Cenovus Energy
Annual Report 2023

Plain-text annual report

2023 ANNUAL REPORT Table of Contents At Cenovus, our purpose is to energize the world to make people’s lives better. Message from our President & Chief Executive Officer Message from our Executive Chair Management’s Discussion and Analysis Consolidated Financial Statements Notes to Consolidated Financial Statements Supplemental Information Advisory Information for Shareholders 4 6 7 71 81 139 146 167 For additional information about forward‑looking statements, specified financial measures and reserves contained in this Annual Report, see the Advisory on page 146. Continuing our safety journey Progressing methane reduction At Cenovus, we prioritize the health and safety of our people, communities and the environment. We want everyone – employees, contractors and suppliers – to return home safe every day. Our goal is to be significant incident and injury free and a sustained top-quartile performer in process and occupational safety against industry benchmarks. To achieve this, we have a clear safety strategy, underpinned by our values, safety behaviours and commitments working to become a proactive safety culture. We released our safety behaviours, one of the critical components of our safety strategy: committed leaders, always learning, risk minded and engaged partners. These behaviours tie to our Cenovus values and are intended to help mature our safety culture, while keeping safety top of mind in everything we do. • We protect what matters by being committed leaders. • We develop competent, accountable safety leaders who coach others and make it safe to speak up. • We do it right by being risk minded. • We manage risks by staying vigilant and verifying the health of our controls. • We make it better by having an always learning mindset. • We’re always learning, questioning and sharing to gain deeper understanding and take action to avoid repeat events. • And we do it together by being engaged partners. • We partner with our contractors and empower staff to find solutions together. We’ve aligned our health and safety initiatives and programs to our safety strategy. This includes our Safety Excellence for Supervisors and Managers (SEFSAM) training for front-line leaders and supervisors, rolled out in 2023. To date, we’ve trained just under 800 front-line leaders, and are on track to train the remaining 600 in 2024. This training is intended to create a consistent safety approach across Cenovus’s operations. In 2023, we furthered our long-standing methane abatement ambitions by announcing a new milestone to reduce absolute methane emissions in our upstream operations by 80 percent by year-end 2028, from a 2019 baseline. The methane milestone will contribute to our target to reduce absolute GHG emissions from operations by 35 percent by year-end 2035. Methane emissions are concentrated in our conventional oil and natural gas operations. They mostly occur from venting and leaks (also called fugitive emissions). Leaks can come from a variety of production equipment including connectors, seals and valves. We’ve been working to reduce our emissions through retrofit projects, technology deployments, and leak detection and repair. Reducing methane emissions is one of the fastest and most cost-effective opportunities we have to address our GHG emissions. We’re already making progress towards our methane milestone and have reduced our absolute methane emissions in upstream by about 60 percent from 2019 levels. Our fugitive emissions management program is in full swing, and since 2020, we’ve completed over 7,600 surveys using optical gas imaging cameras to pinpoint leaks, resulting in over 4,600 leaks being repaired. In parallel, we are also piloting other alternative technologies which help us detect, quantify, visualize, and ultimately mitigate methane emissions from our operations. Some of these technologies utilize novel methane-sensing lasers from airplanes and stationary cameras. We’ve created an internal Methane Challenge Team, involving multiple business units collaborating to act on methane. The team has developed a plan to help us achieve near-term reductions which includes prioritizing a significant inventory of abatement projects across our upstream operations. We have allocated $94 million in our five-year business plan to support these efforts and build on the work we’ve already done in this area. CENOVUS ENERGY 2023 ANNUAL REPORT | 3 Message from our President & Chief Executive Officer As I look back on my first year as CEO, I am energized and humbled by the many individuals who bring their enthusiasm, creativity and commitment to safety to our workplaces each and every day, so we can reliably and responsibly provide the energy the world needs. This is not always a straightforward task, and our staff have met and managed every challenge by upholding our core values. The strategic priorities of the company are unchanged, focusing on delivering value over the long-term through sustainable, low-cost, disciplined integrated energy leadership. During 2023, we safely restarted the Superior Refinery, restarted and completed the acquisition of the Toledo Refinery, and kept our staff and Conventional assets safe during the Alberta wildfires. In addition, the company continues to progress its growth and optimization projects, including the Sunrise and Foster Creek optimizations, the tie-back of Narrows Lake to Christina Lake, and the construction of the West White Rose project, which was approximately 75 percent complete at the end of the year. The strengthening of our balance sheet that we’ve achieved over the past few years means we are now at a point where, in addition to returning more cash to shareholders, we can strategically direct additional capital to a small number of targeted investments to support incremental production. These are high-return, efficient projects that we started funding in 2023 and will continue to fund through 2024 and 2025. We expect these projects to deliver meaningful returns starting in 2025. We also continued to drive our net debt down to just over $5 billion by the end of 2023. Long-term debt, including the current portion, was $7.1 billion at the end of the fourth quarter, a reduction of $1.6 billion compared with year-end 2022. In alignment with our capital allocation strategy, we returned $2.8 billion to our shareholders through share buybacks, dividends and the payment of our remaining warrant purchase liability. Since our strategic acquisition of Husky Energy in 2021, the company’s Total Shareholder Returns have outperformed the S&P/TSX composite and energy indices by 167 percent and 91 percent respectively. In the fourth quarter, we received approval to renew our normal course issuer bid for another year to repurchase up to approximately 133 million of the company’s common shares. Looking forward, we remain focused on achieving our net debt target of $4 billion and beginning to return 100 percent of excess free funds flow to shareholders at that time. Our Oil Sands operations provided strong results through the year, with new well pads brought online at Foster Creek and the production uplift from the execution of a redevelopment program at Sunrise. Our Conventional operations were impacted by the Alberta wildfires, primarily in the second quarter. Production recovered in the third quarter as most of the asset outages were resolved by the end of August. In our U.S. Refining business, we finalized the acquisition of bp’s 50 percent interest in the Toledo Refinery and worked safely and methodically to restart the facility. We also safely restarted our refinery in Superior, Wisconsin, which has been rebuilt with enhanced safety equipment, incorporating advances in technology and efficiencies made across the refining industry. Our refinery in Lima, Ohio continued to safely deliver fuel and petrochemicals needed in the region. Our focus remains the safe and reliable operation of these facilities. In our Offshore segment, we achieved first oil from the MAC field in Indonesia, completed the conical slip for the West White Rose project and saw the restart of production from our partner-operated Terra Nova field offshore Newfoundland and Labrador. Offshore China, Liwan 3-1 achieved a significant milestone, producing one trillion standard cubic feet of natural gas sales with no serious incidents or safety events. Our budgeted capital expenditures of $4.5 billion to $5.0 billion in 2024 are the result of many months of planning and discussion with the leadership team and Board of Directors to determine the right balance of disciplined spending on strategic initiatives. We continue to prioritize achieving our net debt target and driving meaningful incremental returns to shareholders, even in a volatile commodity price environment. As we continue to refine our business plan, we have been setting the table for further strategic growth and success. This included an update to our leadership structure and the creation of a new Chief Commercial Officer position. This new structure is designed to reflect the evolution of the company and better integrate the operational and commercial aspects of our business to maximize margins across our value chain. 4 | CENOVUS ENERGY 2023 ANNUAL REPORT As we continue to refine our business plan, we have been setting the table for further strategic growth and success. Health and safety remains our top value and is foundational to our operations. In 2023, we rolled out a new safety excellence program designed to ensure consistent application of processes across our organization. It’s important that we continue to focus on the things we can control and be prepared to safely meet and manage other challenges. We are defining fit for purpose strategies and plans to be a world class operator for each of the major assets and businesses we own. As we move through the year ahead, our focus will be on safe and reliable operations. We have a wealth of opportunities in our portfolio, which provide a strong trajectory for the company to achieve its goals for 2024 and beyond. We continue to build on our position as an environmental, social and governance (ESG) leader. We reached a number of key ESG targets in 2023, and introduced a new milestone to reduce absolute methane emissions in upstream operations by 80 percent by year-end 2028, from a 2019 baseline. This will be a key contributor to achieving the company’s target to reduce absolute GHG emissions by 35 percent by year-end 2035 as Cenovus works toward achieving its long-term ambition of net zero emissions from operations by 2050. We remain an active partner in the Pathways Alliance, which advanced work in 2023 to begin filing regulatory applications for its foundational carbon capture and storage (CCS) project early this year, representing a significant step forward in achieving industry goals of reducing emissions. In parallel with this, we continue to assess other emissions reduction technologies, 2021-2023 TOTAL SHAREHOLDER RETURN including the potential to use small modular nuclear reactors in our oil sands operations. It is important that industry and government work collaboratively to progress climate initiatives. Canada needs globally competitive government co-funding programs and a stable and predictable policy environment, focused on emission reduction targets that are realistic and technologically and economically achievable. Climate action will only be sustainable if it is balanced with a conducive business environment, strong economy and secure long-term access to affordable energy for all Canadians. We believe that when we do well at Cenovus, the communities around us should also do well, and that has led us to develop meaningful relationships with Indigenous communities near our operations. I am proud to say that in 2023 we achieved our minimum target of spending more than $1.2 billion with Indigenous businesses in Canada ahead of schedule. We view this target as a floor, not a ceiling as economic inclusion is an important part of our approach to Indigenous reconciliation, and we continue to seek opportunities to expand the work we do with Indigenous communities and businesses in the areas where we operate. I want to thank our Board, shareholders, employees and contractors for your continued support. Your commitment to the company and our values will allow us to achieve even greater things in the years ahead. /s/ Jon McKenzie PRESIDENT & CHIEF EXECUTIVE OFFICER $450 $400 $350 $300 $250 $200 $150 $100 $0 December 31, 2020 June 30, 2021 December 31, 2021 June 30, 2022 December 31, 2022 June 30, 2023 December 31, 2023 Source: Bloomberg Cenovus Energy (TSX) S&P/TSX Composite Index S&P/TSX Energy Index CENOVUS ENERGY 2023 ANNUAL REPORT | 5 Message from our Executive Chair Last year was one of succession and new opportunities at Cenovus as I became Executive Chair of the Board of Directors and Jon McKenzie became Chief Executive Officer, backed by one of the strongest management teams in our industry. In my new role, I’m focused on providing sound oversight of management, along with the rest of the Board, while continuing to actively advocate on behalf of Cenovus and our peers in the Pathways Alliance for effective energy policy in Canada. Since becoming Executive Chair, I’ve worked closely with Lead Independent Director Claude Mongeau to ensure our new Board structure remains effective, and that we continue to actively engage with Jon and the Cenovus leadership team on our safety, financial and sustainability commitments. In 2023, our industry experienced continued commodity price volatility, significantly driven by geopolitical events, including the ongoing war in Ukraine and more recently, the spreading conflict in the Middle East. While we expect commodity markets to remain volatile for the foreseeable future, the work we have done to reduce costs and strengthen Cenovus’s balance sheet has positioned the company to remain resilient in a wide range of commodity price environments. Internally, Cenovus continues to focus on the things that are within our control. The company has a top-tier portfolio of integrated assets, a solid business plan and is laser focused on safety and reliability. I’m confident management is on the right track to further unlock the potential of the company’s asset base and deliver on the promise of Cenovus’s long-term strategy. Cenovus continued to return significant cash to shareholders in 2023 in the form of higher dividends and share and warrant repurchases, in line with its capital allocation strategy. The company remains focused on achieving its $4 billion net debt target, to enable even stronger shareholder returns in the future. Our Board continues to evolve in support of our portfolio. Last July, Canning Fok retired and Harold (Hal) Kvisle and Wayne Shaw have decided not to stand for re-election at the 2024 annual meeting of shareholders (AGM) to be held on May 1, 2024. On behalf of the entire Board, I want to express our thanks for their support over the years. Last November, we welcomed new directors James Girgulis and Michael Crothers to the Board. In addition, Stephen Bradley has been nominated to stand for election at the AGM. The addition of their skills and experience supports our ongoing Board renewal process which focuses on an orderly succession of directors, while maintaining an appropriate balance and diversity of skills, experience and perspectives. As we work to decarbonize our operations, I’m more convinced than ever that Cenovus, and our industry, have a critical, long-term role to play as the global energy mix diversifies and becomes lower carbon. Canada has the resources, skilled people and 6 | CENOVUS ENERGY 2023 ANNUAL REPORT technological know-how to be a global supplier of choice for responsibly produced oil and natural gas to help meet the world’s ever-expanding energy demand. To that end, it has been my privilege to represent Cenovus and our Pathways Alliance partners in discussions with the federal and provincial governments on setting an appropriate and supportive framework for our decarbonization efforts, including the Pathways Alliance foundational carbon capture and storage (CCS) project. Together, Pathways Alliance companies have significantly progressed work and are investing time and capital to ensure we are ready to make final investment decisions and start building the Pathways Alliance CCS project when the appropriate fiscal and policy supports are in place. Pathways’ plans are critical to helping Canada achieve its climate goals, and there is an urgent need to clearly establish government co-funding programs as well as realistic and achievable emissions reduction policies similar to those that are enabling large CCS projects to proceed in other oil producing jurisdictions around the world. Global capital is highly mobile and without making progress on this front, Canada risks being severely constrained as decarbonization investment is directed to markets offering higher rates of return and lower risk for investments in oil and gas production and emissions reduction projects. Getting it right is critical, to our economy, our people, and the security of our energy supply. And as recent power shortages in my home province of Alberta have shown, even an energy-rich nation such as Canada can face energy constraints. I will continue to devote my time to this important effort in 2024 and beyond. In closing, I want to thank our shareholders for their continued trust in the company and the Board and thank our employees and contractors for continuing the important work of providing responsible energy products to Canada and the world. /s/ Alex Pourbaix EXECUTIVE CHAIR Management’s Discussion and Analysis (unaudited) FOR THE YEAR ENDED DECEMBER 31, 2023 (Canadian Dollars) Overview of Cenovus Year in Review Operating and Financial Results Commodity Prices Underlying our Financial Results Outlook Reportable Segments Upstream Oil Sands Conventional Offshore Downstream Canadian Refining U.S. Refining 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 8 8 11 16 19 22 23 23 27 29 33 33 35 38 40 43 44 49 68 70 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, joint arrangements, and partnership interests held directly or indirectly by, Cenovus Energy Inc.) dated February 14, 2024, should be read in conjunction with our December 31, 2023 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 14, 2024, 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 14, 2024. Additional information about Cenovus, including our quarterly and annual reports, Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR+ at sedarplus.ca, 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, do not constitute part of this MD&A. Basis of Presentation This MD&A and the Consolidated Financial Statements were prepared in Canadian dollars, (which includes references to “dollar” or “$”), except where another currency is indicated, and in accordance with International Financial Reporting Accounting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board. Production volumes are presented on a before royalties basis. Refer to the Abbreviations section for commonly used oil and gas terms. CENOVUS ENERGY 2023 ANNUAL REPORT | 7 OVERVIEW OF CENOVUS We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian- based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”). 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, natural gas and refined petroleum products in Canada and internationally. Our physically and economically 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, natural gas and NGLs production through to the sale of finished products such as transportation fuels. For a description of our business segments see the Reportable Segments section of this MD&A. Our Strategy At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including reaching and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and the prioritization of Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and common share purchases, reinvest in our business, and diversify our portfolio. On December 14, 2023, we released our 2024 budget focused on disciplined capital investment and balancing growth of our base business with meaningful shareholder returns. We will remain focused on safe operations, reducing costs, capital discipline and realizing the full value of our integrated business. For further details, see the Outlook section of this MD&A and our 2024 Corporate Guidance dated December 13, 2023, available on our website at cenovus.com. YEAR IN REVIEW In 2023, we achieved a number of operational milestones, further enhanced our integrated operations and delivered significant returns to shareholders. • • • Delivered safe and reliable upstream performance. Upstream production averaged 778.7 thousand BOE per day, compared with 786.2 thousand BOE per day in 2022. In the Conventional segment, we quickly and safely responded to significant wildfire activity that started in the second quarter. In the Oil Sands segment, our performance was impacted by lower production in the first half of the year as we prepared for the start-up of new well pads. We were able to regain momentum in the last half of the year. Upstream production averaged 808.6 thousand BOE per day in the fourth quarter, our highest quarterly average since the fourth quarter of 2021. Achieved Offshore milestones. We materially progressed the West White Rose project to deliver first oil in 2026. Construction is approximately 75 percent complete, and we reached a major milestone on the project in the second quarter with the completion of the conical slip form operation for the concrete gravity structure. The Terra Nova floating production, storage and offloading unit (“FPSO”) returned to the field in August and began producing in late November. We also achieved first gas production from the MAC field in Indonesia in September. Further integrated our heavy oil production and refining capabilities. In February, we acquired the remaining 50 percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”), providing us full ownership and operatorship of the refinery (the “Toledo Acquisition”). We safely returned the refinery to full operations in June. At the Superior Refinery, we continued to progress towards a return to full operations. The Toledo Acquisition and the start-up of the Superior Refinery added approximately 129.0 thousand barrels per day of refining capacity, of which 79.0 thousand barrels per day is heavy oil refining capacity. • Safe and strong Canadian Refining performance. In 2023, average crude oil unit throughput (or “throughput”) increased 7.8 thousand barrels per day to 100.7 thousand barrels per day, and crude utilization was 91 percent (2022 – 84 percent). Average refined product production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day. The increases in throughput and refined product production were due to limited downtime and reliable operations. • U.S. Refining operations. Average throughput increased 58.9 thousand barrels per day to 459.7 thousand barrels per day in 2023. Crude utilization was 75 percent (2022 – 80 percent) and refined product production averaged 485.0 thousand barrels per day, an increase of 65.1 thousand barrels per day from 2022. The increases in throughput and refined product production were mainly driven by the Toledo and Superior refineries discussed above. The increases were partially offset by unplanned outages and planned maintenance across our operated and non-operated assets. • Reduced long-term debt. We purchased US$1.0 billion of long-term debt in the third quarter at a discount of $84 million. In 2023 compared with 2022, long-term debt decreased $1.6 billion to $7.1 billion and Net Debt increased $778 million to $5.1 billion at December 31, 2023. In 2023, we strengthened our credit ratings with a rating upgrade from Finch Ratings Inc. to BBB Stable and improved outlooks from S&P Global Ratings and Moody’s Investors Service from Stable to Positive. • Delivered significant cash returns to shareholders. We returned $2.8 billion to shareholders, composed of the purchase of 43.6 million common shares for $1.1 billion through our NCIB, $1.0 billion through common share base dividends and preferred share dividends, and $711 million for the purchase and cancellation of 45.5 million Cenovus Warrants. On February 14, 2024, the Board declared a first quarter base dividend of $0.140 per common share and dividends for our preferred shares of $9 million. • Generated $8.8 billion in Adjusted Funds Flow. Cash flow from operating activities was $7.4 billion (2022 – $11.4 billion) and Adjusted Funds Flow was $8.8 billion (2022 – $11.0 billion), primarily reflecting a weaker commodity price environment. Brent and WTI both decreased 18 percent, to US$82.62 per barrel and US$77.62 per barrel, respectively, and WCS at Hardisty decreased 22 percent to US$58.97 per barrel compared with 2022. Benchmark refined product pricing also fell compared with 2022, with diesel pricing decreasing 24 percent and gasoline pricing decreasing 19 percent. The Chicago 3-2-1 crack spread declined 29 percent to US$24.19 per barrel. • Pathways Alliance advances. Engineering, subsurface evaluation and environmental field work for the proposed carbon capture and storage (“CCS”) project was completed in preparation for filing regulatory applications in the first half of 2024. If completed, the CCS project will be one of the world’s largest CCS networks and play an essential role in helping Canada progress its net zero ambitions. January 1, 2024, marked the third anniversary of the closing of the transaction to combine Cenovus and Husky Energy Inc. (“Husky”). We have made significant progress advancing our strategy to maximize shareholder value through safe operations, the integration of our assets, cost and sustainability leadership, financial discipline, and Free Funds Flow growth. Over the three years we reduced long-term debt by $6.9 billion and reduced Net Debt by $8.0 billion. We have returned $6.7 billion to shareholders through our shareholder returns strategy, including the purchase and cancellation of 173.1 million common shares through our NCIB, the purchase and cancellation of 45.5 million Cenovus Warrants, and payment of dividends. We further integrated our assets through strategic acquisitions and completed the Superior Refinery rebuild. Lastly, we developed and are progressing work around our ambitious ESG targets. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 3 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 4 8 | CENOVUS ENERGY 2023 ANNUAL REPORT OVERVIEW OF CENOVUS We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian- based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”). 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, natural gas and refined petroleum products in Canada and internationally. Our physically and economically 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, natural gas and NGLs production through to the sale of finished products such as For a description of our business segments see the Reportable Segments section of this MD&A. transportation fuels. Our Strategy At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five strategic objectives include delivering top-tier safety performance and sustainability leadership; maximizing value through competitive cost structures and optimizing margins; a focus on financial discipline, including reaching and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital to projects that generate returns at the bottom of the commodity price cycle; and the prioritization of Free Funds Flow generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and common share purchases, reinvest in our business, and diversify our portfolio. On December 14, 2023, we released our 2024 budget focused on disciplined capital investment and balancing growth of our base business with meaningful shareholder returns. We will remain focused on safe operations, reducing costs, capital discipline and realizing the full value of our integrated business. For further details, see the Outlook section of this MD&A and our 2024 Corporate Guidance dated December 13, 2023, available on our website at cenovus.com. YEAR IN REVIEW returns to shareholders. In 2023, we achieved a number of operational milestones, further enhanced our integrated operations and delivered significant • Delivered safe and reliable upstream performance. Upstream production averaged 778.7 thousand BOE per day, compared with 786.2 thousand BOE per day in 2022. In the Conventional segment, we quickly and safely responded to significant wildfire activity that started in the second quarter. In the Oil Sands segment, our performance was impacted by lower production in the first half of the year as we prepared for the start-up of new well pads. We were able to regain momentum in the last half of the year. Upstream production averaged 808.6 thousand BOE per day in the fourth quarter, our highest quarterly average since the fourth quarter of 2021. • Achieved Offshore milestones. We materially progressed the West White Rose project to deliver first oil in 2026. Construction is approximately 75 percent complete, and we reached a major milestone on the project in the second quarter with the completion of the conical slip form operation for the concrete gravity structure. The Terra Nova floating production, storage and offloading unit (“FPSO”) returned to the field in August and began producing in late November. We also achieved first gas production from the MAC field in Indonesia in September. • Further integrated our heavy oil production and refining capabilities. In February, we acquired the remaining 50 percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”), providing us full ownership and operatorship of the refinery (the “Toledo Acquisition”). We safely returned the refinery to full operations in June. At the Superior Refinery, we continued to progress towards a return to full operations. The Toledo Acquisition and the start-up of the Superior Refinery added approximately 129.0 thousand barrels per day of refining capacity, of which 79.0 thousand barrels per day is heavy oil refining capacity. • • • • • • Safe and strong Canadian Refining performance. In 2023, average crude oil unit throughput (or “throughput”) increased 7.8 thousand barrels per day to 100.7 thousand barrels per day, and crude utilization was 91 percent (2022 – 84 percent). Average refined product production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day. The increases in throughput and refined product production were due to limited downtime and reliable operations. U.S. Refining operations. Average throughput increased 58.9 thousand barrels per day to 459.7 thousand barrels per day in 2023. Crude utilization was 75 percent (2022 – 80 percent) and refined product production averaged 485.0 thousand barrels per day, an increase of 65.1 thousand barrels per day from 2022. The increases in throughput and refined product production were mainly driven by the Toledo and Superior refineries discussed above. The increases were partially offset by unplanned outages and planned maintenance across our operated and non-operated assets. Reduced long-term debt. We purchased US$1.0 billion of long-term debt in the third quarter at a discount of $84 million. In 2023 compared with 2022, long-term debt decreased $1.6 billion to $7.1 billion and Net Debt increased $778 million to $5.1 billion at December 31, 2023. In 2023, we strengthened our credit ratings with a rating upgrade from Finch Ratings Inc. to BBB Stable and improved outlooks from S&P Global Ratings and Moody’s Investors Service from Stable to Positive. Delivered significant cash returns to shareholders. We returned $2.8 billion to shareholders, composed of the purchase of 43.6 million common shares for $1.1 billion through our NCIB, $1.0 billion through common share base dividends and preferred share dividends, and $711 million for the purchase and cancellation of 45.5 million Cenovus Warrants. On February 14, 2024, the Board declared a first quarter base dividend of $0.140 per common share and dividends for our preferred shares of $9 million. Generated $8.8 billion in Adjusted Funds Flow. Cash flow from operating activities was $7.4 billion (2022 – $11.4 billion) and Adjusted Funds Flow was $8.8 billion (2022 – $11.0 billion), primarily reflecting a weaker commodity price environment. Brent and WTI both decreased 18 percent, to US$82.62 per barrel and US$77.62 per barrel, respectively, and WCS at Hardisty decreased 22 percent to US$58.97 per barrel compared with 2022. Benchmark refined product pricing also fell compared with 2022, with diesel pricing decreasing 24 percent and gasoline pricing decreasing 19 percent. The Chicago 3-2-1 crack spread declined 29 percent to US$24.19 per barrel. Pathways Alliance advances. Engineering, subsurface evaluation and environmental field work for the proposed carbon capture and storage (“CCS”) project was completed in preparation for filing regulatory applications in the first half of 2024. If completed, the CCS project will be one of the world’s largest CCS networks and play an essential role in helping Canada progress its net zero ambitions. January 1, 2024, marked the third anniversary of the closing of the transaction to combine Cenovus and Husky Energy Inc. (“Husky”). We have made significant progress advancing our strategy to maximize shareholder value through safe operations, the integration of our assets, cost and sustainability leadership, financial discipline, and Free Funds Flow growth. Over the three years we reduced long-term debt by $6.9 billion and reduced Net Debt by $8.0 billion. We have returned $6.7 billion to shareholders through our shareholder returns strategy, including the purchase and cancellation of 173.1 million common shares through our NCIB, the purchase and cancellation of 45.5 million Cenovus Warrants, and payment of dividends. We further integrated our assets through strategic acquisitions and completed the Superior Refinery rebuild. Lastly, we developed and are progressing work around our ambitious ESG targets. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 3 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 4 CENOVUS ENERGY 2023 ANNUAL REPORT | 9 Summary of Annual Results ($ millions, except where indicated) Upstream Production Volumes (1) (MBOE/d) Downstream Crude Oil Unit Throughput (2) (Mbbls/d) Downstream Production Volumes (Mbbls/d) Revenues Operating Margin (3) Cash From (Used In) Operating Activities Adjusted Funds Flow (3) Per Share – Basic (3) ($) Per Share – Diluted (3) ($) Capital Investment Free Funds Flow (3) Net Earnings (Loss) (4) Per Share – Basic ($) Per Share – Diluted ($) 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 Payment for Purchase of Warrants Preferred Share Dividends 2023 778.7 560.4 599.2 52,204 11,022 7,388 8,803 4.64 4.57 4,298 4,505 4,109 2.15 2.12 53,915 18,993 7,108 5,060 2,798 990 0.525 — — 1,061 711 36 2022 786.2 493.7 525.1 66,897 14,263 11,403 10,978 5.63 5.47 3,708 7,270 6,450 3.29 3.20 55,869 20,259 8,691 4,282 3,457 682 0.350 219 0.114 2,530 — 26 2021 791.5 508.0 537.7 46,357 9,373 5,919 7,248 3.59 3.54 2,563 4,685 587 0.27 0.27 54,104 23,191 12,385 9,591 475 176 0.088 — — 265 — 34 (1) (2) (3) (4) 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. Non-GAAP financial measure 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. OPERATING AND FINANCIAL RESULTS Selected Operating Results and Oil and Gas Reserves — 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) Oil and Gas Reserves (MMBOE) Total Proved Probable Total Proved Plus Probable Production with 2022: 2023 595.4 119.9 63.4 778.7 576.7 16.7 14.1 32.5 832.6 778.7 5,866 2,836 8,702 Percent Change 1 (6) (10) (1) 1 2 (26) (10) (4) (1) (4) 2 (2) 2022 588.7 127.2 70.3 786.2 570.3 16.3 19.1 36.2 866.1 786.2 6,082 2,787 8,869 (1) Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type. In 2023, total upstream production decreased slightly from 2022. The factors below increased production in 2023 compared • Higher production from our Oil Sands assets mainly due to the acquisition of the remaining 50 percent interest in the Sunrise Oil Sands Partnership (“SOSP”, “Sunrise” or the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp Canada”) on August 31, 2022, and successful results from the 2023 redevelopment program. Partially offsetting the increase was lower production at Christina Lake resulting from the timing of new well pads in 2023. • First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and from the MAC field in the third quarter of 2023. The factors below decreased production in 2023 compared with 2022: The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel in early April, reconnected in May. • • • activity in the second quarter of 2023. temporarily increased sales volumes. 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, 2023 were approximately 5.9 billion BOE and 8.7 billion BOE, respectively. Total proved reserves decreased four percent from 2022, and proved plus probable reserves decreased two percent from 2022. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 5 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 6 10 | CENOVUS ENERGY 2023 ANNUAL REPORT Summary of Annual Results ($ millions, except where indicated) Upstream Production Volumes (1) (MBOE/d) Downstream Crude Oil Unit Throughput (2) (Mbbls/d) Downstream Production Volumes (Mbbls/d) Cash From (Used In) Operating Activities Revenues Operating Margin (3) Adjusted Funds Flow (3) Per Share – Basic (3) ($) Per Share – Diluted (3) ($) Capital Investment Free Funds Flow (3) Net Earnings (Loss) (4) Per Share – Basic ($) Per Share – Diluted ($) 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 Payment for Purchase of Warrants Preferred Share Dividends 2023 778.7 560.4 599.2 52,204 11,022 7,388 8,803 4.64 4.57 4,298 4,505 4,109 2.15 2.12 53,915 18,993 7,108 5,060 2,798 990 0.525 — — 1,061 711 36 2022 786.2 493.7 525.1 66,897 14,263 11,403 10,978 5.63 5.47 3,708 7,270 6,450 3.29 3.20 55,869 20,259 8,691 4,282 3,457 682 0.350 219 0.114 2,530 — 26 2021 791.5 508.0 537.7 46,357 9,373 5,919 7,248 3.59 3.54 2,563 4,685 587 0.27 0.27 54,104 23,191 12,385 9,591 475 176 0.088 — — 265 — 34 (1) (2) (3) (4) 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. Non-GAAP financial measure 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. OPERATING AND FINANCIAL RESULTS Selected Operating Results and Oil and Gas Reserves — 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) Oil and Gas Reserves (MMBOE) Total Proved Probable Total Proved Plus Probable 2023 595.4 119.9 63.4 778.7 576.7 16.7 14.1 32.5 832.6 778.7 5,866 2,836 8,702 Percent Change 1 (6) (10) (1) 1 2 (26) (10) (4) (1) (4) 2 (2) 2022 588.7 127.2 70.3 786.2 570.3 16.3 19.1 36.2 866.1 786.2 6,082 2,787 8,869 (1) Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type. Production In 2023, total upstream production decreased slightly from 2022. The factors below increased production in 2023 compared with 2022: • • Higher production from our Oil Sands assets mainly due to the acquisition of the remaining 50 percent interest in the Sunrise Oil Sands Partnership (“SOSP”, “Sunrise” or the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp Canada”) on August 31, 2022, and successful results from the 2023 redevelopment program. Partially offsetting the increase was lower production at Christina Lake resulting from the timing of new well pads in 2023. First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and from the MAC field in the third quarter of 2023. The factors below decreased production in 2023 compared with 2022: • • • The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire activity in the second quarter of 2023. Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that temporarily increased sales volumes. A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical by a third-party vessel in early April, reconnected in May. 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, 2023 were approximately 5.9 billion BOE and 8.7 billion BOE, respectively. Total proved reserves decreased four percent from 2022, and proved plus probable reserves decreased two percent from 2022. Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 5 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 6 CENOVUS ENERGY 2023 ANNUAL REPORT | 11 Selected Operating Results — Downstream Downstream Crude Oil Unit Throughput (Mbbls/d) Canadian Refining U.S. Refining Total Crude Oil Unit Throughput Downstream Production Volumes (1) (Mbbls/d) Canadian Refining U.S. Refining Total Downstream Production 2023 100.7 459.7 560.4 114.2 485.0 599.2 Percent Change 8 15 14 9 16 14 2022 92.9 400.8 493.7 105.2 419.9 525.1 (1) Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product type. The Canadian Refining assets ran well in 2023 with crude utilization at the Upgrader and Lloydminster Refinery of 90 percent and 95 percent, respectively (2022 – 84 percent and 83 percent, respectively). The improved performance was driven by consistent operations in 2023, compared with planned turnarounds and temporary unplanned outages in 2022 at both assets. The increases were partially offset by unplanned outages at the Upgrader in the second and fourth quarters of 2023. In our U.S. Refining operations, crude throughput increased by 58.9 thousand barrels per day as we: • • Closed the acquisition of the remaining 50 percent of the Toledo Refinery, increasing our throughput capacity by 80.0 thousand barrels per day. Safely restarted the Toledo Refinery. The Refinery was fully operational by the end of June and the utilization rate was 88 percent in the last half of the year. Utilization for the full year was 57 percent (2022 – 45 percent). • Made significant progress towards a return to full operations at the Superior Refinery after being shut down since 2018. We introduced crude oil in mid-March and safely restarted the fluid catalytic cracking unit (“FCCU”) in early October. During the last half of the year crude utilization was 66 percent. Had strong performance from the Wood River Refinery. In addition, planned turnaround activity in 2022 had a greater impact than the planned spring 2023 turnaround. Combined utilization at the Wood River and Borger refineries was 81 percent (2022 – 83 percent). • The increases were partially offset by: • • • Planned turnarounds and temporary unplanned outages at the Borger Refinery that had a larger impact than the unplanned outages and turnaround completed in 2022. Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Crude utilization at the Lima Refinery in 2023 was 85 percent (2022 – 90 percent). In the fourth quarter of 2023, we flexed throughput at our U.S. refineries to optimize our margins as a result of significantly lower refining benchmark pricing. Selected Consolidated Financial Results Revenues Revenues decreased 22 percent to $52.2 billion from 2022 primarily due to lower blended crude oil benchmark pricing impacting our Oil Sands segment, and lower natural gas and refined product benchmark pricing, partially offset by a weaker Canadian dollar on average relative to the U.S. dollar. Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. 2023 63,708 3,270 60,438 31,425 11,088 6,891 12 11,022 2022 79,152 4,868 74,284 39,150 12,301 6,839 1,731 14,263 (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further Operating Margin ($ millions) Gross Sales (1) Less: Royalties Revenues (1) Expenses Operating Margin details. Purchased Product (1) Transportation and Blending (1) Operating Expenses Realized (Gain) Loss on Risk Management Activities Operating Margin by Segment Years Ended December 31, 2023 and 2022 Operating Margin decreased $3.2 billion to $11.0 billion in 2023 compared with 2022, primarily due to: • • • • • Lower realized crude oil and NGLs sales prices resulting from lower benchmark pricing. Decreased gross margin from the U.S. Refining segment resulting from lower market crack spreads. Lower sales volumes from our Offshore segment. Higher non-fuel operating expenses from the Oil Sands segment. Oil Sands per-unit non-fuel operating expenses increased 15 percent from 2022 to $8.94 per barrel in 2023, primarily due to higher repairs and maintenance costs as a result of planned turnarounds at Foster Creek and Christina Lake, and lower gross sales volumes. A rise in operating expenses in the U.S. Refining segment, primarily due to the Toledo acquisition and the start-up of both the Superior and Toledo refineries. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 7 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 8 12 | CENOVUS ENERGY 2023 ANNUAL REPORT Downstream Crude Oil Unit Throughput (Mbbls/d) Canadian Refining U.S. Refining Total Crude Oil Unit Throughput Downstream Production Volumes (1) (Mbbls/d) Canadian Refining U.S. Refining Total Downstream Production 2023 100.7 459.7 560.4 114.2 485.0 599.2 Percent Change 8 15 14 9 16 14 2022 92.9 400.8 493.7 105.2 419.9 525.1 (1) Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product type. The Canadian Refining assets ran well in 2023 with crude utilization at the Upgrader and Lloydminster Refinery of 90 percent and 95 percent, respectively (2022 – 84 percent and 83 percent, respectively). The improved performance was driven by consistent operations in 2023, compared with planned turnarounds and temporary unplanned outages in 2022 at both assets. The increases were partially offset by unplanned outages at the Upgrader in the second and fourth quarters of 2023. In our U.S. Refining operations, crude throughput increased by 58.9 thousand barrels per day as we: Closed the acquisition of the remaining 50 percent of the Toledo Refinery, increasing our throughput capacity by 80.0 thousand barrels per day. Safely restarted the Toledo Refinery. The Refinery was fully operational by the end of June and the utilization rate was 88 percent in the last half of the year. Utilization for the full year was 57 percent (2022 – 45 percent). • Made significant progress towards a return to full operations at the Superior Refinery after being shut down since 2018. We introduced crude oil in mid-March and safely restarted the fluid catalytic cracking unit (“FCCU”) in early October. During the last half of the year crude utilization was 66 percent. • Had strong performance from the Wood River Refinery. In addition, planned turnaround activity in 2022 had a greater impact than the planned spring 2023 turnaround. Combined utilization at the Wood River and Borger refineries was 81 percent (2022 – 83 percent). The increases were partially offset by: Planned turnarounds and temporary unplanned outages at the Borger Refinery that had a larger impact than the unplanned outages and turnaround completed in 2022. Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Crude utilization at the Lima Refinery in 2023 was 85 percent (2022 – 90 percent). In the fourth quarter of 2023, we flexed throughput at our U.S. refineries to optimize our margins as a result of significantly lower refining benchmark pricing. • • • • • Selected Consolidated Financial Results Revenues Revenues decreased 22 percent to $52.2 billion from 2022 primarily due to lower blended crude oil benchmark pricing impacting our Oil Sands segment, and lower natural gas and refined product benchmark pricing, partially offset by a weaker Canadian dollar on average relative to the U.S. dollar. Selected Operating Results — Downstream Operating Margin Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. ($ millions) Gross Sales (1) Less: Royalties Revenues (1) Expenses Purchased Product (1) Transportation and Blending (1) Operating Expenses Realized (Gain) Loss on Risk Management Activities Operating Margin 2023 63,708 3,270 60,438 31,425 11,088 6,891 12 11,022 2022 79,152 4,868 74,284 39,150 12,301 6,839 1,731 14,263 (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Operating Margin by Segment Years Ended December 31, 2023 and 2022 ) s n o i l l i m $ ( 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 8,979 8,169 1,235 583 1,610 1,118 1,740 675 699 477 Oil Sands Conventional Offshore Canadian Refining U.S. Refining 2023 2022 Operating Margin decreased $3.2 billion to $11.0 billion in 2023 compared with 2022, primarily due to: • • • • • Lower realized crude oil and NGLs sales prices resulting from lower benchmark pricing. Decreased gross margin from the U.S. Refining segment resulting from lower market crack spreads. Lower sales volumes from our Offshore segment. Higher non-fuel operating expenses from the Oil Sands segment. Oil Sands per-unit non-fuel operating expenses increased 15 percent from 2022 to $8.94 per barrel in 2023, primarily due to higher repairs and maintenance costs as a result of planned turnarounds at Foster Creek and Christina Lake, and lower gross sales volumes. A rise in operating expenses in the U.S. Refining segment, primarily due to the Toledo acquisition and the start-up of both the Superior and Toledo refineries. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 7 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 8 CENOVUS ENERGY 2023 ANNUAL REPORT | 13 These decreases in Operating Margin were partially offset by: • • • Significantly lower realized risk management losses in 2023, compared with 2022. Lower royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark pricing. Higher throughput and refined product production primarily from the Toledo and Superior refineries as discussed above. Operating Margin in the Conventional segment decreased compared with 2022, primarily due to lower realized natural gas prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Refining segments on natural gas purchased from the Conventional segment. Cash From (Used in) Operating Activities and Adjusted Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. ($ millions) Cash From (Used in) Operating Activities (Add) Deduct: Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow 2023 7,388 (222) (1,193) 8,803 2022 11,403 (150) 575 10,978 Cash from operating activities decreased in 2023 compared with 2022. The decline was primarily due to a lower Operating Margin as discussed above and changes in non-cash working capital, partially offset by $631 million paid in 2022 for the contingent payment associated with the acquisition of 50 percent of the FCCL Partnership. The net change in non-cash working capital in 2023 was $1.2 billion, mainly due to the settlement of a $1.2 billion income tax liability in the first quarter of 2023. Adjusted Funds Flow was lower in 2023 compared with 2022, primarily due to decreased Operating Margin. Net Earnings (Loss) Net earnings in 2023 was $4.1 billion compared with $6.5 billion in 2022. The decrease was primarily due to lower Operating Margin as discussed above, in addition to: • • • The revaluation gain related to the Sunrise Acquisition in 2022. Lower other income in 2023 primarily due to the 2022 insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region. Higher net gains on asset divestitures in 2022. The decreases were partially offset by: • • • • • Lower income tax expense. Unrealized foreign exchange gains in 2023 compared with losses in 2022. Decreased general and administrative expenses due to lower long-term incentive costs. Lower finance costs due to the purchase of unsecured notes in 2022 and the third quarter of 2023. Decreased losses on the re-measurement of contingent payments. Net Debt As at ($ millions) 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 December 31, 2023 December 31, 2022 179 — 7,108 7,287 (2,227) 5,060 115 — 8,691 8,806 (4,524) 4,282 Long-term debt decreased by $1.6 billion from December 31, 2022, primarily due to the purchase of unsecured notes with an aggregate principal amount of US$1.0 billion in the third quarter of 2023. Net Debt increased by $778 million from December 31, 2022, mainly due to cash from operating activities of $7.4 billion, capital investment of $4.3 billion, acquisitions of $515 million and cash returns to shareholders of $2.8 billion. For further details see the Liquidity and Capital Resources section of this MD&A. Capital Investment (1) ($ millions) Upstream Oil Sands Conventional Offshore Total Upstream Downstream Canadian Refining U.S. Refining Total Downstream Corporate and Eliminations Total Capital Investment • • • • region. Toledo refineries. Drilling Activity Foster Creek Christina Lake Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Other (2) (1) Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes capital expenditures related to the HCML joint venture. Capital investment in 2023 was mainly related to: Sustaining activities in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Drilling, completion, tie-in and infrastructure projects in the Conventional segment. The progression of the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic The Superior Refinery rebuild and margin improvement and reliability initiatives at the Wood River, Borger, Lima and Net Stratigraphic Test Wells and Observation Wells Net Production Wells (1) 2023 87 53 38 71 3 3 255 2022 52 — 15 98 8 22 195 2023 44 27 24 9 34 — 138 SAGD well pairs in the Oil Sands segment are counted as a single producing well. (1) (2) Includes new resource plays. Stratigraphic test wells were drilled to help identify future well pad locations and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions. (net wells) Conventional Drilled 38 2023 Completed 37 Tied-in 41 Drilled 31 2022 Completed 35 Tied-in 36 In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in 2023 (2022 – drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia). 2023 2,382 452 642 3,476 145 602 747 75 4,298 2022 1,792 344 310 2,446 117 1,059 1,176 86 3,708 2022 29 31 10 33 11 — 114 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 9 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 10 14 | CENOVUS ENERGY 2023 ANNUAL REPORT These decreases in Operating Margin were partially offset by: Significantly lower realized risk management losses in 2023, compared with 2022. Lower royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark Higher throughput and refined product production primarily from the Toledo and Superior refineries as discussed pricing. above. Operating Margin in the Conventional segment decreased compared with 2022, primarily due to lower realized natural gas prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Refining segments on natural gas purchased from the Conventional segment. Cash From (Used in) Operating Activities and Adjusted Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. ($ millions) (Add) Deduct: Cash From (Used in) Operating Activities Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow 2023 7,388 (222) (1,193) 8,803 2022 11,403 (150) 575 10,978 Cash from operating activities decreased in 2023 compared with 2022. The decline was primarily due to a lower Operating Margin as discussed above and changes in non-cash working capital, partially offset by $631 million paid in 2022 for the contingent payment associated with the acquisition of 50 percent of the FCCL Partnership. The net change in non-cash working capital in 2023 was $1.2 billion, mainly due to the settlement of a $1.2 billion income tax liability in the first quarter of 2023. Adjusted Funds Flow was lower in 2023 compared with 2022, primarily due to decreased Operating Margin. Net Earnings (Loss) Margin as discussed above, in addition to: Net earnings in 2023 was $4.1 billion compared with $6.5 billion in 2022. The decrease was primarily due to lower Operating The revaluation gain related to the Sunrise Acquisition in 2022. Lower other income in 2023 primarily due to the 2022 insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region. Higher net gains on asset divestitures in 2022. The decreases were partially offset by: Lower income tax expense. Unrealized foreign exchange gains in 2023 compared with losses in 2022. Decreased general and administrative expenses due to lower long-term incentive costs. Lower finance costs due to the purchase of unsecured notes in 2022 and the third quarter of 2023. Decreased losses on the re-measurement of contingent payments. • • • • • • • • • • • Net Debt As at ($ millions) 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 December 31, 2023 December 31, 2022 179 — 7,108 7,287 (2,227) 5,060 115 — 8,691 8,806 (4,524) 4,282 Long-term debt decreased by $1.6 billion from December 31, 2022, primarily due to the purchase of unsecured notes with an aggregate principal amount of US$1.0 billion in the third quarter of 2023. Net Debt increased by $778 million from December 31, 2022, mainly due to cash from operating activities of $7.4 billion, capital investment of $4.3 billion, acquisitions of $515 million and cash returns to shareholders of $2.8 billion. For further details see the Liquidity and Capital Resources section of this MD&A. Capital Investment (1) ($ millions) Upstream Oil Sands Conventional Offshore Total Upstream Downstream Canadian Refining U.S. Refining Total Downstream Corporate and Eliminations Total Capital Investment 2023 2,382 452 642 3,476 145 602 747 75 4,298 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 capital expenditures related to the HCML joint venture. Capital investment in 2023 was mainly related to: • • • • Sustaining activities in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Drilling, completion, tie-in and infrastructure projects in the Conventional segment. The progression of the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic region. The Superior Refinery rebuild and margin improvement and reliability initiatives at the Wood River, Borger, Lima and Toledo refineries. Drilling Activity Foster Creek Christina Lake Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Other (2) Net Stratigraphic Test Wells and Observation Wells Net Production Wells (1) 2023 87 53 38 71 3 3 255 2022 52 — 15 98 8 22 195 2023 44 27 24 9 34 — 138 2022 29 31 10 33 11 — 114 (1) (2) SAGD well pairs in the Oil Sands segment are counted as a single producing well. Includes new resource plays. Stratigraphic test wells were drilled to help identify future well pad locations and to further progress the evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions. (net wells) Conventional Drilled 38 2023 Completed 37 Tied-in 41 Drilled 31 2022 Completed 35 Tied-in 36 In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in 2023 (2022 – drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia). Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 9 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 10 CENOVUS ENERGY 2023 ANNUAL REPORT | 15 COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and 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$/bbl, unless otherwise indicated) Dated Brent WTI Differential Dated Brent-WTI WCS at Hardisty Differential WTI-WCS at Hardisty WCS at Hardisty (C$/bbl) WCS at Nederland Differential WTI-WCS at Nederland Condensate (C5 at Edmonton) Differential Condensate-WTI Premium/(Discount) Differential Condensate-WCS (2) Premium/(Discount) Condensate (C$/bbl) Synthetic at Edmonton Differential Synthetic-WTI Premium/(Discount) Synthetic at Edmonton (C$/bbl) Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (3) Group 3 3-2-1 Crack Spread (3) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (4) (C$/Mcf) NYMEX (5) (US$/Mcf) Foreign Exchange Rates US$ per C$1 - Average US$ per C$1 - End of Period RMB per C$1 - Average 2023 82.62 77.62 5.00 58.97 18.65 79.59 69.74 7.88 76.61 (1.01) 17.64 103.43 79.61 1.99 107.47 97.86 109.70 24.19 29.66 7.04 2.64 2.74 0.741 0.756 5.247 Percent Change 2022 Q4 2023 Q3 2023 Q4 2022 (18) (18) (28) (22) 2 (19) (19) (7) (18) (124) 1 (15) (19) 55 (16) (19) (24) (29) (11) (9) (50) (59) (4) 2 1 101.19 94.23 6.96 76.01 18.22 98.51 85.77 8.46 93.78 (0.45) 17.77 121.78 98.66 4.43 128.19 84.05 78.32 5.73 56.43 21.89 76.95 71.59 6.73 76.24 (2.08) 19.81 103.90 78.64 0.32 107.21 86.76 82.26 4.50 69.35 12.91 93.06 77.89 4.37 77.96 (4.30) 8.61 104.63 84.95 2.69 114.01 120.63 143.85 83.72 107.24 105.59 113.77 34.15 33.21 7.72 5.31 6.64 0.769 0.738 5.170 13.24 18.55 4.77 2.30 2.88 0.734 0.756 5.304 26.06 36.96 7.42 2.60 2.55 0.746 0.740 5.402 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 4.14 117.87 102.80 140.95 32.87 29.99 8.54 5.11 6.26 0.737 0.738 5.241 (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) WCS at Hardisty. (3) (4) (5) 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. Alberta Energy Company ("AECO") 5A natural gas daily index. NYMEX natural gas monthly index. Crude Oil and Condensate Benchmarks Crude oil benchmark prices, Brent and WTI, have trended lower in 2023 compared with 2022. In 2023, we saw a more balanced crude market, resulting in average prices falling from elevated levels in 2022. Global demand growth remained healthy in 2023 despite macroeconomic concerns, but was outpaced by high supply growth from non-OPEC+ countries. Repeated and extended cuts to OPEC+ production quotas have offset production growth elsewhere and supported prices. In the first half of 2022, prices were high as a result of rising global demand amid low global inventories and limited crude production spare capacity, which was exacerbated by risks related to Russian export supply shortfall uncertainty. Prices then decreased gradually in the second half of 2022 as material Russian supply disruption concerns eased and nearly all short-term supply sources were accessed to meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). 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 narrowed in 2023 compared with 2022. In 2022, the differential widened significantly in the months following the Russian invasion of Ukraine in February 2022. 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. On a full- year basis, the average WTI-WCS differential at Hardisty in 2023 was consistent with 2022. Transportation costs reflected pipeline economics in 2022 and 2023 as supply largely remained within export capacity. WCS differentials widened in the fourth quarter of 2023, most notably in December. The widening in the fourth quarter was due to high production and outages at Alberta refineries leading to exports above pipeline capacity. The WCS quality differential was consistent year-over-year, as differentials widened in the second half of 2022 and the first half of 2023 as a result of unplanned refinery maintenance, high global refining utilization, rising supply of medium and heavy oil barrels into the market from OPEC+, releases of SPRs and volatile refined product pricing. 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 in 2023 declined from 2022, due to the same factors impacting the WTI-WCS differential at Hardisty discussed above. In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the 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. In 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with 2022. Synthetic crude prices were elevated in 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil. High upgrader production in 2023 resulted in this premium eroding. The synthetic crude premium to WTI declined in the fourth quarter relative to the third quarter of 2023 as a result of exports above pipeline capacity on light crude pipelines and limited local storage capacity. 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 20 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. On a full-year basis, the average Condensate-WCS differential in 2023 was consistent with 2022. Edmonton condensate differentials are highly seasonal, typically trading at a premium to WTI during peak winter demand and a discount to WTI during the summer months. This is counter-seasonal to the WTI-WCS differential, often resulting in the WCS-Condensate differential experiencing wide swings between summer and winter. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 11 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 12 16 | CENOVUS ENERGY 2023 ANNUAL REPORT COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined product prices and 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 (Average US$/bbl, unless otherwise indicated) 2022 Q4 2023 Q3 2023 Q4 2022 understanding our financial results. Selected Benchmark Prices and Exchange Rates (1) Dated Brent WTI Differential Dated Brent-WTI WCS at Hardisty Differential WTI-WCS at Hardisty WCS at Hardisty (C$/bbl) WCS at Nederland Differential WTI-WCS at Nederland Condensate (C5 at Edmonton) Differential Condensate-WTI Premium/(Discount) Differential Condensate-WCS (2) Premium/(Discount) Condensate (C$/bbl) Synthetic at Edmonton Differential Synthetic-WTI Premium/(Discount) Synthetic at Edmonton (C$/bbl) Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (3) Group 3 3-2-1 Crack Spread (3) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (4) (C$/Mcf) NYMEX (5) (US$/Mcf) Foreign Exchange Rates US$ per C$1 - Average US$ per C$1 - End of Period RMB per C$1 - Average 2023 82.62 77.62 5.00 58.97 18.65 79.59 69.74 7.88 76.61 (1.01) 17.64 103.43 79.61 1.99 107.47 97.86 109.70 24.19 29.66 7.04 2.64 2.74 0.741 0.756 5.247 Percent Change (124) (18) (18) (28) (22) 2 (19) (19) (7) (18) 1 (15) (19) 55 (16) (19) (24) (29) (11) (9) (50) (59) (4) 2 1 101.19 94.23 6.96 76.01 18.22 98.51 85.77 8.46 93.78 (0.45) 17.77 121.78 98.66 4.43 128.19 34.15 33.21 7.72 5.31 6.64 0.769 0.738 5.170 84.05 78.32 5.73 56.43 21.89 76.95 71.59 6.73 76.24 (2.08) 19.81 103.90 78.64 0.32 107.21 13.24 18.55 4.77 2.30 2.88 0.734 0.756 5.304 86.76 82.26 4.50 69.35 12.91 93.06 77.89 4.37 77.96 (4.30) 8.61 104.63 84.95 2.69 114.01 26.06 36.96 7.42 2.60 2.55 0.746 0.740 5.402 120.63 143.85 83.72 107.24 105.59 113.77 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 4.14 117.87 102.80 140.95 32.87 29.99 8.54 5.11 6.26 0.737 0.738 5.241 results, refer to the Netback tables in the Reportable Segments section of this MD&A. (2) WCS at Hardisty. (3) (4) (5) Alberta Energy Company ("AECO") 5A natural gas daily index. NYMEX natural gas monthly index. Crude Oil and Condensate Benchmarks Crude oil benchmark prices, Brent and WTI, have trended lower in 2023 compared with 2022. In 2023, we saw a more balanced crude market, resulting in average prices falling from elevated levels in 2022. Global demand growth remained healthy in 2023 despite macroeconomic concerns, but was outpaced by high supply growth from non-OPEC+ countries. Repeated and extended cuts to OPEC+ production quotas have offset production growth elsewhere and supported prices. In the first half of 2022, prices were high as a result of rising global demand amid low global inventories and limited crude production spare capacity, which was exacerbated by risks related to Russian export supply shortfall uncertainty. Prices then decreased gradually in the second half of 2022 as material Russian supply disruption concerns eased and nearly all short-term supply sources were accessed to meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). 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 narrowed in 2023 compared with 2022. In 2022, the differential widened significantly in the months following the Russian invasion of Ukraine in February 2022. 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. On a full- year basis, the average WTI-WCS differential at Hardisty in 2023 was consistent with 2022. Transportation costs reflected pipeline economics in 2022 and 2023 as supply largely remained within export capacity. WCS differentials widened in the fourth quarter of 2023, most notably in December. The widening in the fourth quarter was due to high production and outages at Alberta refineries leading to exports above pipeline capacity. The WCS quality differential was consistent year-over-year, as differentials widened in the second half of 2022 and the first half of 2023 as a result of unplanned refinery maintenance, high global refining utilization, rising supply of medium and heavy oil barrels into the market from OPEC+, releases of SPRs and volatile refined product pricing. 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 in 2023 declined from 2022, due to the same factors impacting the WTI-WCS differential at Hardisty discussed above. In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the 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. In 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with 2022. Synthetic crude prices were elevated in 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil. High upgrader production in 2023 resulted in this premium eroding. The synthetic crude premium to WTI declined in the fourth quarter relative to the third quarter of 2023 as a result of exports above pipeline capacity on light crude pipelines and limited local storage capacity. Crude Oil Benchmark Prices 120 100 ) l b b / $ S U e g a r e v a ( 80 60 40 20 - (1) These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 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. 2021 2022 2023 Q1 2024F Q2 2024F Q3 2024F Q4 2024F Forward Pricing as at December 31, 2023 Dated Brent WTI WCS at Nederland WCS at Hardisty 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 20 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. On a full-year basis, the average Condensate-WCS differential in 2023 was consistent with 2022. Edmonton condensate differentials are highly seasonal, typically trading at a premium to WTI during peak winter demand and a discount to WTI during the summer months. This is counter-seasonal to the WTI-WCS differential, often resulting in the WCS-Condensate differential experiencing wide swings between summer and winter. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 11 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 12 CENOVUS ENERGY 2023 ANNUAL REPORT | 17 In 2023 and 2022, the average Edmonton condensate benchmark was near parity with WTI as demand for heavy crude blending in Alberta has been strong and condensate supply remains tight. Natural Gas Benchmarks 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 the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. Refined product prices declined in 2023 compared with 2022. Market crack spreads also declined during this period as 2022 saw periods of historically high refined product prices and refining margins due to pandemic refinery rationalization, Russian export volatility and critically low global inventories of refined products. Reduced refinery outages and incremental global capacity additions resulted in declining refined product prices relative to WTI in 2023, compared with 2022, but crack spreads remained above historical norms. Diesel margins declined year-over-year but were high on average amid strong demand, tight global supply and demand balances, and continued low inventories. Gasoline margins were strong on average in 2023 but weakened in the fourth quarter as seasonally lower demand and high refinery utilization resulted in excess supply and high inventory builds. Gasoline and diesel margins, and crack spreads, decreased significantly in December. The Chicago refined product market saw periods of weakness in 2023 relative to Group 3 and the USGC as regional refining utilization was high and waterway maintenance prevented products from being barged to other market demand centers. On a full-year basis, average RINs costs were consistent in 2023 compared with 2022, but declined in the fourth quarter of 2023 due to growing renewable diesel supply. 