss). 2022 236 251 (487) — 2021 63 575 (402) 236 CENOVUS ENERGY 2022 ANNUAL REPORT | 133 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 29. 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, the commercial fuels facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is: Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) Liabilities Settled Liabilities Divested (Note 5) (1) Change in Estimated Future Cash Flows Change in Discount Rates Unwinding of Discount on Decommissioning Liabilities (Note 7) Transfers to Liabilities Related to Assets Held for Sale (Note 18) Exchange Rate Movements and Other Decommissioning Liabilities, End of Year 2022 3,906 22 48 (215) (89) 693 (980) 176 — (2) 3,559 2021 1,248 30 2,856 (144) (140) (472) 450 199 (128) 7 3,906 (1) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million. As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is $14 billion (December 31, 2021 – $14 billion). 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 $250 million to $300 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. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 – 4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent). 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, 2022, the Company had $209 million in restricted cash (December 31, 2021 – $186 million). Sensitivities Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning liabilities: As at December 31, Credit-Adjusted Risk-Free Rate Inflation Rate Sensitivity Range ± one percent ± one percent 2022 2021 Increase Decrease Increase Decrease (319) 419 419 (320) (623) 873 875 (625) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 30. OTHER LIABILITIES As at December 31, Pension and Other Post-Employment Benefit Plan Provision for West White Rose Expansion Project (1) Provisions for Onerous and Unfavourable Contracts Employee Long-Term Incentives Drilling Provisions Deferred Revenue Other (2) 2022 201 204 95 245 31 45 221 1,042 2021 288 259 99 74 56 41 112 929 (1) On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by $47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months. (2) As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively. 31. 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, 2021, and the next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023. 134 | CENOVUS ENERGY 2022 ANNUAL REPORT 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, the NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 29. DECOMMISSIONING LIABILITIES commercial fuels facilities and the crude-by-rail terminal. The aggregate carrying amount of the obligation is: Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) Liabilities Settled Liabilities Divested (Note 5) (1) Change in Estimated Future Cash Flows Change in Discount Rates Unwinding of Discount on Decommissioning Liabilities (Note 7) Transfers to Liabilities Related to Assets Held for Sale (Note 18) Exchange Rate Movements and Other Decommissioning Liabilities, End of Year 2022 3,906 22 48 (215) (89) 693 (980) 176 — (2) 3,559 2021 1,248 30 2,856 (144) (140) (472) 450 199 (128) 7 3,906 (1) In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million. As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is $14 billion (December 31, 2021 – $14 billion). 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 $250 million to $300 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. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 – 4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent). 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, 2022, the Company had $209 million in restricted cash (December 31, 2021 – $186 million). Sensitivities liabilities: Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning As at December 31, Credit-Adjusted Risk-Free Rate Inflation Rate Sensitivity Range ± one percent ± one percent 2022 2021 Increase Decrease Increase Decrease (319) 419 419 (320) (623) 873 875 (625) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 30. OTHER LIABILITIES As at December 31, Pension and Other Post-Employment Benefit Plan Provision for West White Rose Expansion Project (1) Provisions for Onerous and Unfavourable Contracts Employee Long-Term Incentives Drilling Provisions Deferred Revenue Other (2) 2022 201 204 95 245 31 45 221 1,042 2021 288 259 99 74 56 41 112 929 (1) (2) On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by $47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months. As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively. 31. 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, 2021, and the next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023. CENOVUS ENERGY 2022 ANNUAL REPORT | 135 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 2022 2021 OPEB 2022 Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Plan Acquisition Upon the Arrangement (1) Current Service Costs Past Service Costs - Curtailment and Plan Amendments Interest Costs (2) Benefits Paid Plan Participant Contributions Re-measurements: (Gains) Losses From Experience Adjustments (Gains) Losses From Changes in Demographic Assumptions (Gains) Losses From Changes in Financial Assumptions Exchange Rate Movements and Other Defined Benefit Obligation, End of Year Plan Assets Fair Value of Plan Assets, Beginning of Year Plan Acquisition Upon the Arrangement (1) Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (2) Re-measurements: Return on Plan Assets (Excluding Interest Income) Exchange Rate Movements and Other Fair Value of Plan Assets, End of Year Pension and OPEB (Liability) (3) 220 — 16 — 7 (12) 2 1 — (64) 2 172 159 — 16 2 (10) 4 (26) 2 147 (25) 188 41 16 (1) 6 (17) 2 4 (1) (18) — 220 117 32 9 2 (13) 3 9 — 159 (61) 2021 20 224 9 (3) 6 (8) — 10 (3) (30) — 225 — — 3 — (3) — — — — 225 — 8 — 7 (8) — (2) — (57) 1 174 — — 8 — (8) — — — — (174) (225) (1) (2) (3) The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5. Based on the discount rate of the defined benefit obligation at the beginning of the year. 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 14 years and 14 years, respectively. 136 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Past Service Costs - Curtailments and Plan B) Pension and OPEB Costs As at December 31, Defined Benefit Plan Cost Current Service Costs Amendments Net Interest Costs Re-measurements: Return on Plan Assets (Excluding Interest Income) (Gains) Losses From Experience Adjustments (Gains) Losses From Changes in Demographic Assumptions (Gains) Losses From Changes in Financial Assumptions Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost (1) Total Plan Cost (1) Includes defined contribution and U.S. 401(k) plans. 16 — 3 26 1 — (64) (18) 72 54 Pension Benefits OPEB 2022 2021 2020 2022 2021 2020 16 (1) 3 (9) 4 (1) (18) (6) 68 62 13 — 3 (5) 1 — 15 27 22 49 8 — 7 — (2) — (57) (44) — (44) 9 (3) 6 — 10 (3) (30) (11) — (11) 1 — — — (2) — 1 — — — 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 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. 2022 Target Allocation (percent) Equity Funds Fixed Income Funds Real Estate Funds Listed Infrastructure Funds Emerging Market Debt Funds Cash and Cash Equivalents Canadian Plan 25% - 75% 20% - 50% —% - 15% —% - 10% —% - 10% —% - 10% U.S. Plan 21% - 51% 55% - 74% — % — % — % — % 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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 2022 2021 OPEB 2022 Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Plan Acquisition Upon the Arrangement (1) Current Service Costs Past Service Costs - Curtailment and Plan Amendments Interest Costs (2) Benefits Paid Plan Participant Contributions Re-measurements: (Gains) Losses From Experience Adjustments (Gains) Losses From Changes in Demographic Assumptions (Gains) Losses From Changes in Financial Assumptions Exchange Rate Movements and Other Defined Benefit Obligation, End of Year Plan Assets Fair Value of Plan Assets, Beginning of Year Plan Acquisition Upon the Arrangement (1) Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (2) Re-measurements: Return on Plan Assets (Excluding Interest Income) Exchange Rate Movements and Other Fair Value of Plan Assets, End of Year Pension and OPEB (Liability) (3) 2021 20 224 (3) 9 6 (8) — 10 (3) (30) — 225 — — 3 — (3) — — — — 225 — 8 — 7 (8) — (2) — (57) 1 174 — — 8 — (8) — — — — 220 — 16 — 7 (12) 2 1 — (64) 2 172 159 — 16 2 (10) 4 (26) 2 147 (25) 188 41 16 (1) (17) 6 2 4 (1) (18) — 220 117 32 9 2 3 (13) 9 — 159 (61) (1) (2) (3) The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5. Based on the discount rate of the defined benefit obligation at the beginning of the year. 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 14 years and 14 years, respectively. (174) (225) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 B) Pension and OPEB Costs As at December 31, Defined Benefit Plan Cost Current Service Costs Past Service Costs - Curtailments and Plan Amendments Net Interest Costs Re-measurements: Return on Plan Assets (Excluding Interest Income) (Gains) Losses From Experience Adjustments (Gains) Losses From Changes in Demographic Assumptions (Gains) Losses From Changes in Financial Assumptions Defined Benefit Plan Cost (Recovery) Defined Contribution Plan Cost (1) Total Plan Cost (1) Includes defined contribution and U.S. 401(k) plans. Pension Benefits OPEB 2022 2021 2020 2022 2021 2020 16 — 3 26 1 — (64) (18) 72 54 16 (1) 3 (9) 4 (1) (18) (6) 68 62 13 — 3 (5) 1 — 15 27 22 49 8 — 7 — (2) — (57) (44) — (44) 9 (3) 6 — 10 (3) (30) (11) — (11) 1 — — — (2) — 1 — — — 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 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. 2022 Target Allocation (percent) Equity Funds Fixed Income Funds Real Estate Funds Listed Infrastructure Funds Emerging Market Debt Funds Cash and Cash Equivalents Canadian Plan 25% - 75% 20% - 50% —% - 15% —% - 10% —% - 10% —% - 10% U.S. Plan 21% - 51% 55% - 74% — % — % — % — % 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 137 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The fair value of the DB Pension Plan assets is: As at December 31, Equity Funds Fixed Income Funds Real Estate Funds Listed Infrastructure Funds Emerging Market Debt Funds Cash and Cash Equivalents Non-Invested Assets 2022 68 50 9 7 5 7 1 2021 77 54 9 8 8 2 1 Total Fair Value of DB Pension Plan Assets 147 159 Fair value of the cash and cash equivalents, equity, fixed 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 or preferred shares. D) Funding The DB Pension Plan is 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. In the year ended December 31, 2023, the Company expects to contribute $10 million for the DB Pension Plan. The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute $10 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: For the years ended December 31, Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate Pension Benefits 2022 5.12 % 4.05 % 88.4 N/A 2021 2.95 % 4.03 % 88.3 N/A 2020 2.50 % 3.97 % 88.3 N/A 2022 5.13 % N/A 88.4 5.24 % OPEB 2021 2.98 % 4.94 % 88.3 5.64 % 2020 2.50 % 4.94 % 88.2 6.00 % Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations. 138 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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: As at December 31, One Percent Change: Discount Rate Future Salary Growth Rate Health Care Cost Trend Rate One Year Change in Assumed Life Expectancy 2022 2021 Increase Decrease Increase Decrease (43) 3 19 10 51 (3) (17) (10) (59) 4 26 4 76 (4) (20) (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. 32. SHARE CAPITAL AND WARRANTS A) Authorized to the Company’s articles. B) Issued and Outstanding – Common Shares 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 2022 2021 Number of Common Shares (thousands) 2,001,211 — 9,399 11,069 (112,489) 1,909,190 Number of Common Shares (thousands) 1,228,870 788,518 314 535 (17,026) 2,001,211 Amount 17,016 — 93 170 (959) 16,320 Amount 11,040 6,111 3 7 (145) 17,016 Outstanding, Beginning of Year Issued Under the Arrangement, Net of Issuance Costs (Note 5) Issued Upon Exercise of Warrants Issued Under Stock Option Plans Purchase of Common Shares under NCIBs Outstanding, End of Year under the stock option plan. C) Normal Course Issuer Bid As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023. For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021 – 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share (December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB. 2022 68 50 9 7 5 7 1 2021 77 54 9 8 8 2 1 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The fair value of the DB Pension Plan assets is: As at December 31, Equity Funds Fixed Income Funds Real Estate Funds Listed Infrastructure Funds Emerging Market Debt Funds Cash and Cash Equivalents Non-Invested Assets (Level 3). D) Funding Total Fair Value of DB Pension Plan Assets 147 159 Fair value of the cash and cash equivalents, equity, fixed 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 The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares. The DB Pension Plan is 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. In the year ended December 31, 2023, the Company expects to contribute $10 million for the The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute DB Pension Plan. $10 million for the OPEB plans. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions For the years ended December 31, Discount Rate Future Salary Growth Rate Average Longevity (years) Health Care Cost Trend Rate benefit obligations. The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows: Pension Benefits 2022 5.12 % 4.05 % 88.4 N/A 2021 2.95 % 4.03 % 88.3 N/A 2020 2.50 % 3.97 % 88.3 N/A 2022 5.13 % N/A 88.4 5.24 % OPEB 2021 2.98 % 4.94 % 88.3 5.64 % 2020 2.50 % 4.94 % 88.2 6.00 % NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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: As at December 31, One Percent Change: Discount Rate Future Salary Growth Rate Health Care Cost Trend Rate One Year Change in Assumed Life Expectancy 2022 2021 Increase Decrease Increase Decrease (43) 3 19 10 51 (3) (17) (10) (59) 4 26 4 76 (4) (20) (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. 32. 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. B) Issued and Outstanding – Common Shares Outstanding, Beginning of Year Issued Under the Arrangement, Net of Issuance Costs (Note 5) Issued Upon Exercise of Warrants Issued Under Stock Option Plans Purchase of Common Shares under NCIBs Outstanding, End of Year 2022 2021 Number of Common Shares (thousands) 2,001,211 — 9,399 11,069 (112,489) 1,909,190 Number of Common Shares (thousands) 1,228,870 788,518 314 535 (17,026) 2,001,211 Amount 17,016 — 93 170 (959) 16,320 Amount 11,040 6,111 3 7 (145) 17,016 As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance under the stock option plan. Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the C) Normal Course Issuer Bid On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period from November 9, 2022, to November 8, 2023. For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021 – 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share (December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB. CENOVUS ENERGY 2022 ANNUAL REPORT | 139 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 D) Issued and Outstanding – Preferred Shares For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 – $519 million). As at December 31, 2022 Series 1 First Preferred Shares Series 2 First Preferred Shares (1) Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Dividend Reset Date Dividend Rate March 31, 2026 Quarterly December 31, 2024 March 31, 2025 June 30, 2025 2.58 % 5.86 % 4.69 % 4.59 % 3.94 % Number of Preferred Shares (thousands) 10,740 1,260 10,000 8,000 6,000 (1) The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023. Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series. Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8). Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld). Second Preferred Shares There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil). E) Issued and Outstanding – Warrants Outstanding, Beginning of Year Issued Under the Arrangement (Note 5) Exercised Outstanding, End of Year The exercise price of the Cenovus warrants is $6.54 per share. 2022 2021 Number of Warrants (thousands) 65,119 — (9,399) 55,720 Number of Warrants (thousands) — 65,433 (314) 65,119 Amount 215 — (31) 184 Amount — 216 (1) 215 140 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 F) Paid in Surplus Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs. Retained Earnings Prior Stock-Based to Ovintiv Split Compensation Common Shares As at December 31, 2020 Stock-Based Compensation Expense Purchase of Common Shares Under NCIBs Common Shares Issued on Exercise of Stock Options As at December 31, 2021 Stock-Based Compensation Expense Purchase of Common Shares Under NCIBs Common Shares Issued on Exercise of Stock Options As at December 31, 2022 33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) As at December 31, 2020 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2021 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2022 34. STOCK-BASED COMPENSATION PLANS A) Employee Stock Options 4,086 4,086 — — — — — — 4,086 (10) 47 (9) 28 96 (25) 99 305 14 — (1) 318 10 — (32) 296 27 — — 27 2 — 29 (120) (120) — — — — — (1,571) (1,691) 758 (129) — 629 713 — 1,342 Total 4,391 14 (120) (1) 4,284 10 (1,571) (32) 2,691 Total 775 (82) (9) 684 811 (25) 1,470 Pension and Other Post- Retirement Private Equity Benefits Instruments Foreign Currency Translation Adjustment 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. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 D) Issued and Outstanding – Preferred Shares NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 F) Paid in Surplus For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 – $519 million). Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs. As at December 31, 2020 Stock-Based Compensation Expense Purchase of Common Shares Under NCIBs Common Shares Issued on Exercise of Stock Options As at December 31, 2021 Stock-Based Compensation Expense Purchase of Common Shares Under NCIBs Common Shares Issued on Exercise of Stock Options As at December 31, 2022 Retained Earnings Prior to Ovintiv Split Stock-Based Compensation Common Shares 4,086 — — — 4,086 — — — 4,086 305 14 — (1) 318 10 — (32) 296 — — (120) — (120) — (1,571) — (1,691) 33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Pension and Other Post- Retirement Benefits (10) Private Equity Instruments 27 47 (9) 28 96 (25) 99 — — 27 2 — 29 Foreign Currency Translation Adjustment 758 (129) — 629 713 — 1,342 As at December 31, 2020 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2021 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2022 34. STOCK-BASED COMPENSATION PLANS A) Employee Stock Options Total 4,391 14 (120) (1) 4,284 10 (1,571) (32) 2,691 Total 775 (82) (9) 684 811 (25) 1,470 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. CENOVUS ENERGY 2022 ANNUAL REPORT | 141 As at December 31, 2022 Series 1 First Preferred Shares Series 2 First Preferred Shares (1) Series 3 First Preferred Shares Series 5 First Preferred Shares Series 7 First Preferred Shares Dividend Reset Date Dividend Rate (thousands) March 31, 2026 Quarterly December 31, 2024 March 31, 2025 June 30, 2025 2.58 % 5.86 % 4.69 % 4.59 % 3.94 % Number of Preferred Shares 10,740 1,260 10,000 8,000 6,000 (1) The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June 30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 – 1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023. Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter, holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter, holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such option to convert their shares into the other series. Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1), 3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6) and 3.52 percent (series 8). Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and withheld). Second Preferred Shares E) Issued and Outstanding – Warrants There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil). Outstanding, Beginning of Year Issued Under the Arrangement (Note 5) Exercised Outstanding, End of Year The exercise price of the Cenovus warrants is $6.54 per share. 2022 2021 Number of Warrants (thousands) 65,119 — (9,399) 55,720 Number of Warrants (thousands) — 65,433 (314) 65,119 Amount 215 — (31) 184 Amount — 216 (1) 215 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Stock Options With Associated Net Settlement Rights The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 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: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The following tables summarize the information related to the Cenovus replacement stock options: Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) (1) Expected volatility has been based on historical share volatility of the Company. The following tables summarize information related to the NSRs: 1.84 % 0.72 % 24.72 % 5.75 Number of Stock Options with Associated Net Settlement Rights (thousands) 27,233 2,031 (11,599) (258) (3,058) 14,349 Weighted Average Exercise Price ($) 13.06 19.94 12.77 9.75 22.25 12.38 For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2022 Range of Exercise Price ($) 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 Number of Stock Options with Associated Net Settlement Rights (thousands) 5,234 6,229 2,834 52 14,349 Outstanding Weighted Average Remaining Contractual Life (Years) 4.88 3.80 4.26 6.69 4.30 Exercisable Number of Stock Options with Associated Net Settlement Rights (thousands) 1,474 4,280 919 — 6,673 Weighted Average Exercise Price ($) 8.76 12.01 19.71 22.37 12.38 Weighted Average Exercise Price ($) 8.94 12.13 19.36 — 12.42 Cenovus Replacement Stock Options For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised with a weighted average exercise price of $14.98 and settled for 81 thousand common shares. The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black- Scholes-Merton valuation model. 