EX-99.3 5 su-20231231xex99d3.htm EX-99.3

Table of Contents

Exhibit 99-3

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Management’s Discussion and Analysis

March 21, 2024

-ever

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MD&A – Table of Contents
2 |  | Consolidated Financial and Operating Summary
5 | ​ | Suncor Overview
8 | ​ | Financial Information
14 | ​ | Segment Results and Analysis
29 | ​ | Income Tax
30 | ​ | Fourth Quarter 2023 Analysis
33 | ​ | Quarterly Financial Data
35 | ​ | Capital Investment Update
38 | ​ | Financial Condition and Liquidity
44 | ​ | Material Accounting Policies and Critical Accounting Estimates
46 | ​ | Risk Factors
56 | ​ | Other Items
58 | ​ | Advisories

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This Management’s Discussion and Analysis (MD&A) should be read in conjunction with Suncor’s December 31, 2023 audited Consolidated Financial Statements and the accompanying notes. Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor’s Annual Information Form dated March 21, 2024 (the 2023 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedarplus.ca, www.sec.gov and on our website at www.suncor.com. Information contained in or otherwise accessible through our website, even if referred to in this MD&A, does not constitute part of this MD&A and is not incorporated by reference into this MD&A.

References to “we”, “our”, “Suncor” or “the company” means Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements, unless otherwise specified or the context otherwise requires. For a list of abbreviations that may be used in this MD&A, refer to the Advisories – Common Abbreviations section of this MD&A.

Basis of Presentation

Unless otherwise noted, all financial information contained herein has been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, except for production volumes from the company’s Libya operations, which are presented on an economic basis.

References to Oil Sands operations exclude Suncor’s interests in Fort Hills and Syncrude.

Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

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ANNUAL REPORT 2023 SUNCOR ENERGY INC. 1

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1. Consolidated Financial and Operating Summary

Financial Summary

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions, except per share amounts) |  | 2023 |  | 2022 |  | 2021 |
Gross revenues |  | 52 206 |  | 62 907 |  | 41 133 | ​
Royalties | ​ | (3 114) | ​ | (4 571) | ​ | (2 001) | ​
Operating revenues, net of royalties | ​ | 49 092 | ​ | 58 336 | ​ | 39 132 | ​
Net earnings |  | 8 295 |  | 9 077 |  | 4 119 | ​
Per common share – basic (dollars) |  | 6.34 |  | 6.54 |  | 2.77 | ​
Per common share – diluted (dollars) | ​ | 6.33 | ​ | 6.53 | ​ | 2.77 | ​
Adjusted operating earnings(1) |  | 6 677 |  | 11 566 |  | 3 805 | ​
Per common share(1)(2) |  | 5.10 |  | 8.34 |  | 2.56 | ​
Adjusted funds from operations(1) |  | 13 325 |  | 18 101 |  | 10 257 | ​
Per common share(1)(2) |  | 10.19 |  | 13.05 |  | 6.89 | ​
Cash flow provided by operating activities |  | 12 344 |  | 15 680 |  | 11 764 | ​
Per common share(2) |  | 9.44 |  | 11.30 |  | 7.91 | ​
Dividends paid on common shares |  | 2 749 |  | 2 596 |  | 1 550 | ​
Per common share(2) |  | 2.11 |  | 1.88 |  | 1.05 | ​
Share repurchases |  | 2 233 | ​ | 5 135 | ​ | 2 304 | ​
Per common share(2) |  | 1.71 | ​ | 3.70 | ​ | 1.55 | ​
Weighted average number of common shares in millions – basic |  | 1 308 |  | 1 387 |  | 1 488 | ​
Weighted average number of common shares in millions – diluted |  | 1 310 |  | 1 390 |  | 1 489 | ​
Capital expenditures(3)(4) |  | 5 573 |  | 4 819 |  | 4 411 | ​
Asset sustainment and maintenance |  | 3 543 |  | 3 315 |  | 3 057 | ​
Economic investment |  | 2 030 |  | 1 504 |  | 1 354 | ​
Free funds flow(1) |  | 7 497 |  | 13 114 |  | 5 702 | ​
Returns to shareholders(5) | ​ | 4 982 | ​ | 7 731 | ​ | 3 854 | ​
Balance sheet (at December 31) |  | ​ |  | ​ |  | ​ | ​
Total assets |  | 88 539 |  | 84 618 |  | 83 739 | ​
Net debt(1) |  | 13 678 |  | 13 639 |  | 16 149 | ​
Total long-term liabilities(6) |  | 35 663 |  | 32 382 |  | 36 726 | ​

(1) | Non-GAAP financial measures or contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | Represented on a basic per share basis.

(3) | Excludes capitalized interest of $255 million in 2023, $168 million in 2022 and $144 million in 2021.

(4) | Excludes capital expenditures related to assets previously held for sale of $108 million in 2023 and $133 million in 2022.

(5) | Includes dividends paid on common shares and repurchases of common shares.

(6) | Includes long-term debt, long-term lease liabilities, other long-term liabilities, provisions and deferred income taxes.

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Operating Summary

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | 2023 |  | 2022 |  | 2021 |
Production volumes |  |  |  |  |  |  | ​
Oil Sands – Upgraded – net SCO and diesel (mbbls/d) |  | 487.0 |  | 480.0 |  | 468.6 | ​
Oil Sands – Non-upgraded bitumen (mbbls/d) | ​ | 202.6 | ​ | 185.2 | ​ | 175.6 | ​
Total Oil Sands production volumes (mbbls/d) | ​ | 689.6 | ​ | 665.2 | ​ | 644.2 | ​
Exploration and Production (mboe/d) |  | 56.1 |  | 78.0 |  | 87.5 | ​
Total upstream production (mboe/d) |  | 745.7 |  | 743.2 |  | 731.7 | ​
Average price realizations(1)(2) ($/boe) |  |  |  |  |  |  | ​
Upgraded – net SCO and diesel |  | 99.40 | ​ | 118.88 | ​ | 77.73 | ​
Non-upgraded bitumen | ​ | 67.97 | ​ | 84.63 | ​ | 53.80 | ​
Average crude |  | 90.27 | ​ | 109.57 | ​ | 70.96 | ​
Exploration and Production Canada | ​ | 107.62 | ​ | 128.07 | ​ | 84.70 | ​
Exploration and Production International(3) | ​ | 109.00 | ​ | 126.61 | ​ | 82.16 | ​
Refinery crude oil processed (mbbls/d) |  | 420.7 |  | 433.2 |  | 415.5 | ​
Refinery utilization(4) (%) |  |  |  |  |  |  | ​
Eastern North America |  | 96 |  | 93 |  | 91 | ​
Western North America |  | 85 |  | 93 |  | 87 | ​
Total |  | 90 |  | 93 |  | 89 | ​
Refining and marketing gross margin - FIFO(1) ($/bbl) |  | 45.00 |  | 55.85 |  | 36.85 | ​
Refining and marketing gross margin - LIFO(1) ($/bbl) |  | 47.00 |  | 54.45 |  | 30.90 | ​

(1) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | Net of transportation costs, but before royalties.

(3) | Exploration and Production (E&P) International price realizations exclude Libya for all periods presented.

(4) | Refinery utilization is the amount of crude oil and natural gas liquids processed by crude distillation units, expressed as a percentage of the nameplate capacity of these units.

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Segment Summary

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Earnings (loss) before income taxes(1) |  |  |  |  |  |  | ​
Oil Sands |  | 6 811 |  | 5 633 |  | 2 825 | ​
Exploration and Production |  | 1 691 |  | 3 221 |  | 1 791 | ​
Refining and Marketing |  | 3 383 |  | 5 694 |  | 2 867 | ​
Corporate and Eliminations |  | (1 296) |  | (2 232) |  | (1 913) | ​
Income tax expense | ​ | (2 294) | ​ | (3 239) | ​ | (1 451) | ​
Net earnings |  | 8 295 |  | 9 077 |  | 4 119 | ​
Adjusted operating earnings (loss)(1)(2) |  |  |  |  |  | ​ | ​
Oil Sands |  | 5 967 |  | 9 042 |  | 2 829 | ​
Exploration and Production |  | 1 084 |  | 2 494 |  | 1 343 | ​
Refining and Marketing |  | 3 367 |  | 5 687 |  | 2 857 | ​
Corporate and Eliminations |  | (1 349) |  | (1 503) |  | (1 778) | ​
Income tax expense included in adjusted operating earnings | ​ | (2 392) | ​ | (4 154) | ​ | (1 446) | ​
Total |  | 6 677 |  | 11 566 |  | 3 805 | ​
Adjusted funds from (used in) operations(1)(2) |  |  |  |  |  | ​ | ​
Oil Sands |  | 10 725 |  | 13 831 |  | 7 575 | ​
Exploration and Production |  | 1 612 |  | 3 178 |  | 1 951 | ​
Refining and Marketing |  | 4 268 |  | 6 561 |  | 3 831 | ​
Corporate and Eliminations |  | (1 546) |  | (1 240) |  | (1 705) | ​
Current income tax expense | ​ | (1 734) | ​ | (4 229) | ​ | (1 395) | ​
Total |  | 13 325 |  | 18 101 |  | 10 257 | ​
Change in non-cash working capital | ​ | (981) | ​ | (2 421) | ​ | 1 507 | ​
Cash flow provided by operating activities |  | 12 344 |  | 15 680 |  | 11 764 | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(2) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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2. Suncor Overview

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. Suncor’s operations include oil sands development, production and upgrading; offshore oil production; petroleum refining in Canada and the U.S.; and the company’s Petro-Canada™ retail and wholesale distribution networks (including Canada’s Electric Highway™, a coast-to-coast network of fast-charging electric vehicle stations). Suncor is developing petroleum resources while advancing the transition to a low-emissions future through investments in power and renewable fuels. Suncor also conducts energy trading activities focused primarily on the marketing and trading of crude oil, natural gas, byproducts, refined products and power. Suncor’s common shares (symbol: SU) are listed on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE).

For a description of Suncor’s business segments, refer to the Segment Results and Analysis section of this MD&A.

Suncor’s Strategy

Suncor aims to be Canada’s leading energy provider, delivering competitive and sustainable returns to shareholders. Suncor is well positioned to execute on its strategy through the company’s competitive advantages that include its unparalleled, integrated upstream and downstream asset base and business model, underpinned by its large-scale, long-life oil sands resources.

Key components of Suncor’s strategy include the following:

● | Deliver industry-leading performance by focusing on the fundamentals of safety, operational integrity, reliability and profitability: Suncor is focused on driving industry-leading safety, environmental and reliability performance through operational excellence and aligning its asset base with its competencies and competitive advantages to maximize value. The company aims to provide clear priorities and focus to ensure Suncor is a profitable, high-performing company today and in the future.

● | Achieve financial resiliency by structurally lowering costs: Suncor is focused on driving down costs, increasing product margins and exercising capital discipline across the company to provide financial strength and flexibility.

● | Leverage integration to maximize value from upstream production to downstream customers: From the ground to the gas station, Suncor maximizes profit along each step of the value chain through its unparalleled asset integration. This includes leveraging the interconnectivity of its Oil Sands assets to prioritize higher-value synthetic crude oil (SCO) production, and capturing additional margin through its extensive midstream and structurally advantaged downstream assets.

● | Decarbonize base business while maintaining competitiveness and capturing new opportunities to achieve net-zero greenhouse gas (GHG) emissions from operations by 2050: The company is taking tangible actions to decarbonize its existing hydrocarbon business, while investing in other areas aligned with its core competencies, including investments in lower-carbon power and renewable fuels.

The execution of Suncor’s strategy and key priorities is expected to grow free funds flow per share and enable the company to deliver industry-leading shareholder returns through a combination of share price appreciation, dividend growth and share repurchases.