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 refining margins are affected by many other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the feedstock 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. Refined Product Benchmarks 70 60 50 40 30 20 10 - I ) s N R d n a s d a e r p S k c a r C - l b b / $ S U e g a r e v a ( ) D S L U d n a L U R - l b b / $ S U e g a r e v a ( 175 150 125 100 75 50 25 - Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2021 2022 2023 Chicago 3-2-1 Crack Spread Group 3 3-2-1 Crack Spread RINs (1) Q1 2024F Q2 2024F Q3 2024F Q4 2024F Forward Pricing as at December 31, 2023 RUL ULSD (1) There are no forward prices for RINs. Average NYMEX and AECO natural gas prices decreased significantly in 2023 compared with 2022. Prices were very high in 2022 due to strong U.S. domestic demand and high liquified natural gas exports, coupled with a lagged supply response and strong global pricing amid Russia supply concerns. Prices weakened in 2023 as U.S. supply grew rapidly, reaching record high levels, exceeding demand growth which led to high levels of inventory. 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. dollar 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 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2022, positively impacting our reported revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar as at December 31, 2023, compared with December 31, 2022, resulting in unrealized foreign exchange gains on the translation of our U.S. dollar debt. A portion of our long-term sales contracts in the Asia Pacific region 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 2023, the Canadian dollar on average strengthened slightly relative to RMB compared with 2022, negatively Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net interest expense and affect how certain liabilities are measured and impact our cash flow and financial results. As at December 31, 2023, the Bank of Canada’s Policy Interest Rate was 5.00 percent, an increase from 4.25 percent on December 31, 2022, due to concerns over inflation. On January 24, 2024, the Bank of Canada announced the rate will remain at impacting our reported revenues. Interest Rate Benchmarks 5.00 percent. OUTLOOK Commodity Price Outlook Global crude oil prices traded in a narrower range in 2023 compared with 2022, but remained volatile following the EU import ban on Russia’s crude oil and products and subsequent reshuffling of global trade flows, global macro-economic concerns related to rising interest rates and inflation, and geopolitical events such as the crisis in Israel and Gaza. In 2022, global crude oil prices spiked in the first half of the year following Russia’s invasion of Ukraine as low global spare production capacity stoked fears of supply scarcity. Prices gradually declined in the second half of 2022 as nearly all short-term supply sources were called on, and Russian exports remained resilient. Crude oil demand growth was ultimately strong in 2023 despite weak macroeconomic indicators, supported by the lifting of China’s COVID-19 restrictions earlier in the year. High supply growth from non-OPEC+ put downward pressure on prices through the year; however, the OPEC+ announced and extended production cuts have managed and supported the downward pressure from supply growth. OPEC+ policy remains crucial to global oil balances and prices. 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 shift global trade patterns. The OPEC+ announced extension of production cuts that will continue to be supportive of pricing, with production quotas being a key driver of crude oil prices. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non- OPEC+ supply growth, the refilling of SPRs, and the crisis in Israel and Gaza. In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 13 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 14 18 | CENOVUS ENERGY 2023 ANNUAL REPORT In 2023 and 2022, the average Edmonton condensate benchmark was near parity with WTI as demand for heavy crude blending Natural Gas Benchmarks Average NYMEX and AECO natural gas prices decreased significantly in 2023 compared with 2022. Prices were very high in 2022 due to strong U.S. domestic demand and high liquified natural gas exports, coupled with a lagged supply response and strong global pricing amid Russia supply concerns. Prices weakened in 2023 as U.S. supply grew rapidly, reaching record high levels, exceeding demand growth which led to high levels of inventory. 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. dollar 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 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2022, positively impacting our reported revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar as at December 31, 2023, compared with December 31, 2022, resulting in unrealized foreign exchange gains on the translation of our U.S. dollar debt. A portion of our long-term sales contracts in the Asia Pacific region 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 2023, the Canadian dollar on average strengthened slightly relative to RMB compared with 2022, negatively impacting our reported revenues. On a full-year basis, average RINs costs were consistent in 2023 compared with 2022, but declined in the fourth quarter of 2023 Interest Rate Benchmarks Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are impacted by fluctuations in interest rates. A change in interest rates could change our net interest expense and affect how certain liabilities are measured and impact our cash flow and financial results. As at December 31, 2023, the Bank of Canada’s Policy Interest Rate was 5.00 percent, an increase from 4.25 percent on December 31, 2022, due to concerns over inflation. On January 24, 2024, the Bank of Canada announced the rate will remain at 5.00 percent. OUTLOOK Commodity Price Outlook Global crude oil prices traded in a narrower range in 2023 compared with 2022, but remained volatile following the EU import ban on Russia’s crude oil and products and subsequent reshuffling of global trade flows, global macro-economic concerns related to rising interest rates and inflation, and geopolitical events such as the crisis in Israel and Gaza. In 2022, global crude oil prices spiked in the first half of the year following Russia’s invasion of Ukraine as low global spare production capacity stoked fears of supply scarcity. Prices gradually declined in the second half of 2022 as nearly all short-term supply sources were called on, and Russian exports remained resilient. Crude oil demand growth was ultimately strong in 2023 despite weak macroeconomic indicators, supported by the lifting of China’s COVID-19 restrictions earlier in the year. High supply growth from non-OPEC+ put downward pressure on prices through the year; however, the OPEC+ announced and extended production cuts have managed and supported the downward pressure from supply growth. OPEC+ policy remains crucial to global oil balances and prices. 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 shift global trade patterns. The OPEC+ announced extension of production cuts that will continue to be supportive of pricing, with production quotas being a key driver of crude oil prices. Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non- OPEC+ supply growth, the refilling of SPRs, and the crisis in Israel and Gaza. In addition, weakening global economic activity, inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth. in Alberta has been strong and condensate 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 the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. Refined product prices declined in 2023 compared with 2022. Market crack spreads also declined during this period as 2022 saw periods of historically high refined product prices and refining margins due to pandemic refinery rationalization, Russian export volatility and critically low global inventories of refined products. Reduced refinery outages and incremental global capacity additions resulted in declining refined product prices relative to WTI in 2023, compared with 2022, but crack spreads remained above historical norms. Diesel margins declined year-over-year but were high on average amid strong demand, tight global supply and demand balances, and continued low inventories. Gasoline margins were strong on average in 2023 but weakened in the fourth quarter as seasonally lower demand and high refinery utilization resulted in excess supply and high inventory builds. Gasoline and diesel margins, and crack spreads, decreased significantly in December. The Chicago refined product market saw periods of weakness in 2023 relative to Group 3 and the USGC as regional refining utilization was high and waterway maintenance prevented products from being barged to other market demand centers. due to growing renewable diesel supply. 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 refining margins are affected by many other factors such as the quality and purchase location of crude oil feedstock, refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the feedstock 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. (1) There are no forward prices for RINs. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 13 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 14 CENOVUS ENERGY 2023 ANNUAL REPORT | 19 In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following: Cost Leadership • We expect the WTI-WCS at Hardisty 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 the start-up of the Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials. • We expect refined product prices and market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America. NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample natural gas in storage. Weather will continue to be a key driver of demand and impact prices. • • We expect the Canadian dollar to continue to be impacted by 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, crude oil prices and emerging macro-economic factors. Most of our upstream crude oil and downstream refined product production are exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane and used as crude oil feedstock by our downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations. The restart of the Superior and Toledo refineries provide further physical integration. Both refineries process blended crude oil from our Oil Sands assets and HSB from the Upgrader. 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. Traditional crude oil storage tanks in various geographic locations. Key Priorities for 2024 Our 2024 priorities are focused on safety, maximizing shareholder value through downstream profitability, advancing major projects and other asset opportunities and cost leadership, and continuing to advocate for our company and industry. Top-Tier Safety Performance Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best in class operators for each of our major assets and businesses. We aim to maximize shareholder value through continued focus on cost structures and margin optimization. We are focused on reducing operating, capital and general and administrative costs realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus. We will continue to target improved reliability of our downstream assets leveraging our upstream expertise to maximize the long-term profitability of our assets. Sustainability 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. We have allocated resources to invest in our five ESG focus areas, including emissions reduction initiatives. We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale decarbonization projects. It is critical that the federal and provincial governments provide support at a level consistent with what other large-scale decarbonization projects are receiving globally. This will enable the Canadian oil and gas sector to achieve its GHG emissions reduction goals and remain competitive with other oil and gas producing jurisdictions. Additional information on Cenovus’s efforts and targets are available in Cenovus’s 2022 ESG report on our website at cenovus.com. 2024 Corporate Guidance Our 2024 capital investment budget is between $4.5 billion and $5.0 billion. This includes $3.0 billion directed towards sustaining production and supporting continued safe and reliable operations, and between $1.5 billion and $2.0 billion in optimization and growth capital. Optimization and growth capital is mainly related to: Progressing the West White Rose project. Opportunities in the Conventional segment. The following table shows guidance for 2024: • • • • Incrementally growing production at the Foster Creek, Christina Lake and Sunrise facilities. Initiatives in our downstream business to improve reliability and increase margin capture. Upstream Oil Sands Conventional Offshore Downstream Corporate and Eliminations Capital Investment ($ millions) Production (MBOE/d) Crude Oil Unit Throughput (Mbbls/d) 2,500 - 2,750 350 - 425 850 - 950 750 - 850 60 - 70 590 - 610 120 - 130 60 - 70 630 - 670 Returns to Shareholders Target Our 2024 guidance dated December 13, 2023, is available on our website at cenovus.com. 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. Our ultimate Net Debt Target is $4 billion, which serves as our floor on Net Debt, and we strive to continue to make progress towards this target. 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. Project Execution Investing in future growth is a focus for us, with several key projects in flight, including the West White Rose project, the SeaRose FPSO asset life extension project (“SeaRose ALE project”), the Narrows Lake tie-back to Christina Lake and the Foster Creek optimization project. In addition, we have a number of information system upgrades underway in 2024. We plan to execute these multi-year projects on time and budget. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 15 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 16 20 | CENOVUS ENERGY 2023 ANNUAL REPORT In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following: Cost Leadership • We expect the WTI-WCS at Hardisty 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 the start-up of the Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials. • We expect refined product prices and market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and central bank policies could impact demand. Refined product prices and market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America. • NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and ample natural gas in storage. Weather will continue to be a key driver of demand and impact prices. • We expect the Canadian dollar to continue to be impacted by 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, crude oil prices and emerging macro-economic factors. Most of our upstream crude oil and downstream refined product production are exposed to movements in the WTI crude oil price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude oil production in our upstream assets is blended with condensate and butane and used as crude oil feedstock by our downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations. The restart of the Superior and Toledo refineries provide further physical integration. Both refineries process blended crude oil from our Oil Sands assets and HSB from the Upgrader. 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. Traditional crude oil storage tanks in various geographic locations. • • • Our 2024 priorities are focused on safety, maximizing shareholder value through downstream profitability, advancing major projects and other asset opportunities and cost leadership, and continuing to advocate for our company and industry. Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio, and aim to be best in class operators for each of our major assets and businesses. 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. Our ultimate Net Debt Target is $4 billion, which serves as our floor on Net Debt, and we strive to continue to make progress towards this target. 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 Key Priorities for 2024 Top-Tier Safety Performance Returns to Shareholders Target shareholder returns. Project Execution Investing in future growth is a focus for us, with several key projects in flight, including the West White Rose project, the SeaRose FPSO asset life extension project (“SeaRose ALE project”), the Narrows Lake tie-back to Christina Lake and the Foster Creek optimization project. In addition, we have a number of information system upgrades underway in 2024. We plan to execute these multi-year projects on time and budget. We aim to maximize shareholder value through continued focus on cost structures and margin optimization. We are focused on reducing operating, capital and general and administrative costs realizing the full value of our integrated strategy while making decisions that support long-term value for Cenovus. We will continue to target improved reliability of our downstream assets leveraging our upstream expertise to maximize the long-term profitability of our assets. Sustainability 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. We have allocated resources to invest in our five ESG focus areas, including emissions reduction initiatives. We continue to support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal and provincial governments that provide a sufficient level of fiscal support to progress large-scale decarbonization projects. It is critical that the federal and provincial governments provide support at a level consistent with what other large-scale decarbonization projects are receiving globally. This will enable the Canadian oil and gas sector to achieve its GHG emissions reduction goals and remain competitive with other oil and gas producing jurisdictions. Additional information on Cenovus’s efforts and targets are available in Cenovus’s 2022 ESG report on our website at cenovus.com. 2024 Corporate Guidance Our 2024 capital investment budget is between $4.5 billion and $5.0 billion. This includes $3.0 billion directed towards sustaining production and supporting continued safe and reliable operations, and between $1.5 billion and $2.0 billion in optimization and growth capital. Optimization and growth capital is mainly related to: • • • • Progressing the West White Rose project. Incrementally growing production at the Foster Creek, Christina Lake and Sunrise facilities. Initiatives in our downstream business to improve reliability and increase margin capture. Opportunities in the Conventional segment. The following table shows guidance for 2024: Upstream Oil Sands Conventional Offshore Downstream Corporate and Eliminations Capital Investment ($ millions) Production (MBOE/d) Crude Oil Unit Throughput (Mbbls/d) 2,500 - 2,750 350 - 425 850 - 950 750 - 850 60 - 70 590 - 610 120 - 130 60 - 70 630 - 670 Our 2024 guidance dated December 13, 2023, is available on our website at cenovus.com. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 15 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 16 CENOVUS ENERGY 2023 ANNUAL REPORT | 21 REPORTABLE SEGMENTS 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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. Downstream Segments • • Canadian Refining, 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. The Company renamed its Canadian Manufacturing segment to Canadian Refining in 2023. U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023. Corporate and Eliminations (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further 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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 17 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 18 22 | CENOVUS ENERGY 2023 ANNUAL REPORT • • • • • • • • Delivered safe operations. Produced 593.4 thousand barrels of crude oil per day (2022 – 586.6 thousand barrels of crude oil per day). Started production on three new well pads at both Foster Creek and Christina Lake. Completed a planned turnaround at Foster Creek in the second quarter. Completed a planned turnaround at Christina Lake in the third quarter with minimal production impacts. Generated Operating Margin of $8.2 billion, a decrease of $810 million compared with 2022 primarily due to lower average realized sales prices. Invested capital of $2.4 billion primarily for sustaining activities including the drilling of stratigraphic test wells as part of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Averaged a Netback of $38.10 per BOE (2022 – $49.10 per BOE). 2023 2022 26,192 3,059 23,133 1,457 10,774 2,716 8,169 2,993 17 15 19 6 5,136 34,683 4,493 30,190 4,718 12,036 2,930 1,527 8,979 (68) 2,763 9 8 6,267 UPSTREAM Oil Sands In 2023, we: Financial Results ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) 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. Operating Margin Variance Year Ended December 31, 2023 (1) Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses. (2) Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas. REPORTABLE SEGMENTS 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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. Downstream Segments • Canadian Refining, 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. The Company renamed its Canadian Manufacturing segment to Canadian Refining in 2023. • U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023. 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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices. UPSTREAM Oil Sands In 2023, we: • • • • • • • • Delivered safe operations. Produced 593.4 thousand barrels of crude oil per day (2022 – 586.6 thousand barrels of crude oil per day). Started production on three new well pads at both Foster Creek and Christina Lake. Completed a planned turnaround at Foster Creek in the second quarter. Completed a planned turnaround at Christina Lake in the third quarter with minimal production impacts. Generated Operating Margin of $8.2 billion, a decrease of $810 million compared with 2022 primarily due to lower average realized sales prices. Invested capital of $2.4 billion primarily for sustaining activities including the drilling of stratigraphic test wells as part of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Averaged a Netback of $38.10 per BOE (2022 – $49.10 per BOE). Financial Results ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) 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) 2023 2022 26,192 3,059 23,133 1,457 10,774 2,716 17 8,169 15 2,993 19 6 5,136 34,683 4,493 30,190 4,718 12,036 2,930 1,527 8,979 (68) 2,763 9 8 6,267 (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Operating Margin Variance Year Ended December 31, 2023 ) s n o i l l i m $ ( 12,000 10,000 8,000 6,000 4,000 2,000 0 8,979 2,511 121 1,426 1,400 1,327 243 16 8,169 Twelve Months Ended December 31, 2022 Price (1) Sales Volumes Condensate Revenue (1) Royalties Transportation and Blending (1) Operating Expenses Other (2) Twelve Months Ended December 31, 2023 (1) (2) Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses. Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 17 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 18 CENOVUS ENERGY 2023 ANNUAL REPORT | 23 Operating Results Total Sales Volumes (1) (MBOE/d) Total Realized Price (2) ($/BOE) Crude Oil Production by Asset (Mbbls/d) Foster Creek Christina Lake Sunrise (3) Lloydminster Thermal Lloydminster Conventional Heavy Oil Total Crude Oil Production (4) (5) (Mbbls/d) Natural Gas (6) (MMcf/d) Total Production (MBOE/d) Effective Royalty Rate (7) (percent) Foster Creek Christina Lake Sunrise Lloydminster (8) Total Effective Royalty Rate Transportation and Blending Expense (2) ($/BOE) Operating Expense (2) ($/BOE) Per Unit DD&A (2) ($/BOE) 2023 589.5 73.02 186.3 237.4 48.9 104.1 16.7 593.4 11.9 595.4 25.1 29.5 6.8 9.5 21.9 8.18 12.54 12.94 2022 585.8 91.70 191.0 246.5 31.3 99.9 16.3 586.6 12.3 588.7 30.5 30.8 7.3 10.5 25.2 7.89 13.75 11.90 (1) (2) (3) (4) (5) (6) (7) (8) Bitumen, heavy crude oil and natural gas. Specified financial measure. See the Advisory. On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada. Bitumen production in 2022 included 1.6 thousand barrels per day from the Tucker asset that 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. Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses. Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets. Revenues Price Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized heavy oil and bitumen sales price decreases. Our realized sales price decreased to $73.02 per BOE in 2023 from $91.70 per BOE in 2022 mainly due to lower WTI benchmark prices. In 2023, WTI averaged US$77.62 per barrel (2022 – US$94.23 per barrel) and the WTI-WCS at Hardisty differential was US$18.65 per barrel (2022 – US$18.22 per barrel). In 2023, condensate benchmark pricing was at a US$17.64 per barrel premium to WCS at Hardisty, compared with US$17.77 per barrel premium in 2022. Gross sales included $1.2 billion (2022 – $4.4 billion) from third-party sourced volumes and $377 million (2022 – $358 million) relating to construction, transportation and blending activities. Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability. Production Volumes Oil Sands crude oil production was 593.4 thousand barrels per day in 2023 (2022 – 586.6 thousand barrels per day). In 2023, we sold approximately 25 percent (2022 – 20 percent) of our oil sands crude oil sales volumes to third parties at U.S. destinations and sold approximately 20 percent of our oil sands crude oil sales volumes to our Canadian and U.S. downstream operations. All remaining sales were at Canadian destinations. Production at Foster Creek decreased 4.7 thousand barrels per day to 186.3 thousand barrels per day in 2023 compared with 2022, primarily due to a planned turnaround that commenced in mid-April and completed in early May 2023, which had a greater impact than planned maintenance and an unplanned outage in 2022. The decrease was partially offset by three new well pads that started up in 2023. Production at Christina Lake decreased 9.1 thousand barrels per day to 237.4 thousand barrels per day in 2023 compared with 2022, primarily due to the timing of three new well pads that started up in 2023 combined with strong production in 2022 from development wells drilled in prior years. The decrease was partially offset by turnaround activity in 2022. We completed a planned turnaround in the third quarter of 2023 that had minimal production impacts. Production at Sunrise increased 17.6 thousand barrels per day to 48.9 thousand barrels per day in 2023, compared with 2022. The Sunrise Acquisition was completed on August 31, 2022. In addition, successful results from our 2023 redevelopment program completed in the third quarter increased production year-over-year. Production from our Lloydminster thermal assets increased 4.2 thousand barrels per day to 104.1 thousand barrels per day in 2023, compared with 2022. The increase was due to first oil at the Spruce Lake North thermal plant in August 2022, partially offset by wells taken offline for a redevelopment program and workover activity in 2023. 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. In 2023, royalties were $3.1 billion (2022 – $4.5 billion). The Oil Sands effective royalty rate decreased to 21.9 percent in 2023 from 25.2 percent in 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates. Expenses Transportation and Blending Sunrise Acquisition. Per-unit Transportation Expenses In 2023, blending costs decreased $1.4 billion to $8.9 billion compared with 2022 due to lower condensate prices, partially offset by higher volumes. Transportation costs rose $138 million to $1.8 billion in 2023 compared with 2022, mainly due to the Transportation costs increased to $8.18 per BOE in 2023 from $7.89 per BOE in 2022. At Foster Creek, per-unit transportation costs increased slightly to $11.98 per barrel in 2023 from $11.78 per barrel in 2022, primarily due to higher storage costs, partially offset by lower fixed rail costs. In 2023, we shipped 44 percent (2022 – 43 percent) of our volumes from Foster Creek to U.S. destinations. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 19 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 20 24 | CENOVUS ENERGY 2023 ANNUAL REPORT 2023 589.5 73.02 186.3 237.4 48.9 104.1 16.7 593.4 11.9 595.4 25.1 29.5 6.8 9.5 21.9 8.18 12.54 12.94 2022 585.8 91.70 191.0 246.5 31.3 99.9 16.3 586.6 12.3 588.7 30.5 30.8 7.3 10.5 25.2 7.89 13.75 11.90 Operating Results Total Sales Volumes (1) (MBOE/d) Total Realized Price (2) ($/BOE) Crude Oil Production by Asset (Mbbls/d) Foster Creek Christina Lake Sunrise (3) Lloydminster Thermal Lloydminster Conventional Heavy Oil Total Crude Oil Production (4) (5) (Mbbls/d) Natural Gas (6) (MMcf/d) Total Production (MBOE/d) Effective Royalty Rate (7) (percent) Foster Creek Christina Lake Sunrise Lloydminster (8) Total Effective Royalty Rate Transportation and Blending Expense (2) ($/BOE) Operating Expense (2) ($/BOE) Per Unit DD&A (2) ($/BOE) Bitumen, heavy crude oil and natural gas. Specified financial measure. See the Advisory. (1) (2) (3) (4) (5) (6) (7) (8) Revenues Price decreases. On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada. Bitumen production in 2022 included 1.6 thousand barrels per day from the Tucker asset that 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. Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses. Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets. Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity in order to transport it to market through pipelines. Within our netback calculations, our realized bitumen and heavy oil sales price excludes the impact of purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending increases relative to the price of blended crude oil or our blend ratio increases, our realized heavy oil and bitumen sales price Our realized sales price decreased to $73.02 per BOE in 2023 from $91.70 per BOE in 2022 mainly due to lower WTI benchmark prices. In 2023, WTI averaged US$77.62 per barrel (2022 – US$94.23 per barrel) and the WTI-WCS at Hardisty differential was US$18.65 per barrel (2022 – US$18.22 per barrel). In 2023, condensate benchmark pricing was at a US$17.64 per barrel premium to WCS at Hardisty, compared with US$17.77 per barrel premium in 2022. Gross sales included $1.2 billion (2022 – $4.4 billion) from third-party sourced volumes and $377 million (2022 – $358 million) relating to construction, transportation and blending activities. Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification. To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and improve cash flow stability. Production Volumes Oil Sands crude oil production was 593.4 thousand barrels per day in 2023 (2022 – 586.6 thousand barrels per day). In 2023, we sold approximately 25 percent (2022 – 20 percent) of our oil sands crude oil sales volumes to third parties at U.S. destinations and sold approximately 20 percent of our oil sands crude oil sales volumes to our Canadian and U.S. downstream operations. All remaining sales were at Canadian destinations. Production at Foster Creek decreased 4.7 thousand barrels per day to 186.3 thousand barrels per day in 2023 compared with 2022, primarily due to a planned turnaround that commenced in mid-April and completed in early May 2023, which had a greater impact than planned maintenance and an unplanned outage in 2022. The decrease was partially offset by three new well pads that started up in 2023. Production at Christina Lake decreased 9.1 thousand barrels per day to 237.4 thousand barrels per day in 2023 compared with 2022, primarily due to the timing of three new well pads that started up in 2023 combined with strong production in 2022 from development wells drilled in prior years. The decrease was partially offset by turnaround activity in 2022. We completed a planned turnaround in the third quarter of 2023 that had minimal production impacts. Production at Sunrise increased 17.6 thousand barrels per day to 48.9 thousand barrels per day in 2023, compared with 2022. The Sunrise Acquisition was completed on August 31, 2022. In addition, successful results from our 2023 redevelopment program completed in the third quarter increased production year-over-year. Production from our Lloydminster thermal assets increased 4.2 thousand barrels per day to 104.1 thousand barrels per day in 2023, compared with 2022. The increase was due to first oil at the Spruce Lake North thermal plant in August 2022, partially offset by wells taken offline for a redevelopment program and workover activity in 2023. 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. In 2023, royalties were $3.1 billion (2022 – $4.5 billion). The Oil Sands effective royalty rate decreased to 21.9 percent in 2023 from 25.2 percent in 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates. Expenses Transportation and Blending In 2023, blending costs decreased $1.4 billion to $8.9 billion compared with 2022 due to lower condensate prices, partially offset by higher volumes. Transportation costs rose $138 million to $1.8 billion in 2023 compared with 2022, mainly due to the Sunrise Acquisition. Per-unit Transportation Expenses Transportation costs increased to $8.18 per BOE in 2023 from $7.89 per BOE in 2022. At Foster Creek, per-unit transportation costs increased slightly to $11.98 per barrel in 2023 from $11.78 per barrel in 2022, primarily due to higher storage costs, partially offset by lower fixed rail costs. In 2023, we shipped 44 percent (2022 – 43 percent) of our volumes from Foster Creek to U.S. destinations. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 19 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 20 CENOVUS ENERGY 2023 ANNUAL REPORT | 25 At Christina Lake, transportation costs increased slightly to $6.69 per barrel in 2023 from $6.51 per barrel in 2022. Increased tariff rates and a higher percentage of our volumes shipped to U.S. destinations were partially offset by lower fixed rail costs. In 2023, we shipped 18 percent (2022 – 13 percent) of our volumes from Christina Lake to U.S. destinations. At Sunrise, transportation costs increased slightly to $12.47 per barrel in 2023 from $12.26 per barrel in 2022, mainly due to higher tariff rates. In 2023, we shipped 50 percent (2022 – 51 percent) of our volumes from Sunrise to U.S. destinations. At our other Oil Sands assets, transportation costs in 2023, were $3.51 per barrel (2022 – $3.49 per barrel). Operating Primary drivers of our operating expenses in 2023 were fuel, workforce, repairs and maintenance, and chemicals. Total operating expenses decreased $214 million to $2.7 billion in 2023 compared with 2022, mainly driven by lower fuel costs as a result of significant declines in AECO benchmark prices. The decreases were offset by higher repairs and maintenance costs in 2023, compared with 2022. We have experienced some inflationary pressures on our costs, however, we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations. Unit Operating Expenses (1) ($/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 Oil Sands Fuel Non-Fuel Total 2023 3.48 7.96 11.44 2.98 5.54 8.52 4.78 12.24 17.02 4.54 15.78 20.32 3.60 8.94 12.54 Percent Change (43) 22 (9) (41) 14 (14) (32) 17 (3) (38) 5 (9) (39) 15 (9) 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 5.95 7.80 13.75 (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. Per-unit non-fuel costs increased in 2023 compared with 2022 at all of our Oil Sands assets, primarily due to: • • • Lower sales volumes and planned turnarounds at Foster Creek and Christina Lake, partially offset by a planned turnaround, maintenance activity and an unplanned outage in 2022. Higher repairs and maintenance costs at Sunrise, partially offset by higher gross sales volumes in 2023. A rise in repairs and maintenance and workover activity in our other Oil Sands assets. (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 21 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 22 26 | CENOVUS ENERGY 2023 ANNUAL REPORT Year Ended December 31, 2023 73.02 14.20 8.18 12.54 38.10 2022 91.70 20.96 7.89 13.75 49.10 Netbacks (1) ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Netback 2022. Conventional In 2023, we: (1) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. Realized (Gain) Loss on Risk Management In 2023, our realized risk management losses were $17 million (2022 – $1.5 billion). The decrease from 2022 is due to management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of • • • • • • Delivered safe operations. Produced 119.9 thousand BOE per day (2022 – 127.2 thousand BOE per day). Responded to wildfires in northern Alberta. In early May, we temporarily shut-in approximately 85 thousand BOE per day of production in the operating areas of Rainbow Lake, Elmworth-Wapiti, Kaybob-Edson and Clearwater to ensure the safety of our staff, local communities and assets. The majority of our wells and facilities impacted by the fire were restarted by June. Additional wildfire activity impacted our Rainbow Lake property in September and into the fourth quarter, and had minor impacts on production. We returned to full operations in the fourth quarter. Generated Operating Margin of $583 million, a decrease from $1.2 billion in 2022 primarily due to lower average realized sales prices. Invested capital of $452 million with continued focus on drilling, completion, tie-in and infrastructure projects. Averaged a Netback of $12.02 per BOE (2022 – $27.43 per BOE). Financial Results ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product Transportation and Blending (1) Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) details. 2023 3,273 112 3,161 1,695 298 590 (5) 583 (19) 386 6 210 2022 4,439 298 4,141 2,023 1,235 250 541 92 13 370 1 851 At Christina Lake, transportation costs increased slightly to $6.69 per barrel in 2023 from $6.51 per barrel in 2022. Increased tariff rates and a higher percentage of our volumes shipped to U.S. destinations were partially offset by lower fixed rail costs. In 2023, we shipped 18 percent (2022 – 13 percent) of our volumes from Christina Lake to U.S. destinations. At Sunrise, transportation costs increased slightly to $12.47 per barrel in 2023 from $12.26 per barrel in 2022, mainly due to higher tariff rates. In 2023, we shipped 50 percent (2022 – 51 percent) of our volumes from Sunrise to U.S. destinations. At our other Oil Sands assets, transportation costs in 2023, were $3.51 per barrel (2022 – $3.49 per barrel). Operating Primary drivers of our operating expenses in 2023 were fuel, workforce, repairs and maintenance, and chemicals. Total operating expenses decreased $214 million to $2.7 billion in 2023 compared with 2022, mainly driven by lower fuel costs as a result of significant declines in AECO benchmark prices. The decreases were offset by higher repairs and maintenance costs in 2023, compared with 2022. We have experienced some inflationary pressures on our costs, however, we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations. Unit Operating Expenses (1) ($/BOE) Foster Creek Fuel Non-Fuel Total Fuel Non-Fuel Christina Lake Total Sunrise Fuel Non-Fuel Total Fuel Non-Fuel Total Fuel Non-Fuel Total Total Oil Sands Other Oil Sands (2) 2023 3.48 7.96 11.44 2.98 5.54 8.52 4.78 12.24 17.02 4.54 15.78 20.32 3.60 8.94 12.54 Percent Change (43) 22 (9) (41) 14 (14) (32) 17 (3) (38) 5 (9) (39) 15 (9) 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 5.95 7.80 13.75 Specified financial measure. See the Advisory. (1) (2) Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022. Per-unit non-fuel costs increased in 2023 compared with 2022 at all of our Oil Sands assets, primarily due to: • • • Lower sales volumes and planned turnarounds at Foster Creek and Christina Lake, partially offset by a planned turnaround, maintenance activity and an unplanned outage in 2022. Higher repairs and maintenance costs at Sunrise, partially offset by higher gross sales volumes in 2023. A rise in repairs and maintenance and workover activity in our other Oil Sands assets. Netbacks (1) ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Netback Year Ended December 31, 2023 73.02 14.20 8.18 12.54 38.10 2022 91.70 20.96 7.89 13.75 49.10 (1) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. Realized (Gain) Loss on Risk Management In 2023, our realized risk management losses were $17 million (2022 – $1.5 billion). The decrease from 2022 is due to management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of 2022. Conventional In 2023, we: • • • • • • Delivered safe operations. Produced 119.9 thousand BOE per day (2022 – 127.2 thousand BOE per day). Responded to wildfires in northern Alberta. In early May, we temporarily shut-in approximately 85 thousand BOE per day of production in the operating areas of Rainbow Lake, Elmworth-Wapiti, Kaybob-Edson and Clearwater to ensure the safety of our staff, local communities and assets. The majority of our wells and facilities impacted by the fire were restarted by June. Additional wildfire activity impacted our Rainbow Lake property in September and into the fourth quarter, and had minor impacts on production. We returned to full operations in the fourth quarter. Generated Operating Margin of $583 million, a decrease from $1.2 billion in 2022 primarily due to lower average realized sales prices. Invested capital of $452 million with continued focus on drilling, completion, tie-in and infrastructure projects. Averaged a Netback of $12.02 per BOE (2022 – $27.43 per BOE). Financial Results ($ millions) Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product Transportation and Blending (1) Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Exploration Expense Segment Income (Loss) 2023 3,273 112 3,161 1,695 298 590 (5) 583 (19) 386 6 210 2022 4,439 298 4,141 2,023 250 541 92 1,235 13 370 1 851 (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 21 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 22 CENOVUS ENERGY 2023 ANNUAL REPORT | 27 Operating Margin Variance Year Ended December 31, 2023 ) s n o i l l i m $ ( 1,400 1,200 1,000 800 600 400 200 0 1,235 620 131 185 35 50 1 583 Twelve Months Ended December 31, 2022 Price (1) Sales Volumes Royalties Transportation and Blending Operating Expenses Other (2) Twelve Months Ended December 31, 2023 (1) (2) Changes to price include the impact of realized risk management gains and losses. Reflects Operating Margin from processing facilities. Operating Results Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Light Crude Oil ($/bbl) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product 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 Expense (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) (1) Specified financial measure. See the Advisory. Revenues Price 2023 119.9 31.76 101.34 48.25 3.91 5.9 21.7 554.1 119.9 77 23 10.8 4.16 13.02 8.76 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 Our total realized sales price decreased in 2023, compared with 2022, primarily due to lower crude oil and natural gas benchmark prices. In 2023, gross sales included $1.7 billion (2022 – $2.0 billion) relating to third-party sourced volumes; and amounts relating to processing activities undertaken for third parties of $188 million (2022 – $178 million). Production Volumes Production volumes decreased 7.3 thousand BOE per day in 2023 to 119.9 thousand BOE per day in 2023 compared with 2022. The year-over-year decrease was primarily due to the impact of the wildfires in the second quarter of 2023, partially offset by successful results from our 2023 development program. Royalties The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased to $112 million in 2023 from $298 million in 2022 and effective royalty rates declined, primarily due to sharp declines in natural gas pricing. Expenses Transportation Operating Netbacks (1) ($/BOE) Sales Price Royalties Offshore In 2023, we: Transportation and Blending Operating Expenses Netback 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 $48 million to $298 million in 2023 compared with 2022, and per-unit transportation costs increased to $4.16 per BOE in 2023 from $3.16 per BOE in 2022. The increases were mainly due to higher tariff rates and additional storage costs, combined with lower sales volumes. Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce, property taxes and lease costs, and electricity. Total operating expenses increased $49 million to $590 million in 2023 compared with 2022, due to the higher repairs and maintenance costs. The wildfires had minimal impact on total operating expenses. Operating expenses per BOE increased $1.84 per BOE to $13.02 per BOE in 2023 compared with 2022, due to the same factors impacting total operating costs and lower sales volumes as a result of wildfire activity. 2023 31.76 2.56 4.16 13.02 12.02 2022 48.15 6.38 3.16 11.18 27.43 (1) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. Delivered safe operations. thousand barrels per day. • • • • • • • region. Resumed production at the Terra Nova FPSO in late November. Our share of production in December was 4.1 Achieved first gas production from the MAC field in Indonesia in September. Produced 63.4 thousand BOE per day of light crude oil, NGLs and natural gas (2022 – 70.3 thousand BOE per day). Generated Operating Margin of $1.1 billion, a decrease of $492 million compared with 2022, mainly due to lower sales volumes from our Atlantic and China operations, and decreased realized light crude oil sales prices. Earned a Netback of $56.48 per BOE (2022 – $68.90 per BOE). Invested capital of $642 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic The West White Rose project was approximately 75 percent complete as at December 31, 2023. Since our decision in 2022 to restart the project, we have invested approximately $578 million. We reached a major milestone on the project in the second quarter with the completion of the conical slip form operation for the concrete gravity structure. First oil is expected in 2026. In late December 2023, we suspended production at the White Rose field as we prepared for the planned SeaRose ALE project. The SeaRose FPSO departed the field for its scheduled dry docking in late January 2024. We expect to resume production at the White Rose field late in the third quarter of 2024. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 23 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 24 28 | CENOVUS ENERGY 2023 ANNUAL REPORT Operating Margin Variance Year Ended December 31, 2023 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 $48 million to $298 million in 2023 compared with 2022, and per-unit transportation costs increased to $4.16 per BOE in 2023 from $3.16 per BOE in 2022. The increases were mainly due to higher tariff rates and additional storage costs, combined with lower sales volumes. Operating Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce, property taxes and lease costs, and electricity. Total operating expenses increased $49 million to $590 million in 2023 compared with 2022, due to the higher repairs and maintenance costs. The wildfires had minimal impact on total operating expenses. Operating expenses per BOE increased $1.84 per BOE to $13.02 per BOE in 2023 compared with 2022, due to the same factors impacting total operating costs and lower sales volumes as a result of wildfire activity. Netbacks (1) ($/BOE) Sales Price Royalties Transportation and Blending Operating Expenses Netback 2023 31.76 2.56 4.16 13.02 12.02 2022 48.15 6.38 3.16 11.18 27.43 (1) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. Offshore In 2023, we: • • • • • • • Delivered safe operations. Resumed production at the Terra Nova FPSO in late November. Our share of production in December was 4.1 thousand barrels per day. Achieved first gas production from the MAC field in Indonesia in September. Produced 63.4 thousand BOE per day of light crude oil, NGLs and natural gas (2022 – 70.3 thousand BOE per day). Generated Operating Margin of $1.1 billion, a decrease of $492 million compared with 2022, mainly due to lower sales volumes from our Atlantic and China operations, and decreased realized light crude oil sales prices. Earned a Netback of $56.48 per BOE (2022 – $68.90 per BOE). Invested capital of $642 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic region. The West White Rose project was approximately 75 percent complete as at December 31, 2023. Since our decision in 2022 to restart the project, we have invested approximately $578 million. We reached a major milestone on the project in the second quarter with the completion of the conical slip form operation for the concrete gravity structure. First oil is expected in 2026. In late December 2023, we suspended production at the White Rose field as we prepared for the planned SeaRose ALE project. The SeaRose FPSO departed the field for its scheduled dry docking in late January 2024. We expect to resume production at the White Rose field late in the third quarter of 2024. (1) (2) Changes to price include the impact of realized risk management gains and losses. Reflects Operating Margin from processing facilities. Operating Results Total Sales Volumes (MBOE/d) Total Realized Price (1) ($/BOE) Light Crude Oil ($/bbl) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production (MBOE/d) Conventional Natural Gas Production (percentage of total) Crude Oil and NGLs Production (percentage of total) Effective Royalty Rate (percent) Transportation Expense (1) ($/BOE) Operating Expense (1) ($/BOE) Per Unit DD&A (1) ($/BOE) (1) Specified financial measure. See the Advisory. 2023 119.9 31.76 101.34 48.25 3.91 5.9 21.7 554.1 119.9 77 23 10.8 4.16 13.02 8.76 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 Revenues Price benchmark prices. Production Volumes Royalties Our total realized sales price decreased in 2023, compared with 2022, primarily due to lower crude oil and natural gas In 2023, gross sales included $1.7 billion (2022 – $2.0 billion) relating to third-party sourced volumes; and amounts relating to processing activities undertaken for third parties of $188 million (2022 – $178 million). Production volumes decreased 7.3 thousand BOE per day in 2023 to 119.9 thousand BOE per day in 2023 compared with 2022. The year-over-year decrease was primarily due to the impact of the wildfires in the second quarter of 2023, partially offset by successful results from our 2023 development program. The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased to $112 million in 2023 from $298 million in 2022 and effective royalty rates declined, primarily due to sharp declines in natural gas pricing. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 23 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 24 CENOVUS ENERGY 2023 ANNUAL REPORT | 29  Financial Results ($ 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) 2023 2022 Atlantic Asia Pacific Offshore Atlantic Asia Pacific Offshore 400 15 385 16 262 107 1,217 84 1,133 — 122 1,011 1,617 99 1,518 16 384 1,118 487 17 (57) 671 578 (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) Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Advisory. Operating Margin Variance Year Ended December 31, 2023 ) s n o i l l i m $ ( 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 1,610 89 314 22 1 76 10 1,118 Twelve Months Ended December 31, 2022 Price Sales Volumes Royalties Transportation and Blending Operating Expenses Other Twelve Months Ended December 31, 2023 Operating Expense (2) ($/BOE) Operating Results Sales Volumes Atlantic (Mbbls/d) Asia Pacific (MBOE/d) China Indonesia (1) Total Asia Pacific Total Sales Volumes (MBOE/d) Total Realized Price (2) ($/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) Total Asia Pacific (MBOE/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Atlantic Asia Pacific (1) Atlantic Asia Pacific (1) Per Unit DD&A (2) ($/BOE) Revenues Price Production Volumes 2023 9.6 40.5 14.7 55.2 64.8 81.63 113.74 76.04 99.73 11.71 8.2 10.8 266.6 55.2 63.4 3.7 10.3 17.20 67.93 8.37 25.57 2022 11.3 48.2 10.5 58.7 70.0 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 (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. 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 decreased in 2023 compared with 2022, primarily due to lower Brent benchmark pricing. Atlantic production decreased 3.4 thousand barrels per day to 8.2 thousand barrels per day in 2023 compared with 2022. The decrease was due to turnaround work on the SeaRose FPSO completed in March and April of 2023 having a larger impact than annual planned maintenance completed in the third quarter in 2022. In addition, the decrease in Cenovus’s working interest at the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil production from 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. Asia Pacific production decreased 3.5 thousand barrels per day to 55.2 thousand barrels per day in 2023 compared with 2022. The decrease was mainly due to a temporary unplanned outage in the second quarter in China, related to the disconnection of the umbilical by a third-party vessel in early April and reconnected in May. Changes to gas sales agreements at Liwan 3-1 and Liuhua 29-1 in the second quarter of 2022 also resulted 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, first gas production at the MAC field in Indonesia in September 2023, and planned maintenance in China in the second and third quarters of 2022 having a larger impact than planned maintenance in June 2023. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 25 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 26 30 | CENOVUS ENERGY 2023 ANNUAL REPORT  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, 2023 (1) Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Advisory. 2023 2022 Atlantic Asia Pacific Offshore Atlantic Asia Pacific Offshore 400 15 385 16 262 107 1,217 84 1,133 — 122 1,011 578 (3) 581 15 204 362 1,442 80 1,362 — 114 1,248 1,617 99 1,518 16 384 1,118 487 17 (57) 671 2,020 77 1,943 15 318 1,610 585 91 (23) 957 Operating Results Sales Volumes Atlantic (Mbbls/d) Asia Pacific (MBOE/d) China Indonesia (1) Total Asia Pacific Total Sales Volumes (MBOE/d) Total Realized Price (2) ($/BOE) Atlantic - Light Crude Oil ($/bbl) Asia Pacific (1) ($/BOE) NGLs ($/bbl) Conventional Natural Gas ($/Mcf) Production by Product Atlantic - Light Crude Oil (Mbbls/d) Asia Pacific (1) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Asia Pacific (MBOE/d) Total Production (MBOE/d) Effective Royalty Rate (percent) Atlantic Asia Pacific (1) Operating Expense (2) ($/BOE) Atlantic Asia Pacific (1) Per Unit DD&A (2) ($/BOE) 2023 9.6 40.5 14.7 55.2 64.8 81.63 113.74 76.04 99.73 11.71 8.2 10.8 266.6 55.2 63.4 3.7 10.3 17.20 67.93 8.37 25.57 2022 11.3 48.2 10.5 58.7 70.0 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 (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 decreased in 2023 compared with 2022, primarily due to lower Brent benchmark pricing. Production Volumes Atlantic production decreased 3.4 thousand barrels per day to 8.2 thousand barrels per day in 2023 compared with 2022. The decrease was due to turnaround work on the SeaRose FPSO completed in March and April of 2023 having a larger impact than annual planned maintenance completed in the third quarter in 2022. In addition, the decrease in Cenovus’s working interest at the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil production from 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. Asia Pacific production decreased 3.5 thousand barrels per day to 55.2 thousand barrels per day in 2023 compared with 2022. The decrease was mainly due to a temporary unplanned outage in the second quarter in China, related to the disconnection of the umbilical by a third-party vessel in early April and reconnected in May. Changes to gas sales agreements at Liwan 3-1 and Liuhua 29-1 in the second quarter of 2022 also resulted 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, first gas production at the MAC field in Indonesia in September 2023, and planned maintenance in China in the second and third quarters of 2022 having a larger impact than planned maintenance in June 2023. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 25 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 26 CENOVUS ENERGY 2023 ANNUAL REPORT | 31 Royalties For the year ended December 31, 2023, Atlantic royalties were $15 million (2022 – recoveries of $3 million). Royalties increased in 2023, as 2022 royalties at the White Rose field included adjustments based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador. 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 the year ended December 31, 2023, declined to 10.3 percent (2022 – 11.5 percent), as a result of the MBH, MDA and MAC fields coming online in 2022 and 2023, having lower rates on initial start-up. The decrease was partially offset by a consumption tax implemented in China in June 2023 impacting royalties on NGLs. Expenses Operating Primary drivers of our Atlantic operating expenses in 2023 were repairs and maintenance, vessel and helicopter costs, and workforce. Operating expenses increased $58 million to $262 million in 2023 compared with 2022. The increase was due to costs associated with preparation and maintenance activities for the Terra Nova FPSO restart, and preparation costs for the SeaRose ALE project. We incurred costs in 2023 and 2022 on the ramp-up of the West White Rose project leading up to the start of major construction in late March 2023. Per-unit operating expenses increased in 2023 compared with 2022 due to lower sales volumes combined with the same factors that impacted total operating expenses. Primary drivers of our China operating expenses in 2023 were repairs and maintenance, insurance and workforce. Total operating expenses in China increased $8 million to $122 million in 2023, compared with 2022, due to costs related to the umbilical repair. Per-unit operating expenses associated with our assets in China increased compared with 2022 mainly due to lower sales volumes and the same factors that impacted total operating expenses. Per-unit operating expenses associated with our Indonesian assets decreased compared with 2022 mainly due to higher sales volumes. Transportation Transportation costs in the Atlantic region were $16 million in 2023 (2022 – $15 million), and includes the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs. Netbacks (1) ($/BOE, except where indicated) Atlantic ($/bbl) China Indonesia (2) Total Offshore 2023 Sales Price Royalties Transportation and Blending Operating Expenses Netback 113.74 4.24 4.44 67.93 37.13 82.14 5.68 — 7.51 68.95 2022 59.16 13.75 — 10.76 34.65 81.63 7.29 0.66 17.20 56.48 ($/BOE, except where indicated) Atlantic ($/bbl) China Indonesia (2) Total Offshore Sales Price Royalties Transportation and Blending Operating Expenses Netback 140.65 (0.74) 3.79 42.03 95.57 81.99 4.57 — 5.62 71.80 70.66 30.19 — 13.32 27.15 89.72 7.57 0.61 12.64 68.90 (1) (2) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. 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. Exploration Expense We recorded exploration expense of $17 million in 2023 (2022 – $91 million). Exploration expense in 2022 was primarily due to a $58 million write-off related to our decision not to pursue development at Block 15/33 in China. DOWNSTREAM Canadian Refining In 2023, we: Financial Results ($ millions) Revenues Purchased Product Gross Margin (1) Expenses Operating Operating Margin Depreciation, Depletion and Amortization Segment Income (Loss) (1) Non-GAAP financial measure. See the Advisory. Select Operating Results Total Canadian Refining Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Total Production (2) (Mbbls/d) Synthetic Crude Oil Asphalt Diesel Other Ethanol Refining Margin (3) ($/bbl) Unit Operating Expense (4) ($/bbl) Based on crude oil name plate capacity. (1) (2) (3) – $1.1 billion). (4) Specified financial measure. See the Advisory. • • • Delivered safe and reliable operations. Increased throughput to 100.7 thousand barrels per day (2022 – 92.9 thousand barrels per day), and achieved crude utilization of 90 percent and 95 percent at the Upgrader and Lloydminster Refinery, respectively (2022 – 84 percent and 83 percent, respectively). Generated Operating Margin of $675 million, a decrease of $24 million compared with 2022. 2023 6,233 4,919 1,314 639 675 185 490 2023 110.5 100.7 91 114.2 47.6 15.4 12.9 33.3 5.0 32.04 12.68 2022 7,792 6,389 1,403 704 699 208 491 2022 110.5 92.9 84 105.2 46.0 13.5 9.3 31.5 4.9 33.92 13.91 Includes volumes from the Upgrader, Lloydminster Refinery and the ethanol plants. Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023, was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 27 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 28 32 | CENOVUS ENERGY 2023 ANNUAL REPORT For the year ended December 31, 2023, Atlantic royalties were $15 million (2022 – recoveries of $3 million). Royalties increased in 2023, as 2022 royalties at the White Rose field included adjustments based on an amended agreement between our working interest partners and the Government of Newfoundland and Labrador. 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 the year ended December 31, 2023, declined to 10.3 percent (2022 – 11.5 percent), as a result of the MBH, MDA and MAC fields coming online in 2022 and 2023, having lower rates on initial start-up. The decrease was partially offset by a consumption tax implemented in China in June 2023 impacting DOWNSTREAM Canadian Refining In 2023, we: • • • Delivered safe and reliable operations. Increased throughput to 100.7 thousand barrels per day (2022 – 92.9 thousand barrels per day), and achieved crude utilization of 90 percent and 95 percent at the Upgrader and Lloydminster Refinery, respectively (2022 – 84 percent and 83 percent, respectively). Generated Operating Margin of $675 million, a decrease of $24 million compared with 2022. Financial Results ($ millions) Revenues Purchased Product Gross Margin (1) Expenses Operating Operating Margin Depreciation, Depletion and Amortization Segment Income (Loss) (1) Non-GAAP financial measure. See the Advisory. Select Operating Results Total Canadian Refining Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Total Production (2) (Mbbls/d) Synthetic Crude Oil Asphalt Diesel Other Ethanol Refining Margin (3) ($/bbl) Unit Operating Expense (4) ($/bbl) 2023 6,233 4,919 1,314 639 675 185 490 2023 110.5 100.7 91 114.2 47.6 15.4 12.9 33.3 5.0 32.04 12.68 2022 7,792 6,389 1,403 704 699 208 491 2022 110.5 92.9 84 105.2 46.0 13.5 9.3 31.5 4.9 33.92 13.91 ($/BOE, except where indicated) Atlantic ($/bbl) China Indonesia (2) Total Offshore (1) (2) (3) (4) Based on crude oil name plate capacity. Includes volumes from the Upgrader, Lloydminster Refinery and the ethanol plants. Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023, was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022 – $1.1 billion). Specified financial measure. See the Advisory. Royalties royalties on NGLs. Expenses Operating Transportation Netbacks (1) Sales Price Royalties Transportation and Blending Operating Expenses Netback Sales Price Royalties Transportation and Blending Operating Expenses Netback Exploration Expense Primary drivers of our Atlantic operating expenses in 2023 were repairs and maintenance, vessel and helicopter costs, and workforce. Operating expenses increased $58 million to $262 million in 2023 compared with 2022. The increase was due to costs associated with preparation and maintenance activities for the Terra Nova FPSO restart, and preparation costs for the SeaRose ALE project. We incurred costs in 2023 and 2022 on the ramp-up of the West White Rose project leading up to the start of major construction in late March 2023. Per-unit operating expenses increased in 2023 compared with 2022 due to lower sales volumes combined with the same factors that impacted total operating expenses. Primary drivers of our China operating expenses in 2023 were repairs and maintenance, insurance and workforce. Total operating expenses in China increased $8 million to $122 million in 2023, compared with 2022, due to costs related to the umbilical repair. Per-unit operating expenses associated with our assets in China increased compared with 2022 mainly due to lower sales volumes and the same factors that impacted total operating expenses. Per-unit operating expenses associated with our Indonesian assets decreased compared with 2022 mainly due to higher sales volumes. Transportation costs in the Atlantic region were $16 million in 2023 (2022 – $15 million), and includes the cost of transporting crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs. ($/BOE, except where indicated) Atlantic ($/bbl) China Indonesia (2) Total Offshore 2023 2022 82.14 5.68 — 7.51 68.95 81.99 4.57 — 5.62 71.80 59.16 13.75 — 10.76 34.65 70.66 30.19 — 13.32 27.15 113.74 4.24 4.44 67.93 37.13 140.65 (0.74) 3.79 42.03 95.57 81.63 7.29 0.66 17.20 56.48 89.72 7.57 0.61 12.64 68.90 (1) (2) The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory. 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. We recorded exploration expense of $17 million in 2023 (2022 – $91 million). Exploration expense in 2022 was primarily due to a $58 million write-off related to our decision not to pursue development at Block 15/33 in China. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 27 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 28 CENOVUS ENERGY 2023 ANNUAL REPORT | 33 Lloydminster Upgrader Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Upgrading Differential (4) ($/bbl) Lloydminster Refinery Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) 2023 81.5 73.1 90 81.5 34.48 12.32 31.14 29.0 27.6 95 27.7 25.58 13.62 2022 81.5 68.7 84 76.0 36.04 12.65 32.84 29.0 24.2 83 24.3 27.91 17.49 (1) (2) (3) (4) Based on crude oil name plate capacity. Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023, was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022 – $1.1 billion). Specified financial measure. See the Advisory. Based on benchmark price differential between heavy oil feedstock and synthetic crude. In 2023, Canadian Refining throughput increased 7.8 thousand barrels per day from 2022 to 100.7 thousand barrels per day, and total production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day due to: • • Increased throughput at the Upgrader, which rose 4.4 thousand barrels per day to 73.1 thousand barrels per day, primarily due to a planned turnaround and unplanned operational outages in 2022. The increase was partially offset by temporary unplanned outages in the second and fourth quarters of 2023. Throughput was also impacted by cold weather in the fourth quarter of 2022 until the middle of January 2023. Increased throughput at the Lloydminster Refinery, primarily due to the refinery’s high utilization in 2023, combined with a planned turnaround in the second quarter of 2022 and an unplanned outage in the third quarter of 2022. Throughput rose 3.4 thousand barrels per day to 27.6 thousand barrels per day compared with 2022. Revenues and Gross Margin The Upgrader processes blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur diesel. 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. Gross margin is largely dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year. The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2023, approximately 13 percent of total crude oil sales volumes from our Lloydminster thermal and Lloydminster conventional heavy oil assets were sold to our Canadian Refining segment. In 2023, revenues decreased by $1.6 billion to $6.2 billion due to lower synthetic crude and refined product pricing, combined with the disposition of our retail fuels network in the third quarter of 2022. The decrease was partially offset by higher production volumes from the Upgrader and Lloydminster Refinery. Synthetic crude oil benchmark prices decreased 19 percent to US$79.61 per barrel compared with 2022. Gross margin decreased $89 million to $1.3 billion in 2023 compared with 2022, primarily driven by the disposition of our retail fuels network in the third quarter of 2022 and the factors discussed above. We increased diesel production relative to synthetic crude in 2023 as we continually optimize production to capture higher margins. See the Advisory for revenues and gross margin by asset. Operating Expenses Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce and energy costs. Total operating costs decreased $65 million to $639 million in 2023 compared with 2022, mainly due to the disposition of our retail fuels network in the third quarter of 2022, lower energy costs and planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter of 2022. The decrease was partially offset by higher repairs and maintenance spend at the Upgrader in 2023. Per-unit operating costs decreased $1.23 per barrel to $12.68 per barrel in 2023, primarily due to higher throughput and lower energy costs. Per-unit operating expenses only include operating costs and throughput at the Upgrader and Lloydminster Refinery. U.S. Refining oil production and refining capabilities. In addition, we: In 2023, we increased our crude throughput capacity by 129.0 thousand barrels per day through the acquisition of the remaining 50 percent of the Toledo Refinery and the restart of the Superior Refinery, providing further integration of our heavy • • • • • • • • Delivered safe operations and averaged crude utilization of 75 percent (2022 – 80 percent). Generated operating margin of $477 million, $1.3 billion lower than 2022 driven by lower market crack spreads and refined product pricing. Refining benchmarks weakened significantly in the fourth quarter of 2023. Closed the Toledo Acquisition on February 28, 2023. The acquisition provided us with full ownership and operatorship of the Toledo Refinery and gave us an additional 80.0 thousand barrels per day of throughput capacity. Safely restarted, and subsequently returned, the Toledo Refinery to full operations in June. The refinery had a strong second half of the year, demonstrated by crude utilization of 88 percent during that period. Total crude utilization in 2023 was 57 percent (2022 – 45 percent). Introduced crude oil at the Superior Refinery in mid-March and restarted the FCCU in early October. Crude utilization for the last two months of 2023, following the restart of the FCCU, was 66 percent. Safely completed planned turnarounds at the Wood River Refinery in the spring and at the Borger Refinery in the spring and fall. Achieved utilization of 85 percent (2022 – 90 percent) at the Lima Refinery, which was impacted by planned maintenance and unplanned outages in the fourth quarter. Invested capital of $602 million, primarily focused on the Superior Refinery rebuild, refining reliability projects and growth spend at the Wood River and Borger refineries, and sustaining activities at the Lima and Toledo refineries. Financial Results ($ millions) Revenues (1) Purchased Product (1) Gross Margin (2) Expenses Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Segment Income (Loss) details. (2) Non-GAAP financial measure. See the Advisory. 