142 | CENOVUS ENERGY 2022 ANNUAL REPORT Stock Options Exercise Price Number of Cenovus Replacement (thousands) 12,256 (6,145) (186) (2,458) 3,467 Weighted Average ($) 15.21 16.12 15.85 20.59 9.99 Exercisable Outstanding Weighted Average Remaining Contractual 2,065 124 14 594 524 146 3,467 1.63 1.36 0.47 1.04 0.20 0.58 1.25 Number of Cenovus Replacement Stock Options (thousands) Number of Cenovus Weighted Average Replacement Weighted Average Life Exercise Price Stock Options Exercise Price (Years) (thousands) ($) 3.54 6.06 12.88 18.35 21.77 27.88 9.99 742 59 14 594 524 146 2,079 ($) 3.54 6.06 12.88 18.35 21.77 27.88 14.21 For the year ended December 31, 2022 Outstanding, Beginning of Year Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2022 Range of Exercise Price ($) 3.00 to 4.99 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 B) Performance Share Units For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Cancelled Vested and Paid Out Units in Lieu of Dividends Outstanding, End of Year 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 $216 million as at December 31, 2022, (December 31, 2021 – $61 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, 2022. The following table summarizes the information related to the PSUs held by Cenovus employees: Number of Performance Share Units (thousands) 7,163 3,226 (1,413) (465) 167 8,678 The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 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: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Stock Options With Associated Net Settlement Rights Risk-Free Interest Rate Expected Dividend Yield Expected Volatility (1) Expected Life (years) (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 with Associated Net Weighted Average Settlement Rights Exercise Price (thousands) 27,233 2,031 (11,599) (258) (3,058) 14,349 Exercisable Number of Stock Options 1.84 % 0.72 % 24.72 % 5.75 ($) 13.06 19.94 12.77 9.75 22.25 12.38 ($) 8.94 12.13 19.36 — 12.42 Number of Stock Options with Associated Net Settlement Rights (thousands) 5,234 6,229 2,834 52 14,349 Outstanding Weighted Average Remaining Contractual (Years) 4.88 3.80 4.26 6.69 4.30 Weighted with Associated Average Net Settlement Weighted Average Life Exercise Price Rights Exercise Price ($) 8.76 12.01 19.71 22.37 12.38 (thousands) 1,474 4,280 919 — 6,673 For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2022 Range of Exercise Price ($) 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 Cenovus Replacement Stock Options For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised with a weighted average exercise price of $14.98 and settled for 81 thousand common shares. The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black- Scholes-Merton valuation model. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 The following tables summarize the information related to the Cenovus replacement stock options: Number of Cenovus Replacement Stock Options (thousands) 12,256 (6,145) (186) (2,458) 3,467 Weighted Average Exercise Price ($) 15.21 16.12 15.85 20.59 9.99 Exercisable Number of Cenovus Replacement Stock Options (thousands) 742 59 14 594 524 146 2,079 Weighted Average Exercise Price ($) 3.54 6.06 12.88 18.35 21.77 27.88 14.21 Outstanding Weighted Average Remaining Contractual Life (Years) 1.63 1.36 0.47 1.04 0.20 0.58 1.25 Number of Cenovus Replacement Stock Options (thousands) 2,065 124 14 594 524 146 3,467 Weighted Average Exercise Price ($) 3.54 6.06 12.88 18.35 21.77 27.88 9.99 For the year ended December 31, 2022 Outstanding, Beginning of Year Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2022 Range of Exercise Price ($) 3.00 to 4.99 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 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 $216 million as at December 31, 2022, (December 31, 2021 – $61 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, 2022. The following table summarizes the information related to the PSUs held by Cenovus employees: For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year Number of Performance Share Units (thousands) 7,163 3,226 (1,413) (465) 167 8,678 CENOVUS ENERGY 2022 ANNUAL REPORT | 143 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 C) Restricted Share Units Cenovus 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. The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 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, the intrinsic value of vested RSUs was $nil as at December 31, 2022. The following table summarizes the information related to the RSUs held by Cenovus employees: For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Vested and Paid Out Cancelled Units in Lieu of Dividends Outstanding, End of Year D) Deferred Share Units Number of Restricted Share Units (thousands) 6,025 3,161 (2,230) (430) 129 6,655 Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock 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: 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, 50, 75 or 100 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 recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 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. The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees: For the year ended December 31, 2022 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year E) Total Stock-Based Compensation For the years ended December 31, Stock Options With Associated Net Settlement Rights Cenovus Replacement Stock Options Performance Share Units Restricted Share Units Deferred Share Units Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation 144 | CENOVUS ENERGY 2022 ANNUAL REPORT Number of Deferred Share Units (thousands) 1,256 161 316 30 (257) 1,506 2022 2021 2020 15 53 183 100 22 373 — 373 14 26 56 48 15 159 8 167 11 — 19 23 (4) 49 16 65 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 35. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Post-Employment Benefits Stock-Based Compensation (Note 34) Other Incentive Benefits (Recovery) Termination Benefits options, PSUs, RSUs and DSUs. 36. RELATED PARTY TRANSACTIONS A) Key Management Compensation For the years ended December 31, Salaries, Director Fees and Other Short-Term Benefits Post-Employment Benefits Stock-Based Compensation Other Incentive Benefits Termination Benefits 2022 1,246 92 373 (9) 27 1,729 2022 40 4 140 — 3 187 2021 1,327 89 159 201 180 1,956 2021 69 4 72 4 3 152 2020 605 33 49 (4) 9 692 2020 21 3 15 1 6 46 Post-employment benefits represent the present value of future pension benefits earned during the year. B) Other Related Party Transactions Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). 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 on a cost recovery basis with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction costs and management services (2021 – $243 million). 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, 2022, the Company incurred costs of $263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million). 37. 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, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. 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, net investment in finance leases and long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 C) Restricted Share Units Cenovus 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. The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 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, the intrinsic value of vested RSUs was $nil as at December 31, 2022. The following table summarizes the information related to the RSUs held by Cenovus employees: NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 35. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Post-Employment Benefits Stock-Based Compensation (Note 34) Other Incentive Benefits (Recovery) Termination Benefits 2022 1,246 92 373 (9) 27 1,729 2021 1,327 89 159 201 180 1,956 2020 605 33 49 (4) 9 692 Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs. 36. 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, Salaries, Director Fees and Other Short-Term Benefits Post-Employment Benefits Stock-Based Compensation Other Incentive Benefits Termination Benefits 2022 40 4 140 — 3 187 2021 69 4 72 4 3 152 2020 21 3 15 1 6 46 Post-employment benefits represent the present value of future pension benefits earned during the year. B) Other Related Party Transactions Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). 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 on a cost recovery basis with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction costs and management services (2021 – $243 million). 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, 2022, the Company incurred costs of $263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million). 37. 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, risk management assets and liabilities, investments in the equity of companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and other liabilities. 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, net investment in finance leases and long-term receivables approximate their carrying amount due to the specific non-tradeable nature of these instruments. CENOVUS ENERGY 2022 ANNUAL REPORT | 145 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, 50, 75 or 100 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 recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 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. The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees: For the year ended December 31, 2022 Outstanding, Beginning of Year Granted Cancelled Vested and Paid Out Units in Lieu of Dividends Outstanding, End of Year D) Deferred Share Units For the year ended December 31, 2022 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year E) Total Stock-Based Compensation For the years ended December 31, Stock Options With Associated Net Settlement Rights Cenovus Replacement Stock Options Performance Share Units Restricted Share Units Deferred Share Units Stock-Based Compensation Expense (Recovery) Stock-Based Compensation Costs Capitalized Total Stock-Based Compensation Number of Restricted Share Units (thousands) 6,025 3,161 (2,230) (430) 129 6,655 Number of Deferred Share Units (thousands) 1,256 161 316 30 (257) 1,506 11 — 19 23 (4) 49 16 65 2022 2021 2020 15 53 183 100 22 373 — 373 14 26 56 48 15 159 8 167 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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, 2022, the carrying value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value – $12.4 billion, fair value – $13.7 billion). The Company classifies certain private equity investments as 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 investments classified as FVOCI: from January 1 to December 31: Fair Value, Beginning of Year Acquisition (Note 5) Changes in Fair Value (1) Fair Value, End of Year (1) Changes in fair value are recorded in OCI. 2022 2021 53 — 2 55 52 1 — 53 Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value on the Consolidated Balance Sheets in other assets. Fair value was 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, condensate, natural gas, and refined product futures, as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards, and options to manage commodity and foreign exchange exposures, as well as interest rate swaps. Crude oil, natural gas, condensate, refined product contracts and power swaps 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 rate contracts, and interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2). The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques. Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk management. Summary of Risk Management Positions As at December 31, Crude Oil, Natural Gas, Condensate and Refined Products Power Swap Contracts Renewable Power Contracts Foreign Exchange Rate Contracts 2022 Risk Management Asset Liability 2 1 90 — 93 40 7 — — 47 Net (38) (6) 90 — 46 2021 Risk Management Asset Liability 46 — — 2 48 116 — — — 116 Net (70) — — 2 (68) Level 2 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. Level 3 prices are sourced from partially observable data used in internal valuations. 146 | CENOVUS ENERGY 2022 ANNUAL REPORT 2022 (44) 90 46 2022 (68) — (5) (1,641) 1,762 (2) 46 2021 (68) — (68) 2021 (53) (14) — (995) 993 1 (68) Net (68) — (68) The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value: The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 As at December 31, Level 2 – Prices Sourced From Observable Data or Market Corroboration Level 3 – Prices Sourced From Partially Observable Data Fair Value of Contracts, Beginning of Year Acquisition (Note 5) Change in Fair Value of Contracts in Place at Beginning of Year Change in Fair Value of Contracts Entered Into During the Year Fair Value of Contracts Realized During the Year Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 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. 2022 Risk Management 2021 Risk Management As at December 31, Asset Liability Net Asset Liability Recognized Risk Management Positions Gross Amount Amount Offset Net Amount 153 (60) 93 107 (60) 47 46 — 46 263 (215) 48 331 (215) 116 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. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 – $114 million). C) Fair Value of Contingent Payments The variable payment (Level 3) associated with the Sunrise Acquisition 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 discounted using a credit-adjusted risk-free rate. Fair value of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable payment is $600 million. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 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, 2022, the carrying value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value – $12.4 billion, fair value – $13.7 billion). The Company classifies certain private equity investments as 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 investments classified as FVOCI: The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value: As at December 31, Level 2 – Prices Sourced From Observable Data or Market Corroboration Level 3 – Prices Sourced From Partially Observable Data 2022 (44) 90 46 2021 (68) — (68) 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: Fair Value, Beginning of Year Acquisition (Note 5) Changes in Fair Value (1) Fair Value, End of Year (1) Changes in fair value are recorded in OCI. 2022 2021 53 — 2 55 52 1 — 53 Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value on the Consolidated Balance Sheets in other assets. Fair value was 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, condensate, natural gas, and refined product futures, as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards, and options to manage commodity and foreign exchange exposures, as well as interest rate swaps. Crude oil, natural gas, condensate, refined product contracts and power swaps 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 rate contracts, and interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves (Level 2). The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have experience in fair value techniques. Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets (for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk management. Summary of Risk Management Positions As at December 31, Crude Oil, Natural Gas, Condensate and Refined Products Power Swap Contracts Renewable Power Contracts Foreign Exchange Rate Contracts 2022 Risk Management Asset Liability 2 1 90 — 93 40 7 — — 47 Net (38) (6) 90 — 46 2021 Risk Management Asset Liability 46 — — 2 48 116 — — — 116 Net (70) — — 2 (68) Level 2 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. Level 3 prices are sourced from partially observable data used in internal valuations. Fair Value of Contracts, Beginning of Year Acquisition (Note 5) Change in Fair Value of Contracts in Place at Beginning of Year Change in Fair Value of Contracts Entered Into During the Year Fair Value of Contracts Realized During the Year Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts Fair Value of Contracts, End of Year 2022 (68) — (5) (1,641) 1,762 (2) 46 2021 (53) (14) — (995) 993 1 (68) 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. 2022 Risk Management 2021 Risk Management As at December 31, Asset Liability Net Asset Liability Recognized Risk Management Positions Gross Amount Amount Offset Net Amount 153 (60) 93 107 (60) 47 46 — 46 263 (215) 48 331 (215) 116 Net (68) — (68) 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. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 – $114 million). C) Fair Value of Contingent Payments The variable payment (Level 3) associated with the Sunrise Acquisition 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 discounted using a credit-adjusted risk-free rate. Fair value of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable payment is $600 million. CENOVUS ENERGY 2022 ANNUAL REPORT | 147 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 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, 2022 WCS Forward Prices WTI Option Volatility Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility Sensitivity Range Increase Decrease ± $10.00 per barrel ± ten percent ± five percent (68) (1) — 157 4 — The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022. As at December 31, 2021 WCS Forward Prices Sensitivity Range ± $5.00 per barrel Increase (45) Decrease 45 The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in 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, Realized (Gain) Loss Unrealized (Gain) Loss (1) (Gain) Loss on Risk Management 2022 1,762 (126) 1,636 2021 993 2 995 2020 252 56 308 (1) All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a realized net loss related to these positions of $467 million. Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. 38. RISK MANAGEMENT Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, commodity power prices 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, natural gas, condensate, refined products, and power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or to offset select carbon emissions. The Company entered into risk management positions to 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 future cash flows. To manage exposure to interest rate volatility, the Company periodically enters 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. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts. As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil, natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding. 148 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Net Fair Value of Risk Management Positions As at December 31, 2022 Futures Contracts Related to Blending (4) WTI Fixed – Sell WTI Fixed – Buy Power Swap Contacts Renewable Power Contracts Other Financial Positions (5) Total Fair Value Notional Volumes (1)(2) Weighted Average Price (1) (2) Fair Value Asset (Liability) Terms (3) 3.2 MMbbls 2.3 MMbbls January 2023 - June 2024 US$80.35/bbl February 2023 - June 2024 US$79.93/bbl 1 — (6) 90 (39) 46 (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) (4) Contract terms represent various individual contracts with different terms, and range from one month to eighteen months. Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure. (5) Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the Company’s U.S. manufacturing and marketing activities. A) Commodity Price, Foreign Exchange and Interest Rate Risk i) 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. The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially mitigate 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. The Company has used commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas commodity price risk. ii) Foreign Exchange Risk (December 31, 2021 – US$7.4 billion). iii) Interest Rate 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. 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 (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt 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, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil). NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 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: Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022. Sensitivity Range Increase Decrease ± $10.00 per barrel ± ten percent ± five percent (68) (1) — 157 4 — Sensitivity Range ± $5.00 per barrel Increase (45) Decrease 45 The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income D) Earnings Impact of (Gains) Losses From Risk Management Positions (1) All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a realized net loss related to these positions of $467 million. Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative 2022 1,762 (126) 1,636 2021 993 2 995 2020 252 56 308 As at December 31, 2022 WCS Forward Prices WTI Option Volatility As at December 31, 2021 WCS Forward Prices tax. For the years ended December 31, Realized (Gain) Loss Unrealized (Gain) Loss (1) (Gain) Loss on Risk Management instrument relates. 