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2023 Highlights

Best overall employee and contractor safety performance in the company’s history.

| ● | In 2023, Suncor delivered its best overall employee and contractor safety performance, with zero life-threatening or life-altering injuries. Year-over-year, lost-time injuries were down nearly 50%.

| ● | Aligned with its objective to achieve industry-leading safety performance, Suncor successfully implemented collision awareness technology and a fatigue management solution (technologies aimed at preventing mobile equipment contact) on over 1,000 pieces of mobile equipment combined in its mining fleet. Suncor is the first oil sands operator to execute a full-scale implementation of these technologies.

Suncor generated adjusted funds from operations(1) of $13.3 billion, the second highest in the company’s history, reflecting the strength of its integrated business model.

| ● | In 2023, Suncor generated $13.325 billion in adjusted funds from operations, or $10.19 per common share, compared to $18.101 billion, or $13.05 per common share, in the prior year. Cash flow provided by operating activities, which includes changes in non-cash working capital, was $12.344 billion, or $9.44 per common share, in 2023, compared to $15.680 billion, or $11.30 per common share, in the prior year. The decreased cash flows were primarily a result of a weaker business environment in the current year.

| ● | Suncor generated its second highest annual adjusted operating earnings(1) of $6.677 billion in 2023, or $5.10 per common share, compared to $11.566 billion, or $8.34 per common share, in the prior year. Net earnings of $8.295 billion in 2023, or $6.34 per common share, were also the second highest in the company’s history, compared to $9.077 billion, or $6.54 per common share, in the prior year.

The company returned $5.0 billion to its shareholders in 2023, which included a quarterly dividend increase of approximately 5% in the fourth quarter.

| ● | Suncor returned $5.0 billion of value to its shareholders in 2023, which included $2.8 billion of dividends paid and $2.2 billion in share repurchases. In 2023, the company repurchased 52.0 million common shares at an average price of $42.96 per common share, or 3.9% of its issued and outstanding common shares as at December 31, 2022.

| ● | Suncor increased its dividend per share to $0.545 per common share in the fourth quarter of 2023, an increase of approximately 5% over the prior quarter dividend.

The company focused on core assets to drive value.

| ● | During the first quarter of 2023, the company completed the sale of its wind and solar assets for gross proceeds of $730 million, before closing adjustments and other closing costs, resulting in a gain on sale of $302 million.

| ● | During the second quarter of 2023, Suncor completed the sale of its U.K. E&P portfolio for gross proceeds of $1.1 billion, before closing adjustments and other closing costs, resulting in a gain on sale of $607 million.

| ● | In 2023, the company completed two separate transactions to acquire the remaining 45.89% working interest in Fort Hills for $2.2 billion, making Suncor the sole owner of Fort Hills. These transactions advanced the company’s long-term bitumen supply strategy, and collectively added 89,000 bbls/d of high-quality bitumen production capacity to the company’s portfolio.

Oil Sands delivered record annual production, including the highest-ever production at Syncrude and Firebag.

| ● | Suncor delivered record Oil Sands production of 689,600 bbls/d in 2023, compared to 665,200 bbls/d in 2022, reflecting the company’s increased working interest in Fort Hills. Oil Sands production also included record production from Syncrude and Firebag.

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(1) | Non-GAAP financial measure. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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Oil Sands delivered its best-ever combined upgrader utilization of 92%, 3% better than previous high.

| ● | The company leveraged its regional asset connectivity to maximize upgrader utilization, resulting in combined upgrader utilization of 92% in 2023, compared to 89% in the prior year.

Safe restart of production at Terra Nova.

| ● | The Terra Nova Floating, Production, Storage and Offloading vessel safely restarted production in the fourth quarter of 2023, with production expected to continue ramping up in the beginning of 2024. The restart of production at this key offshore asset is expected to provide long-term value to shareholders as well as many benefits to the Newfoundland and Labrador and Canadian economies.

Refining and Marketing (R&M) continued to deliver strong results, as the company focused on strengthening its integrated R&M business and driving increased long-term value for shareholders.

| ● | The company delivered refinery crude throughput of 420,700 bbls/d and refinery utilization of 90% in 2023, which included 99% utilization in the second half of the year, compared to 433,200 bbls/d and 93% in the prior year.

| ● | The company entered into a co-ownership agreement with North Atlantic, a leading gas station and convenience store operator in Atlantic Canada, to combine retail fuel networks. The combined network has 110 sites and will include the rebranding of a number of North Atlantic’s sites to the Petro-Canada™ brand.

| ● | Petro-Canada™ and Canadian Tire Corporation announced a new partnership that will result in the rebranding of over 200 of Canadian Tire Corporation’s retail fuel network sites to the Petro-Canada™ brand, increasing the presence of Petro-Canada’s brand across the country, as well as the partnering of the two brands’ loyalty programs, benefiting millions of loyalty members. Suncor will also become the primary fuel provider for Canadian Tire Corporation’s retail fuel network.

The company continued to decarbonize its business while maintaining its competitiveness.

| ● | To help reach Suncor’s strategic objective to achieve net-zero GHG emissions from operations by 2050, the company has continued to work collaboratively with industry peers through the Oil Sands Pathways to Net Zero alliance (Pathways Alliance) and with federal and provincial governments and other stakeholders in the implementation of a global-scale carbon capture and storage facility for the Canadian Oil Sands. In 2023, the Pathways Alliance was awarded exploratory rights from the Government of Alberta for its proposed carbon capture and storage hub, which is expected to enable the safe and permanent storage of CO2 captured from over 20 oil sands facilities in northern Alberta.

| ● | The company continued to advance other projects aimed at decarbonizing its existing hydrocarbon business, including advancing construction on the new cogeneration facility to replace the coke-fired boilers at Oil Sands Base.

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3. Financial Information

Net Earnings

Suncor’s net earnings in 2023 were $8.295 billion, compared to $9.077 billion in 2022. Net earnings were impacted by the same factors that influenced adjusted operating earnings discussed below. Other items affecting net earnings in 2023 and 2022 included:

● | An unrealized foreign exchange gain on the revaluation of U.S. dollar denominated debt of $184 million recorded in financing expenses in the Corporate and Eliminations segment in 2023, compared to a loss of $729 million in 2022.

● | An unrealized loss on risk management activities of $12 million recorded in other income in 2023, compared to $5 million in 2022.

● | In 2023, Suncor recorded a gain of $607 million on the sale of its U.K. E&P portfolio and a gain of $302 million on the sale of its wind and solar assets in the Corporate and Eliminations segment. Also in 2023, the company recorded a non-cash gain of $1.125 billion in the Oil Sands segment as a result of the acquisition of the remaining working interest in Fort Hills, via the purchase of TotalEnergies EP Canada Ltd. (TotalEnergies Canada). In 2022, the company recorded a $65 million foreign exchange loss related to the sale of the company’s share of its assets in Norway in the E&P segment.

● | In 2023, the company recorded non-cash derecognition charges of $253 million on its Meadow Creek development properties in the Oil Sands segment and a non-cash impairment of $158 million against an equity investment in the Corporate and Eliminations segment. In 2022, the company recorded a non-cash impairment of $3.397 billion against its share of the Fort Hills assets in the Oil Sands segment. Also in 2022, the company recorded a non-cash impairment reversal of $715 million on its share of the White Rose assets in the E&P segment and a non-cash impairment of $70 million against its share of its assets in Norway in the E&P segment.

● | In 2023, the company recorded a restructuring charge of $275 million in operating, selling and general (OS&G) expenses in the Corporate and Eliminations segment related to the company’s workforce reductions.

● | In 2022, the company recognized $147 million of property damage insurance proceeds in other income related to the company’s assets in Libya in the E&P segment.

● | An income tax recovery related to the items noted above of $98 million in 2023, compared to $915 million in 2022.

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Adjusted Operating Earnings

Consolidated Adjusted Operating Earnings Reconciliation(1)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Net earnings |  | 8 295 |  | 9 077 |  | 4 119 | ​
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt |  | (184) |  | 729 |  | (113) | ​
Unrealized loss (gain) on risk management activities | ​ | 12 | ​ | 5 | ​ | (6) | ​
(Gain) loss on significant disposals and acquisitions(2) | ​ | (2 034) | ​ | 65 | ​ | (227) | ​
Asset impairments (reversals) and derecognition(3) | ​ | 411 | ​ | 2 752 | ​ | (221) | ​
Restructuring charge(4) | ​ | 275 | ​ | — | ​ | 168 | ​
Recognition of insurance proceeds | ​ | — | ​ | (147) | ​ | — | ​
Loss on early repayment of long-term debt(5) | ​ | — | ​ | — | ​ | 80 | ​
Income tax (recovery) expense on adjusted operating earnings adjustments |  | (98) |  | (915) |  | 5 | ​
Adjusted operating earnings(1) |  | 6 677 |  | 11 566 |  | 3 805 | ​

(1) | Non-GAAP financial measure. All reconciling items are presented on a before-tax basis and adjusted for income taxes in the income tax (recovery) expense on adjusted operating earnings adjustments line. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | In 2021, the company recorded a gain of $227 million on the sale of the company’s interest in the Golden Eagle Area Development in the E&P segment.

(3) | In 2021, the company recorded a non-cash impairment reversal of $221 million against its share of the Terra Nova assets in the E&P segment as a result of the decision to proceed with the Terra Nova Asset Life Extension (ALE) Project and the benefit of royalty and financial support from the Government of Newfoundland and Labrador.

(4) | In 2021, the company recorded a restructuring charge of $168 million related to workforce reductions in OS&G expenses in the Corporate and Eliminations segment.

(5) | In 2021, in connection with the early repayment of long-term debt, the company recorded a loss of $80 million in financing expenses in the Corporate and Eliminations segment.

(1) | For an explanation of this bridge analysis, see the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

Suncor’s consolidated adjusted operating earnings were $6.677 billion in 2023, compared to $11.566 billion in the prior year. The decrease in adjusted operating earnings in 2023 was primarily due to decreased crude oil and refined product price realizations compared to the prior year, reflecting a weaker business environment in the current year, and decreased sales volumes in E&P in 2023 due to international asset divestments, partially offset by lower incomes taxes and royalties, and increased sales volumes in Oil Sands. Adjusted operating earnings were also unfavourably impacted by a weakening in benchmark pricing in 2023 compared to a strengthening in 2022, resulting in a first-in, first-out (FIFO) inventory valuation loss, partially offset by a realization of intersegment profit in 2023, compared to a FIFO inventory valuation gain, partially offset by a deferral of intersegment profit in 2022.

Adjusted Funds from Operations and Cash Flow Provided by Operating Activities

Adjusted funds from operations were $13.325 billion in 2023, compared to $18.101 billion in 2022, and were primarily influenced by the same factors impacting adjusted operating earnings. Adjusted funds from operations in 2023 were also impacted by a one-time tax benefit of approximately $880 million relating to the acquisition of TotalEnergies Canada and a restructuring charge of $275 million related to the company’s workforce reductions. Adjusted funds from operations in 2022 were also impacted by the recognition of $147 million of property damage insurance proceeds related to the company’s assets in Libya.

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Cash flow provided by operating activities, which includes changes in non-cash working capital, was $12.344 billion in 2023, compared to $15.680 billion in 2022. In addition to the factors discussed above, cash flow provided by operating activities was impacted by a significant decrease in the use of working capital in the current year compared to the prior year. The use of cash in 2023 was primarily due to significantly lower net income taxes payable, and a decrease in accounts payable and accrued liabilities, partially offset by a decrease in accounts receivable balances related to the decrease in commodity prices in 2023.