2023 26,393 23,354 3,039 2,562 — 477 (17) 486 8 2022 30,218 26,020 4,198 2,346 112 1,740 18 640 1,082 (1) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 29 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 30 34 | CENOVUS ENERGY 2023 ANNUAL REPORT Lloydminster Upgrader Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Upgrading Differential (4) ($/bbl) Lloydminster Refinery Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Based on crude oil name plate capacity. 2023 81.5 73.1 90 81.5 34.48 12.32 31.14 29.0 27.6 95 27.7 25.58 13.62 2022 81.5 68.7 84 76.0 36.04 12.65 32.84 29.0 24.2 83 24.3 27.91 17.49 (1) (2) (3) (4) Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023, was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022 – $1.1 billion). Specified financial measure. See the Advisory. Based on benchmark price differential between heavy oil feedstock and synthetic crude. In 2023, Canadian Refining throughput increased 7.8 thousand barrels per day from 2022 to 100.7 thousand barrels per day, and total production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day due to: • Increased throughput at the Upgrader, which rose 4.4 thousand barrels per day to 73.1 thousand barrels per day, primarily due to a planned turnaround and unplanned operational outages in 2022. The increase was partially offset by temporary unplanned outages in the second and fourth quarters of 2023. Throughput was also impacted by cold weather in the fourth quarter of 2022 until the middle of January 2023. • Increased throughput at the Lloydminster Refinery, primarily due to the refinery’s high utilization in 2023, combined with a planned turnaround in the second quarter of 2022 and an unplanned outage in the third quarter of 2022. Throughput rose 3.4 thousand barrels per day to 27.6 thousand barrels per day compared with 2022. Revenues and Gross Margin The Upgrader processes blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur diesel. 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. Gross margin is largely dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery are seasonal and increase during paving season, which typically runs from May through October each year. The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2023, approximately 13 percent of total crude oil sales volumes from our Lloydminster thermal and Lloydminster conventional heavy oil assets were sold to our Canadian Refining segment. In 2023, revenues decreased by $1.6 billion to $6.2 billion due to lower synthetic crude and refined product pricing, combined with the disposition of our retail fuels network in the third quarter of 2022. The decrease was partially offset by higher production volumes from the Upgrader and Lloydminster Refinery. Synthetic crude oil benchmark prices decreased 19 percent to US$79.61 per barrel compared with 2022. Gross margin decreased $89 million to $1.3 billion in 2023 compared with 2022, primarily driven by the disposition of our retail fuels network in the third quarter of 2022 and the factors discussed above. We increased diesel production relative to synthetic crude in 2023 as we continually optimize production to capture higher margins. See the Advisory for revenues and gross margin by asset. Operating Expenses Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce and energy costs. Total operating costs decreased $65 million to $639 million in 2023 compared with 2022, mainly due to the disposition of our retail fuels network in the third quarter of 2022, lower energy costs and planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter of 2022. The decrease was partially offset by higher repairs and maintenance spend at the Upgrader in 2023. Per-unit operating costs decreased $1.23 per barrel to $12.68 per barrel in 2023, primarily due to higher throughput and lower energy costs. Per-unit operating expenses only include operating costs and throughput at the Upgrader and Lloydminster Refinery. U.S. Refining In 2023, we increased our crude throughput capacity by 129.0 thousand barrels per day through the acquisition of the remaining 50 percent of the Toledo Refinery and the restart of the Superior Refinery, providing further integration of our heavy oil production and refining capabilities. In addition, we: • • • • • • • • Delivered safe operations and averaged crude utilization of 75 percent (2022 – 80 percent). Generated operating margin of $477 million, $1.3 billion lower than 2022 driven by lower market crack spreads and refined product pricing. Refining benchmarks weakened significantly in the fourth quarter of 2023. Closed the Toledo Acquisition on February 28, 2023. The acquisition provided us with full ownership and operatorship of the Toledo Refinery and gave us an additional 80.0 thousand barrels per day of throughput capacity. Safely restarted, and subsequently returned, the Toledo Refinery to full operations in June. The refinery had a strong second half of the year, demonstrated by crude utilization of 88 percent during that period. Total crude utilization in 2023 was 57 percent (2022 – 45 percent). Introduced crude oil at the Superior Refinery in mid-March and restarted the FCCU in early October. Crude utilization for the last two months of 2023, following the restart of the FCCU, was 66 percent. Safely completed planned turnarounds at the Wood River Refinery in the spring and at the Borger Refinery in the spring and fall. Achieved utilization of 85 percent (2022 – 90 percent) at the Lima Refinery, which was impacted by planned maintenance and unplanned outages in the fourth quarter. Invested capital of $602 million, primarily focused on the Superior Refinery rebuild, refining reliability projects and growth spend at the Wood River and Borger refineries, and sustaining activities at the Lima and Toledo refineries. Financial Results ($ millions) Revenues (1) Purchased Product (1) Gross Margin (2) Expenses Operating Realized (Gain) Loss on Risk Management Operating Margin Unrealized (Gain) Loss on Risk Management Depreciation, Depletion and Amortization Segment Income (Loss) 2023 26,393 23,354 3,039 2,562 — 477 (17) 486 8 2022 30,218 26,020 4,198 2,346 112 1,740 18 640 1,082 (1) (2) Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Non-GAAP financial measure. See the Advisory. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 29 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 30 CENOVUS ENERGY 2023 ANNUAL REPORT | 35 Select Operating Results - Consolidated Revenues and Gross Margin Total U.S. Refining Crude Oil Unit Throughput Capacity (1) (2) (Mbbls/d) Crude Oil Unit Throughput (2) (Mbbls/d) Heavy Crude Oil Light and Medium Crude Oil Crude Utilization (2) (percent) Total Refined Product Production (Mbbls/d) Gasoline Distillates (3) Asphalt Other Refining Margin (4) ($/bbl) Unit Operating Expense (5) ($/bbl) 2023 635.2 459.7 173.9 285.8 75 485.0 231.2 167.0 19.8 67.0 18.12 15.27 2022 551.5 400.8 116.1 284.7 80 419.9 199.8 153.4 8.9 57.8 28.70 16.04 (1) (2) (3) (4) (5) Based on crude oil name plate capacity. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023. Includes diesel and jet fuel. Contains a non-GAAP financial measure. See the Advisory. Specified financial measure. See the Advisory. Select Operating Results - by Refinery 2023 2022 Lima Toledo Superior Wood River and Borger (1) Lima Toledo Superior Wood River and Borger (1) 178.7 160.0 152.7 83.1 85 57 49.0 22.6 61 247.5 175.0 201.3 157.9 81 90 80.0 36.3 45 49.0 247.5 — — 206.6 83 Crude Oil Unit Throughput Capacity (2) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) (1) (2) (3) Represents Cenovus’s 50 percent interest in the non-operated Wood River and Borger refinery operations. Based on crude oil name plate capacity. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023. U.S. Refining throughput increased 58.9 thousand barrels per day from 2022 to 459.7 thousand barrels per day, and total refined product production increased 65.1 thousand barrels per day to 485.0 thousand barrels per day, primarily related to the Toledo Acquisition and the restart of the Toledo and Superior refineries. Other factors that impacted throughput and production include: • • • • Less downtime at the Wood River Refinery, primarily due to the two planned turnarounds in 2022 having a larger impact than the planned turnaround in the spring of 2023, combined with the decision to reduce rates to optimize margins as market conditions dictated in the first quarter of 2022. Two planned turnarounds and unplanned outages at the Borger Refinery, which had a larger impact than unplanned outages and the turnaround completed in 2022. The refinery experienced an unplanned operational outage following the fall turnaround which resulted in a slower than expected restart. Combined throughput at the Wood River and Borger refineries decreased 5.3 thousand barrels per day to 201.3 thousand barrels per day in 2023. Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Late in the year, we flexed throughput at our U.S. refineries to optimize our margins. Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator. The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. 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, distillates and secondary product output, the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis. In 2023, the Chicago 3-2-1 crack spread decreased 29 percent to US$24.19 per barrel compared with 2022 and the Group 3 crack spread declined 11 percent to US$29.66 per barrel. Because of the relative strength of the Group 3 crack spread, our Borger and Superior refineries were not impacted as heavily by pricing declines as our other refineries. Average benchmark gasoline prices fell 19 percent to US$97.86 per barrel in 2023 compared with 2022. Average benchmark diesel prices also fell US$34.15 per barrel to US$109.70 per barrel in the year compared with 2022. Revenues decreased $3.8 billion in 2023 compared with 2022, primarily due to lower refined product pricing, partially offset by higher production. Gross margin decreased $1.2 billion in 2023 compared with 2022, primarily due to lower market crack spreads discussed above, impacts from processing feedstock purchased at higher prices in prior periods, partially offset by higher production and weaker RINs pricing (US$7.04 per barrel in 2023 compared with US$7.72 per barrel in 2022). Operating Expenses Primary drivers of operating expenses in 2023 were repairs and maintenance, and workforce. Operating expenses increased $216 million to $2.6 billion in 2023, compared with 2022, primarily due to the restart of operations at the Toledo and Superior refineries combined with full ownership of the Toledo Refinery. The increases were also Increased repairs and maintenance spend at the Lima Refinery, primarily due to higher engineering services and inspection costs, combined with turnaround preparation costs related to the turnaround that was deferred from 2023 Increased per barrel repairs and maintenance spend at the Borger Refinery, primarily related to the two planned Increased workforce costs at the Superior Refinery for restart and ramp up activities and higher overall workforce to 2024. turnarounds that were completed in 2023. costs related to the Toledo Acquisition. Higher electricity pricing, primarily impacting the Lima Refinery, partially offset by lower electricity pricing at the Wood River Refinery. Inflationary pressures on maintenance and chemical costs. The increase was partially offset by lower turnaround costs on a per barrel basis at the Toledo Refinery due to the significant planned turnaround completed in 2022, as well as lower per barrel repairs and maintenance costs at the Wood River Refinery due to the planned turnarounds in 2022. Fuel costs also decreased at the Wood River, Lima and Borger refineries due to the decline in natural gas benchmark pricing. In 2023, per-unit operating expenses decreased $0.77 per barrel to $15.27 per barrel, compared with 2022, primarily due to higher throughput, partially offset by the increase in operating expenses discussed above. (Gain) Loss on Risk Management In 2023, we incurred no realized risk management gains or losses, compared with losses of $112 million in 2022, due to the settlement of benchmark prices relative to our risk management contract prices. In 2023, we recorded unrealized risk management gains of $17 million (2022 – losses of $18 million), on our crude oil and refined products financial instruments primarily due to changes to forward benchmark pricing relative to our risk management contract prices that related to future due to: • • • • • periods. DD&A U.S. Refining DD&A in 2023 was $486 million, compared with $640 million in 2022. The decrease was primarily due to net impairment charges of $266 million recorded in the fourth quarter of 2022. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 31 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 32 36 | CENOVUS ENERGY 2023 ANNUAL REPORT Select Operating Results - Consolidated Revenues and Gross Margin 2023 635.2 459.7 173.9 285.8 75 485.0 231.2 167.0 19.8 67.0 18.12 15.27 2022 551.5 400.8 116.1 284.7 80 419.9 199.8 153.4 8.9 57.8 28.70 16.04 Total U.S. Refining Crude Oil Unit Throughput Capacity (1) (2) (Mbbls/d) Crude Oil Unit Throughput (2) (Mbbls/d) Heavy Crude Oil Light and Medium Crude Oil Crude Utilization (2) (percent) Total Refined Product Production (Mbbls/d) Gasoline Distillates (3) Asphalt Other Refining Margin (4) ($/bbl) Unit Operating Expense (5) ($/bbl) Based on crude oil name plate capacity. Includes diesel and jet fuel. Contains a non-GAAP financial measure. See the Advisory. Specified financial measure. See the Advisory. Select Operating Results - by Refinery (1) (2) (3) (4) (5) (1) (2) (3) The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023. 2023 2022 Lima Toledo Superior Lima Toledo Superior Wood River and Borger (1) Wood River and Borger (1) 178.7 160.0 247.5 175.0 49.0 247.5 152.7 83.1 201.3 157.9 85 57 81 90 — — 206.6 83 49.0 22.6 61 80.0 36.3 45 Crude Oil Unit Throughput Capacity (2) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) Represents Cenovus’s 50 percent interest in the non-operated Wood River and Borger refinery operations. Based on crude oil name plate capacity. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023. U.S. Refining throughput increased 58.9 thousand barrels per day from 2022 to 459.7 thousand barrels per day, and total refined product production increased 65.1 thousand barrels per day to 485.0 thousand barrels per day, primarily related to the Toledo Acquisition and the restart of the Toledo and Superior refineries. Other factors that impacted throughput and production include: • • • • Less downtime at the Wood River Refinery, primarily due to the two planned turnarounds in 2022 having a larger impact than the planned turnaround in the spring of 2023, combined with the decision to reduce rates to optimize margins as market conditions dictated in the first quarter of 2022. Two planned turnarounds and unplanned outages at the Borger Refinery, which had a larger impact than unplanned outages and the turnaround completed in 2022. The refinery experienced an unplanned operational outage following the fall turnaround which resulted in a slower than expected restart. Combined throughput at the Wood River and Borger refineries decreased 5.3 thousand barrels per day to 201.3 thousand barrels per day in 2023. Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Late in the year, we flexed throughput at our U.S. refineries to optimize our margins. Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as a general market indicator. The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. 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, distillates and secondary product output, the time lag between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued on a FIFO accounting basis. In 2023, the Chicago 3-2-1 crack spread decreased 29 percent to US$24.19 per barrel compared with 2022 and the Group 3 crack spread declined 11 percent to US$29.66 per barrel. Because of the relative strength of the Group 3 crack spread, our Borger and Superior refineries were not impacted as heavily by pricing declines as our other refineries. Average benchmark gasoline prices fell 19 percent to US$97.86 per barrel in 2023 compared with 2022. Average benchmark diesel prices also fell US$34.15 per barrel to US$109.70 per barrel in the year compared with 2022. Revenues decreased $3.8 billion in 2023 compared with 2022, primarily due to lower refined product pricing, partially offset by higher production. Gross margin decreased $1.2 billion in 2023 compared with 2022, primarily due to lower market crack spreads discussed above, impacts from processing feedstock purchased at higher prices in prior periods, partially offset by higher production and weaker RINs pricing (US$7.04 per barrel in 2023 compared with US$7.72 per barrel in 2022). Operating Expenses Primary drivers of operating expenses in 2023 were repairs and maintenance, and workforce. Operating expenses increased $216 million to $2.6 billion in 2023, compared with 2022, primarily due to the restart of operations at the Toledo and Superior refineries combined with full ownership of the Toledo Refinery. The increases were also due to: • • • • • Increased repairs and maintenance spend at the Lima Refinery, primarily due to higher engineering services and inspection costs, combined with turnaround preparation costs related to the turnaround that was deferred from 2023 to 2024. Increased per barrel repairs and maintenance spend at the Borger Refinery, primarily related to the two planned turnarounds that were completed in 2023. Increased workforce costs at the Superior Refinery for restart and ramp up activities and higher overall workforce costs related to the Toledo Acquisition. Higher electricity pricing, primarily impacting the Lima Refinery, partially offset by lower electricity pricing at the Wood River Refinery. Inflationary pressures on maintenance and chemical costs. The increase was partially offset by lower turnaround costs on a per barrel basis at the Toledo Refinery due to the significant planned turnaround completed in 2022, as well as lower per barrel repairs and maintenance costs at the Wood River Refinery due to the planned turnarounds in 2022. Fuel costs also decreased at the Wood River, Lima and Borger refineries due to the decline in natural gas benchmark pricing. In 2023, per-unit operating expenses decreased $0.77 per barrel to $15.27 per barrel, compared with 2022, primarily due to higher throughput, partially offset by the increase in operating expenses discussed above. (Gain) Loss on Risk Management In 2023, we incurred no realized risk management gains or losses, compared with losses of $112 million in 2022, due to the settlement of benchmark prices relative to our risk management contract prices. In 2023, we recorded unrealized risk management gains of $17 million (2022 – losses of $18 million), on our crude oil and refined products financial instruments primarily due to changes to forward benchmark pricing relative to our risk management contract prices that related to future periods. DD&A U.S. Refining DD&A in 2023 was $486 million, compared with $640 million in 2022. The decrease was primarily due to net impairment charges of $266 million recorded in the fourth quarter of 2022. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 31 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 32 CENOVUS ENERGY 2023 ANNUAL REPORT | 37 CORPORATE AND ELIMINATIONS Financial Results ($ millions) Realized (Gain) Loss on Risk Management Unrealized (Gain) Loss on Risk Management General and Administrative Finance Costs Interest Income Integration, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Risk Management 2023 (3) 73 688 671 (133) 85 (67) 34 59 (14) (63) 2022 31 (89) 865 820 (81) 106 343 (549) 162 (269) (532) In 2023, our corporate risk management activities resulted in realized risk management gains related to foreign exchange risk management contracts. Unrealized risk management losses were primarily related to renewable power contracts. We had no material divestitures in 2023. In 2022, we recognized a gain on divestiture of assets of $269 million due to the sale of our Tucker and Wembley assets, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions, General and Administrative Primary drivers of our general and administrative expenses in 2023 were workforce costs, information technology costs and employee long-term incentive costs. General and administrative expenses decreased in 2023 compared with 2022, primarily due to lower stock-based compensation costs of $97 million (2022 – $373 million). The decrease is partially offset by higher spending on community investment initiatives, workforce and information technology costs. Finance Costs Finance costs were lower in 2023 compared with 2022 as a result of the Company’s lower long-term debt. In the third quarter of 2023, we purchased long-term debt with an aggregate principal amount of US$1.0 billion at a discount of $84 million. In the third quarter of 2022, we purchased long-term debt with an aggregate principal amount of US$2.2 billion at a discount of $4 million. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt. The annualized weighted average interest rate on outstanding debt for 2023 was 4.7 percent (2022 – 4.7 percent). Integration, Transaction and Other Costs We incurred integration and transaction costs of $57 million related to the Toledo Acquisition. We also incurred costs of $28 million related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. In 2022, we incurred integration and transaction costs of $106 million, primarily related to the integration of Cenovus and Husky. Foreign Exchange (Gain) Loss, Net ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2023 (210) 143 (67) 2022 365 (22) 343 In 2023, unrealized foreign exchange gains, compared with losses in 2022, were mainly related to the translation of U.S. denominated debt caused by a stronger Canadian dollar at December 31, 2023. Realized foreign exchange losses in 2023 were primarily due to the settlement of fixed-term debt. Realized foreign exchange gains in 2022 were primarily related to working capital, partially offset by a lower realized foreign exchange loss on the settlement of fixed-term debt in 2023 compared with 2022. Revaluation (Gain) Loss As required by IFRS 3, “Business Combinations”, 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. Cenovus recognized a revaluation loss of $34 million in 2023 as part of the Toledo Acquisition. In the third quarter of 2022, Cenovus recognized a revaluation gain of $549 million as part of the Sunrise Acquisition. Re-measurement of Contingent Payments 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 maximum cumulative variable payment is $600 million. Refer to Note 26 of the Consolidated Financial Statements for further details. The variable payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at December 31, 2023, the fair value of the variable payment was estimated to be $164 million, resulting in non-cash re- measurement losses of $59 million in the year ended December 31, 2023 (2022 – gains of $89 million). For the year ended December 31, 2023, we paid $299 million under this agreement (2022 – $nil). The payment of $107 million for the quarter ended November 30, 2023, was made on January 29, 2024. The payments are recognized in cash from (used in) investing activities. As of December 31, 2023, average estimated WCS forward pricing for the remaining term of the variable payment is approximately $71.86 per barrel. As at December 31, 2023, the remaining payments are considered current liabilities. The maximum payment over the remaining term of the contract is $194 million. The contingent payment associated with the transaction with ConocoPhillips related to its 50 percent interest in the FCCL Partnership ended on May 17, 2022, and the final payment was made in July 2022. We recorded a non-cash remeasurement loss of $251 million associated with this payment in 2022. (Gain) Loss on Divestiture of Assets In 2023, other income was $63 million (2022 – $532 million). Other income in 2022 was primarily due to insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region, combined with funding received under the Government of Alberta’s Site Rehabilitation Program. The largest drivers of corporate depreciation include information technology assets, right-of-use buildings and leasehold improvements. DD&A for the year ended December 31, 2023, was $107 million, compared with $113 million in 2022. and the retail divestiture. Other (Income) Loss, Net DD&A Income Taxes ($ millions) Current Tax Canada United States Asia Pacific Other International Total Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) 2023 1,041 (109) 224 25 1,181 (250) 931 2022 1,252 104 262 21 1,639 642 2,281 The decline in current income tax expense for 2023 was primarily due to lower earnings compared with 2022. The effective tax rate in 2023 was 18.5 percent (2022 – 26.1 percent). The lower rate is primarily due to the deferred tax recovery recorded in 2023 related to the recognition of tax attributes acquired in the Toledo Acquisition. 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 Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and legislation. other legislation. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 33 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 34 38 | CENOVUS ENERGY 2023 ANNUAL REPORT 2023 (3) 73 688 671 (133) 85 (67) 34 59 (14) (63) 2022 31 (89) 865 820 (81) 106 343 (549) 162 (269) (532) Re-measurement of Contingent Payments 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 maximum cumulative variable payment is $600 million. Refer to Note 26 of the Consolidated Financial Statements for further details. The variable payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at December 31, 2023, the fair value of the variable payment was estimated to be $164 million, resulting in non-cash re- measurement losses of $59 million in the year ended December 31, 2023 (2022 – gains of $89 million). For the year ended December 31, 2023, we paid $299 million under this agreement (2022 – $nil). The payment of $107 million for the quarter ended November 30, 2023, was made on January 29, 2024. The payments are recognized in cash from (used in) investing activities. As of December 31, 2023, average estimated WCS forward pricing for the remaining term of the variable payment is approximately $71.86 per barrel. As at December 31, 2023, the remaining payments are considered current liabilities. The maximum payment over the remaining term of the contract is $194 million. The contingent payment associated with the transaction with ConocoPhillips related to its 50 percent interest in the FCCL Partnership ended on May 17, 2022, and the final payment was made in July 2022. We recorded a non-cash remeasurement loss of $251 million associated with this payment in 2022. (Gain) Loss on Divestiture of Assets We had no material divestitures in 2023. In 2022, we recognized a gain on divestiture of assets of $269 million due to the sale of our Tucker and Wembley assets, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions, and the retail divestiture. Other (Income) Loss, Net In 2023, other income was $63 million (2022 – $532 million). Other income in 2022 was primarily due to insurance proceeds related to the 2018 incidents at the Superior Refinery and in the Atlantic region, combined with funding received under the Government of Alberta’s Site Rehabilitation Program. Finance Costs DD&A The largest drivers of corporate depreciation include information technology assets, right-of-use buildings and leasehold improvements. DD&A for the year ended December 31, 2023, was $107 million, compared with $113 million in 2022. Income Taxes ($ millions) Current Tax Canada United States Asia Pacific Other International Total Current Tax Expense (Recovery) Deferred Tax Expense (Recovery) 2023 1,041 (109) 224 25 1,181 (250) 931 2022 1,252 104 262 21 1,639 642 2,281 The decline in current income tax expense for 2023 was primarily due to lower earnings compared with 2022. The effective tax rate in 2023 was 18.5 percent (2022 – 26.1 percent). The lower rate is primarily due to the deferred tax recovery recorded in 2023 related to the recognition of tax attributes acquired in the Toledo Acquisition. 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. Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to, different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other legislation. CORPORATE AND ELIMINATIONS Financial Results ($ millions) Realized (Gain) Loss on Risk Management Unrealized (Gain) Loss on Risk Management General and Administrative Finance Costs Interest Income Integration, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Risk Management General and Administrative In 2023, our corporate risk management activities resulted in realized risk management gains related to foreign exchange risk management contracts. Unrealized risk management losses were primarily related to renewable power contracts. Primary drivers of our general and administrative expenses in 2023 were workforce costs, information technology costs and employee long-term incentive costs. General and administrative expenses decreased in 2023 compared with 2022, primarily due to lower stock-based compensation costs of $97 million (2022 – $373 million). The decrease is partially offset by higher spending on community investment initiatives, workforce and information technology costs. Finance costs were lower in 2023 compared with 2022 as a result of the Company’s lower long-term debt. In the third quarter of 2023, we purchased long-term debt with an aggregate principal amount of US$1.0 billion at a discount of $84 million. In the third quarter of 2022, we purchased long-term debt with an aggregate principal amount of US$2.2 billion at a discount of $4 million. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt. The annualized weighted average interest rate on outstanding debt for 2023 was 4.7 percent (2022 – 4.7 percent). Integration, Transaction and Other Costs We incurred integration and transaction costs of $57 million related to the Toledo Acquisition. We also incurred costs of $28 million related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. In 2022, we incurred integration and transaction costs of $106 million, primarily related to the integration of Cenovus and Husky. Foreign Exchange (Gain) Loss, Net ($ millions) Unrealized Foreign Exchange (Gain) Loss Realized Foreign Exchange (Gain) Loss 2023 (210) 143 (67) 2022 365 (22) 343 In 2023, unrealized foreign exchange gains, compared with losses in 2022, were mainly related to the translation of U.S. denominated debt caused by a stronger Canadian dollar at December 31, 2023. Realized foreign exchange losses in 2023 were primarily due to the settlement of fixed-term debt. Realized foreign exchange gains in 2022 were primarily related to working capital, partially offset by a lower realized foreign exchange loss on the settlement of fixed-term debt in 2023 compared with 2022. Revaluation (Gain) Loss Acquisition. As required by IFRS 3, “Business Combinations”, 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. Cenovus recognized a revaluation loss of $34 million in 2023 as part of the Toledo Acquisition. In the third quarter of 2022, Cenovus recognized a revaluation gain of $549 million as part of the Sunrise Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 33 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 34 CENOVUS ENERGY 2023 ANNUAL REPORT | 39 QUARTERLY RESULTS ($ millions, except where indicated) Average Commodity Prices (1) (US$/bbl) Dated Brent WTI WCS at Hardisty Differential WTI-WCS at Hardisty Chicago 3-2-1 Crack Spread (2) RINs Upstream Production Volumes Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Downstream Crude Oil Unit Throughput (3) (Mbbls/d) Downstream Production Volumes (Mbbls/d) Revenues Operating Margin (4) Q4 84.05 78.32 56.43 21.89 13.24 4.77 595.1 17.5 15.8 34.2 876.3 808.6 579.1 627.4 2023 Q3 Q2 Q1 Q4 2022 Q3 Q2 Q1 86.76 82.26 69.35 12.91 26.06 7.42 586.0 15.6 15.2 35.6 867.4 797.0 664.3 706.0 78.39 73.78 58.74 15.04 28.57 7.72 554.6 17.0 10.1 26.7 729.4 729.9 537.8 571.9 81.27 76.13 51.36 24.77 28.88 8.20 570.7 16.8 15.3 33.4 857.0 779.0 457.9 487.7 88.71 82.65 56.99 25.66 32.87 8.54 593.5 15.8 17.1 38.5 852.0 806.9 473.3 506.3 100.85 91.55 71.69 19.86 38.87 8.11 568.2 16.8 16.0 32.1 868.7 777.9 533.5 572.6 113.78 108.41 95.61 12.80 46.50 7.80 540.3 16.4 20.8 36.7 882.2 761.5 457.3 482.1 101.41 94.29 79.76 14.53 18.35 6.44 578.8 16.2 21.9 37.6 865.3 798.6 501.8 538.0 13,134 14,577 12,231 12,262 14,063 17,471 19,165 16,198 2022, primarily due to: 2,151 4,369 2,400 2,102 2,782 3,339 4,678 3,464 Cash From (Used in) Operating Activities 2,946 2,738 1,990 (286) 2,970 4,089 2,979 1,365 Adjusted Funds Flow (4) Per Share - Basic (4) ($) Per Share - Diluted (4) ($) Capital Investment Free Funds Flow (4) Excess Free Funds Flow (4) Net Earnings (Loss) (5) Per Share - Basic ($) Per Share - Diluted ($) Total Assets Total Long-Term Liabilities Long-Term Debt, Including Current Portion Net Debt Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Payment for Purchase of Warrants Preferred Share Dividends 2,062 1.10 1.09 1,170 892 471 743 0.39 0.39 3,447 1.82 1.81 1,025 2,422 1,989 1,864 0.98 0.97 1,899 1.00 0.98 1,395 0.73 0.71 1,002 1,101 897 505 866 0.45 0.44 294 (499) 636 0.33 0.32 2,346 2,951 3,098 2,583 1.22 1.19 1,274 1,072 786 784 0.40 0.39 1.53 1.49 866 2,085 1,756 1,609 0.83 0.81 1.57 1.53 822 2,276 2,020 2,432 1.23 1.19 1.30 1.27 746 1,837 2,615 1,625 0.81 0.79 53,915 54,427 53,747 54,000 55,869 55,086 55,894 55,655 18,993 18,395 19,831 19,917 20,259 19,378 20,742 21,889 7,108 5,060 731 261 0.140 — — 350 111 9 7,224 5,976 1,225 264 0.140 — — 361 600 — 8,534 6,367 584 265 0.140 — — 310 — 9 8,681 6,632 258 200 0.105 — — 40 — 18 8,691 4,282 807 201 0.105 219 0.114 387 — — 8,774 11,228 11,744 5,280 873 205 0.105 — — 659 — 9 7,535 1,233 207 0.105 — — 1,018 — 8 8,407 544 69 0.035 — — 466 — 9 (1) (2) (3) (4) (5) 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. Represents Cenovus’s net interest in refining operations. Non-GAAP financial measure 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. The fourth quarter was highlighted by strong upstream performance, planned and unplanned outages in our downstream business, and financial results reflecting a declining commodity price environment. Upstream production averaged 808.6 thousand BOE per day, an increase from 797.0 thousand BOE per day in the third quarter of 2023, and our highest quarterly average since the fourth quarter of 2021. Downstream throughput decreased to 579.1 thousand barrels per day from 664.3 thousand barrels per day in the third quarter, largely driven by the planned turnaround and delayed startup at the Borger Refinery, and planned and unplanned outages at the Lima Refinery in the fourth quarter. • WCS at Hardisty decreased from US$69.35 per barrel in the third quarter to US$56.43 per barrel, including a decrease in December to US$45.54 per barrel. The Chicago 3-2-1 crack spread declined significantly from US$26.06 per barrel in the third quarter to US$13.24 per barrel, the lowest quarterly average since the first quarter of 2021. The December 2023 average Chicago 3-2-1 crack spread was US$7.65 per barrel, the lowest monthly average since 2020. Operating Margin fell to $2.2 billion from $4.4 billion in the third quarter of 2023 and Adjusted Funds Flow decreased to $2.1 billion from $3.4 billion in the third quarter. • We reduced Net Debt by $916 million from September 30, 2023, primarily due to cash from operating activities of $2.9 billion, capital investment of $1.2 billion and cash returns to shareholders of $731 million. Fourth Quarter 2023 Results Compared with the Fourth Quarter 2022 The summary below compares financial and operating results for the three months ended December 31, 2023, compared with the same period in 2022. Upstream Production Volumes Total upstream production increased 1.7 thousand BOE per day in the fourth quarter of 2023 compared with the same period in Successful results from redevelopment programs at our Sunrise and Lloydminster thermal assets. Production from the MAC field in Indonesia that started in the third quarter of 2023, and the MBH and MDA fields that came online part way through the fourth quarter of 2022. The impact of well pads brought online at Foster Creek in the second and third quarters of 2023. The Terra Nova FPSO resuming production in late November. The increases were partially offset by lower production at Christina Lake due to the timing of new wells pads in 2023 in addition to the suspension of production at the White Rose field as we prepared for the planned SeaRose ALE project in late December. Downstream Refining Throughput and Production Canadian Refining throughput increased 6.0 thousand barrels per day to 100.3 thousand barrels per day and refined product production increased 5.7 thousand barrels per day to 113.3 thousand barrels per day compared with 2022. Utilization at the Upgrader and Lloydminster Refinery was 90 percent and 92 percent, respectively (2022 – 84 percent and 89 percent, respectively). Operations were solid in the fourth quarter of 2023 compared with cold weather impacts and unplanned operational outages in the fourth quarter of 2022. The increases were partially offset by an unplanned outage at the Upgrader in October, which returned to full rates in November. U.S. Refining throughput increased 99.8 thousand barrels per day to 478.8 thousand barrels per day and total refined product production increased 115.4 thousand barrels per day to 514.1 thousand barrels per day compared with 2022, primarily due to: An increase in throughput at the Toledo Refinery of 138.4 thousand barrels per day due to the Toledo Acquisition and the restart of the Toledo Refinery. Throughput of 32.4 thousand barrels per day because of the restart of the Superior Refinery. The increases in throughput and production were partially offset by: The planned turnaround at the Borger Refinery completed in the fourth quarter of 2023 and an unplanned operational outage following the turnaround which resulted in slower than expected ramp up. Planned maintenance and a temporary unplanned outage at the Lima Refinery in the fourth quarter of 2023. Our ability to flex throughput across our refining network to optimize our margins. • • • • • • • • • • • • • Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 35 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 36 40 | CENOVUS ENERGY 2023 ANNUAL REPORT Revenues Operating Margin (4) 13,134 14,577 12,231 12,262 14,063 17,471 19,165 16,198 2,151 4,369 2,400 2,102 2,782 3,339 4,678 3,464 Cash From (Used in) Operating Activities 2,946 2,738 1,990 (286) 2,970 4,089 2,979 1,365 QUARTERLY RESULTS ($ millions, except where indicated) Average Commodity Prices (1) (US$/bbl) Dated Brent WTI WCS at Hardisty Differential WTI-WCS at Hardisty Chicago 3-2-1 Crack Spread (2) RINs Upstream Production Volumes Bitumen (Mbbls/d) Heavy Crude Oil (Mbbls/d) Light Crude Oil (Mbbls/d) NGLs (Mbbls/d) Conventional Natural Gas (MMcf/d) Total Production Volumes (MBOE/d) Downstream Crude Oil Unit Throughput (3) (Mbbls/d) Downstream Production Volumes (Mbbls/d) Adjusted Funds Flow (4) Per Share - Basic (4) ($) Per Share - Diluted (4) ($) Capital Investment Free Funds Flow (4) Excess Free Funds Flow (4) Net Earnings (Loss) (5) Per Share - Basic ($) Per Share - Diluted ($) Total Assets Total Long-Term Liabilities Net Debt Cash Returns to Shareholders Common Shares – Base Dividends Base Dividends Per Common Share ($) Common Shares – Variable Dividends Variable Dividends Per Common Share ($) Purchase of Common Shares Under NCIB Payment for Purchase of Warrants Preferred Share Dividends 595.1 586.0 554.6 570.7 593.5 568.2 540.3 578.8 Q4 84.05 78.32 56.43 21.89 13.24 4.77 17.5 15.8 34.2 876.3 808.6 579.1 627.4 2,062 1.10 1.09 1,170 892 471 743 0.39 0.39 7,108 5,060 731 261 0.140 — — 350 111 9 2023 Q3 Q2 Q1 Q4 Q2 Q1 2022 Q3 86.76 82.26 69.35 12.91 26.06 7.42 15.6 15.2 35.6 867.4 797.0 664.3 706.0 3,447 1.82 1.81 1,025 2,422 1,989 1,864 0.98 0.97 7,224 5,976 1,225 264 0.140 — — 361 600 — 78.39 73.78 58.74 15.04 28.57 7.72 17.0 10.1 26.7 729.4 729.9 537.8 571.9 897 505 866 0.45 0.44 8,534 6,367 584 265 310 — — — 9 81.27 76.13 51.36 24.77 28.88 8.20 16.8 15.3 33.4 857.0 779.0 457.9 487.7 294 (499) 636 0.33 0.32 8,681 6,632 258 200 — — 40 — 18 88.71 82.65 56.99 25.66 32.87 8.54 15.8 17.1 38.5 852.0 806.9 473.3 506.3 1.22 1.19 1,274 1,072 786 784 0.40 0.39 8,691 4,282 807 201 0.105 219 0.114 387 — — 100.85 91.55 71.69 19.86 38.87 8.11 113.78 108.41 95.61 12.80 46.50 7.80 101.41 94.29 79.76 14.53 18.35 6.44 16.8 16.0 32.1 868.7 777.9 533.5 572.6 1.53 1.49 866 2,085 1,756 1,609 0.83 0.81 5,280 873 205 0.105 — — — 9 16.4 20.8 36.7 882.2 761.5 457.3 482.1 1.57 1.53 822 2,276 2,020 2,432 1.23 1.19 7,535 1,233 207 0.105 — — — 8 16.2 21.9 37.6 865.3 798.6 501.8 538.0 1.30 1.27 746 1,837 2,615 1,625 0.81 0.79 8,407 544 69 0.035 466 — — — 9 659 1,018 2,346 2,951 3,098 2,583 1,899 1.00 0.98 1,395 0.73 0.71 1,002 1,101 Long-Term Debt, Including Current Portion 8,774 11,228 11,744 53,915 54,427 53,747 54,000 55,869 55,086 55,894 55,655 18,993 18,395 19,831 19,917 20,259 19,378 20,742 21,889 (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. 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. Represents Cenovus’s net interest in refining operations. Non-GAAP financial measure 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. (2) (3) (4) (5) The fourth quarter was highlighted by strong upstream performance, planned and unplanned outages in our downstream business, and financial results reflecting a declining commodity price environment. • • Upstream production averaged 808.6 thousand BOE per day, an increase from 797.0 thousand BOE per day in the third quarter of 2023, and our highest quarterly average since the fourth quarter of 2021. Downstream throughput decreased to 579.1 thousand barrels per day from 664.3 thousand barrels per day in the third quarter, largely driven by the planned turnaround and delayed startup at the Borger Refinery, and planned and unplanned outages at the Lima Refinery in the fourth quarter. • WCS at Hardisty decreased from US$69.35 per barrel in the third quarter to US$56.43 per barrel, including a decrease • • in December to US$45.54 per barrel. The Chicago 3-2-1 crack spread declined significantly from US$26.06 per barrel in the third quarter to US$13.24 per barrel, the lowest quarterly average since the first quarter of 2021. The December 2023 average Chicago 3-2-1 crack spread was US$7.65 per barrel, the lowest monthly average since 2020. Operating Margin fell to $2.2 billion from $4.4 billion in the third quarter of 2023 and Adjusted Funds Flow decreased to $2.1 billion from $3.4 billion in the third quarter. • We reduced Net Debt by $916 million from September 30, 2023, primarily due to cash from operating activities of $2.9 billion, capital investment of $1.2 billion and cash returns to shareholders of $731 million. Fourth Quarter 2023 Results Compared with the Fourth Quarter 2022 The summary below compares financial and operating results for the three months ended December 31, 2023, compared with the same period in 2022. Upstream Production Volumes Total upstream production increased 1.7 thousand BOE per day in the fourth quarter of 2023 compared with the same period in 2022, primarily due to: • • • • Successful results from redevelopment programs at our Sunrise and Lloydminster thermal assets. Production from the MAC field in Indonesia that started in the third quarter of 2023, and the MBH and MDA fields that came online part way through the fourth quarter of 2022. The impact of well pads brought online at Foster Creek in the second and third quarters of 2023. The Terra Nova FPSO resuming production in late November. The increases were partially offset by lower production at Christina Lake due to the timing of new wells pads in 2023 in addition to the suspension of production at the White Rose field as we prepared for the planned SeaRose ALE project in late December. Downstream Refining Throughput and Production Canadian Refining throughput increased 6.0 thousand barrels per day to 100.3 thousand barrels per day and refined product production increased 5.7 thousand barrels per day to 113.3 thousand barrels per day compared with 2022. Utilization at the Upgrader and Lloydminster Refinery was 90 percent and 92 percent, respectively (2022 – 84 percent and 89 percent, respectively). Operations were solid in the fourth quarter of 2023 compared with cold weather impacts and unplanned operational outages in the fourth quarter of 2022. The increases were partially offset by an unplanned outage at the Upgrader in October, which returned to full rates in November. U.S. Refining throughput increased 99.8 thousand barrels per day to 478.8 thousand barrels per day and total refined product production increased 115.4 thousand barrels per day to 514.1 thousand barrels per day compared with 2022, primarily due to: • • An increase in throughput at the Toledo Refinery of 138.4 thousand barrels per day due to the Toledo Acquisition and the restart of the Toledo Refinery. Throughput of 32.4 thousand barrels per day because of the restart of the Superior Refinery. 0.140 0.105 The increases in throughput and production were partially offset by: • • • The planned turnaround at the Borger Refinery completed in the fourth quarter of 2023 and an unplanned operational outage following the turnaround which resulted in slower than expected ramp up. Planned maintenance and a temporary unplanned outage at the Lima Refinery in the fourth quarter of 2023. Our ability to flex throughput across our refining network to optimize our margins. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 35 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 36 CENOVUS ENERGY 2023 ANNUAL REPORT | 41 OIL AND GAS RESERVES As at December 31, 2023 (before royalties) (1) Total Proved Probable Total Proved Plus Probable As at December 31, 2022 (before royalties) (1) Total Proved Probable Total Proved Plus Probable Bitumen (2) (MMbbls) 5,411 2,487 7,899 Bitumen (2) (MMbbls) 5,592 2,448 8,040 Light and Medium Oil (MMbbls) 38 125 163 42 129 171 Light and Medium Oil (MMbbls) NGLs (MMbbls) 74 40 114 NGLs (MMbbls) 82 39 121 Conventional Natural Gas (3) (Bcf) 2,062 1,100 3,162 (Bcf) 2,194 1,029 3,223 Conventional Natural Gas (3) Total (MMBOE) 5,866 2,836 8,702 Total (MMBOE) 6,082 2,787 8,869 (1) (2) (3) Totals may not sum due to rounding. Includes heavy crude oil that is not material. Includes shale gas that is not material. Developments in 2023 compared with 2022 include: • Bitumen gross total proved and gross total proved plus probable reserves decreased by 181 million barrels and 141 million barrels, respectively. The changes were due to current year production and recovery factor adjustments at Christina Lake and Foster Creek, partially offset by additions from regulatory approvals at Foster Creek and Lloydminster thermal, updates to the Sunrise development plan, an acquisition in the Oil Sands segment and improved recovery performance at Lloydminster thermal. Light and medium oil gross total proved and gross total proved plus probable reserves decreased by 4 million barrels and 8 million barrels, respectively. The changes were due to current year production and technical revisions, 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 8 million barrels and 7 million barrels , respectively. The changes were due to current year production, partially offset by additions from updates to the Conventional segment development plans. Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 132 billion cubic feet and 61 billion cubic feet, respectively. The changes were due to current year production, partially offset by updates to the Conventional segment development plans and updates to gas contracts in Asia Pacific. • • • The reserves data is presented as at December 31, 2023, using an average of the forecast prices, inflation and exchange rate (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast is dated January 1, 2024. Comparative information as at December 31, 2022 uses the January 1, 2023, Average Forecast. 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, 2023. Our AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section of this MD&A and the Advisory section. Operating Margin Three Months Ended December 31, 2023 and 2022 ) s n o i l l i m $ ( 2,400 1,800 1,200 600 0 (600) 1,962 1,639 248 123 370 337 278 126 280 Oil Sands Conventional Offshore Canadian Refining U.S. Refining (430) Q4 2023 Q4 2022 Operating Margin decreased $631 million to $2.2 billion in the fourth quarter of 2023, compared with 2022 primarily due to significantly lower market crack spreads and lower synthetic crude oil prices relative to crude oil feedstock impacting our downstream business. In addition, we processed feedstock from inventory purchased at higher prices in prior periods and recorded non-cash inventory write-downs on our refined products inventory in the fourth quarter. The decreases were partially offset by higher throughput and refined product production due to the Toledo Acquisition and the start-up of the Toledo and Superior refineries. Also offsetting the decrease was a higher Operating Margin from our upstream business mainly due to increased sales volumes, and higher realized pricing from the Oil Sands segment. Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash from operating activities of $2.9 billion in the fourth quarter of 2023 was consistent with 2022, as the decrease in Operating Margin discussed above, was partially offset by changes in non-cash working capital. The net change in non-cash working capital in the fourth quarter of 2023 was $949 million, compared with a net change of $673 million in the fourth quarter of 2022. The increase in 2023 was mainly due to decreases in accounts receivable and inventory, partially offset by a decrease in accounts payable, primarily due to falling commodity prices. Adjusted Funds Flow decreased to $2.1 billion in the fourth quarter of 2023 compared with $2.3 billion in 2022, primarily due to lower Operating Margin discussed above. Net Earnings (Loss) Net earnings were $743 million in the fourth quarter of 2023 compared with $784 million in 2022. The decrease was due to lower Operating Margin, partially offset by lower general and administrative costs and DD&A. Capital Investment Capital investment in the fourth quarter of 2023 was $1.2 billion (2022 – $1.3 billion), mainly related to: • • • • Sustaining activities and the drilling of stratigraphic test wells as part of our integrated winter program in the Oil Sands segment, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Drilling, completion, tie-in and infrastructure projects in the Conventional segment. The West White Rose project in the Atlantic region. Sustaining activities at the Lima, Borger and Toledo refineries. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 37 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 38 42 | CENOVUS ENERGY 2023 ANNUAL REPORT Operating Margin Three Months Ended December 31, 2023 and 2022 Operating Margin decreased $631 million to $2.2 billion in the fourth quarter of 2023, compared with 2022 primarily due to significantly lower market crack spreads and lower synthetic crude oil prices relative to crude oil feedstock impacting our downstream business. In addition, we processed feedstock from inventory purchased at higher prices in prior periods and recorded non-cash inventory write-downs on our refined products inventory in the fourth quarter. The decreases were partially offset by higher throughput and refined product production due to the Toledo Acquisition and the start-up of the Toledo and Superior refineries. Also offsetting the decrease was a higher Operating Margin from our upstream business mainly due to increased sales volumes, and higher realized pricing from the Oil Sands segment. Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash from operating activities of $2.9 billion in the fourth quarter of 2023 was consistent with 2022, as the decrease in Operating Margin discussed above, was partially offset by changes in non-cash working capital. The net change in non-cash working capital in the fourth quarter of 2023 was $949 million, compared with a net change of $673 million in the fourth quarter of 2022. The increase in 2023 was mainly due to decreases in accounts receivable and inventory, partially offset by a decrease in accounts payable, primarily due to falling commodity prices. Adjusted Funds Flow decreased to $2.1 billion in the fourth quarter of 2023 compared with $2.3 billion in 2022, primarily due to lower Operating Margin discussed above. Net Earnings (Loss) Net earnings were $743 million in the fourth quarter of 2023 compared with $784 million in 2022. The decrease was due to lower Operating Margin, partially offset by lower general and administrative costs and DD&A. Capital Investment • • • • Capital investment in the fourth quarter of 2023 was $1.2 billion (2022 – $1.3 billion), mainly related to: Sustaining activities and the drilling of stratigraphic test wells as part of our integrated winter program in the Oil Sands segment, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster Creek and Sunrise. Drilling, completion, tie-in and infrastructure projects in the Conventional segment. The West White Rose project in the Atlantic region. Sustaining activities at the Lima, Borger and Toledo refineries. OIL AND GAS RESERVES As at December 31, 2023 (before royalties) (1) Total Proved Probable Total Proved Plus Probable As at December 31, 2022 (before royalties) (1) Total Proved Probable Total Proved Plus Probable Bitumen (2) (MMbbls) 5,411 2,487 7,899 Bitumen (2) (MMbbls) 5,592 2,448 8,040 Light and Medium Oil (MMbbls) 38 125 163 Light and Medium Oil (MMbbls) 42 129 171 NGLs (MMbbls) 74 40 114 NGLs (MMbbls) 82 39 121 Conventional Natural Gas (3) (Bcf) 2,062 1,100 3,162 Conventional Natural Gas (3) (Bcf) 2,194 1,029 3,223 Total (MMBOE) 5,866 2,836 8,702 Total (MMBOE) 6,082 2,787 8,869 (1) (2) (3) Totals may not sum due to rounding. Includes heavy crude oil that is not material. Includes shale gas that is not material. Developments in 2023 compared with 2022 include: • • • • Bitumen gross total proved and gross total proved plus probable reserves decreased by 181 million barrels and 141 million barrels, respectively. The changes were due to current year production and recovery factor adjustments at Christina Lake and Foster Creek, partially offset by additions from regulatory approvals at Foster Creek and Lloydminster thermal, updates to the Sunrise development plan, an acquisition in the Oil Sands segment and improved recovery performance at Lloydminster thermal. Light and medium oil gross total proved and gross total proved plus probable reserves decreased by 4 million barrels and 8 million barrels, respectively. The changes were due to current year production and technical revisions, 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 8 million barrels and 7 million barrels , respectively. The changes were due to current year production, partially offset by additions from updates to the Conventional segment development plans. Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 132 billion cubic feet and 61 billion cubic feet, respectively. The changes were due to current year production, partially offset by updates to the Conventional segment development plans and updates to gas contracts in Asia Pacific. The reserves data is presented as at December 31, 2023, using an average of the forecast prices, inflation and exchange rate (“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast is dated January 1, 2024. Comparative information as at December 31, 2022 uses the January 1, 2023, Average Forecast. 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, 2023. Our AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section of this MD&A and the Advisory section. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 37 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 38 CENOVUS ENERGY 2023 ANNUAL REPORT | 43 LIQUIDITY AND CAPITAL RESOURCES Our capital allocation framework enables us to strengthen our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders. The framework enables a shift to pay out a higher percentage of Excess Free Funds Flow to common shareholders, with lower leverage and a lower risk profile. 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, Morningstar DBRS 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 Effect of Foreign Exchange on Cash and Cash Equivalents Increase (Decrease) in Cash and Cash Equivalents As at December 31, Cash and Cash Equivalents Total Debt Cash From (Used in) Operating Activities 2023 2022 7,388 (5,295) 2,093 (4,313) (77) (2,297) 2023 2,227 7,287 11,403 (2,314) 9,089 (7,676) 238 1,651 2022 4,524 8,806 For the year ended December 31, 2023, cash from operating activities was $7.4 billion (2022 – $11.4 billion). The decrease was primarily due to lower Operating Margin and changes in non-cash working capital. During the year ended December 31, 2023, the net change in non-cash working capital decreased cash by $1.2 billion, primarily driven by the payment of the December 31, 2022, income tax liability of $1.2 billion in the first quarter of 2023. Cash From (Used in) Investing Activities Cash used in investing activities increased significantly in 2023 compared with 2022. The increase was partly due to higher capital spend, including acquisition capital. Acquisition capital was higher in 2023 with the closing of the Toledo Acquisition in the first quarter, which was partially offset by the Sunrise Acquisition in the third quarter of 2022. The increase was also due to minimal proceeds from divestitures in 2023, compared with the sales of our retail fuels network and the Tucker and Wembley assets in 2022. The net change in non-cash working capital, which includes the Sunrise contingent payments, decreased cash in 2023. Cash From (Used in) Financing Activities In 2023, we reduced debt through the purchase of US$1.0 billion of certain unsecured notes due between 2029 and 2047 at a discount of $84 million. In 2022, we purchased long-term debt of US$2.6 billion and C$750 million. We also returned $2.8 billion to shareholders in 2023 compared with $3.5 billion in 2022. In 2023, we issued $58 million, net, of short-term borrowings (2022 – $34 million, net). Working Capital Excluding the current portion of the contingent payments, our adjusted working capital at December 31, 2023, was $3.7 billion (December 31, 2022 – $4.7 billion). We anticipate that we will continue to meet our payment obligations as they come due. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 39 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 44 | CENOVUS ENERGY 2023 ANNUAL REPORT Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds Cenovus has after financing its capital programs. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our Three Months Ended December 31, Year Ended December 31, shareholder returns plan. ($ 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 Returns to Shareholders Target 2023 7,388 (222) (1,193) 8,803 4,298 4,505 2022 11,403 (150) 575 10,978 3,708 7,270 2023 2,946 (65) 949 2,062 1,170 892 (261) (9) (65) (72) (14) — 471 2022 2,970 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 786 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. We have set an ultimate Net Debt Target of $4 billion, which serves as our floor on Net Debt. 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 pricing cycle. 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 • When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s Flow to deleveraging the balance sheet. Excess Free Funds Flow to shareholder returns. Share buybacks are 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. On September 30, 2023, our long-term debt was $7.2 billion, and our Net Debt position was $6.0 billion. Therefore, our returns to shareholders target for the three months ended December 31, 2023, was 50 percent of the current quarter’s Excess Free Funds Flow of $471 million. Our target return was $236 million, which was exceeded through share buybacks of $350 million and warrant purchase payments of $111 million. As such, no variable dividend was declared for the first quarter of 2024. December 31, 2023 September 30, 2023 June 30, 2023 March 31, 2023 Three Months Ended ($ millions) Excess Free Funds Flow Target Return Less: Purchase of Common Shares Under NCIB Less: Payment for Purchase of Warrants Amount Available for Variable Dividend 471 236 (350) (111) — 1,989 995 (361) (600) 34 505 253 (310) — — (499) — (40) — — 40 LIQUIDITY AND CAPITAL RESOURCES Our capital allocation framework enables us to strengthen our balance sheet, provide flexibility in both high and low commodity price environments, and deliver value to shareholders. The framework enables a shift to pay out a higher percentage of Excess Free Funds Flow to common shareholders, with lower leverage and a lower risk profile. 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, Morningstar DBRS 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 Effect of Foreign Exchange on Cash and Cash Equivalents Increase (Decrease) in Cash and Cash Equivalents As at December 31, Cash and Cash Equivalents Total Debt Cash From (Used in) Operating Activities 2023 2022 7,388 (5,295) 2,093 (4,313) (77) (2,297) 2023 2,227 7,287 11,403 (2,314) 9,089 (7,676) 238 1,651 2022 4,524 8,806 For the year ended December 31, 2023, cash from operating activities was $7.4 billion (2022 – $11.4 billion). The decrease was primarily due to lower Operating Margin and changes in non-cash working capital. During the year ended December 31, 2023, the net change in non-cash working capital decreased cash by $1.2 billion, primarily driven by the payment of the December 31, 2022, income tax liability of $1.2 billion in the first quarter of 2023. Cash From (Used in) Investing Activities Cash used in investing activities increased significantly in 2023 compared with 2022. The increase was partly due to higher capital spend, including acquisition capital. Acquisition capital was higher in 2023 with the closing of the Toledo Acquisition in the first quarter, which was partially offset by the Sunrise Acquisition in the third quarter of 2022. The increase was also due to minimal proceeds from divestitures in 2023, compared with the sales of our retail fuels network and the Tucker and Wembley assets in 2022. The net change in non-cash working capital, which includes the Sunrise contingent payments, decreased cash in 2023. Cash From (Used in) Financing Activities In 2023, we reduced debt through the purchase of US$1.0 billion of certain unsecured notes due between 2029 and 2047 at a discount of $84 million. In 2022, we purchased long-term debt of US$2.6 billion and C$750 million. We also returned $2.8 billion to shareholders in 2023 compared with $3.5 billion in 2022. In 2023, we issued $58 million, net, of short-term borrowings (2022 – $34 million, net). Working Capital (December 31, 2022 – $4.7 billion). Excluding the current portion of the contingent payments, our adjusted working capital at December 31, 2023, was $3.7 billion We anticipate that we will continue to meet our payment obligations as they come due. Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds Cenovus has after financing its capital programs. Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our shareholder returns plan. ($ 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 Returns to Shareholders Target Year Ended December 31, 2023 7,388 (222) (1,193) 8,803 4,298 4,505 2022 11,403 (150) 575 10,978 3,708 7,270 Three Months Ended December 31, 2022 2023 2,946 2,970 (65) 949 2,062 1,170 892 (261) (9) (65) (72) (14) — 471 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 786 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. We have set an ultimate Net Debt Target of $4 billion, which serves as our floor on Net Debt. 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 pricing cycle. 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. Share buybacks are 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. On September 30, 2023, our long-term debt was $7.2 billion, and our Net Debt position was $6.0 billion. Therefore, our returns to shareholders target for the three months ended December 31, 2023, was 50 percent of the current quarter’s Excess Free Funds Flow of $471 million. Our target return was $236 million, which was exceeded through share buybacks of $350 million and warrant purchase payments of $111 million. As such, no variable dividend was declared for the first quarter of 2024. December 31, 2023 September 30, 2023 June 30, 2023 March 31, 2023 Three Months Ended ($ millions) Excess Free Funds Flow Target Return 471 236 (350) (111) — 1,989 995 (361) (600) 34 505 253 (310) — — (499) — (40) — — 40 CENOVUS ENERGY 2023 ANNUAL REPORT | 45 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 39 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis Less: Purchase of Common Shares Under NCIB Less: Payment for Purchase of Warrants Amount Available for Variable Dividend At December 31, 2023, our Net Debt position was $5.1 billion and as a result, our returns to shareholders target for the three months ended March 31, 2024, will be 50 percent of the first quarter’s Excess Free Funds Flow. Short-Term Borrowings As at December 31, 2023, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$135 million (C$179 million) (December 31, 2022 – the Company’s proportionate share drawn was US$85 million (C$115 million)). There were no direct borrowings on our uncommitted demand facilities as at December 31, 2023, or December 31, 2022. Long-Term Debt, Including Current Portion Long-term debt, including the current portion, as at December 31, 2023, was $7.1 billion (December 31, 2022 – $8.7 billion). This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.0 billion (December 31, 2022 – US$4.8 billion, or C$6.5 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2022 – $2.0 billion). The decrease in long-term debt was primarily due to the third quarter purchase of unsecured notes with an aggregate principal amount of US$1.0 billion at a discount of $84 million. As at December 31, 2023, we were in compliance with all of the terms of our debt agreements. Available Sources of Liquidity The following sources of liquidity are available as at December 31, 2023: ($ millions) Cash and Cash Equivalents Committed Credit Facility (1) Revolving Credit Facility – Tranche A Revolving Credit Facility – Tranche B Uncommitted Demand Facilities Cenovus Energy Inc. (2) WRB (3) Maturity n/a Amount Available 2,227 November 10, 2026 November 10, 2025 n/a n/a 3,700 1,800 1,071 119 (1) (2) (3) No amounts were drawn on the committed credit facility as at December 31, 2023 (December 31, 2022 – $nil). Our uncommitted demand facilities include $1.7 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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no direct borrowings (December 31, 2022 – $nil). Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2023, US$135 million (C$179 million) of this capacity was drawn (December 31, 2022 – US$85 million (C$115 million)). 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. Base Shelf Prospectus On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements. 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 25 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 (loss) before finance costs, net of capitalized interest, interest income, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity- accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, revaluation (gain) loss, re- measurement of contingent payments, (gain) loss on divestiture of assets, and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial strength. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 41 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 46 | CENOVUS ENERGY 2023 ANNUAL REPORT As at Net Debt to Capitalization Ratio (percent) Net Debt to Adjusted Funds Flow Ratio (times) Net Debt to Adjusted EBITDA Ratio (times) December 31, 2023 December 31, 2022 15 0.6 0.5 13 0.4 0.3 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$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. Our Net Debt to Capitalization Ratio as at December 31, 2023, increased compared with December 31, 2022, primarily due to higher Net Debt. Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2023, increased compared with December 31, 2022, as a result of higher Net Debt and lower Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt. Share Capital and Stock-Based Compensation Plans Our common shares and Cenovus Warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. As at December 31, 2023, there were approximately 1,871.9 million common shares outstanding (December 31, 2022 – 1,909.2 million common shares) and 36 million preferred shares outstanding (December 31, 2022 – 36 million preferred shares). Refer to Note 30 of the Consolidated Financial Statements for further details. On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024. Common Shares Purchased and Cancelled Under NCIB (millions of common shares) Weighted Average Price per Common Share ($) Purchase of Common Shares Under NCIB ($ millions) 2023 43.6 24.32 (1,061) 2022 112.5 22.49 (2,530) From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million. As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the existing NCIB. As at December 31, 2023, there were approximately 7.6 million Cenovus Warrants outstanding (December 31, 2022 – 55.7 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 30 of the Consolidated Financial Statements for further details. On June 14, 2023, we purchased and cancelled 45.5 million outstanding Cenovus Warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. We also recorded $2 million of transaction costs. This purchase represented 84 percent of Cenovus’s outstanding warrants. The full warrant purchase obligation was paid by December 31, 2023. Refer to Note 32 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 12, 2024 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 Units Outstanding Units Exercisable (thousands) (thousands) 1,867,826 7,614 10,740 1,260 10,000 8,000 6,000 12,852 19,230 n/a n/a n/a n/a n/a n/a n/a 7,615 1,772 42 At December 31, 2023, our Net Debt position was $5.1 billion and as a result, our returns to shareholders target for the three months ended March 31, 2024, will be 50 percent of the first quarter’s Excess Free Funds Flow. Short-Term Borrowings As at December 31, 2023, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$135 million (C$179 million) (December 31, 2022 – the Company’s proportionate share drawn was US$85 million (C$115 million)). There were no direct borrowings on our uncommitted demand facilities as at December 31, 2023, or December 31, 2022. Long-Term Debt, Including Current Portion Long-term debt, including the current portion, as at December 31, 2023, was $7.1 billion (December 31, 2022 – $8.7 billion). This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.0 billion (December 31, 2022 – US$4.8 billion, or C$6.5 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2022 – $2.0 billion). The decrease in long-term debt was primarily due to the third quarter purchase of unsecured notes with an aggregate principal amount of US$1.0 billion at a discount of $84 million. As at December 31, 2023, we were in compliance with all of the terms of our debt agreements. Available Sources of Liquidity The following sources of liquidity are available as at December 31, 2023: ($ millions) Cash and Cash Equivalents Committed Credit Facility (1) Revolving Credit Facility – Tranche A Revolving Credit Facility – Tranche B Uncommitted Demand Facilities Cenovus Energy Inc. (2) WRB (3) (1) (2) November 10, 2026 November 10, 2025 n/a n/a n/a 2,227 3,700 1,800 1,071 119 Base Shelf Prospectus Financial Metrics details. No amounts were drawn on the committed credit facility as at December 31, 2023 (December 31, 2022 – $nil). Our uncommitted demand facilities include $1.7 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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no direct borrowings (December 31, 2022 – $nil). (3) Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2023, US$135 million (C$179 million) of this capacity was drawn (December 31, 2022 – US$85 million (C$115 million)). 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. On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements. 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 25 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 (loss) before finance costs, net of capitalized interest, interest income, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity- accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, revaluation (gain) loss, re- measurement of contingent payments, (gain) loss on divestiture of assets, and net other (income) loss calculated on a trailing twelve-month basis. These ratios are used to steward our overall debt position and are 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) December 31, 2023 December 31, 2022 15 0.6 0.5 13 0.4 0.3 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$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. Our Net Debt to Capitalization Ratio as at December 31, 2023, increased compared with December 31, 2022, primarily due to higher Net Debt. Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2023, increased compared with December 31, 2022, as a result of higher Net Debt and lower Operating Margin. See the Operating and Financial Results section of this MD&A for more information on Operating Margin and Net Debt. Maturity Amount Available Share Capital and Stock-Based Compensation Plans Our common shares and Cenovus Warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. As at December 31, 2023, there were approximately 1,871.9 million common shares outstanding (December 31, 2022 – 1,909.2 million common shares) and 36 million preferred shares outstanding (December 31, 2022 – 36 million preferred shares). Refer to Note 30 of the Consolidated Financial Statements for further details. On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares from November 9, 2023, to November 8, 2024. Common Shares Purchased and Cancelled Under NCIB (millions of common shares) Weighted Average Price per Common Share ($) Purchase of Common Shares Under NCIB ($ millions) 2023 43.6 24.32 (1,061) 2022 112.5 22.49 (2,530) From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million. As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the existing NCIB. As at December 31, 2023, there were approximately 7.6 million Cenovus Warrants outstanding (December 31, 2022 – 55.7 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 30 of the Consolidated Financial Statements for further details. On June 14, 2023, we purchased and cancelled 45.5 million outstanding Cenovus Warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. We also recorded $2 million of transaction costs. This purchase represented 84 percent of Cenovus’s outstanding warrants. The full warrant purchase obligation was paid by December 31, 2023. Refer to Note 32 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: Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 41 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis As at February 12, 2024 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 Units Outstanding (thousands) Units Exercisable (thousands) 1,867,826 7,614 10,740 1,260 10,000 8,000 6,000 12,852 19,230 n/a n/a n/a n/a n/a n/a n/a 7,615 1,772 42 CENOVUS ENERGY 2023 ANNUAL REPORT | 47 Common Share Dividends In 2023, we paid base dividends of $990 million or $0.525 per common share (2022 – $682 million or $0.350 per common share). No variable dividend was declared or paid in 2023. The Board declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common shareholders of record as at March 15, 2024. The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly. Cumulative Redeemable Preferred Share Dividends In 2023, dividends of $36 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2022 – $26 million). 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 April 1, 2024, to preferred shareholders of record as at March 15, 2024. Contractual Obligations and Commitments We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from the table below. Our total commitments were $28.8 billion as at December 31, 2023 (December 31, 2022 – $33.0 billion). Total commitments decreased from December 31, 2022, primarily due to the cancellation of the contract terms of certain product purchase contracts, combined with the use of contracts. The decrease was partially offset by increased tolls due to the Trans Mountain Pipeline Expansion and commitments acquired as part of the Toledo Acquisition. As at December 31, 2023, our total commitments included commitments with HMLP of $2.1 billion related to long-term transportation and storage commitments. As at December 31, 2023 ($ millions) Commitments Transportation and Storage (1) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments (2) Total Commitments Long-Term Debt (Principal and Interest) Decommissioning Liabilities Contingent Payment Lease Liabilities (Principal and Interest) (3) 2024 2025 2026 2027 2028 Thereafter Total 2,018 1,927 1,680 1,663 1,641 15,738 24,667 617 57 94 417 3,203 313 259 168 438 — 57 94 194 2,272 489 296 — 367 — 59 94 184 2,017 303 291 — 345 — 63 89 175 1,990 1,523 286 — 294 — 58 52 166 1,917 1,484 283 — 275 — 604 90 965 17,397 7,145 6,063 — 2,635 33,240 617 898 513 2,101 28,796 11,257 7,478 168 4,354 52,053 Total Commitments and Obligations 4,381 3,424 2,956 4,093 3,959 (1) (2) (3) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023. Lease contracts related to railcars, barges, vessels, pipelines, caverns, storage tanks, office space, our commercial fuels network and other refining and field equipment. As at December 31, 2023, outstanding letters of credit issued as security for performance under certain contracts totaled $364 million (2022 – $490 million). Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for $587 million. Legal Proceedings We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our Consolidated Financial Statements. Transactions with Related Parties Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs in accordance with our profit sharing agreement. 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, 2023, we charged HMLP $160 million for construction and management services (2022 – $188 million). Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 43 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 44 48 | CENOVUS ENERGY 2023 ANNUAL REPORT 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. Payments for access fees and transportation and storage services are made based on rates contractually agreed to with HMLP. For the year ended December 31, 2023, we incurred costs of $295 million for the use of HMLP’s pipeline systems, as well as for transportation and storage services (2022 – $263 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 The following discussion describes the financial, operational, regulatory, environmental, reputational, climate change related, 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. Risk Governance through regular updates. Risk Factors Financial Risk Commodity Prices Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and NGLs. Prices for crude oil, refined products, natural gas and NGLs are impacted by a number of factors, including, but not limited to: global and regional supply of and demand for these commodities; the ability of producers and governments to replace reduced supply; transportation restrictions; processing and export capacity; export restrictions; domestic and global economic conditions; inflation and changes to interest rates; increased tariffs; central bank policies; 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 and refilling of the U.S. Strategic Petroleum Reserves; developments related to the market for these commodities; inventory levels of these commodities; seasonal trends; refinery availability; planned and unplanned refinery maintenance; 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; political stability and social conditions in countries producing these commodities; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic, or war or other international or regional conflict and any related government action; the occurrence of natural disasters; and weather conditions. 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, the transition to a lower-carbon economy. Common Share Dividends In 2023, we paid base dividends of $990 million or $0.525 per common share (2022 – $682 million or $0.350 per common share). No variable dividend was declared or paid in 2023. The Board declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common shareholders of record as at March 15, 2024. The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly. Cumulative Redeemable Preferred Share Dividends record as at March 15, 2024. Contractual Obligations and Commitments In 2023, dividends of $36 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2022 – $26 million). 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 April 1, 2024, to preferred shareholders of We have obligations for goods and services entered into in the normal course of business. Obligations that have original maturities of less than one year are excluded from the table below. Our total commitments were $28.8 billion as at December 31, 2023 (December 31, 2022 – $33.0 billion). Total commitments decreased from December 31, 2022, primarily due to the cancellation of the contract terms of certain product purchase contracts, combined with the use of contracts. The decrease was partially offset by increased tolls due to the Trans Mountain Pipeline Expansion and commitments acquired as part of the Toledo Acquisition. As at December 31, 2023, our total commitments included commitments with HMLP of $2.1 billion related to long-term transportation and storage commitments. As at December 31, 2023 ($ millions) Commitments Transportation and Storage (1) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments (2) Total Commitments Long-Term Debt (Principal and Interest) Decommissioning Liabilities Contingent Payment Lease Liabilities (Principal and Interest) (3) (2) (3) equipment. $587 million. Legal Proceedings Consolidated Financial Statements. Transactions with Related Parties 2024 2025 2026 2027 2028 Thereafter Total 2,018 1,927 1,680 1,663 1,641 15,738 24,667 617 57 94 417 3,203 313 259 168 438 — 57 94 194 2,272 489 296 — 367 — 59 94 184 2,017 303 291 — 345 — 63 89 175 1,990 1,523 286 — 294 — 58 52 166 1,917 1,484 283 — 275 — 604 90 965 17,397 7,145 6,063 — 2,635 33,240 617 898 513 2,101 28,796 11,257 7,478 168 4,354 52,053 Total Commitments and Obligations 4,381 3,424 2,956 4,093 3,959 (1) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023. Lease contracts related to railcars, barges, vessels, pipelines, caverns, storage tanks, office space, our commercial fuels network and other refining and field As at December 31, 2023, outstanding letters of credit issued as security for performance under certain contracts totaled $364 million (2022 – $490 million). Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for 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 Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for which we recover shared service costs in accordance with our profit sharing agreement. 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, 2023, we charged HMLP $160 million for construction and management services (2022 – $188 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. Payments for access fees and transportation and storage services are made based on rates contractually agreed to with HMLP. For the year ended December 31, 2023, we incurred costs of $295 million for the use of HMLP’s pipeline systems, as well as for transportation and storage services (2022 – $263 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, climate change related, 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. Financial Risk Commodity Prices Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and NGLs. Prices for crude oil, refined products, natural gas and NGLs are impacted by a number of factors, including, but not limited to: global and regional supply of and demand for these commodities; the ability of producers and governments to replace reduced supply; transportation restrictions; processing and export capacity; export restrictions; domestic and global economic conditions; inflation and changes to interest rates; increased tariffs; central bank policies; 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 and refilling of the U.S. Strategic Petroleum Reserves; developments related to the market for these commodities; inventory levels of these commodities; seasonal trends; refinery availability; planned and unplanned refinery maintenance; 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; political stability and social conditions in countries producing these commodities; market access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a pandemic, or war or other international or regional conflict and any related government action; the occurrence of natural disasters; and weather conditions. 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, the transition to a lower-carbon economy. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 43 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 44 CENOVUS ENERGY 2023 ANNUAL REPORT | 49 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. 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. All these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. See “Foreign Exchange Rates” below. Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our ability to meet guidance targets, the value of our assets, our cash flows, the 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 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, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended period, 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. Risks Associated with Financial Risk Management Activities Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials, NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as fluctuations in foreign exchange rates and interest rates. We may also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil, natural gas, NGLs and refined products. These risk management 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 risk management instrument being poorly correlated to the change in the valuation of the underlying exposures; change in price of the underlying commodity or market value of the instrument; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction. These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial Statements. Impact of Financial Risk Management Activities Cenovus may employ various price alignment and volatility management strategies, including financial risk management contracts, to reduce volatility in future cash flows and improve cash flow stability. 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. (primarily WTI). price. • • • • • • • The discussion below 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 below are a reasonable measure of volatility. The impact of the below 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, 2023 Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges Sensitivity Range Increase Decrease 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). A sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate. For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements. Credit, Liquidity and Availability of Future Financing The future development of our business may be dependent on our ability to obtain additional capital, including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn 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. Capital markets are increasingly considering ESG matters, including those related to the transition to a lower carbon economy. Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event that stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is perceived that our GHG emissions reduction goals are insufficient or will not be achieved. 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 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 We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated favourable terms. repayment. 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 several 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 45 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 46 50 | CENOVUS ENERGY 2023 ANNUAL REPORT 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. 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. All these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars. See “Foreign Exchange Rates” below. Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our ability to meet guidance targets, the value of our assets, our cash flows, the 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 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, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended period, 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. Risks Associated with Financial Risk Management Activities Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials, NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as fluctuations in foreign exchange rates and interest rates. We may also use derivative instruments in various operational markets to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil, natural gas, NGLs and refined products. These risk management 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 risk management instrument being poorly correlated to the change in the valuation of the underlying exposures; change in price of the underlying commodity or market value of the instrument; lack of market liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction. These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change. For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional discussion on exposure of risks and the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial Statements. Impact of Financial Risk Management Activities Cenovus may employ various price alignment and volatility management strategies, including financial risk management contracts, to reduce volatility in future cash flows and improve cash flow stability. 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 discussion below 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 below are a reasonable measure of volatility. The impact of the below 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, 2023 Power Commodity Price Sensitivity Range ± C$20.00/MWh (1) Applied to Power Hedges Increase Decrease 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). A sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: • • • • • • • A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price (primarily WTI). A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential price. A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate. For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements. Credit, Liquidity and Availability of Future Financing The future development of our business may be dependent on our ability to obtain additional capital, including, but not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn 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. Capital markets are increasingly considering ESG matters, including those related to the transition to a lower carbon economy. Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event that stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is perceived that our GHG emissions reduction goals are insufficient or will not be achieved. 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 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. We are required to comply with various financial and operating covenants under our credit facility and the indentures governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated repayment. 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 several 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 45 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 46 CENOVUS ENERGY 2023 ANNUAL REPORT | 51 If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business arrangements terminated. Exposure to Counterparties In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other counterparties for the provision and sale of goods and services, in connection with our risk management 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 to 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. Foreign Exchange Rates Fluctuations in foreign exchange rates may affect our results, particularly the U.S./Canadian dollar and RMB/Canadian dollar exchange rates. Global prices for crude oil, refined products and natural gas are generally determined by reference to U.S. dollar benchmark prices. In addition, a significant portion of our long-term debt and interest expense is also denominated in U.S. dollars, while many of our operating and capital costs are 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 the U.S. dollar or the RMB will impact revenues and costs, as expressed in Canadian dollars. The Company periodically enters into foreign exchange 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. Interest Rates Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation and have increased in response to inflation. Changes in interest rates could increase our net interest rate exposure and affect how certain liabilities are recorded, both of which could negatively impact our cash flow and financial results. We are also 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. 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. Operational Risk Operational Considerations (Safety, Environment and Reliability) Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii) the 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; (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; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including carbon capture utilization and storage projects. 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; flooding; geologic activity arising from fracking or carbon capture utilization and storage projects; 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; accidents or damage caused by third parties or otherwise occurring in the operation of our business; 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, facilities, wells and projects; the breakdown or failure of operational and information technology and systems and processes, any compromise thereof or released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; failure to maintain adequate supplies of spare parts; 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; protests, blockades or other acts of activism; catastrophic events, including, but not limited to, war or other regional or international conflict, adverse sea conditions, vandalism or terrorism, extreme weather events, wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures. Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of the impact of physical climate risks, such as floods, wildfires, earthquakes, hurricanes, storms, extreme temperatures and other extreme weather events or natural disasters. For example, the frequency and severity of wildfires may result in the shutting in and bringing down of our producing assets and processing plants. In addition, 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. Severe weather conditions may result in an operational incident with the potential to result in spills, asset damage, and production or refining disruption. 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. If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG targets, including our GHG emissions reduction goals; impact our reputation; cause loss of life or personal injury; result in loss of or damage to equipment, property, operational and information technology and control systems and 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 our oil sands production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production. We maintain 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 we cannot guarantee 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 47 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 48 52 | CENOVUS ENERGY 2023 ANNUAL REPORT If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business Operational Risk Operational Considerations (Safety, Environment and Reliability) arrangements terminated. Exposure to Counterparties In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other counterparties for the provision and sale of goods and services, in connection with our risk management 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 to 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. Foreign Exchange Rates Fluctuations in foreign exchange rates may affect our results, particularly the U.S./Canadian dollar and RMB/Canadian dollar exchange rates. Global prices for crude oil, refined products and natural gas are generally determined by reference to U.S. dollar benchmark prices. In addition, a significant portion of our long-term debt and interest expense is also denominated in U.S. dollars, while many of our operating and capital costs are 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 the U.S. dollar or the RMB will impact revenues and costs, as expressed in Canadian dollars. The Company periodically enters into foreign exchange 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. Interest Rates Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation and have increased in response to inflation. Changes in interest rates could increase our net interest rate exposure and affect how certain liabilities are recorded, both of which could negatively impact our cash flow and financial results. We are also 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. 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. Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii) the 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; (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; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including carbon capture utilization and storage projects. 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; flooding; geologic activity arising from fracking or carbon capture utilization and storage projects; 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; accidents or damage caused by third parties or otherwise occurring in the operation of our business; 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, facilities, wells and projects; the breakdown or failure of operational and information technology and systems and processes, any compromise thereof or released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; failure to maintain adequate supplies of spare parts; 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; protests, blockades or other acts of activism; catastrophic events, including, but not limited to, war or other regional or international conflict, adverse sea conditions, vandalism or terrorism, extreme weather events, wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or industrial sites. Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures. Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of the impact of physical climate risks, such as floods, wildfires, earthquakes, hurricanes, storms, extreme temperatures and other extreme weather events or natural disasters. For example, the frequency and severity of wildfires may result in the shutting in and bringing down of our producing assets and processing plants. In addition, 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. Severe weather conditions may result in an operational incident with the potential to result in spills, asset damage, and production or refining disruption. 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. If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG targets, including our GHG emissions reduction goals; impact our reputation; cause loss of life or personal injury; result in loss of or damage to equipment, property, operational and information technology and control systems and 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 our oil sands production are largely fixed in the short-term and, as a result, operating costs per unit are largely dependent on levels of production. We maintain 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 we cannot guarantee 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 47 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 48 CENOVUS ENERGY 2023 ANNUAL REPORT | 53 Market Access Constraints and Transportation Restrictions Cost Management and Inflation Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine and truck networks, to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected production growth, upstream or refining operations and cash flows. 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 third-party pipeline projects for new or expanded capacity will be constructed or that such projects would provide sufficient transportation capacity. Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about pipeline spills, GHG emissions and the transition to a lower carbon economy. There is no certainty that rail, marine and truck 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, geopolitical factors, war, terrorism, or other international or regional conflict, 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. Development, operating and construction costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies, including those related to our GHG emissions reduction goals; 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; changing government or environmental policies; regulations and supply chain disruptions, including force majeure; and access to skilled labour and critical third-party services. In addition, if our 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 and other sources of funding. Continued inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls, 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. Technology, Information Systems and Data Privacy We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This includes on premise systems (such as networks, computer hardware and software), telecommunications systems, mobile applications, cloud services and other technology systems, networks, and services, including systems using artificial intelligence. Some systems and services are 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, infrastructure, and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war, regional or international conflict, or the geopolitical landscape. 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, preventing access to systems, among others. Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or other vendor technology systems and 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, business, financial, proprietary, personal or other sensitive information. The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s technology, information systems and data privacy related risks due to its potential for user misuse, biased decision-making or unauthorized exposure of Cenovus’s sensitive data. Cyber incidents, breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses, remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the decisions that may arise from same, including, laws related to data transfers, privacy and the protection of data, regulatory penalties or scrutiny, fines, 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. The regulation of technology is rapidly evolving across many of the jurisdictions in which we operate, creating a complex legal and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related tools, data transfers, artificial intelligence, data protection and privacy. These laws and regulations include obligations on companies that process personal information and provide additional rights of actions and remedies to individuals whose personal information is in the Company’s control. Failure to comply with these regulatory standards, including the misuse of or failure to secure personal information, could result in violation of data protection, artificial intelligence and privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition of severe fines and penalties by governmental authorities, damage to our reputation and credibility, and may have a negative impact on financial condition, results of operations and cash flows. Compliance with continuously evolving legislation may also result in increased operating costs. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 49 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 50 54 | CENOVUS ENERGY 2023 ANNUAL REPORT Market Access Constraints and Transportation Restrictions Cost Management and Inflation Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine and truck networks, to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected production growth, upstream or refining operations and cash flows. 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 third-party pipeline projects for new or expanded capacity will be constructed or that such projects would provide sufficient transportation capacity. Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about pipeline spills, GHG emissions and the transition to a lower carbon economy. There is no certainty that rail, marine and truck 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, geopolitical factors, war, terrorism, or other international or regional conflict, 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. Development, operating and construction costs are affected by a number of factors including, but not limited to: development, adoption and success of new technologies, including those related to our GHG emissions reduction goals; 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; changing government or environmental policies; regulations and supply chain disruptions, including force majeure; and access to skilled labour and critical third-party services. In addition, if our 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 and other sources of funding. Continued inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls, 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. Technology, Information Systems and Data Privacy We rely heavily on technology, including operating technology and information technology, to effectively operate our business. This includes on premise systems (such as networks, computer hardware and software), telecommunications systems, mobile applications, cloud services and other technology systems, networks, and services, including systems using artificial intelligence. Some systems and services are 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, infrastructure, and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war, regional or international conflict, or the geopolitical landscape. 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, preventing access to systems, among others. Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or other vendor technology systems and 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, business, financial, proprietary, personal or other sensitive information. The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s technology, information systems and data privacy related risks due to its potential for user misuse, biased decision-making or unauthorized exposure of Cenovus’s sensitive data. Cyber incidents, breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses, remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the decisions that may arise from same, including, laws related to data transfers, privacy and the protection of data, regulatory penalties or scrutiny, fines, 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. The regulation of technology is rapidly evolving across many of the jurisdictions in which we operate, creating a complex legal and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related tools, data transfers, artificial intelligence, data protection and privacy. These laws and regulations include obligations on companies that process personal information and provide additional rights of actions and remedies to individuals whose personal information is in the Company’s control. Failure to comply with these regulatory standards, including the misuse of or failure to secure personal information, could result in violation of data protection, artificial intelligence and privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition of severe fines and penalties by governmental authorities, damage to our reputation and credibility, and may have a negative impact on financial condition, results of operations and cash flows. Compliance with continuously evolving legislation may also result in increased operating costs. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 49 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 50 CENOVUS ENERGY 2023 ANNUAL REPORT | 55 Competition Governmental Policy The oil and gas industry is highly competitive in all aspects, including accessing capital, the exploration and 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. We may not be able to compete successfully against current and future competitors, and competitive pressures 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 growth and optimization projects across our global portfolio of assets. In addition, we have a number of other projects in various stages of planning and development, including projects related to our GHG emissions reduction goals. 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; our ability to access, implement and use operational and information technologies and data, including improvements thereto; 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 on a cost effective basis; our ability to identify or complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the impacts of oil and gas operations on the environment and associated with GHG emissions abatement initiatives. The commissioning and integration of new infrastructure and 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. Joint Ventures and Partnerships Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures. In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows and progress towards our GHG emissions reduction goals 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 and operation of various projects and assets, their management of operational issues and their reporting. Our partners may have objectives and interests that either 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 and projects 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, progress towards our GHG emissions reduction goals, reputation and cash flows. Existing and Emerging Technologies Current technologies used for the recovery of bitumen are 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. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals including our ESG targets and ambitions. 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. 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. Regulatory Risk The oil and gas industry in general and our operations in particular are subject to regulation and intervention under various levels of legislation in the countries in which we operate, seek to develop or explore in matters which include, but are not limited to: land tenure; permitting of 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; environmental plans and regulations; the reduction of GHG and other emissions; the export of crude oil, natural gas and other products; the transportation of crude oil, natural gas and other products by pipeline, rail, marine or truck transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding, acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any changes to applicable regulatory regimes, including the implementation of new regulations or enforcement initiatives, 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. 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 on acceptable conditions, or at all, all necessary licenses, permits, and other approvals required to conduct activities (including, without limitation, certain exploration, development and operating activities) related to our projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation, consensus seeking, collaboration or consent, 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. The failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis or satisfactory terms could result in increased costs, project delays, and may limit Cenovus’s ability to develop or expand proposed projects efficiently or at all. Abandonment and Reclamation 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 various levels of 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 the expected scope of 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, Saskatchewan and British Columbia, 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 regulators in these jurisdictions may seek additional funding for such liabilities from industry participants, including Cenovus. 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 may not be determinable due to the unknown timing and extent of corrective actions that may be required. The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 51 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 52 56 | CENOVUS ENERGY 2023 ANNUAL REPORT Competition Governmental Policy The oil and gas industry is highly competitive in all aspects, including accessing capital, the exploration and 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. We may not be able to compete successfully against current and future competitors, and competitive pressures 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 growth and optimization projects across our global portfolio of assets. In addition, we have a number of other projects in various stages of planning and development, including projects related to our GHG emissions reduction goals. 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; our ability to access, implement and use operational and information technologies and data, including improvements thereto; 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 on a cost effective basis; our ability to identify or complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the impacts of oil and gas operations on the environment and associated with GHG emissions abatement initiatives. The commissioning and integration of new infrastructure and 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. Joint Ventures and Partnerships Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures. In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows and progress towards our GHG emissions reduction goals 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 and operation of various projects and assets, their management of operational issues and their reporting. Our partners may have objectives and interests that either 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 and projects 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, progress towards our GHG emissions reduction goals, reputation and cash flows. Existing and Emerging Technologies Current technologies used for the recovery of bitumen are 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. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business goals including our ESG targets and ambitions. 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. 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. Regulatory Risk The oil and gas industry in general and our operations in particular are subject to regulation and intervention under various levels of legislation in the countries in which we operate, seek to develop or explore in matters which include, but are not limited to: land tenure; permitting of 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; environmental plans and regulations; the reduction of GHG and other emissions; the export of crude oil, natural gas and other products; the transportation of crude oil, natural gas and other products by pipeline, rail, marine or truck transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding, acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations; control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities; and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any changes to applicable regulatory regimes, including the implementation of new regulations or enforcement initiatives, 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. 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 on acceptable conditions, or at all, all necessary licenses, permits, and other approvals required to conduct activities (including, without limitation, certain exploration, development and operating activities) related to our projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder consultation, Indigenous consultation, consensus seeking, collaboration or consent, 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. The failure to obtain applicable regulatory approvals or satisfy any conditions on a timely basis or satisfactory terms could result in increased costs, project delays, and may limit Cenovus’s ability to develop or expand proposed projects efficiently or at all. Abandonment and Reclamation 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 various levels of 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 the expected scope of 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, Saskatchewan and British Columbia, 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 regulators in these jurisdictions may seek additional funding for such liabilities from industry participants, including Cenovus. 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 may not be determinable due to the unknown timing and extent of corrective actions that may be required. The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could materially and adversely affect, among other things, our business, financial condition, results of operations and cash flows. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 51 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 52 CENOVUS ENERGY 2023 ANNUAL REPORT | 57 Royalty Regimes Climate Change Regulations Our cash flows may be directly affected by changes to royalty and mineral tax 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 and mineral tax 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 and mineral tax 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. Indigenous Land and Rights Claims Opposition by Indigenous people to our Company, our operations, development or exploration, or disagreements between Indigenous communities, or between Indigenous peoples and governments, in the jurisdictions in which we conduct business may adversely impact our reputation, relationship with host governments, local communities and Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal, other regulatory and other advisory expenses, and our ability to explore, develop and continue to operate projects. In Canada, Indigenous and/or treaty rights held by Indigenous peoples are protected under the constitution. Impacts to these Indigenous and treaty rights must be considered, in particular in areas where Cenovus operates on Crown lands. In some cases, there may be 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. 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 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 result of which may affect the way governments are required to fulfill their duty to consult. 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, licenses and other approvals, or to meet the terms and conditions of those approvals. Indigenous rights or affect treaty rights and, In addition, the Canadian federal government and the British Columbia provincial government have passed legislation which requires such governments to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by government is ongoing and, in some instances, 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. Climate Change Related Risks to a transition lower-carbon economy. Governments, There is growing international concern regarding climate change and a significant increase in focus on the timing and pace of insurance companies, non- the governmental organizations (“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. institutions, financial 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 53 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 54 58 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 from the 2023 rate of $65/tonne. The 2024 rate is $80/tonne CO2e and took effect on January 1, 2024. 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 jurisdictions where provincial carbon pricing regulations apply to industry. In British Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan, and Newfoundland and Labrador, the provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal stringency requirements such that the federal backstop regulations do not apply. The federal government has committed to engaging provinces, territories, and Indigenous organizations in an interim review of the federal carbon tax benchmark by 2026. In December 2023, the Government of Canada announced plans to implement a national emissions cap-and-trade model under the Canadian Environmental Protection Act (“CEPA”). The proposal is to phase in the cap-and-trade system between 2026 and 2030 and have it apply to, among other things, all direct GHG emissions from liquified natural gas facilities and upstream oil and gas facilities, including offshore facilities, while also accounting for indirect emissions and emissions that are captured and permanently stored. It is currently proposed that the 2030 emissions cap (which will inform the number of emission allowances issued to regulated facilities) will be set at 35 percent to 38 percent below 2019 emission levels. Under the proposed regime, facilities that emit more than the allowances allocated would have some flexibility to compensate for a limited quantity of additional emissions, up to the level of the legal upper bound, which, for 2030, is proposed to be set at 20 percent to 23 percent below 2019 emission levels. The Government of Canada has committed to regularly reviewing the emissions cap trajectory, the emissions trading market, and access to compliance flexibilities in setting the allowance level and legal upper bound for the post-2030 period with a view to its long-term objective of achieving net-zero GHG emissions in the oil and gas sector by 2050. Draft regulations for the cap-and-trade system are scheduled to be released for comment in mid-2024. The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025 through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas destruction equipment and fugitive emissions, and would come into force between 2027 and 2030. Finalized amendments to the Methane Regulation are expected in late 2024. 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. The U.S. has 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; shift away from fossil fuel-based energy; 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, shutting in production and the suspension of operations. Royalty Regimes Climate Change Regulations Our cash flows may be directly affected by changes to royalty and mineral tax 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 and mineral tax 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 and mineral tax 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. Indigenous Land and Rights Claims Opposition by Indigenous people to our Company, our operations, development or exploration, or disagreements between Indigenous communities, or between Indigenous peoples and governments, in the jurisdictions in which we conduct business may adversely impact our reputation, relationship with host governments, local communities and other Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal, regulatory and other advisory expenses, and our ability to explore, develop and continue to operate projects. In Canada, Indigenous and/or treaty rights held by Indigenous peoples are protected under the constitution. Impacts to these Indigenous and treaty rights must be considered, in particular in areas where Cenovus operates on Crown lands. In some cases, there may be 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. 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 result of which may affect the way governments are required to fulfill their duty to consult. 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, licenses and other approvals, or to meet the terms and conditions of those approvals. In addition, the Canadian federal government and the British Columbia provincial government have passed legislation which requires such governments to take all necessary measures to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by government is ongoing and, in some instances, 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. Climate Change 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, non- governmental organizations (“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. 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 from the 2023 rate of $65/tonne. The 2024 rate is $80/tonne CO2e and took effect on January 1, 2024. 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 jurisdictions where provincial carbon pricing regulations apply to industry. In British Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan, and Newfoundland and Labrador, the provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal stringency requirements such that the federal backstop regulations do not apply. The federal government has committed to engaging provinces, territories, and Indigenous organizations in an interim review of the federal carbon tax benchmark by 2026. In December 2023, the Government of Canada announced plans to implement a national emissions cap-and-trade model under the Canadian Environmental Protection Act (“CEPA”). The proposal is to phase in the cap-and-trade system between 2026 and 2030 and have it apply to, among other things, all direct GHG emissions from liquified natural gas facilities and upstream oil and gas facilities, including offshore facilities, while also accounting for indirect emissions and emissions that are captured and permanently stored. It is currently proposed that the 2030 emissions cap (which will inform the number of emission allowances issued to regulated facilities) will be set at 35 percent to 38 percent below 2019 emission levels. Under the proposed regime, facilities that emit more than the allowances allocated would have some flexibility to compensate for a limited quantity of additional emissions, up to the level of the legal upper bound, which, for 2030, is proposed to be set at 20 percent to 23 percent below 2019 emission levels. The Government of Canada has committed to regularly reviewing the emissions cap trajectory, the emissions trading market, and access to compliance flexibilities in setting the allowance level and legal upper bound for the post-2030 period with a view to its long-term objective of achieving net-zero GHG emissions in the oil and gas sector by 2050. Draft regulations for the cap-and-trade system are scheduled to be released for comment in mid-2024. The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025 through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas destruction equipment and fugitive emissions, and would come into force between 2027 and 2030. Finalized amendments to the Methane Regulation are expected in late 2024. 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. The U.S. has 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; shift away from fossil fuel-based energy; 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, shutting in production and the suspension of operations. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 53 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 54 CENOVUS ENERGY 2023 ANNUAL REPORT | 59 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. Clean Fuel Regulations In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene, and light and heavy fuel oils (“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. Starting in 2022, each Primary Supplier must reduce the carbon intensity by the prescribed amount. In 2024, that amount is 90.0 gCO2e/MJ for gasoline fuels and 88.0 gCO2e/MJ for diesel fuels. These regulations could result in the negative consequences noted above under “Climate Change Regulations”, including increased compliance costs, increased operating, and capital expenditures. 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 compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations have the potential to impact our business, financial condition, results of operations and cash flows. Renewable Fuel Standards Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into transportation fuel, or by purchasing RINs from other parties on the open market. 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 blend stocks, and the costs to obtain the necessary RINs and blend stocks 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 blend stocks to comply with the RFS mandated standards. Clean Electricity Regulations Security and Terrorist Threats In August 2023, the Government of Canada released draft Clean Electricity Regulations intended to accelerate progress towards a near-zero power generation sector in Canada. The draft regulations would impose a stringent performance standard on all power generation facilities on the latter of January 1, 2035 or 20 years after their commissioning date. Limited exemptions for peaking units and emergency circumstances are available under the proposed regulations, but natural gas-fired facilities will be required to convert to near-zero emissions hydrogen or install carbon capture and coal-fired units will no longer be able to legally operate. The extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time. 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. Climate Scenarios and Assumptions We integrate the potential impact of climate change and 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 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. Labour Relations We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour disputes, which could disrupt operations at such facilities. As of December 31, 2023, approximately 11 percent of our employees are represented by unions under collective bargaining agreements, which includes just over 44 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. In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve 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, future unionization efforts of Cenovus’s non-represented workforce 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 have a material adverse effect on our safety and reliability performance, results of operations and cash flows and may limit our operational flexibility. Leadership and Talent 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 behaviors and leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations, reputation, and our ability to meet our leadership related ESG targets. Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could result in 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 or terrorist attack 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. International Developments and Geopolitical Risk We are exposed to the financial and operational risks associated with uncertain international and regional 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 55 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 56 60 | CENOVUS ENERGY 2023 ANNUAL REPORT 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. Clean Fuel Regulations In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene, and light and heavy fuel oils (“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. Starting in 2022, each Primary Supplier must reduce the carbon intensity by the prescribed amount. In 2024, that amount is 90.0 gCO2e/MJ for gasoline fuels and 88.0 gCO2e/MJ for diesel fuels. These regulations could result in the negative consequences noted above under “Climate Change Regulations”, including increased compliance costs, increased operating, and capital expenditures. 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 compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations have the potential to impact our business, financial condition, results of operations and cash flows. Renewable Fuel Standards Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into transportation fuel, or by purchasing RINs from other parties on the open market. 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 blend stocks, and the costs to obtain the necessary RINs and blend stocks 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 blend stocks to comply with the RFS mandated standards. Clean Electricity Regulations In August 2023, the Government of Canada released draft Clean Electricity Regulations intended to accelerate progress towards a near-zero power generation sector in Canada. The draft regulations would impose a stringent performance standard on all power generation facilities on the latter of January 1, 2035 or 20 years after their commissioning date. Limited exemptions for peaking units and emergency circumstances are available under the proposed regulations, but natural gas-fired facilities will be required to convert to near-zero emissions hydrogen or install carbon capture and coal-fired units will no longer be able to legally operate. The extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time. 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. Climate Scenarios and Assumptions We integrate the potential impact of climate change and 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 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. Labour Relations We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour disputes, which could disrupt operations at such facilities. As of December 31, 2023, approximately 11 percent of our employees are represented by unions under collective bargaining agreements, which includes just over 44 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. In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve 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, future unionization efforts of Cenovus’s non-represented workforce 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 have a material adverse effect on our safety and reliability performance, results of operations and cash flows and may limit our operational flexibility. Leadership and Talent 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 behaviors and leadership, professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations, reputation, and our ability to meet our leadership related ESG targets. Security and Terrorist Threats Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could result in 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 or terrorist attack 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. International Developments and Geopolitical Risk We are exposed to the financial and operational risks associated with uncertain international and regional 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 55 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 56 CENOVUS ENERGY 2023 ANNUAL REPORT | 61 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’ approaches 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 have 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 which 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. 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. Litigation and Claims From time to time, we may be involved in demands, disputes, regulatory investigations or 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 those related to health and safety, climate change, 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, human rights, labour relations, personal injury and other claims. 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. 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. We may 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 substantial expenses and devote significant resources in respect of any such Claims. In addition, any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows. Environmental Plans and Regulations Risks All phases of our operations are subject to environmental regulation, oversight and enforcement 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”). Land management plans may be prepared in jurisdictions in which we operate, these may be legally binding and have the same effect as regulations. Environmental plans and regulations provide that exploration areas, wells, facility sites, pipelines, 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. Land management plans may limit future resource access, and failure to comply with approved plans may result in litigation or government intervention. Third party NGOs and citizen activist groups can also directly influence environmental regulations in the jurisdictions in which we operate, including the U.S. and Canada. 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 plans and 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, legal or regulatory proceedings, and could adversely affect our reputation. The costs of complying with environmental plans and 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 57 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 58 62 | CENOVUS ENERGY 2023 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’ approaches 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 have 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 which 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. 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. Litigation and Claims From time to time, we may be involved in demands, disputes, regulatory investigations or 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 those related to health and safety, climate change, 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, human rights, labour relations, personal injury and other claims. 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. 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. We may 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 substantial expenses and devote significant resources in respect of any such Claims. In addition, any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and cash flows. Environmental Plans and Regulations Risks All phases of our operations are subject to environmental regulation, oversight and enforcement 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”). Land management plans may be prepared in jurisdictions in which we operate, these may be legally binding and have the same effect as regulations. Environmental plans and regulations provide that exploration areas, wells, facility sites, pipelines, 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. Land management plans may limit future resource access, and failure to comply with approved plans may result in litigation or government intervention. Third party NGOs and citizen activist groups can also directly influence environmental regulations in the jurisdictions in which we operate, including the U.S. and Canada. 