38. RISK MANAGEMENT Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates, commodity power prices 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, natural gas, condensate, refined products, and power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or to offset select carbon emissions. The Company entered into risk management positions to 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 future cash flows. To manage exposure to interest rate volatility, the Company periodically enters 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. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs, power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts. As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil, natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Net Fair Value of Risk Management Positions As at December 31, 2022 Futures Contracts Related to Blending (4) WTI Fixed – Sell WTI Fixed – Buy Power Swap Contacts Renewable Power Contracts Other Financial Positions (5) Total Fair Value Notional Volumes (1)(2) Weighted Average Price (1) (2) Fair Value Asset (Liability) Terms (3) 3.2 MMbbls 2.3 MMbbls January 2023 - June 2024 US$80.35/bbl February 2023 - June 2024 US$79.93/bbl 1 — (6) 90 (39) 46 (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. Contract terms represent various individual contracts with different terms, and range from one month to eighteen months. Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure. (3) (4) (5) Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts, reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the Company’s U.S. manufacturing and marketing activities. A) Commodity Price, Foreign Exchange and Interest Rate Risk i) 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. The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially mitigate 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. The Company has used commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate its natural gas commodity price risk. ii) 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. 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 (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt (December 31, 2021 – US$7.4 billion). iii) 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, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil). CENOVUS ENERGY 2022 ANNUAL REPORT | 149 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities C) Liquidity Risk 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, 2022 Sensitivity Range Increase Decrease ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges Crude Oil Commodity Price WCS and Condensate Differential Price (1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production WCS (Hardisty) Differential Price ± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production Refined Products Commodity Price ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges Natural Gas Basis Price Power Commodity Price ± US$0.50/MCF Applied to Natural Gas Basis Hedges ± C$20.00/Megawatt Hour Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate 1 13 (1) (2) 1 113 14 (1) (13) 1 2 (1) (113) (17) (1) Excludes WCS (Hardisty) differential. As at December 31, 2021 Crude Oil Commodity Price WCS and Condensate Differential Price Refined Products Commodity Price U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate ± US$5.00/bbl Applied to WTI, Condensate and Related Hedges ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production ± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges (225) 4 (2) 11 225 (4) 2 (12) Undiscounted cash outflows relating to financial liabilities are: Sensitivity Range Increase Decrease US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market 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, $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate 2022 246 (246) 2021 372 (372) Management believes the fluctuations identified in the table above are a reasonable measure of volatility. As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates. B) 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, which is 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 its 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, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent). 150 | CENOVUS ENERGY 2022 ANNUAL REPORT 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 26, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle 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, 2022, the Company’s sources of capital $4.5 billion in cash and cash equivalents. $5.5 billion available on its committed credit facility. $1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from included: • • • • • WRB. conditions. As at December 31, 2022 Accounts Payable and Accrued Liabilities Short-Term Borrowings (1) Long-Term Debt (1) Contingent Payments Lease Liabilities (1) As at December 31, 2021 Accounts Payable and Accrued Liabilities Short-Term Borrowings (1) Long-Term Debt (1) Contingent Payments Lease Liabilities (1) A) Working Capital As at December 31, Total Current Assets Total Current Liabilities Working Capital 1 Year 6,124 115 401 271 426 1 Year 6,353 79 561 238 453 Years 2 and 3 Years 4 and 5 Thereafter Years 2 and 3 Years 4 and 5 Thereafter — — 983 167 746 — — 1,608 — 794 — — 2,014 — 596 — — 2,603 — 634 — — — — — — 11,196 2,889 14,892 3,192 Total 6,124 115 14,594 438 4,657 Total 6,353 79 19,664 238 5,073 (1) Principal and interest, including current portion if applicable. 39. SUPPLEMENTARY CASH FLOW INFORMATION As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million (December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million). 2022 12,430 8,021 4,409 2021 11,988 7,305 4,683 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities C) Liquidity Risk 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: Sensitivity Range Increase Decrease As at December 31, 2022 Crude Oil Commodity Price WCS and Condensate Differential Price (1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production WCS (Hardisty) Differential Price ± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production Refined Products Commodity Price ± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges ± US$10.00/bbl Applied to WTI, Condensate and Related Hedges Natural Gas Basis Price Power Commodity Price ± US$0.50/MCF Applied to Natural Gas Basis Hedges ± C$20.00/Megawatt Hour Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate (1) Excludes WCS (Hardisty) differential. As at December 31, 2021 Crude Oil Commodity Price ± US$5.00/bbl Applied to WTI, Condensate and Related Hedges WCS and Condensate Differential Price ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production Refined Products Commodity Price ± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate Sensitivity Range Increase Decrease In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have 1 13 (1) (2) 1 113 14 (225) 4 (2) 11 2022 246 (246) (1) (13) 1 2 (1) (113) (17) 225 (4) 2 (12) 2021 372 (372) resulted in a change to the foreign exchange (gain) loss as follows: As at December 31, $0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate $0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate Management believes the fluctuations identified in the table above are a reasonable measure of volatility. As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains unchanged from the respective balance sheet dates. B) 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, which is 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 its 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, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent). 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 26, over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle 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, 2022, the Company’s sources of capital included: • • • • • $4.5 billion in cash and cash equivalents. $5.5 billion available on its committed credit facility. $1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB. 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, 2022 Accounts Payable and Accrued Liabilities Short-Term Borrowings (1) Long-Term Debt (1) Contingent Payments Lease Liabilities (1) 1 Year 6,124 115 401 271 426 Years 2 and 3 Years 4 and 5 Thereafter — — 983 167 746 — — 2,014 — 596 — — 11,196 — 2,889 As at December 31, 2021 1 Year Years 2 and 3 Years 4 and 5 Thereafter Accounts Payable and Accrued Liabilities Short-Term Borrowings (1) Long-Term Debt (1) Contingent Payments Lease Liabilities (1) 6,353 79 561 238 453 — — 1,608 — 794 — — 2,603 — 634 — — 14,892 — 3,192 (1) Principal and interest, including current portion if applicable. Total 6,124 115 14,594 438 4,657 Total 6,353 79 19,664 238 5,073 39. SUPPLEMENTARY CASH FLOW INFORMATION A) Working Capital As at December 31, Total Current Assets Total Current Liabilities Working Capital 2022 12,430 8,021 4,409 2021 11,988 7,305 4,683 As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million (December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million). CENOVUS ENERGY 2022 ANNUAL REPORT | 151 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Changes in non-cash working capital is as follows: For the years ended December 31, Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Accounts Payable and Accrued Liabilities Income Tax Payable Total Change in Non-Cash Working Capital Net Change in Non-Cash Working Capital – Operating Activities Net Change in Non-Cash Working Capital – Investing Activities Total Change in Non-Cash Working Capital For the years ended December 31, Interest Paid Interest Received Income Taxes Paid B) Reconciliation of Liabilities 2022 838 (58) (143) (524) 1,000 1,113 575 538 1,113 2022 647 78 723 2021 (953) (1) (1,646) 1,645 87 (868) (1,227) 359 (868) 2021 811 24 209 The following table provides a reconciliation of liabilities to cash flows arising from financing activities: Dividends Payable Short-Term Borrowings Long-Term Debt As at December 31, 2019 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Revolving Long-Term Debt Issuance of Long-Term Debt (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Terminations Base Dividends Declared on Common Shares Exchange Rate Movements and Other As at December 31, 2020 — — — — — — (77) — — — — — — 77 — — — 117 — — — — — — — — — — — — 4 121 6,699 — (220) 1,326 (112) — — (25) 5 — — — — — (232) 7,441 2020 77 (12) 450 (338) (17) 160 198 (38) 160 2020 381 5 18 Lease Liabilities 1,916 — — — — (197) — — — 49 (2) (2) (1) — (6) 1,757 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 As at December 31, 2020 Acquisition (Note 5) Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Revolving Long-Term Debt Issuance of Long-Term Debt (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Dividends Paid on Preferred Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Termination Dividends Declared on Preferred Shares Exchange Rate Movements and Other As at December 31, 2021 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Variable Dividends Paid on Common Shares Dividends Paid on Preferred Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Terminations Base Dividends Declared on Common Shares Variable Dividends Declared on Common Shares Dividends Declared on Preferred Shares Exchange Rate Movements and Other As at December 31, 2022 Dividends Payable Short-Term Borrowings Long-Term Lease Liabilities 1,757 1,441 (176) (34) — — — — — — — — — — — — — — 34 — — — — — (682) (219) (26) — — — — — — 682 219 35 — 9 Debt 7,441 6,602 — (350) 1,557 (2,870) 121 (59) (57) 12,385 (4,149) (29) (28) — — — — — — — — — — — — — — — — — — — — — — 121 40 (77) — — — — — — — — — — — — — — — (5) 79 34 — — — — — — — — — — — — — — 2 (300) — — — — — — — — 110 22 (4) (1) (58) — — (10) 2,957 (302) — — — — — — — 25 83 7 (5) — — — 71 115 2,836 512 8,691 Transfers to Liabilities Related to Assets Held for Sale Base Dividends Declared on Common Shares 176 152 | CENOVUS ENERGY 2022 ANNUAL REPORT NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 Changes in non-cash working capital is as follows: For the years ended December 31, Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories Accounts Payable and Accrued Liabilities Income Tax Payable Total Change in Non-Cash Working Capital Net Change in Non-Cash Working Capital – Operating Activities Net Change in Non-Cash Working Capital – Investing Activities Total Change in Non-Cash Working Capital For the years ended December 31, Interest Paid Interest Received Income Taxes Paid B) Reconciliation of Liabilities As at December 31, 2019 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Revolving Long-Term Debt Issuance of Long-Term Debt (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Terminations Base Dividends Declared on Common Shares Exchange Rate Movements and Other As at December 31, 2020 2022 838 (58) (143) (524) 1,000 1,113 575 538 1,113 2022 647 78 723 117 — — — — — — — — — — — — — 4 2021 (953) (1) (1,646) 1,645 87 (868) (1,227) 359 (868) 2021 811 24 209 Debt 6,699 — (220) 1,326 (112) (25) — — 5 — — — — — (232) 7,441 2020 77 (12) 450 (338) (17) 160 198 (38) 160 2020 381 5 18 (197) — — — — — — — 49 (2) (2) (1) — (6) 121 1,757 (77) — — — — — — — — — — — — 77 — — The following table provides a reconciliation of liabilities to cash flows arising from financing activities: Dividends Payable Short-Term Borrowings Long-Term Lease Liabilities 1,916 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 As at December 31, 2020 Acquisition (Note 5) Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Revolving Long-Term Debt Issuance of Long-Term Debt (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Dividends Paid on Preferred Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Termination Transfers to Liabilities Related to Assets Held for Sale Base Dividends Declared on Common Shares Dividends Declared on Preferred Shares Exchange Rate Movements and Other As at December 31, 2021 Changes From Financing Cash Flows: Net Issuance (Repayment) of Short-Term Borrowings (Repayment) of Long-Term Debt Principal Repayment of Leases Base Dividends Paid on Common Shares Variable Dividends Paid on Common Shares Dividends Paid on Preferred Shares Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance Costs Lease Additions Lease Modifications Lease Re-measurements Lease Terminations Base Dividends Declared on Common Shares Variable Dividends Declared on Common Shares Dividends Declared on Preferred Shares Exchange Rate Movements and Other As at December 31, 2022 Dividends Payable Short-Term Borrowings Long-Term Debt — — — — — — — (176) (34) — — — — — — — 176 34 — — — — — (682) (219) (26) — — — — — — 682 219 35 — 9 121 40 (77) — — — — — — — — — — — — — — — (5) 79 34 — — — — — — — — — — — — — — 2 115 7,441 6,602 — (350) 1,557 (2,870) — — — 121 (59) — — — — — — — (57) 12,385 — (4,149) — — — — (29) (28) — — — — — — — 512 8,691 Lease Liabilities 1,757 1,441 — — — — (300) — — — — 110 22 (4) (1) (58) — — (10) 2,957 — — (302) — — — — — 25 83 7 (5) — — — 71 2,836 CENOVUS ENERGY 2022 ANNUAL REPORT | 153 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 40. COMMITMENTS AND CONTINGENCIES A) Commitments Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below: As at December 31, 2022 Transportation and Storage (1) Product Purchases Real Estate (2) Obligation to Fund Equity- Accounted Affiliate (3) Other Long-Term Commitments (4) Total Payments As at December 31, 2021 Transportation and Storage (1) Product Purchases (5) Real Estate (2) Obligation to Fund Equity- Accounted Affiliate (3) Other Long-Term Commitments (4) Total Payments 1 Year 1,747 1,626 48 92 381 3,894 1 Year 1,677 1,684 44 68 436 3,909 2 Years 2,011 1,509 50 105 90 3,765 2 Years 1,958 1,682 43 85 83 3 Years 1,542 4 Years 1,416 922 50 96 75 2,685 3 Years 1,853 1,593 52 99 72 922 50 96 74 2,558 4 Years 1,488 731 54 90 63 5 Years Thereafter 1,360 922 54 91 65 13,005 3,457 604 143 395 2,492 17,604 5 Years Thereafter 1,350 731 57 90 81 13,244 4,204 658 210 366 3,851 3,669 2,426 2,309 18,682 Total 21,081 9,358 856 623 1,080 32,998 Total 21,570 10,625 908 642 1,101 34,846 (1) (2) (3) (4) (5) Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract. 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. Relates to funding obligations for HCML. Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment. Previously included in transportation and storage. As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term transportation and storage commitments (December 31, 2021 – $2.6 billion). There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security for financial and performance conditions under certain contracts. B) Contingencies Legal Proceedings Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its Consolidated Financial Statements. Income Tax Matters The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the provision for taxes is adequate. 154 | CENOVUS ENERGY 2022 ANNUAL REPORT Cash From (Used in) Operating Activities and Adjusted Funds Flow 2,782 3,339 4,678 3,464 2,600 14,263 9,373 2,970 4,089 2,979 1,365 2,184 11,403 5,919 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Upstream Oil Sands (1) Conventional Offshore (2) Total Upstream Revenue Downstream Canadian Manufacturing (3) U.S. Manufacturing Total Downstream Revenue Corporate and Eliminations (3) Total Revenues Operating Margin Upstream Oil Sands (1) Conventional Offshore (2) Total Upstream Operating Margin (4) Downstream Canadian Manufacturing (3) U.S. Manufacturing Total Downstream Operating Margin (4) Total Operating Margin (5) Cash From (Used in) Operating Activities Deduct (Add Back): Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (5) Per Share - Basic (5) Per Share - Diluted (5) Net Earnings (Loss) Net Earnings (Loss) Per Share - Basic Per Share - Diluted Capital Investment Oil Sands (1) Conventional Offshore Asia Pacific (2) Atlantic Total Offshore Manufacturing Canadian Manufacturing (3) U.S. Manufacturing Total Manufacturing Corporate Total Capital Investment (1) (2) (4) (5) change. Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 5,947 1,061 424 7,432 1,772 6,608 8,380 (1,749) 14,063 7,642 942 428 8,557 990 556 9,012 10,103 2,168 8,719 10,887 (2,428) 17,471 2,245 8,474 10,719 (1,657) 19,165 1,639 248 337 2,224 278 280 558 (49) 673 2,346 1.22 1.19 784 0.40 0.39 681 156 3 82 85 40 285 325 27 1,274 2,220 290 339 2,849 246 244 490 (55) 1,193 2,951 1.53 1.49 1,609 0.83 0.81 360 67 3 78 81 24 300 324 34 866 2,921 434 476 3,831 54 793 847 (27) (92) 3,098 1.57 1.53 2,432 1.23 1.19 376 33 2 89 91 38 267 305 17 822 (1,630) 16,198 (1,706) 13,726 8,136 1,041 535 9,712 1,607 6,509 8,116 2,199 263 458 2,920 121 423 544 5,983 953 486 7,422 1,856 6,154 8,010 1,890 260 408 139 (97) 42 30,282 4,034 1,943 36,259 7,792 30,310 38,102 (7,464) 66,897 20,631 3,085 1,674 25,390 6,215 20,043 26,258 (5,291) 46,357 8,979 1,235 1,610 699 1,740 2,439 6,365 803 1,420 8,588 573 212 785 2,558 11,824 (19) (1,199) 2,583 1.30 1.27 (35) 271 1,948 0.97 0.97 (150) 575 10,978 5.63 5.47 (102) (1,227) 7,248 3.59 3.54 1,625 0.81 0.79 (408) (0.21) (0.21) 6,450 3.29 3.20 587 0.27 0.27 375 88 — 53 53 15 207 222 8 746 402 87 — 45 45 23 252 275 26 835 1,792 344 1,019 222 8 302 310 117 1,059 1,176 86 3,708 21 154 175 68 995 1,063 84 2,563 On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”). Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture ("HCML"), which is accounted for using the equity method. For the year ended December 31, 2022, our portion of the capital investment in HCML was $74 million (December 31, 2021 – $8 million). (3) In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment.Comparative periods have been re-presented to reflect this Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2022 40. COMMITMENTS AND CONTINGENCIES A) Commitments Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities less than one year are excluded from the table below. Future payments for the Company’s commitments are below: As at December 31, 2022 Transportation and Storage (1) Product Purchases Real Estate (2) Obligation to Fund Equity- Accounted Affiliate (3) Other Long-Term Commitments (4) Total Payments As at December 31, 2021 Transportation and Storage (1) Product Purchases (5) Real Estate (2) Obligation to Fund Equity- Accounted Affiliate (3) Other Long-Term Commitments (4) Total Payments 1 Year 1,747 1,626 48 92 381 3,894 1 Year 1,677 1,684 44 68 436 3,909 2 Years 2,011 1,509 50 105 90 3,765 2 Years 1,958 1,682 43 85 83 3 Years 1,542 4 Years 1,416 5 Years Thereafter 922 50 96 75 2,685 3 Years 1,853 1,593 52 99 72 2,558 4 Years 1,488 922 50 96 74 731 54 90 63 2,492 17,604 5 Years Thereafter 1,360 922 54 91 65 1,350 731 57 90 81 13,005 3,457 604 143 395 13,244 4,204 658 210 366 Total 21,081 9,358 856 623 1,080 32,998 Total 21,570 10,625 908 642 1,101 34,846 (1) Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract. (2) Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for 3,851 3,669 2,426 2,309 18,682 which a provision has been provided. Relates to funding obligations for HCML. (3) (4) (5) Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment. Previously included in transportation and storage. As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term transportation and storage commitments (December 31, 2021 – $2.6 billion). There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security for financial and performance conditions under certain contracts. B) Contingencies Legal Proceedings Consolidated Financial Statements. Income Tax Matters provision for taxes is adequate. Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are continually changing. As a result, there are usually a number of tax matters under review. Management believes that the SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Upstream Oil Sands (1) Conventional Offshore (2) Total Upstream Revenue Downstream Canadian Manufacturing (3) U.S. Manufacturing Total Downstream Revenue Corporate and Eliminations (3) Total Revenues Operating Margin Upstream Oil Sands (1) Conventional Offshore (2) Total Upstream Operating Margin (4) Downstream Canadian Manufacturing (3) U.S. Manufacturing Total Downstream Operating Margin (4) Total Operating Margin (5) Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 5,947 1,061 424 7,432 1,772 6,608 8,380 (1,749) 14,063 7,642 942 428 9,012 2,168 8,719 10,887 (2,428) 17,471 8,557 990 556 10,103 2,245 8,474 10,719 (1,657) 19,165 8,136 1,041 535 9,712 1,607 6,509 8,116 (1,630) 16,198 5,983 953 486 7,422 1,856 6,154 8,010 (1,706) 13,726 1,639 248 337 2,224 278 280 558 2,782 2,220 290 339 2,849 246 244 490 3,339 2,921 434 476 3,831 54 793 847 4,678 2,199 263 458 2,920 121 423 544 3,464 1,890 260 408 2,558 139 (97) 42 2,600 30,282 4,034 1,943 36,259 7,792 30,310 38,102 (7,464) 66,897 8,979 1,235 1,610 11,824 699 1,740 2,439 14,263 20,631 3,085 1,674 25,390 6,215 20,043 26,258 (5,291) 46,357 6,365 803 1,420 8,588 573 212 785 9,373 Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash From (Used in) Operating Activities Deduct (Add Back): Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (5) Per Share - Basic (5) Per Share - Diluted (5) (49) 673 2,346 1.22 1.19 2,970 Net Earnings (Loss) Net Earnings (Loss) Per Share - Basic Per Share - Diluted Capital Investment Oil Sands (1) Conventional Offshore Asia Pacific (2) Atlantic Total Offshore Manufacturing Canadian Manufacturing (3) U.S. Manufacturing Total Manufacturing Corporate Total Capital Investment 784 0.40 0.39 681 156 3 82 85 40 285 325 27 1,274 4,089 2,979 1,365 2,184 11,403 5,919 (55) 1,193 2,951 1.53 1.49 1,609 0.83 0.81 360 67 3 78 81 24 300 324 34 866 (27) (92) 3,098 1.57 1.53 2,432 1.23 1.19 376 33 2 89 91 38 267 305 17 822 (19) (1,199) 2,583 1.30 1.27 (35) 271 1,948 0.97 0.97 (150) 575 10,978 5.63 5.47 (102) (1,227) 7,248 3.59 3.54 1,625 0.81 0.79 (408) (0.21) (0.21) 6,450 3.29 3.20 587 0.27 0.27 375 88 — 53 53 15 207 222 8 746 402 87 — 45 45 23 252 275 26 835 1,792 344 1,019 222 8 302 310 117 1,059 1,176 86 3,708 21 154 175 68 995 1,063 84 2,563 (1) (2) (3) (4) (5) On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”). Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture ("HCML"), which is accounted for using the equity method. For the year ended December 31, 2022, our portion of the capital investment in HCML was $74 million (December 31, 2021 – $8 million). In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment.Comparative periods have been re-presented to reflect this change. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. CENOVUS ENERGY 2022 ANNUAL REPORT | 155 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics Financial Metrics Free Funds Flow (1) Excess Free Funds Flow (1) (2) Long-Term Debt Net Debt Net Debt to Adjusted Funds Flow (3) (times) Net Debt to Adjusted EBITDA (times) Income Tax & Exchange Rates Effective Tax Rates Using: Net Earnings (Loss) Foreign Exchange Rates US$ per C$1 Average Period End RMB per C$1 Average Common Share Information Commons Shares Outstanding (millions) Period End Average - Basic Average - Diluted Base Dividends ($ per share) Variable Dividends ($ per share) Closing Price Toronto Stock Exchange (C$ per share) New York Stock Exchange (US$ per share) Total Share Volume Traded (millions) Selected Average Benchmark Prices Crude Oil Prices US$/bbl Dated Brent West Texas Intermediate (“WTI”) Differential Dated Brent - WTI Western Canadian Select at Hardisty (“WCS”) Differential WTI - WCS Mixed Sweet Blend Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount Synthetic @ Edmonton Differential WTI - Synthetic (Premium)/Discount C$/bbl WCS Synthetic @ Edmonton Mixed Sweet Blend Refining Benchmarks (US$/bbl) Chicago 3-2-1 Crack Spreads (4) Group 3 3-2-1 Crack Spreads (4) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO 7A Monthly Index (5) (C$/Mcf) NYMEX (6) (US$/Mcf) Differential NYMEX - AECO (US$/Mcf) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties Upstream Production Volumes Crude Oil and Natural Gas Liquids (Mbbls/d) Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 1,072 786 8,691 4,282 0.4 0.3 2,085 1,756 8,774 5,280 0.5 0.4 2,276 2,020 11,228 7,535 0.8 0.6 1,837 2,615 11,744 8,407 1.0 0.8 1,113 1,169 12,385 9,591 1.3 1.2 7,270 n/a 8,691 4,282 0.4 0.3 4,685 n/a 12,385 9,591 1.3 1.2 26.1% 55.4% Lloydminster Conventional Heavy Oil 0.737 0.738 0.766 0.730 0.783 0.776 0.790 0.800 0.794 0.789 0.769 0.738 0.798 0.789 5.241 5.246 5.180 5.014 5.073 5.170 5.147 1,909.2 1,917.0 1,967.2 0.105 0.114 1,922.7 1,927.9 1,978.7 0.105 — 1,949.6 1,971.3 2,029.4 0.105 — 1,981.7 1,989.9 2,041.5 0.035 — 2,001.2 2,012.3 2,012.3 0.035 — 1,909.2 1,951.3 2,006.1 0.350 0.114 2,001.2 2,016.2 2,045.1 0.088 — 26.27 19.41 21.22 15.37 24.49 19.01 20.84 16.68 15.51 12.28 26.27 19.41 15.51 12.28 1,026.6 1,287.4 1,682.8 1,883.5 1,485.7 5,880.3 5,689.1 88.71 82.65 6.06 56.99 25.66 81.04 83.40 (0.75) 86.79 (4.14) 77.42 117.87 110.06 32.87 29.99 8.54 5.58 6.26 2.15 100.85 91.55 9.30 71.69 19.86 89.51 87.26 4.29 100.34 (8.79) 93.53 130.90 116.80 38.87 38.57 8.11 5.81 8.20 3.75 113.78 108.41 5.37 95.61 12.80 107.91 108.34 0.07 114.46 (6.05) 122.07 146.13 137.77 46.50 44.35 7.80 6.28 7.17 2.25 101.41 94.29 7.12 79.76 14.53 91.33 96.09 (1.80) 93.05 1.24 101.01 117.84 115.66 18.35 19.94 6.44 4.59 4.95 1.32 79.73 77.19 2.54 62.55 14.64 74.09 79.13 (1.94) 75.40 1.79 78.71 94.94 93.29 16.06 15.82 6.11 4.94 5.83 1.91 101.19 94.23 6.96 76.01 18.22 92.45 93.78 0.45 98.66 (4.43) 98.51 128.19 120.07 34.15 33.21 7.72 5.56 6.64 2.36 70.73 67.91 2.82 54.87 13.04 64.03 68.20 (0.29) 66.28 1.63 68.73 83.04 80.23 17.54 17.82 6.76 3.56 3.84 1.00 Oil Sands Bitumen Foster Creek Christina Lake Sunrise (1) Lloydminster Thermal Tucker (2) Oil Sands Heavy Crude Oil Total Oil Sands Conventional (3) Light Crude Oil Natural Gas Liquids (4) Total Conventional Offshore Natural Gas Liquids Asia Pacific - China Asia Pacific - Indonesia (5) Offshore Light Crude Oil Atlantic Total Offshore Total Liquids Production Conventional Natural Gas (MMcf/d) Oil Sands Conventional (3) (6) Offshore Asia Pacific - China Asia Pacific - Indonesia (5) Total Conventional Natural Gas Production Total Production (7) (MBOE/d) Oil Sands Foster Creek Christina Lake Sunrise (1) Lloydminster Thermal Lloydminster Conventional Heavy Oil Conventional (3) Offshore Asia Pacific - China Asia Pacific - Indonesia (5) Atlantic Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 195.9 250.3 44.8 102.5 — 15.8 609.3 6.8 26.1 32.9 9.9 2.5 10.3 22.7 664.9 11.9 555.3 222.8 62.0 852.0 806.9 32.9% 26.5% 7.6% 12.6% 12.0% 15.9% 5.8% 34.2% 1.1% 182.4 252.8 30.9 102.1 — 16.8 585.0 6.9 19.9 26.8 9.5 2.7 9.1 21.3 633.1 12.6 596.1 215.5 44.5 868.7 777.9 33.6% 34.8% 9.6% 9.4% 11.3% 15.9% 5.7% 40.0% 1.8 % 187.8 228.8 25.3 98.4 — 16.4 556.7 7.5 24.7 32.2 9.4 2.6 13.3 25.3 614.2 12.0 601.2 224.9 44.1 882.2 761.5 32.1% 31.9% 6.9% 9.8% 6.5% 13.6% 5.4% 52.2% (8.0)% 197.9 254.1 24.1 96.3 6.4 16.2 595.0 8.2 24.5 32.7 10.6 2.5 13.7 26.8 654.5 12.8 555.0 257.7 39.8 865.3 798.6 24.4% 29.1% 5.5% 11.3% 9.3% 15.9% 5.4% 45.7% 6.1% 211.8 250.9 25.2 99.0 19.1 18.9 624.9 7.2 22.5 29.7 10.4 2.7 10.6 23.7 678.3 12.4 574.3 254.2 42.6 883.5 825.3 24.5% 26.4% 5.3% 10.1% 10.0% 10.7% 6.6% 45.3% 6.0% 191.0 246.5 31.3 99.9 1.6 16.3 586.6 7.5 23.8 31.3 9.8 2.6 11.6 24.0 641.9 12.3 576.1 230.1 47.6 866.1 786.2 30.5% 30.8% 7.3% 10.6% 9.9% 15.4% 5.6% 42.7% (0.5)% 179.9 236.8 25.9 97.7 21.0 20.2 581.5 8.4 25.6 34.0 10.0 2.7 14.1 26.8 642.3 12.6 597.6 244.1 41.2 895.5 791.5 21.0% 23.6% 4.1% 9.1% 8.7% 10.3% 5.9% 23.1% 6.7% Effective Royalty Rates (8) (Excluding Realized (Gain) Loss on Risk Management) On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise. Sale of the Tucker asset closed on January 31, 2022. Sale of the Wembley assets closed on February 28, 2022. Natural gas liquids include condensate volumes. (1) (2) (3) (4) (5) using the equity method in the Consolidated Financial Statements. Production volumes and associated royalty rates reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for (6) Includes production used for internal consumption by the Oil Sands segment of 561 MMcf per day and 520 MMcf per day for the three months ended and twelve months ended December 31, 2022, respectively (533 MMcf per day and 517 MMcf per day for the three and twelve months months ended December 31, 2021, respectively). (7) 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. (8) Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation. (1) (2) (3) (4) (5) (6) Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. New financial metric as of June 30, 2022. New financial metric as of March 31, 2022. 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. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator. Alberta Energy Company ("AECO") natural gas monthly index. New York Mercantile Exchange (“NYMEX”) natural gas monthly index. 156 | CENOVUS ENERGY 2022 ANNUAL REPORT SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Before Royalties Upstream Production Volumes Crude Oil and Natural Gas Liquids (Mbbls/d) Oil Sands Bitumen Foster Creek Christina Lake Sunrise (1) Lloydminster Thermal Tucker (2) Oil Sands Heavy Crude Oil Lloydminster Conventional Heavy Oil Total Oil Sands Conventional (3) Light Crude Oil Natural Gas Liquids (4) Total Conventional Offshore Natural Gas Liquids Asia Pacific - China Asia Pacific - Indonesia (5) Offshore Light Crude Oil Atlantic Total Offshore Total Liquids Production Conventional Natural Gas (MMcf/d) Oil Sands Conventional (3) (6) Offshore Asia Pacific - China Asia Pacific - Indonesia (5) Total Conventional Natural Gas Production Total Production (7) (MBOE/d) Financial Statistics Financial Metrics Free Funds Flow (1) Excess Free Funds Flow (1) (2) Long-Term Debt Net Debt Net Debt to Adjusted Funds Flow (3) (times) Net Debt to Adjusted EBITDA (times) Income Tax & Exchange Rates Effective Tax Rates Using: Net Earnings (Loss) Foreign Exchange Rates US$ per C$1 Average Period End RMB per C$1 Average Common Share Information Commons Shares Outstanding (millions) Period End Average - Basic Average - Diluted Base Dividends ($ per share) Variable Dividends ($ per share) Closing Price Toronto Stock Exchange (C$ per share) New York Stock Exchange (US$ per share) Total Share Volume Traded (millions) Selected Average Benchmark Prices Crude Oil Prices US$/bbl Dated Brent West Texas Intermediate (“WTI”) Differential Dated Brent - WTI Western Canadian Select at Hardisty (“WCS”) Differential WTI - WCS Mixed Sweet Blend Condensate (C5 @ Edmonton) Differential WTI - Condensate (Premium)/Discount Synthetic @ Edmonton Differential WTI - Synthetic (Premium)/Discount C$/bbl WCS Synthetic @ Edmonton Mixed Sweet Blend Refining Benchmarks (US$/bbl) Chicago 3-2-1 Crack Spreads (4) Group 3 3-2-1 Crack Spreads (4) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO 7A Monthly Index (5) (C$/Mcf) NYMEX (6) (US$/Mcf) Differential NYMEX - AECO (US$/Mcf) New financial metric as of June 30, 2022. New financial metric as of March 31, 2022. (1) (2) (3) (4) (5) (6) Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 1,072 786 8,691 4,282 0.4 0.3 2022 2,085 1,756 8,774 5,280 0.5 0.4 2022 2022 2021 2,276 2,020 11,228 7,535 0.8 0.6 1,837 2,615 11,744 8,407 1.0 0.8 1,113 1,169 12,385 9,591 1.3 1.2 2022 7,270 n/a 8,691 4,282 0.4 0.3 2021 4,685 n/a 12,385 9,591 1.3 1.2 26.1% 55.4% 0.737 0.738 0.766 0.730 0.783 0.776 0.790 0.800 0.794 0.789 0.769 0.738 0.798 0.789 5.241 5.246 5.180 5.014 5.073 5.170 5.147 1,909.2 1,917.0 1,967.2 0.105 0.114 1,922.7 1,927.9 1,978.7 0.105 — 1,949.6 1,971.3 2,029.4 0.105 — 1,981.7 1,989.9 2,041.5 0.035 — 2,001.2 2,012.3 2,012.3 0.035 — 1,909.2 1,951.3 2,006.1 0.350 0.114 2,001.2 2,016.2 2,045.1 0.088 — 26.27 19.41 21.22 15.37 24.49 19.01 20.84 16.68 15.51 12.28 26.27 19.41 15.51 12.28 1,026.6 1,287.4 1,682.8 1,883.5 1,485.7 5,880.3 5,689.1 88.71 82.65 6.06 56.99 25.66 81.04 83.40 (0.75) 86.79 (4.14) 77.42 117.87 110.06 32.87 29.99 8.54 5.58 6.26 2.15 100.85 91.55 9.30 71.69 19.86 89.51 87.26 4.29 100.34 (8.79) 93.53 130.90 116.80 38.87 38.57 8.11 5.81 8.20 3.75 113.78 108.41 5.37 95.61 12.80 107.91 108.34 0.07 114.46 (6.05) 122.07 146.13 137.77 46.50 44.35 7.80 6.28 7.17 2.25 101.41 94.29 7.12 79.76 14.53 91.33 96.09 (1.80) 93.05 1.24 101.01 117.84 115.66 18.35 19.94 6.44 4.59 4.95 1.32 79.73 77.19 2.54 62.55 14.64 74.09 79.13 (1.94) 75.40 1.79 78.71 94.94 93.29 16.06 15.82 6.11 4.94 5.83 1.91 101.19 94.23 6.96 76.01 18.22 92.45 93.78 0.45 98.66 (4.43) 98.51 128.19 120.07 34.15 33.21 7.72 5.56 6.64 2.36 70.73 67.91 2.82 54.87 13.04 64.03 68.20 (0.29) 66.28 1.63 68.73 83.04 80.23 17.54 17.82 6.76 3.56 3.84 1.00 Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. 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. The market crack spreads do not precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator. Alberta Energy Company ("AECO") natural gas monthly index. New York Mercantile Exchange (“NYMEX”) natural gas monthly index. Effective Royalty Rates (8) (Excluding Realized (Gain) Loss on Risk Management) Oil Sands Foster Creek Christina Lake Sunrise (1) Lloydminster Thermal Lloydminster Conventional Heavy Oil Conventional (3) Offshore Asia Pacific - China Asia Pacific - Indonesia (5) Atlantic 32.9% 26.5% 7.6% 12.6% 12.0% 15.9% 5.8% 34.2% 1.1% 195.9 250.3 44.8 102.5 — 15.8 609.3 6.8 26.1 32.9 9.9 2.5 10.3 22.7 664.9 11.9 555.3 222.8 62.0 852.0 806.9 Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 182.4 252.8 30.9 102.1 — 16.8 585.0 6.9 19.9 26.8 9.5 2.7 9.1 21.3 633.1 12.6 596.1 215.5 44.5 868.7 777.9 33.6% 34.8% 9.6% 9.4% 11.3% 15.9% 5.7% 40.0% 1.8 % 187.8 228.8 25.3 98.4 — 16.4 556.7 7.5 24.7 32.2 9.4 2.6 13.3 25.3 614.2 12.0 601.2 224.9 44.1 882.2 761.5 32.1% 31.9% 6.9% 9.8% 6.5% 13.6% 5.4% 52.2% (8.0)% 197.9 254.1 24.1 96.3 6.4 16.2 595.0 8.2 24.5 32.7 10.6 2.5 13.7 26.8 654.5 12.8 555.0 257.7 39.8 865.3 798.6 24.4% 29.1% 5.5% 11.3% 9.3% 15.9% 5.4% 45.7% 6.1% 211.8 250.9 25.2 99.0 19.1 18.9 624.9 7.2 22.5 29.7 10.4 2.7 10.6 23.7 678.3 12.4 574.3 254.2 42.6 883.5 825.3 24.5% 26.4% 5.3% 10.1% 10.0% 10.7% 6.6% 45.3% 6.0% 191.0 246.5 31.3 99.9 1.6 16.3 586.6 7.5 23.8 31.3 9.8 2.6 11.6 24.0 641.9 12.3 576.1 230.1 47.6 866.1 786.2 30.5% 30.8% 7.3% 10.6% 9.9% 15.4% 5.6% 42.7% (0.5)% 179.9 236.8 25.9 97.7 21.0 20.2 581.5 8.4 25.6 34.0 10.0 2.7 14.1 26.8 642.3 12.6 597.6 244.1 41.2 895.5 791.5 21.0% 23.6% 4.1% 9.1% 8.7% 10.3% 5.9% 23.1% 6.7% (1) (2) (3) (4) (5) (6) (7) (8) On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise. Sale of the Tucker asset closed on January 31, 2022. Sale of the Wembley assets closed on February 28, 2022. Natural gas liquids include condensate volumes. Production volumes and associated royalty rates reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements. Includes production used for internal consumption by the Oil Sands segment of 561 MMcf per day and 520 MMcf per day for the three months ended and twelve months ended December 31, 2022, respectively (533 MMcf per day and 517 MMcf per day for the three and twelve months months ended December 31, 2021, respectively). 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. Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation. CENOVUS ENERGY 2022 ANNUAL REPORT | 157 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Netbacks (1) Operating Statistics - Netbacks (1) Oil Sands Foster Creek Bitumen ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Christina Lake Bitumen ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Sunrise Bitumen ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Other Oil Sands (2) Bitumen & Heavy Crude Oil ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Total Oil Sands (3) ($/BOE) Sales Price Royalties Transportation and Blending Operating Netback Conventional (3) Total Conventional ($/BOE) Sales Price Royalties Transportation and Blending Operating Netback Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 75.43 19.87 15.06 11.44 29.06 64.07 15.14 6.95 9.75 32.23 57.20 3.54 10.97 15.55 27.14 69.24 8.16 3.59 23.84 33.65 68.06 14.40 9.08 13.52 31.06 48.09 6.05 4.08 11.67 26.29 89.42 26.01 11.96 13.46 37.99 81.18 26.13 6.02 9.19 39.84 79.96 6.42 13.17 17.74 42.63 84.95 7.52 3.57 20.87 52.99 84.29 21.26 7.72 13.40 41.91 44.07 5.81 2.43 11.77 24.06 122.03 35.72 10.37 14.31 61.63 114.10 34.04 6.75 11.77 61.54 128.54 7.81 12.48 21.22 87.03 127.98 11.76 3.28 24.58 88.36 119.98 28.94 7.51 15.70 67.83 57.11 7.34 2.97 10.02 36.78 101.06 21.56 9.90 11.19 58.41 94.18 24.65 6.37 9.22 53.94 102.01 4.98 13.15 16.95 66.93 90.75 9.19 3.51 20.63 57.42 95.90 19.72 7.23 12.51 56.44 42.84 6.29 3.18 11.33 22.04 72.86 15.67 9.27 10.31 37.61 65.49 15.67 6.32 8.82 34.68 68.62 3.06 10.36 14.03 41.17 70.23 7.95 3.31 18.02 40.95 69.00 13.22 6.76 11.76 37.26 39.07 4.01 1.50 10.96 22.60 97.27 25.80 11.78 12.59 47.10 88.02 24.84 6.51 9.94 46.73 86.05 5.38 12.26 17.49 50.92 92.82 9.12 3.49 22.45 57.76 91.70 20.96 7.89 13.75 49.10 48.15 6.38 3.16 11.18 27.43 66.50 11.75 10.51 10.74 33.50 60.22 12.69 6.19 8.24 33.10 67.10 2.23 12.14 17.15 35.58 62.20 6.40 4.01 16.64 35.15 62.82 10.38 7.23 11.52 33.69 31.20 3.06 1.53 10.66 15.95 Offshore Asia Pacific - China Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/mcf) Asia Pacific - China Total (2) ($/BOE) Asia Pacific - Indonesia (3) Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/mcf) Asia Pacific - Indonesia Total (2) ($/BOE) Asia Pacific - Total (3) Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/mcf) Asia Pacific - Total (2) ($/BOE) Sales Price Royalties Operating Sales Price Royalties Operating Sales Price Royalties Operating Netback Sales Price Royalties Operating Sales Price Royalties Operating Sales Price Royalties Operating Netback Sales Price Royalties Operating Sales Price Royalties Operating Sales Price Royalties Operating Netback Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 115.56 66.96 13.76 137.20 81.50 12.08 148.31 110.02 13.66 119.91 70.28 13.54 108.68 68.21 12.23 130.62 82.56 13.24 97.62 5.49 5.36 13.16 0.77 0.89 82.89 4.80 5.36 72.73 9.09 1.99 2.32 66.50 22.74 13.88 29.88 12.27 1.03 1.20 79.37 8.64 7.19 63.54 100.28 112.96 108.05 5.68 6.66 12.58 0.72 1.13 80.68 4.63 6.73 69.32 6.94 1.18 2.01 66.97 26.80 12.05 28.12 11.62 0.80 1.28 78.19 8.65 7.70 61.84 6.42 5.86 12.43 0.66 0.98 82.25 4.44 5.89 71.92 8.34 2.40 2.29 76.06 39.69 13.70 22.67 11.76 0.94 1.20 81.16 10.65 7.27 63.24 6.15 4.68 12.61 0.67 0.78 82.09 4.43 4.66 73.00 9.67 3.46 2.25 74.82 34.23 13.51 27.08 12.22 1.04 0.97 81.04 8.76 5.95 66.33 101.25 17.91 7.06 108.39 22.33 7.85 120.75 29.27 7.58 110.30 18.29 6.36 90.71 5.30 5.19 12.39 0.85 0.80 77.57 5.15 4.88 67.54 9.16 2.95 2.01 69.72 31.58 12.08 26.06 94.41 18.25 6.64 11.93 1.15 0.97 76.34 9.28 6.01 61.05 104.67 5.93 5.61 12.69 0.70 0.94 81.99 4.57 5.62 71.80 8.53 2.20 2.22 70.66 30.19 13.32 27.15 110.05 21.84 7.20 11.98 0.96 1.16 79.96 9.16 7.00 63.80 76.51 4.38 5.18 11.90 0.70 0.85 72.44 4.25 5.10 63.09 92.36 30.99 9.55 8.96 1.45 1.59 64.52 14.93 9.55 40.04 79.83 9.95 6.10 11.48 0.81 0.95 71.19 5.94 5.80 59.45 (1) (2) (3) The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this Supplemental. Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil. Sale of the Tucker asset closed on January 31, 2022. 