Results for 2022 Compared with 2021

Suncor’s consolidated adjusted operating earnings increased to $11.566 billion in 2022, compared to $3.805 billion in the prior year. The increase in adjusted operating earnings in 2022 was primarily due to significantly higher crude oil and refined product price realizations compared to the prior year, reflecting the improved business environment, and higher overall crude production and refinery throughput in 2022. These factors were partially offset by an increase in income taxes associated with increased earnings, increased royalties associated with higher crude price realizations, and increased operating and transportation expenses. Adjusted operating earnings were also impacted by a smaller strengthening in benchmark pricing in 2022 compared to the prior year, resulting in a net unfavourable inventory valuation change of $742 million on crude feedstock costs.

Adjusted funds from operations for 2022 were $18.101 billion, compared to $10.257 billion in 2021, and were impacted by the same factors as adjusted operating earnings.

Cash flow provided by operating activities, which includes changes in non-cash working capital, was $15.680 billion in 2022, compared to $11.764 billion in 2021. In addition to the factors discussed above, cash flow provided by operating activities was further impacted by a use of cash in working capital in 2022, compared to a source of cash in the prior year. The use of cash in 2022 was primarily due to an increase in accounts receivable and inventory balances related to the increase in commodity prices and crude oil price realizations in 2022, partially offset by an increase in accounts payable and accrued liabilities.

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Business Environment

Commodity prices, refining crack spreads and foreign exchange rates are important factors that affect the results of Suncor’s operations.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Average for the year ended December 31 |  | 2023 |  | 2022 |  | 2021 |
WTI crude oil at Cushing (US$/bbl) |  | 77.60 | ​ | 94.25 | ​ | 67.95 |
Dated Brent Crude (US$/bbl) |  | 82.60 | ​ | 101.20 | ​ | 70.75 |
Dated Brent/Maya crude oil FOB price differential (US$/bbl) |  | 25.35 | ​ | 15.50 | ​ | 6.85 |
MSW at Edmonton (Cdn$/bbl) |  | 100.45 | ​ | 120.10 | ​ | 80.30 |
WCS at Hardisty (US$/bbl) |  | 59.00 | ​ | 75.95 | ​ | 54.90 |
WTI-WCS light/heavy differential (US$/bbl) |  | (18.60) | ​ | (18.30) | ​ | (13.05) |
SYN-WTI premium (differential) (US$/bbl) | ​ | 2.00 | ​ | 4.45 | ​ | (1.65) | ​
Condensate at Edmonton (US$/bbl) |  | 76.60 | ​ | 93.75 | ​ | 68.25 |
Natural gas (Alberta spot) at AECO (Cdn$/GJ) |  | 2.50 | ​ | 5.10 | ​ | 3.45 |
Alberta Power Pool Price (Cdn$/MWh) |  | 133.65 | ​ | 162.45 | ​ | 101.95 |
New York Harbor 2-1-1 crack(1) (US$/bbl) |  | 34.40 | ​ | 47.00 | ​ | 19.40 |
Chicago 2-1-1 crack(1) (US$/bbl) |  | 26.15 | ​ | 38.10 | ​ | 17.75 |
Portland 2-1-1 crack(1) (US$/bbl) |  | 40.00 | ​ | 51.35 | ​ | 23.15 |
Gulf Coast 2-1-1 crack(1) (US$/bbl) |  | 32.20 | ​ | 40.40 | ​ | 18.00 |
U.S. Renewable Volume Obligation (US$/bbl) | ​ | 7.00 | ​ | 7.75 | ​ | 6.80 | ​
Suncor custom 5-2-2-1 index(2) (US$/bbl) | ​ | 36.60 | ​ | 45.30 | ​ | 26.55 | ​
Exchange rate (average) (US$/Cdn$) |  | 0.74 | ​ | 0.77 | ​ | 0.80 |
Exchange rate (end of period) (US$/Cdn$) |  | 0.76 | ​ | 0.74 | ​ | 0.79 |

(1) | 2-1-1 crack spreads are indicators of the refining margin generated by converting two barrels of WTI into one barrel of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

(2) | Suncor has developed an indicative 5-2-2-1 index based on publicly available pricing data to more accurately reflect the company’s realized refining and marketing gross margin.

Commodity market volatility increased during 2023 due to ongoing economic concerns regarding rising interest rates, inflationary pressures and future economic growth.

Suncor’s sweet SCO price realizations are influenced primarily by the price of WTI at Cushing and by the supply and demand for sweet SCO from Western Canada. Sweet SCO price realizations in 2023 reflected a decrease in WTI at Cushing, which averaged US$77.60/bbl, compared to US$94.25/bbl in the prior year, and also reflected declining SYN-WTI premiums.

Suncor also produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty. The price of sour SCO can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton decreased to $100.45/bbl in 2023 compared to $120.10/bbl in 2022, and prices for WCS at Hardisty decreased to US$59.00/bbl in 2023, from US$75.95/bbl in 2022.

Bitumen production that Suncor does not upgrade is blended with diluent or SCO to facilitate delivery through pipeline systems. Net bitumen price realizations are therefore influenced by both prices for Canadian heavy crude oil (WCS at Hardisty is a common reference), prices for diluent (condensate at Edmonton) and SCO.

The company leverages its marketing and logistics business to optimize midstream capacity to the U.S. Gulf Coast, which is reflected in bitumen and sour SCO price realizations. Bitumen prices were unfavourably impacted by the widening of heavy crude oil differentials in 2023 compared to 2022.

Suncor’s price realizations for production from E&P Canada and E&P International assets are influenced primarily by the price for Brent crude, which decreased to US$82.60/bbl in 2023, compared to US$101.20/bbl in 2022.

Suncor’s refining and marketing gross margins are primarily influenced by 2-1-1 benchmark crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates. Market crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel, and do not necessarily reflect the margins at a specific refinery. Suncor’s realized refining and marketing gross margins are influenced by crude mix, actual crude oil feedstock costs, refinery configuration, product mix and realized market prices unique to Suncor’s refining and marketing business. In addition, U.S. regulatory renewable blending obligations influence the benchmark cracks, which may increase their volatility. The cost of regulatory compliance is not deducted in calculating the benchmark cracks.

Suncor has developed an indicative 5-2-2-1 index based on publicly available pricing data to reflect the company’s realized refining and marketing gross margin more accurately. This custom index is a single value representing a notional five barrels

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of crude oil of varying grades refined to produce two barrels each of gasoline and distillate and one barrel of secondary product to approximate Suncor’s unique set of refinery configurations, overall crude slate and product mix, location, quality and grade differentials, and the benefits of its marketing margins. The custom index is calculated by taking the product value of refined products less the crude value of refinery feedstock excluding the impact of FIFO inventory accounting methodology. The product value incorporates the New York Harbor 2-1-1 crack, Chicago 2-1-1 crack, WTI benchmarks and a seasonal factor. The seasonal factor applies an incremental US$6.50/bbl in the first and fourth quarters and US$5.00/bbl in the second and third quarters and reflects the location, quality and grade differentials for refined products sold in the company’s core markets during the winter and summer months, respectively. The crude value incorporates the SYN, WCS and WTI benchmarks.

Crack spreads are based on current crude feedstock prices, whereas actual earnings are accounted for on a FIFO basis in accordance with IFRS where a delay exists between the time that feedstock is purchased to when it is processed and when products are sold to a third party. A FIFO loss normally reflects a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. The company’s realized refining and marketing gross margins are also presented on a last-in, first-out (LIFO) basis, which is consistent with how industry benchmarks and the Suncor 5-2-2-1 index are calculated and with how management evaluates performance.

In 2023, 2-1-1 benchmark crack spreads decreased compared to 2022, primarily due to inventory growth as a result of increased global refining runs and softening demand. The Suncor 5-2-2-1 index was US$36.60/bbl in 2023 compared to US$45.30/bbl in 2022, reflecting the decrease in benchmark crack spreads.

The cost of natural gas used in Suncor’s Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $2.50/GJ in 2023, from $5.10/GJ in the prior year.

Excess electricity produced at Suncor’s Oil Sands assets is sold to the Alberta Electric System Operator, with the proceeds netted against the applicable cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $133.65/MWh in 2023 from $162.45/MWh in the prior year.

The majority of Suncor’s revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices, while the majority of Suncor’s expenditures are realized in Canadian dollars. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of commodities. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease revenues received from the sale of commodities. In 2023, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to US$0.74 per one Canadian dollar from US$0.77 per one Canadian dollar in 2022. The decrease in the Canadian dollar relative to the U.S. dollar had a positive impact on price realizations for the company in 2023 when compared to 2022.

Suncor also has assets and liabilities, including approximately 55% of the company’s debt, that are denominated in U.S. dollars and translated to Suncor’s reporting currency (Canadian dollars) at each balance sheet date. A decrease in the value of the Canadian dollar, relative to the U.S. dollar, from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations, while an increase in the value of the Canadian dollar, relative to the U.S. dollar, decreases the amount of Canadian dollars required to settle U.S. dollar denominated obligations. As at December 31, 2023, the Canadian dollar strengthened in relation to the U.S. dollar as the exchange rate at the end of the period increased to US$0.76 per one Canadian dollar from US$0.74 per one Canadian dollar at the end of the prior year. This exchange rate increase had a positive impact on the company’s debt balances as at December 31, 2023, compared to December 31, 2022.

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Economic Sensitivities(1)(2)

The following table illustrates the estimated effects that changes in certain factors would have had on 2023 net earnings and adjusted funds from operations(3) if the listed changes had occurred.

​ | ​ | ​ | ​ | ​ | ​
​ |  | ​ |  | ​ |
​ | ​ | Impact on 2023 | ​ | Impact on 2023 |
(Estimated change, in $ millions) | ​ | Net Earnings | ​ | Adjusted Funds from Operations(3) |
Crude oil +US$1.00/bbl |  | 180 | ​ | 180 | ​
Natural gas +Cdn$1.00/GJ(4) |  | (160) | ​ | (160) | ​
2-1-1 crack spreads +US$1.00/bbl |  | 140 | ​ | 140 | ​
Foreign exchange +$0.01 US$/Cdn$ related to operating activities(5) |  | (200) | ​ | (200) | ​
Foreign exchange on U.S. dollar denominated debt +$0.01 US$/Cdn$ |  | 120 | ​ | — | ​

(1) | Each line item in this table shows the effects of a change in that variable only, with other variables being held consistent.

(2) | Changes for a variable imply that all such similar variables are impacted, such that Suncor’s average price realizations increase uniformly. For instance, “Crude oil +US$1.00/bbl” implies that price realizations influenced by WTI, Brent, SCO, WCS, par crude at Edmonton and condensate all increase by US$1.00/bbl.

(3) | Non-GAAP financial measure. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(4) | The company’s exposure to natural gas costs is partially mitigated by revenue from power sales, which is not included in the above sensitivity.

(5) | Excludes the foreign exchange impact on U.S. dollar denominated debt.

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4. Segment Results and Analysis

Suncor has classified its operations into the following segments:

Oil Sands

Suncor’s Oil Sands segment produces bitumen from mining and in situ operations in northern Alberta. Bitumen is either upgraded into SCO or blended with diluent for either refinery feedstock or direct sale to market. The segment includes the marketing, supply, transportation and risk management of crude oil, power and byproducts.

The Oil Sands segment includes:

● | Oil Sands operations refer to Suncor’s owned and operated mining, extraction, upgrading, in situ and related logistics, blending and storage assets. Oil Sands operations consist of: Oil Sands Base operations, which include the Millennium and North Steepbank mines, integrated upgrading facilities Upgrader 1 and Upgrader 2, and the associated infrastructure for these assets, as well as interests in future mining development opportunities; and In Situ operations, which include oil sands bitumen production from Firebag and MacKay River and supporting infrastructure, as well as development opportunities that may support future in situ production.