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 plans and 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, legal or regulatory proceedings, and could adversely affect our reputation. The costs of complying with environmental plans and 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 57 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 58 CENOVUS ENERGY 2023 ANNUAL REPORT | 63 Canadian Species at Risk Act Cenovus ESG Focus Areas, Targets and Ambitions The Canadian federal Species at Risk Act and associated agreements, 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. Previous petitions and litigation against the federal government in relation to the 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, and these petitions compelled governments to enter into binding conservation and recovery agreements. 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 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 or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in which we operate, seek development or explore may create risk of increased costs and project development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving 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 such regulatory frameworks on project development and operations cannot be estimated at this time. Water Regulation We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including through water licences. If water use fees increase, the terms of water licences change or there are restrictions 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 licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted, or 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. Hydraulic Fracturing Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. 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, restrictions to freshwater usage, 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. We have set ambitious, achievable targets for each of our five ESG focus areas, 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 benefits of 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. 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 than we expect or may not occur within the anticipated time periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our business, which could have a negative impact on our future operating and financial results. Climate and GHG Emissions Reduction Goals Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in implementing such goals 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, and the cooperation and actions of third parties, including Pathways Alliance. The Pathways Alliance’s proposed CCS project is of particular importance, and if this project is delayed or does not proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved. 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. 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. If we are unable to effectively deploy the necessary technology, or such strategies or technologies do not perform as expected, we may be unable to meet our GHG emissions reduction goals on the planned timelines, or at all. In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emissions reduction goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification initiatives in our Conventional and Conventional Heavy Oil segments; 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; 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 GHG emissions reduction goals on the planned timelines, or at all. In addition, achieving our GHG emissions reduction goals relies on the existence of a favorable and stable regulatory framework that includes, among other things, support from various levels of government, including financial support and shared capital cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our 2035 GHG emissions reduction goals will also 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 resulting 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 meet our water stewardship targets 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 deploy the necessary technologies, or such strategies or technologies do not perform as expected, achieving our stated target of reducing our freshwater intensity could be interrupted, delayed or abandoned. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 59 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 60 64 | CENOVUS ENERGY 2023 ANNUAL REPORT Canadian Species at Risk Act Cenovus ESG Focus Areas, Targets and Ambitions The Canadian federal Species at Risk Act and associated agreements, 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. Previous petitions and litigation against the federal government in relation to the 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, and these petitions compelled governments to enter into binding conservation and recovery agreements. 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 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 or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in which we operate, seek development or explore may create risk of increased costs and project development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving 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 such regulatory frameworks on project development and operations cannot be estimated at this time. Water Regulation We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including through water licences. If water use fees increase, the terms of water licences change or there are restrictions 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 licences. There is no assurance that if we require new licences or amendments to existing licences, that these licences or amendments will be granted, or 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. Hydraulic Fracturing Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. 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, restrictions to freshwater usage, 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. We have set ambitious, achievable targets for each of our five ESG focus areas, 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 benefits of 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. 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 than we expect or may not occur within the anticipated time periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our business, which could have a negative impact on our future operating and financial results. Climate and GHG Emissions Reduction Goals Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in implementing such goals 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, and the cooperation and actions of third parties, including Pathways Alliance. The Pathways Alliance’s proposed CCS project is of particular importance, and if this project is delayed or does not proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved. 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. 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. If we are unable to effectively deploy the necessary technology, or such strategies or technologies do not perform as expected, we may be unable to meet our GHG emissions reduction goals on the planned timelines, or at all. In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emissions reduction goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification initiatives in our Conventional and Conventional Heavy Oil segments; 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; 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 GHG emissions reduction goals on the planned timelines, or at all. In addition, achieving our GHG emissions reduction goals relies on the existence of a favorable and stable regulatory framework that includes, among other things, support from various levels of government, including financial support and shared capital cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our 2035 GHG emissions reduction goals will also 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 resulting 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 meet our water stewardship targets 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 deploy the necessary technologies, or such strategies or technologies do not perform as expected, achieving our stated target of reducing our freshwater intensity could be interrupted, delayed or abandoned. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 59 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 60 CENOVUS ENERGY 2023 ANNUAL REPORT | 65 Biodiversity Targets Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See “Abandonment and Reclamation” 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 A failure or delay in: (i) achieving our Indigenous reconciliation targets; or (ii) continuing to advance Indigenous reconciliation initiatives once targets have been met, may adversely affect our relationship with neighboring Indigenous businesses and communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate projects in line with our current business and operational strategies may be adversely impacted. Inclusion and Diversity Targets A failure or delay in achieving our inclusion and diversity targets and our ability to maintain targets once met, could have a material adverse effect on our recruitment activities and reputation with our stakeholders. 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. 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. Shareholder activism has been increasing in the oil and gas 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, Management 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. 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, including equity awards granted to our directors and officers, 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. Risks Relating to Acquisitions and Dispositions We have completed, and may complete in the future, one or more acquisitions or dispositions for various strategic reasons. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. The integration of acquired assets and operations may result in the disruption of business, and may divert Management’s focus and resources from other strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition. Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material. Should any of the risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial condition or reputation. Risks Related to Significant Shareholders of Cenovus The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments"), or market perception regarding any intention of Hutchison or L.F. Investments 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 impact the value of the Cenovus Warrants. Tax Laws 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 similar factors as those impacting the market price of Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects us, our financial results, our ability to achieve our GHG emissions reduction goals 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. Further, as there are usually a number of tax matters under review, income taxes are subject to measurement uncertainty. 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 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. Pandemic Risk Pandemics, epidemics or outbreaks, including COVID-19, remain a risk for the Company, and the ultimate impact of a pandemic is highly uncertain and subject to change. A 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. Actions taken by various levels of government and health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of, commodities that are closely linked to our financial performance and may negatively impact our business, results of operations and financial condition. Modern Slavery Act On January 1, 2024, the Fighting Against Forced Labour and Child Labour in Supply Chains Act (“Modern Slavery Act”)came into force in Canada. The Modern Slavery Act obligates Cenovus to publish an annual modern slavery report detailing steps regarding the previous year’s efforts to mitigate the risk of forced labour used at any step in their supply chain, including production of goods in Canada or elsewhere or of goods imported into Canada. There is a risk that our supply chain may actually use or be alleged to have used forced labour or child labour, and there may be difficulty in gathering sufficient information from suppliers. Additional work is required to assess and understand this risk. Such measures may affect our operational efficiency, results of operations, financial condition, or reputation. 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 sedarplus.ca, on EDGAR at sec.gov and at cenovus.com. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 61 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 62 66 | CENOVUS ENERGY 2023 ANNUAL REPORT Biodiversity Targets Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See “Abandonment and Reclamation” 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 A failure or delay in: (i) achieving our Indigenous reconciliation targets; or (ii) continuing to advance Indigenous reconciliation initiatives once targets have been met, may adversely affect our relationship with neighboring Indigenous businesses and communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our operations, our progress and ability to develop and operate projects in line with our current business and operational strategies may be adversely impacted. Inclusion and Diversity Targets Reputation Risk operations. A failure or delay in achieving our inclusion and diversity targets and our ability to maintain targets once met, could have a material adverse effect on our recruitment activities and reputation with our stakeholders. 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 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. Shareholder activism has been increasing in the oil and gas 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, Management 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. 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, including equity awards granted to our directors and officers, 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. Risks Relating to Acquisitions and Dispositions We have completed, and may complete in the future, one or more acquisitions or dispositions for various strategic reasons. We may not be able to complete these transactions on favorable terms, on a timely basis, or at all. The integration of acquired assets and operations may result in the disruption of business, and may divert Management’s focus and resources from other strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition. Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material. Should any of the risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial condition or reputation. Risks Related to Significant Shareholders of Cenovus The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments"), or market perception regarding any intention of Hutchison or L.F. Investments 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 similar factors as those impacting the market price of Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively impact the value of the Cenovus Warrants. Tax Laws Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects us, our financial results, our ability to achieve our GHG emissions reduction goals 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. Further, as there are usually a number of tax matters under review, income taxes are subject to measurement uncertainty. 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 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. Pandemic Risk Pandemics, epidemics or outbreaks, including COVID-19, remain a risk for the Company, and the ultimate impact of a pandemic is highly uncertain and subject to change. A 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. Actions taken by various levels of government and health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of, commodities that are closely linked to our financial performance and may negatively impact our business, results of operations and financial condition. Modern Slavery Act On January 1, 2024, the Fighting Against Forced Labour and Child Labour in Supply Chains Act (“Modern Slavery Act”)came into force in Canada. The Modern Slavery Act obligates Cenovus to publish an annual modern slavery report detailing steps regarding the previous year’s efforts to mitigate the risk of forced labour used at any step in their supply chain, including production of goods in Canada or elsewhere or of goods imported into Canada. There is a risk that our supply chain may actually use or be alleged to have used forced labour or child labour, and there may be difficulty in gathering sufficient information from suppliers. Additional work is required to assess and understand this risk. Such measures may affect our operational efficiency, results of operations, financial condition, or reputation. 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 sedarplus.ca, on EDGAR at sec.gov and at cenovus.com. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 61 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 62 CENOVUS ENERGY 2023 ANNUAL REPORT | 67 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 material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements. Critical Judgments in Applying Accounting Policies Assessment of Impairment Indicators or Impairment Reversals 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 WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC, which was jointly controlled with bp and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls the Toledo Refinery through Ohio Refining Company LLC, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, the Ohio Refining Company LLC was consolidated. 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. 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, and, accordingly, SOSP was consolidated. In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future development of WRB, 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. Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles. As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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. In each arrangement, output is taken by the partners, indicating that the partners have the 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. 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. 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. 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. The identification of indicators of impairment or reversal of impairment requires significant judgment. 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 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 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 market 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. 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. 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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated 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 quantity of reserves, expected production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount rates. 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 63 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 64 68 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial Statements. Critical Judgments in Applying Accounting Policies Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements. Joint Arrangements judgment. The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires Cenovus has a 50 percent interest in WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC, which was jointly controlled with bp and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls the Toledo Refinery through Ohio Refining Company LLC, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, the Ohio Refining Company LLC was consolidated. 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. 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, and, accordingly, SOSP was consolidated. In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes • • payable and loans. facility. • WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt • Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles. • As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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. • In each arrangement, output is taken by the partners, indicating that the partners have the 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. 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. Assessment of Impairment Indicators or Impairment Reversals 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. 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. The identification of indicators of impairment or reversal of impairment requires significant judgment. 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 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 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 market 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. 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. 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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated 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 quantity of reserves, expected production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount rates. 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 63 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 64 CENOVUS ENERGY 2023 ANNUAL REPORT | 69 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, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. Income Tax Provisions The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. 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, 2024, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2023. 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 ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2023. 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, 2023. The effectiveness of our ICFR was audited as at December 31, 2023 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, 2023. 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 Inc. – 2023 Management's Discussion and Analysis 65 70 | CENOVUS ENERGY 2023 ANNUAL REPORT 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, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. Income Tax Provisions The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. 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, 2024, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2023. 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 ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2023. 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, 2023. The effectiveness of our ICFR was audited as at December 31, 2023 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, 2023. 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 Inc. – 2023 Management's Discussion and Analysis 65 CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2023 (Canadian Dollars) REPORT OF MANAGEMENT REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) 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 3. SUMMARY OF ACCOUNTING POLICIES 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY 5. ACQUISITIONS 6. GENERAL AND ADMINISTRATIVE 7. FINANCE COSTS 72 73 76 77 78 79 80 81 81 87 87 96 99 101 101 8. INTEGRATION, TRANSACTION AND OTHER COSTS 101 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 102 102 102 105 105 108 15. CASH AND CASH EQUIVALENTS 109 16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES 109 17. INVENTORIES 18. EXPLORATION AND EVALUATION ASSETS, NET 19. PROPERTY, PLANT AND EQUIPMENT, NET 20. LEASES 21. JOINT ARRANGEMENTS 22. OTHER ASSETS 23. GOODWILL 24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES 25. DEBT AND CAPITAL STRUCTURE 26. CONTINGENT PAYMENTS 27. DECOMMISSIONING LIABILITIES 28. OTHER LIABILITIES 29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS 30. SHARE CAPITAL AND WARRANTS 31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) 32. STOCK-BASED COMPENSATION PLANS 33. EMPLOYEE SALARIES AND BENEFIT EXPENSES 34. RELATED PARTY TRANSACTIONS 35. FINANCIAL INSTRUMENTS 36. RISK MANAGEMENT 37. SUPPLEMENTARY CASH FLOW INFORMATION 38. COMMITMENTS AND CONTINGENCIES 39. PRIOR PERIOD REVISIONS 109 110 111 112 113 114 115 115 115 119 119 120 120 123 125 126 129 129 129 132 135 137 137 CENOVUS ENERGY 2023 ANNUAL REPORT | 71 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 four 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 meets 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, 2023. 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 their evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2023. 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, 2023, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2024. PricewaterhouseCoopers LLP has provided such opinions. /s/ Jonathan M. McKenzie Jonathan M. McKenzie President & Chief Executive Officer Cenovus Energy Inc. February 14, 2024 /s/ Karamjit S. Sandhar Karamjit S. Sandhar Executive Vice-President & Chief Financial Officer Cenovus Energy Inc. 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, 2023 and 2022, and the related consolidated statements of earnings (loss), comprehensive income (loss), equity and cash flows for the years then ended, 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, 2023, 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, 2023 and 2022, and its financial performance and its cash flows for the years then ended in conformity with IFRS Accounting 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, 2023, 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 Inc. – 2023 Consolidated Financial Statements 3 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 4 72 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 four 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 meets 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, 2023. 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 their evaluation, Management has concluded that internal control over financial reporting was effective as at December 31, 2023. 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, 2023, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2024. PricewaterhouseCoopers LLP has provided such opinions. /s/ Jonathan M. McKenzie Jonathan M. McKenzie President & Chief Executive Officer Cenovus Energy Inc. February 14, 2024 /s/ Karamjit S. Sandhar Karamjit S. Sandhar 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, 2023 and 2022, and the related consolidated statements of earnings (loss), comprehensive income (loss), equity and cash flows for the years then ended, 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, 2023, 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, 2023 and 2022, and its financial performance and its cash flows for the years then ended in conformity with IFRS Accounting 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, 2023, 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 Inc. – 2023 Consolidated Financial Statements 3 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 4 CENOVUS ENERGY 2023 ANNUAL REPORT | 73 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 matter communicated below is a matter arising from the current period audit of the Consolidated Financial Statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the Oil Sands and Offshore Segments As described in Notes 1, 3, 4, 11 and 19 to the Consolidated Financial Statements, Management assesses its cash-generating units (CGUs) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated depreciation, depletion and amortization (DD&A) and net impairment losses, may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method based on estimated proved reserves. 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 those proved or proved plus probable reserves. As of December 31, 2023, the Company had $24.4 billion and $2.8 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.5 billion of DD&A expense and noted no indicators of impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2023. Estimating reserves requires the use of significant assumptions and judgments by Management related to expected future production volumes, future development and operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for 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 on PP&E, net, within 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 (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to expected future production volumes, future development and operating expenses, as well as forward commodity prices. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimates of reserves and 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 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 estimates of reserves; (iii) assessing the reasonability of the significant assumptions related to expected future production volumes, future development and operating expenses, as well as forward commodity prices, 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 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 expected future production volumes, future development and operating expenses, as well as forward commodity prices 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. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 14, 2024 We have served as the Company’s auditor since 2008. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 5 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 6 74 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 matter communicated below is a matter arising from the current period audit of the Consolidated Financial Statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the Oil Sands and Offshore Segments As described in Notes 1, 3, 4, 11 and 19 to the Consolidated Financial Statements, Management assesses its cash-generating units (CGUs) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of a CGU, which is net of accumulated depreciation, depletion and amortization (DD&A) and net impairment losses, may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method based on estimated proved reserves. 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 those proved or proved plus probable reserves. As of December 31, 2023, the Company had $24.4 billion and $2.8 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company recognized $3.5 billion of DD&A expense and noted no indicators of impairment related to PP&E in the Oil Sands and Offshore segments in the year ended December 31, 2023. Estimating reserves requires the use of significant assumptions and judgments by Management related to expected future production volumes, future development and operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for 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 on PP&E, net, within 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 (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to expected future production volumes, future development and operating expenses, as well as forward commodity prices. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to Management’s estimates of reserves and 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 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 estimates of reserves; (iii) assessing the reasonability of the significant assumptions related to expected future production volumes, future development and operating expenses, as well as forward commodity prices, 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 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 expected future production volumes, future development and operating expenses, as well as forward commodity prices 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. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Alberta, Canada February 14, 2024 We have served as the Company’s auditor since 2008. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 5 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 6 CENOVUS ENERGY 2023 ANNUAL REPORT | 75 CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 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 the Consolidated Financial Statements. Notes 31 29 35 2023 4,109 (44) 56 (274) (262) 3,847 2022 6,450 71 2 713 786 7,236 For the years ended December 31, ($ millions, except per share amounts) Revenues Gross Sales Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating (1) (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, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss 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 ($) Basic Diluted (1) Comparative periods reflect certain revisions. See Note 39. See accompanying Notes to the Consolidated Financial Statements. Notes 2023 2022 1 1 35 11,19,20,22 18 21 6 7 8 9 5 26 10 12 13 14 55,474 3,270 52,204 24,715 10,141 6,352 61 4,644 42 (51) 688 671 (133) 85 (67) 34 59 (14) (63) 5,040 931 4,109 2.15 2.12 71,765 4,868 66,897 33,958 11,126 5,816 1,636 4,679 101 (15) 865 820 (81) 106 343 (549) 162 (269) (532) 8,731 2,281 6,450 3.29 3.20 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 7 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 8 76 | CENOVUS ENERGY 2023 ANNUAL REPORT CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) For the years ended December 31, ($ 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 the Consolidated Financial Statements. Notes 31 29 35 2023 4,109 (44) 56 (274) (262) 3,847 2022 6,450 71 2 713 786 7,236 For the years ended December 31, ($ millions, except per share amounts) Revenues Gross Sales Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating (1) (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, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss 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 ($) Basic Diluted (1) Comparative periods reflect certain revisions. See Note 39. See accompanying Notes to the Consolidated Financial Statements. Notes 2023 2022 11,19,20,22 1 1 35 18 21 6 7 8 9 5 26 10 12 13 14 55,474 3,270 52,204 24,715 10,141 6,352 61 4,644 (133) 42 (51) 688 671 85 (67) 34 59 (14) (63) 5,040 931 4,109 2.15 2.12 71,765 4,868 66,897 33,958 11,126 5,816 1,636 4,679 101 (15) 865 820 (81) 106 343 (549) 162 (269) (532) 8,731 2,281 6,450 3.29 3.20 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 7 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 8 CENOVUS ENERGY 2023 ANNUAL REPORT | 77 CONSOLIDATED BALANCE SHEETS As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories 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 Income Tax Payable Short-Term Borrowings Lease Liabilities Contingent Payments 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 the Consolidated Financial Statements. /s/ Alexander J. Pourbaix Alexander J. Pourbaix Director Cenovus Energy Inc. February 14, 2024 /s/ Jane E. Kinney Jane E. Kinney Director Cenovus Energy Inc. Notes 2023 2022 2,227 3,035 416 4,030 9,708 211 738 37,250 1,680 25 366 318 696 2,923 53,915 5,480 88 179 299 164 6,210 7,108 2,359 — 4,155 1,183 4,188 25,203 28,698 14 53,915 4,524 3,473 121 4,312 12,430 209 685 36,499 1,845 25 365 342 546 2,923 55,869 6,124 1,211 115 308 263 8,021 8,691 2,528 156 3,559 1,042 4,283 28,280 27,576 13 55,869 15 16 17 27 1,18 1,19 1,20 21 22 13 1,23 24 25 20 26 25 20 26 27 28 13 38 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 9 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 78 | CENOVUS ENERGY 2023 ANNUAL REPORT CONSOLIDATED STATEMENTS OF EQUITY ($ millions) Shareholders’ Equity Common Preferred Shares Shares Warrants (Note 30) (Note 30) (Note 30) Paid in Surplus Retained Earnings AOCI (1) (Note 31) Non- Controlling Interest Total As at December 31, 2021 Net Earnings (Loss) 17,016 519 — 215 — 4,284 Other Comprehensive Income (Loss), Net of Tax Total Comprehensive Income (Loss) Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIB (2) 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 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 NCIB (2) Warrants Exercised Warrants Purchased and Cancelled Stock-Based Compensation Expense Base Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest As at December 31, 2023 170 (959) 93 — — — — — — — — — — — 58 26 — — — — — (373) (32) (1,571) — — — — 10 — — — — — — — — — 11 — — — (12) (688) (31) — — — — — — — — — — — — — (8) — — — — 25 (151) 878 6,450 — 6,450 — — — — (682) (219) (35) — 6,392 4,109 — 4,109 — — — (562) — (990) (36) — 8,913 684 — 786 786 — — — — — — — — — — — — — — — — — 1,470 (262) (262) 23,596 6,450 786 7,236 138 (2,530) 62 10 (682) (219) (35) — 27,576 4,109 (262) 3,847 46 (1,061) 18 (713) 11 (990) (36) — — — — — — — — — — — — — — — — — — — — — 16,320 519 — 184 — 2,691 16,031 519 2,002 1,208 28,698 (1) (2) Accumulated other comprehensive income (loss) (“AOCI”). Normal course issuer bid (“NCIB”). See accompanying Notes to the Consolidated Financial Statements. 12 — — — — — — — — — — 1 13 — — — — — — — — — — 1 14 10 CONSOLIDATED BALANCE SHEETS As at December 31, ($ millions) Assets Current Assets Cash and Cash Equivalents Accounts Receivable and Accrued Revenues Income Tax Receivable Inventories 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 Other Assets Deferred Income Taxes Goodwill Total Assets Liabilities and Equity Current Liabilities Income Tax Payable Short-Term Borrowings Lease Liabilities Contingent Payments 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/ Alexander J. Pourbaix Alexander J. Pourbaix Director Cenovus Energy Inc. February 14, 2024 Commitments and Contingencies See accompanying Notes to the Consolidated Financial Statements. /s/ Jane E. Kinney Jane E. Kinney Director Cenovus Energy Inc. Notes 2023 2022 2,227 3,035 416 4,030 9,708 211 738 37,250 1,680 25 366 318 696 2,923 53,915 5,480 88 179 299 164 6,210 7,108 2,359 — 4,155 1,183 4,188 25,203 28,698 14 53,915 4,524 3,473 121 4,312 12,430 209 685 36,499 1,845 25 365 342 546 2,923 55,869 6,124 1,211 115 308 263 8,021 8,691 2,528 156 3,559 1,042 4,283 28,280 27,576 13 55,869 15 16 17 27 1,18 1,19 1,20 21 22 13 1,23 24 25 20 26 25 20 26 27 28 13 38 CONSOLIDATED STATEMENTS OF EQUITY ($ millions) Shareholders’ Equity Common Shares (Note 30) Preferred Shares Warrants (Note 30) (Note 30) Paid in Surplus Retained Earnings AOCI (1) (Note 31) Non- Controlling Interest Total As at December 31, 2021 17,016 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 NCIB (2) 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 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 NCIB (2) Warrants Exercised Warrants Purchased and Cancelled Stock-Based Compensation Expense Base Dividends on Common Shares Dividends on Preferred Shares Non-Controlling Interest — — — 170 (959) 93 — — — — — 16,320 — — — 58 (373) 26 — — — — — 519 — — — — — — — — — — — 519 — — — — — — — — — — — As at December 31, 2023 16,031 519 (1) (2) Accumulated other comprehensive income (loss) (“AOCI”). Normal course issuer bid (“NCIB”). See accompanying Notes to the Consolidated Financial Statements. 215 — — — — — (31) — — — — — 184 — — — — — (8) (151) — — — — 25 4,284 — — — (32) (1,571) — 10 — — — — 2,691 — — — (12) (688) — — 11 — — — 2,002 878 6,450 — 6,450 — — — — (682) (219) (35) — 6,392 4,109 — 4,109 — — — (562) — (990) (36) — 8,913 684 — 786 786 — — — — — — — — 1,470 — (262) (262) — — — — — — — — 23,596 6,450 786 7,236 138 (2,530) 62 10 (682) (219) (35) — 27,576 4,109 (262) 3,847 46 (1,061) 18 (713) 11 (990) (36) — 1,208 28,698 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 9 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 12 — — — — — — — — — — 1 13 — — — — — — — — — — 1 14 10 CENOVUS ENERGY 2023 ANNUAL REPORT | 79 CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, ($ millions) Notes 2023 2022 Cenovus Energy Inc. (“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 Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization 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 (Gain) Loss Re-measurement of Contingent Payments (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 Provided (Used) Before Financing Activities Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Repayment of Long-Term Debt Principal Repayment of Leases Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIB Payment for Purchase of Warrants 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 the Consolidated Financial Statements. 11,19,20,22 13 35 9 5 26 10 27 21 21 27 37 5 1 10 10 37 37 25 20 30 30 14 14 14 4,109 4,644 (250) 52 (210) 98 34 59 (14) 220 (51) 149 (37) (222) (1,193) 7,388 (515) (4,298) 12 — (125) (369) (5,295) 2,093 58 (1,346) (288) 46 (1,061) (711) 18 (990) — (36) (3) (4,313) (77) (2,297) 4,524 2,227 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 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES States (“U.S.”). 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 the 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 The Company operates through the following reportable segments: operating margin. 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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. Downstream Segments • Canadian Refining, 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. The Company renamed its Canadian Manufacturing segment to Canadian Refining in 2023. • U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023. 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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 11 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 12 80 | CENOVUS ENERGY 2023 ANNUAL REPORT CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, ($ millions) Operating Activities Net Earnings (Loss) Depreciation, Depletion and Amortization 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 (Gain) Loss Re-measurement of Contingent Payments (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 Provided (Used) Before Financing Activities Financing Activities Net Issuance (Repayment) of Short-Term Borrowings Repayment of Long-Term Debt Principal Repayment of Leases Common Shares Issued Under Stock Option Plans Purchase of Common Shares Under NCIB Payment for Purchase of Warrants 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 the Consolidated Financial Statements. Notes 2023 2022 11,19,20,22 13 35 9 5 26 10 27 21 21 27 37 5 1 10 10 37 37 25 20 30 30 14 14 14 4,109 4,644 (250) (210) 52 98 34 59 (14) 220 (51) 149 (37) (222) (1,193) 7,388 (515) (4,298) 12 — (125) (369) (5,295) 2,093 58 (1,346) (288) 46 (1,061) (711) 18 (990) — (36) (3) (4,313) (77) (2,297) 4,524 2,227 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 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United States (“U.S.”). Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase warrants are listed on the Toronto Stock Exchange (“TSX”) and the 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. 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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the exploration for and production of NGLs and natural gas in offshore Indonesia. Downstream Segments • • Canadian Refining, 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. The Company renamed its Canadian Manufacturing segment to Canadian Refining in 2023. U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023. 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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 11 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 12 CENOVUS ENERGY 2023 ANNUAL REPORT | 81 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 A) Results of Operations – Segment and Operational Information For the years ended December 31, 2023 2022 2023 2022 2023 2022 2023 2022 Oil Sands Conventional Offshore Total Upstream Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) 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 26,192 3,059 23,133 1,457 10,774 2,716 17 8,169 34,683 4,493 30,190 4,718 12,036 2,930 1,527 8,979 15 (68) 2,993 2,763 19 6 9 8 Segment Income (Loss) 5,136 6,267 3,273 112 3,161 1,695 298 590 (5) 583 (19) 386 6 — 210 4,439 298 4,141 2,023 250 541 92 1,235 13 370 1 — 851 1,617 99 1,518 — 16 384 — 1,118 — 487 17 (57) 671 2,020 77 1,943 — 15 318 — 1,610 — 585 91 (23) 957 Canadian Refining Downstream U.S. Refining 31,082 3,270 27,812 3,152 11,088 3,690 12 9,870 41,142 4,868 36,274 6,741 12,301 3,789 1,619 11,824 (4) (55) 3,718 101 (15) 8,075 3,866 42 (51) 6,017 Total For the years ended December 31, 2023 2022 2023 2022 2023 2022 Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) 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) (1) Comparative periods reflect certain revisions. See Note 39. 6,233 — 6,233 7,792 — 7,792 4,919 6,389 — 639 — 675 — 185 — — 490 — 704 — 699 — 208 — — 491 26,393 — 26,393 23,354 — 2,562 — 477 (17) 486 — — 8 30,218 — 30,218 26,020 — 2,346 112 1,740 18 640 — — 1,082 32,626 — 32,626 28,273 — 3,201 — 1,152 (17) 671 — — 498 38,010 — 38,010 32,409 — 3,050 112 2,439 18 848 — — 1,573 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 For the years ended December 31, Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating (1) 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, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss 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) (1) Comparative periods reflect certain revisions. See Note 39. Corporate and Eliminations Consolidated 2023 2022 2023 2022 (8,234) — (8,234) (6,710) (947) (539) (3) 73 107 — — (215) 688 671 (133) 85 (67) 34 59 (14) (63) 1,260 (7,387) — (7,387) (5,192) (1,175) (1,023) 31 (89) 113 — — (52) 865 820 (81) 106 343 (549) 162 (269) (532) 865 55,474 3,270 52,204 24,715 10,141 6,352 9 52 4,644 42 (51) 6,300 688 671 (133) 85 (67) 34 59 (14) (63) 1,260 5,040 931 4,109 71,765 4,868 66,897 33,958 11,126 5,816 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 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 13 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 14 82 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 A) Results of Operations – Segment and Operational Information For the years ended December 31, 2023 2022 2023 2022 2023 2022 2023 2022 Oil Sands Conventional Offshore Total Upstream Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) 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 26,192 3,059 23,133 1,457 10,774 2,716 17 8,169 15 19 6 34,683 4,493 30,190 4,718 12,036 2,930 1,527 8,979 (68) 9 8 2,993 2,763 Segment Income (Loss) 5,136 6,267 3,273 112 3,161 1,695 298 590 (5) 583 (19) 386 6 — 210 4,439 298 4,141 2,023 250 541 92 1,235 13 370 1 — 851 1,617 99 1,518 — 16 384 — 1,118 — 487 17 (57) 671 2,020 77 1,943 — 15 318 — 1,610 — 585 91 (23) 957 For the years ended December 31, 2023 2022 2023 2022 2023 2022 Canadian Refining Total Downstream U.S. Refining Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) 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) (1) Comparative periods reflect certain revisions. See Note 39. 6,233 — 6,233 7,792 — 7,792 4,919 6,389 — 639 — 675 — 185 — — 490 — 704 — 699 — 208 — — 491 26,393 — 26,393 23,354 — 2,562 — 477 (17) 486 — — 8 30,218 — 30,218 26,020 — 2,346 112 1,740 18 640 — — 1,082 (4) (55) 31,082 3,270 27,812 3,152 11,088 3,690 12 9,870 3,866 42 (51) 6,017 32,626 — 32,626 28,273 — 3,201 — 1,152 (17) 671 — — 498 41,142 4,868 36,274 6,741 12,301 3,789 1,619 11,824 3,718 101 (15) 8,075 38,010 — 38,010 32,409 — 3,050 112 2,439 18 848 — — 1,573 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 For the years ended December 31, Revenues Gross Sales (1) Less: Royalties Expenses Purchased Product (1) Transportation and Blending (1) Operating (1) 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, Transaction and Other Costs Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss 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) (1) Comparative periods reflect certain revisions. See Note 39. Corporate and Eliminations Consolidated 2023 2022 2023 2022 (8,234) — (8,234) (6,710) (947) (539) (3) 73 107 — — (215) 688 671 (133) 85 (67) 34 59 (14) (63) 1,260 (7,387) — (7,387) (5,192) (1,175) (1,023) 31 (89) 113 — — (52) 865 820 (81) 106 343 (549) 162 (269) (532) 865 55,474 3,270 52,204 24,715 10,141 6,352 9 52 4,644 42 (51) 6,300 688 671 (133) 85 (67) 34 59 (14) (63) 1,260 5,040 931 4,109 71,765 4,868 66,897 33,958 11,126 5,816 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 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 13 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 14 CENOVUS ENERGY 2023 ANNUAL REPORT | 83 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 B) Revenues by Product For the years ended December 31, Upstream Oil Sands Crude Oil (1) NGLs (2) Natural Gas and Other Conventional Crude Oil NGLs (2) Natural Gas and Other (1) Offshore Crude Oil NGLs Natural Gas Total Upstream Downstream Canadian Refining Synthetic Crude Oil Diesel Asphalt Gasoline Other Products and Services U.S. Refining Gasoline Distillates Asphalt Other Products (1) Total Downstream Corporate and Eliminations (1) Consolidated (1) (2) Comparative periods reflect certain revisions. See Note 39. Third-party condensate sales are included within NGLs. 2023 2022 22,550 28,921 352 231 589 799 1,773 385 280 853 27,812 2,124 1,752 571 522 1,264 12,375 9,612 864 3,542 32,626 (8,234) 52,204 877 392 429 926 2,786 581 354 1,008 36,274 2,360 2,164 620 948 1,700 14,116 11,453 533 4,116 38,010 (7,387) 66,897 C) Geographical Information For the years ended December 31, Canada (2) United States (2) China Consolidated (1) (2) Revenues by country are classified based on where the operations are located. Comparative periods reflect certain revisions. See Note 39. As at December 31, Canada United States China Indonesia Consolidated Major Customers D) Assets by Segment As at December 31, Oil Sands Conventional Offshore Canadian Refining U.S. Refining Corporate and Eliminations Consolidated As at December 31, Oil Sands Conventional Offshore Canadian Refining U.S. Refining Corporate and Eliminations Consolidated (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. 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, 2023, Cenovus had two customers (2022 – two) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $18.0 billion and $7.1 billion, respectively (2022 – $16.1 billion and $9.1 billion), and are reported across all of the Company’s operating segments. E&E Assets PP&E ROU Assets 2023 729 — 9 — — — 738 2022 674 6 5 — — — 2023 24,443 2,209 2,798 2,469 5,014 317 Goodwill 2023 2,923 — — — — — 2022 24,657 2,020 2,549 2,466 4,482 325 2022 2,923 — — — — — 685 37,250 36,499 Total Assets 2,923 2,923 53,915 55,869 Revenues (1) Non-Current Assets (1) 2023 25,128 25,943 1,133 52,204 2023 35,876 5,230 1,608 344 43,058 2023 849 1 102 28 268 432 1,680 2023 31,673 2,429 3,511 2,960 8,660 4,682 2022 33,314 32,221 1,362 66,897 2022 35,194 4,824 2,064 365 42,447 2022 638 2 152 252 329 472 1,845 2022 32,248 2,410 3,339 3,172 8,324 6,376 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 15 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 16 84 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 B) Revenues by Product For the years ended December 31, Natural Gas and Other Natural Gas and Other (1) Upstream Oil Sands Crude Oil (1) NGLs (2) Conventional Crude Oil NGLs (2) Offshore Crude Oil NGLs Natural Gas Total Upstream Downstream Diesel Asphalt Gasoline U.S. Refining Gasoline Distillates Asphalt Canadian Refining Synthetic Crude Oil Other Products and Services Other Products (1) Total Downstream Corporate and Eliminations (1) Consolidated (1) (2) Comparative periods reflect certain revisions. See Note 39. Third-party condensate sales are included within NGLs. 2023 2022 22,550 28,921 352 231 589 799 385 280 853 1,773 27,812 2,124 1,752 571 522 1,264 12,375 9,612 864 3,542 32,626 (8,234) 52,204 877 392 429 926 2,786 581 354 1,008 36,274 2,360 2,164 620 948 1,700 14,116 11,453 533 4,116 38,010 (7,387) 66,897 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 C) Geographical Information For the years ended December 31, Canada (2) United States (2) China Consolidated (1) (2) Revenues by country are classified based on where the operations are located. Comparative periods reflect certain revisions. See Note 39. As at December 31, Canada United States China Indonesia Consolidated Revenues (1) 2023 25,128 25,943 1,133 52,204 2022 33,314 32,221 1,362 66,897 Non-Current Assets (1) 2023 35,876 5,230 1,608 344 43,058 2022 35,194 4,824 2,064 365 42,447 (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. 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, 2023, Cenovus had two customers (2022 – two) that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings, were approximately $18.0 billion and $7.1 billion, respectively (2022 – $16.1 billion and $9.1 billion), and are reported across all of the Company’s operating segments. D) Assets by Segment As at December 31, Oil Sands Conventional Offshore Canadian Refining U.S. Refining Corporate and Eliminations Consolidated As at December 31, Oil Sands Conventional Offshore Canadian Refining U.S. Refining Corporate and Eliminations Consolidated E&E Assets PP&E ROU Assets 2023 729 — 9 — — — 738 2022 674 6 5 — — — 2023 24,443 2,209 2,798 2,469 5,014 317 2022 24,657 2,020 2,549 2,466 4,482 325 685 37,250 36,499 Goodwill 2023 2,923 — — — — — 2022 2,923 — — — — — 2023 849 1 102 28 268 432 1,680 Total Assets 2023 31,673 2,429 3,511 2,960 8,660 4,682 2022 638 2 152 252 329 472 1,845 2022 32,248 2,410 3,339 3,172 8,324 6,376 2,923 2,923 53,915 55,869 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 15 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 16 CENOVUS ENERGY 2023 ANNUAL REPORT | 85 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Conventional Offshore Asia Pacific Atlantic Total Upstream Canadian Refining U.S. Refining Total Downstream Corporate and Eliminations Acquisitions (Note 5) Oil Sands (2) Conventional U.S. Refining (3) Total Capital Expenditures 2023 2,382 452 7 635 3,476 145 602 747 75 4,298 37 5 385 427 4,725 2022 1,792 344 8 302 2,446 117 1,059 1,176 86 3,708 1,609 12 — 1,621 5,329 (1) (2) (3) Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture. In 2022, 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. In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS 3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 were prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee. accounting policies as disclosed in Note 3. These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s These Consolidated Financial Statements were approved by the Board of Directors effective February 14, 2024. 3. SUMMARY OF 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 associate’s profit or loss and other comprehensive income (“OCI”). B) Foreign Currency Translation 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 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 Inc. – 2023 Consolidated Financial Statements 17 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 18 86 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 E) Capital Expenditures (1) For the years ended December 31, Capital Investment Oil Sands Conventional Offshore Asia Pacific Atlantic Total Upstream Canadian Refining U.S. Refining Total Downstream Corporate and Eliminations Acquisitions (Note 5) Oil Sands (2) Conventional U.S. Refining (3) Total Capital Expenditures 2023 2,382 452 7 635 3,476 145 602 747 75 4,298 37 5 385 427 4,725 2022 1,792 344 8 302 2,446 117 1,059 1,176 86 3,708 1,609 12 — 1,621 5,329 (1) (2) Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture. In 2022, 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. (3) In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS 3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 were prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee. These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s accounting policies as disclosed in Note 3. These Consolidated Financial Statements were approved by the Board of Directors effective February 14, 2024. 3. SUMMARY OF 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 associate’s profit or loss and other comprehensive income (“OCI”). B) Foreign Currency Translation 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 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 Inc. – 2023 Consolidated Financial Statements 17 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 18 CENOVUS ENERGY 2023 ANNUAL REPORT | 87 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Cenovus recognizes revenue from the following major products and services: • • • • • • Sale of crude oil, NGLs and natural gas. Sale of petroleum and refined products. Crude oil and natural gas processing services. Pipeline transportation, the blending of crude oil and 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 crude oil, NGLs and natural gas production is recorded net of royalties. 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 costs 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. H) Government Grants services were performed. I) Income Taxes date. The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are • • recorded with pension benefit costs. Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. • 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. 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 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 were enacted or substantively enacted at the Consolidated Balance Sheet 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 19 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 20 88 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Cenovus recognizes revenue from the following major products and services: • • • • • • Sale of crude oil, NGLs and natural gas. Sale of petroleum and refined products. Crude oil and natural gas processing services. 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 crude oil, NGLs and natural gas production is recorded net of royalties. Revenue associated with natural gas processing, transportation services and transloading services are generally based on fixed price contracts. 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 costs 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. Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are 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. D) Purchased Product E) Transportation and Blending F) Exploration Expense incurred as exploration expense. G) Employee Benefit Plans component. 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. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future contributions to the plans. Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows: • • • Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are recorded with pension benefit costs. Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and E&E assets. 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. 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 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 were 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 were 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. 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 Inc. – 2023 Consolidated Financial Statements 19 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 20 CENOVUS ENERGY 2023 ANNUAL REPORT | 89 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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. 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 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. 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 M) Inventories Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable value. 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 E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility and commercial viability of the field/project/area, 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 is 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 PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. 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. 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. Included in crude oil and natural 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. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Refining Assets 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. Also included in refining assets are information technology assets used to support the downstream business that are depreciated on a straight-line basis over their useful lives of three 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 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 using forward prices, costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads, operating expenses and future capital expenditures. 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 Inc. – 2023 Consolidated Financial Statements 21 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 22 90 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within twelve months, it is classified as a non-current asset. L) Cash and Cash Equivalents maturity of three months or less. M) Inventories Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable value. 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 E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility and commercial viability of the field/project/area, 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 is 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 PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals. 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. 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. Included in crude oil and natural 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. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Refining 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. Also included in refining assets are information technology assets used to support the downstream business that are depreciated on a straight-line basis over their useful lives of three 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 using forward prices, costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads, operating expenses and future capital expenditures. 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 Inc. – 2023 Consolidated Financial Statements 21 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 22 CENOVUS ENERGY 2023 ANNUAL REPORT | 91 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 on the date that 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, restoration and removal costs, variable lease payments that are based on an index or a rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease incentive receivables. 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. Finance costs are 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 due to a change in an index or rate, if there is a change in the expected residual value guarantee or if the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control. 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. 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 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 THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 At acquisition, goodwill is allocated to the CGU to which it relates. Subsequent measurement of goodwill is at cost less any expensed as incurred. 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. Cenovus recognizes decommissioning liabilities when the disturbances occur. 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 at the expected market price or on a contracted forward rate, if applicable, 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. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 23 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 24 92 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Q) Leases As Lessee characteristics. 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 on the date that 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, restoration and removal costs, variable lease payments that are based on an index or a rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease incentive receivables. 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 Lease payments are allocated between the liability and finance costs. Finance costs are 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 due to a change in an index or rate, if there is a change in the expected residual value guarantee or if the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control. 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. 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 income. 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 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 THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 the CGU 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. Cenovus recognizes decommissioning liabilities when the disturbances occur. 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 liability resulting from revisions to expected timing or future related 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. long-lived asset. Changes in the estimated 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 at the expected market price or on a contracted forward rate, if applicable, 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. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is included in other liabilities. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 23 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 24 CENOVUS ENERGY 2023 ANNUAL REPORT | 93 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 transaction to combine Cenovus and Husky Energy Inc. (the “Husky 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. 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. Cenovus has certain PSU and RSU plans that may be settled in cash or common shares and certain plans that are settled in cash. 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 THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 are 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 Inc. – 2023 Consolidated Financial Statements 25 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 26 94 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 transaction to combine Cenovus and Husky Energy Inc. (the “Husky 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. 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. Cenovus has certain PSU and RSU plans that may be settled in cash or common shares and certain plans that are settled in cash. 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 THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 are 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 Inc. – 2023 Consolidated Financial Statements 25 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 26 CENOVUS ENERGY 2023 ANNUAL REPORT | 95 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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) 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, 2024, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2023. 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, 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 WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, Toledo was consolidated. 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. 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, and, accordingly, SOSP was consolidated. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes payable and loans. facility. • WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt • Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles. • As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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. • In each arrangement, output is taken by the partners, indicating that the partners have the 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. Assessment of Impairment Indicators or Impairment Reversals 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. 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. The identification of indicators of impairment or reversal of impairment requires significant judgment. B) Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The 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 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 market expectations and the evolving worldwide demand for energy. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 27 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 28 96 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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) 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, 2024, and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2023. 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, 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 judgment. The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires Cenovus has a 50 percent interest in WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial Statements. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, Toledo was consolidated. 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. 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, and, accordingly, SOSP was consolidated. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future development of WRB, 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. Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services, purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does not have employees and, as such, is not capable of performing these roles. As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries, purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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. In each arrangement, output is taken by the partners, indicating that the partners have the 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. Assessment of Impairment Indicators or Impairment Reversals 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. 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. The identification of indicators of impairment or reversal of impairment requires significant judgment. B) Key Sources of Estimation Uncertainty Critical accounting estimates are those estimates that require Management to make particularly subjective or complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised. The 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 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 market expectations and the evolving worldwide demand for energy. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 27 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 28 CENOVUS ENERGY 2023 ANNUAL REPORT | 97 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. 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. 