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. The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this 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 Supplemental. (1) (2) (3) on a 6:1 basis is not an accurate reflection of value. Consolidated Financial Statements. Per unit values reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the 158 | CENOVUS ENERGY 2022 ANNUAL REPORT SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Netbacks (1) Operating Statistics - Netbacks (1) Transportation and Blending Transportation and Blending Oil Sands Foster Creek Bitumen ($/bbl) Sales Price Royalties Operating Netback Christina Lake Bitumen ($/bbl) Sunrise Bitumen ($/bbl) Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Supplemental. (1) (2) (3) Transportation and Blending Other Oil Sands (2) Bitumen & Heavy Crude Oil ($/bbl) Transportation and Blending Total Oil Sands (3) ($/BOE) Transportation and Blending Conventional (3) Total Conventional ($/BOE) Transportation and Blending Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 122.03 101.06 128.54 102.01 75.43 19.87 15.06 11.44 29.06 64.07 15.14 6.95 9.75 32.23 57.20 3.54 10.97 15.55 27.14 69.24 8.16 3.59 23.84 33.65 68.06 14.40 9.08 13.52 31.06 48.09 6.05 4.08 11.67 26.29 89.42 26.01 11.96 13.46 37.99 81.18 26.13 6.02 9.19 39.84 79.96 6.42 13.17 17.74 42.63 84.95 7.52 3.57 20.87 52.99 84.29 21.26 7.72 13.40 41.91 44.07 5.81 2.43 11.77 24.06 35.72 10.37 14.31 61.63 114.10 34.04 6.75 11.77 61.54 7.81 12.48 21.22 87.03 127.98 11.76 3.28 24.58 88.36 119.98 28.94 7.51 15.70 67.83 57.11 7.34 2.97 10.02 36.78 21.56 9.90 11.19 58.41 94.18 24.65 6.37 9.22 53.94 4.98 13.15 16.95 66.93 90.75 9.19 3.51 20.63 57.42 95.90 19.72 7.23 12.51 56.44 42.84 6.29 3.18 11.33 22.04 72.86 15.67 9.27 10.31 37.61 65.49 15.67 6.32 8.82 34.68 68.62 3.06 10.36 14.03 41.17 70.23 7.95 3.31 18.02 40.95 69.00 13.22 6.76 11.76 37.26 39.07 4.01 1.50 10.96 22.60 97.27 25.80 11.78 12.59 47.10 88.02 24.84 6.51 9.94 46.73 86.05 5.38 12.26 17.49 50.92 92.82 9.12 3.49 22.45 57.76 91.70 20.96 7.89 13.75 49.10 48.15 6.38 3.16 11.18 27.43 66.50 11.75 10.51 10.74 33.50 60.22 12.69 6.19 8.24 33.10 67.10 2.23 12.14 17.15 35.58 62.20 6.40 4.01 16.64 35.15 62.82 10.38 7.23 11.52 33.69 31.20 3.06 1.53 10.66 15.95 Offshore Asia Pacific - China Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/mcf) Sales Price Royalties Operating Asia Pacific - China Total (2) ($/BOE) Sales Price Royalties Operating Netback Asia Pacific - Indonesia (3) Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/mcf) Sales Price Royalties Operating Asia Pacific - Indonesia Total (2) ($/BOE) Sales Price Royalties Operating Netback Asia Pacific - Total (3) Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/mcf) Sales Price Royalties Operating Asia Pacific - Total (2) ($/BOE) Sales Price Royalties Operating Netback Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 97.62 5.49 5.36 13.16 0.77 0.89 82.89 4.80 5.36 72.73 100.28 5.68 6.66 112.96 6.42 5.86 108.05 6.15 4.68 12.58 0.72 1.13 80.68 4.63 6.73 69.32 12.43 0.66 0.98 82.25 4.44 5.89 71.92 12.61 0.67 0.78 82.09 4.43 4.66 73.00 90.71 5.30 5.19 12.39 0.85 0.80 77.57 5.15 4.88 67.54 104.67 5.93 5.61 12.69 0.70 0.94 81.99 4.57 5.62 71.80 115.56 66.96 13.76 137.20 81.50 12.08 148.31 110.02 13.66 119.91 70.28 13.54 108.68 68.21 12.23 130.62 82.56 13.24 9.09 1.99 2.32 66.50 22.74 13.88 29.88 6.94 1.18 2.01 66.97 26.80 12.05 28.12 8.34 2.40 2.29 76.06 39.69 13.70 22.67 9.67 3.46 2.25 74.82 34.23 13.51 27.08 101.25 17.91 7.06 108.39 22.33 7.85 120.75 29.27 7.58 110.30 18.29 6.36 12.27 1.03 1.20 79.37 8.64 7.19 63.54 11.62 0.80 1.28 78.19 8.65 7.70 61.84 11.76 0.94 1.20 81.16 10.65 7.27 63.24 12.22 1.04 0.97 81.04 8.76 5.95 66.33 9.16 2.95 2.01 69.72 31.58 12.08 26.06 94.41 18.25 6.64 11.93 1.15 0.97 76.34 9.28 6.01 61.05 8.53 2.20 2.22 70.66 30.19 13.32 27.15 110.05 21.84 7.20 11.98 0.96 1.16 79.96 9.16 7.00 63.80 76.51 4.38 5.18 11.90 0.70 0.85 72.44 4.25 5.10 63.09 92.36 30.99 9.55 8.96 1.45 1.59 64.52 14.93 9.55 40.04 79.83 9.95 6.10 11.48 0.81 0.95 71.19 5.94 5.80 59.45 The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil. Sale of the Tucker asset closed on January 31, 2022. 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. (1) (2) (3) The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this Supplemental. 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. Per unit values reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the Consolidated Financial Statements. CENOVUS ENERGY 2022 ANNUAL REPORT | 159 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Downstream U.S. Manufacturing Total Crude Oil Processed (Mbbls/d) Heavy Crude Oil Light/Medium Crude Oil Crude Oil Throughput Capacity (1) (Mbbls/d) Crude Utilization (2) (%) Refining Margin (3) (4) ($/bbl) Unit Operating Expense (4) (5) ($/bbl) Refining (6) Lima Refinery Throughput (Mbbls/d) WRB Throughput (7) (Mbbls/d) Toledo Refinery Throughput (7) (8) (Mbbls/d) Production (Mbbls/d) Canada Transportation Fuels Distillate Total Transportation Fuels Synthetic Crude Oil Total Refined Production Asphalt Other Ethanol Total Canada United States Transportation Fuels Gasoline Distillate Total Transportation Fuels Other Total United States Total Downstream Production Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 379.2 127.4 251.8 552.5 75% 24.70 16.88 162.6 216.4 0.2 10.5 10.5 45.1 14.3 25.3 95.2 5.0 194.4 148.0 342.4 52.5 394.9 495.1 435.0 145.2 289.8 502.5 87% 18.98 14.90 164.2 224.2 46.6 10.5 10.5 47.7 15.5 25.5 99.2 5.1 211.3 173.6 384.9 77.8 462.7 567.0 376.4 106.5 269.9 502.5 75% 44.81 19.13 159.4 190.0 27.0 7.0 7.0 43.5 9.2 20.3 80.0 4.6 84.6 176.3 144.7 321.0 71.5 392.5 477.1 403.7 153.8 249.9 502.5 80% 28.26 13.59 136.1 195.5 72.1 9.4 9.4 47.8 15.1 27.1 99.4 4.9 104.3 217.5 147.3 364.8 65.8 430.6 534.9 361.6 155.8 205.8 502.5 72% 15.63 16.88 59.5 227.3 74.8 10.8 10.8 55.3 15.6 28.0 109.7 5.2 114.9 192.1 131.4 323.5 56.4 379.9 494.8 100.2 104.3 400.8 116.1 284.7 552.5 80% 28.70 16.04 157.9 206.6 36.3 9.3 9.3 46.0 13.5 24.6 93.4 4.9 98.3 200.0 153.5 353.5 67.0 420.5 518.8 401.5 138.7 262.8 502.5 80% 14.25 12.09 126.9 204.7 69.9 10.0 10.0 54.9 15.5 27.5 107.9 4.2 112.1 205.3 145.3 350.6 68.0 418.6 530.7 (1) (2) (3) (4) (5) (6) (7) (8) The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d. Based on crude oil name plate capacity. Excludes the permitted capacity of Superior. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. On April 26, 2018, the Superior refinery experienced an incident while preparing for a major turnaround and was taken out of operation. Represents Cenovus's 50 percent interest in Wood River, Borger and Toledo refinery operations. On September 20, 2022, there was an incident at the Toledo refinery. It remains shut down in a safe state. Operating Statistics - Netbacks (1) Offshore (continued) Atlantic Light Crude Oil ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Total Upstream (2) (3) Total Upstream ($/BOE) Sales Price Royalties Transportation and Blending Operating Netback Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 128.76 1.39 5.05 72.43 49.89 158.42 2.86 5.86 47.23 102.47 146.38 (11.50) 2.40 30.57 124.91 130.87 7.81 3.51 36.06 83.49 103.63 6.20 3.62 32.61 61.20 140.65 (0.74) 3.79 42.03 95.57 69.77 14.19 8.57 9.59 37.42 83.43 19.69 7.01 10.87 45.86 114.40 25.89 6.81 10.61 71.09 94.12 18.61 6.71 10.06 58.74 70.02 12.76 6.02 9.36 41.88 90.34 19.56 7.28 10.29 53.21 91.01 6.07 3.02 28.34 53.58 62.99 9.80 6.33 9.82 37.04 (1) (2) (3) The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this Supplemental. 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. Excludes natural gas volumes used for internal consumption by the Oil Sands segment. For the three months ended September 30, 2022, the total upstream netback has been represented. Downstream Canadian Manufacturing Total Heavy Crude Oil Throughput (Mbbls/d) Heavy Crude Oil Throughput Capacity (Mbbls/d) Crude Utilization (1) (%) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (3) (4) ($/bbl) Lloydminster Upgrader Production (Mbbls/d) Heavy Crude Oil Throughput (5) (Mbbls/d) Upgrading Differential ($/bbl) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (4) ($/bbl) Lloydminster Refinery Production (Mbbls/d) Heavy Crude Oil Throughput (Mbbls/d) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (4) ($/bbl) Ethanol Ethanol Production (millions of litres/d) Rail Volumes Loaded (6) (Mbbls/d) Sales at U.S. Locations (7) (Mbbls/d) Fuel (8) Number of Fuel Outlets (average) Fuel Sales Volume (millions of litres/d) Fuel Sales per Outlet (thousands of litres/d) Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 94.3 110.5 85% 46.21 13.78 69.2 68.4 45.30 52.60 12.83 26.0 25.9 29.36 16.30 0.8 2.8 0.7 170 4.8 28.5 98.5 110.5 89% 38.88 11.72 71.9 71.3 39.36 38.33 11.25 27.3 27.2 40.33 12.96 0.8 1.4 1.4 454 6.9 15.2 80.9 110.5 73% 24.87 19.93 63.7 64.6 26.47 25.54 16.26 16.3 16.3 22.22 36.14 0.7 — — 511 6.4 12.6 98.1 110.5 89% 24.28 10.99 71.9 70.7 20.50 26.98 10.59 27.5 27.4 17.33 12.01 0.8 3.0 8.5 515 6.6 12.8 108.3 110.5 98% 19.07 7.99 81.7 80.4 19.71 21.26 7.44 27.9 27.9 12.77 9.81 0.8 9.6 8.1 522 7.1 13.5 92.9 110.5 84% 33.92 13.91 69.1 68.7 32.84 36.04 12.65 24.3 24.2 27.91 17.49 0.8 1.8 2.6 413 6.2 15.0 106.5 110.5 96% 18.09 7.55 80.2 79.0 16.83 18.96 7.28 27.6 27.5 15.60 8.35 0.7 12.1 12.3 531 6.9 13.0 (1) (2) (3) (4) (5) (6) (7) (8) Based on crude oil name plate capacity. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Upgrader throughput includes diluent returned to the field. Volumes loaded and transported outside of Alberta, Canada. Includes sales volumes from third-party purchases. On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170 cardlock, bulk plant and travel centre locations. 160 | CENOVUS ENERGY 2022 ANNUAL REPORT The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this 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. Excludes natural gas volumes used for internal consumption by the Oil Sands segment. For the three months ended September 30, 2022, the total upstream netback has Operating Statistics - Netbacks (1) Offshore (continued) Atlantic Light Crude Oil ($/bbl) Transportation and Blending Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Supplemental. Total Upstream (2) (3) Total Upstream ($/BOE) Transportation and Blending been represented. Downstream Canadian Manufacturing Total Heavy Crude Oil Throughput (Mbbls/d) Heavy Crude Oil Throughput Capacity (Mbbls/d) Crude Utilization (1) (%) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (3) (4) ($/bbl) Lloydminster Upgrader Production (Mbbls/d) Heavy Crude Oil Throughput (5) (Mbbls/d) Upgrading Differential ($/bbl) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (4) ($/bbl) Lloydminster Refinery Production (Mbbls/d) Heavy Crude Oil Throughput (Mbbls/d) Refining Margin (2) (3) ($/bbl) Unit Operating Expense (4) ($/bbl) Ethanol Production (millions of litres/d) Volumes Loaded (6) (Mbbls/d) Sales at U.S. Locations (7) (Mbbls/d) Ethanol Rail Fuel (8) Number of Fuel Outlets (average) Fuel Sales Volume (millions of litres/d) Fuel Sales per Outlet (thousands of litres/d) Based on crude oil name plate capacity. (1) (2) (3) (1) (2) (3) (4) (5) (6) (7) (8) Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 128.76 158.42 130.87 103.63 1.39 5.05 72.43 49.89 2.86 5.86 47.23 102.47 146.38 (11.50) 2.40 30.57 124.91 7.81 3.51 36.06 83.49 94.12 18.61 6.71 10.06 58.74 6.20 3.62 32.61 61.20 70.02 12.76 6.02 9.36 41.88 140.65 (0.74) 3.79 42.03 95.57 90.34 19.56 7.28 10.29 53.21 91.01 6.07 3.02 28.34 53.58 62.99 9.80 6.33 9.82 37.04 69.77 14.19 8.57 9.59 37.42 83.43 19.69 7.01 10.87 45.86 114.40 25.89 6.81 10.61 71.09 Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2022 2022 2022 2022 2021 2022 2021 94.3 110.5 85% 46.21 13.78 69.2 68.4 45.30 52.60 12.83 26.0 25.9 29.36 16.30 0.8 2.8 0.7 170 4.8 28.5 98.5 110.5 89% 38.88 11.72 71.9 71.3 39.36 38.33 11.25 27.3 27.2 40.33 12.96 0.8 1.4 1.4 454 6.9 15.2 80.9 110.5 73% 24.87 19.93 63.7 64.6 26.47 25.54 16.26 16.3 16.3 22.22 36.14 0.7 — — 511 6.4 12.6 98.1 110.5 89% 24.28 10.99 71.9 70.7 20.50 26.98 10.59 27.5 27.4 17.33 12.01 0.8 3.0 8.5 515 6.6 12.8 108.3 110.5 98% 19.07 7.99 81.7 80.4 19.71 21.26 7.44 27.9 27.9 12.77 9.81 0.8 9.6 8.1 522 7.1 13.5 92.9 110.5 84% 33.92 13.91 69.1 68.7 32.84 36.04 12.65 24.3 24.2 27.91 17.49 0.8 1.8 2.6 413 6.2 15.0 106.5 110.5 96% 18.09 7.55 80.2 79.0 16.83 18.96 7.28 27.6 27.5 15.60 8.35 0.7 12.1 12.3 531 6.9 13.0 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Downstream U.S. Manufacturing Total Crude Oil Processed (Mbbls/d) Heavy Crude Oil Light/Medium Crude Oil Crude Oil Throughput Capacity (1) (Mbbls/d) Crude Utilization (2) (%) Refining Margin (3) (4) ($/bbl) Unit Operating Expense (4) (5) ($/bbl) Refining (6) Lima Refinery Throughput (Mbbls/d) WRB Throughput (7) (Mbbls/d) Toledo Refinery Throughput (7) (8) (Mbbls/d) Production (Mbbls/d) Canada Transportation Fuels Distillate Total Transportation Fuels Synthetic Crude Oil Asphalt Other Total Refined Production Ethanol Total Canada United States Transportation Fuels Gasoline Distillate Total Transportation Fuels Other Total United States Total Downstream Production Three Months Ended Dec. 31, 2022 Sep. 30, 2022 Jun. 30, Mar. 31, 2022 2022 Dec. 31, 2021 Twelve Months Ended Dec. 31, 2021 Dec. 31, 2022 379.2 127.4 251.8 552.5 75% 24.70 16.88 162.6 216.4 0.2 10.5 10.5 45.1 14.3 25.3 95.2 5.0 100.2 194.4 148.0 342.4 52.5 394.9 495.1 435.0 145.2 289.8 502.5 87% 18.98 14.90 164.2 224.2 46.6 10.5 10.5 47.7 15.5 25.5 99.2 5.1 104.3 211.3 173.6 384.9 77.8 462.7 567.0 376.4 106.5 269.9 502.5 75% 44.81 19.13 159.4 190.0 27.0 7.0 7.0 43.5 9.2 20.3 80.0 4.6 84.6 176.3 144.7 321.0 71.5 392.5 477.1 403.7 153.8 249.9 502.5 80% 28.26 13.59 136.1 195.5 72.1 9.4 9.4 47.8 15.1 27.1 99.4 4.9 104.3 217.5 147.3 364.8 65.8 430.6 534.9 361.6 155.8 205.8 502.5 72% 15.63 16.88 59.5 227.3 74.8 10.8 10.8 55.3 15.6 28.0 109.7 5.2 114.9 192.1 131.4 323.5 56.4 379.9 494.8 400.8 116.1 284.7 552.5 80% 28.70 16.04 157.9 206.6 36.3 9.3 9.3 46.0 13.5 24.6 93.4 4.9 98.3 200.0 153.5 353.5 67.0 420.5 518.8 401.5 138.7 262.8 502.5 80% 14.25 12.09 126.9 204.7 69.9 10.0 10.0 54.9 15.5 27.5 107.9 4.2 112.1 205.3 145.3 350.6 68.0 418.6 530.7 (1) (2) (3) (4) (5) (6) (7) (8) The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d. Based on crude oil name plate capacity. Excludes the permitted capacity of Superior. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. On April 26, 2018, the Superior refinery experienced an incident while preparing for a major turnaround and was taken out of operation. Represents Cenovus's 50 percent interest in Wood River, Borger and Toledo refinery operations. On September 20, 2022, there was an incident at the Toledo refinery. It remains shut down in a safe state. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Upgrader throughput includes diluent returned to the field. Volumes loaded and transported outside of Alberta, Canada. Includes sales volumes from third-party purchases. cardlock, bulk plant and travel centre locations. On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170 CENOVUS ENERGY 2022 ANNUAL REPORT | 161 SUPPLEMENTAL INFORMATION (unaudited) Advisory Specified Financial Measures Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by IFRS and, therefore, are considered specified financial measures. These specified financial measures may not be comparable to similar measures presented by other issuers. See the Specified Financial Measures Advisory located in our Management’s Discussion and Analysis (“MD&A”) for the periods ended March 31, 2022, June 30, 2022, September 30, 2022 and the annual MD&A for the year ended December 31, 2022 (available on SEDAR at sedar.com) for information incorporated by reference about these specified financial measures. 162 | CENOVUS ENERGY 2022 ANNUAL REPORT ADVISORY ADVISORY ADVISORY Oil and Gas Information Oil and Gas Information 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 Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be 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 misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency 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 conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that 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 the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy 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. equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Forward-looking Information Forward-looking Information Forward-looking Information This document contains forward-looking statements and other information (collectively “forward-looking information”) This document contains forward-looking statements and other information (collectively “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 about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and 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 perception of historical trends. Although the Company believes that the expectations represented by such forward-looking 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. information are reasonable, there can be no assurance that such expectations will prove to be correct. information are reasonable, there can be no assurance that such expectations will prove to be correct. This This This information information information forward-looking forward-looking forward-looking is is is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, identified by words such as “anticipate”, “believe”, “capacity”, “commit”, identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net land land land Debt targets; disciplined capital allocation; ensuring sufficient Debt targets; disciplined capital allocation; ensuring sufficient Debt targets; disciplined capital allocation; ensuring sufficient liquidity through all stages of the economic cycle; liquidity through all stages of the economic cycle; liquidity through all stages of the economic cycle; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost savings; cost structures and market optimization; savings; cost structures and market optimization; savings; cost structures and market optimization; interest expense; improving efficiencies to drive incremental interest expense; improving efficiencies to drive incremental interest expense; improving efficiencies to drive incremental capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing condensate costs associated with heavy oil condensate costs associated with heavy oil condensate costs associated with heavy oil transportation; maintaining transportation; maintaining transportation; maintaining the Company’s capital program and the Company’s capital program and the Company’s capital program and sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil differentials; partially mitigating the differentials; partially mitigating the differentials; partially mitigating the impact of exposure to various prices for commodities and associated price impact of exposure to various prices for commodities and associated price impact of exposure to various prices for commodities and associated price differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital investment, including for: portfolio adjustments, the investment, including for: portfolio adjustments, the investment, including for: portfolio adjustments, the impact of impact of impact of inflation, maintaining safe and reliable operations, inflation, maintaining safe and reliable operations, inflation, maintaining safe and reliable operations, sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas production from the MAC and MDK fields; drilling development wells and construction of production facilities and production production from the MAC and MDK fields; drilling development wells and construction of production facilities and production production from the MAC and MDK fields; drilling development wells and construction of production facilities and production therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and impact of commodity impact of commodity impact of commodity Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ the effects thereof on Cenovus. the effects thereof on Cenovus. the effects thereof on Cenovus. materially from those expressed or implied. materially from those expressed or implied. materially from those expressed or implied. SUPPLEMENTAL INFORMATION (unaudited) Advisory Specified Financial Measures Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by IFRS and, therefore, are considered specified financial measures. These specified financial measures may not be comparable to similar measures presented by other issuers. See the Specified Financial Measures Advisory located in our Management’s Discussion and Analysis (“MD&A”) for the periods ended March 31, 2022, June 30, 2022, September 30, 2022 and the annual MD&A for the year ended December 31, 2022 (available on SEDAR at sedar.com) for information incorporated by reference about these specified financial measures. is is is information information information forward-looking forward-looking forward-looking ADVISORY ADVISORY ADVISORY Oil and Gas Information Oil and Gas Information 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 Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be 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 misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency 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 conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that 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 the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy 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. equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Forward-looking Information Forward-looking Information Forward-looking Information This document contains forward-looking statements and other information (collectively “forward-looking information”) This document contains forward-looking statements and other information (collectively “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 about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and 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 perception of historical trends. Although the Company believes that the expectations represented by such forward-looking 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. information are reasonable, there can be no assurance that such expectations will prove to be correct. information are reasonable, there can be no assurance that such expectations will prove to be correct. identified by words such as “anticipate”, “believe”, “capacity”, “commit”, This identified by words such as “anticipate”, “believe”, “capacity”, “commit”, This identified by words such as “anticipate”, “believe”, “capacity”, “commit”, This “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes “potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond, including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend; allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance land to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; land to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; land to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat; restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow; reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net liquidity through all stages of the economic cycle; Debt targets; disciplined capital allocation; ensuring sufficient liquidity through all stages of the economic cycle; Debt targets; disciplined capital allocation; ensuring sufficient liquidity through all stages of the economic cycle; Debt targets; disciplined capital allocation; ensuring sufficient strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments; managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost interest expense; improving efficiencies to drive incremental savings; cost structures and market optimization; interest expense; improving efficiencies to drive incremental savings; cost structures and market optimization; interest expense; improving efficiencies to drive incremental savings; cost structures and market optimization; capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing the Company’s capital program and condensate costs associated with heavy oil the Company’s capital program and condensate costs associated with heavy oil the Company’s capital program and condensate costs associated with heavy oil sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil impact of exposure to various prices for commodities and associated price differentials; partially mitigating the impact of exposure to various prices for commodities and associated price differentials; partially mitigating the impact of exposure to various prices for commodities and associated price differentials; partially mitigating the differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated (including WTI, utilized in condensate and price risk management for refining operations) and products, including associated price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment; initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending, drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital inflation, maintaining safe and reliable operations, impact of investment, including for: portfolio adjustments, the inflation, maintaining safe and reliable operations, impact of investment, including for: portfolio adjustments, the inflation, maintaining safe and reliable operations, impact of investment, including for: portfolio adjustments, the sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas production from the MAC and MDK fields; drilling development wells and construction of production facilities and production production from the MAC and MDK fields; drilling development wells and construction of production facilities and production production from the MAC and MDK fields; drilling development wells and construction of production facilities and production impact of commodity therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the impact of commodity therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the impact of commodity therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and the effects thereof on Cenovus. the effects thereof on Cenovus. the effects thereof on Cenovus. Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ 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. materially from those expressed or implied. materially from those expressed or implied. transportation; maintaining transportation; maintaining transportation; maintaining CENOVUS ENERGY 2022 ANNUAL REPORT | 163 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 acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and throughput volumes and timing thereof; 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 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 global supply factors and heavy crude processing capacity; 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 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 ambition, and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS prices used to calculate the variable payment to BP Canada; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities. 2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel; and an exchange rate of $0.75 US$/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 COVID-19 workplace policies; the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated liabilities associated with acquisitions; 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 ambition 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 net zero ambition; 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 will remain largely tied to global supply factors and heavy crude processing capacity; 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 164 | CENOVUS ENERGY 2022 ANNUAL REPORT The following abbreviations and definitions have been used in this document: crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to recalculate the variable payment to BP Canada; 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 and Net Debt to Adjusted Funds Flow; 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 at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, 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, adverse sea conditions, extreme weather events, natural disasters, acts of activism, 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 downstream operations 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 and diverse 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 communities; 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 pursuing our ESG focus area targets, commitments and ambition 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 this MD&A, and 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 this Annual Report unless expressly incorporated by reference herein. ABBREVIATIONS AND DEFINITIONS Crude Oil bbl Mbbls/d MMbbls BOE MBOE MBOE/d MMBOE WTI WCS HSB OPEC OPEC+ FPSO barrel thousand barrels per day million barrels barrel of oil equivalent million barrels of oil equivalent West Texas Intermediate Western Canadian Select Husky Synthetic Blend Organization of Petroleum Exporting Countries OPEC and a group of 10 non-OPEC members Floating production storage and offloading unit thousand barrels of oil equivalent MMBtu million British thermal units thousand barrels of oil equivalent per day gigajoule Natural Gas Mcf MMcf thousand cubic feet million cubic feet MMcf/d million cubic feet per day billion cubic feet Bcf GJ AECO NYMEX SAGD Alberta Energy Company New York Mercantile Exchange steam-assisted gravity drainage Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets. Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling for use at the owned or operated facility. 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 acquisitions; the accuracy of any assessments undertaken in connection with acquisitions; forecast production and throughput volumes and timing thereof; 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 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 global supply factors and heavy crude processing capacity; 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 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 ambition, and the commercial viability and scalability of emission reduction strategies and related technology and products; collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS prices used to calculate the variable payment to BP Canada; market and business conditions; forecast inflation and other assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described from time to time in the filings the Company makes with securities regulatory authorities. 2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel; and an exchange rate of $0.75 US$/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 COVID-19 workplace policies; the Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated liabilities associated with acquisitions; 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 ambition 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 net zero ambition; 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 will remain largely tied to global supply factors and heavy crude processing capacity; 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; the accuracy of cost estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices used to recalculate the variable payment to BP Canada; 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 and Net Debt to Adjusted Funds Flow; 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 at facilities operated by our partners or third parties, such as blowouts, fires, explosions, railcar incidents or derailments, aviation incidents, iceberg collisions, 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, adverse sea conditions, extreme weather events, natural disasters, acts of activism, 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 downstream operations 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 and diverse 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 communities; 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 pursuing our ESG focus area targets, commitments and ambition 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 this MD&A, and 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 this Annual Report unless expressly incorporated by reference herein. ABBREVIATIONS AND DEFINITIONS The following abbreviations and definitions have been used in this document: CENOVUS ENERGY 2022 ANNUAL REPORT | 165 thousand barrels of oil equivalent MMBtu million British thermal units thousand barrels of oil equivalent per day gigajoule Crude Oil bbl Mbbls/d MMbbls BOE MBOE MBOE/d MMBOE WTI WCS HSB OPEC OPEC+ FPSO barrel thousand barrels per day million barrels barrel of oil equivalent million barrels of oil equivalent West Texas Intermediate Western Canadian Select Husky Synthetic Blend Organization of Petroleum Exporting Countries OPEC and a group of 10 non-OPEC members Floating production storage and offloading unit Natural Gas Mcf MMcf thousand cubic feet million cubic feet MMcf/d million cubic feet per day billion cubic feet Bcf GJ AECO NYMEX SAGD Alberta Energy Company New York Mercantile Exchange steam-assisted gravity drainage Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets. Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling for use at the owned or operated facility. Information on or connected to the Company’s website at cenovus.com does not form part of this Annual Report unless expressly incorporated by reference herein. ABBREVIATIONS AND DEFINITIONS The following abbreviations and definitions have been used in this document: Crude Oil bbl Mbbls/d MMbbls BOE MBOE MBOE/d MMBOE WTI WCS HSB OPEC OPEC+ FPSO barrel thousand barrels per day million barrels barrel of oil equivalent Natural Gas Mcf MMcf thousand cubic feet million cubic feet MMcf/d million cubic feet per day Bcf billion cubic feet thousand barrels of oil equivalent MMBtu million British thermal units thousand barrels of oil equivalent per day million barrels of oil equivalent West Texas Intermediate Western Canadian Select Husky Synthetic Blend Organization of Petroleum Exporting Countries OPEC and a group of 10 non-OPEC members Floating production storage and offloading unit GJ AECO NYMEX SAGD gigajoule Alberta Energy Company New York Mercantile Exchange steam-assisted gravity drainage Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets. Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling for use at the owned or operated facility. 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 operations, Operating Margin by asset, Total Arrangement Integration Costs, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks (including the 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 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, and Operating Margin for the Upstream or Downstream segment are specified financial measures. These are 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 the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. Upstream Downstream 2021 (2) 2022 2021 (1) 2020 2022 2020 2022 ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin details. 41,127 4,868 36,259 6,833 12,194 3,789 1,619 11,824 27,844 2,454 25,390 4,059 8,714 3,241 788 8,588 Upstream Three Months Ended 875 7,432 1,157 2,962 955 134 2,224 1,226 9,012 2,397 2,800 915 51 2,849 1,582 10,103 1,461 3,238 1,010 563 3,831 9,708 371 9,337 1,530 4,764 1,476 268 1,299 1,185 9,712 1,818 3,194 909 871 2,920 Total 2021 (1) (2) 54,102 2,454 51,648 27,170 8,714 5,499 892 9,373 2020 14,523 371 14,152 5,959 4,764 2,261 247 921 4,815 — 4,815 4,429 — 785 (21) (378) 79,229 4,868 74,361 39,334 12,194 6,839 1,731 14,263 Total Three Months Ended 38,102 — 38,102 32,501 — 3,050 112 2,439 26,258 — 26,258 23,111 — 2,258 104 785 2022 Downstream Three Months Ended — — — — 875 1,226 1,582 1,185 8,380 10,887 10,719 8,116 15,812 19,899 20,822 17,828 7,071 9,694 8,919 6,817 12,091 10,380 — 759 (8) 558 — 780 (77) 490 — 866 87 847 — 645 110 544 8,228 2,962 1,714 126 2,782 2,800 1,695 (26) 3,339 3,238 1,876 650 4,678 8,635 3,194 1,554 981 3,464 Q4 Q3 Q2 Q1 (1) Q4 Q3 (2) Q2 (2) Q1 (2) Q4 Q3 (2) Q2 (2) Q1 (1) (2) 8,307 10,238 11,685 10,897 8,380 10,887 10,719 8,116 16,687 21,125 22,404 19,013 (1) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (2) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. 166 | CENOVUS ENERGY 2022 ANNUAL REPORT Information on or connected to the Company’s website at cenovus.com does not form part of this Annual Report unless expressly incorporated by reference herein. ABBREVIATIONS AND DEFINITIONS The following abbreviations and definitions have been used in this document: thousand barrels of oil equivalent MMBtu million British thermal units thousand barrels of oil equivalent per day gigajoule Crude Oil bbl Mbbls/d MMbbls BOE MBOE MBOE/d MMBOE WTI WCS HSB OPEC OPEC+ FPSO barrel thousand barrels per day million barrels barrel of oil equivalent million barrels of oil equivalent West Texas Intermediate Western Canadian Select Husky Synthetic Blend Organization of Petroleum Exporting Countries OPEC and a group of 10 non-OPEC members Floating production storage and offloading unit Natural Gas Mcf MMcf thousand cubic feet million cubic feet MMcf/d million cubic feet per day billion cubic feet Bcf GJ AECO NYMEX SAGD Alberta Energy Company New York Mercantile Exchange steam-assisted gravity drainage Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets. Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling for use at the owned or operated facility. 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 operations, Operating Margin by asset, Total Arrangement Integration Costs, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks (including the 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 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, and Operating Margin for the Upstream or Downstream segment are specified financial measures. These are 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 the Corporate and Eliminations segment are excluded from the calculation of Operating Margin. ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin ($ millions) Revenues Gross Sales Less: Royalties Expenses Purchased Product Transportation and Blending Operating Realized (Gain) Loss on Risk Management Operating Margin Upstream 2022 2021 (1) 2020 2022 Downstream 2021 (2) 2020 2022 Total 2021 (1) (2) 41,127 4,868 36,259 6,833 12,194 3,789 1,619 11,824 27,844 2,454 25,390 4,059 8,714 3,241 788 8,588 9,708 371 9,337 1,530 4,764 1,476 268 1,299 38,102 — 38,102 32,501 — 3,050 112 2,439 26,258 — 26,258 23,111 — 2,258 104 785 4,815 — 4,815 4,429 — 785 (21) (378) 79,229 4,868 74,361 39,334 12,194 6,839 1,731 14,263 54,102 2,454 51,648 27,170 8,714 5,499 892 9,373 2020 14,523 371 14,152 5,959 4,764 2,261 247 921 Upstream Three Months Ended 2022 Downstream Three Months Ended Total Three Months Ended Q4 Q3 Q2 Q1 (1) Q4 Q3 (2) Q2 (2) Q1 (2) Q4 Q3 (2) Q2 (2) Q1 (1) (2) 8,307 10,238 11,685 10,897 8,380 10,887 10,719 8,116 16,687 21,125 22,404 19,013 875 7,432 1,157 2,962 955 134 2,224 1,226 9,012 2,397 2,800 915 51 2,849 1,582 10,103 1,461 3,238 1,010 563 3,831 1,185 9,712 1,818 3,194 909 871 2,920 — — — — 875 1,226 1,582 1,185 8,380 10,887 10,719 8,116 15,812 19,899 20,822 17,828 7,071 9,694 8,919 6,817 — 759 (8) 558 — 780 (77) 490 — 866 87 847 — 645 110 544 8,228 2,962 1,714 126 2,782 12,091 10,380 2,800 1,695 (26) 3,339 3,238 1,876 650 4,678 8,635 3,194 1,554 981 3,464 (1) (2) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. CENOVUS ENERGY 2022 ANNUAL REPORT | 167 ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating Realized (Gain) Loss on Risk Management Operating Margin Upstream (1) Three Months Ended 2021 Downstream (2) Three Months Ended Total (1) (2) Three Months Ended Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 8,237 815 7,422 1,198 2,599 865 202 2,558 7,354 733 6,621 1,074 2,137 800 168 2,442 6,128 533 5,595 717 2,006 791 188 1,893 6,125 373 5,752 1,070 1,972 785 230 1,695 8,010 7,422 6,226 4,600 16,247 14,776 12,354 10,725 — — — — 815 733 533 373 8,010 7,422 6,226 4,600 15,432 14,043 11,821 10,352 7,223 6,600 5,410 3,878 — 689 56 42 — 537 17 268 — 515 10 291 — 517 21 184 8,421 2,599 1,554 7,674 2,137 1,337 6,127 2,006 1,306 4,948 1,972 1,302 258 185 198 251 2,600 2,710 2,184 1,879 (1) (2) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. Operating Margin by Asset ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin Three Months Ended December 31, 2022 Offshore (1) Asia Pacific Atlantic Year Ended December 31, 2022 Asia Pacific Atlantic Offshore (2) 359 20 339 — 26 313 86 1 85 3 58 24 445 21 424 3 84 337 1,442 80 1,362 — 114 1,248 578 (3) 581 15 204 362 2,020 77 1,943 15 318 1,610 (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Found in Note 1 of the Consolidated Financial Statements. ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin Three Months Ended December 31, 2021 Offshore (1) Asia Pacific Atlantic Year Ended December 31, 2021 Asia Pacific Atlantic Offshore (2) 377 26 351 — 29 322 143 8 135 5 44 86 520 34 486 5 73 408 1,342 79 1,263 — 103 1,160 440 29 411 15 136 260 1,782 108 1,674 15 239 1,420 (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Found in Note 1 of the Consolidated Financial Statements. Total Arrangement Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Total Arrangement Integration Costs Arrangement, excluding share issuance costs. ($ millions) Integration Costs (1) Capitalized Integration Costs (2) Total Arrangement Integration Costs (1) (2) See Note 8 of the Consolidated Financial Statements. Included in capital expenditures on the Consolidated Statements of Cash Flows. Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Year Ended December 31, 2022 90 5 95 2021 349 53 402 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. Adjusted Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares. Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of shares. 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. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds Flow minus base dividends paid on common shares, dividends paid on preferred shares, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and acquisition costs, plus proceeds from or payments related to divestitures. Excess Free Funds Flow was a new metric as of June 30, 2022. Cash From (Used in) Operating Activities 2,970 4,089 2,979 1,365 2,184 2,138 1,369 Q4 Q2 Q1 Q4 2022 Q3 2021 Q3 Q2 Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital ($ millions) (Add) Deduct: Adjusted Funds Flow Capital Investment Free Funds Flow Add (Deduct): Dividends Paid on Preferred Shares Settlement of Decommissioning Liabilities Principal Repayment of Leases Acquisitions, Net of Cash Acquired Proceeds From Divestitures Payment on Divestiture of Assets (49) 673 2,346 1,274 1,072 (55) 1,193 2,951 866 2,085 (27) (92) 3,098 822 2,276 (19) (1,199) 2,583 746 1,837 — (49) (74) (7) 45 — (9) (55) (78) (389) 407 — (8) (27) (75) (1) 112 (50) (69) (9) (19) (75) — 950 — (35) 271 1,948 835 1,113 (70) (8) (35) (78) — 247 — (38) (166) 2,342 647 1,695 (35) (9) (38) (70) — 83 — (18) (430) 1,817 534 1,283 (36) (8) (18) (77) — 100 — Q1 228 (11) (902) 1,141 547 594 (35) (9) (11) (75) (7) 5 — 462 Excess Free Funds Flow 786 1,756 2,020 2,615 1,169 1,626 1,244 Base Dividends Paid on Common Shares (201) (205) (207) 168 | CENOVUS ENERGY 2022 ANNUAL REPORT Upstream (1) Three Months Ended 2021 Downstream (2) Three Months Ended Total (1) (2) Three Months Ended Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 8,237 815 7,422 1,198 2,599 865 202 2,558 7,354 733 6,621 1,074 2,137 800 168 2,442 6,128 533 5,595 717 2,006 791 188 1,893 6,125 373 5,752 1,070 1,972 785 230 1,695 8,010 7,422 6,226 4,600 16,247 14,776 12,354 10,725 — — — — 815 733 533 373 8,010 7,422 6,226 4,600 15,432 14,043 11,821 10,352 7,223 6,600 5,410 3,878 — 689 56 42 — 537 17 268 — 515 10 291 — 517 21 184 8,421 2,599 1,554 7,674 2,137 1,337 6,127 2,006 1,306 4,948 1,972 1,302 258 185 198 251 2,600 2,710 2,184 1,879 (1) Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (2) Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating Realized (Gain) Loss on Risk Management Operating Margin details. Operating Margin by Asset ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Found in Note 1 of the Consolidated Financial Statements. (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Found in Note 1 of the Consolidated Financial Statements. Three Months Ended December 31, 2022 Year Ended December 31, 2022 Asia Pacific Atlantic Offshore (1) Asia Pacific Atlantic Offshore (2) 359 20 339 — 26 313 377 26 351 — 29 322 86 1 85 3 58 24 143 8 135 5 44 86 445 21 424 3 84 337 520 34 486 5 73 408 1,442 80 1,362 — 114 1,248 1,342 79 1,263 — 103 1,160 578 (3) 581 15 204 362 440 29 411 15 136 260 2,020 77 1,943 15 318 1,610 1,782 108 1,674 15 239 1,420 Three Months Ended December 31, 2021 Year Ended December 31, 2021 Asia Pacific Atlantic Offshore (1) Asia Pacific Atlantic Offshore (2) Total Arrangement Integration Costs Total Arrangement Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Arrangement, excluding share issuance costs. ($ millions) Integration Costs (1) Capitalized Integration Costs (2) Total Arrangement Integration Costs (1) (2) See Note 8 of the Consolidated Financial Statements. Included in capital expenditures on the Consolidated Statements of Cash Flows. Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Year Ended December 31, 2022 90 5 95 2021 349 53 402 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. Adjusted Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares. Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of shares. 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. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds Flow minus base dividends paid on common shares, dividends paid on preferred shares, other uses of cash (including settlement of decommissioning liabilities and principal repayment of leases), and acquisition costs, plus proceeds from or payments related to divestitures. Excess Free Funds Flow was a new metric as of June 30, 2022. ($ millions) Q4 2022 Q3 Q2 Q1 Q4 2021 Q3 Q2 Cash From (Used in) Operating Activities 2,970 4,089 2,979 1,365 2,184 2,138 1,369 (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Add (Deduct): (49) 673 2,346 1,274 1,072 (55) 1,193 2,951 866 2,085 (27) (92) 3,098 822 2,276 (19) (1,199) 2,583 746 1,837 Base Dividends Paid on Common Shares (201) (205) (207) Dividends Paid on Preferred Shares Settlement of Decommissioning Liabilities Principal Repayment of Leases Acquisitions, Net of Cash Acquired Proceeds From Divestitures Payment on Divestiture of Assets — (49) (74) (7) 45 — (9) (55) (78) (389) 407 — (8) (27) (75) (1) 112 (50) (69) (9) (19) (75) — 950 — (35) 271 1,948 835 1,113 (70) (8) (35) (78) — 247 — (38) (166) 2,342 647 1,695 (35) (9) (38) (70) — 83 — (18) (430) 1,817 534 1,283 (36) (8) (18) (77) — 100 — Excess Free Funds Flow 786 1,756 2,020 2,615 1,169 1,626 1,244 Q1 228 (11) (902) 1,141 547 594 (35) (9) (11) (75) (7) 5 — 462 CENOVUS ENERGY 2022 ANNUAL REPORT | 169 ($ millions) Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Year Ended December 31, 2022 11,403 (150) 575 10,978 3,708 7,270 2021 5,919 (102) (1,227) 7,248 2,563 4,685 2020 273 (42) 198 117 841 (724) Gross Margin, Refining Margin and Unit Operating Expense Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, used to evaluate the 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 oil throughput. Unit Operating Expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense as operating expenses divided by barrels of crude oil throughput in our downstream operations. Canadian Manufacturing ($ millions) Revenues Purchased Product Gross Margin Basis of Refining Margin Calculation Three Months Ended December 31, 2022 Lloydminster Upgrader Lloydminster Refinery 905 574 331 240 170 70 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,145 744 401 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 68.4 52.60 25.9 29.36 94.3 46.21 ($ millions) Revenues Purchased Product Gross Margin Three Months Ended September 30, 2022 (3)(4) Basis of Refining Margin Calculation Lloydminster Upgrader Lloydminster Refinery 999 747 252 387 286 101 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,386 1,033 353 Lloydminster Upgrader and Lloydminster Refinery Total Other (1) 627 580 47 Total Canadian Manufacturing (2) 1,772 1,324 448 Other (1) 782 714 68 Total Canadian Manufacturing (2) 2,168 1,747 421 Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 71.3 38.33 27.2 40.33 98.5 38.88 (1) (2) (3) (4) Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. 170 | CENOVUS ENERGY 2022 ANNUAL REPORT Basis of Refining Margin Calculation Three Months Ended June 30, 2022 (1) Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 840 760 80 Total Canadian Manufacturing (3) (4) 2,245 1,982 263 Basis of Refining Margin Calculation Three Months Ended March 31, 2022 (1) Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 665 605 60 Total Canadian Manufacturing (3) (4) 1,607 1,333 274 Basis of Refining Margin Calculation Year Ended December 31, 2022 Lloydminster Upgrader and Lloydminster Refinery Total Lloydminster Upgrader Lloydminster Refinery Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 2,914 2,662 252 Total Canadian Manufacturing (3) 7,792 6,389 1,403 1,162 1,012 150 64.6 25.54 756 585 171 70.7 26.98 3,822 2,918 904 68.7 36.04 1,405 1,222 183 80.9 24.87 942 728 214 98.1 24.28 4,878 3,727 1,151 92.9 33.92 243 210 33 16.3 22.22 186 143 43 27.4 17.33 1,056 809 247 24.2 27.91 ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) (1) (2) (3) (4) Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. ($ millions) (Add) Deduct: Cash From (Used in) Operating Activities Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow Capital Investment Free Funds Flow Year Ended December 31, 2022 11,403 (150) 575 10,978 3,708 7,270 2021 5,919 (102) (1,227) 7,248 2,563 4,685 2020 273 (42) 198 117 841 (724) Gross Margin, Refining Margin and Unit Operating Expense Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, used to evaluate the 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 oil throughput. Unit Operating Expenses are specified financial measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense as operating expenses divided by barrels of crude oil throughput in our downstream operations. Canadian Manufacturing Basis of Refining Margin Calculation Three Months Ended December 31, 2022 Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (1) 627 580 47 Total Canadian Manufacturing (2) 1,772 1,324 448 905 574 331 68.4 52.60 999 747 252 71.3 38.33 240 170 70 25.9 29.36 387 286 101 27.2 40.33 1,145 744 401 94.3 46.21 1,386 1,033 353 98.5 38.88 Three Months Ended September 30, 2022 (3)(4) Basis of Refining Margin Calculation Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (1) 782 714 68 Total Canadian Manufacturing (2) 2,168 1,747 421 ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) (1) (2) (3) (4) Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. ($ millions) Revenues Purchased Product Gross Margin Basis of Refining Margin Calculation Three Months Ended June 30, 2022 (1) Lloydminster Upgrader Lloydminster Refinery 1,162 1,012 150 243 210 33 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,405 1,222 183 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 64.6 25.54 16.3 22.22 80.9 24.87 ($ millions) Revenues Purchased Product Gross Margin Basis of Refining Margin Calculation Three Months Ended March 31, 2022 (1) Lloydminster Upgrader Lloydminster Refinery 756 585 171 186 143 43 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 942 728 214 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 70.7 26.98 27.4 17.33 98.1 24.28 ($ millions) Revenues Purchased Product Gross Margin Basis of Refining Margin Calculation Year Ended December 31, 2022 Lloydminster Upgrader Lloydminster Refinery 3,822 2,918 904 1,056 809 247 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 4,878 3,727 1,151 Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 840 760 80 Total Canadian Manufacturing (3) (4) 2,245 1,982 263 Other (2) 665 605 60 Total Canadian Manufacturing (3) (4) 1,607 1,333 274 Other (2) 2,914 2,662 252 Total Canadian Manufacturing (3) 7,792 6,389 1,403 Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 68.7 36.04 24.2 27.91 92.9 33.92 (1) (2) (3) (4) Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. CENOVUS ENERGY 2022 ANNUAL REPORT | 171 ($ millions) Revenues Purchased Product Gross Margin Three Months Ended December 31, 2021 (1) Basis of Refining Margin Calculation Lloydminster Upgrader Lloydminster Refinery 1,044 887 157 205 172 33 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,249 1,059 190 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 80.4 21.26 27.9 12.77 108.3 19.07 ($ millions) Revenues Purchased Product Gross Margin Basis of Refining Margin Calculation Year Ended December 31, 2021 (1) Lloydminster Upgrader Lloydminster Refinery 3,245 2,698 547 816 659 157 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 4,061 3,357 704 Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 607 529 78 Total Canadian Manufacturing (3) (4) 1,856 1,588 268 Other (2) 2,154 1,799 355 Total Canadian Manufacturing (3) (4) 6,215 5,156 1,059 Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) 79.0 18.96 27.5 15.60 106.5 18.09 (1) (2) (3) (4) Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. U.S. Manufacturing ($ millions) Revenues (1) Purchased Product (1) Gross Margin Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues (1) Purchased Product (1) Gross Margin Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) Per Unit DD&A divided by sales volumes. Three Months Ended December 31, 2022 6,608 5,747 861 379.2 24.70 2021 20,043 17,955 2,088 401.5 14.25 2021 6,154 5,635 519 361.6 15.63 2020 4,733 4,429 304 185.9 4.47 2022 30,310 26,112 4,198 400.8 28.70 (1) Found in Note 1 of the interim Consolidated Financial Statements. Year Ended December 31, (1) Found in Note 1 of the Consolidated Financial Statements. Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis. We define Per Unit DD&A as DD&A 172 | CENOVUS ENERGY 2022 ANNUAL REPORT Three Months Ended December 31, 2021 (1) Basis of Refining Margin Calculation Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (2) 607 529 78 Total Canadian Manufacturing (3) (4) 1,856 1,588 268 1,044 887 157 80.4 21.26 3,245 2,698 547 79.0 18.96 205 172 33 27.9 12.77 816 659 157 27.5 15.60 Basis of Refining Margin Calculation Year Ended December 31, 2021 (1) Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,249 1,059 190 108.3 19.07 4,061 3,357 704 106.5 18.09 ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) (1) (2) (3) (4) Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities. Includes ethanol operations, crude-by-rail operations and the commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to total downstream Operating Margin or total Operating Margin. U.S. Manufacturing ($ millions) Revenues (1) Purchased Product (1) Gross Margin Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) (1) Found in Note 1 of the interim Consolidated Financial Statements. ($ millions) Revenues (1) Purchased Product (1) Gross Margin Other (2) 2,154 1,799 355 Total Canadian Manufacturing (3) (4) 6,215 5,156 1,059 Crude Oil Throughput (Mbbls/d) Refining Margin ($/bbl) (1) Found in Note 1 of the Consolidated Financial Statements. Per Unit DD&A Three Months Ended December 31, 2022 6,608 5,747 861 379.2 24.70 Year Ended December 31, 2022 30,310 26,112 4,198 400.8 28.70 2021 20,043 17,955 2,088 401.5 14.25 2021 6,154 5,635 519 361.6 15.63 2020 4,733 4,429 304 185.9 4.47 Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis. We define Per Unit DD&A as DD&A divided by sales volumes. CENOVUS ENERGY 2022 ANNUAL REPORT | 173 Netback Reconciliations Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses, and netback per BOE is divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold and exclude risk management activities. The sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market. The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin found in our interim Consolidated Financial Statements. Total Production Upstream Financial Results Three Months Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Total Upstream (1) 8,307 875 1,157 2,962 955 2,358 134 2,224 Total Upstream (1) 8,237 815 1,198 2,599 865 2,760 202 2,558 Condensate (2,415) — — (2,415) — — — — Third-Party Sourced (1,063) — (1,063) — — — — — Adjustments Internal Consumption (2) (349) Equity Adjustment (3) 77 Other (4) (123) — — — (349) — — — 27 — — 15 35 — 35 (1) (94) (4) (11) (13) — (13) Condensate (2,201) — — (2,201) — — — — Third-Party Sourced (1,079) — (1,079) — (8) 8 — 8 Adjustments Internal Consumption (2) (241) Equity Adjustment (3) 62 Other (4) (146) — — — (241) — — — 29 — — 7 26 — 26 — (119) — (3) (24) — (24) Basis of Netback Calculation Total Upstream 4,434 901 — 543 610 2,380 134 2,246 Basis of Netback Calculation Total Upstream 4,632 844 — 398 620 2,770 202 2,568 (1) (2) (3) (4) (5) These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Other includes construction, transportation and blending and third-party processing margin. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. Year Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2021 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2020 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Total Upstream (1) 27,844 Condensate (7,095) Third-Party Sourced (3,761) Adjustments Internal Equity Consumption (2) Adjustment (3) Other (4) Total Upstream (1) Condensate (10,307) Third-Party Sourced (6,524) Adjustments Internal Equity Consumption (2) Adjustment (3) Other (4) 41,127 4,868 6,833 12,194 3,789 13,443 1,619 11,824 2,454 4,059 8,714 3,241 9,376 788 8,588 9,708 371 1,530 4,764 1,476 1,567 268 1,299 (10,307) — — — — — — — — — — — — — — — — — — (7,095) (3,452) (6,524) — — — — (8) 8 (3,761) — — (8) 8 (2) 10 (1,559) — — — — — — (1,170) (1,170) — — — — — — (710) (710) — — — — — — — (1) — 1 — — — — Basis of Netback Calculation Total Upstream 22,968 4,972 — 1,848 2,616 13,532 1,611 11,921 Basis of Netback Calculation Total Upstream 16,112 2,506 — 1,619 2,512 9,475 786 8,689 Basis of Netback Calculation Total Upstream 4,344 370 — 1,313 1,109 1,552 268 1,284 (429) (12) (309) (39) (39) (30) — (30) (390) — (298) — (36) (56) — (56) (58) — 29 — (72) (15) — (15) 271 116 — — 36 119 — 119 224 52 — — 25 147 — 147 (295) (295) — — — — — — Total Upstream (1) Condensate (3,452) Third-Party Sourced (1,559) Adjustments Internal Equity Consumption (2) Adjustment (3) Other (4) These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Other includes construction, transportation and blending and third-party processing margin. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (1) (2) (3) (4) (5) details. 174 | CENOVUS ENERGY 2022 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 and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE 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, and netback per BOE is 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 and exclude risk management activities. 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, and Netbacks per BOE to Operating Margin found in our interim Consolidated Financial Statements. Total Production Upstream Financial Results Three Months Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Total Upstream (1) Condensate (2,415) Third-Party Sourced (1,063) Adjustments Internal Equity Consumption (2) Adjustment (3) 8,307 875 1,157 2,962 955 2,358 134 2,224 8,237 815 1,198 2,599 865 2,760 202 2,558 (2,415) — — — — — — — — — — — — (2,201) (1,063) — — — — — — (1,079) — — (8) 8 — 8 (349) (349) — — — — — — (241) (241) — — — — — — Total Upstream (1) Condensate (2,201) Third-Party Sourced (1,079) Adjustments Internal Equity Consumption (2) Adjustment (3) Other (4) Basis of Netback Calculation Total Upstream 4,434 901 — 543 610 2,380 134 2,246 844 — 398 620 2,770 202 2,568 Basis of Netback Calculation Total Upstream 4,632 Other (4) (123) (1) (94) (4) (11) (13) — (13) (146) — (119) — (3) (24) — (24) 77 27 — — 15 35 — 35 62 29 — — 7 26 — 26 These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Other includes construction, transportation and blending and third-party processing margin. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (1) (2) (3) (4) (5) details. Year Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2021 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2020 ($ millions) Gross Sales (5) Royalties Purchased Product (5) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Total Upstream (1) 41,127 4,868 6,833 12,194 3,789 13,443 1,619 11,824 Total Upstream (1) 27,844 2,454 4,059 8,714 3,241 9,376 788 8,588 Total Upstream (1) 9,708 371 1,530 4,764 1,476 1,567 268 1,299 Condensate (10,307) — — (10,307) — — — — Third-Party Sourced (6,524) — (6,524) — — — (8) 8 Adjustments Internal Consumption (2) (1,170) Equity Adjustment (3) 271 Other (4) (429) — — — (1,170) — — — 116 — — 36 119 — 119 (12) (309) (39) (39) (30) — (30) Condensate (7,095) — — (7,095) — — — — Third-Party Sourced (3,761) — (3,761) — (8) 8 (2) 10 Adjustments Internal Consumption (2) (710) Equity Adjustment (3) 224 Other (4) (390) — — — (710) — — — 52 — — 25 147 — 147 — (298) — (36) (56) — (56) Condensate (3,452) — — (3,452) — — — — Third-Party Sourced (1,559) — (1,559) — — — — — Adjustments Internal Consumption (2) — Equity Adjustment (3) (295) Other (4) (58) (1) — 1 — — — — — — — (295) — — — — 29 — (72) (15) — (15) Basis of Netback Calculation Total Upstream 22,968 4,972 — 1,848 2,616 13,532 1,611 11,921 Basis of Netback Calculation Total Upstream 16,112 2,506 — 1,619 2,512 9,475 786 8,689 Basis of Netback Calculation Total Upstream 4,344 370 — 1,313 1,109 1,552 268 1,284 (1) (2) (3) (4) (5) These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Other includes construction, transportation and blending and third-party processing margin. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. CENOVUS ENERGY 2022 ANNUAL REPORT | 175 Oil Sands Three Months Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Basis of Netback Calculation Foster Creek Christina Lake 1,282 1,453 Sunrise 222 338 — 255 194 495 344 — 157 221 731 13 — 42 60 107 Other Oil Sands (1) 745 88 — 39 257 361 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 3,702 783 — 493 732 1,694 4 1 — — 3 — 3,706 784 — 493 735 1,694 59 1,635 Basis of Netback Calculation Total Oil Sands 3,706 784 — 493 735 1,694 59 1,635 Adjustments Condensate 2,415 Third-party Sourced 500 Other (2) 110 Total Oil Sands (3) 6,731 — — 2,415 — — — — — 500 — — — — — Basis of Netback Calculation — 94 14 (2) 4 — 4 784 594 2,922 733 1,698 59 1,639 Foster Creek Christina Lake 1,304 1,441 Sunrise 189 280 — 166 184 674 345 — 140 194 762 7 — 28 39 115 Other Oil Sands (1) 903 102 — 42 230 529 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 3,837 734 — 376 647 2,080 4 — — — 6 (2) 3,841 734 — 376 653 2,078 202 1,876 Basis of Netback Calculation Adjustments Total Oil Sands Condensate Third-party Sourced 3,841 734 — 376 653 2,078 202 1,876 2,201 — — 2,201 — — — — 537 — 537 — — — — — Basis of Netback Calculation Other (2) 138 Total Oil Sands (3) 6,717 — 119 — 5 14 — 14 734 656 2,577 658 2,092 202 1,890 Year Ended December 31, 2022 ($ millions) Foster Creek Christina Lake Sunrise Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 6,723 1,783 — 814 870 3,256 7,951 2,244 — 588 898 4,221 950 59 — 135 193 563 Other Oil Sands (1) 3,967 390 — 149 960 2,468 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 19,591 4,476 — 1,686 2,921 10,508 18 6 — — 20 (8) 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 (1) (2) (3) (4) Includes Lloydminster thermal and Lloydminster conventional heavy oil assets. Other includes construction, transportation and blending margin. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. 176 | CENOVUS ENERGY 2022 ANNUAL REPORT Year Ended December 31, 2022 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) Total Oil Sands (3) Basis of Netback Calculation Adjustments Year Ended December 31, 2021 ($ millions) Foster Creek Christina Lake Sunrise Natural Gas Total Oil Sands 4,341 767 — 686 701 2,187 5,115 1,078 — 526 700 2,811 Basis of Netback Calculation Other Oil Sands (1) 3,212 330 — 207 858 1,817 Total Bitumen and Heavy Oil 13,284 2,195 — 1,530 2,416 7,143 13 1 — — 21 (9) Year Ended December 31, 2021 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) Total Oil Sands (3) Basis of Netback Calculation Adjustments 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 13,297 2,196 — 1,530 2,437 7,134 786 6,348 10,307 10,307 — — — — — — 616 20 — 111 157 328 7,095 7,095 — — — — — — 4,501 4,501 — — — — — — 2,106 2,106 — — — — — — 358 11 309 43 (11) 6 — 6 329 — 298 — 14 17 — 17 Basis of Netback Calculation Foster Creek Christina Lake Total Oil Sands 1,859 2,194 Year Ended December 31, 2020 ($ millions) Total Oil Sands Condensate down (5) Other (2) Total Oil Sands (3) Basis of Netback Calculation Adjustments Third-party Inventory Write- 95 — 667 558 539 — 1 — (1) — — — — 235 — 565 551 843 9 — (28) — 47 (10) — (10) 4,053 330 — 1,232 1,109 1,382 268 1,114 3,452 3,452 — — — — — — Sourced 1,290 1,290 — — — — — — Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2020 ($ millions) Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 34,775 4,493 4,810 12,036 2,930 10,506 1,527 8,979 13,297 2,196 — 1,530 2,437 7,134 786 6,348 22,827 2,196 2,404 8,625 2,451 7,151 786 6,365 4,053 330 — 1,232 1,109 1,382 268 1,114 8,804 331 1,262 4,683 1,156 1,372 268 1,104 (1) (2) (3) (4) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022. Other includes construction, transportation and blending margin. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further (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 details. write-down reversals. Oil Sands Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin (1) (2) (3) (4) details. Three Months Ended December 31, 2022 ($ millions) Foster Creek Christina Lake 1,282 1,453 Sunrise 222 Natural Gas Total Oil Sands Basis of Netback Calculation Other Oil Sands (1) Total Bitumen and Heavy Oil 745 88 — 39 257 361 3,702 783 — 493 732 1,694 338 — 255 194 495 344 — 157 221 731 Three Months Ended December 31, 2022 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) 110 Total Oil Sands (3) Three Months Ended December 31, 2021 ($ millions) Foster Creek Christina Lake 1,304 1,441 Sunrise 189 Natural Gas Total Oil Sands Basis of Netback Calculation Other Oil Sands (1) Total Bitumen and Heavy Oil 903 102 — 42 230 529 3,837 734 — 376 647 2,080 280 — 166 184 674 345 — 140 194 762 Three Months Ended December 31, 2021 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) Total Oil Sands (3) Basis of Netback Calculation Adjustments 3,706 784 — 493 735 1,694 59 1,635 3,841 734 — 376 653 2,078 202 1,876 13 — 42 60 107 2,415 2,415 — — — — — — 7 — 28 39 115 2,201 2,201 — — — — — — 950 59 — 135 193 563 500 — 500 — — — — — 537 — 537 — — — — — 4 1 — — 3 — 4 — — — 6 (2) 18 6 — — 20 (8) — 94 14 (2) 4 — 4 138 — 119 — 5 14 — 14 3,706 784 — 493 735 1,694 59 1,635 6,731 784 594 2,922 733 1,698 59 1,639 3,841 734 — 376 653 2,078 202 1,876 6,717 734 656 2,577 658 2,092 202 1,890 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 Year Ended December 31, 2022 ($ millions) Foster Creek Christina Lake Sunrise Natural Gas Total Oil Sands 6,723 1,783 — 814 870 3,256 7,951 2,244 — 588 898 4,221 Basis of Netback Calculation Other Oil Sands (1) 3,967 390 — 149 960 2,468 Total Bitumen and Heavy Oil 19,591 4,476 — 1,686 2,921 10,508 Includes Lloydminster thermal and Lloydminster conventional heavy oil assets. Other includes construction, transportation and blending margin. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further Year Ended December 31, 2022 ($ millions) Total Oil Sands Condensate Third-party Sourced Basis of Netback Calculation Adjustments Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 10,307 — — 10,307 — — — — 4,501 — 4,501 — — — — — Basis of Netback Calculation Other (2) 358 Total Oil Sands (3) 34,775 11 309 43 (11) 6 — 6 4,493 4,810 12,036 2,930 10,506 1,527 8,979 Basis of Netback Calculation Adjustments Year Ended December 31, 2021 ($ millions) Foster Creek Christina Lake Sunrise Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2021 ($ millions) Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2020 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2020 ($ millions) Gross Sales (4) Royalties Purchased Product (4) Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 4,341 767 — 686 701 2,187 5,115 1,078 — 526 700 2,811 616 20 — 111 157 328 Other Oil Sands (1) 3,212 330 — 207 858 1,817 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 13,284 2,195 — 1,530 2,416 7,143 13 1 — — 21 (9) 13,297 2,196 — 1,530 2,437 7,134 786 6,348 Basis of Netback Calculation Adjustments Total Oil Sands Condensate Third-party Sourced 13,297 2,196 — 1,530 2,437 7,134 786 6,348 7,095 — — 7,095 — — — — 2,106 — 2,106 — — — — — Other (2) 329 Total Oil Sands (3) 22,827 — 298 — 14 17 — 17 2,196 2,404 8,625 2,451 7,151 786 6,365 Basis of Netback Calculation Foster Creek Christina Lake Total Oil Sands 1,859 2,194 95 — 667 558 539 235 — 565 551 843 4,053 330 — 1,232 1,109 1,382 268 1,114 Basis of Netback Calculation Adjustments Total Oil Sands Condensate Third-party Sourced 4,053 330 — 1,232 1,109 1,382 268 1,114 3,452 — — 3,452 — — — — 1,290 — 1,290 — — — — — Inventory Write- down (5) — Other (2) 9 Total Oil Sands (3) 8,804 1 — (1) — — — — — (28) — 47 (10) — (10) 331 1,262 4,683 1,156 1,372 268 1,104 (1) (2) (3) (4) (5) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022. Other includes construction, transportation and blending margin. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further details. 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 2022 ANNUAL REPORT | 177 Conventional Offshore Three Months Ended December 31, 2022 ($ millions) Conventional Third-party Sourced Basis of Netback Calculation Adjustments 555 69 — 47 135 304 75 229 563 — 563 — — — — — Other (1) 13 Conventional (2) 1,131 Three Months Ended December 31, 2022 ($ millions) China Indonesia (1) Asia Pacific Atlantic Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments 1 — (10) 3 19 — 19 70 563 37 138 323 75 248 Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Basis of Netback Calculation Adjustments Conventional 450 Third-party Sourced 542 Other (1) 8 Conventional (2) 1,000 47 — 17 128 258 — 258 — 542 — 8 (8) — (8) — — — (2) 10 — 10 47 542 17 134 260 — 260 Year Ended December 31, 2022 ($ millions) Conventional Third-party Sourced Basis of Netback Calculation Adjustments Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 2,238 297 — 147 520 1,274 84 1,190 2,023 — 2,023 — — — 8 (8) Year Ended December 31, 2021 ($ millions) Conventional Third-party Sourced Basis of Netback Calculation Adjustments Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 1,519 150 — 74 521 774 — 774 1,655 — 1,655 — 8 (8) 2 (10) Year Ended December 31, 2020 ($ millions) Conventional Third-party Sourced Basis of Netback Calculation Adjustments Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 586 40 — 81 295 170 — 170 269 — 269 — — — — — (1) (2) Reflects Operating Margin from processing facilities. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Other (1) 71 Conventional (2) 4,332 1 — (4) 21 53 — 53 298 2,023 143 541 1,327 92 1,235 Other (1) 61 Conventional (2) 3,235 — — — 22 39 — 39 150 1,655 74 551 805 2 803 Other (1) 49 Conventional (2) 904 — (1) — 25 25 — 25 40 268 81 320 195 — 195 178 | CENOVUS ENERGY 2022 ANNUAL REPORT Three Months Ended December 31, 2021 ($ millions) Indonesia (1) Asia Pacific Atlantic Total Offshore Adjustment (1) Total Offshore (3) Basis of Netback Calculation Adjustment Equity Year Ended December 31, 2022 ($ millions) Indonesia (1) Asia Pacific Atlantic Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin (1) (2) (3) Relates to costs in the Atlantic. 359 20 — — 24 315 77 27 — — 17 33 436 47 — — 41 348 86 1 — 3 48 34 China 377 26 — — 23 328 China 1,442 80 — — 99 1,263 China 1,342 79 — — 94 1,169 62 29 — — 12 21 439 55 — — 35 349 143 8 — 5 45 85 271 116 — — 51 104 1,713 196 — — 150 1,367 578 (3) — 15 175 391 224 52 — — 33 139 1,566 131 — — 127 1,308 440 29 — 15 137 259 522 48 — 3 89 382 — 382 2,291 193 — 15 325 1,758 — 1,758 (77) (27) — — (15) (35) — (35) 582 63 — 5 80 434 — 434 (271) (116) — — (36) (119) — (119) 2,006 160 — 15 264 1,567 — 1,567 — — — — 10 (10) — (10) (62) (29) — — (7) (26) — (26) — — — — 29 (29) — (29) (224) (52) — — (25) (147) — (147) 445 21 — 3 84 337 — 337 520 34 — 5 73 408 — 408 2,020 77 — 15 318 1,610 — 1,610 1,782 108 — 15 239 1,420 — 1,420 Year Ended December 31, 2021 ($ millions) Indonesia (1) Asia Pacific Atlantic Total Offshore Adjustment (1) Total Offshore (2) Basis of Netback Calculation Adjustment Equity Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Three Months Ended December 31, 2022 ($ millions) Conventional Third-party Sourced Other (1) Basis of Netback Calculation Adjustments Three Months Ended December 31, 2021 ($ millions) Conventional Third-party Sourced Other (1) Basis of Netback Calculation Adjustments Conventional Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin Gross Sales Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin 555 69 — 47 135 304 75 229 450 47 — 17 128 258 — 258 2,238 297 — 147 520 1,274 84 1,190 1,519 150 — 74 521 774 — 774 586 40 — 81 295 170 — 170 563 — 563 — — — — — 542 — 542 — 8 (8) — (8) 2,023 2,023 — — — — 8 (8) 1,655 — 1,655 — 8 (8) 2 (10) 269 — 269 — — — — — (10) 13 1 — 3 19 — 19 8 — — — (2) 10 — 10 71 1 — (4) 21 53 — 53 61 — — — 22 39 — 39 49 — (1) — 25 25 — 25 Conventional (2) 1,131 Conventional (2) 1,000 70 563 37 138 323 75 248 47 542 17 134 260 — 260 4,332 298 2,023 143 541 1,327 92 1,235 3,235 150 1,655 74 551 805 2 803 904 40 268 81 320 195 — 195 Year Ended December 31, 2022 ($ millions) Conventional Third-party Sourced Other (1) Conventional (2) Basis of Netback Calculation Adjustments Year Ended December 31, 2021 ($ millions) Conventional Third-party Sourced Other (1) Conventional (2) Basis of Netback Calculation Adjustments Year Ended December 31, 2020 ($ millions) Conventional Third-party Sourced Other (1) Conventional (2) Basis of Netback Calculation Adjustments Reflects Operating Margin from processing facilities. (1) (2) These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. Offshore Three Months Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Three Months Ended December 31, 2021 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2022 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2021 ($ millions) Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Basis of Netback Calculation China 359 Indonesia (1) 77 20 — — 24 315 27 — — 17 33 Asia Pacific Atlantic Total Offshore 436 47 — — 41 348 86 1 — 3 48 34 522 48 — 3 89 382 — 382 Adjustments Equity Adjustment (1) (77) Other (2) — Total Offshore (3) 445 (27) — — (15) (35) — (35) — — — 10 (10) — (10) 21 — 3 84 337 — 337 Basis of Netback Calculation China 377 Indonesia (1) 62 Asia Pacific 439 Atlantic 143 Total Offshore 582 26 — — 23 328 29 — — 12 21 55 — — 35 349 8 — 5 45 85 63 — 5 80 434 — 434 Adjustment Equity Adjustment (1) (62) Total Offshore (3) 520 (29) — — (7) (26) — (26) 34 — 5 73 408 — 408 Basis of Netback Calculation China 1,442 Indonesia (1) 271 80 — — 99 1,263 116 — — 51 104 Asia Pacific Atlantic 1,713 196 — — 150 1,367 578 (3) — 15 175 391 Total Offshore 2,291 193 — 15 325 1,758 — 1,758 Adjustments Equity Adjustment (1) (271) Other (2) — Total Offshore (3) 2,020 (116) — — (36) (119) — (119) — — — 29 (29) — (29) 77 — 15 318 1,610 — 1,610 Basis of Netback Calculation China 1,342 Indonesia (1) 224 79 — — 94 1,169 52 — — 33 139 Asia Pacific Atlantic Total Offshore 1,566 131 — — 127 1,308 440 29 — 15 137 259 2,006 160 — 15 264 1,567 — 1,567 Adjustment Equity Adjustment (1) (224) Total Offshore (2) 1,782 (52) — — (25) (147) — (147) 108 — 15 239 1,420 — 1,420 (1) (2) (3) Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements. Relates to costs in the Atlantic. These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements. CENOVUS ENERGY 2022 ANNUAL REPORT | 179 Sales Volumes (1) The following table provides the sales volumes used to calculate Netback: (MBOE/d) Oil Sands Foster Creek Christina Lake Sunrise (2) Other Oil Sands Total Oil Sands (2) Conventional Sales before Internal Consumption Less: Internal Consumption (3) Sales after Internal Consumption Offshore Asia Pacific - China Asia Pacific - Indonesia Asia Pacific - Total Atlantic Total Offshore Total Sales Three Months Ended December 31, Year Ended December 31, 2022 2021 2022 2021 2020 184.7 246.5 42.0 118.5 591.7 125.5 717.2 (93.4) 623.8 47.1 12.8 59.9 7.3 67.2 194.5 239.1 29.9 141.2 604.7 125.3 730.0 (88.8) 641.2 52.7 9.8 62.5 15.0 77.5 189.4 247.5 30.2 118.7 585.8 127.2 713.0 (86.6) 626.4 48.2 10.5 58.7 11.3 70.0 178.8 232.7 25.2 143.2 579.9 133.4 713.3 (86.0) 627.3 50.8 9.5 60.3 13.2 73.5 164.9 221.7 — — 386.6 89.8 476.4 (55.9) 420.5 — — — — — 691.0 718.7 696.4 700.8 420.5 (1) (2) (3) Presented on dry bitumen basis. Sunrise sales volumes have been re-presented to reflect a change in classification of marketing activities for the first and second quarters of 2021. Less natural gas volumes used for internal consumption by the Oil Sands segment. Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands, Canadian Manufacturing, historical Retail and Corporate and Eliminations segments were revised. During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. Refer to the interim Consolidated Financial Statements for the periods ended June 30, 2022, for further details. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows. Refer to the Consolidated Financial Statements for further details. The following tables reconcile the amounts previously reported in the interim Consolidated Statements of Earnings (Loss) for the respective period or the December 31, 2021 Consolidated Financial Statements, to the corresponding revised amounts: Three Months Ended March 31, 2022 y Three Months Ended June 30, 2022 y Three Months Ended September 30, 2022 y Reported Revision Revised Reported Revision Revised Reported Revision Revised ($ millions) Oil Sands Segment Purchased Product Transportation and Blending Canadian Manufacturing Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Consolidated Gross Sales Purchased Product Transportation and Blending Operating Expenses Depreciation, Depletion and Amortization 1,483 2,885 4,368 1,044 806 124 42 72 694 660 27 8 (1) (1,761) (1,497) (6) (258) 17,383 7,538 2,919 1,287 1,030 4,609 (271) 271 — 563 529 27 8 (1) (694) (660) (27) (8) 1 131 346 (215) — — (56) 56 — — — 1,212 3,156 4,368 1,607 1,335 151 50 71 — — — — — 1,521 1,294 180 64 (17) 849 811 31 8 (1) (1,630) (1,151) (221) (258) — (1,782) (1,111) (188) (483) 17,383 20,747 7,482 2,975 1,287 9,396 3,048 1,481 1,030 1,132 4,609 — 5,690 724 686 31 8 (1) (849) (811) (31) (8) 1 125 125 — — — — — — — — 2,245 1,980 211 72 (18) — — — — — 1,478 1,095 134 37 212 881 846 38 5 (8) (1,657) (986) (188) (483) — (2,619) (2,267) (119) (233) 20,747 9,396 3,048 1,481 18,697 10,012 2,684 1,439 1,132 1,047 5,690 — 3,515 690 655 38 5 (8) (881) (846) (38) (5) 8 191 191 — — — — — — — — 2,168 1,750 172 42 204 — — — — — (2,428) (2,076) (119) (233) 18,697 10,012 2,684 1,439 1,047 3,515 180 | CENOVUS ENERGY 2022 ANNUAL REPORT The following table provides the sales volumes used to calculate Netback: Sales Volumes (1) (MBOE/d) Oil Sands Foster Creek Christina Lake Sunrise (2) Other Oil Sands Total Oil Sands (2) Conventional Sales before Internal Consumption Less: Internal Consumption (3) Sales after Internal Consumption Offshore Asia Pacific - China Asia Pacific - Indonesia Asia Pacific - Total Atlantic Total Offshore Total Sales (1) (2) (3) Three Months Ended December 31, Year Ended December 31, 2022 2021 2022 2021 2020 184.7 246.5 42.0 118.5 591.7 125.5 717.2 (93.4) 623.8 47.1 12.8 59.9 7.3 67.2 194.5 239.1 29.9 141.2 604.7 125.3 730.0 (88.8) 641.2 52.7 9.8 62.5 15.0 77.5 189.4 247.5 30.2 118.7 585.8 127.2 713.0 (86.6) 626.4 48.2 10.5 58.7 11.3 70.0 178.8 232.7 25.2 143.2 579.9 133.4 713.3 (86.0) 627.3 50.8 9.5 60.3 13.2 73.5 164.9 221.7 — — 386.6 89.8 476.4 (55.9) 420.5 — — — — — Presented on dry bitumen basis. Sunrise sales volumes have been re-presented to reflect a change in classification of marketing activities for the first and second quarters of 2021. Less natural gas volumes used for internal consumption by the Oil Sands segment. 691.0 718.7 696.4 700.8 420.5 Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands, Canadian Manufacturing, historical Retail and Corporate and Eliminations segments were revised. During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of costs between purchased product and transportation and blending. An associated elimination entry was recorded in the Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. Refer to the interim Consolidated Financial Statements for the periods ended June 30, 2022, for further details. In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net earnings (loss), financial position or cash flows. Refer to the Consolidated Financial Statements for further details. The following tables reconcile the amounts previously reported in the interim Consolidated Statements of Earnings (Loss) for the respective period or the December 31, 2021 Consolidated Financial Statements, to the corresponding revised amounts: ($ millions) Oil Sands Segment Purchased Product Transportation and Blending Canadian Manufacturing Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Consolidated Gross Sales Purchased Product Transportation and Blending Operating Expenses Depreciation, Depletion and Amortization Three Months Ended March 31, 2022 y Reported Revision Revised Three Months Ended June 30, 2022 y Reported Revision Revised y Reported Three Months Ended September 30, 2022 Revision Revised 1,483 2,885 4,368 1,044 806 124 42 72 694 660 27 8 (1) (1,761) (1,497) (6) (258) 17,383 7,538 2,919 1,287 1,030 4,609 (271) 271 — 563 529 27 8 (1) (694) (660) (27) (8) 1 131 346 (215) — — (56) 56 — — — 1,212 3,156 4,368 1,607 1,335 151 50 71 — — — — — 1,521 1,294 180 64 (17) 849 811 31 8 (1) (1,630) (1,151) (221) (258) — (1,782) (1,111) (188) (483) 17,383 20,747 7,482 2,975 1,287 9,396 3,048 1,481 1,030 4,609 — 1,132 5,690 724 686 31 8 (1) (849) (811) (31) (8) 1 125 125 — — — — — — — — 2,245 1,980 211 72 (18) — — — — — 1,478 1,095 134 37 212 881 846 38 5 (8) (1,657) (986) (188) (483) — (2,619) (2,267) (119) (233) 20,747 9,396 3,048 1,481 18,697 10,012 2,684 1,439 1,132 1,047 5,690 — 3,515 690 655 38 5 (8) (881) (846) (38) (5) 8 191 191 — — — — — — — — 2,168 1,750 172 42 204 — — — — — (2,428) (2,076) (119) (233) 18,697 10,012 2,684 1,439 1,047 3,515 CENOVUS ENERGY 2022 ANNUAL REPORT | 181 Three Months Ended March 31, 2021 Three Months Ended June 30, 2021 Three Months Ended September 30, 2021 Three Months Ended December 31, 2021 Year Ended December 31, 2021 Previously Reported Revision Revised Previously Reported Revision Revised Previously Reported Revision Revised Previously Reported Revision Revised Previously Reported Revision Revised 861 (172) 689 634 (204) 430 825 (196) 629 868 (212) 656 ($ millions) Oil Sands Segment Purchased Product Transportation and Blending 1,778 2,639 172 1,950 — 2,639 1,780 2,414 204 1,984 — 2,414 Canadian Manufacturing Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Expenses Depreciation, Depletion and Amortization Corporate and Eliminations Segment 806 631 93 43 39 447 417 19 12 (1) 357 327 19 12 (1) (447) (417) (19) (12) 1 1,163 1,088 958 112 55 38 — — — — — 807 92 43 146 501 466 29 13 (7) 409 374 29 1,497 1,181 121 13 (7) 56 139 (501) (466) (29) (13) 7 — — — — — 1,918 2,743 1,215 986 99 41 89 592 551 25 11 5 196 2,114 — 2,743 484 443 25 11 5 (592) (551) (25) (11) (5) 1,699 1,429 124 52 94 — — — — — 2,365 3,233 1,363 1,128 104 40 91 618 585 25 23 (15) 212 2,577 3,188 7,841 (784) 2,404 784 8,625 — 3,233 11,029 — 11,029 493 460 25 23 (15) (618) (585) (25) (23) 15 1,856 1,588 129 4,472 1,743 6,215 3,552 1,604 5,156 388 98 486 63 76 — — — — — 167 365 59 (18) 226 347 2,158 (2,158) 2,019 (2,019) 98 (98) 59 (18) (59) 18 — — — — — Gross Sales (1,149) 90 (1,059) (1,276) 92 (1,184) Purchased Product (973) 228 Transportation and Blending (15) (138) (745) (153) (1,110) 238 (6) (146) (872) (152) (1,450) (1,244) 108 261 (18) (153) (1,342) (983) (171) (1,831) (1,561) 125 317 (1,706) (1,244) (5,706) 415 (5,291) (4,888) 1,044 (3,844) (8) (192) (200) (47) (629) (161) — (161) — (160) — (160) — (188) — (188) — (262) — (262) — (771) — (676) (771) Consolidated Gross Sales Purchased Product Transportation and Blending Operating Expenses Depreciation, Depletion and Amortization 9,666 4,237 1,785 1,134 1,045 1,465 34 — — — — 9,666 11,170 — 11,170 13,434 — 13,434 14,541 — 14,541 48,811 — 48,811 (34) 4,203 (58) 5,255 (43) 6,691 1,819 1,134 5,313 1,796 1,144 1,854 1,144 6,734 1,923 1,150 1,966 1,150 7,197 2,379 1,288 1,045 1,036 1,465 — 1,881 1,036 1,153 1,881 — 2,474 1,153 2,652 2,474 — 1,025 43 — — — 58 — — — (20) 7,177 23,481 (155) 23,326 20 — — — 2,399 1,288 7,883 4,716 155 8,038 — 4,716 2,652 5,886 1,025 — 6,845 — — 5,886 6,845 182 | CENOVUS ENERGY 2022 ANNUAL REPORT I E N P S E D I S N I INFORMATION FOR SHAREHOLDERS ANNUAL MEETING The meeting will be held virtually only. This allows a broader base of shareholders to participate regardless of their location. Holders of Cenovus common shares are invited to attend the virtual Annual Meeting of Shareholders to be held on Wednesday, April 26, 2023 at 11:00 a.m. MT via live webcast accessible online at https://web.lumiagm.com/422837892. Please see our Management Information Circular available on cenovus.com for additional information. REGISTRAR AND TRANSFER AGENT Computershare Investor Services Inc. 8th Floor, 100 University Avenue Toronto, Ontario M5J 2Y1 Canada https://www.cenovus.com/Investors/Shareholder-information 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/Our-company/Governance, 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, 2023) Alex Pourbaix, President & Chief Executive Officer Susan Anderson, SVP, People Services Keith Chiasson, EVP, Downstream Andrew Dahlin, EVP, Corporate & Operations Services Rho na DelFrari, Chief Sustainability Officer & EVP, 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, 2023) 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) Melanie A. Little, Alpharetta, Georgia (3,4) 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 a d a n a C n i d e t n i r P CONTENTS MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER MESSAGE FROM OUR BOARD CHAIR MANAGEMENT’S DISCUSSION AND ANALYSIS CONSOLIDATED FINANCIAL STATEMENTS NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SUPPLEMENTAL INFORMATION ADVISORY INFORMATION FOR SHAREHOLDERS 4 6 7 77 88 155 163 183 For additional information about forward‑looking statements, specified financial measures and reserves contained in this Annual Report, see the Advisory on page 163. At Cenovus, our purpose is to energize the world to make people’s lives better. C E N O V U S E N E R G Y 2 0 2 2 A N N U A L R E P O R T CENOVUS ENERGY INC. Cenovus Energy Inc. is an integrated energy company with 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. The company is focused on managing its assets in a safe, innovative and cost‑efficient manner, integrating environmental, social and governance considerations into its business plans. Cenovus common shares and warrants are listed on the Toronto and New York stock exchanges, and the company’s preferred shares are listed on the Toronto Stock Exchange. For more information, visit cenovus.com. cenovus.com 1‑877‑766‑2066 (Toll‑free in Canada & U.S.) 225 6 Ave SW PO Box 766 Calgary, AB T2P 0M5 Canada © Cenovus Energy Inc. 2023 2022 ANNUAL REPORT 

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