● | Fort Hills includes Suncor’s wholly owned and operated Fort Hills mining and extraction operation, and the East Tank Farm Development, which Suncor operates and holds a 51% interest. In 2023, Suncor completed two separate acquisitions of additional working interests in the Fort Hills mining and extraction operation, increasing its ownership from 54.11% to 100%.

● | Syncrude refers to Suncor’s 58.74% operated working interest in Syncrude’s two producing oil sands mines, Mildred Lake and Aurora North, and integrated upgrading facilities. Syncrude also includes development opportunities that may support future production.

Exploration and Production

Suncor’s E&P segment consists of offshore operations off the East Coast of Canada, and onshore assets in Libya and Syria. This segment also includes the marketing and risk management of crude oil and natural gas.

● | E&P Canada operations include Suncor’s 48% working interest in Terra Nova, which Suncor operates. Suncor also holds non-operated interests in the White Rose assets (40% in the base project and 38.6% in the extensions), Hibernia (20% in the base project and 19.485% in the Hibernia Southern Extension Unit) and Hebron (21.034%). In addition, the company holds interests in several exploration licences and significant discovery licences offshore Newfoundland and Labrador.

● | E&P International operations include Suncor’s working interests in the exploration and development of oilfields in the Sirte Basin in Libya, pursuant to exploration and production sharing agreements. Suncor also owns, pursuant to a production sharing contract, an interest in the Ebla gas development in Syria, which has been suspended indefinitely since 2011 due to political unrest in the country. E&P International previously included Suncor’s U.K. portfolio and Norway assets which were divested in 2023 and 2022, respectively.

Refining and Marketing

Suncor’s R&M segment consists of two primary operations, discussed below. This segment also includes the trading of crude oil, refined products, natural gas and power.

● | Refining and Supply operations refine crude oil and intermediate feedstock into a wide range of petroleum and petrochemical products. Refining and Supply consists of: Eastern North America operations, which include a 137 mbbls/d refinery located in Montreal, Quebec, and an 85 mbbls/d refinery located in Sarnia, Ontario; and Western North America operations, which include a 146 mbbls/d refinery located in Edmonton, Alberta, and a 98 mbbls/d refinery in Commerce City, Colorado. Other Refining and Supply assets include interests in a petrochemical plant and a sulphur recovery facility in Montreal, Quebec, product pipelines and terminals throughout Canada and the U.S., and the St. Clair ethanol plant in Ontario.

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● | Marketing operations sell refined petroleum products to retail customers primarily through a combination of company-owned Petro-Canada™ locations, branded dealers in Canada and company-owned locations in the U.S. marketed under other international brands. This includes Canada’s Electric Highway™, a coast-to-coast network of fast-charging electric vehicle stations. The company’s marketing operations also sells refined petroleum products through a nationwide commercial road transportation network in Canada, and to other commercial and industrial customers, including other retail sellers, in Canada and the U.S.

Corporate and Eliminations

The Corporate and Eliminations segment includes activities not directly attributable to any other operating segment. This segment previously included Suncor’s renewable energy assets, which were sold in the first quarter of 2023.

● | Corporate activities include Suncor’s debt and borrowing costs, expenses not allocated to the company’s businesses, and investments in certain clean technologies.

● | Intersegment revenues and expenses are removed from consolidated results in Eliminations. Intersegment activity includes the sale of product between the company’s segments, primarily relating to crude refining feedstock sold from Oil Sands to R&M.

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Oil Sands

Strategy and Investment Updates

| ● | At Oil Sands Base, the company plans to further deploy autonomous haul trucks at its Millennium mine and expects to have 91 autonomous haul trucks in its Oil Sands Base operations by the end of 2024. Autonomous haul trucks offer a number of advantages over existing staffed trucks, including enhanced safety, environmental and operational performance.

| ● | The company plans to continue construction of a cogeneration facility to replace the coke-fired boilers at Oil Sands Base, which is expected to be in service in late 2024 and provide the steam generation required for extraction and upgrading activities at a lower cost and with significantly lower carbon emissions. The cogeneration facility is also expected to generate lower-carbon-intensive electricity that will be transmitted to Alberta’s power grid.

| ● | In 2024, the company plans to continue to progress the Upgrader 1 coke drum replacement project, which is expected to be in service in late 2025. The Upgrader 1 coke drum replacement project is expected to extend the life of the Upgrader 1 facility by approximately 30 years and reduce the facility’s future operating and capital cost requirements.

| ● | In 2024, the company plans to continue to advance the Mildred Lake West Extension (MLX-W) project at Syncrude, which is expected to sustain Syncrude’s current production levels by extending the life of its North Mine using existing extraction and upgrading facilities. MLX-W is expected to commence production in late 2025.

| ● | In 2024, the company will be in the second year of its three-year mine improvement plan at Fort Hills, while also accelerating a sequence of mine development relative to its historical plans, requiring the opening of two sections in the North Pit rather than one as originally planned. Upon completion of the three-year mine improvement plan, opportunities for further value optimization will be implemented for the remaining life of the mine.

| ● | The company will continue to leverage its integrated regional asset base to generate incremental value by maximizing upgrader utilizations. This includes internal asset transfers on the interconnecting pipelines, as well as directing higher quantities of Fort Hills bitumen to upgrading at Oil Sands Base.

| ● | The company will continue efforts to decarbonize its Oil Sands business, including through its participation in the Pathways Alliance. The Pathways Alliance expects to submit required regulatory applications for a proposed carbon capture and storage hub in 2024.

Financial Highlights

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Operating revenues |  | 26 035 |  | 30 431 |  | 19 920 | ​
Less: Royalties |  | (2 623) |  | (3 963) |  | (1 523) | ​
Operating revenues, net of royalties |  | 23 412 |  | 26 468 |  | 18 397 | ​
Earnings before income taxes(1) |  | 6 811 |  | 5 633 |  | 2 825 | ​
Adjusted for: |  |  |  |  |  | ​ | ​
Unrealized loss on risk management activities | ​ | 28 | ​ | 12 | ​ | 4 | ​
Gain on significant acquisition | ​ | (1 125) | ​ | — | ​ | — | ​
Derecognition and asset impairment | ​ | 253 | ​ | 3 397 | ​ | — | ​
Adjusted operating earnings(1)(2) |  | 5 967 |  | 9 042 |  | 2 829 | ​
Adjusted funds from operations(1)(2) |  | 10 725 |  | 13 831 |  | 7 575 | ​
Free funds flow(2) | ​ | 6 629 | ​ | 10 291 | ​ | 4 407 | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(2) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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(1) | For an explanation of this bridge analysis, see the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

The Oil Sands segment had adjusted operating earnings of $5.967 billion in 2023, compared to $9.042 billion in 2022. The decrease was primarily due to lower realized crude oil prices compared to the prior year, partially offset by decreased royalties due to lower crude benchmark prices and increased sales volumes.

Oil Sands earnings before income taxes were $6.811 billion in 2023, compared to $5.633 billion in 2022. In addition to the factors impacting adjusted operating earnings, earnings before income taxes for 2023 included a non-cash gain of $1.125 billion as a result of the acquisition of TotalEnergies Canada, and non-cash derecognition charges of $253 million on the company’s Meadow Creek development properties. Earnings before income taxes in 2022 included a non-cash impairment charge of $3.397 billion against the company’s share of the Fort Hills assets. Additionally, both periods were impacted by unrealized losses on risk management activities.

Adjusted funds from operations for the Oil Sands segment were $10.725 billion in 2023, compared to $13.831 billion in 2022, and were influenced by the same factors that impacted adjusted operating earnings.

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Production Volumes(1)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |
(mbbls/d) | ​ | 2023 | ​ | 2022 | ​ | 2021 |
Total Oil Sands bitumen production | ​ | 819.8 | ​ | 790.5 | ​ | 770.3 | ​
SCO and diesel production(2) | ​ | 505.8 | ​ | 493.7 | ​ | 483.5 | ​
Internally consumed diesel and internal transfers(3)(4) |  | (18.8) | ​ | (13.7) | ​ | (14.9) | ​
Upgraded production – net SCO and diesel |  | 487.0 | ​ | 480.0 | ​ | 468.6 | ​
Bitumen production | ​ | 231.5 | ​ | 191.9 | ​ | 178.8 | ​
Internal bitumen transfers(5)(6) | ​ | (28.9) | ​ | (6.7) | ​ | (3.2) | ​
Non-upgraded bitumen production | ​ | 202.6 | ​ | 185.2 | ​ | 175.6 | ​
Total Oil Sands production |  | 689.6 | ​ | 665.2 | ​ | 644.2 | ​

(1) | Bitumen production from Oil Sands Base is upgraded, while bitumen production from In Situ operations and Fort Hills is either upgraded or sold as bitumen, with SCO and diesel yields of approximately 79% of bitumen feedstock input. Nearly all bitumen produced at Syncrude is upgraded to sweet SCO and a small amount of diesel at an approximate yield of 85%.

(2) | Upgrader utilization rates are calculated using total upgraded production, inclusive of internally consumed diesel and internal transfers.

(3) | Both Oil Sands operations and Syncrude produce diesel, which is internally consumed in mining operations. In addition, Fort Hills and Syncrude use internally produced diesel from Oil Sands Base. In 2023, Oil Sands operations production volumes included 11,400 bbls/d of internally consumed diesel, of which 6,900 bbls/d was consumed at Oil Sands Base, 3,200 bbls/d was consumed at Fort Hills and 1,300 bbls/d was consumed at Syncrude. Syncrude production volumes included 2,700 bbls/d of internally consumed diesel.

(4) | Internal feedstock transfers between Oil Sands operations and Syncrude are included in SCO and diesel production volumes. In 2023, Oil Sands operations production included 4,700 bbls/d of SCO that were transferred to Suncor’s share of Syncrude.

(5) | Internal feedstock transfers between Oil Sands operations and Syncrude are included in bitumen production volumes. In 2023, Oil Sands operations production included 8,600 bbls/d of bitumen that were transferred to Suncor’s share of Syncrude. Syncrude production included 1,700 bbls/d of bitumen that were transferred to Oil Sands Base.

(6) | Internal feedstock transfers from Fort Hills to Oil Sands operations are included in bitumen production volumes. In 2023, Fort Hills production included 18,600 bbls/d of bitumen that was transferred to Oil Sands Base.

Total Oil Sands bitumen production increased in 2023 compared to 2022, primarily due to the company’s increased working interest in Fort Hills and record Firebag bitumen production.

The company’s net SCO production was a record 487,000 bbls/d in 2023, compared to 480,000 bbls/d in 2022. During 2023, the company achieved a combined upgrader utilization rate of 92%, compared to 89% in the prior year, with both periods benefiting from Suncor’s regional asset connectivity.

Non-upgraded bitumen production increased to 202,600 bbls/d in 2023, compared to 185,200 bbls/d in the prior year. Increased In Situ and Fort Hills bitumen production to market in 2023 was due to the company’s increased working interest in Fort Hills and strong In Situ production, being partially offset by increased internal transfers due to higher upgrader availability in the current period.

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Sales Volumes

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |
(mbbls/d) | ​ | 2023 | ​ | 2022 | ​ | 2021 |
Upgraded – net SCO and diesel | ​ | 486.6 | ​ | 482.6 | ​ | 465.7 | ​
Non-upgraded bitumen | ​ | 199.4 | ​ | 180.7 | ​ | 183.8 | ​
Total | ​ | 686.0 | ​ | 663.3 | ​ | 649.5 | ​

SCO and diesel sales volumes increased to 486,600 bbls/d in 2023, compared to 482,600 bbls/d in 2022, consistent with the increase in production, partially offset by a draw of inventory in the prior year.

Non-upgraded bitumen sales volumes increased to 199,400 bbls/d in 2023, from 180,700 bbls/d in the prior year, primarily due to the increase in production.