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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated 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 quantity of reserves, expected production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount rates. 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, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. Income Tax Provisions The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 5. ACQUISITIONS A) BP-Husky Refining LLC i) Summary of the Acquisition On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, including cost of working capital. The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at fair value 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 Assumed The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of $96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and prior quarters have not been restated to reflect the impact of the measurement period adjustments. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition. 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed As at Cash Accounts Receivable and Accrued Revenues Inventories Property, Plant and Equipment Right-of-Use Assets Other Assets Accounts Payable and Accrued Liabilities Lease Liabilities Decommissioning Liabilities Other Liabilities Total Identifiable Net Assets was collected. iii) Goodwill As at Total Purchase Consideration Fair Value of Identifiable Net Assets Goodwill Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was 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). February 28, 2023 69 3 387 770 33 10 (139) (33) (5) (73) 1,022 February 28, 2023 514 508 (1,022) — Cenovus Energy Inc. – 2023 Consolidated Financial Statements 29 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 30 98 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next financial year. 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. 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 expected future production volumes, future development and operating expenses, forward commodity prices, estimated 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 quantity of reserves, expected production volumes, future development and operating expenses, forward commodity prices and discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount rates. 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, discount rates, future development and operating expenses. Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired. Income Tax Provisions The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are subject to measurement uncertainty. Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated Financial Statements of future periods. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 5. ACQUISITIONS A) BP-Husky Refining LLC i) Summary of the Acquisition On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash, including cost of working capital. The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method, assets and liabilities are recorded at fair value 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 Assumed The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of $96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and prior quarters have not been restated to reflect the impact of the measurement period adjustments. The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition. As at 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed Cash Accounts Receivable and Accrued Revenues Inventories Property, Plant and Equipment Right-of-Use Assets Other Assets Accounts Payable and Accrued Liabilities Lease Liabilities Decommissioning Liabilities Other Liabilities Total Identifiable Net Assets February 28, 2023 69 3 387 770 33 10 (139) (33) (5) (73) 1,022 The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which was collected. iii) Goodwill As at Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo Fair Value of Identifiable Net Assets Goodwill February 28, 2023 514 508 (1,022) — Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11. Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was 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). Cenovus Energy Inc. – 2023 Consolidated Financial Statements 29 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 30 CENOVUS ENERGY 2023 ANNUAL REPORT | 99 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re- measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency translation adjustments. iv) Transaction Costs For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the Consolidated Statements of Earnings (Loss). v) Revenue and Profit Contribution The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023, to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be $52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for: • • • Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1, 2023. Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023. The consequential tax effects. This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had actually occurred on January 1, 2023. B) Sunrise Oil Sands Partnership i) Summary of the Acquisition On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3. 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 394 40 600 1,034 Cenovus 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. ii) Identifiable Assets Acquired and Liabilities Assumed As at 100 Percent of the Identifiable Assets Acquired and Liabilities Assumed 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 August 31, 2022 Capitalized Interest 9 164 88 3,218 (313) (39) (48) (486) 2,593 (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. 8. INTEGRATION, TRANSACTION AND OTHER COSTS For the years ended December 31, Integration Costs (1) Transaction Costs (Note 5) Other (2) (1) For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo Acquisition and $90 million related to the Husky Arrangement). (2) Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 31 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 100 | CENOVUS ENERGY 2023 ANNUAL REPORT 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. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. 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 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re- measurement of its pre-existing interest in SOSP to fair value. For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 iii) Goodwill As at Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP Fair Value of Identifiable Net Assets Goodwill iv) Transaction Costs Earnings (Loss). 6. GENERAL AND ADMINISTRATIVE For the years ended December 31, Salaries and Benefits Administrative and Other Stock-Based Compensation Expense (Recovery) (Note 32) 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 20) Unwinding of Discount on Decommissioning Liabilities (Note 27) Other August 31, 2022 1,034 1,559 (2,593) — 2023 249 342 97 — 688 2023 362 (84) 161 220 32 691 (20) 671 2023 46 11 28 85 2022 204 297 373 (9) 865 2022 478 (29) 163 176 37 825 (5) 820 2022 95 11 — 106 32 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re- measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the translation adjustments. iv) Transaction Costs Consolidated Statements of Earnings (Loss). v) Revenue and Profit Contribution The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023, to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be $52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting them for: 2023. • • • Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1, Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023. The consequential tax effects. On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3. The following table summarizes the fair value of total consideration: Cenovus 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. actually occurred on January 1, 2023. B) Sunrise Oil Sands Partnership i) Summary of the Acquisition As at Cash, Net of Closing Adjustments Bay Du Nord Variable Payment Total Consideration ii) Identifiable Assets Acquired and Liabilities Assumed 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 394 40 600 1,034 9 164 88 3,218 (313) (39) (48) (486) 2,593 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 iii) Goodwill As at Total Purchase Consideration Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP Fair Value of Identifiable Net Assets Goodwill 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. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10 and, accordingly SOSP has been consolidated. 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 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re- measurement of its pre-existing interest in SOSP to fair value. iv) Transaction Costs For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of Earnings (Loss). This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had 6. GENERAL AND ADMINISTRATIVE For the years ended December 31, Salaries and Benefits Administrative and Other Stock-Based Compensation Expense (Recovery) (Note 32) Other Incentive Benefits Expense (Recovery) August 31, 2022 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 20) Unwinding of Discount on Decommissioning Liabilities (Note 27) Other August 31, 2022 Capitalized Interest 2023 249 342 97 — 688 2023 362 (84) 161 220 32 691 (20) 671 (1) Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments. 8. INTEGRATION, TRANSACTION AND OTHER COSTS For the years ended December 31, Integration Costs (1) Transaction Costs (Note 5) Other (2) 2023 46 11 28 85 2022 204 297 373 (9) 865 2022 478 (29) 163 176 37 825 (5) 820 2022 95 11 — 106 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 31 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 32 CENOVUS ENERGY 2023 ANNUAL REPORT | 101 (1) (2) For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo Acquisition and $90 million related to the Husky Arrangement). Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the Company. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 10. DIVESTITURES A) 2023 Divestitures There were no material divestitures in the year end December 31, 2023. B) 2022 Divestitures 2023 (231) 21 (210) 143 (67) 2022 365 — 365 (22) 343 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). On May 31, 2022, the Company completed the transfer of 12.5 percent of Cenovus’s working interest in the White Rose field and satellite extensions in the Atlantic region. 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. 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 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). 11. IMPAIRMENT CHARGES AND REVERSALS At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest that 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) 2023 Impairment Charges The Company tested CGUs with associated goodwill for impairment as at December 31, 2023, and there were no impairments. No impairment indicators were identified for the remaining CGUs. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill that were tested for impairment were estimated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include expected production volumes, quantity of reserves, forward commodity prices, future development and operating expenses, all consistent with Cenovus’s IQREs, and discount rates. 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, 2023. All reserves were evaluated as at December 31, 2023, by the Company’s IQREs. Crude Oil, NGLs and Natural Gas Prices gas reserves were: The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural 2024 73.67 76.74 96.79 2.20 2025 74.98 79.77 98.75 3.37 2026 76.14 81.12 100.71 4.05 2027 77.66 82.88 102.72 4.13 2028 79.22 85.04 104.78 4.21 Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % West Texas Intermediate (“WTI”) (US$/bbl) (1) Western Canadian Select at Hardisty (2) (C$/bbl) Condensate at Edmonton (C$/bbl) Alberta Energy Company Natural Gas (C$/Mcf) (3) (1) Barrel ("bbl"). (2) Western Canadian Select at Hardisty (“WCS”). (3) One thousand cubic feet (“Mcf”). Discount Rates Sensitivities ii) 2022 Impairment Charges Discounted future cash flows were determined by applying a discount rate of 14 percent. A one percent increase in the discount rate or a five percent decrease in forward commodity price estimates would not impact the results of the impairment tests performed on CGUs with associated goodwill. 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. Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment were approximated using FVLCOD. The key assumptions used to estimate the present value of future net cash flows were consistent with those noted above for the year ended December 31, 2023. All reserves were evaluated as at December 31, 2022, by the Company's IQREs. Crude Oil, NGLs and Natural Gas Prices gas reserves were: The forward commodity prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural WTI (US$/bbl) WCS (C$/bbl) Condensate at Edmonton (C$/bbl) Alberta Energy Company Natural Gas (C$/Mcf) 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 Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Cenovus Energy Inc. – 2023 Consolidated Financial Statements 33 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 34 102 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 10. DIVESTITURES A) 2023 Divestitures B) 2022 Divestitures There were no material divestitures in the year end December 31, 2023. 2023 (231) 21 (210) 143 (67) 2022 365 — 365 (22) 343 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). On May 31, 2022, the Company completed the transfer of 12.5 percent of Cenovus’s working interest in the White Rose field and satellite extensions in the Atlantic region. 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). 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 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). 11. IMPAIRMENT CHARGES AND REVERSALS At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest that 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) 2023 Impairment Charges The Company tested CGUs with associated goodwill for impairment as at December 31, 2023, and there were no impairments. No impairment indicators were identified for the remaining CGUs. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill that were tested for impairment were estimated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include expected production volumes, quantity of reserves, forward commodity prices, future development and operating expenses, all consistent with Cenovus’s IQREs, and discount rates. 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, 2023. All reserves were evaluated as at December 31, 2023, by the Company’s IQREs. Crude Oil, NGLs and Natural Gas Prices The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: West Texas Intermediate (“WTI”) (US$/bbl) (1) Western Canadian Select at Hardisty (2) (C$/bbl) Condensate at Edmonton (C$/bbl) Alberta Energy Company Natural Gas (C$/Mcf) (3) 2024 73.67 76.74 96.79 2.20 2025 74.98 79.77 98.75 3.37 2026 76.14 81.12 100.71 4.05 2027 77.66 82.88 102.72 4.13 2028 79.22 85.04 104.78 4.21 Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Barrel ("bbl"). (1) (2) Western Canadian Select at Hardisty (“WCS”). (3) One thousand cubic feet (“Mcf”). On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. for proceeds of $110 million, with no gain or Sensitivities Discount Rates Discounted future cash flows were determined by applying a discount rate of 14 percent. A one percent increase in the discount rate or a five percent decrease in forward commodity price estimates would not impact the results of the impairment tests performed on CGUs with associated goodwill. ii) 2022 Impairment Charges The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its carrying amount and no impairment was recorded. Key Assumptions The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment were approximated using FVLCOD. The key assumptions used to estimate the present value of future net cash flows were consistent with those noted above for the year ended December 31, 2023. All reserves were evaluated as at December 31, 2022, by the Company's IQREs. Crude Oil, NGLs and Natural Gas Prices The forward commodity prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves were: WTI (US$/bbl) WCS (C$/bbl) Condensate at Edmonton (C$/bbl) Alberta Energy Company Natural Gas (C$/Mcf) 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 Average Annual Increase Thereafter 2.00 % 2.00 % 2.00 % 2.00 % Cenovus Energy Inc. – 2023 Consolidated Financial Statements 33 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 34 CENOVUS ENERGY 2023 ANNUAL REPORT | 103 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the impairment amount and impairment reversal amount recorded as at December 31, 2022, for the U.S. Refining 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 commodity 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. B) Downstream Cash-Generating Units i) 2023 Impairment Charges and Reversals As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream CGUs. ii) 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 an incident 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. Refining 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 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. Refining CGUs was estimated to be $5.4 billion. Key Assumptions The recoverable amount (Level 3) of the U.S. Refining CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included refined product production, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts. Crude Oil and Crack Spreads Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: (US$/bbl) WTI Differential WTI – WTS (1) Differential WTI – WCS Chicago 3-2-1 Crack Spread (1) West Texas Sour (“WTS”). 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 between 15 percent and 18 percent based on the individual characteristics of the CGU, and other economic and operating factors. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Sensitivities segment CGUs: Increase (Decrease) to Impairment Amount Increase (Decrease) to Impairment Reversal Amount 12. OTHER INCOME (LOSS), NET 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 (268) 168 268 (342) Rate (65) 14 Rate 69 (72) For the year ended December 31, 2023, the Company recorded other income of $63 million (2022 – $532 million). In 2022, other income included insurance proceeds of $328 million, related to the 2018 incidents at the Superior Refinery and in the Atlantic region, and $65 million under the Government of Alberta’s Site Rehabilitation Program, which provided qualifying entities funding to abandon and reclaim oil and gas sites. No similar amounts were recorded in 2023. 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) 2023 1,041 (109) 224 25 1,181 (250) 931 2022 1,252 104 262 21 1,639 642 2,281 In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global minimum tax framework (“Pillar Two”). In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to address Pillar Two, which provide clarity on the impacts and additional disclosure requirements once legislation is substantively enacted. Cenovus has applied the mandatory temporary exemption of IAS 12 and in turn, has not recognized the impacts of Pillar Two in the deferred income tax calculation. The Company is not expecting a material impact as a result of Pillar Two. For the year ended December 31, 2023, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The decrease from the prior year is due to lower earnings compared to 2022 and a deferred income tax recovery in the U.S. of which $115 million related to a step-up in the U.S. tax basis on the Toledo Acquisition. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 35 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 36 104 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Discount Rates Sensitivities performed on CGUs with associated goodwill. B) Downstream Cash-Generating Units i) 2023 Impairment Charges and Reversals CGUs. ii) 2022 Impairment Charges and Reversals NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Sensitivities 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 sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would have on the impairment amount and impairment reversal amount recorded as at December 31, 2022, for the U.S. Refining segment CGUs: 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 commodity 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 Increase (Decrease) to Impairment Amount Increase (Decrease) to Impairment Reversal Amount One Percent Increase in the Discount Rate One Percent Decrease in the Discount Rate Five Percent Increase in the Forward Price Estimates Five Percent Decrease in the Forward Price Estimates 69 (72) (65) 14 (268) 168 268 (342) As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream 12. OTHER INCOME (LOSS), NET For the year ended December 31, 2023, the Company recorded other income of $63 million (2022 – $532 million). In 2022, other income included insurance proceeds of $328 million, related to the 2018 incidents at the Superior Refinery and in the Atlantic region, and $65 million under the Government of Alberta’s Site Rehabilitation Program, which provided qualifying entities funding to abandon and reclaim oil and gas sites. No similar amounts were recorded in 2023. 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) 2023 1,041 (109) 224 25 1,181 (250) 931 2022 1,252 104 262 21 1,639 642 2,281 In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global minimum tax framework (“Pillar Two”). In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to address Pillar Two, which provide clarity on the impacts and additional disclosure requirements once legislation is substantively enacted. Cenovus has applied the mandatory temporary exemption of IAS 12 and in turn, has not recognized the impacts of Pillar Two in the deferred income tax calculation. The Company is not expecting a material impact as a result of Pillar Two. For the year ended December 31, 2023, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The decrease from the prior year is due to lower earnings compared to 2022 and a deferred income tax recovery in the U.S. of which $115 million related to a step-up in the U.S. tax basis on the Toledo Acquisition. 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 an incident 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. Refining 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 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. Refining CGUs was estimated to be $5.4 billion. The recoverable amount (Level 3) of the U.S. Refining CGUs were determined using FVLCOD. FVLCOD was calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash flows included refined product production, forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts. Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022, the forward prices used to determine future cash flows were: 2023 80.33 (0.56) (23.32) 29.37 2024 78.50 (0.56) (19.09) 24.10 2025 76.95 (0.56) (17.42) 22.12 2026 77.61 (0.56) (15.87) 21.70 2027 79.16 (0.56) (15.74) 21.67 Key Assumptions Crude Oil and Crack Spreads (US$/bbl) WTI Differential WTI – WTS (1) Differential WTI – WCS Chicago 3-2-1 Crack Spread (1) West Texas Sour (“WTS”). Discount Rates 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 between 15 percent and 18 percent based on the individual characteristics of the CGU, and other economic and operating factors. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 35 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 36 CENOVUS ENERGY 2023 ANNUAL REPORT | 105 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: For the years ended December 31, Earnings (Loss) Before Income Tax Canadian Statutory Rate (percent) Expected Income Tax Expense (Recovery) 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 Recognition of U.S. Tax Basis Other Total Tax Expense (Recovery) Effective Tax Rate (percent) B) Deferred Income Tax Assets and Liabilities 2023 5,040 23.7 1,194 (38) (15) (30) (16) (115) (49) 931 18.5 2022 8,731 23.7 2,069 17 84 84 15 — 12 2,281 26.1 The breakdown of deferred income tax assets and deferred income tax liabilities, 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 Assets Deferred Income Tax Assets to be Settled Within Twelve Months Deferred Income Tax Assets to be Settled After More Than Twelve Months 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 Net Deferred Income Tax Liability 2023 (315) (1,174) (1,489) 138 4,843 4,981 3,492 2022 (31) (747) (778) 55 4,460 4,515 3,737 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 assets and liabilities, without taking into consideration the offsetting of balances within the same tax jurisdiction, is: Deferred Income Tax Assets As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income As at December 31, 2022 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income As at December 31, 2023 Unused Tax Losses Risk Management (655) 490 9 (156) (777) 19 (914) (11) 11 — — — — — Other (788) 158 8 (622) 54 (7) (575) Total (1,454) 659 17 (778) (723) 12 (1,489) PP&E 3,949 25 486 4,460 495 (7) 4,948 Risk Management — 11 — 11 (8) — 3 Other 97 (53) (14) — 44 — 30 Total 4,046 (17) 486 4,515 473 (7) 4,981 Total 2,592 642 486 17 3,737 (250) 5 3,492 2023 8,547 8,058 347 16,952 2022 8,505 6,477 457 15,439 Charged (Credited) to Sunrise Purchase Price Allocation Charged (Credited) to Other Comprehensive Income Deferred Income Tax Liabilities As at December 31, 2021 Charged (Credited) to Earnings As at December 31, 2022 Charged (Credited) to Earnings As at December 31, 2023 Net Deferred Income Tax Liabilities 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 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income As at December 31, 2023 C) Tax Pools As at December 31, Canada United States Asia Pacific earlier than 2038. The deferred income tax asset of $696 million as at December 31, 2023 (December 31, 2022 – $546 million) represents net deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2023, or December 31, 2022, 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, 2023, the above tax pools included $126 million (December 31, 2022 – $115 million) of Canadian federal non-capital losses and $3.7 billion (December 31, 2022 – $468 million) of U.S. net operating losses. These losses expire no As at December 31, 2023, the Company had Canadian net capital losses totaling $59 million (December 31, 2022 – $28 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $141 million (December 31, 2022 – $504 million) of deductible temporary differences associated with unrealized foreign exchange losses on its U.S. denominated debt. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 37 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 38 106 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes: Deferred Income Tax Liabilities As at December 31, 2021 Charged (Credited) to Earnings Charged (Credited) to Sunrise Purchase Price Allocation As at December 31, 2022 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income As at December 31, 2023 Net Deferred Income Tax Liabilities 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 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income As at December 31, 2023 PP&E 3,949 25 486 4,460 495 (7) 4,948 Risk Management — 11 — 11 (8) — 3 Other 97 (53) — 44 (14) — 30 Total 4,046 (17) 486 4,515 473 (7) 4,981 Total 2,592 642 486 17 3,737 (250) 5 3,492 The deferred income tax asset of $696 million as at December 31, 2023 (December 31, 2022 – $546 million) represents net deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2023, or December 31, 2022, 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 2023 8,547 8,058 347 16,952 2022 8,505 6,477 457 15,439 As at December 31, 2023, the above tax pools included $126 million (December 31, 2022 – $115 million) of Canadian federal non-capital losses and $3.7 billion (December 31, 2022 – $468 million) of U.S. net operating losses. These losses expire no earlier than 2038. As at December 31, 2023, the Company had Canadian net capital losses totaling $59 million (December 31, 2022 – $28 million), which are available for carry forward to reduce future capital gains. The Company has not recognized $141 million (December 31, 2022 – $504 million) of deductible temporary differences associated with unrealized foreign exchange losses on its U.S. denominated debt. For the years ended December 31, Earnings (Loss) Before Income Tax Canadian Statutory Rate (percent) Expected Income Tax Expense (Recovery) 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 Recognition of U.S. Tax Basis Other Total Tax Expense (Recovery) Effective Tax Rate (percent) B) Deferred Income Tax Assets and Liabilities 2023 5,040 23.7 1,194 (38) (15) (30) (16) (115) (49) 931 18.5 2023 (315) (1,174) (1,489) 138 4,843 4,981 3,492 Other (788) 158 8 (622) 54 (7) (575) 2022 8,731 23.7 2,069 17 84 84 15 — 12 2,281 26.1 2022 (31) (747) (778) 55 4,460 4,515 3,737 Total (1,454) 659 17 (778) (723) 12 (1,489) The breakdown of deferred income tax assets and deferred income tax liabilities, 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 Assets Deferred Income Tax Assets to be Settled Within Twelve Months Deferred Income Tax Assets to be Settled After More Than Twelve Months 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 Net Deferred Income Tax Liability year. the same tax jurisdiction, is: Deferred Income Tax Assets As at December 31, 2021 Charged (Credited) to Earnings As at December 31, 2022 Charged (Credited) to Earnings Charged (Credited) to Other Comprehensive Income Charged (Credited) to Other Comprehensive Income As at December 31, 2023 Unused Tax Losses Management (655) 490 9 (156) (777) 19 (914) Risk (11) 11 — — — — — 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 assets and liabilities, without taking into consideration the offsetting of balances within Cenovus Energy Inc. – 2023 Consolidated Financial Statements 37 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 38 CENOVUS ENERGY 2023 ANNUAL REPORT | 107 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Joint Operations Receivables Other 17. INVENTORIES As at December 31, Product Crude Oil Diluent Natural Gas and NGLs Refined Products Total Product Parts and Supplies NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 (thousands) Dilutive Effect of Warrants Dilutive Effect of Net Settlement Rights Dilutive Effect of Cenovus Replacement Stock Options Diluted – Weighted Average Number of Shares (thousands) Net Earnings (Loss) Per Common Share – Basic ($) Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2023 4,109 (36) 4,073 2022 6,450 (35) 6,415 1,895,487 1,951,262 22,223 7,150 580 44,845 10,045 — 1,925,440 2,006,152 2.15 2.12 3.29 3.20 (1) (2) For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive. For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of shares as the effect was anti-dilutive. B) Common Share Dividends For the years ended December 31, Per Share Amount Per Share Amount Base Dividends Variable Dividends Total Common Share Dividends Declared and Paid 0.525 — 0.525 990 — 990 0.350 0.114 0.464 682 219 901 2023 2022 The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 14, 2024, the Company’s Board of Directors declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common shareholders of record as at March 15, 2024. 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 2023 2022 expense. 7 2 12 9 6 36 7 1 12 9 6 35 The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. For the year ended December 31, 2023, the Company paid $36 million in preferred share dividends (December 31, 2022 – $26 million). On January 2, 2024, the Company paid preferred share dividends of $9 million, as declared on November 1, 2023. On January 3, 2023, the Company paid preferred share dividends of $9 million, as declared on November 1, 2022. On February 14, 2024, the Company’s Board of Directors declared first quarter dividends of $9 million payable on April 1, 2024, to preferred shareholders of record as at March 15, 2024. 2023 2,109 118 2,227 2023 2,722 242 49 22 3,035 2023 2,084 379 68 1,073 3,604 426 4,030 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 For the year ended December 31, 2023, approximately $39.1 billion of produced and purchased inventory was recorded as an expense (2022 – approximately $49.1 billion). As at December 31, 2023, the Company recorded non-cash inventory write-downs of $86 million and $3 million in refined products and crude oil inventory, respectively. The non-cash inventory write-downs were included in purchased product Cenovus Energy Inc. – 2023 Consolidated Financial Statements 39 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 40 108 | CENOVUS ENERGY 2023 ANNUAL REPORT Basic – Weighted Average Number of Shares (thousands) 1,895,487 1,951,262 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Dilutive Effect of Warrants Dilutive Effect of Net Settlement Rights Dilutive Effect of Cenovus Replacement Stock Options Diluted – Weighted Average Number of Shares (thousands) Net Earnings (Loss) Per Common Share – Basic ($) Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($) 2023 4,109 (36) 4,073 22,223 7,150 580 2.15 2.12 1,925,440 2,006,152 2022 6,450 (35) 6,415 44,845 10,045 — 3.29 3.20 682 219 901 12 7 1 9 6 35 2023 2022 12 7 2 9 6 36 (1) For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive. (2) For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of For the years ended December 31, Per Share Amount Per Share Amount 2023 2022 0.525 — 0.525 990 — 990 0.350 0.114 0.464 The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered On February 14, 2024, the Company’s Board of Directors declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common shareholders of record as at March 15, 2024. shares as the effect was anti-dilutive. 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. million). The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered For the year ended December 31, 2023, the Company paid $36 million in preferred share dividends (December 31, 2022 – $26 On January 2, 2024, the Company paid preferred share dividends of $9 million, as declared on November 1, 2023. On January 3, 2023, the Company paid preferred share dividends of $9 million, as declared on November 1, 2022. On February 14, 2024, the Company’s Board of Directors declared first quarter dividends of $9 million payable on April 1, 2024, to preferred shareholders of record as at March 15, 2024. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Joint Operations Receivables Other 17. INVENTORIES As at December 31, Product Crude Oil Diluent Natural Gas and NGLs Refined Products Total Product Parts and Supplies 2023 2,109 118 2,227 2023 2,722 242 49 22 3,035 2023 2,084 379 68 1,073 3,604 426 4,030 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 For the year ended December 31, 2023, approximately $39.1 billion of produced and purchased inventory was recorded as an expense (2022 – approximately $49.1 billion). As at December 31, 2023, the Company recorded non-cash inventory write-downs of $86 million and $3 million in refined products and crude oil inventory, respectively. The non-cash inventory write-downs were included in purchased product expense. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 39 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 40 CENOVUS ENERGY 2023 ANNUAL REPORT | 109 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 18. EXPLORATION AND EVALUATION ASSETS, NET As at December 31, 2021 Additions Write-downs (1) Change in Decommissioning Liabilities Exchange Rate Movements and Other As at December 31, 2022 Acquisition Additions Transfer to PP&E (Note 19) Write-downs (1) Change in Decommissioning Liabilities Exchange Rate Movements and Other As at December 31, 2023 Total 720 37 (64) (12) 4 685 31 84 (60) (29) 28 (1) 738 (1) For the year ended December 31, 2023, previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the carrying value was not considered to be recoverable. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 41 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 110 | CENOVUS ENERGY 2023 ANNUAL REPORT 254 12,132 1,825 57,739 Crude Oil and Transportation Processing, and Storage Natural Gas Properties Assets Refining Assets Other Assets (1) NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 19. PROPERTY, PLANT AND EQUIPMENT, NET COST As at December 31, 2021 Acquisitions (Note 5) (2) Additions Change in Decommissioning Liabilities Divestitures (Notes 5 and 10) (2) Exchange Rate Movements and Other As at December 31, 2022 Acquisitions (Note 5) (3) Additions Transfer from E&E (Note 18) Change in Decommissioning Liabilities Divestitures (Note 5) (3) Exchange Rate Movements and Other ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2021 Depreciation, Depletion and Amortization (4) Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Notes 5 and 10) (2) Exchange Rate Movements and Other As at December 31, 2022 Depreciation, Depletion and Amortization (4) Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 CARRYING VALUE As at December 31, 2022 As at December 31, 2023 38,443 3,230 2,409 (186) (557) 189 43,528 11 3,392 60 542 (17) (91) 10,912 3,461 — — (84) 13 14,302 3,692 (8) (11) 17,975 29,226 29,450 As at December 31, 2023 47,425 272 228 — 11 (6) — 21 — 14 — — — 4 53 37 — — — 16 19 — 4 106 129 148 143 10,495 — 1,143 (29) — 523 770 719 — 21 (633) (239) 12,770 4,572 466 1,499 (1,233) — 243 5,547 554 (299) (135) 5,667 6,585 7,103 (1) (2) Includes assets within the commercial fuels business, 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) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million. (4) For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively). PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A: Assets Under Construction As at December 31, Crude Oil and Natural Gas Properties Refining Assets 1,735 — 108 (32) — 14 — 89 — 18 (17) (7) 1,908 1,139 103 — — — 43 1,285 86 (12) (5) 1,354 540 554 2023 2,507 243 2,750 Total 50,901 3,230 3,671 (253) (557) 747 781 4,214 60 581 (667) (333) 62,375 16,676 4,067 1,499 (1,233) (84) 315 21,240 4,351 (319) (147) 25,125 36,499 37,250 2022 2,142 137 2,279 42 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 18. EXPLORATION AND EVALUATION ASSETS, NET NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 19. PROPERTY, PLANT AND EQUIPMENT, NET As at December 31, 2021 Additions Write-downs (1) Change in Decommissioning Liabilities Exchange Rate Movements and Other As at December 31, 2022 Acquisition Additions Transfer to PP&E (Note 19) Write-downs (1) Change in Decommissioning Liabilities Exchange Rate Movements and Other As at December 31, 2023 Total 720 37 (64) (12) 4 685 31 84 (60) (29) 28 (1) 738 (1) For the year ended December 31, 2023, previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the carrying value was not considered to be recoverable. COST As at December 31, 2021 Acquisitions (Note 5) (2) Additions Change in Decommissioning Liabilities Divestitures (Notes 5 and 10) (2) Exchange Rate Movements and Other As at December 31, 2022 Acquisitions (Note 5) (3) Additions Transfer from E&E (Note 18) Change in Decommissioning Liabilities Divestitures (Note 5) (3) Exchange Rate Movements and Other Crude Oil and Natural Gas Properties Processing, Transportation and Storage Assets Refining Assets Other Assets (1) Total 38,443 3,230 2,409 (186) (557) 189 43,528 11 3,392 60 542 (17) (91) 228 — 11 (6) — 21 254 — 14 — — — 4 10,495 — 1,143 (29) — 523 1,735 50,901 — 108 (32) — 14 3,230 3,671 (253) (557) 747 12,132 1,825 57,739 770 719 — 21 (633) (239) — 89 — 18 (17) (7) 781 4,214 60 581 (667) (333) As at December 31, 2023 47,425 272 12,770 1,908 62,375 ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION As at December 31, 2021 Depreciation, Depletion and Amortization (4) Impairment Charges (Note 11) Impairment Reversals (Note 11) Divestitures (Notes 5 and 10) (2) Exchange Rate Movements and Other As at December 31, 2022 Depreciation, Depletion and Amortization (4) Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 CARRYING VALUE As at December 31, 2022 As at December 31, 2023 10,912 3,461 — — (84) 13 14,302 3,692 (8) (11) 17,975 29,226 29,450 53 37 — — — 16 106 19 — 4 129 148 143 4,572 466 1,499 (1,233) — 243 5,547 554 (299) (135) 5,667 6,585 7,103 1,139 103 — — — 43 1,285 86 (12) (5) 1,354 540 554 16,676 4,067 1,499 (1,233) (84) 315 21,240 4,351 (319) (147) 25,125 36,499 37,250 (1) (2) (3) (4) Includes assets within the commercial fuels business, 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. In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million. For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively). Assets Under Construction PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A: Cenovus Energy Inc. – 2023 Consolidated Financial Statements 41 Cenovus Energy Inc. – 2023 Consolidated Financial Statements As at December 31, Crude Oil and Natural Gas Properties Refining Assets 2023 2,507 243 2,750 2022 2,142 137 2,279 42 CENOVUS ENERGY 2023 ANNUAL REPORT | 111 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 20. LEASES A) Right-of-Use Assets, Net COST As at December 31, 2021 Additions Exchange Rate Movements and Other As at December 31, 2022 Acquisitions (Note 5) (3) Additions Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 ACCUMULATED DEPRECIATION As at December 31, 2021 Depreciation Exchange Rate Movements and Other As at December 31, 2022 Depreciation Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 CARRYING VALUE As at December 31, 2022 As at December 31, 2023 Transportation and Storage Assets (1) Real Estate Refining Assets Other Assets (2) 592 — 7 599 1 1 — (13) 588 92 36 (1) 127 36 — (7) 156 472 432 1,841 22 (23) 1,840 24 56 — 44 1,964 520 226 (101) 645 223 — (5) 863 1,195 1,101 161 1 12 174 8 — (19) (2) 161 33 21 4 58 22 (12) (3) 65 116 96 62 2 10 74 — — — (4) 70 1 14 (3) 12 12 — (5) 19 62 51 Total 2,656 25 6 2,687 33 57 (19) 25 2,783 646 297 (101) 842 293 (12) (20) 1,103 1,845 1,680 (1) (2) (3) Includes railcars, barges, vessels, pipelines, caverns and storage tanks. Includes assets in the commercial fuels business, fleet vehicles and other equipment. In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million. B) Lease Liabilities Lease Liabilities, Beginning of Year Acquisitions (Note 5) (1) Additions Interest Expense (Note 7) Lease Payments Divestitures (Note 5) (1) Exchange Rate Movements and Other Lease Liabilities, End of Year Less: Current Portion Long-Term Portion 21. JOINT ARRANGEMENTS A) Joint Operations on these transactions. B) Joint Ventures Husky-CNOOC Madura Ltd. equity-accounted affiliates. Results of Operations For the years ended December 31, Revenue Expenses Net Earnings (Loss) (1) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million. 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. 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. Cenovus has a number of joint operations in the Upstream segments. At December 31, 2023, the Company also has a 50 percent interest in WRB in the U.S. Refining segment. 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. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with bp. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with bp Canada. Subsequent to these dates, both of these joint operations are fully controlled by Cenovus and have been consolidated, refer to Note 5 for more information The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from Summarized below is the financial information for HCML accounted for using the equity method. 2023 2,836 33 57 161 (449) (11) 31 2,658 299 2,359 2022 2,957 — 25 163 (465) — 156 2,836 308 2,528 2023 615 545 70 2022 383 350 33 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 43 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 44 112 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 20. LEASES A) Right-of-Use Assets, Net Exchange Rate Movements and Other COST As at December 31, 2021 Additions As at December 31, 2022 Acquisitions (Note 5) (3) Additions Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 ACCUMULATED DEPRECIATION As at December 31, 2021 Depreciation Exchange Rate Movements and Other As at December 31, 2022 Depreciation Divestitures (Note 5) (3) Exchange Rate Movements and Other As at December 31, 2023 CARRYING VALUE As at December 31, 2022 As at December 31, 2023 Transportation and Storage Assets (1) Real Estate Refining Assets Other Assets (2) 592 599 — 7 1 1 — (13) 588 127 92 36 (1) 36 — (7) 156 472 432 1,841 22 (23) 1,840 24 56 — 44 1,964 520 226 (101) 645 223 — (5) 863 1,195 1,101 161 1 12 174 8 — (19) (2) 161 33 21 4 58 22 (12) (3) 65 116 96 Total 2,656 2,687 25 6 33 57 (19) 25 2,783 646 297 (101) 842 293 (12) (20) 1,103 1,845 1,680 62 2 10 74 — — — (4) 70 1 14 (3) 12 12 — (5) 19 62 51 B) Lease Liabilities Lease Liabilities, Beginning of Year Acquisitions (Note 5) (1) Additions Interest Expense (Note 7) Lease Payments Divestitures (Note 5) (1) Exchange Rate Movements and Other Lease Liabilities, End of Year Less: Current Portion Long-Term Portion 2023 2,836 33 57 161 (449) (11) 31 2,658 299 2,359 2022 2,957 — 25 163 (465) — 156 2,836 308 2,528 (1) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million. 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. 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. 21. JOINT ARRANGEMENTS A) Joint Operations Cenovus has a number of joint operations in the Upstream segments. At December 31, 2023, the Company also has a 50 percent interest in WRB in the U.S. Refining segment. 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. Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with bp. Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with bp Canada. Subsequent to these dates, both of these joint operations are fully controlled by Cenovus and have been consolidated, refer to Note 5 for more information on these transactions. Includes railcars, barges, vessels, pipelines, caverns and storage tanks. Includes assets in the commercial fuels business, fleet vehicles and other equipment. (1) (2) (3) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million. B) Joint Ventures Husky-CNOOC Madura Ltd. The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from equity-accounted affiliates. 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) 2023 615 545 70 2022 383 350 33 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 43 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 44 CENOVUS ENERGY 2023 ANNUAL REPORT | 113 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Balance Sheet As at December 31, Current Assets (1) Non-Current Assets Current Liabilities Non-Current Liabilities Net Assets 2023 334 1,751 140 1,188 757 2022 247 1,926 160 1,293 720 (1) Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million). For the year ended December 31, 2023, the Company’s share of income from the equity-accounted affiliate was $57 million (2022 – $23 million). As at December 31, 2023, the carrying amount of the Company’s share of net assets was $344 million (December 31, 2022 – $365 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, 2023, the Company received $93 million of distributions from HCML (2022 – $42 million) and paid $35 million in contributions (2022 – $54 million). Husky Midstream Limited Partnership The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity- accounted affiliates. For the years ended December 31, HMLP Net Earnings (Loss) Cenovus's Share of HMLP Net Earnings (Loss) (1) Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1) Distributions Received Contributions Paid 2023 231 (1) (2) 56 62 2022 190 (23) 8 23 31 (1) Cenovus does not receive 35 percent of HMLP's net earnings and OCI due to the nature of the profit sharing agreement. The carrying value of the Company’s investment in HMLP as at December 31, 2023, was $nil (December 31, 2022 – $nil) due to losses in excess of the equity investment. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $31 million as at December 31, 2023 (December 31, 2022 – $28 million). 22. OTHER ASSETS As at December 31, Private Equity Investments (Note 35) Precious Metals Net Investment in Finance Leases Long-Term Receivables and Prepaids Intangible Assets (1) 2023 131 76 61 50 — 318 2022 55 86 62 120 19 342 (1) For the year 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. 2023 2,923 — 2,923 2023 1,171 1,101 651 2,923 2023 3,931 1,075 284 69 75 19 18 9 2022 3,473 (550) 2,923 2022 1,171 1,101 651 2,923 2022 3,412 2,331 162 80 66 39 25 9 5,480 6,124 23. GOODWILL Carrying Value, Beginning of Year Goodwill Disposed (Note 5) Carrying Value, End of Year As at December 31, Primrose (Foster Creek) Christina Lake Lloydminster Thermal The carrying amount of goodwill is allocated to the following CGUs: 24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Interest Other Employee Long-Term Incentives Joint Operations Payable Risk Management Provisions for Onerous and Unfavourable Contracts 25. 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 and no direct borrowings. ii) WRB Uncommitted Demand Facilities For the year ended December 31, 2023, the annualized weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings, was 4.7 percent (2022 – 4.7 percent). Notes i ii 2023 — 179 179 2022 — 115 115 As at December 31, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) WRB has uncommitted demand facilities of US$450 million that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at December 31, 2023, US$270 million was drawn on these facilities, of which Cenovus’s proportionate share was US$135 million (C$179 million). As at December 31, 2022, Cenovus’s proportionate share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 45 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 46 114 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Balance Sheet As at December 31, Current Assets (1) Non-Current Assets Current Liabilities Non-Current Liabilities Net Assets (1) Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million). For the year ended December 31, 2023, the Company’s share of income from the equity-accounted affiliate was $57 million (2022 – $23 million). As at December 31, 2023, the carrying amount of the Company’s share of net assets was $344 million (December 31, 2022 – $365 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 For the year ended December 31, 2023, the Company received $93 million of distributions from HCML (2022 – $42 million) and venture and the Company. paid $35 million in contributions (2022 – $54 million). Husky Midstream Limited Partnership The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity- accounted affiliates. For the years ended December 31, HMLP Net Earnings (Loss) Cenovus's Share of HMLP Net Earnings (Loss) (1) Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1) Distributions Received Contributions Paid (1) Cenovus does not receive 35 percent of HMLP's net earnings and OCI due to the nature of the profit sharing agreement. The carrying value of the Company’s investment in HMLP as at December 31, 2023, was $nil (December 31, 2022 – $nil) due to losses in excess of the equity investment. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $31 million as at December 31, 2023 (December 31, 2022 – $28 million). 2023 334 1,751 140 1,188 757 2022 247 1,926 160 1,293 720 2023 231 (1) (2) 56 62 2023 131 76 61 50 — 318 2022 190 (23) 8 23 31 2022 55 86 62 120 19 342 22. OTHER ASSETS As at December 31, Private Equity Investments (Note 35) Precious Metals Net Investment in Finance Leases Long-Term Receivables and Prepaids Intangible Assets (1) (1) For the year 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. 23. GOODWILL Carrying Value, Beginning of Year Goodwill Disposed (Note 5) 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 24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As at December 31, Accruals Trade Employee Long-Term Incentives Interest Joint Operations Payable Risk Management Provisions for Onerous and Unfavourable Contracts Other 25. DEBT AND CAPITAL STRUCTURE 2023 2,923 — 2,923 2023 1,171 1,101 651 2,923 2023 3,931 1,075 284 69 75 19 18 9 2022 3,473 (550) 2,923 2022 1,171 1,101 651 2,923 2022 3,412 2,331 162 80 66 39 25 9 5,480 6,124 For the year ended December 31, 2023, the annualized weighted average interest rate on outstanding debt, including the Company’s proportionate share of short-term borrowings, was 4.7 percent (2022 – 4.7 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 2023 — 179 179 2022 — 115 115 As at December 31, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no direct borrowings. ii) WRB Uncommitted Demand Facilities WRB has uncommitted demand facilities of US$450 million that may be used to cover short-term working capital requirements, of which Cenovus’s proportionate share is 50 percent. As at December 31, 2023, US$270 million was drawn on these facilities, of which Cenovus’s proportionate share was US$135 million (C$179 million). As at December 31, 2022, Cenovus’s proportionate share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 45 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 46 CENOVUS ENERGY 2023 ANNUAL REPORT | 115 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 2023 — 5,028 2,000 7,028 80 7,108 2022 — 6,537 2,000 8,537 154 8,691 (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 As at December 31, 2023, the Company had in place a committed credit facility that 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, 2023, no amount was drawn on the credit facility (December 31, 2022 – $nil). ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes For the year ended December 31, 2023, the Company purchased US$1.0 billion (2022 – US$2.6 billion and C$750 million) in principal of its outstanding unsecured notes. The principal amounts of the Company’s outstanding unsecured notes are: As at December 31, U.S. Dollar Denominated Unsecured Notes 5.38% due July 15, 2025 4.25% due April 15, 2027 4.40% due April 15, 2029 2.65% due January 15, 2032 5.25% due June 15, 2037 6.80% due September 15, 2037 6.75% due November 15, 2039 4.45% due September 15, 2042 5.20% due September 15, 2043 5.40% due June 15, 2047 3.75% due February 15, 2052 Canadian Dollar Unsecured Notes 3.60% due March 10, 2027 3.50% due February 7, 2028 Total Unsecured Notes 2023 2022 US$ Principal C$ Principal and Equivalent US$ Principal C$ Principal and Equivalent 133 373 183 500 333 191 652 91 27 569 750 3,802 176 493 241 661 441 253 862 121 36 752 992 5,028 750 1,250 2,000 7,028 133 373 240 500 583 387 935 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 As at December 31, 2023, 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 agreement, not to exceed 65 percent. The Company is well below this limit. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 C) Mandatory Debt Payments As at December 31, 2023 2024 2025 2026 2027 2028 Thereafter D) Capital Structure U.S. Dollar Unsecured Notes Canadian Dollar Unsecured Notes US$ Principal C$ Principal Equivalent C$ Principal C$ Principal and Equivalent — 133 — 373 — 3,296 3,802 — 176 — 493 — 4,359 5,028 — — — 750 1,250 — 2,000 Total — 176 — 1,243 1,250 4,359 7,028 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, 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. 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 November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 47 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 48 116 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 2023 — 5,028 2,000 7,028 80 7,108 (1) The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans. As at December 31, 2023, the Company had in place a committed credit facility that 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, 2023, no amount was drawn on the credit facility (December 31, 2022 – $nil). ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes For the year ended December 31, 2023, the Company purchased US$1.0 billion (2022 – US$2.6 billion and C$750 million) in principal of its outstanding unsecured notes. The principal amounts of the Company’s outstanding unsecured notes are: As at December 31, US$ Principal Equivalent US$ Principal U.S. Dollar Denominated Unsecured Notes 2023 C$ Principal and 2022 C$ Principal and Equivalent 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 3.60% due March 10, 2027 3.50% due February 7, 2028 Total Unsecured Notes 133 373 240 500 583 387 935 97 29 800 750 4,827 133 373 183 500 333 191 652 91 27 569 750 3,802 176 493 241 661 441 253 862 121 36 752 992 5,028 750 1,250 2,000 7,028 2022 — 6,537 2,000 8,537 154 8,691 181 505 324 677 790 524 1,267 131 39 1,083 1,016 6,537 750 1,250 2,000 8,537 As at December 31, 2023, 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 agreement, not to exceed 65 percent. The Company is well below this limit. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 C) Mandatory Debt Payments As at December 31, 2023 2024 2025 2026 2027 2028 Thereafter D) Capital Structure U.S. Dollar Unsecured Notes Canadian Dollar Unsecured Notes US$ Principal C$ Principal Equivalent C$ Principal Total C$ Principal and Equivalent — 133 — 373 — 3,296 3,802 — 176 — 493 — 4,359 5,028 — — — 750 1,250 — 2,000 — 176 — 1,243 1,250 4,359 7,028 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, 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. 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 November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf prospectus are subject to market conditions on terms set forth in one or more prospectus supplements. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 47 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 48 CENOVUS ENERGY 2023 ANNUAL REPORT | 117 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Exploration and Evaluation Asset Write-downs (Income) Loss From Equity-Accounted Affiliates Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA (times) (1) Calculated on a trailing twelve-month basis. 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 (times) (1) Calculated on a trailing twelve-month basis. Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Capitalization 2023 179 — 7,108 7,287 (2,227) 5,060 4,109 671 (133) 931 4,644 29 (51) 52 (67) 34 59 (14) (63) 10,201 0.5 2023 5,060 7,388 (222) (1,193) 8,803 0.6 2023 5,060 28,698 33,758 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 0.3 2022 4,282 11,403 (150) 575 10,978 0.4 2022 4,282 27,576 31,858 Net Debt to Capitalization (percent) 15 13 (1) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities was $2 million. (2) 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 49 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 118 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 26. CONTINGENT PAYMENTS A) Sunrise Oil Sands Partnership In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS 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 payment over the remaining term of the contract is $194 million. The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re- measurement of contingent payments. In the year ended December 31, 2023, payments totaled $299 million for the quarterly payment periods ending November 30, 2022, February 28, 2023, May 31, 2023, and August 31, 2023. On May 17, 2022, the contingent payment obligation associated with the acquisition of 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended. The final payment of $177 million was made in Contingent Payments, Beginning of Year Initial Recognition Liabilities Settled or Payable Re-measurement Contingent Payments, End of Year Less: Current Portion Long-Term Portion B) FCCL Partnership July 2022. Contingent Payments, Beginning of Year Re-measurement Liabilities Settled Contingent Payments, End of Year 27. DECOMMISSIONING LIABILITIES Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) (2) Liabilities Settled Liabilities Divested (Note 5) (1) (2) Change in Estimated Future Cash Flows Change in Discount Rates Unwinding of Discount on Decommissioning Liabilities (Note 7) Exchange Rate Movements and Other Decommissioning Liabilities, End of Year 2023 419 — (314) 59 164 164 — 2023 3,559 14 5 (221) (5) 330 265 220 (12) 4,155 2022 — 600 (92) (89) 419 263 156 2022 236 251 (487) — 2022 3,906 22 48 (215) (89) 693 (980) 176 (2) 3,559 50 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Exploration and Evaluation Asset Write-downs (Income) Loss From Equity-Accounted Affiliates Unrealized (Gain) Loss on Risk Management Foreign Exchange (Gain) Loss, Net Revaluation (Gain) Loss Re-measurement of Contingent Payments (Gain) Loss on Divestiture of Assets Other (Income) Loss, Net Adjusted EBITDA (1) Net Debt to Adjusted EBITDA (times) (1) Calculated on a trailing twelve-month basis. 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 (times) (1) Calculated on a trailing twelve-month basis. Net Debt to Capitalization As at December 31, Net Debt Shareholders’ Equity Capitalization 2023 179 — 7,108 7,287 (2,227) 5,060 4,109 671 (133) 931 4,644 29 (51) 52 (67) 34 59 (14) (63) 0.5 2023 5,060 7,388 (222) (1,193) 8,803 0.6 2023 5,060 28,698 33,758 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) 0.3 2022 4,282 11,403 (150) 575 10,978 0.4 2022 4,282 27,576 31,858 10,201 13,227 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 26. CONTINGENT PAYMENTS A) Sunrise Oil Sands Partnership In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS 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 payment over the remaining term of the contract is $194 million. The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re- measurement of contingent payments. In the year ended December 31, 2023, payments totaled $299 million for the quarterly payment periods ending November 30, 2022, February 28, 2023, May 31, 2023, and August 31, 2023. Contingent Payments, Beginning of Year Initial Recognition Liabilities Settled or Payable Re-measurement Contingent Payments, End of Year Less: Current Portion Long-Term Portion B) FCCL Partnership 2023 419 — (314) 59 164 164 — 2022 — 600 (92) (89) 419 263 156 On May 17, 2022, the contingent payment obligation associated with the acquisition of 50 percent interest in the FCCL Partnership from ConocoPhillips Company and certain of its subsidiaries ended. The final payment of $177 million was made in July 2022. Contingent Payments, Beginning of Year Re-measurement Liabilities Settled Contingent Payments, End of Year 27. DECOMMISSIONING LIABILITIES Decommissioning Liabilities, Beginning of Year Liabilities Incurred Liabilities Acquired (Note 5) (1) (2) Liabilities Settled Liabilities Divested (Note 5) (1) (2) Change in Estimated Future Cash Flows Change in Discount Rates Unwinding of Discount on Decommissioning Liabilities (Note 7) Exchange Rate Movements and Other Decommissioning Liabilities, End of Year 2022 236 251 (487) — 2022 3,906 22 48 (215) (89) 693 (980) 176 (2) 3,559 2023 3,559 14 5 (221) (5) 330 265 220 (12) 4,155 (1) (2) In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities was $2 million. 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. Net Debt to Capitalization (percent) 15 13 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 49 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 50 CENOVUS ENERGY 2023 ANNUAL REPORT | 119 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation is $15.0 billion (December 31, 2022 – $14.2 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 $259 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 were discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2022 – 6.1 percent) and assumes an inflation rate of two percent (December 31, 2022 – 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, 2023, the Company had $211 million in restricted cash (December 31, 2022 – $209 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 28. OTHER LIABILITIES Sensitivity Range ± one percent ± one percent 2023 2022 Increase Decrease Increase Decrease (387) 519 515 (392) (319) 419 419 (320) As at December 31, Renewable Volume Obligation, Net (1) Pension and Other Post-Employment Benefit Plan Provision for West White Rose Expansion Project (2) Provisions for Onerous and Unfavourable Contracts Employee Long-Term Incentives Drilling Provisions Deferred Revenue Other 2023 2022 397 276 156 72 100 25 — 157 1,183 101 201 204 95 245 31 45 120 1,042 (1) (2) The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively). Cenovus expects to draw down the provision by $73 million in the next 12 months. 29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS The Company provides the majority of employees with a defined contribution pension plan (“DC 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 actuarial valuations of its registered defined benefit pension plans with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2022, and the next required actuarial valuation will be as at December 31, 2025. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2023, and the next required actuarial valuation will be as at January 1, 2024. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 51 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 120 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 A) Plan Obligations, Assets and Funded Status Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Current Service Costs Past Service Costs - Curtailment and Plan Amendments Interest Costs (1) Benefits Paid Plan Participant Contributions Re-measurements: (Gains) Losses From Experience Adjustments (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 Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (1) Re-measurements: Return on Plan Assets (Excluding Interest Income) Exchange Rate Movements and Other Fair Value of Plan Assets, End of Year DB Pension Plan OPEB Plans 2023 2022 2023 174 249 14 10 10 (9) — 1 50 (1) — 9 — (9) — — — — 172 10 — 9 (8) 3 4 13 (1) 202 147 18 3 (7) 8 10 (1) 178 (24) 220 16 — 7 (12) 2 1 2 (64) 172 159 16 2 (10) 4 (26) 2 147 (25) Defined Benefit Pension and OPEB Asset (Liability) (2) (249) (174) (1) (2) 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. The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 15 years and 14 years, respectively. B) Costs For the years ended December 31, Defined Benefit Plan Cost Current Service Costs Net Interest Costs Re-measurements: Past Service Costs – Curtailments and Plan Amendments 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. DB Pension Plan and DC Pension Plan OPEB Plans 2023 2022 2023 2022 (10) 10 — 1 4 — 13 18 99 117 16 — 3 26 1 — (64) (18) 72 54 14 10 10 — 1 — 50 85 — 85 2022 225 8 — 7 (8) — (2) (57) 1 174 — 8 — (8) — — — — 8 — 7 — (2) — (57) (44) — (44) 52 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation is $15.0 billion (December 31, 2022 – $14.2 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 $259 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 were discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2022 – 6.1 percent) and assumes an inflation rate of two percent (December 31, 2022 – 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, 2023, the Company had $211 million in restricted cash (December 31, 2022 – $209 million). Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning Sensitivity Range ± one percent ± one percent 2023 2022 Increase Decrease Increase Decrease (387) 519 515 (392) (319) 419 419 (320) Sensitivities liabilities: As at December 31, Credit-Adjusted Risk-Free Rate Inflation Rate 28. OTHER LIABILITIES As at December 31, Renewable Volume Obligation, Net (1) Pension and Other Post-Employment Benefit Plan Provision for West White Rose Expansion Project (2) Provisions for Onerous and Unfavourable Contracts Employee Long-Term Incentives Drilling Provisions Deferred Revenue Other (1) (2) Pension Plan”). 2023 2022 397 276 156 72 100 25 — 157 1,183 101 201 204 95 245 31 45 120 1,042 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 A) Plan Obligations, Assets and Funded Status Defined Benefit Obligation Defined Benefit Obligation, Beginning of Year Current Service Costs Past Service Costs - Curtailment and Plan Amendments Interest Costs (1) Benefits Paid Plan Participant Contributions Re-measurements: (Gains) Losses From Experience Adjustments (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 Employer Contributions Plan Participant Contributions Benefits Paid Interest Income (1) Re-measurements: Return on Plan Assets (Excluding Interest Income) Exchange Rate Movements and Other Fair Value of Plan Assets, End of Year Defined Benefit Pension and OPEB Asset (Liability) (2) DB Pension Plan OPEB Plans 2023 2022 172 10 — 9 (8) 3 4 13 (1) 202 147 18 3 (7) 8 10 (1) 178 (24) 220 16 — 7 (12) 2 1 (64) 2 172 159 16 2 (10) 4 (26) 2 147 (25) 2023 174 14 10 10 (9) — 1 50 (1) 249 — 9 — (9) — — — — 2022 225 8 — 7 (8) — (2) (57) 1 174 — 8 — (8) — — — — (249) (174) The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively). Cenovus expects to draw down the provision by $73 million in the next 12 months. The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 15 years and 14 years, respectively. (1) (2) 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. 29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS The Company provides the majority of employees with a defined contribution pension plan (“DC 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 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 actuarial valuations of its registered defined benefit pension plans with regulators on a periodic basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2022, and the next required actuarial valuation will be as at December 31, 2025. The most recently filed valuation for the U.S. defined benefit pension plan was dated January 1, 2023, and the next required actuarial valuation will be as at January 1, 2024. B) Costs For the years ended 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 51 Cenovus Energy Inc. – 2023 Consolidated Financial Statements DB Pension Plan and DC Pension Plan OPEB Plans 2023 2022 2023 2022 10 — 1 (10) 4 — 13 18 99 117 16 — 3 26 1 — (64) (18) 72 54 14 10 10 — 1 — 50 85 — 85 8 — 7 — (2) — (57) (44) — (44) 52 CENOVUS ENERGY 2023 ANNUAL REPORT | 121 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 that 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. The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage these risks from prior periods. The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows: As at December 31, Level 1 – Cash and Cash Equivalents Level 2 – Equity and Fixed Income Funds Level 3 – Real Estate Funds and Other 2023 5 161 12 178 2022 7 130 10 147 30. SHARE CAPITAL AND WARRANTS 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 the direction of the Management Pension Committees 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, 2024, the Company expects to contribute $11 million to the DB Pension Plan. The OPEB plans are funded on an as required basis. For the year ended December 31, 2024, the Company expects to contribute $13 million to the OPEB plans. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions The principal weighted average actuarial assumptions used to determine benefit obligations are as follows: For the years ended December 31, Discount Rate (percent) Future Salary Growth Rate (percent) Average Longevity (years) Health Care Cost Trend Rate (percent) Defined Benefit Plan OPEB Plans 2023 4.58 4.00 88.4 N/A 2022 5.12 4.05 88.4 N/A 2023 4.65 N/A 88.4 5.24 2022 5.13 N/A 88.4 5.24 Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the benefit obligations. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while holding all other assumptions constant, would result in a sensitivity to change as follows: 2023 2022 Increase Decrease (54) 66 Increase (43) Decrease 51 Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated Sensitivities As at December 31, Discount Rate Balance Sheets. 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 2023 2022 Number of Common Shares (thousands) 1,909,190 2,610 3,679 (43,611) 1,871,868 Number of Common Shares (thousands) 2,001,211 9,399 11,069 (112,489) 1,909,190 Amount 16,320 26 58 (373) 16,031 Amount 17,016 93 170 (959) 16,320 Outstanding, Beginning of Year Issued Upon Exercise of Warrants Issued Under Stock Option Plans Purchase of Common Shares under NCIB Outstanding, End of Year issuance under the stock option plan. C) Normal Course Issuer Bid As at December 31, 2023, there were 45.5 million (December 31, 2022 – 43.1 million) common shares available for future On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares during the period from November 9, 2023, to November 8, 2024. For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares (2022 – 112.5 million) through the NCIB. The shares were purchased at a volume weighted average price of $24.32 per common share (2022 – $22.49) for a total of $1.1 billion (2022 – $2.5 billion). Paid in surplus was reduced by $688 million (2022 – $1.6 billion), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million. As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the NCIB. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 53 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 54 122 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 that 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. 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 The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows: these risks from prior periods. As at December 31, Level 1 – Cash and Cash Equivalents Level 2 – Equity and Fixed Income Funds Level 3 – Real Estate Funds and Other D) Funding DB Pension Plan. $13 million to the OPEB plans. E) Actuarial Assumptions and Sensitivities Actuarial Assumptions For the years ended December 31, Discount Rate (percent) Future Salary Growth Rate (percent) Average Longevity (years) Health Care Cost Trend Rate (percent) benefit obligations. 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 the direction of the Management Pension Committees 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, 2024, the Company expects to contribute $11 million to the The OPEB plans are funded on an as required basis. For the year ended December 31, 2024, the Company expects to contribute The principal weighted average actuarial assumptions used to determine benefit obligations are as follows: Defined Benefit Plan OPEB Plans 2023 4.58 4.00 88.4 N/A 2022 5.12 4.05 88.4 N/A 2023 4.65 N/A 88.4 5.24 2022 5.13 N/A 88.4 5.24 Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the 2023 5 161 12 178 2022 7 130 10 147 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Sensitivities The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while holding all other assumptions constant, would result in a sensitivity to change as follows: As at December 31, Discount Rate 2023 2022 Increase Decrease (54) 66 Increase (43) Decrease 51 Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated Balance Sheets. 30. SHARE CAPITAL AND WARRANTS A) Authorized Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject to the Company’s articles. B) Issued and Outstanding – Common Shares Outstanding, Beginning of Year Issued Upon Exercise of Warrants Issued Under Stock Option Plans Purchase of Common Shares under NCIB Outstanding, End of Year 2023 2022 Number of Common Shares (thousands) 1,909,190 2,610 3,679 (43,611) 1,871,868 Number of Common Shares (thousands) 2,001,211 9,399 11,069 (112,489) 1,909,190 Amount 16,320 26 58 (373) 16,031 Amount 17,016 93 170 (959) 16,320 As at December 31, 2023, there were 45.5 million (December 31, 2022 – 43.1 million) common shares available for future issuance under the stock option plan. C) Normal Course Issuer Bid On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to 133.2 million common shares during the period from November 9, 2023, to November 8, 2024. For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares (2022 – 112.5 million) through the NCIB. The shares were purchased at a volume weighted average price of $24.32 per common share (2022 – $22.49) for a total of $1.1 billion (2022 – $2.5 billion). Paid in surplus was reduced by $688 million (2022 – $1.6 billion), representing the excess of the purchase price of the common shares over their average carrying value. From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million. As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the NCIB. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 53 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 54 CENOVUS ENERGY 2023 ANNUAL REPORT | 123 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 D) Issued and Outstanding – Preferred Shares For the year ended December 31, 2023, there were no preferred shares issued. As at December 31, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million). As at December 31, 2023 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 March 31, 2026 Quarterly December 31, 2024 March 31, 2025 June 30, 2025 Dividend Rate (percent) 2.58 6.77 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 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023 (June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to December 30, 2022 – 5.05 percent). 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, 2023 (December 31, 2022 – nil). Cenovus Energy Inc. – 2023 Consolidated Financial Statements 55 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 124 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 E) Issued and Outstanding – Warrants Outstanding, Beginning of Year Exercised Purchased and Cancelled Outstanding, End of Year 2023 2022 Number of Warrants (thousands) 55,720 (2,610) (45,485) 7,625 Number of Warrants (thousands) 65,119 (9,399) — 55,720 Amount 184 (8) (151) 25 Amount 215 (31) — 184 The exercise price of the warrants is $6.54 per share. On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their average carrying value, and $2 million in transaction costs. The purchased warrants were paid in full by December 31, 2023. 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 the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIB and stock-based compensation expense related to the Company’s NSRs discussed in Note 32. As at December 31, 2021 Stock-Based Compensation Expense Purchase of Common Shares Under NCIB Common Shares Issued on Exercise of Stock Options As at December 31, 2022 Stock-Based Compensation Expense Purchase of Common Shares Under NCIB Common Shares Issued on Exercise of Stock Options As at December 31, 2023 31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) As at December 31, 2021 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2022 Other Comprehensive Income (Loss), Before Tax Reclassification on Divestiture (Note 5) Income Tax (Expense) Recovery As at December 31, 2023 28 96 (25) 99 (58) — 14 55 Retained Earnings Prior Stock-Based to Ovintiv Split Compensation (1,571) 3,966 — — — — 2,395 (688) 1,707 27 2 — 29 63 — (7) 85 318 10 — (32) 296 11 — (12) 295 629 713 — 1,342 (286) 12 — 1,068 Pension and Other Post- Retirement Benefits Private Equity Instruments Foreign Currency Translation Adjustment Total 4,284 10 (1,571) (32) 2,691 11 (688) (12) 2,002 Total 684 811 (25) 1,470 (281) 12 7 1,208 56 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 D) Issued and Outstanding – Preferred Shares For the year ended December 31, 2023, there were no preferred shares issued. As at December 31, 2023, there were 36 million preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 – $519 million). As at December 31, 2023 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 March 31, 2026 Quarterly December 31, 2024 March 31, 2025 June 30, 2025 Dividend Rate (percent) 2.58 6.77 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 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023 (June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to December 30, 2022 – 5.05 percent). 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, 2023 (December 31, 2022 – nil). NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 E) Issued and Outstanding – Warrants Outstanding, Beginning of Year Exercised Purchased and Cancelled Outstanding, End of Year 2023 2022 Number of Warrants (thousands) 55,720 (2,610) (45,485) 7,625 Number of Warrants (thousands) 65,119 (9,399) — 55,720 Amount 184 (8) (151) 25 Amount 215 (31) — 184 The exercise price of the warrants is $6.54 per share. On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million. Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their average carrying value, and $2 million in transaction costs. The purchased warrants were paid in full by December 31, 2023. 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 the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIB and stock-based compensation expense related to the Company’s NSRs discussed in Note 32. As at December 31, 2021 Stock-Based Compensation Expense Purchase of Common Shares Under NCIB Common Shares Issued on Exercise of Stock Options As at December 31, 2022 Stock-Based Compensation Expense Purchase of Common Shares Under NCIB Common Shares Issued on Exercise of Stock Options As at December 31, 2023 31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) Retained Earnings Prior to Ovintiv Split Stock-Based Compensation 3,966 — (1,571) — 2,395 — (688) — 1,707 318 10 — (32) 296 11 — (12) 295 As at December 31, 2021 Other Comprehensive Income (Loss), Before Tax Income Tax (Expense) Recovery As at December 31, 2022 Other Comprehensive Income (Loss), Before Tax Reclassification on Divestiture (Note 5) Income Tax (Expense) Recovery As at December 31, 2023 Pension and Other Post- Retirement Benefits 28 Private Equity Instruments 27 96 (25) 99 (58) — 14 55 2 — 29 63 — (7) 85 Foreign Currency Translation Adjustment 629 713 — 1,342 (286) 12 — 1,068 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 55 Cenovus Energy Inc. – 2023 Consolidated Financial Statements Total 4,284 10 (1,571) (32) 2,691 11 (688) (12) 2,002 Total 684 811 (25) 1,470 (281) 12 7 1,208 56 CENOVUS ENERGY 2023 ANNUAL REPORT | 125 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 32. STOCK-BASED COMPENSATION PLANS Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs. On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus common share. The number of units 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. The RSUs are whole-share units and entitle employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share. A) Employee Stock Options Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. Options issued by the Company have associated NSRs. The NSR, 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 term and conditions of the underlying option. Stock Options With Associated Net Settlement Rights The weighted average unit fair value of NSRs granted during the year ended December 31, 2023, was $7.41 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate (percent) Expected Dividend Yield (percent) Expected Volatility (1) (percent) Expected Life (years) (1) Expected volatility has been based on historical share volatility of the Company. For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Exercised Forfeited Expired Outstanding, End of Year 3.42 1.78 31.95 5.45 Number of Stock Options with Associated Net Settlement Rights (thousands) Weighted Average Exercise Price ($/unit) 14,349 1,571 (3,839) (128) (58) 11,895 12.38 24.34 13.08 15.78 19.89 13.66 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023 Range of Exercise Price ($) 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 Outstanding Exercisable Number of Stock Options with Associated Net Settlement Rights (thousands) Weighted Average Remaining Contractual Number of Stock Options with Associated Net Settlement Weighted Average Weighted Average Life Exercise Price Rights Exercise Price (years) ($/unit) (thousands) ($/unit) 4,303 4,163 1,851 1,561 17 11,895 3.83 2.92 5.13 6.17 6.70 4.03 8.77 11.93 19.88 24.25 27.71 13.66 2,218 3,894 536 10 — 6,658 8.85 11.94 19.88 22.75 — 11.56 Cenovus Replacement Stock Options For the year ended December 31, 2023, 2.1 million Cenovus replacement stock options, with a weighted average exercise price of $9.98, were exercised and net settled for cash and 3 thousand Cenovus replacement stock options were exercised with a weighted average price of $3.54 and settled for 2 thousand common shares. The Company recorded a liability of $12 million as at December 31, 2023, (December 31, 2022 – $42 million) for Cenovus replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model. Number of Cenovus Replacement Stock Options (thousands) Weighted Average Exercise Price ($/unit) 3,467 (2,113) (23) (326) 1,005 Exercisable 9.99 9.97 6.58 21.09 6.49 3.54 6.19 — 18.35 6.49 Outstanding Weighted Average Remaining Contractual Number of Cenovus Replacement Stock Options (thousands) Weighted Average Number of Cenovus Replacement Weighted Average Life Exercise Price Stock Options Exercise Price (years) ($/unit) (thousands) ($/unit) 782 28 — 195 1,005 1.22 0.42 — 0.18 0.99 3.54 6.19 — 18.35 6.49 782 28 — 195 1,005 For the year ended December 31, 2023 Outstanding, Beginning of Year Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2023 Range of Exercise Price ($) 3.00 to 4.99 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 B) Performance Share Units Cenovus common share. In addition to the Performance Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. The 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 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 57 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 58 126 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 32. STOCK-BASED COMPENSATION PLANS Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, PSUs, RSUs and DSUs. On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus common share. The number of units 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. The RSUs are whole-share units and entitle employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share. A) Employee Stock Options Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a common share of the Company. Option exercise prices approximate the market value for the common shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years. Options issued by the Company have associated NSRs. The NSR, 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 term and conditions of the underlying option. Stock Options With Associated Net Settlement Rights The weighted average unit fair value of NSRs granted during the year ended December 31, 2023, was $7.41 before considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows: Risk-Free Interest Rate (percent) Expected Dividend Yield (percent) Expected Volatility (1) (percent) Expected Life (years) (1) Expected volatility has been based on historical share volatility of the Company. 3.42 1.78 31.95 5.45 12.38 24.34 13.08 15.78 19.89 13.66 Number of Stock Options with Associated Net Settlement Rights (thousands) Weighted Average Exercise Price ($/unit) 14,349 1,571 (3,839) (128) (58) 11,895 For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Exercised Forfeited Expired Outstanding, End of Year NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023 Range of Exercise Price ($) 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 20.00 to 24.99 25.00 to 29.99 Outstanding Exercisable Number of Stock Options with Associated Net Settlement Rights (thousands) 4,303 4,163 1,851 1,561 17 11,895 Weighted Average Remaining Contractual Life Weighted Average Exercise Price (years) 3.83 2.92 5.13 6.17 6.70 4.03 ($/unit) 8.77 11.93 19.88 24.25 27.71 13.66 Number of Stock Options with Associated Net Settlement Rights (thousands) 2,218 3,894 536 10 — 6,658 Weighted Average Exercise Price ($/unit) 8.85 11.94 19.88 22.75 — 11.56 Cenovus Replacement Stock Options For the year ended December 31, 2023, 2.1 million Cenovus replacement stock options, with a weighted average exercise price of $9.98, were exercised and net settled for cash and 3 thousand Cenovus replacement stock options were exercised with a weighted average price of $3.54 and settled for 2 thousand common shares. The Company recorded a liability of $12 million as at December 31, 2023, (December 31, 2022 – $42 million) for Cenovus replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model. Number of Cenovus Replacement Stock Options (thousands) Weighted Average Exercise Price ($/unit) 3,467 (2,113) (23) (326) 1,005 Exercisable 9.99 9.97 6.58 21.09 6.49 Weighted Average Exercise Price ($/unit) 3.54 6.19 — 18.35 6.49 Number of Cenovus Replacement Stock Options (thousands) 782 28 — 195 1,005 Weighted Average Exercise Price ($/unit) 3.54 6.19 — 18.35 6.49 Outstanding Weighted Average Remaining Contractual Life (years) 1.22 0.42 — 0.18 0.99 Number of Cenovus Replacement Stock Options (thousands) 782 28 — 195 1,005 For the year ended December 31, 2023 Outstanding, Beginning of Year Exercised Forfeited Expired Outstanding, End of Year As at December 31, 2023 Range of Exercise Price ($) 3.00 to 4.99 5.00 to 9.99 10.00 to 14.99 15.00 to 19.99 B) Performance Share Units In addition to the Performance Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. The 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 57 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 58 CENOVUS ENERGY 2023 ANNUAL REPORT | 127 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The Company has recorded a liability of $238 million as at December 31, 2023, (December 31, 2022 – $216 million) 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, 2023. For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Vested and Paid Out Forfeited Units in Lieu of Base Dividends Outstanding, End of Year C) Restricted Share Units Number of Performance Share Units (thousands) 8,678 2,539 (972) (231) 229 10,243 In addition to the Restricted Share Unit Plan for Local Employees in the Asia Pacific Region, 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 $97 million as at December 31, 2023, (December 31, 2022 – $109 million) 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, 2023. For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Vested and Paid Out Forfeited Units in Lieu of Base Dividends Outstanding, End of Year D) Deferred Share Units Number of Restricted Share Units (thousands) 6,655 2,961 (2,300) (243) 161 7,234 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 settled in cash and 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 $37 million as at December 31, 2023 (December 31, 2022 – $40 million) 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. For the year ended December 31, 2023 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year Cenovus Energy Inc. – 2023 Consolidated Financial Statements 128 | CENOVUS ENERGY 2023 ANNUAL REPORT Number of Deferred Share Units (thousands) 1,506 126 59 37 (37) 1,691 59 2023 11 (5) 47 46 (2) 97 2023 1,344 125 97 — 14 1,580 2023 40 3 40 — 83 2022 15 53 183 100 22 373 2022 1,246 92 373 (9) 27 1,729 2022 40 4 140 3 187 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Total Stock-Based Compensation Expense (Recovery) 33. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Pension and Post-Employment Benefits Stock-Based Compensation (Note 32) Other Incentive Benefits (Recovery) Termination Benefits 34. RELATED PARTY TRANSACTIONS A) Key Management Compensation For the years ended December 31, Salaries, Director Fees and Other Short-Term Benefits Pension and Post-Employment Benefits Stock-Based Compensation Termination Benefits B) Other Related Party Transactions 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: Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 21). 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, 2023, the Company charged HMLP $160 million (2022 – $188 million) for construction costs and management services. The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2023, the Company incurred costs of $295 million (2022 – $263 million) for the use of HMLP’s pipeline systems, as well as transportation and storage services. 35. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and certain portions of other assets 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 60 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The Company has recorded a liability of $238 million as at December 31, 2023, (December 31, 2022 – $216 million) 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, 2023. In addition to the Restricted Share Unit Plan for Local Employees in the Asia Pacific Region, 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 $97 million as at December 31, 2023, (December 31, 2022 – $109 million) 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, 2023. 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 settled in cash and 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 $37 million as at December 31, 2023 (December 31, 2022 – $40 million) 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. For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Forfeited Vested and Paid Out Units in Lieu of Base Dividends Outstanding, End of Year C) Restricted Share Units For the year ended December 31, 2023 Outstanding, Beginning of Year Granted Forfeited Vested and Paid Out Units in Lieu of Base Dividends Outstanding, End of Year D) Deferred Share Units For the year ended December 31, 2023 Outstanding, Beginning of Year Granted to Directors Granted Units in Lieu of Dividends Redeemed Outstanding, End of Year Number of Performance Share Units (thousands) 8,678 2,539 (972) (231) 229 10,243 Number of Restricted Share Units (thousands) 6,655 2,961 (2,300) (243) 161 7,234 Number of Deferred Share Units (thousands) 1,506 126 59 37 (37) 1,691 59 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 Total Stock-Based Compensation Expense (Recovery) 33. EMPLOYEE SALARIES AND BENEFIT EXPENSES For the years ended December 31, Salaries, Bonuses and Other Short-Term Employee Benefits Pension and Post-Employment Benefits Stock-Based Compensation (Note 32) Other Incentive Benefits (Recovery) Termination Benefits 34. RELATED PARTY TRANSACTIONS A) Key Management Compensation 2023 11 (5) 47 46 (2) 97 2023 1,344 125 97 — 14 1,580 2022 15 53 183 100 22 373 2022 1,246 92 373 (9) 27 1,729 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 Pension and Post-Employment Benefits Stock-Based Compensation Termination Benefits B) Other Related Party Transactions 2023 40 3 40 — 83 2022 40 4 140 3 187 Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 21). 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, 2023, the Company charged HMLP $160 million (2022 – $188 million) for construction costs and management services. The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays HMLP for transportation and storage services. For the year ended December 31, 2023, the Company incurred costs of $295 million (2022 – $263 million) for the use of HMLP’s pipeline systems, as well as transportation and storage services. 35. FINANCIAL INSTRUMENTS Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent payments, long-term debt and certain portions of other assets 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements Cenovus Energy Inc. – 2023 Consolidated Financial Statements 60 CENOVUS ENERGY 2023 ANNUAL REPORT | 129 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to the specific non-tradeable nature of these instruments. Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2023, the carrying value of Cenovus’s long-term debt was $7.1 billion and the fair value was $6.6 billion (December 31, 2022 carrying value – $8.7 billion, fair value – $7.8 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 in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Fair Value of Contracts, Beginning of Year 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 The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI: Offsetting Financial Assets and Liabilities Fair Value, Beginning of Year Acquisition Changes in Fair Value Fair Value, End of Year 2023 55 13 63 131 2022 53 — 2 55 B) Fair Value of Risk Management Assets and Liabilities Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other liabilities and other assets (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management. The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and options to manage commodity, foreign exchange and interest rate exposures. Crude oil, natural gas, condensate, refined product and power contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data and foreign exchange forward 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. Summary of Risk Management Positions As at December 31, Asset Liability Net Asset Liability 2023 Risk Management 2022 Risk Management Crude Oil, Natural Gas, Condensate and Refined Products Power Swap Contracts Renewable Power Contracts 11 2 18 31 19 — — 19 (8) 2 18 12 2 1 90 93 40 7 — 47 Net (38) (6) 90 46 The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities: 2023 (45) 46 — 9 2 12 2022 (68) (5) (1,641) 1,762 (2) 46 Net 46 — 46 2023 9 52 61 2022 1,762 (126) 1,636 Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same. 2023 Risk Management 2022 Risk Management As at December 31, Asset Liability Net Asset Liability Recognized Risk Management Positions Gross Amount Amount Offset Net Amount 71 (40) 31 59 (40) 19 12 — 12 153 (60) 93 107 (60) 47 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, 2023, $47 million was pledged as cash collateral (December 31, 2022 – $211 million). C) Earnings Impact of (Gains) Losses From Risk Management Positions For the years ended December 31, Realized (Gain) Loss Unrealized (Gain) Loss (Gain) Loss on Risk Management instrument relates. D) Fair Value of Contingent Payments Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the contingent payments. Fair value is 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 WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair value of the variable payment was 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, 2023, the fair value of the variable payment was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent. As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment is $71.86 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively. As at December 31, 2023 and December 31, 2022, changes in WCS forward prices, with fluctuations in all other variables held constant, could have impacted earnings before income tax as follows: As at December 31, WCS Forward Prices Sensitivity Range ± $10.00 per barrel Increase (21) Decrease 45 2023 2022 Increase (68) Decrease 157 Level 2 – Prices Sourced From Observable Data or Market Corroboration Level 3 – Prices Sourced From Partially Unobservable Data (6) 18 12 (44) 90 46 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 61 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 62 130 | CENOVUS ENERGY 2023 ANNUAL REPORT The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value: As at December 31, 2022 2023 the specific non-tradeable nature of these instruments. Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2023, the carrying value of Cenovus’s long-term debt was $7.1 billion and the fair value was $6.6 billion (December 31, 2022 carrying value – $8.7 billion, fair value – $7.8 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 in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. Fair Value, Beginning of Year Acquisition Changes in Fair Value Fair Value, End of Year 2023 55 13 63 131 2022 53 — 2 55 B) Fair Value of Risk Management Assets and Liabilities Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable and accrued liabilities (for short-term positions), other liabilities and other assets (for long-term positions). Changes in fair value are recorded in (gain) loss on risk management. The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures, as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and options to manage commodity, foreign exchange and interest rate exposures. Crude oil, natural gas, condensate, refined product and power contracts are recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data and foreign exchange forward 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. Summary of Risk Management Positions 2023 Risk Management 2022 Risk Management Crude Oil, Natural Gas, Condensate and Refined Products Power Swap Contracts Renewable Power Contracts 11 2 18 31 19 — — 19 (8) 2 18 12 2 1 90 93 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 Unobservable Data Net (38) (6) 90 46 2022 (44) 90 46 40 7 — 47 2023 (6) 18 12 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities: Fair Value of Contracts, Beginning of Year 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 2023 46 — (45) 9 2 12 2022 (68) (5) (1,641) 1,762 (2) 46 The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI: Offsetting Financial Assets and Liabilities Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same. 2023 Risk Management 2022 Risk Management As at December 31, Asset Liability Net Asset Liability Recognized Risk Management Positions Gross Amount Amount Offset Net Amount 71 (40) 31 59 (40) 19 12 — 12 153 (60) 93 107 (60) 47 Net 46 — 46 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, 2023, $47 million was pledged as cash collateral (December 31, 2022 – $211 million). C) Earnings Impact of (Gains) Losses From Risk Management Positions For the years ended December 31, Realized (Gain) Loss Unrealized (Gain) Loss (Gain) Loss on Risk Management 2023 9 52 61 2022 1,762 (126) 1,636 Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. As at December 31, Asset Liability Net Asset Liability D) Fair Value of Contingent Payments The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the contingent payments. Fair value is 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 WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair value of the variable payment was 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, 2023, the fair value of the variable payment was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent. As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment is $71.86 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively. As at December 31, 2023 and December 31, 2022, changes in WCS forward prices, with fluctuations in all other variables held constant, could have impacted earnings before income tax as follows: As at December 31, WCS Forward Prices Sensitivity Range ± $10.00 per barrel Increase (21) Decrease 45 2023 2022 Increase (68) Decrease 157 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 61 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 62 CENOVUS ENERGY 2023 ANNUAL REPORT | 131 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023 and December 31, 2022, a 10 percent increase or decrease in WTI option price volatility, or a five percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility would have resulted in nominal changes to earnings before income tax. 36. 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, such as renewable power contracts or power swaps, to manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions. To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2023, the fair value of risk management positions was a net asset of $12 million (see Note 35). As at December 31, 2023, there were no foreign exchange contracts, interest rate contracts or cross currency interest rate swap contracts outstanding. As at December 31, 2022, there were forward exchange contracts with a notional value of US$168 million outstanding and there were no interest rate contracts or cross currency interest rate swap contracts outstanding. Net Fair Value of Risk Management Positions As at December 31, 2023 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) Terms (3) Weighted Average Price (1) (2) Fair Value Asset (Liability) 3.5 MMbbls January 2024 – December 2024 US$75.22/bbl 1.5 MMbbls January 2024 – December 2024 US$73.69/bbl 16 (4) 2 18 (20) 12 (1) Million barrels ("MMbbls"). (2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month. Includes individual contracts with varying terms, the longest of which is 13 months. (3) (4) WTI futures contracts are used to help manage price exposure to condensate used for blending. (5) Includes 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 and the Company’s U.S. refining and marketing activities. A) Commodity Price and Foreign Exchange 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. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 63 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 64 132 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 and condensate transactions 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, 2023, Cenovus had US$3.8 billion in U.S. dollar debt (December 31, 2022 – US$4.8 billion). iii) Commodity Price and Foreign Exchange Rate Sensitivities The following tables summarize 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 tables below are a reasonable measure of volatility. The impact of the below 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, 2023 Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges Sensitivity Range Increase Decrease 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). As at December 31, 2023, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: (primarily WTI). price. A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate. As at December 31, 2022 Sensitivity Range WCS and Condensate Differential Price ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production Power Commodity Price ± C$20.00/MWh Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate Increase Decrease 13 113 14 (13) (113) (17) As at December 31, 2022, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price income tax: (primarily WTI). A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A $0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. • • • • • • • • • • • • NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023 and December 31, 2022, a 10 percent increase or decrease in WTI option price volatility, or a five percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility would have resulted in nominal changes to earnings before income tax. 36. 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, such as renewable power contracts or power swaps, to manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation and refining of crude oil, or to offset select carbon emissions. To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2023, the fair value of risk management positions was a net asset of $12 million (see Note 35). As at December 31, 2023, there were no foreign exchange contracts, interest rate contracts or cross currency interest rate swap contracts outstanding. As at December 31, 2022, there were forward exchange contracts with a notional value of US$168 million outstanding and there were no interest rate contracts or cross currency interest rate swap contracts outstanding. Net Fair Value of Risk Management Positions As at December 31, 2023 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 (1) Million barrels ("MMbbls"). Notional Volumes (1) (2) Terms (3) Weighted Average Price (1) (2) Fair Value Asset (Liability) 3.5 MMbbls January 2024 – December 2024 US$75.22/bbl 1.5 MMbbls January 2024 – December 2024 US$73.69/bbl 16 (4) 2 18 (20) 12 (2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the notional volumes and weighted average price may fluctuate from month to month. (3) Includes individual contracts with varying terms, the longest of which is 13 months. (4) WTI futures contracts are used to help manage price exposure to condensate used for blending. (5) Includes 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 and the Company’s U.S. refining and marketing activities. A) Commodity Price and Foreign Exchange 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 and condensate transactions 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, 2023, Cenovus had US$3.8 billion in U.S. dollar debt (December 31, 2022 – US$4.8 billion). iii) Commodity Price and Foreign Exchange Rate Sensitivities The following tables summarize 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 tables below are a reasonable measure of volatility. The impact of the below 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, 2023 Power Commodity Price ± C$20.00/MWh (1) Applied to Power Hedges Sensitivity Range Increase Decrease 92 (92) (1) One thousand kilowatts of electricity per hour (“MWh”). As at December 31, 2023, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: • • • • • • • A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price (primarily WTI). A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential price. A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate. As at December 31, 2022 WCS and Condensate Differential Price Power Commodity Price Sensitivity Range ± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production ± C$20.00/MWh Applied to Power Hedges U.S. to Canadian Dollar Exchange Rate ± $0.05 in the U.S. to Canadian Dollar Exchange Rate Increase Decrease 13 113 14 (13) (113) (17) As at December 31, 2022, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax: • • • • • A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price (primarily WTI). A US$5.00 per barrel increase or decrease in the WCS differential price. A US$10.00 per barrel increase or decrease in refined products commodity prices. A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price. A $0.50 per one thousand cubic feet increase or decrease in natural gas basis prices. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 63 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 64 CENOVUS ENERGY 2023 ANNUAL REPORT | 133 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 B) Credit Risk 2023 197 (197) 2022 246 (246) 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, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average ECL on these accounts was 0.4 percent as at December 31, 2023 (December 31, 2022 – 0.4 percent). C) Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt, by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings, and by ensuring that it has access to multiple sources of capital. As disclosed in Note 25, 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. As at December 31, 2023, the Company’s sources of capital included: • • • • • $2.2 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 $1.1 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. US$90 million (C$119 million) on the Company’s proportionate share of the uncommitted demand facilities from WRB. The base shelf prospectus, availability of which is dependent on market conditions. NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 Undiscounted cash outflows relating to financial liabilities are: As at December 31, 2023 Accounts Payable and Accrued Liabilities (1) Short-Term Borrowings Contingent Payments Lease Liabilities (2) Long-Term Debt (2) Short-Term Borrowings Contingent Payments Lease Liabilities (2) Long-Term Debt (2) As at December 31, 2022 Accounts Payable and Accrued Liabilities (1) 1 Year 5,480 179 168 438 313 1 Year 6,124 115 271 426 401 Years 2 and 3 Years 4 and 5 Thereafter 569 3,007 2,635 7,145 Years 2 and 3 Years 4 and 5 Thereafter — — — — — — — — — 712 792 — — 167 746 983 596 2,014 2,889 11,196 (1) (2) Includes current risk management liabilities. Principal and interest, including current portion, if applicable. 37. SUPPLEMENTARY CASH FLOW INFORMATION A) Working Capital As at December 31, Total Current Assets Total Current Liabilities Working Capital $3.7 billion (December 31, 2022 – $4.7 billion). 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 — — — — — — 2023 9,708 6,210 3,498 2023 314 (295) 216 (685) (1,112) (1,562) (1,193) (369) (1,562) 2023 402 130 2,595 Total 5,480 179 168 4,354 11,257 Total 6,124 115 438 4,657 14,594 2022 12,430 8,021 4,409 2022 838 (58) (143) (524) 1,000 1,113 575 538 1,113 2022 647 78 723 As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was Cenovus Energy Inc. – 2023 Consolidated Financial Statements 65 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 66 134 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 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 B) Credit Risk 2023 197 (197) 2022 246 (246) 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, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated average ECL on these accounts was 0.4 percent as at December 31, 2023 (December 31, 2022 – 0.4 percent). C) Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its liquidity risk through the active management of cash and debt, by maintaining appropriate access to credit, which may be impacted by the Company’s credit ratings, and by ensuring that it has access to multiple sources of capital. As disclosed in Note 25, 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. As at December 31, 2023, the Company’s sources of capital included: $2.2 billion in cash and cash equivalents. $5.5 billion available on its committed credit facility. • • • • • WRB. $1.4 billion available on its uncommitted demand facilities, of which $1.1 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. US$90 million (C$119 million) on the Company’s proportionate share of the uncommitted demand facilities from The base shelf prospectus, availability of which is dependent on market conditions. In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have Undiscounted cash outflows relating to financial liabilities are: NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 As at December 31, 2023 Accounts Payable and Accrued Liabilities (1) Short-Term Borrowings Contingent Payments Lease Liabilities (2) Long-Term Debt (2) As at December 31, 2022 Accounts Payable and Accrued Liabilities (1) Short-Term Borrowings Contingent Payments Lease Liabilities (2) Long-Term Debt (2) 1 Year 5,480 179 168 438 313 1 Year 6,124 115 271 426 401 Years 2 and 3 Years 4 and 5 Thereafter — — — 712 792 — — — 569 3,007 — — — 2,635 7,145 Years 2 and 3 Years 4 and 5 Thereafter — — 167 746 983 — — — 596 2,014 — — — 2,889 11,196 Total 5,480 179 168 4,354 11,257 Total 6,124 115 438 4,657 14,594 (1) (2) Includes current risk management liabilities. Principal and interest, including current portion, if applicable. 37. SUPPLEMENTARY CASH FLOW INFORMATION A) Working Capital As at December 31, Total Current Assets Total Current Liabilities Working Capital 2023 9,708 6,210 3,498 2022 12,430 8,021 4,409 As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was $3.7 billion (December 31, 2022 – $4.7 billion). 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 2023 314 (295) 216 (685) (1,112) (1,562) (1,193) (369) (1,562) 2023 402 130 2,595 2022 838 (58) (143) (524) 1,000 1,113 575 538 1,113 2022 647 78 723 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 65 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 66 CENOVUS ENERGY 2023 ANNUAL REPORT | 135 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 B) Reconciliation of Liabilities The following table provides a reconciliation of liabilities to cash flows arising from financing activities: Dividends Payable Warrant Purchase Payable Short-Term Borrowings Long-Term Debt 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 and Transaction Costs Lease Additions 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 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 Dividends Paid on Preferred Shares Payment for Purchase of Warrants Finance and Transaction Costs Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance and Transaction Costs Lease Acquisitions Lease Additions Lease Divestitures Base Dividends Declared on Common Shares Dividends Declared on Preferred Shares Warrants Purchased and Cancelled Exchange Rate Movements and Other As at December 31, 2023 — — — — (682) (219) (26) — — — 682 219 35 — 9 — — — (990) (36) — — — — — — — 990 36 — — 9 — — — — — — — — — — — — — — — — — — — — (711) (2) — 2 — — — — — 711 — — 79 34 — — — — — — — — — — — 2 115 58 — — — — — — — — — — — — — — 6 179 12,385 — (4,149) — — — — (29) (28) — — — — 512 8,691 — (1,346) — — — — — (84) (19) — — — — — — (134) 7,108 Lease Liabilities 2,957 — — (302) — — — — — 25 — — — 156 2,836 — — (288) — — — — — — 33 57 (11) — — — 31 2,658 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 38. 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, 2023 Transportation and Storage (1) (2) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments (3) Total Commitments As at December 31, 2022 Transportation and Storage (1) (2) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments Total Commitments 1 Year 2,018 617 57 94 417 3,203 1 Year 1,747 1,626 48 92 381 3,894 2 Years 1,927 3 Years 1,680 4 Years 1,663 5 Years Thereafter 1,641 15,738 — 57 94 194 2,272 2,011 1,509 50 105 90 — 59 94 184 2,017 1,542 922 50 96 75 — 63 89 175 1,990 1,416 922 50 96 74 — 58 52 166 1,917 1,360 922 54 91 65 — 604 90 965 17,397 13,005 3,457 604 143 395 2 Years 3 Years 4 Years 5 Years Thereafter 3,765 2,685 2,558 2,492 17,604 Total 24,667 617 898 513 2,101 28,796 Total 21,081 9,358 856 623 1,080 32,998 (1) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion). The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023. (2) (3) There were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) issued as security for financial and performance conditions under certain contracts. Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for $587 million. 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 B) Contingencies Legal Proceedings Consolidated Financial Statements. Income Tax Matters provision for taxes is adequate. 39. PRIOR PERIOD REVISIONS revised for classification changes. Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made: • • Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense. Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product. Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 67 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 68 136 | CENOVUS ENERGY 2023 ANNUAL REPORT NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 B) Reconciliation of Liabilities The following table provides a reconciliation of liabilities to cash flows arising from financing activities: 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 and Transaction Costs Lease Additions 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 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 Dividends Paid on Preferred Shares Payment for Purchase of Warrants Finance and Transaction Costs Non-Cash Changes: Net Premium (Discount) on Redemption of Long-Term Debt Finance and Transaction Costs Lease Acquisitions Lease Additions Lease Divestitures Base Dividends Declared on Common Shares 990 Dividends Declared on Preferred Shares Warrants Purchased and Cancelled Exchange Rate Movements and Other As at December 31, 2023 Dividends Payable Warrant Purchase Payable Short-Term Borrowings Long-Term Debt 12,385 Lease Liabilities 2,957 (4,149) (302) — — — — (682) (219) (26) — — — 682 219 (990) (36) 35 — 9 — — — — — — — — — — 36 — — 9 — — — — — — — — — — — — — — — — — — — — — 2 — — — — — — — (711) (2) 711 79 34 — — — — — — — — — — — 2 58 — — — — — — — — — — — — — — 6 115 512 8,691 156 2,836 (1,346) (288) (29) (28) — — — — — — — — — — — — — — — — — — — — — (84) (19) — — — — — — — 25 — — — — — — — — — — — 33 57 — — — 31 (11) 179 2,658 (134) 7,108 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 38. 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, 2023 Transportation and Storage (1) (2) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments (3) Total Commitments As at December 31, 2022 Transportation and Storage (1) (2) Product Purchases Real Estate Obligation to Fund HCML Other Long-Term Commitments Total Commitments 1 Year 2,018 617 57 94 417 3,203 1 Year 1,747 1,626 48 92 381 3,894 2 Years 1,927 — 57 94 194 2,272 3 Years 1,680 — 59 94 184 2,017 4 Years 1,663 — 63 89 175 1,990 5 Years Thereafter 1,641 15,738 — 58 52 166 1,917 — 604 90 965 17,397 2 Years 3 Years 4 Years 5 Years Thereafter 2,011 1,509 50 105 90 1,542 922 50 96 75 1,416 922 50 96 74 1,360 922 54 91 65 13,005 3,457 604 143 395 3,765 2,685 2,558 2,492 17,604 Total 24,667 617 898 513 2,101 28,796 Total 21,081 9,358 856 623 1,080 32,998 (1) (2) (3) Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 – $9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator. As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion). The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023. There were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) issued as security for financial and performance conditions under certain contracts. Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for $587 million. 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. 39. PRIOR PERIOD REVISIONS Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised for classification changes. In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made: • • Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense. Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product. Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. Cenovus Energy Inc. – 2023 Consolidated Financial Statements 67 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 68 CENOVUS ENERGY 2023 ANNUAL REPORT | 137 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: Year Ended December 31, 2022 Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Previously Reported 34,775 4,810 29,965 4,332 143 4,189 30,310 26,112 4,198 (7,464) (5,533) (664) (1,270) 3 33,801 11,530 5,569 50,900 Revisions (92) (92) — 107 107 — (92) (92) — 77 341 (511) 247 — 157 (404) 247 — Revised Balance 34,683 4,718 29,965 4,439 250 4,189 30,218 26,020 4,198 (7,387) (5,192) (1,175) (1,023) 3 33,958 11,126 5,816 50,900 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 69 138 | CENOVUS ENERGY 2023 ANNUAL REPORT Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information (1) (2) (3) (4) On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”). On February 28, 2023, we purchased the remaining 50 percent interest in BP-Husky Refining LLC (“Toledo”). 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. SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Upstream Oil Sands (1) Conventional Offshore Total Upstream Revenue Downstream Canadian Refining U.S. Refining (2) Total Downstream Revenue Corporate and Eliminations Total Revenues Operating Margin Upstream Oil Sands (1) Conventional Offshore Downstream Canadian Refining U.S. Refining (2) Total Upstream Operating Margin (3) Total Downstream Operating Margin (3) Total Operating Margin (3) Cash From (Used in) Operating Activities Deduct (Add Back): Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (4) Per Share - Basic (4) Per Share - Diluted (4) Net Earnings (Loss) Net Earnings (Loss) Per Share - Basic Per Share - Diluted Capital Investment Upstream Oil Sands (1) Conventional Offshore Asia Pacific Atlantic Total Offshore Downstream Canadian Refining U.S. Refining (2) Total Upstream Capital Investment Total Downstream Capital Investment Corporate Total Capital Investment Cash From (Used in) Operating Activities and Adjusted Funds Flow Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2023 2023 2023 2023 2022 2023 2022 5,636 6,489 5,817 5,191 779 480 783 376 616 215 983 447 6,895 7,648 6,648 6,621 1,557 6,847 8,404 1,805 7,853 9,658 1,363 6,064 7,427 1,508 5,629 7,137 5,869 1,083 424 7,376 1,772 6,530 8,302 (2,165) (2,729) (1,844) (1,496) (1,615) 13,134 14,577 12,231 12,262 14,063 23,133 3,161 1,518 27,812 6,233 26,393 32,626 (8,234) 52,204 30,190 4,141 1,943 36,274 7,792 30,218 38,010 (7,387) 66,897 1,962 3,021 2,036 1,150 1,639 2,455 3,447 2,257 1,711 2,224 123 370 126 (430) (304) 126 300 170 752 922 73 148 116 27 143 261 300 263 128 391 248 337 278 280 558 2,151 4,369 2,400 2,102 2,782 8,169 583 1,118 9,870 675 477 1,152 11,022 8,979 1,235 1,610 11,824 699 1,740 2,439 14,263 2,946 2,738 1,990 (286) 2,970 7,388 11,403 (65) 949 2,062 1.10 1.09 (68) (641) 3,447 1.82 1.81 (41) 132 1,899 1.00 0.98 (48) (1,633) 1,395 0.73 0.71 (49) 673 2,346 1.22 1.19 (222) (1,193) 8,803 4.64 4.57 (150) 575 10,978 5.63 5.47 743 0.39 0.39 1,864 0.98 0.97 866 0.45 0.44 636 0.33 0.32 784 0.40 0.39 4,109 2.15 2.12 6,450 3.29 3.20 618 129 3 161 164 911 46 167 213 46 590 100 3 191 194 884 38 88 126 15 539 82 1 183 184 805 34 153 187 10 635 141 — 100 100 876 27 194 221 4 681 156 3 82 85 922 40 285 325 27 1,170 1,025 1,002 1,101 1,274 4,298 2,382 452 1,792 344 3,476 2,446 7 635 642 145 602 747 75 8 302 310 117 1,059 1,176 86 3,708 1 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS All amounts in $ millions, unless otherwise indicated For the year ended December 31, 2023 It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Year Ended December 31, 2022 Revisions Previously Reported 34,775 4,810 29,965 Revised Balance 34,683 4,718 29,965 4,439 250 4,189 30,218 26,020 4,198 (7,387) (5,192) (1,175) (1,023) 3 33,958 11,126 5,816 50,900 (92) (92) — 107 107 — (92) (92) — 77 341 (511) 247 — 157 (404) 247 — 4,332 143 4,189 30,310 26,112 4,198 (7,464) (5,533) (664) (1,270) 3 33,801 11,530 5,569 50,900 Cenovus Energy Inc. – 2023 Consolidated Financial Statements 69 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics ($ millions, except per share amounts) Revenues Upstream Oil Sands (1) Conventional Offshore Total Upstream Revenue Downstream Canadian Refining U.S. Refining (2) Total Downstream Revenue Corporate and Eliminations Total Revenues Operating Margin Upstream Oil Sands (1) Conventional Offshore Total Upstream Operating Margin (3) Downstream Canadian Refining U.S. Refining (2) Total Downstream Operating Margin (3) Total Operating Margin (3) Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 5,636 779 480 6,895 6,489 783 376 7,648 5,817 616 215 6,648 5,191 983 447 6,621 5,869 1,083 424 7,376 1,557 6,847 8,404 (2,165) 1,805 7,853 9,658 (2,729) 1,363 6,064 7,427 (1,844) 1,508 5,629 7,137 (1,496) 1,772 6,530 8,302 (1,615) 14,063 13,134 14,577 12,231 12,262 23,133 3,161 1,518 27,812 6,233 26,393 32,626 (8,234) 52,204 30,190 4,141 1,943 36,274 7,792 30,218 38,010 (7,387) 66,897 1,962 123 370 2,455 126 (430) (304) 2,151 3,021 126 300 3,447 170 752 922 4,369 2,036 73 148 2,257 116 27 143 2,400 1,150 261 300 1,711 263 128 391 2,102 1,639 248 337 2,224 278 280 558 2,782 8,169 583 1,118 9,870 675 477 1,152 11,022 8,979 1,235 1,610 11,824 699 1,740 2,439 14,263 Cash From (Used in) Operating Activities and Adjusted Funds Flow Cash From (Used in) Operating Activities 2,946 Deduct (Add Back): Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital Adjusted Funds Flow (4) Per Share - Basic (4) Per Share - Diluted (4) (65) 949 2,062 1.10 1.09 2,738 1,990 (286) 2,970 7,388 11,403 (68) (641) 3,447 1.82 1.81 (41) 132 1,899 1.00 0.98 (48) (1,633) 1,395 0.73 0.71 (49) 673 2,346 1.22 1.19 (222) (1,193) 8,803 4.64 4.57 (150) 575 10,978 5.63 5.47 Net Earnings (Loss) Net Earnings (Loss) Per Share - Basic Per Share - Diluted Capital Investment Upstream Oil Sands (1) Conventional Offshore Asia Pacific Atlantic Total Offshore Total Upstream Capital Investment Downstream Canadian Refining U.S. Refining (2) Total Downstream Capital Investment Corporate Total Capital Investment 743 0.39 0.39 1,864 0.98 0.97 866 0.45 0.44 636 0.33 0.32 784 0.40 0.39 4,109 2.15 2.12 6,450 3.29 3.20 618 129 3 161 164 911 46 167 213 46 1,170 590 100 3 191 194 884 38 88 126 15 1,025 539 82 1 183 184 805 34 153 187 10 1,002 635 141 — 100 100 876 27 194 221 4 1,101 681 156 3 82 85 922 40 285 325 27 1,274 2,382 452 7 635 642 3,476 145 602 747 75 4,298 1,792 344 8 302 310 2,446 117 1,059 1,176 86 3,708 (1) (2) (3) (4) On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”). On February 28, 2023, we purchased the remaining 50 percent interest in BP-Husky Refining LLC (“Toledo”). 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 Inc. – Q4 2023 Interim Supplemental Information CENOVUS ENERGY 2023 ANNUAL REPORT | 139 1 SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics SUPPLEMENTAL INFORMATION (unaudited) Financial Metrics Free Funds Flow (1) Excess Free Funds Flow (1) Long-Term Debt Total Debt Net Debt Net Debt to Adjusted Funds Flow (2) (times) Net Debt to Adjusted EBITDA (2) (times) Income Tax and Exchange Rates Effective Tax Rate on Net Earnings (Loss) (percent) Foreign Exchange Rates US$ per C$1 Average Period End RMB per C$1 Average Common Share Information Commons Shares Outstanding (millions) Period End Weighted Average - Basic Weighted Average - Diluted Base Dividend ($ per share) Variable Dividend ($ 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 (Average US$/bbl, unless otherwise indicated) Crude Oil Prices Dated Brent West Texas Intermediate (“WTI”) Differential Dated Brent - WTI Western Canadian Select (“WCS”) at Hardisty WCS at Hardisty (C$/bbl) Differential WTI - WCS at Hardisty WCS at Nederland Differential WTI - WCS at Nederland Condensate (C5 at Edmonton) Condensate (C$/bbl) Differential Condensate - WTI Premium/(Discount) Differential Condensate - WCS at Hardisty Premium/(Discount) Synthetic at Edmonton Synthetic at Edmonton (C$/bbl) Differential Synthetic - WTI Premium/(Discount) Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (3) Group 3 3-2-1 Crack Spread (3) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (4) (C$/Mcf) NYMEX (5) (US$/Mcf) Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 892 471 7,108 7,287 5,060 0.6 0.5 2,422 1,989 7,224 7,238 5,976 0.7 0.6 897 505 8,534 8,534 6,367 0.7 0.7 294 (499) 8,681 8,681 6,632 0.7 0.6 1,072 786 8,691 8,806 4,282 0.4 0.3 4,505 n/a 7,108 7,287 5,060 0.6 0.5 7,270 n/a 8,691 8,806 4,282 0.4 0.3 18.5 26.1 0.734 0.756 0.746 0.740 0.745 0.755 0.739 0.739 0.737 0.738 0.741 0.756 0.769 0.738 5.304 5.402 5.228 5.059 5.241 5.247 5.170 1,872 1,879 1,891 0.140 — 22.08 16.65 1,193 1,886 1,892 1,905 0.140 — 28.28 20.82 1,036 1,896 1,903 1,943 0.140 — 22.50 16.98 1,066 1,908 1,908 1,958 0.105 — 23.58 17.46 1,126 1,909 1,917 1,967 0.105 0.114 26.27 19.41 1,027 1,872 1,895 1,925 0.525 — 22.08 16.65 4,421 1,909 1,951 2,006 0.350 0.114 26.27 19.41 5,880 84.05 78.32 5.73 56.43 76.95 21.89 71.59 6.73 76.24 103.90 86.76 82.26 4.50 69.35 93.06 12.91 77.89 4.37 77.96 104.63 (2.08) 19.81 78.64 107.21 0.32 (4.30) 8.61 84.95 114.01 2.69 78.39 73.78 4.61 58.74 78.90 15.04 66.98 6.80 72.39 97.25 (1.39) 13.65 76.66 102.98 2.88 81.27 76.13 5.14 51.36 69.44 24.77 62.49 13.64 79.87 107.95 3.74 28.51 78.18 105.67 2.05 88.71 82.65 6.06 56.99 77.42 25.66 67.65 15.00 83.40 113.25 0.75 26.41 86.79 117.87 4.14 82.62 77.62 5.00 58.97 79.59 18.65 69.74 7.88 76.61 103.43 (1.01) 17.64 79.61 107.47 1.99 101.19 94.23 6.96 76.01 98.51 18.22 85.77 8.46 93.78 121.78 (0.45) 17.77 98.66 128.19 4.43 83.72 107.24 105.59 113.77 102.32 102.40 99.82 115.39 102.80 140.95 97.86 109.70 120.63 143.85 13.24 18.55 4.77 2.30 2.88 26.06 36.96 7.42 2.60 2.55 28.57 31.78 7.72 2.45 2.10 28.88 31.35 8.20 3.22 3.42 32.87 29.99 8.54 5.11 6.26 24.19 29.66 7.04 2.64 2.74 34.15 33.21 7.72 5.31 6.64 Bitumen production volumes for the twelve months ended December 31, 2022, included 1.6 Mbbls per day from the Tucker asset that was sold on January 31, 2022. Natural gas liquids include condensate volumes. 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. Total Operating Statistics Upstream Production Volumes (1) Crude Oil and Natural Gas Liquids (Mbbls/d) Oil Sands Bitumen Foster Creek Christina Lake Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Total Oil Sands Production (2) Conventional Light Crude Oil Natural Gas Liquids (3) Total Conventional Production Offshore Natural Gas Liquids Asia Pacific - China Asia Pacific - Indonesia Offshore Light Crude Oil Atlantic Total Offshore Production Total Liquids Production Conventional Natural Gas (MMcf/d) Oil Sands Conventional Offshore Asia Pacific - China Asia Pacific - Indonesia Total Conventional Natural Gas Production Total Upstream Production (MBOE/d) (4) Downstream Production Volumes Canadian Production Volumes (Mbbls/d) Transportation Fuels Diesel Total Transportation Fuels Synthetic Crude Oil Asphalt Other Ethanol Total Refined Product Production Total Canadian Production U.S. Production Volumes (Mbbls/d) Transportation Fuels Gasoline Distillates (5) Total Transportation Fuels Asphalt Other Total U.S. Production Total Downstream Production Amounts are before royalty rates. (1) (2) (3) (4) (5) Includes diesel and jet fuel. Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2023 2023 2023 2023 2022 2023 2022 198.8 239.6 50.1 106.6 17.5 612.6 6.1 22.8 28.9 9.5 1.9 9.7 21.1 662.6 12.3 569.6 207.8 86.6 876.3 808.6 13.2 13.2 46.4 14.9 33.4 107.9 5.4 113.3 269.6 172.2 441.8 21.5 50.8 514.1 627.4 189.3 237.6 54.5 104.6 15.6 601.6 167.0 234.9 46.5 106.2 17.0 571.6 6.3 23.9 30.2 10.0 1.7 8.9 20.6 4.8 18.0 22.8 6.2 2.5 5.3 14.0 652.4 608.4 10.6 582.1 12.9 491.4 202.7 72.0 867.4 797.0 150.3 74.8 729.4 729.9 13.8 13.8 53.2 15.7 34.1 116.8 5.6 122.4 267.6 196.1 463.7 24.7 95.2 583.6 706.0 12.4 12.4 44.8 15.3 31.9 104.4 3.9 108.3 199.4 160.9 360.3 22.1 81.2 463.6 571.9 190.0 237.2 44.5 99.0 16.8 587.5 6.4 22.0 28.4 9.5 1.9 8.9 20.3 636.2 12.0 572.9 201.5 70.6 857.0 779.0 12.3 12.3 45.7 15.8 34.0 107.8 5.1 112.9 187.1 138.1 325.2 10.8 38.8 374.8 487.7 195.9 250.3 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 10.5 10.5 45.1 14.3 32.7 102.6 5.0 107.6 192.6 147.7 340.3 9.2 49.2 398.7 506.3 186.3 237.4 48.9 104.1 16.7 593.4 5.9 21.7 27.6 8.8 2.0 8.2 19.0 640.0 11.9 554.1 190.6 76.0 832.6 778.7 12.9 12.9 47.6 15.4 33.3 109.2 5.0 114.2 231.2 167.0 398.2 19.8 67.0 485.0 599.2 191.0 246.5 31.3 99.9 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 9.3 9.3 46.0 13.5 31.5 100.3 4.9 105.2 199.8 153.4 353.2 8.9 57.8 419.9 525.1 (1) (2) (3) (4) (5) Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Calculated on a trailing twelve-month basis. 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") 5A natural gas daily index. New York Mercantile Exchange ("NYMEX") natural gas monthly index. 140 | CENOVUS ENERGY 2023 ANNUAL REPORT Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 2 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 3 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Financial Statistics Financial Metrics Free Funds Flow (1) Excess Free Funds Flow (1) Long-Term Debt Total Debt Net Debt Net Debt to Adjusted Funds Flow (2) (times) Net Debt to Adjusted EBITDA (2) (times) Income Tax and Exchange Rates Effective Tax Rate on Net Earnings (Loss) (percent) Foreign Exchange Rates US$ per C$1 Average Period End RMB per C$1 Average Common Share Information Commons Shares Outstanding (millions) Period End Weighted Average - Basic Weighted Average - Diluted Base Dividend ($ per share) Variable Dividend ($ 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 (Average US$/bbl, unless otherwise indicated) Crude Oil Prices Dated Brent West Texas Intermediate (“WTI”) Differential Dated Brent - WTI Western Canadian Select (“WCS”) at Hardisty WCS at Hardisty (C$/bbl) Differential WTI - WCS at Hardisty WCS at Nederland Differential WTI - WCS at Nederland Condensate (C5 at Edmonton) Condensate (C$/bbl) Synthetic at Edmonton Synthetic at Edmonton (C$/bbl) Differential Synthetic - WTI Premium/(Discount) Refined Product Prices Chicago Regular Unleaded Gasoline (“RUL”) Chicago Ultra-low Sulphur Diesel (“ULSD”) Refining Benchmarks Chicago 3-2-1 Crack Spread (3) Group 3 3-2-1 Crack Spread (3) Renewable Identification Numbers (“RINs”) Natural Gas Prices AECO (4) (C$/Mcf) NYMEX (5) (US$/Mcf) Differential Condensate - WTI Premium/(Discount) Differential Condensate - WCS at Hardisty Premium/(Discount) Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2023 892 471 7,108 7,287 5,060 0.6 0.5 2023 2,422 1,989 7,224 7,238 5,976 0.7 0.6 2023 897 505 8,534 8,534 6,367 0.7 0.7 2023 294 (499) 8,681 8,681 6,632 0.7 0.6 2022 1,072 786 8,691 8,806 4,282 0.4 0.3 2023 4,505 n/a 7,108 7,287 5,060 0.6 0.5 2022 7,270 n/a 8,691 8,806 4,282 0.4 0.3 18.5 26.1 0.734 0.756 0.746 0.740 0.745 0.755 0.739 0.739 0.737 0.738 0.741 0.756 0.769 0.738 5.304 5.402 5.228 5.059 5.241 5.247 5.170 1,872 1,879 1,891 0.140 — 22.08 16.65 1,193 84.05 78.32 5.73 56.43 76.95 21.89 71.59 6.73 76.24 1,886 1,892 1,905 0.140 — 28.28 20.82 1,036 86.76 82.26 4.50 69.35 93.06 12.91 77.89 4.37 77.96 1,896 1,903 1,943 0.140 — 22.50 16.98 1,066 78.39 73.78 4.61 58.74 78.90 15.04 66.98 6.80 72.39 1,908 1,908 1,958 0.105 — 23.58 17.46 1,126 81.27 76.13 5.14 51.36 69.44 24.77 62.49 13.64 79.87 3.74 28.51 78.18 1,909 1,917 1,967 0.105 0.114 26.27 19.41 1,027 88.71 82.65 6.06 56.99 77.42 25.66 67.65 15.00 83.40 0.75 26.41 86.79 1,872 1,895 1,925 0.525 — 22.08 16.65 4,421 1,909 1,951 2,006 0.350 0.114 26.27 19.41 5,880 82.62 77.62 5.00 58.97 79.59 18.65 69.74 7.88 76.61 101.19 94.23 6.96 76.01 98.51 18.22 85.77 8.46 93.78 (1.01) 17.64 79.61 107.47 1.99 (0.45) 17.77 98.66 128.19 4.43 103.90 104.63 97.25 107.95 113.25 103.43 121.78 (2.08) (4.30) (1.39) 19.81 78.64 8.61 84.95 13.65 76.66 107.21 114.01 102.98 105.67 117.87 0.32 2.69 2.88 2.05 4.14 83.72 105.59 102.32 99.82 102.80 107.24 113.77 102.40 115.39 140.95 97.86 109.70 120.63 143.85 13.24 18.55 4.77 2.30 2.88 26.06 36.96 7.42 2.60 2.55 28.57 31.78 7.72 2.45 2.10 28.88 31.35 8.20 3.22 3.42 32.87 29.99 8.54 5.11 6.26 24.19 29.66 7.04 2.64 2.74 34.15 33.21 7.72 5.31 6.64 (1) (2) (3) (4) (5) Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental. Calculated on a trailing twelve-month basis. 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") 5A natural gas daily index. New York Mercantile Exchange ("NYMEX") natural gas monthly index. Total Operating Statistics Upstream Production Volumes (1) Crude Oil and Natural Gas Liquids (Mbbls/d) Oil Sands Bitumen Foster Creek Christina Lake Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil Total Oil Sands Production (2) Conventional Light Crude Oil Natural Gas Liquids (3) Total Conventional Production Offshore Natural Gas Liquids Asia Pacific - China Asia Pacific - Indonesia Offshore Light Crude Oil Atlantic Total Offshore Production Total Liquids Production Conventional Natural Gas (MMcf/d) Oil Sands Conventional Offshore Asia Pacific - China Asia Pacific - Indonesia Total Conventional Natural Gas Production Total Upstream Production (MBOE/d) (4) Downstream Production Volumes Canadian Production Volumes (Mbbls/d) Transportation Fuels Diesel Total Transportation Fuels Synthetic Crude Oil Asphalt Other Total Refined Product Production Ethanol Total Canadian Production U.S. Production Volumes (Mbbls/d) Transportation Fuels Gasoline Distillates (5) Total Transportation Fuels Asphalt Other Total U.S. Production Total Downstream Production Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 198.8 239.6 50.1 106.6 17.5 612.6 6.1 22.8 28.9 9.5 1.9 9.7 21.1 662.6 12.3 569.6 207.8 86.6 876.3 808.6 13.2 13.2 46.4 14.9 33.4 107.9 5.4 113.3 269.6 172.2 441.8 21.5 50.8 514.1 627.4 189.3 237.6 54.5 104.6 15.6 601.6 6.3 23.9 30.2 10.0 1.7 167.0 234.9 46.5 106.2 17.0 571.6 4.8 18.0 22.8 6.2 2.5 8.9 20.6 652.4 5.3 14.0 608.4 10.6 582.1 12.9 491.4 202.7 72.0 867.4 797.0 150.3 74.8 729.4 729.9 13.8 13.8 53.2 15.7 34.1 116.8 5.6 122.4 267.6 196.1 463.7 24.7 95.2 583.6 706.0 12.4 12.4 44.8 15.3 31.9 104.4 3.9 108.3 199.4 160.9 360.3 22.1 81.2 463.6 571.9 190.0 237.2 44.5 99.0 16.8 587.5 6.4 22.0 28.4 9.5 1.9 8.9 20.3 636.2 12.0 572.9 201.5 70.6 857.0 779.0 12.3 12.3 45.7 15.8 34.0 107.8 5.1 112.9 187.1 138.1 325.2 10.8 38.8 374.8 487.7 195.9 250.3 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 10.5 10.5 45.1 14.3 32.7 102.6 5.0 107.6 192.6 147.7 340.3 9.2 49.2 398.7 506.3 186.3 237.4 48.9 104.1 16.7 593.4 5.9 21.7 27.6 8.8 2.0 8.2 19.0 640.0 11.9 554.1 190.6 76.0 832.6 778.7 12.9 12.9 47.6 15.4 33.3 109.2 5.0 114.2 231.2 167.0 398.2 19.8 67.0 485.0 599.2 191.0 246.5 31.3 99.9 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 9.3 9.3 46.0 13.5 31.5 100.3 4.9 105.2 199.8 153.4 353.2 8.9 57.8 419.9 525.1 (1) (2) (3) (4) (5) Amounts are before royalty rates. Bitumen production volumes for the twelve months ended December 31, 2022, included 1.6 Mbbls per day from the Tucker asset that was sold on January 31, 2022. Natural gas liquids include condensate volumes. 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. Includes diesel and jet fuel. Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 2 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information CENOVUS ENERGY 2023 ANNUAL REPORT | 141 3 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Upstream Operating Statistics - Upstream Effective Royalty Rates (1) (2) Oil Sands (percent) Foster Creek Christina Lake Sunrise Lloydminster (3) Conventional (percent) Offshore (percent) Asia Pacific - China Asia Pacific - Indonesia Atlantic Oil Sands - Netbacks (4) 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 ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Other Oil Sands (5) Bitumen and Heavy Crude Oil ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Total Oil Sands ($/BOE) (6) Sales Price Royalties Transportation and Blending Operating Netback Conventional - Netbacks (4) Total Conventional ($/BOE) (6) Sales Price Royalties Transportation and Blending Operating Netback Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 31.7 28.5 10.6 11.7 10.8 8.7 19.9 2.6 74.06 19.89 11.33 9.82 33.02 65.95 16.67 7.36 7.59 34.33 76.55 6.81 12.41 13.92 43.41 69.11 7.59 3.42 18.05 40.05 70.00 15.03 8.24 10.96 35.77 29.09 2.34 4.71 12.32 9.72 23.4 33.2 5.6 8.5 9.6 7.5 19.7 2.4 98.93 20.65 10.55 10.91 56.82 91.72 28.55 5.76 9.32 48.09 96.67 4.69 12.29 15.94 63.75 91.71 7.46 3.29 20.07 60.89 94.45 19.70 7.41 12.56 54.78 28.13 2.29 3.82 12.36 9.66 21.9 24.6 5.4 9.3 2.5 5.4 23.4 — 75.41 13.71 12.80 12.21 36.69 66.39 14.91 5.91 8.09 37.48 70.93 3.15 12.58 17.38 37.82 74.25 6.42 3.60 20.30 43.93 71.03 11.78 8.04 12.72 38.49 25.09 0.53 4.08 14.59 5.89 23.4 30.3 4.7 8.3 17.3 5.5 30.8 5.3 62.45 11.44 13.45 12.99 24.57 49.83 12.76 7.70 9.11 20.26 50.44 1.78 12.67 22.03 13.96 59.01 4.49 3.74 23.08 27.70 55.60 9.94 9.07 14.04 22.55 43.99 4.81 4.03 13.07 22.08 32.9 26.5 7.6 12.5 15.9 5.8 34.2 1.1 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 25.1 29.5 6.8 9.5 10.8 6.9 23.2 3.7 78.18 16.61 11.98 11.44 38.15 68.38 18.19 6.69 8.52 34.98 75.23 4.28 12.47 17.02 41.46 73.69 6.53 3.51 20.32 43.33 73.02 14.20 8.18 12.54 38.10 31.76 2.56 4.16 13.02 12.02 30.5 30.8 7.3 10.5 15.4 5.6 42.7 (0.5) 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 Offshore - Netbacks (1) China Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/Mcf) Asia Pacific - China Total ($/BOE) (2) Indonesia Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/Mcf) Asia Pacific - Indonesia Total ($/BOE) (2) Total Asia Pacific Natural Gas Liquids ($/bbl) Conventional Natural Gas ($/Mcf) Asia Pacific - Total ($/BOE) (2) Atlantic (3) Light Crude Oil ($/bbl) Transportation and Blending 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 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, 2023 2023 2023 2023 2022 2023 2022 124.02 115.17 64.60 10.87 58.53 12.15 101.79 115.56 57.48 14.52 66.96 13.76 106.87 56.84 11.17 130.62 82.56 13.24 109.31 18.59 7.23 13.04 0.71 1.21 84.94 7.36 7.26 70.32 8.64 0.83 1.81 60.32 11.99 10.86 37.47 26.35 7.84 11.75 0.75 1.39 78.28 8.61 8.23 61.44 99.72 13.14 6.50 12.49 0.66 1.08 80.61 6.06 6.51 68.04 8.44 0.82 1.93 58.68 11.59 11.66 35.43 19.73 7.32 11.43 0.70 1.31 75.38 7.38 7.73 60.27 111.78 101.97 95.39 5.54 5.62 13.36 0.72 0.93 83.50 4.60 5.58 73.32 8.78 2.00 1.87 59.46 18.31 11.69 29.46 96.45 14.19 7.11 12.17 1.05 1.17 77.71 7.90 7.05 62.76 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 29.88 101.25 17.91 7.06 12.27 1.03 1.20 79.37 8.64 7.19 63.54 82.24 4.71 11.69 12.92 0.68 1.99 78.48 4.23 11.91 62.34 91.66 49.17 8.25 8.55 1.07 1.52 58.05 13.60 8.98 35.47 84.95 17.52 10.70 11.47 0.81 1.84 71.86 7.26 10.96 53.64 — — — — — 98.11 11.13 7.38 12.95 0.70 1.26 82.14 5.68 7.51 68.95 8.60 1.16 1.78 59.16 13.75 10.76 34.65 99.73 19.61 8.08 11.71 0.83 1.41 76.04 7.83 8.37 59.84 4.24 4.44 67.93 37.13 104.67 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 63.80 140.65 (0.74) 3.79 42.03 95.57 121.88 107.99 104.98 128.76 113.74 3.16 5.10 51.41 62.21 2.56 (0.53) 65.91 40.05 5.53 3.16 59.73 36.56 1.39 5.05 72.43 49.89 The components of each netback are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of (1) (2) (3) this Supplemental. See footnote 4 on page 141 for BOE definition. During the three months ended June 30, 2023, there were no sales volumes in the Atlantic. (1) (2) (3) (4) (5) (6) Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses. Excluding Realized (Gain) Loss on Risk Management. Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets. 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 assets. Sale of the Tucker asset closed on January 31, 2022. See footnote 4 on page 141 for BOE definition. 142 | CENOVUS ENERGY 2023 ANNUAL REPORT Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 4 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 5 SUPPLEMENTAL INFORMATION (unaudited) SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Upstream Operating Statistics - Upstream Offshore - Netbacks (1) China Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/Mcf) Sales Price Royalties Operating Asia Pacific - China Total ($/BOE) (2) Sales Price Royalties Operating Netback Indonesia Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/Mcf) Sales Price Royalties Operating Asia Pacific - Indonesia Total ($/BOE) (2) Sales Price Royalties Operating Netback Total Asia Pacific Natural Gas Liquids ($/bbl) Sales Price Royalties Operating Conventional Natural Gas ($/Mcf) Sales Price Royalties Operating Asia Pacific - Total ($/BOE) (2) Sales Price Royalties Operating Netback Atlantic (3) Light Crude Oil ($/bbl) Sales Price Royalties Transportation and Blending Operating Netback Effective Royalty Rates (1) (2) Oil Sands (percent) Foster Creek Christina Lake Sunrise Lloydminster (3) Conventional (percent) Offshore (percent) Asia Pacific - China Asia Pacific - Indonesia Atlantic Oil Sands - Netbacks (4) Transportation and Blending Foster Creek Bitumen ($/bbl) Sales Price Royalties Operating Netback Christina Lake Bitumen ($/bbl) Transportation and Blending Sunrise Bitumen ($/bbl) Transportation and Blending Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Sales Price Royalties Operating Netback Other Oil Sands (5) Bitumen and Heavy Crude Oil ($/bbl) Transportation and Blending Total Oil Sands ($/BOE) (6) Transportation and Blending Conventional - Netbacks (4) Total Conventional ($/BOE) (6) Transportation and Blending Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2023 2023 2023 2023 2022 2023 2022 31.7 28.5 10.6 11.7 10.8 8.7 19.9 2.6 74.06 19.89 11.33 9.82 33.02 65.95 16.67 7.36 7.59 34.33 76.55 6.81 12.41 13.92 43.41 69.11 7.59 3.42 18.05 40.05 70.00 15.03 8.24 10.96 35.77 29.09 2.34 4.71 12.32 9.72 23.4 33.2 5.6 8.5 9.6 7.5 19.7 2.4 98.93 20.65 10.55 10.91 56.82 91.72 28.55 5.76 9.32 48.09 96.67 4.69 12.29 15.94 63.75 91.71 7.46 3.29 20.07 60.89 94.45 19.70 7.41 12.56 54.78 28.13 2.29 3.82 12.36 9.66 21.9 24.6 5.4 9.3 2.5 5.4 23.4 — 75.41 13.71 12.80 12.21 36.69 66.39 14.91 5.91 8.09 37.48 70.93 3.15 12.58 17.38 37.82 74.25 6.42 3.60 20.30 43.93 71.03 11.78 8.04 12.72 38.49 25.09 0.53 4.08 14.59 5.89 23.4 30.3 4.7 8.3 17.3 5.5 30.8 5.3 62.45 11.44 13.45 12.99 24.57 49.83 12.76 7.70 9.11 20.26 50.44 1.78 12.67 22.03 13.96 59.01 4.49 3.74 23.08 27.70 55.60 9.94 9.07 14.04 22.55 43.99 4.81 4.03 13.07 22.08 32.9 26.5 7.6 12.5 15.9 5.8 34.2 1.1 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 25.1 29.5 6.8 9.5 10.8 6.9 23.2 3.7 78.18 16.61 11.98 11.44 38.15 68.38 18.19 6.69 8.52 34.98 75.23 4.28 12.47 17.02 41.46 73.69 6.53 3.51 20.32 43.33 73.02 14.20 8.18 12.54 38.10 31.76 2.56 4.16 13.02 12.02 30.5 30.8 7.3 10.5 15.4 5.6 42.7 (0.5) 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 (1) (2) (3) (4) (5) (6) Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses. Excluding Realized (Gain) Loss on Risk Management. Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets. The components of each netback are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. Sale of the Tucker asset closed on January 31, 2022. this Supplemental. See footnote 4 on page 141 for BOE definition. Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 109.31 18.59 7.23 13.04 0.71 1.21 84.94 7.36 7.26 70.32 99.72 13.14 6.50 12.49 0.66 1.08 80.61 6.06 6.51 68.04 124.02 64.60 10.87 115.17 58.53 12.15 8.64 0.83 1.81 60.32 11.99 10.86 37.47 8.44 0.82 1.93 58.68 11.59 11.66 35.43 111.78 26.35 7.84 101.97 19.73 7.32 11.75 0.75 1.39 78.28 8.61 8.23 61.44 11.43 0.70 1.31 75.38 7.38 7.73 60.27 82.24 4.71 11.69 12.92 0.68 1.99 78.48 4.23 11.91 62.34 91.66 49.17 8.25 8.55 1.07 1.52 58.05 13.60 8.98 35.47 84.95 17.52 10.70 11.47 0.81 1.84 71.86 7.26 10.96 53.64 95.39 5.54 5.62 13.36 0.72 0.93 83.50 4.60 5.58 73.32 97.62 5.49 5.36 13.16 0.77 0.89 82.89 4.80 5.36 72.73 98.11 11.13 7.38 12.95 0.70 1.26 82.14 5.68 7.51 68.95 104.67 5.93 5.61 12.69 0.70 0.94 81.99 4.57 5.62 71.80 101.79 57.48 14.52 115.56 66.96 13.76 106.87 56.84 11.17 130.62 82.56 13.24 8.78 2.00 1.87 59.46 18.31 11.69 29.46 96.45 14.19 7.11 12.17 1.05 1.17 77.71 7.90 7.05 62.76 9.09 1.99 2.32 66.50 22.74 13.88 29.88 101.25 17.91 7.06 12.27 1.03 1.20 79.37 8.64 7.19 63.54 128.76 1.39 5.05 72.43 49.89 8.60 1.16 1.78 59.16 13.75 10.76 34.65 99.73 19.61 8.08 11.71 0.83 1.41 76.04 7.83 8.37 59.84 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 63.80 113.74 4.24 4.44 67.93 37.13 140.65 (0.74) 3.79 42.03 95.57 121.88 3.16 5.10 51.41 62.21 107.99 2.56 (0.53) 65.91 40.05 — — — — — 104.98 5.53 3.16 59.73 36.56 (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. See footnote 4 on page 141 for BOE definition. During the three months ended June 30, 2023, there were no sales volumes in the Atlantic. Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 4 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information CENOVUS ENERGY 2023 ANNUAL REPORT | 143 5 SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Downstream SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Downstream Canadian Refining Total Canadian Refining Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Lloydminster Upgrader Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Upgrading Differential (4) ($/bbl) Lloydminster Refinery Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Ethanol Ethanol Production (Mbbls/d) U.S. Refining (5) Total U.S. Refining Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Heavy Crude Oil Light/Medium Crude Oil Crude Utilization (6) (percent) Production Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 110.5 100.3 91 113.3 27.74 13.37 81.5 73.6 90 80.9 33.48 12.25 34.13 29.0 26.7 92 27.0 11.96 16.45 110.5 108.4 98 122.4 29.17 11.60 81.5 80.6 99 88.9 29.12 11.29 22.31 29.0 27.8 96 27.9 29.30 12.51 110.5 95.3 86 108.3 28.36 13.40 81.5 68.1 84 77.2 27.66 13.55 26.40 29.0 27.2 94 27.2 30.14 13.02 110.5 98.7 89 112.9 43.30 12.46 81.5 70.0 86 79.1 48.53 12.40 41.75 29.0 28.7 99 28.7 30.53 12.60 110.5 94.3 85 107.6 46.21 13.78 81.5 68.4 84 76.6 52.60 12.83 45.30 29.0 25.9 89 26.0 29.36 16.30 110.5 100.7 91 114.2 32.04 12.68 81.5 73.1 90 81.5 34.48 12.32 31.14 29.0 27.6 95 27.7 25.58 13.62 110.5 92.9 84 105.2 33.92 13.91 81.5 68.7 84 76.0 36.04 12.65 32.84 29.0 24.2 83 24.3 27.91 17.49 5.4 5.6 3.9 5.1 5.0 5.0 4.9 635.2 478.8 216.3 262.5 75 514.1 5.03 14.94 635.2 555.9 210.6 345.3 88 583.6 27.10 12.17 635.2 442.5 155.1 287.4 70 463.6 17.40 16.88 635.2 359.2 114.7 244.5 67 374.8 22.62 18.63 551.5 379.0 127.4 251.6 75 398.7 24.70 16.88 635.2 459.7 173.9 285.8 75 485.0 18.12 15.27 551.5 400.8 116.1 284.7 80 419.9 28.70 16.04 (1) (2) (3) (4) (5) (6) 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. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Based on benchmark price differential between heavy oil feedstock and synthetic crude. Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023. Three Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, 2023 2023 2023 2023 2022 2023 2022 Twelve Months Ended Dec. 31, Dec. 31, 178.7 131.8 74 160.0 138.4 87 49.0 32.4 66 247.5 176.2 71 178.7 146.2 82 160.0 143.5 90 49.0 32.2 66 247.5 234.0 95 178.7 165.8 93 160.0 48.3 30 49.0 25.2 51 247.5 203.2 82 178.7 167.2 94 160.0 — — 49.0 0.2 — 247.5 191.8 77 175.0 162.6 93 80.0 — — 49.0 — — 247.5 216.4 87 178.7 152.7 85 160.0 83.1 57 49.0 22.6 61 247.5 201.3 81 175.0 157.9 90 80.0 36.3 45 49.0 — — 247.5 206.6 83 U.S. Refining Lima Refinery Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Toledo Refinery (2) Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) Superior Refinery Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) Wood River and Borger Refineries (4) Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Based on crude oil name plate capacity. (1) (2) (3) Advisory Specified Financial Measures On February 28, 2023, we purchased the remaining 50 percent interest in Toledo. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023. (4) Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations. Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International Financial Reporting Standards 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 section in the Advisory and in our MD&A for the periods ended September 30, 2023, June 30, 2023 and March 31, 2023 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference about these specified financial measures. 144 | CENOVUS ENERGY 2023 ANNUAL REPORT Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 6 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 7 Canadian Refining Total Canadian Refining Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Lloydminster Upgrader Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Upgrading Differential (4) ($/bbl) Lloydminster Refinery Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Heavy Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Production (Mbbls/d) Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Ethanol Ethanol Production (Mbbls/d) U.S. Refining (5) Total U.S. Refining Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Heavy Crude Oil Light/Medium Crude Oil Crude Utilization (6) (percent) Production Refining Margin (2) ($/bbl) Unit Operating Expense (3) ($/bbl) Based on crude oil name plate capacity. Three Months Ended Twelve Months Ended Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, Dec. 31, Dec. 31, 2023 2023 2023 2023 2022 2023 2022 110.5 100.3 91 113.3 27.74 13.37 81.5 73.6 90 80.9 33.48 12.25 34.13 29.0 26.7 92 27.0 11.96 16.45 635.2 478.8 216.3 262.5 75 514.1 5.03 14.94 110.5 108.4 98 122.4 29.17 11.60 81.5 80.6 99 88.9 29.12 11.29 22.31 29.0 27.8 96 27.9 29.30 12.51 635.2 555.9 210.6 345.3 88 583.6 27.10 12.17 110.5 95.3 86 108.3 28.36 13.40 81.5 68.1 84 77.2 27.66 13.55 26.40 29.0 27.2 94 27.2 30.14 13.02 635.2 442.5 155.1 287.4 70 463.6 17.40 16.88 110.5 98.7 89 112.9 43.30 12.46 81.5 70.0 86 79.1 48.53 12.40 41.75 29.0 28.7 99 28.7 30.53 12.60 635.2 359.2 114.7 244.5 67 374.8 22.62 18.63 110.5 94.3 85 107.6 46.21 13.78 81.5 68.4 84 76.6 52.60 12.83 45.30 29.0 25.9 89 26.0 29.36 16.30 551.5 379.0 127.4 251.6 75 398.7 24.70 16.88 110.5 100.7 91 114.2 32.04 12.68 81.5 73.1 90 81.5 34.48 12.32 31.14 29.0 27.6 95 27.7 25.58 13.62 635.2 459.7 173.9 285.8 75 485.0 18.12 15.27 110.5 92.9 84 105.2 33.92 13.91 81.5 68.7 84 76.0 36.04 12.65 32.84 29.0 24.2 83 24.3 27.91 17.49 551.5 400.8 116.1 284.7 80 419.9 28.70 16.04 (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. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental. Based on benchmark price differential between heavy oil feedstock and synthetic crude. Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023. SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Downstream SUPPLEMENTAL INFORMATION (unaudited) Operating Statistics - Downstream U.S. Refining Lima Refinery Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) Toledo Refinery (2) Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) Superior Refinery Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (3) (percent) Wood River and Borger Refineries (4) Crude Oil Unit Throughput Capacity (1) (Mbbls/d) Crude Oil Unit Throughput (Mbbls/d) Crude Utilization (percent) (1) (2) (3) Three Months Ended Dec. 31, 2023 Sep. 30, 2023 Jun. 30, Mar. 31, 2023 2023 Dec. 31, 2022 Twelve Months Ended Dec. 31, 2022 Dec. 31, 2023 178.7 131.8 74 160.0 138.4 87 49.0 32.4 66 247.5 176.2 71 178.7 146.2 82 160.0 143.5 90 49.0 32.2 66 247.5 234.0 95 178.7 165.8 93 160.0 48.3 30 49.0 25.2 51 247.5 203.2 82 178.7 167.2 94 160.0 — — 49.0 0.2 — 247.5 191.8 77 175.0 162.6 93 80.0 — — 49.0 — — 247.5 216.4 87 178.7 152.7 85 160.0 83.1 57 49.0 22.6 61 247.5 201.3 81 175.0 157.9 90 80.0 36.3 45 49.0 — — 247.5 206.6 83 Based on crude oil name plate capacity. On February 28, 2023, we purchased the remaining 50 percent interest in Toledo. The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023. Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations. (4) 5.4 5.6 3.9 5.1 5.0 5.0 4.9 Advisory Specified Financial Measures Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International Financial Reporting Standards 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 section in the Advisory and in our MD&A for the periods ended September 30, 2023, June 30, 2023 and March 31, 2023 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference about these specified financial measures. Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information 6 Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information CENOVUS ENERGY 2023 ANNUAL REPORT | 145 7 ADVISORY Oil and Gas Information Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Forward-looking Information This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “may”, “objective”, “opportunities”, “plan”, “position”, “prioritize”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: shareholder value and returns; reducing operating, capital and general and administrative costs; realizing the full value of our integrated business; supporting long term value for Cenovus; safety performance; reliability and profitability; strategic growth; cost leadership; advocating for our company and industry; executing major projects such as West White Rose, SeaRose ALE, Narrows Lake tie-back at Christina Lake, and Sunrise and Foster Creek Optimization on time and on budget; delivering first oil from the West White Rose project in 2026; being world class operators; meeting targets for our five ESG focus areas; the Pathways Alliance foundational CCS project; sustainability and sustainability leadership; decarbonizing operations; maximizing long term profitability of our assets; our 2024 capital investment budget; returning incremental value to shareholders through share buybacks and/or variable dividends in accordance with the capital allocation framework; GHG emissions; methane emissions; infrastructure; operating and capital costs; capital investment, allocation, and structure; capital discipline; Free Funds Flow generation; resiliency; Excess Free Funds Flow allocation; flexibility in both high and low commodity price environments; funding near-term cash requirements; managing capital structure; returns from projects; dividends of any kind; share repurchases under the NCIB; deleveraging; meeting payment obligations; maintaining credit ratings; debt levels; Net Debt; Net Debt to Adjusted Funds Flow Ratio; Net Debt to Adjusted EBITDA Ratio; maintaining liquidity; production and production rates; crude throughput; consistent and reliable operations at all operated assets; operating performance; liabilities from legal proceedings; cash flow; price alignment and volatility management strategies; financial results; variable payments; provision for income taxes; capturing value; mitigating the impact of crude oil and refined product differentials; optimizing run rates at the Company’s refineries; achieving full operation of the Superior Refinery; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar and the influences and effects on Cenovus. Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to 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 bitumen, crude 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 crude 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 bitumen, 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; 146 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 ambitions 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 and achieving appropriate fiscal and policy supports for the Pathways Alliance foundational CCS project; 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 2024 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. 2024 guidance dated December 13, 2023, and available on cenovus.com, assumes: Brent prices of US$79.00 per barrel, WTI prices of US$75.00 per barrel; WCS of US$58.00 per barrel; Differential WTI-WCS of US$17.00 per barrel; AECO natural gas prices of $2.80 per Mcf; Chicago 3-2-1 crack spread of US$21.00 per barrel; and an exchange rate of $0.73 US$/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 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 ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions including obtaining policy and fiscal supports for the Pathways Alliance foundational CCS project; 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 being 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 Refining 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 ADVISORY Oil and Gas Information Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value. Forward-looking Information This document contains forward-looking statements and other information (collectively “forward-looking information”) about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”, “continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “may”, “objective”, “opportunities”, “plan”, “position”, “prioritize”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes, including, but not limited to, statements about: shareholder value and returns; reducing operating, capital and general and administrative costs; realizing the full value of our integrated business; supporting long term value for Cenovus; safety performance; reliability and profitability; strategic growth; cost leadership; advocating for our company and industry; executing major projects such as West White Rose, SeaRose ALE, Narrows Lake tie-back at Christina Lake, and Sunrise and Foster Creek Optimization on time and on budget; delivering first oil from the West White Rose project in 2026; being world class operators; meeting targets for our five ESG focus areas; the Pathways Alliance foundational CCS project; sustainability and sustainability leadership; decarbonizing operations; maximizing long term profitability of our assets; our 2024 capital investment budget; returning incremental value to shareholders through share buybacks and/or variable dividends in accordance with the capital allocation framework; GHG emissions; methane emissions; infrastructure; operating and capital costs; capital investment, allocation, and structure; capital discipline; Free Funds Flow generation; resiliency; Excess Free Funds Flow allocation; flexibility in both high and low commodity price environments; funding near-term cash requirements; managing capital structure; returns from projects; dividends of any kind; share repurchases under the NCIB; deleveraging; meeting payment obligations; maintaining credit ratings; debt levels; Net Debt; Net Debt to Adjusted Funds Flow Ratio; Net Debt to Adjusted EBITDA Ratio; maintaining liquidity; production and production rates; crude throughput; consistent and reliable operations at all operated assets; operating performance; liabilities from legal proceedings; cash flow; price alignment and volatility management strategies; financial results; variable payments; provision for income taxes; capturing value; mitigating the impact of crude oil and refined product differentials; optimizing run rates at the Company’s refineries; achieving full operation of the Superior Refinery; transportation and storage commitments; and the Company’s outlook for commodities and the Canadian dollar and the influences and effects on Cenovus. Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ materially from those expressed or implied. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to 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 bitumen, crude 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 crude 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 bitumen, 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 ambitions 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 and achieving appropriate fiscal and policy supports for the Pathways Alliance foundational CCS project; 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 2024 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. 2024 guidance dated December 13, 2023, and available on cenovus.com, assumes: Brent prices of US$79.00 per barrel, WTI prices of US$75.00 per barrel; WCS of US$58.00 per barrel; Differential WTI-WCS of US$17.00 per barrel; AECO natural gas prices of $2.80 per Mcf; Chicago 3-2-1 crack spread of US$21.00 per barrel; and an exchange rate of $0.73 US$/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 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 ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products; the development and execution of implementing strategies to meet climate and GHG emissions targets and ambitions including obtaining policy and fiscal supports for the Pathways Alliance foundational CCS project; 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 being 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 Refining 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 CENOVUS ENERGY 2023 ANNUAL REPORT | 147 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 Refining 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 implementing targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in the Company’s most recently filed Annual 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 sedarplus.ca, 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 Crude Oil and NGLs bbl barrel The following abbreviations and definitions are used in this document: Natural Gas Mcf thousand cubic feet Other BOE Mbbls/d thousand barrels per day MMcf million cubic feet MBOE equivalent WCS WTI Western Canadian Select MMcf/d million cubic feet per day MBOE/d equivalent per day West Texas Intermediate Bcf billion cubic feet MMBOE million barrels of oil equivalent barrel of oil equivalent thousand barrels of oil thousand barrels of oil CO2e carbon dioxide equivalent depreciation, depletion and amortization greenhouse gas normal course issuer bid Alberta Energy Company NYMEX New York Mercantile Exchange Organization of Petroleum OPEC Exporting Countries OPEC and a group of 11 non-OPEC members steam-assisted gravity drainage U.S. Gulf Coast DD&A GHG NCIB AECO OPEC+ SAGD USGC 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. 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. all of its assets. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 68 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 69 148 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 Refining 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 implementing targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results from operations. Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors in the Company’s most recently filed Annual 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 sedarplus.ca, 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 The following abbreviations and definitions are used in this document: Crude Oil and NGLs bbl barrel Natural Gas Mcf thousand cubic feet Mbbls/d thousand barrels per day MMcf million cubic feet WCS WTI Western Canadian Select MMcf/d million cubic feet per day West Texas Intermediate Bcf billion cubic feet Other BOE MBOE MBOE/d MMBOE CO2e DD&A GHG NCIB AECO barrel of oil equivalent thousand barrels of oil equivalent thousand barrels of oil equivalent per day million barrels of oil equivalent carbon dioxide equivalent depreciation, depletion and amortization greenhouse gas normal course issuer bid Alberta Energy Company NYMEX New York Mercantile Exchange OPEC OPEC+ SAGD USGC Organization of Petroleum Exporting Countries OPEC and a group of 11 non-OPEC members steam-assisted gravity drainage U.S. Gulf Coast 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. 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. Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 68 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 69 CENOVUS ENERGY 2023 ANNUAL REPORT | 149 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, 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 are 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. Refer to the Specified Financial Measures Advisory of our 2022 annual MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow for quarters in 2022 and 2021 not found below. Operating Margin Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for Upstream or Downstream operations 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 expenses, 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. 2023 2022 2021 2023 2022 2021 2023 2022 2021 Upstream (1) Downstream (1) Total 31,082 3,270 27,812 3,152 11,088 3,690 12 9,870 41,142 4,868 36,274 6,741 12,301 3,789 1,619 11,824 27,925 2,454 25,471 4,059 8,795 3,241 788 8,588 32,626 38,010 26,258 — — — 32,626 38,010 26,258 28,273 32,409 23,111 — 3,201 — 1,152 — 3,050 112 2,439 — 2,258 104 785 63,708 3,270 60,438 31,425 11,088 6,891 12 11,022 79,152 4,868 74,284 39,150 12,301 6,839 1,731 14,263 54,183 2,454 51,729 27,170 8,795 5,499 892 9,373 Upstream (1) Q4 Q3 Q2 Q1 Q4 2023 Downstream (1) Q2 Q3 Total Q1 Q4 Q3 Q2 Q1 7,797 902 6,895 8,783 1,135 7,648 7,285 7,217 8,404 9,658 7,427 7,137 16,201 18,441 14,712 14,354 637 596 — — — — 902 1,135 637 596 6,648 6,621 8,404 9,658 7,427 7,137 15,299 17,306 14,075 13,758 663 900 751 838 7,888 7,947 6,447 5,991 8,551 8,847 7,198 6,829 ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management Operating Margin ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management 2,894 2,397 2,770 864 914 883 3,027 1,029 — 826 19 (10) (13) 16 (6) — 778 11 922 — 843 (6) 143 — 2,894 754 1,690 2,397 1,692 2,770 1,726 3,027 1,783 1 13 1 (19) 17 391 2,151 4,369 2,400 2,102 Operating Margin 2,455 3,447 2,257 1,711 (304) (1) (2) Found in Note 1 of the Consolidated Financial Statements. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 70 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 71 150 | CENOVUS ENERGY 2023 ANNUAL REPORT Upstream (1) 2022 Downstream (1) Total Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 8,251 10,250 11,719 10,922 8,302 10,873 10,719 8,116 16,553 21,123 22,438 19,038 875 7,376 1,226 9,024 1,582 10,137 1,185 9,737 — — — — 875 1,226 1,582 1,185 8,302 10,873 10,719 8,116 15,678 19,897 20,856 17,853 1,079 2,383 1,461 1,818 6,993 9,680 8,919 6,817 8,072 12,063 10,380 8,635 2,984 2,826 955 915 3,272 1,010 3,219 909 134 51 563 871 — 759 (8) 558 — 780 (77) 490 — 866 87 847 — 2,984 645 1,714 2,826 1,695 3,272 1,876 3,219 1,554 110 544 126 (26) 650 981 2,782 3,339 4,678 3,464 Operating Margin 2,224 2,849 3,831 2,920 Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions Found in Note 1 of the Consolidated Financial Statements. (1) (2) found in the Advisory for further details. Operating Margin by Asset Year Ended December 31, 2023 Atlantic Asia Pacific Offshore (1) ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management ($ 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) Found in Note 1 of the Consolidated Financial Statements. 400 15 385 16 262 107 578 (3) 581 15 204 362 1,217 84 1,133 — 122 1,011 1,442 80 1,362 — 114 1,248 1,617 99 1,518 16 384 1,118 2,020 77 1,943 15 318 1,610 Year Ended December 31, 2022 Atlantic Asia Pacific Offshore (1) (1) Found in Note 1 of the Consolidated Financial Statements. 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, in total and on a per-share basis. 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, income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), 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. Operating Margin 2,224 2,849 3,831 2,920 2,984 2,826 955 915 3,272 1,010 3,219 909 134 51 563 871 ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management — 759 (8) 558 — 780 (77) 490 — 866 87 847 — 2,984 645 1,714 2,826 1,695 3,272 1,876 3,219 1,554 110 544 126 (26) 650 981 2,782 3,339 4,678 3,464 Upstream (1) Q4 Q3 Q2 Q1 Q4 2022 Downstream (1) Q2 Q3 Total Q1 Q4 Q3 Q2 Q1 8,251 10,250 11,719 10,922 8,302 10,873 10,719 8,116 16,553 21,123 22,438 19,038 875 7,376 1,226 9,024 1,582 10,137 1,185 9,737 — — — — 875 1,226 1,582 1,185 8,302 10,873 10,719 8,116 15,678 19,897 20,856 17,853 1,079 2,383 1,461 1,818 6,993 9,680 8,919 6,817 8,072 12,063 10,380 8,635 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, 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 are 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. Refer to the Specified Financial Measures Advisory of our 2022 annual MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow for quarters in 2022 and 2021 not found below. Operating Margin Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for Upstream or Downstream operations 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 expenses, 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. 2023 2022 2021 2023 2022 2021 2023 2022 2021 Upstream (1) Downstream (1) Total ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management Operating Margin ($ millions) Revenues Gross Sales (2) Less: Royalties Expenses Purchased Product (2) Transportation and Blending (2) Operating Realized (Gain) Loss on Risk Management 31,082 3,270 27,812 3,152 11,088 3,690 12 9,870 41,142 4,868 36,274 6,741 12,301 3,789 1,619 11,824 27,925 2,454 25,471 4,059 8,795 3,241 788 8,588 32,626 38,010 26,258 — — — 32,626 38,010 26,258 28,273 32,409 23,111 3,201 — — 1,152 — 3,050 112 2,439 — 2,258 104 785 63,708 3,270 60,438 31,425 11,088 6,891 12 11,022 54,183 2,454 51,729 27,170 8,795 5,499 892 9,373 79,152 4,868 74,284 39,150 12,301 6,839 1,731 14,263 Total Upstream (1) 2023 Downstream (1) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 7,797 902 6,895 8,783 1,135 7,648 7,285 7,217 8,404 9,658 7,427 7,137 16,201 18,441 14,712 14,354 637 596 — — — — 902 1,135 637 596 6,648 6,621 8,404 9,658 7,427 7,137 15,299 17,306 14,075 13,758 663 900 751 838 7,888 7,947 6,447 5,991 8,551 8,847 7,198 6,829 2,894 2,397 2,770 864 914 883 3,027 1,029 — 826 — 2,894 754 1,690 2,397 1,692 2,770 1,726 3,027 1,783 — 778 11 922 — 843 (6) 143 Operating Margin 2,455 3,447 2,257 1,711 (304) 19 (10) (13) 16 (6) 1 13 1 (19) 17 391 2,151 4,369 2,400 2,102 Found in Note 1 of the Consolidated Financial Statements. (1) (2) found in the Advisory for further details. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions (1) (2) Found in Note 1 of the Consolidated Financial Statements. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Operating Margin by Asset ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin (1) Found in Note 1 of the Consolidated Financial Statements. ($ millions) Revenues Gross Sales Less: Royalties Expenses Transportation and Blending Operating Operating Margin Year Ended December 31, 2023 Atlantic Asia Pacific Offshore (1) 400 15 385 16 262 107 1,217 84 1,133 — 122 1,011 1,617 99 1,518 16 384 1,118 Year Ended December 31, 2022 Atlantic Asia Pacific Offshore (1) 578 (3) 581 15 204 362 1,442 80 1,362 — 114 1,248 2,020 77 1,943 15 318 1,610 (1) Found in Note 1 of the Consolidated Financial Statements. 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, in total and on a per-share basis. 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, income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), 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. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 70 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 71 CENOVUS ENERGY 2023 ANNUAL REPORT | 151 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. 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 Payment on Divestiture of Assets Excess Free Funds Flow 2023 7,388 (222) (1,193) 8,803 4,298 4,505 2022 11,403 (150) 575 10,978 3,708 7,270 2023 2,946 (65) 949 2,062 1,170 892 (261) (9) (65) (72) (14) — — 471 2022 2,970 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 — 786 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 unit 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 from our refineries and upgrader divided by barrels of crude oil unit throughput. Canadian Refining Basis of Refining Margin Calculation Three Months Ended December 31, 2023 ($ millions) Revenues Purchased Product Gross Margin Lloydminster Upgrader Lloydminster Refinery 1,191 964 227 263 233 30 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,454 1,197 257 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) 73.6 33.48 26.7 11.96 100.3 27.74 (1) (2) Includes ethanol operations and crude-by-rail operations. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Other (1) 103 66 37 Total Canadian Refining (2) 1,557 1,263 294 Basis of Refining Margin Calculation Three Months Ended December 31, 2022 Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total Other (1) 627 580 47 Total Canadian Refining (2) 1,772 1,324 448 ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) (1) (2) Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Basis of Refining Margin Calculation Year Ended December 31, 2023 Lloydminster Upgrader and Lloydminster Refinery Total Lloydminster Upgrader Lloydminster Refinery Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total (1) (2) Includes ethanol operations and crude-by-rail operations. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. 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 (1) (2) Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. 1,145 744 401 94.3 46.21 5,812 4,634 1,178 100.7 32.04 4,878 3,727 1,151 92.9 33.92 905 574 331 68.4 52.60 4,810 3,890 920 73.1 34.48 3,822 2,918 904 68.7 36.04 240 170 70 25.9 29.36 1,002 744 258 27.6 25.58 1,056 809 247 24.2 27.91 Other (1) 421 285 136 Total Canadian Refining (2) 6,233 4,919 1,314 Other (1) 2,914 2,662 252 Total Canadian Refining (2) 7,792 6,389 1,403 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 72 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 73 152 | CENOVUS ENERGY 2023 ANNUAL REPORT 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 Three Months Ended December 31, Year Ended December 31, payments related to divestitures. ($ 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 Payment on Divestiture of Assets Excess Free Funds Flow 2023 7,388 (222) (1,193) 8,803 4,298 4,505 2022 11,403 (150) 575 10,978 3,708 7,270 2023 2,946 (65) 949 2,062 1,170 892 (261) (9) (65) (72) (14) — — 471 2022 2,970 (49) 673 2,346 1,274 1,072 (201) — (49) (74) (7) 45 — 786 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 unit 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 from our refineries and upgrader divided by barrels of crude oil unit throughput. ($ 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 Unit Throughput (Mbbls/d) Refining Margin ($/bbl) 68.4 52.60 25.9 29.36 94.3 46.21 (1) (2) Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Basis of Refining Margin Calculation Year Ended December 31, 2023 ($ millions) Revenues Purchased Product Gross Margin Lloydminster Upgrader Lloydminster Refinery 4,810 3,890 920 1,002 744 258 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 5,812 4,634 1,178 Lloydminster Upgrader and Lloydminster Refinery Total Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) 73.1 34.48 27.6 25.58 100.7 32.04 (1) (2) Includes ethanol operations and crude-by-rail operations. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Other (1) 627 580 47 Total Canadian Refining (2) 1,772 1,324 448 Other (1) 421 285 136 Total Canadian Refining (2) 6,233 4,919 1,314 Canadian Refining ($ millions) Revenues Purchased Product Gross Margin Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) Basis of Refining Margin Calculation Three Months Ended December 31, 2023 Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total 1,191 964 227 73.6 33.48 263 233 30 26.7 11.96 1,454 1,197 257 100.3 27.74 Operating Statistics Lloydminster Upgrader Lloydminster Refinery Lloydminster Upgrader and Lloydminster Refinery Total (1) (2) Includes ethanol operations and crude-by-rail operations. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Other (1) 103 66 37 Total Canadian Refining (2) 1,557 1,263 294 ($ 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 (1) 2,914 2,662 252 Total Canadian Refining (2) 7,792 6,389 1,403 Heavy Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) 68.7 36.04 24.2 27.91 92.9 33.92 (1) (2) Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business. These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 72 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 73 CENOVUS ENERGY 2023 ANNUAL REPORT | 153 U.S. Refining ($ millions) Revenues (1) (2) Purchased Product (1) (2) Gross Margin Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues (1) (2) Purchased Product (1) (2) Gross Margin Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) Three Months Ended 2023 Q3 7,853 6,467 1,386 555.9 27.10 Q2 6,064 5,364 700 442.5 17.40 Q4 6,847 6,625 222 478.8 5.03 Q1 5,629 4,898 731 359.2 22.62 2022 Q4 6,530 5,669 861 379.0 24.70 Year Ended December 31, 2023 26,393 23,354 3,039 459.7 18.12 2022 30,218 26,020 4,198 400.8 28.70 (1) (2) Found in Note 1 of the interim Consolidated Financial Statements. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Per Unit DD&A Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define Per Unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties and the associated asset retirement costs divided by sales volumes. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 74 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 154 | CENOVUS ENERGY 2023 ANNUAL REPORT Netback Reconciliations Netback per BOE is a non-GAAP ratio. Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. 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 expense, 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. Three Months Ended December 31, 2023 ($ millions) Foster Creek Christina Lake Natural Gas Total Oil Sands 1,312 1,447 353 — 200 174 585 366 — 161 167 753 Basis of Netback Calculation Other Oil Sands (1) Total Bitumen and Heavy Oil 778 86 — 39 203 450 3,894 837 — 458 609 1,990 Three Months Ended December 31, 2023 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) Total Oil Sands (3) Basis of Netback Calculation Adjustments Sunrise 357 32 — 58 65 202 2,329 2,329 — — — — — — Sunrise 222 13 — 42 60 107 2,415 2,415 — — — — — — 3,896 838 — 458 610 1,990 24 1,966 3,706 784 — 493 735 1,694 59 1,635 156 — 156 — — — — — 422 — 422 — — — — — Three Months Ended December 31, 2022 ($ millions) Foster Creek Christina Lake Natural Gas Total Oil Sands 1,282 1,453 338 — 255 194 495 344 — 157 221 731 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 Three Months Ended December 31, 2022 ($ millions) Total Oil Sands Condensate Third-party Sourced (4) Other (2) Total Oil Sands (3) (4) Basis of Netback Calculation Adjustments 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. (1) (2) (3) (4) Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. 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 Royalties Operating Netback Purchased Product Transportation and Blending Realized (Gain) Loss on Risk Management Operating Margin 2 1 — — 1 — 4 1 — — 3 — 96 3 70 22 5 (4) — (4) 110 — 94 14 (2) 4 — 4 3,896 838 — 458 610 1,990 24 1,966 6,477 841 226 2,809 615 1,986 24 1,962 3,706 784 — 493 735 1,694 59 1,635 6,653 784 516 2,922 733 1,698 59 1,639 75 U.S. Refining ($ millions) Revenues (1) (2) Purchased Product (1) (2) Gross Margin Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) ($ millions) Revenues (1) (2) Purchased Product (1) (2) Gross Margin Crude Oil Unit Throughput (Mbbls/d) Refining Margin ($/bbl) Per Unit DD&A Three Months Ended 2023 2022 Q4 6,847 6,625 222 478.8 5.03 Q3 7,853 6,467 1,386 555.9 27.10 Q2 6,064 5,364 700 442.5 17.40 Q1 5,629 4,898 731 359.2 22.62 2023 26,393 23,354 3,039 459.7 18.12 Q4 6,530 5,669 861 379.0 24.70 2022 30,218 26,020 4,198 400.8 28.70 Found in Note 1 of the interim Consolidated Financial Statements. (1) (2) found in the Advisory for further details. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define Per Unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties and the associated asset retirement costs divided by sales volumes. Netback Reconciliations Netback per BOE is a non-GAAP ratio. Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating performance. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and blending and operating expenses, and Netback per BOE is divided by sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold, and exclude risk management activities. The sales price, transportation and blending expense, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market. The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin found in our interim Consolidated Financial Statements. Year Ended December 31, Basis of Netback Calculation Oil Sands Three Months Ended December 31, 2023 ($ millions) Foster Creek Christina Lake Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 1,312 1,447 353 — 200 174 585 366 — 161 167 753 Basis of Netback Calculation Sunrise 357 32 — 58 65 202 Other Oil Sands (1) 778 86 — 39 203 450 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 3,894 837 — 458 609 1,990 2 1 — — 1 — 3,896 838 — 458 610 1,990 24 1,966 Three Months Ended December 31, 2023 ($ millions) Total Oil Sands Condensate Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 3,896 838 — 458 610 1,990 24 1,966 2,329 — — 2,329 — — — — Adjustments Third-party Sourced 156 Other (2) 96 Total Oil Sands (3) 6,477 — 156 — — — — — 3 70 22 5 (4) — (4) 841 226 2,809 615 1,986 24 1,962 Three Months Ended December 31, 2022 ($ millions) Foster Creek Christina Lake Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 1,282 1,453 338 — 255 194 495 344 — 157 221 731 Basis of Netback Calculation Basis of Netback Calculation Sunrise 222 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 Three Months Ended December 31, 2022 ($ millions) Total Oil Sands Condensate Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 3,706 784 — 493 735 1,694 59 1,635 2,415 — — 2,415 — — — — Adjustments Third-party Sourced (4) 422 Other (2) 110 Total Oil Sands (3) (4) 6,653 — 422 — — — — — — 94 14 (2) 4 — 4 784 516 2,922 733 1,698 59 1,639 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 74 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 75 CENOVUS ENERGY 2023 ANNUAL REPORT | 155 (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. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Year Ended December 31, 2023 ($ millions) Foster Creek Christina Lake 5,347 1,136 — 819 782 2,610 5,848 1,556 — 572 729 2,991 Basis of Netback Calculation Total Oil Sands 15,709 3,056 — 1,759 2,698 8,196 17 8,179 Basis of Netback Calculation Conventional Sunrise 1,298 74 — 215 294 715 Other Oil Sands (1) 3,208 285 — 153 884 1,886 Total Bitumen and Heavy Oil Natural Gas Total Oil Sands 15,701 3,051 — 1,759 2,689 8,202 8 5 — — 9 (6) 15,709 3,056 — 1,759 2,698 8,196 17 8,179 Adjustments Condensate 8,907 Third-party Sourced 1,199 Other (2) 377 Total Oil Sands (3) 26,192 — — 8,907 — — — — — 1,199 — — — — — Basis of Netback Calculation 3 258 108 18 (10) — (10) 3,059 1,457 10,774 2,716 8,186 17 8,169 Foster Creek 6,723 Christina Lake 7,951 Sunrise 950 1,783 — 814 870 3,256 2,244 — 588 898 4,221 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 Basis of Netback Calculation Total Oil Sands 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 Adjustments Condensate 10,307 Third-party Sourced (4) 4,409 Other (2) 358 Total Oil Sands (3) (4) 34,683 — — 10,307 — — — — — 4,409 — — — — — 11 309 43 (11) 6 — 6 4,493 4,718 12,036 2,930 10,506 1,527 8,979 Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin Year Ended December 31, 2023 ($ 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, 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, 2023 ($ millions) Conventional Third-party Sourced Other (1) Conventional (2) Basis of Netback Calculation Adjustments Three Months Ended December 31, 2022 ($ millions) Conventional Third-party Sourced (3) Other (1) Conventional (2) (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 331 27 — 54 141 109 (5) 114 555 69 — 47 135 304 75 229 1,390 112 — 182 570 526 (5) 531 2,238 297 — 147 520 1,274 84 1,190 437 — 437 — — — — — 563 — 563 — — — — — 1,695 1,695 — — — — — — 2,023 2,023 — — — — 8 (8) 38 — — 24 5 9 — 9 35 1 — 12 3 19 — 19 188 — — 116 20 52 — 52 178 1 — 103 21 53 — 53 806 27 437 78 146 118 (5) 123 1,153 70 563 59 138 323 75 248 3,273 112 1,695 298 590 578 (5) 583 4,439 298 2,023 250 541 1,327 92 1,235 Year Ended December 31, 2022 ($ millions) Conventional Third-party Sourced (3) Other (1) Conventional (2) (3) Basis of Netback Calculation Adjustments Year Ended December 31, 2023 ($ millions) Conventional Third-party Sourced Other (1) Conventional (2) Basis of Netback Calculation Adjustments (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. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Reflects Operating Margin from processing facilities. These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements. (1) (2) (3) Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 76 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 77 156 | CENOVUS ENERGY 2023 ANNUAL REPORT Year Ended December 31, 2023 ($ millions) Foster Creek Christina Lake Basis of Netback Calculation Total Bitumen and Heavy Oil Natural Gas Total Oil Sands Conventional Basis of Netback Calculation Adjustments Three Months Ended December 31, 2023 ($ millions) Conventional Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 331 27 — 54 141 109 (5) 114 Third-party Sourced 437 Other (1) 38 Conventional (2) 806 — 437 — — — — — — — 24 5 9 — 9 27 437 78 146 118 (5) 123 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 Basis of Netback Calculation Adjustments Conventional 555 Third-party Sourced (3) 563 Other (1) 35 Conventional (2) (3) 1,153 69 — 47 135 304 75 229 — 563 — — — — — 1 — 12 3 19 — 19 70 563 59 138 323 75 248 Year Ended December 31, 2022 ($ millions) Foster Creek Christina Lake Sunrise Natural Gas Total Oil Sands Year Ended December 31, 2023 ($ 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 1,390 112 — 182 570 526 (5) 531 1,695 — 1,695 — — — — — Other (1) 188 Conventional (2) 3,273 — — 116 20 52 — 52 112 1,695 298 590 578 (5) 583 Basis of Netback Calculation Adjustments Year Ended December 31, 2022 ($ millions) Conventional 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 Third-party Sourced (3) 2,023 Other (1) 178 Conventional (2) (3) 4,439 — 2,023 — — — 8 (8) 1 — 103 21 53 — 53 298 2,023 250 541 1,327 92 1,235 (1) (2) (3) Reflects Operating Margin from processing facilities. These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements. Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Year Ended December 31, 2023 ($ millions) Total Oil Sands Condensate Third-party Sourced Other (2) Total Oil Sands (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 5,347 1,136 — 819 782 2,610 5,848 1,556 — 572 729 2,991 Sunrise 1,298 74 — 215 294 715 Other Oil Sands (1) 3,208 285 — 153 884 1,886 15,701 3,051 — 1,759 2,689 8,202 15,709 3,056 — 1,759 2,698 8,196 17 8,179 6,723 1,783 — 814 870 3,256 7,951 2,244 — 588 898 4,221 Basis of Netback Calculation Total Oil Sands 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 8,907 8,907 — — — — — — 950 59 — 135 193 563 10,307 10,307 — — — — — — 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 Adjustments 1,199 1,199 — — — — — — 4,409 4,409 — — — — — — 8 5 — — 9 (6) 18 6 — — 20 (8) 377 3 258 108 18 (10) — (10) 358 11 309 43 (11) 6 — 6 15,709 3,056 — 1,759 2,698 8,196 17 8,179 26,192 3,059 1,457 10,774 2,716 8,186 17 8,169 19,609 4,482 — 1,686 2,941 10,500 1,527 8,973 34,683 4,493 4,718 12,036 2,930 10,506 1,527 8,979 Year Ended December 31, 2022 ($ millions) Condensate Third-party Sourced (4) Other (2) Total Oil Sands (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. (1) (2) (3) (4) Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further details. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 76 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 77 CENOVUS ENERGY 2023 ANNUAL REPORT | 157 Offshore Three Months Ended December 31, 2023 ($ millions) Atlantic Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 168 4 — 7 71 86 Basis of Netback Calculation China 346 Indonesia (1) 91 Total Asia Pacific 437 Total Offshore 605 30 — — 29 287 18 — — 17 56 48 — — 46 343 52 — 7 117 429 — 429 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 Basis of Netback Calculation Atlantic 86 China 359 Indonesia (1) 77 Total Asia Pacific 436 Total Offshore 522 1 — 3 48 34 20 — — 24 315 27 — — 17 33 47 — — 41 348 48 — 3 89 382 — 382 Adjustments Equity Adjustment (1) (91) (18) — — (15) (58) — (58) Adjustments Equity Adjustment (1) (77) (27) — — (15) (35) — (35) Year Ended December 31, 2023 ($ millions) Atlantic Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 400 15 — 16 239 130 Year Ended December 31, 2022 ($ millions) Atlantic Gross Sales Royalties Purchased Product Transportation and Blending Operating Netback Realized (Gain) Loss on Risk Management Operating Margin 578 (3) — 15 175 391 Basis of Netback Calculation China 1,217 Indonesia (1) 317 84 — — 111 1,022 74 — — 58 185 Total Asia Pacific Total Offshore 1,534 158 — — 169 1,207 1,934 173 — 16 408 1,337 — 1,337 Adjustments Equity Adjustment (1) (317) (74) — — (47) (196) — (196) Basis of Netback Calculation China 1,442 Indonesia (1) 271 80 — — 99 1,263 116 — — 51 104 Total Asia Pacific Total Offshore 1,713 196 — — 150 1,367 2,291 193 — 15 325 1,758 — 1,758 Adjustments Equity Adjustment (1) (271) (116) — — (36) (119) — (119) Other (2) — Total Offshore (3) 514 — — — 1 (1) — (1) 34 — 7 103 370 — 370 Other (2) — Total Offshore (3) 445 — — — 10 (10) — (10) 21 — 3 84 337 — 337 Other (2) — Total Offshore (3) 1,617 — — 23 (23) — (23) 99 — 16 384 1,118 — 1,118 Other (2) — Total Offshore (3) 2,020 — — — 29 (29) — (29) 77 — 15 318 1,610 — 1,610 (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 West White Rose project expenses. These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements. Upstream Sales Volumes (1) The following table provides the sales volumes used to calculate Netback: Three Months Ended December 31, Year Ended December 31, (MBOE/d) Oil Sands Foster Creek Christina Lake Sunrise Other Oil Sands Total Oil Sands Conventional Offshore Atlantic Asia Pacific China Indonesia Total Asia Pacific Total Offshore Sales Before Internal Consumption Less: Internal Consumption (2) Total Upstream Sales 2023 192.6 238.6 50.8 123.4 605.4 123.8 15.0 44.2 16.3 60.5 75.5 804.7 (104.5) 700.2 2022 184.7 246.5 42.0 118.5 591.7 125.5 7.3 47.1 12.8 59.9 67.2 784.4 (93.4) 691.0 2023 187.4 234.3 47.3 120.5 589.5 119.9 9.6 40.5 14.7 55.2 64.8 774.2 (92.6) 681.6 2022 189.4 247.5 30.2 118.7 585.8 127.2 11.3 48.2 10.5 58.7 70.0 783.0 (86.6) 696.4 Sales volumes exclude the impact of purchased condensate. (1) (2) Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 78 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 79 158 | CENOVUS ENERGY 2023 ANNUAL REPORT Three Months Ended December 31, 2023 ($ millions) Atlantic China Indonesia (1) Asia Pacific Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments Upstream Sales Volumes (1) The following table provides the sales volumes used to calculate Netback: Three Months Ended December 31, Year Ended December 31, (MBOE/d) Oil Sands Foster Creek Christina Lake Sunrise Other Oil Sands Total Oil Sands Conventional Offshore Atlantic Asia Pacific China Indonesia Total Asia Pacific Total Offshore Year Ended December 31, 2023 ($ millions) Atlantic Indonesia (1) Asia Pacific Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments Sales Before Internal Consumption Less: Internal Consumption (2) Total Upstream Sales 2023 192.6 238.6 50.8 123.4 605.4 123.8 15.0 44.2 16.3 60.5 75.5 804.7 (104.5) 700.2 2022 184.7 246.5 42.0 118.5 591.7 125.5 7.3 47.1 12.8 59.9 67.2 784.4 (93.4) 691.0 2023 187.4 234.3 47.3 120.5 589.5 119.9 9.6 40.5 14.7 55.2 64.8 774.2 (92.6) 681.6 2022 189.4 247.5 30.2 118.7 585.8 127.2 11.3 48.2 10.5 58.7 70.0 783.0 (86.6) 696.4 (1) (2) Sales volumes exclude the impact of purchased condensate. Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment. Three Months Ended December 31, 2022 ($ millions) Atlantic China Indonesia (1) Asia Pacific Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments Offshore 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 168 4 — 7 71 86 86 1 — 3 48 34 400 15 — 16 239 130 578 (3) — 15 175 391 346 30 — — 29 287 359 20 — — 24 315 China 1,217 84 — — 111 1,022 China 1,442 80 — — 99 1,263 Total 437 48 — — 46 343 Total 436 47 — — 41 348 Total 1,534 158 — — 169 1,207 Total 1,713 196 — — 150 1,367 91 18 — — 17 56 77 27 — — 17 33 317 74 — — 58 185 271 116 — — 51 104 605 52 — 7 117 429 — 429 522 48 — 3 89 382 — 382 1,934 173 — 16 408 1,337 — 1,337 2,291 193 — 15 325 1,758 — 1,758 (91) (18) — — (15) (58) — (58) (77) (27) — — (15) (35) — (35) (317) (74) — — (47) (196) — (196) (271) (116) — — (36) (119) — (119) — — — — 1 (1) — (1) — — — — 10 (10) — (10) — — — 23 (23) — (23) — — — — 29 (29) — (29) 514 34 — 7 103 370 — 370 445 21 — 3 84 337 — 337 1,617 99 — 16 384 1,118 — 1,118 2,020 77 — 15 318 1,610 — 1,610 Year Ended December 31, 2022 ($ millions) Atlantic Indonesia (1) Asia Pacific Total Offshore Equity Adjustment (1) Other (2) Total Offshore (3) Basis of Netback Calculation Adjustments (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 West White Rose project expenses. These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 78 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 79 CENOVUS ENERGY 2023 ANNUAL REPORT | 159 Prior Period Revisions Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was revised for classification changes. Classification Revisions In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made: • • Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense. Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product. Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. Change to Reporting Segments In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Refining segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss), cash flows or financial position. The following tables reconcile the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Purchased Product Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Corporate and Eliminations Segment Three Months Ended March 31, 2023 (1) Three Months Ended June 30, 2023 (2) Previously Reported Revisions Revised Balance Previously Reported Revisions Revised Balance 5,911 559 5,352 1,031 510 48 473 5,860 5,129 731 (1,925) (1,499) (141) (231) (54) 5,792 2,853 1,552 10,197 (204) (204) — 6 (27) 33 — (231) (231) — 429 479 (134) 84 — 17 (101) 84 — 5,707 355 5,352 1,037 483 81 473 5,629 4,898 731 (1,496) (1,020) (275) (147) (54) 5,809 2,752 1,636 10,197 6,556 533 6,023 615 352 46 217 6,198 5,498 700 (2,092) (1,757) (109) (185) (41) 5,709 2,641 1,541 9,891 (119) (119) — 5 (15) 20 — (134) (134) — 248 287 (98) 59 — 19 (78) 59 — 6,437 414 6,023 620 337 66 217 6,064 5,364 700 (1,844) (1,470) (207) (126) (41) 5,728 2,563 1,600 9,891 (1) Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Refining segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment. (2) Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in the U.S. Refining segment for the reasons noted above with an offsetting adjustment to the Corporate and Eliminations segment. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 80 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 81 160 | CENOVUS ENERGY 2023 ANNUAL REPORT Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was Prior Period Revisions revised for classification changes. Classification Revisions In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to correct the elimination of these transactions on consolidation. The following adjustments were made: • • Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between gross sales and transportation and blending expense. Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which resulted in a reclassification between gross sales and purchased product. Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an understatement of operating expense, overstatement of purchased product and an overstatement of transportation and blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating margin, segment income (loss), cash flows or financial position. Change to Reporting Segments In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022, Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the Canadian Refining segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss), cash flows or financial position. The following tables reconcile the amounts previously reported in the Consolidated Statements of Earnings (Loss) and segmented disclosures to the corresponding revised amounts: ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Purchased Product Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Three Months Ended March 31, 2023 (1) Previously Reported Revisions Revised Balance Three Months Ended June 30, 2023 (2) Previously Reported Revisions Revised Balance 5,911 559 5,352 1,031 510 48 473 5,860 5,129 731 (1,925) (1,499) (141) (231) (54) 5,792 2,853 1,552 10,197 (204) (204) — 6 (27) 33 — (231) (231) — 429 479 (134) 84 — 17 (101) 84 — 5,707 355 5,352 1,037 483 81 473 5,629 4,898 731 (1,496) (1,020) (275) (147) (54) 5,809 2,752 1,636 10,197 6,556 533 6,023 615 352 46 217 6,198 5,498 700 (2,092) (1,757) (109) (185) (41) 5,709 2,641 1,541 9,891 (119) (119) — 5 (15) 20 — (134) (134) — 248 287 (98) 59 — 19 (78) 59 — 6,437 414 6,023 620 337 66 217 6,064 5,364 700 (1,844) (1,470) (207) (126) (41) 5,728 2,563 1,600 9,891 (1) (2) Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in the U.S. Refining segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting adjustment to the Corporate and Eliminations segment. Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in the U.S. Refining segment for the reasons noted above with an offsetting adjustment to the Corporate and Eliminations segment. Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 80 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 81 CENOVUS ENERGY 2023 ANNUAL REPORT | 161 ($ millions) Conventional Segment Gross Sales Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Transportation and Blending Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Three Months Ended March 31, 2022 Three Months Ended June 30, 2022 Previously Reported Revisions Segment Aggregation Revised Balance Previously Reported Revisions Segment Aggregation Revised Balance 1,112 34 1,078 1,044 804 2 124 42 72 694 660 27 8 (1) (1,761) (1,282) (221) (267) 9 7,482 2,975 1,287 11,744 25 25 — — 2 (2) — — — — — — — — (25) 39 (110) 46 — 41 (87) 46 — — — — 563 529 — 27 8 (1) (694) (660) (27) (8) 1 131 131 — — — — — — — 1,137 59 1,078 1,607 1,335 — 151 50 71 — — — — — (1,655) (1,112) (331) (221) 9 7,523 2,888 1,333 1,079 34 1,045 1,521 1,296 (2) 180 64 (17) 849 811 31 8 (1) (1,782) (1,111) (188) (395) (88) 9,396 3,048 1,481 11,744 13,925 34 34 — — (2) 2 — — — — — — — — (34) 69 (145) 42 — 67 (109) 42 — — — — 724 686 — 31 8 (1) (849) (811) (31) (8) 1 125 125 — — — — — — — 1,113 68 1,045 2,245 1,980 — 211 72 (18) — — — — — (1,691) (917) (333) (353) (88) 9,463 2,939 1,523 13,925 ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Transportation and Blending Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization U.S. Refining Segment Gross Sales Purchased Product Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Corporate and Eliminations Segment Three Months Ended September 30, 2022 Three Months Ended December 31, 2022 Previously Reported Segment Revisions Aggregation Revised Balance Previously Reported Revisions Revised Balance 8,778 1,933 6,845 1,010 38 972 1,478 1,092 3 134 37 212 881 846 38 5 (8) 8,719 7,944 775 (2,619) (2,267) (119) (256) 23 10,012 2,684 1,439 14,135 (14) (14) — 26 26 — — 3 (3) — — — — — — — — (14) (14) — (128) 2 65 65 — 40 (105) 65 — — — — — — — 690 655 — 38 5 (8) (881) (846) (38) (5) 8 — — — 191 191 — — — — — — — 8,764 1,919 6,845 1,036 64 972 2,168 1,750 — 172 42 204 — — — — — 8,705 7,930 775 (2,426) (2,011) (247) (191) 23 10,052 2,579 1,504 6,731 594 6,137 1,131 37 1,094 1,772 1,324 — 170 44 234 — — — — — 6,608 5,747 861 (1,749) (1,320) (136) (352) 59 6,908 2,826 1,362 14,135 11,096 (78) (78) — 22 22 — — — — — — — — — — — — (78) (78) — 134 168 (128) 94 — 12 (106) 94 — 6,653 516 6,137 1,153 59 1,094 1,772 1,324 — 170 44 234 — — — — — 6,530 5,669 861 (1,615) (1,152) (264) (258) 59 6,920 2,720 1,456 11,096 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 82 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 83 162 | CENOVUS ENERGY 2023 ANNUAL REPORT ($ millions) Gross Sales Conventional Segment Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Transportation and Blending Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Three Months Ended March 31, 2022 Three Months Ended June 30, 2022 Previously Reported Segment Revisions Aggregation Revised Balance Previously Reported Segment Revisions Aggregation Revised Balance 1,112 34 1,078 1,044 804 2 124 42 72 694 660 27 8 (1) (1,761) (1,282) (221) (267) 9 7,482 2,975 1,287 11,744 25 25 — — 2 (2) — — — — — — — — (25) 39 (110) 46 — 41 (87) 46 — — — — 563 529 — 27 8 (1) (694) (660) (27) (8) 1 131 131 — — — — — — — 1,137 59 1,078 1,607 1,335 — 151 50 71 — — — — — (1,655) (1,112) (331) (221) 9 7,523 2,888 1,333 1,079 34 1,045 1,521 1,296 (2) 180 64 (17) 849 811 31 8 (1) (1,782) (1,111) (188) (395) (88) 9,396 3,048 1,481 11,744 13,925 34 34 — — (2) 2 — — — — — — — — (34) 69 (145) 42 — 67 (109) 42 — — — — 724 686 — 31 8 (1) (849) (811) (31) (8) 1 125 125 — — — — — — — 1,113 68 1,045 2,245 1,980 — 211 72 (18) — — — — — (1,691) (917) (333) (353) (88) 9,463 2,939 1,523 13,925 ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Transportation and Blending Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization U.S. Refining Segment Gross Sales Purchased Product Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Three Months Ended September 30, 2022 Three Months Ended December 31, 2022 Previously Reported Revisions Segment Aggregation Revised Balance Previously Reported Revisions Revised Balance 8,778 1,933 6,845 1,010 38 972 1,478 1,092 3 134 37 212 881 846 38 5 (8) 8,719 7,944 775 (2,619) (2,267) (119) (256) 23 10,012 2,684 1,439 14,135 (14) (14) — 26 26 — — 3 (3) — — — — — — — — (14) (14) — 2 65 (128) 65 — 40 (105) 65 — — — — — — — 690 655 — 38 5 (8) (881) (846) (38) (5) 8 — — — 191 191 — — — — — — — 8,764 1,919 6,845 1,036 64 972 2,168 1,750 — 172 42 204 — — — — — 8,705 7,930 775 (2,426) (2,011) (247) (191) 23 10,052 2,579 1,504 6,731 594 6,137 1,131 37 1,094 1,772 1,324 — 170 44 234 — — — — — 6,608 5,747 861 (1,749) (1,320) (136) (352) 59 6,908 2,826 1,362 14,135 11,096 (78) (78) — 22 22 — — — — — — — — — — — — (78) (78) — 134 168 (128) 94 — 12 (106) 94 — 6,653 516 6,137 1,153 59 1,094 1,772 1,324 — 170 44 234 — — — — — 6,530 5,669 861 (1,615) (1,152) (264) (258) 59 6,920 2,720 1,456 11,096 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 82 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 83 CENOVUS ENERGY 2023 ANNUAL REPORT | 163 ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Twelve Months Ended December 31, 2022 Previously Reported Revisions Revised Balance 34,775 4,810 29,965 4,332 143 4,189 30,310 26,112 4,198 (7,464) (5,533) (664) (1,270) 3 33,801 11,530 5,569 50,900 (92) (92) — 107 107 — (92) (92) — 77 341 (511) 247 — 157 (404) 247 — 34,683 4,718 29,965 4,439 250 4,189 30,218 26,020 4,198 (7,387) (5,192) (1,175) (1,023) 3 33,958 11,126 5,816 50,900 ($ millions) Gross Sales Conventional Segment Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Corporate and Eliminations Segment Twelve Months Ended December 31, 2021 Previously Reported Revisions Revised Balance Segment Aggregation 3,235 74 3,161 4,472 3,552 388 167 365 2,158 2,019 98 59 (18) (5,706) (4,259) (676) (783) 12 23,326 8,038 4,716 36,080 81 81 — — — — — — — — — — — (81) 163 (363) 119 — 163 (282) 119 — — — — 1,743 1,604 98 59 (18) (2,158) (2,019) (98) (59) 18 415 415 — — — — — — — 3,316 155 3,161 6,215 5,156 486 226 347 — — — — — (5,372) (3,681) (1,039) (664) 12 23,489 7,756 4,835 36,080 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 84 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 85 164 | CENOVUS ENERGY 2023 ANNUAL REPORT ($ millions) Oil Sands Segment Gross Sales Purchased Product Conventional Segment Gross Sales Transportation and Blending U.S. Refining Segment Gross Sales Purchased Product Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Corporate and Eliminations Segment Twelve Months Ended December 31, 2022 Previously Reported Revisions Revised Balance 34,775 4,810 29,965 4,332 143 4,189 30,310 26,112 4,198 (7,464) (5,533) (664) (1,270) 3 33,801 11,530 5,569 50,900 (92) (92) — 107 107 — (92) (92) — 77 341 (511) 247 — 157 (404) 247 — 34,683 4,718 29,965 4,439 250 4,189 30,218 26,020 4,198 (7,387) (5,192) (1,175) (1,023) 3 33,958 11,126 5,816 50,900 ($ millions) Conventional Segment Gross Sales Transportation and Blending Canadian Refining Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Retail Segment Gross Sales Purchased Product Operating Depreciation, Depletion and Amortization Corporate and Eliminations Segment Gross Sales Purchased Product Transportation and Blending Operating Consolidated Purchased Product Transportation and Blending Operating Twelve Months Ended December 31, 2021 Previously Reported Revisions Segment Aggregation Revised Balance 3,235 74 3,161 4,472 3,552 388 167 365 2,158 2,019 98 59 (18) (5,706) (4,259) (676) (783) 12 23,326 8,038 4,716 36,080 81 81 — — — — — — — — — — — (81) 163 (363) 119 — 163 (282) 119 — — — — 1,743 1,604 98 59 (18) (2,158) (2,019) (98) (59) 18 415 415 — — — — — — — 3,316 155 3,161 6,215 5,156 486 226 347 — — — — — (5,372) (3,681) (1,039) (664) 12 23,489 7,756 4,835 36,080 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 84 Cenovus Energy Inc. – 2023 Management's Discussion and Analysis 85 CENOVUS ENERGY 2023 ANNUAL REPORT | 165 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, May 1, 2024 at 11:00 a.m. MT via live webcast accessible online at https://web.lumiagm.com/424902861 Password: cenovus2024 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 sedarplus.ca 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 6, 2024) Alex Pourbaix, Executive Chair Jon McKenzie, President & Chief Executive Officer Susan Anderson, SVP, People Services Keith Chiasson, EVP & Chief Operating Officer Doreen Cole, EVP, Downstream Andrew Dahlin, EVP, Natural Gas & Technical Services Rho na DelFrari, Chief Sustainability Officer & EVP, Stakeholder Engagement Jeff Hart, EVP, Corporate & Operations Services Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary Norrie Ramsay, EVP, Upstream – Thermal, Major Projects & Offshore Kam Sandhar, EVP & Chief Financial Officer Drew Zieglgansberger, EVP & Chief Commercial Officer Cenovus’s Board of Directors (as at March 6, 2024) Alex J. Pourbaix, Executive Chair, Calgary, Alberta (5) Claude Mongeau, Lead Independent Director, Montréal, Québec (1,2) Keith M. Casey, San Antonio, Texas (3,4) Michael J. Crothers, Calgary, Alberta (2,3) James D. Girgulis, Luxembourg, Grand-Duchy of Luxembourg (2,6) Jane E. Kinney, Toronto, Ontario (1,4) Harold N. Kvisle, Calgary, Alberta (2,3) Eva L. Kwok, Vancouver, British Columbia (2) Melanie A. Little, Alpharetta, Georgia (3,4) Richard J. Marcogliese, Alamo, California (1,4) Jon M. McKenzie, 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 Committee (4) Member of the Safety, Sustainability and Reserves Committee (5) As officers and non-independent directors, Messrs. McKenzie and Pourbaix are not members of any of the committees of Cenovus’s Board (6) Non-independent director CENOVUS ENERGY 2023 ANNUAL REPORT | 167 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. 1.877.766.2066 (Toll-free in Canada & U.S.) 225 6 Ave SW PO Box 766 Calgary, AB T2P 0M5 Canada cenovus.com © Cenovus Energy Inc. 2024 

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