Price Realizations(1)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |
Net of transportation costs, but before royalties ($/bbl) | ​ | 2023 | ​ | 2022 | ​ | 2021 |
Upgraded – net SCO and diesel |  | 99.40 |  | 118.88 |  | 77.73 | ​
Non-upgraded bitumen | ​ | 67.97 | ​ | 84.63 | ​ | 53.80 | ​
Average crude | ​ | 90.27 | ​ | 109.57 | ​ | 70.96 | ​
Average crude, relative to WTI | ​ | (14.44) | ​ | (13.02) | ​ | (14.20) | ​

(1) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

Oil Sands price realizations decreased in 2023 compared to 2022, in line with the decrease in crude oil benchmark prices, the impact of weaker SYN-WTI differentials and the widening of heavy crude oil differentials in 2023, partially offset by a weaker Canadian dollar in relation to the U.S. dollar.

Royalties

Royalties for the Oil Sands segment decreased in 2023 compared to 2022, primarily due to the decrease in crude benchmark prices and crude price realizations, partially offset by increased bitumen production volumes.

Expenses and Other Factors

Total Oil Sands operating expenses for 2023 were higher relative to 2022, primarily due to increased operating expenses associated with the company’s additional working interests in Fort Hills acquired in the first and fourth quarters of 2023, increased maintenance costs, higher levels of mining activity and inflationary impacts, partially offset by lower natural gas prices and other commodity costs. See the Cash Operating Costs section below for additional details regarding cash operating costs and a breakdown of non-production costs by asset.

In 2023, depreciation, depletion, and amortization (DD&A) expense, adjusting for the impacts of derecognitions and asset impairments, was higher than 2022, primarily due to increased depreciation related to the company’s asset retirement obligation asset and the company’s increased working interest in Fort Hills, partially offset by lower derecognition charges of property, plant and equipment in the current year.

Financing expense and other, which includes other income, adjusted for the $1.125 billion non-cash gain on acquisition, increased in 2023 compared to 2022. The increase was primarily due to increased accretion expense resulting from asset retirement obligations and increased interest on leases, as a result of net leases assumed with the Fort Hills acquisitions, and entered into, during 2023, partially offset by a provision reversal in 2023 related to the company’s arrangement involving a third-party byproduct processor.

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Cash Operating Costs

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | 2023 |  | 2022 |  | 2021 |
Oil Sands OS&G(1) | ​ | 9 329 | ​ | 9 152 | ​ | 8 056 | ​
Oil Sands operations cash operating costs reconciliation |  | ​ | ​ | ​ | ​ | ​ | ​
Oil Sands operations OS&G |  | 5 174 | ​ | 5 429 | ​ | 4 840 | ​
Non-production costs(3) |  | (35) | ​ | (302) | ​ | (317) | ​
Excess power capacity and other(4) |  | (388) | ​ | (586) | ​ | (366) | ​
Oil Sands operations cash operating costs(2) ($ millions) |  | 4 751 | ​ | 4 541 | ​ | 4 157 | ​
Oil Sands operations production volumes (mbbls/d) | ​ | 438.3 | ​ | 415.7 | ​ | 439.2 | ​
Oil Sands operations cash operating costs(2) ($/bbl) |  | 29.70 | ​ | 29.95 | ​ | 25.90 | ​
Fort Hills cash operating costs reconciliation |  | ​ | ​ | ​ | ​ | ​ | ​
Fort Hills OS&G |  | 1 607 | ​ | 1 146 | ​ | 882 | ​
Non-production costs(3) |  | (220) | ​ | (161) | ​ | (81) | ​
Excess power capacity(4) | ​ | (52) | ​ | (53) | ​ | (37) | ​
Fort Hills cash operating costs(2) ($ millions) |  | 1 335 | ​ | 932 | ​ | 764 | ​
Fort Hills production volumes (mbbls/d) | ​ | 106.4 | ​ | 85.1 | ​ | 50.7 | ​
Fort Hills cash operating costs(2) ($/bbl) |  | 34.40 | ​ | 30.00 | ​ | 41.35 | ​
Syncrude cash operating costs reconciliation |  | ​ | ​ | ​ | ​ | ​ | ​
Syncrude OS&G |  | 2 837 | ​ | 2 840 | ​ | 2 449 | ​
Non-production costs(3) |  | (202) | ​ | (337) | ​ | (214) | ​
Excess power capacity(4) | ​ | (24) | ​ | (31) | ​ | (20) | ​
Syncrude cash operating costs(2) ($ millions) |  | 2 611 | ​ | 2 472 | ​ | 2 215 | ​
Syncrude production volumes (mbbls/d) | ​ | 192.6 | ​ | 184.8 | ​ | 172.4 | ​
Syncrude cash operating costs(2) ($/bbl) |  | 37.15 | ​ | 36.65 | ​ | 35.20 | ​

(1) | Beginning in 2022, the company revised the presentation of its cash operating costs reconciliation to present Oil Sands inventory changes and internal transfers on an aggregate basis and reflect: i) the impacts of changes in inventory levels and valuations, such that the company is able to present cost information based on production volumes; and ii) adjustments for internal diesel sales between assets. Comparative periods have been updated to reflect this change, with no impact to total Oil Sands operations, Fort Hills or Syncrude cash operating costs or cash operating costs per barrel. In 2023, Oil Sands OS&G included ($289) million of inventory changes and internal transfers. In 2022, Oil Sands OS&G included ($263) million of inventory changes and internal transfers. In 2021, Oil Sands OS&G included ($115) million of inventory changes and internal transfers.

(2) | Non-GAAP financial measures. Related per barrel amounts contain non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(3) | Non-production costs include, but are not limited to, share-based compensation adjustments, research costs, project startup costs and adjustments to reflect the cost of internal transfers in the receiving asset at the cost of production versus the cost of purchase. Non-production costs at Fort Hills and Syncrude also include, but are not limited to, an adjustment to reflect internally produced diesel from Oil Sands operations at the cost of production.

(4) | Represents excess power revenue from cogeneration units that is recorded in operating revenues. Oil Sands operations excess power capacity and other also includes, but is not limited to, the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.

Oil Sands operations cash operating costs per barrel(1) in 2023 decreased to $29.70 compared to $29.95 in 2022, primarily due to lower natural gas prices and increased production, partially offset by a higher proportion of Fort Hills bitumen being directed to upgrading at Oil Sands Base, increased maintenance costs and a decrease in excess power revenues resulting from lower power prices.

Fort Hills cash operating costs per barrel(1) averaged $34.40 in 2023, compared to $30.00 in 2022, with the increase primarily due to increased mining activity associated with the mine improvement plan and lower gross production volumes, partially offset by lower natural gas prices and other commodity costs.

Syncrude cash operating costs per barrel(1) averaged $37.15 in 2023, compared to $36.65 in 2022, with the increase primarily due to a higher proportion of volumes transferred from Oil Sands Base and In Situ, and increased mining activity, partially offset by higher production volumes.

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(1) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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Non-Cash Asset Impairment

During the third quarter of 2022, in connection with the company entering into an agreement to acquire Teck Resources Limited's interest in Fort Hills, as well as updates to the Fort Hills long-range plan including production and operating cost plans, the company recorded a non-cash impairment of $3.397 billion against its share of the Fort Hills assets.

Asset Transactions

On February 2, 2023, the company completed the acquisition of an additional 14.65% working interest in Fort Hills from Teck Resources Limited for $712 million, bringing the company’s working interest to 68.76%.

On November 20, 2023, Suncor completed the acquisition of TotalEnergies Canada, which held the remaining 31.23% working interest in Fort Hills, for $1.468 billion before closing adjustments and other closing costs, making Suncor the sole owner of Fort Hills. The effective date of the transaction was April 1, 2023, and the acquisition resulted in a non-cash gain of $1.125 billion.

Planned Maintenance

Significant planned turnaround activities at Syncrude are scheduled to commence in the first quarter of 2024 and are expected to be completed in the second quarter of 2024. Significant planned turnaround activities at Oil Sands Base Upgrader 1 are scheduled for the second quarter of 2024, and planned annual coker maintenance at Oil Sands Base Upgrader 2 is scheduled to commence in the third quarter of 2024 and is expected to be completed in the fourth quarter of 2024. Planned turnaround activities are scheduled at MacKay River in the third quarter of 2024. At Fort Hills, planned maintenance activities are scheduled for the second and fourth quarters of 2024. The anticipated impact of these maintenance events has been reflected in the company’s 2024 guidance.

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Exploration and Production

Strategy and Investment Updates

| ● | The company will continue to focus on the safe ramp up of production at Terra Nova in the beginning of 2024. Additionally in 2024, Suncor will continue development activities expected to extend the productive life of existing fields, such as development drilling at Hebron and Hibernia.

| ● | In 2024, the company intends to invest in the SeaRose Floating, Production, Storage and Offloading (FPSO) Asset Life Extension Project at White Rose, and the West White Rose Project, which are expected to provide long-term value for the company by extending the production life of the field. Production at White Rose is expected to resume once the SeaRose FPSO Asset Life Extension Project is completed. Production from the West White Rose Project is expected to commence in 2026.

Financial Highlights

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Operating revenues(1) |  | 2 689 |  | 4 331 |  | 2 978 | ​
Less: Royalties(1) |  | (491) |  | (608) |  | (478) | ​
Operating revenues, net of royalties |  | 2 198 |  | 3 723 |  | 2 500 | ​
Earnings before income taxes(2) |  | 1 691 |  | 3 221 |  | 1 791 | ​
Adjusted for: |  |  |  |  |  |  | ​
(Gain) loss on significant disposals(3) |  | (607) |  | 65 |  | (227) | ​
Asset impairment (reversal)(4) |  | — | ​ | (645) | ​ | (221) | ​
Recognition of insurance proceeds |  | — |  | (147) |  | — | ​
Adjusted operating earnings(2)(5) |  | 1 084 |  | 2 494 |  | 1 343 | ​
Adjusted funds from operations(2)(5) |  | 1 612 |  | 3 178 |  | 1 951 | ​
Free funds flow(5) | ​ | 944 | ​ | 2 735 | ​ | 1 681 | ​

(1) | Production from the company’s Libya operations has been presented in the E&P section of this MD&A on an economic basis. Revenue and royalties from the company’s Libya operations are presented on a working-interest basis, which is required for presentation purposes in the company’s financial statements. In 2023, revenue included a gross-up amount of $528 million, with an offsetting amount of $282 million in royalties in the E&P segment and $246 million in income tax expense recorded at the consolidated level. In 2022, revenue included a gross-up amount of $486 million, with an offsetting amount of $266 million in royalties in the E&P segment and $220 million in income tax expense recorded at the consolidated level. In 2021, revenue included a gross-up amount of $345 million, with an offsetting amount of $241 million in royalties in the E&P segment and $104 million in income tax expense recorded at the consolidated level.

(2) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(3) | In 2021, the company recorded a gain of $227 million on the sale of its interest in the Golden Eagle Area Development.

(4) | In 2021, the company recorded a non-cash impairment reversal of $221 million against its share of the Terra Nova assets as a result of the decision to proceed with the Terra Nova ALE Project and the benefit of royalty and financial support from the Government of Newfoundland and Labrador.

(5) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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(1) | For an explanation of this bridge analysis, see the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

Adjusted operating earnings were $1.084 billion for E&P in 2023, compared to $2.494 billion in the prior year, with the decrease due to lower sales volumes as a result of asset divestments, and lower realized crude prices, partially offset by decreased royalties.

Earnings before income taxes for E&P were $1.691 billion in 2023, compared to $3.221 billion in 2022. In addition to the factors impacting adjusted operating earnings, earnings before income taxes in 2023 included a gain of $607 million on the sale of the company’s U.K. portfolio, which was completed in the second quarter of 2023. Earnings before income taxes in 2022 included a non-cash impairment reversal of $715 million on the company’s share of the White Rose assets, a non-cash impairment of $70 million against the company’s share of its assets in Norway, the recognition of $147 million of property damage insurance proceeds related to the company’s assets in Libya and a $65 million foreign exchange loss related to the sale of the company’s share of its assets in Norway.

Adjusted funds from operations were $1.612 billion in 2023, compared to $3.178 billion in 2022, and were influenced by the same factors that impacted adjusted operating earnings. Adjusted funds from operations in 2022 were also impacted by the recognition of $147 million of property damage insurance proceeds related to the company’s assets in Libya.

Volumes

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | 2023 |  | 2022 |  | 2021 |
E&P Canada (mbbls/d) |  | 44.4 | ​ | 50.2 | ​ | 54.4 | ​
E&P International (mboe/d) |  | 11.7 | ​ | 27.8 | ​ | 33.1 | ​
Total production (mboe/d) |  | 56.1 | ​ | 78.0 | ​ | 87.5 | ​
Total sales volumes (mboe/d) |  | 52.9 | ​ | 80.6 | ​ | 82.8 | ​

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E&P Canada production volumes averaged 44,400 bbls/d in 2023, compared to 50,200 bbls/d the prior year, with the decrease primarily due to natural declines. White Rose was taken offline late in the fourth quarter of 2023 to commence the SeaRose FPSO Asset Life Extension Project. Production at White Rose is planned to resume once the project is completed.

E&P International production volumes averaged 11,700 boe/d in 2023, compared to 27,800 boe/d in 2022, with the decrease primarily due to the divestment of the company’s U.K. portfolio in the second quarter of 2023 and the company’s Norway assets in the third quarter of 2022.

E&P sales volumes averaged 52,900 boe/d in 2023, compared to 80,600 boe/d in the prior year, consistent with the decrease in production, as well as a build of inventory in 2023, compared to a draw in the prior year.

Price Realizations(1)

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |
Net of transportation costs, but before royalties | ​ | 2023 | ​ | 2022 | ​ | 2021 |
E&P Canada ($/bbl) |  | 107.62 |  | 128.07 |  | 84.70 | ​
E&P International(2) ($/boe) |  | 109.00 |  | 126.61 |  | 82.16 | ​

(1) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | E&P International price realizations exclude Libya for all periods presented.

E&P price realizations decreased in 2023 from the prior year, in line with the decrease in benchmark prices for Brent crude, partially offset by weaker foreign exchange rates.

Royalties

E&P royalties, excluding the impact of Libya, were lower in 2023 than the prior year primarily due to the decrease in price realizations and sales volumes.

Expenses and Other Factors

Operating and transportation expenses for 2023 were lower compared to the prior year primarily due to asset divestments at E&P International, partially offset by increased commissioning costs related to the Terra Nova ALE Project.

DD&A and exploration expenses, excluding the impacts of asset impairments, were lower in 2023 compared to the prior year primarily due to lower sales volumes and asset divestments at E&P International.

Non-Cash Asset Impairment Reversal and Impairment

During the second quarter of 2022, as a result of the decision to restart the West White Rose Project, the company recorded a non-cash impairment reversal of $715 million before-tax on its share of the White Rose assets. Also, during the second quarter of 2022, as a result of the company’s expected sale of its assets in Norway, and the subsequently reached agreement for such sale, the company recorded a non-cash impairment of $70 million before-tax against its share of the Norway assets.

Asset Transactions

During the third quarter of 2022, the company completed the sale of its assets in Norway for gross proceeds of approximately $430 million, before closing adjustments and other closing costs, resulting in a $65 million loss including foreign exchange impacts.

During the second quarter of 2023, the company completed the sale of its U.K. E&P portfolio for gross proceeds of $1.1 billion before closing adjustments and other closing costs, resulting in a gain on sale of $607 million ($607 million after-tax).

Planned Maintenance of Operated Assets

There are no planned maintenance activities scheduled for Suncor’s operated E&P assets in 2024.

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Refining and Marketing

Strategy and Investment Updates

| ● | In 2024, the company will continue the enhancement of its Petro-Canada™ retail business, with the goal of maintaining its industry leading brand position and driving increased long-term value for shareholders. Economic investment in 2024 is expected to focus on company-owned and controlled sites in the most profitable locations and markets, while targeting non-company-controlled sites in less densely populated areas using alternative ownership structures and partnerships to grow the brand’s scale and presence.

| ● | Suncor will continue to invest in the sustainment and enhancement of its refinery operations to improve efficiency and maintain safe and reliable downstream operations and its industry-leading profitability.

Financial Highlights

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Operating revenues |  | 31 068 |  | 36 728 |  | 22 915 | ​
Earnings before income taxes(1) |  | 3 383 |  | 5 694 |  | 2 867 | ​
Adjusted for: |  |  |  |  |  | ​ | ​
Unrealized gain on risk management activities | ​ | (16) | ​ | (7) | ​ | (10) | ​
Adjusted operating earnings(1)(2) |  | 3 367 |  | 5 687 |  | 2 857 | ​
Adjusted funds from operations(1)(2) |  | 4 268 |  | 6 561 |  | 3 831 | ​
Free funds flow(2) |  | 3 266 | ​ | 5 745 | ​ | 3 006 | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(2) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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(1) | For an explanation of this bridge analysis, see the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

R&M adjusted operating earnings were $3.367 billion in 2023, compared with $5.687 billion in 2022. The decrease in adjusted operating earnings was primarily due to a decrease in refining and marketing benchmark crack spreads, a FIFO inventory valuation loss in 2023, compared to a gain in 2022, and increased operating and transportation expenses.

R&M earnings before income taxes in 2023 were $3.383 billion compared to $5.694 billion in 2022. In addition to the factors impacting adjusted operating earnings, earnings before income taxes in both periods were impacted by unrealized gains on risk management activities.

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R&M achieved annual adjusted funds from operations of $4.268 billion in 2023, compared to $6.561 billion in 2022, due primarily to the same factors that impacted adjusted operating earnings.

Volumes

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | 2023 |  | 2022 |  | 2021 |
Crude oil processed (mbbls/d) |  |  |  |  |  |  | ​
Eastern North America |  | 212.4 |  | 206.2 |  | 202.8 | ​
Western North America |  | 208.3 |  | 227.0 |  | 212.7 | ​
Total |  | 420.7 |  | 433.2 |  | 415.5 | ​
Refinery utilization(1) (%) |  |  |  |  |  | ​ | ​
Eastern North America |  | 96 |  | 93 |  | 91 | ​
Western North America |  | 85 |  | 93 |  | 87 | ​
Total |  | 90 |  | 93 |  | 89 | ​
Refined product sales (mbbls/d) |  |  |  |  |  | ​ | ​
Gasoline |  | 228.0 |  | 227.6 |  | 225.8 | ​
Distillate |  | 243.9 |  | 244.6 |  | 228.5 | ​
Other |  | 81.2 |  | 81.4 |  | 74.1 | ​
Total |  | 553.1 |  | 553.6 |  | 528.4 | ​
Refinery production(2) (mbbls) | ​ | 163 895 | ​ | 168 149 | ​ | 162 862 | ​
Refining and marketing gross margin – First-in, first-out (FIFO)(3) ($/bbl) |  | 45.00 |  | 55.85 |  | 36.85 | ​
Refining and marketing gross margin – Last-in, first-out (LIFO)(3) ($/bbl) | ​ | 47.00 | ​ | 54.45 | ​ | 30.90 | ​
Refining operating expense(3) ($/bbl) |  | 7.45 |  | 7.00 |  | 5.95 | ​

(1) | Refinery utilization is the amount of crude oil and natural gas liquids processed by crude distillation units, expressed as a percentage of the nameplate capacity of these units.

(2) | Refinery production is the output of the refining process and differs from crude oil processed as a result of volumetric adjustments for non-crude feedstock, volumetric gain associated with the refining process and changes in unfinished product inventories.

(3) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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Refinery crude throughput was 420,700 bbls/d and refinery utilization averaged 90% in 2023, compared to refinery crude throughput of 433,200 bbls/d and refinery utilization of 93% in 2022, with the current year being impacted by unplanned maintenance at the Commerce City refinery in the first quarter of 2023. Refinery utilization was 99% in the second half of 2023.

Total refined product sales of 553,100 bbls/d in 2023 were comparable to 553,600 bbls/d in 2022.

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Refining and Marketing Gross Margins(1)

Refining and marketing gross margins were influenced by the following:

| ● | On a LIFO(2) basis, Suncor’s refining and marketing gross margin decreased to $47.00/bbl in 2023 from $54.45/bbl in the prior year. The decrease was due to lower benchmark crack spreads compared to the prior year, which were partially offset by strong location and quality differentials from regional benchmarks to the company’s local markets. Suncor’s refining and marketing gross margin also reflects the company’s feedstock advantage, which enables Suncor to process heavier crude oil, marketing and logistics capabilities and strong sales channels within its integrated retail and wholesale networks. On a LIFO basis, Suncor’s refining and marketing gross margin represents a margin capture of 95% of Suncor’s 5-2-2-1 index in 2023, compared to 92% in 2022.

| ● | On a FIFO basis, Suncor’s refining and marketing gross margin decreased to $45.00/bbl in 2023, from $55.85/bbl in the prior year due to the same factors discussed above, in addition to FIFO inventory valuation impacts. In 2023, the impact of the FIFO method of inventory valuation, relative to an estimated LIFO(2) accounting method, resulted in a loss of $330 million. In 2022, FIFO resulted in a gain of $230 million, for an overall unfavourable year-over-year impact of $560 million.

Expenses and Other Factors

R&M operating and transportation expenses increased compared to the prior year due to higher maintenance costs and inflationary impacts, partially offset by lower natural gas and other commodity input costs.

Refining operating expense per barrel(1) was $7.45 in 2023, compared to $7.00 in the prior year, with the increase primarily due to higher maintenance costs and lower production, partially offset by lower natural gas and other commodity input costs.

Planned Maintenance

Planned maintenance activities have commenced at the company’s Commerce City refinery and are expected to be completed in the first quarter of 2024. Planned turnaround maintenance is scheduled to commence at the company’s Montreal refinery in the first quarter of 2024 and is expected to be completed in the second quarter of 2024, and planned turnaround maintenance at the company’s Sarnia refinery is scheduled for the second quarter of 2024. The anticipated impact of these maintenance events has been reflected in the company’s 2024 guidance.

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(1) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | The estimated impact of the LIFO method is a non-GAAP financial measure. The impact of the FIFO method of inventory valuation, relative to an estimated LIFO accounting method, also includes the impact of the realized portion of commodity risk management activities. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

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Corporate and Eliminations

Strategy and Investment Updates

| ● | The company remains committed to the execution of its capital allocation framework, strengthening its balance sheet through debt reductions and maximizing shareholder returns. While the company’s net debt levels are between $12 billion and $15 billion, the company expects to allocate excess funds equally towards share repurchases and debt reductions. Once net debt is reduced to $12 billion, the company expects to allocate 75% of excess funds towards share repurchases and 25% towards debt repayment.

| ● | Suncor also has investments in low-carbon projects, including alternative fuel facilities such as the Varennes Carbon Recycling facility, a biofuel plant that is designed to convert commercial and industrial non-recyclable waste into biofuels, and in LanzaJet, Inc., a company working to bring sustainable aviation fuel and renewable diesel to the commercial market. The Varennes Carbon Recycling facility is currently under construction and expected to be operational in 2026. LanzaJet’s Freedom Pines Fuel facility, the world’s first ethanol-to-sustainable aviation fuel production facility, is currently completing fabrication and is expected to be operational in early 2024.

Financial Highlights

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Loss before income taxes(1) |  | (1 296) |  | (2 232) |  | (1 913) | ​
Adjusted for: |  |  |  |  |  |  | ​
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt |  | (184) |  | 729 |  | (113) | ​
Asset impairment | ​ | 158 | ​ | — | ​ | — | ​
Restructuring charge(2) | ​ | 275 | ​ | — | ​ | 168 | ​
Gain on significant disposal | ​ | (302) | ​ | — | ​ | — | ​
Loss on early repayment of long-term debt(3) | ​ | — | ​ | — | ​ | 80 | ​
Adjusted operating loss(1)(4) |  | (1 349) |  | (1 503) |  | (1 778) | ​
Corporate and Renewables |  | (1 405) |  | (1 456) |  | (1 588) | ​
Eliminations - Intersegment profit realized (eliminated) |  | 56 |  | (47) |  | (190) | ​
Adjusted funds used in operations(1)(4) |  | (1 546) |  | (1 240) |  | (1 705) | ​
Free funds deficit(4) | ​ | (1 608) | ​ | (1 428) | ​ | (1 997) | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated net earnings, adjusted operating earnings and adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(2) | In 2021, the company recorded a restructuring charge of $168 million related to workforce reductions in OS&G expenses.

(3) | In 2021, in connection with the early repayment of long-term debt, the company recorded a loss of $80 million in financing expenses.

(4) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

Corporate

The adjusted operating loss for Corporate was $1.405 billion in 2023, compared to $1.456 billion in 2022. The decrease in adjusted operating loss was primarily due to an increase in interest revenue on the company’s cash balances, higher costs associated with the early redemption of long-term debt in the prior year, lower share-based compensation expense and a net decrease in interest expense due to debt reductions in 2022. The decreased loss was partially offset by an operational foreign exchange loss in 2023, versus a gain in 2022, and an unrealized gain on investment recorded in 2022.

Suncor capitalized $255 million of its borrowing costs in 2023, compared to $168 million in 2022, as part of the cost of major development assets and construction projects in progress.

Eliminations – Intersegment Profit Eliminated

Eliminations reflect the deferral or realization of profit or loss on crude oil sales from Oil Sands to Suncor’s refineries. Consolidated profits and losses are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. In 2023, the company realized $56 million of intersegment profit, compared to a deferral of profit of $47 million in the prior year. The realization of profit in 2023 was primarily driven by a weakening in benchmark pricing in the current year, compared to the increase in Oil Sands price realizations in 2022.

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Adjusted funds used in operations for the Corporate and Eliminations segment were $1.546 billion in 2023, compared to $1.240 billion in 2022, and were influenced by the same factors that impacted adjusted operating loss, excluding the impact of the non-cash component of share-based compensation expense, the unrealized gain on investment recorded in 2022, and the impact of costs associated with the early redemption of long-term debt in 2022. Adjusted funds from operations in 2023 were also impacted by a restructuring charge related to the company’s workforce reductions in the second quarter of 2023.

Asset Transactions

During the first quarter of 2023, the company completed the sale of its wind and solar assets for gross proceeds of $730 million, before closing adjustments and other closing costs, resulting in a gain on sale of $302 million ($260 million after-tax).

5. Income Tax

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |
Current income tax expense |  | 1 734 |  | 4 229 |  | 1 395 | ​
Deferred income tax expense (recovery) |  | 560 |  | (990) |  | 56 | ​
Income tax expense included in net earnings |  | 2 294 |  | 3 239 |  | 1 451 | ​
Less: Income tax (recovery) expense on adjusted operating earnings adjustments | ​ | (98) | ​ | (915) | ​ | 5 | ​
Income tax expense included in adjusted operating earnings | ​ | 2 392 | ​ | 4 154 | ​ | 1 446 | ​
Effective tax rate | ​ | 21.7% | ​ | 26.3% | ​ | 26.1% | ​

The provision for income taxes in 2023 decreased compared to the prior year, primarily due to decreased earnings. In 2023, the company’s effective tax rate on net earnings decreased compared to the prior year, primarily due to the non-cash gain on the acquisition of TotalEnergies Canada, the non-taxable gain on the disposition of the company’s U.K. portfolio, as well as non-taxable foreign exchange gains on the revaluation of U.S. dollar denominated debt and other permanent items impacting total tax expense.

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6. Fourth Quarter 2023 Analysis

Financial and Operational Highlights

​ | ​ | ​ | ​ | ​ | ​
Three months ended December 31 |  | ​ |  | ​ |
($ millions, except as noted) | ​ | 2023 | ​ | 2022 |
Earnings (loss) before income taxes |  |  |  |  | ​
Oil Sands |  | 2 660 |  | 1 625 | ​
Exploration and Production |  | 133 |  | 578 | ​
Refining and Marketing |  | 598 |  | 1 517 | ​
Corporate and Eliminations |  | (1) |  | (182) | ​
Income tax expense | ​ | (570) | ​ | (797) | ​
Net earnings |  | 2 820 |  | 2 741 | ​
Adjusted operating earnings (loss)(1) |  |  |  |  | ​
Oil Sands |  | 1 526 |  | 1 719 | ​
Exploration and Production |  | 133 |  | 578 | ​
Refining and Marketing |  | 598 |  | 1 529 | ​
Corporate and Eliminations |  | (42) |  | (382) | ​
Income tax expense included in adjusted operating earnings | ​ | (580) | ​ | (1 012) | ​
Total |  | 1 635 |  | 2 432 | ​
Adjusted funds from (used in) operations(1) |  |  |  |  | ​
Oil Sands |  | 2 651 |  | 2 929 | ​
Exploration and Production |  | 228 |  | 719 | ​
Refining and Marketing |  | 811 |  | 1 663 | ​
Corporate and Eliminations |  | 10 |  | (273) | ​
Current income tax recovery (expense) | ​ | 334 | ​ | (849) | ​
Total adjusted funds from operations |  | 4 034 |  | 4 189 | ​
Changes in non-cash working capital | ​ | 284 | ​ | (265) | ​
Cash flow provided by operating activities | ​ | 4 318 | ​ | 3 924 | ​
Free funds flow(1) | ​ | 2 482 | ​ | 2 887 | ​
Production volumes |  |  |  |  | ​
Oil Sands – Upgraded – net SCO and diesel (mbbls/d) |  | 475.7 |  | 517.5 | ​
Oil Sands – Non-upgraded bitumen (mbbls/d) | ​ | 281.7 | ​ | 170.6 | ​
Total Oil Sands production volumes (mbbls/d) | ​ | 757.4 | ​ | 688.1 | ​
Exploration and Production (mboe/d) |  | 50.7 |  | 75.0 | ​
Total upstream production (mboe/d) |  | 808.1 |  | 763.1 | ​

(1) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

Net Earnings

Suncor’s consolidated net earnings for the fourth quarter of 2023 were $2.820 billion, compared to $2.741 billion in the prior year quarter. Net earnings were primarily influenced by the same factors that impacted adjusted operating earnings discussed below.

Other items affecting net earnings over these periods included:

● | An unrealized foreign exchange gain on the revaluation of U.S. dollar denominated debt of $199 million recorded in financing expenses in the Corporate and Eliminations segment in the fourth quarter of 2023, compared to $200 million in the fourth quarter of 2022.

● | An unrealized gain on risk management activities of $9 million recorded in other income (loss) in the fourth quarter of 2023, compared to an unrealized loss of $106 million in the fourth quarter of 2022.

● | During the fourth quarter of 2023, the company recorded a non-cash gain of $1.125 billion in the Oil Sands segment as a result of the acquisition of TotalEnergies Canada.

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● | During the fourth quarter of 2023, Suncor recorded a non-cash impairment of $158 million against an equity investment in the Corporate and Eliminations segment.

● | An income tax recovery related to the items noted above of $10 million in the fourth quarter of 2023, compared to $215 million in the fourth quarter of 2022.

Adjusted Operating Earnings

Suncor’s adjusted operating earnings were $1.635 billion ($1.26 per common share) in the fourth quarter of 2023, compared to $2.432 billion ($1.81 per common share) in the prior year quarter, with the decrease primarily due to lower crude oil and refined product realizations reflecting a weaker business environment in the current quarter, and decreased sales volumes in E&P, partially offset by lower income taxes, increased sales volumes in Oil Sands and increased refinery production in R&M. Adjusted operating earnings were also impacted by a weakening of benchmark pricing in both periods, resulting in an increased realization of intersegment profit in the current quarter compared to the prior year quarter.

​

Adjusted Funds from Operations and Cash Flow Provided by Operating Activities

Adjusted funds from operations were $4.034 billion ($3.12 per common share) in the fourth quarter of 2023, compared to $4.189 billion ($3.11 per common share) in the prior year quarter, and were influenced by the same factors impacting adjusted operating earnings, as well as a one-time tax benefit of approximately $880 million relating to the acquisition of TotalEnergies Canada in the fourth quarter of 2023.

Cash flow provided by operating activities, which includes changes in non-cash working capital, was $4.318 billion ($3.34 per common share) in the fourth quarter of 2023, compared to $3.924 billion ($2.91 per common share) in the prior year quarter. In addition to the factors impacting adjusted funds from operations, cash flow provided by operating activities was impacted by a source of cash associated with the company’s working capital balances in the current quarter compared to a use of cash in the prior year quarter. The source of cash in the fourth quarter of 2023 was primarily due to lower accounts receivable balances, as a result of a decrease in benchmark commodity prices during the quarter, partially offset by lower current income taxes payable, and a decrease in accounts payable and accrued liabilities.

Segmented Analysis

Oil Sands

Oil Sands segment adjusted operating earnings were $1.526 billion in the fourth quarter of 2023, compared to $1.719 billion in the prior year quarter, with the decrease primarily due to lower realized crude oil prices and increased DD&A expense, partially offset by increased sales volumes.

Total Oil Sands bitumen production increased in the fourth quarter of 2023 compared to the prior year quarter, primarily due to the company’s increased working interest and strong bitumen production at Fort Hills, partially offset by decreased bitumen production at Oil Sands Base and Firebag as a result of planned turnaround and maintenance activities.

The company’s net SCO production was 475,700 bbls/d in the fourth quarter of 2023, compared to 517,500 bbls/d in the prior year quarter, reflecting significant planned turnaround activities at Oil Sands Base Upgrader 2 that were completed in the first part of the fourth quarter of 2023. Oil Sands Base upgrader utilization was 83% in the fourth quarter of 2023, compared to 93% in the prior year quarter. Syncrude upgrader utilization was 101% in the fourth quarter of 2023, compared to 99% in the prior year quarter.

Internal bitumen transfers reached 45,300 bbls/d in the fourth quarter of 2023, demonstrating the increased level of integration within Suncor’s regional Oil Sands assets. The increase was primarily driven by 41,800 bbls/d of bitumen transferred from Fort Hills to upgrading at Oil Sands Base, taking advantage of the yield uplift from Fort Hills barrels.

The company’s saleable non-upgraded bitumen production increased to 281,700 bbls/d in the fourth quarter of 2023, compared to 170,600 bbls/d in the prior year quarter, reflecting the company’s increased working interest and strong production at Fort Hills, as well as increased In Situ and Fort Hills bitumen production sent to market in the current quarter due to lower upgrader availability as a result of the planned turnaround at Oil Sands Base Upgrader 2.

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Exploration and Production

Adjusted operating earnings for the E&P segment in the fourth quarter of 2023 were $133 million, compared to $578 million in the prior year quarter, with the decrease primarily due to decreased sales volumes.

Production volumes for E&P Canada were 45,300 bbls/d in the fourth quarter of 2023, compared to 49,100 bbls/d in the prior year quarter, with the decrease primarily due to natural declines, partially offset by the ramp up of production at Terra Nova in the current quarter.

Production volumes for E&P International were 5,400 boe/d in the fourth quarter of 2023, compared to 25,900 boe/d in the prior year quarter, with the decrease primarily due the divestment of the company’s U.K. portfolio in the second quarter of 2023.

Total E&P sales volumes were 29,200 boe/d in the fourth quarter of 2023, compared to 75,100 boe/d in the prior year quarter, primarily due to the same factors that impacted production volumes, as well as a larger build of inventory in E&P Canada in the fourth quarter of 2023 compared to the prior year quarter, associated with the timing of cargo sales at year-end, and a draw of inventory in E&P International in the prior year quarter.

Refining and Marketing

R&M adjusted operating earnings in the fourth quarter of 2023 were $598 million, compared to $1.529 billion in the prior year quarter. The decrease in adjusted operating earnings was primarily due to lower benchmark crack spreads in the current quarter compared to the prior year quarter, partially offset by increased refinery production.

Refinery crude throughput was 455,900 bbls/d and refinery utilization was 98% in the fourth quarter of 2023, compared to 440,000 bbls/d and 94% in the prior year quarter, reflecting strong utilization across all refineries in the current quarter, and the impact of unplanned maintenance in the prior year quarter, including a weather-related event at the Commerce City refinery.

Refined product sales were 575,500 bbls/d in the fourth quarter of 2023, compared to 548,200 bbls/d in the prior year quarter, with the increase due to higher refinery production, partially offset by a larger build of refined product inventory in the current quarter compared to the prior year quarter.

Corporate and Eliminations

Corporate incurred an adjusted operating loss of $341 million in the fourth quarter of 2023, compared to $482 million in the prior year quarter. The decreased loss was primarily attributable to an operational foreign exchange gain in the fourth quarter of 2023, compared to a loss in the prior year quarter. The decreased loss was also driven by a lower share-based compensation expense, decreased spend in low-carbon fuel development projects compared to the prior year quarter, and increased costs associated with the early redemption of long-term debt in the prior year quarter. Suncor capitalized $70 million of its borrowing costs in the fourth quarter of 2023, as part of the cost of major development assets and construction projects in progress, compared to $44 million in the prior year quarter.

Eliminations reflect the deferral or realization of profit or loss on crude oil sales from Oil Sands to Suncor’s refineries. Consolidated profits and losses are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the fourth quarter of 2023, the company realized $299 million of intersegment profit, compared to $100 million in the prior year quarter. The realization of intersegment profit was primarily driven by a weakening in benchmark pricing in both periods.

​

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7. Quarterly Financial Data

Financial Summary

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Three months ended |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |
($ millions, unless otherwise noted) | ​ | 2023 | ​ | 2023 | ​ | 2023 | ​ | 2023 | ​ | 2022 | ​ | 2022 | ​ | 2022 | ​ | 2022 |
Total production (mboe/d) |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  |  |  |  |  |  |  |  | ​
Oil Sands |  | 757.4 | ​ | 646.1 | ​ | 679.1 | ​ | 675.1 | ​ | 688.1 | ​ | 646.0 | ​ | 641.5 | ​ | 685.7 | ​
Exploration and Production |  | 50.7 | ​ | 44.4 | ​ | 62.8 | ​ | 67.0 | ​ | 75.0 | ​ | 78.1 | ​ | 78.7 | ​ | 80.4 | ​
Total upstream production |  | 808.1 |  | 690.5 |  | 741.9 |  | 742.1 |  | 763.1 |  | 724.1 |  | 720.2 |  | 766.1 | ​
Revenues and other income |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ | ​
Operating revenues, net of royalties(1) |  | 12 810 | ​ | 12 649 | ​ | 11 719 | ​ | 11 914 | ​ | 13 920 | ​ | 14 944 | ​ | 16 135 | ​ | 13 337 | ​
Other income (loss) |  | 1 328 | ​ | (13) | ​ | (3) | ​ | 342 | ​ | (65) | ​ | 113 | ​ | 69 | ​ | 14 | ​
​ |  | 14 138 |  | 12 636 |  | 11 716 |  | 12 256 |  | 13 855 |  | 15 057 |  | 16 204 |  | 13 351 | ​
Net earnings (loss) |  | 2 820 | ​ | 1 544 | ​ | 1 879 | ​ | 2 052 | ​ | 2 741 | ​ | (609) | ​ | 3 996 | ​ | 2 949 | ​
Per common share – basic (dollars) | ​ | 2.18 | ​ | 1.19 | ​ | 1.44 | ​ | 1.54 | ​ | 2.03 | ​ | (0.45) | ​ | 2.84 | ​ | 2.06 | ​
Per common share – diluted (dollars) |  | 2.18 | ​ | 1.19 | ​ | 1.43 | ​ | 1.54 | ​ | 2.03 | ​ | (0.45) | ​ | 2.83 | ​ | 2.06 | ​
Adjusted operating earnings(2) |  | 1 635 | ​ | 1 980 | ​ | 1 253 | ​ | 1 809 | ​ | 2 432 | ​ | 2 565 | ​ | 3 814 | ​ | 2 755 | ​
Per common share(3)(4) (dollars) |  | 1.26 | ​ | 1.52 | ​ | 0.96 | ​ | 1.36 | ​ | 1.81 | ​ | 1.88 | ​ | 2.71 | ​ | 1.92 | ​
Adjusted funds from operations(2) |  | 4 034 | ​ | 3 634 | ​ | 2 655 | ​ | 3 002 | ​ | 4 189 | ​ | 4 473 | ​ | 5 345 | ​ | 4 094 | ​
Per common share(3)(4) (dollars) |  | 3.12 | ​ | 2.80 | ​ | 2.03 | ​ | 2.26 | ​ | 3.11 | ​ | 3.28 | ​ | 3.80 | ​ | 2.86 | ​
Cash flow provided by operating activities |  | 4 318 | ​ | 4 184 | ​ | 2 803 | ​ | 1 039 | ​ | 3 924 | ​ | 4 449 | ​ | 4 235 | ​ | 3 072 | ​
Per common share(4) (dollars) |  | 3.34 | ​ | 3.22 | ​ | 2.14 | ​ | 0.78 | ​ | 2.91 | ​ | 3.26 | ​ | 3.01 | ​ | 2.14 | ​
Return on Capital Employed (ROCE)(3) (%) for the twelve months ended |  | 15.6 | ​ | 15.8 | ​ | 12.8 | ​ | 17.8 | ​ | 19.4 | ​ | 17.5 | ​ | 19.4 | ​ | 12.7 | ​
ROCE excluding impairments and impairment reversals(3)(5) (%) for the twelve months ended |  | 15.6 | ​ | 15.8 | ​ | 16.3 | ​ | 21.6 | ​ | 22.9 | ​ | 21.0 | ​ | 18.2 | ​ | 12.4 | ​
Common share information (dollars) | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Dividend per common share(4) |  | 0.55 | ​ | 0.52 | ​ | 0.52 | ​ | 0.52 | ​ | 0.52 | ​ | 0.47 | ​ | 0.47 | ​ | 0.42 | ​
Share price at the end of trading | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Toronto Stock Exchange (Cdn$) |  | 42.45 | ​ | 46.71 | ​ | 38.86 | ​ | 41.96 | ​ | 42.95 | ​ | 38.90 | ​ | 45.16 | ​ | 40.70 | ​
New York Stock Exchange (US$) |  | 32.04 | ​ | 34.38 | ​ | 29.32 | ​ | 31.05 | ​ | 31.73 | ​ | 28.15 | ​ | 35.07 | ​ | 32.59 | ​

(1) | The company revised certain gross revenues and purchases of crude oil and products to align with the current period presentation. For the three months ended March 31, 2022, gross revenues and purchases of crude oil and products was decreased by $150 million, with no effect on net earnings.

(2) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A. Adjusted operating earnings (loss) for each quarter are defined in the Non-GAAP and Other Financial Measures Advisory section and reconciled to the most directly comparable GAAP measure in the Consolidated Financial Information and Segment Results and Analysis sections of each Quarterly Report to Shareholders issued by Suncor (Quarterly Reports) in respect of the relevant quarter, with such information being incorporated by reference herein and available on SEDAR+ at www.sedarplus.ca. Adjusted funds from operations for each quarter are defined and reconciled to the most directly comparable GAAP measure in the Non-GAAP and Other Financial Measures Advisory section of each Quarterly Report in respect of the relevant quarter, with such information being incorporated by reference herein and available on SEDAR+ at www.sedarplus.ca.

(3) | Contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A. Non-GAAP measures included in ROCE and ROCE excluding impairments and impairment reversals are defined and reconciled to the most directly comparable GAAP measure in the Non-GAAP and Other Financial Measures Advisory section of each Quarterly Report in respect of the relevant quarter, with such information being incorporated by reference herein and available on SEDAR+ at www.sedarplus.ca.

(4) | Represented on a basic per share basis.

(5) | ROCE would have been 13.6% for the twelve months ended December 31, 2023, excluding the impact of the $1.125 billion non-cash gain on acquisition of TotalEnergies Canada.

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Business Environment

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Three months ended | ​ | ​ |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 | ​
(average for the period ended, except as noted) | ​ | ​ | ​ | 2023 | ​ | 2023 | ​ | 2023 | ​ | 2023 | ​ | 2022 | ​ | 2022 | ​ | 2022 | ​ | 2022 |
WTI crude oil at Cushing |  | US$/bbl |  | 78.35 | ​ | 82.20 | ​ | 73.75 | ​ | 76.10 | ​ | 82.65 | ​ | 91.65 | ​ | 108.40 | ​ | 94.40 | ​
Dated Brent crude |  | US$/bbl |  | 84.05 | ​ | 86.70 | ​ | 78.35 | ​ | 81.25 | ​ | 88.65 | ​ | 100.95 | ​ | 113.75 | ​ | 101.50 | ​
Dated Brent/Maya FOB price differential |  | US$/bbl |  | 56.80 | ​ | 11.15 | ​ | 14.75 | ​ | 18.40 | ​ | 17.70 | ​ | 17.95 | ​ | 11.65 | ​ | 14.30 | ​
MSW at Edmonton |  | Cdn$/bbl |  | 99.70 | ​ | 107.80 | ​ | 95.10 | ​ | 99.05 | ​ | 110.05 | ​ | 116.85 | ​ | 137.80 | ​ | 115.75 | ​
WCS at Hardisty |  | US$/bbl |  | 56.45 | ​ | 69.30 | ​ | 58.70 | ​ | 51.35 | ​ | 57.00 | ​ | 71.75 | ​ | 95.60 | ​ | 79.80 | ​
WTI-WCS light/heavy differential |  | US$/bbl |  | (21.90) | ​ | (12.90) | ​ | (15.05) | ​ | (24.75) | ​ | (25.65) | ​ | (19.90) | ​ | (12.80) | ​ | (14.60) | ​
SYN-WTI premium (differential) | ​ | US$/bbl | ​ | 0.30 | ​ | 2.80 | ​ | 2.90 | ​ | 2.10 | ​ | 4.15 | ​ | 8.80 | ​ | 6.05 | ​ | (1.30) | ​
Condensate at Edmonton |  | US$/bbl |  | 76.25 | ​ | 77.90 | ​ | 72.35 | ​ | 79.85 | ​ | 83.40 | ​ | 87.35 | ​ | 108.35 | ​ | 96.15 | ​
Natural gas (Alberta spot) at AECO |  | Cdn$/GJ |  | 2.15 | ​ | 2.50 | ​ | 2.35 | ​ | 3.05 | ​ | 4.90 | ​ | 4.15 | ​ | 6.90 | ​ | 4.50 | ​
Alberta Power Pool Price |  | Cdn$/MWh |  | 81.60 | ​ | 151.60 | ​ | 159.80 | ​ | 142.00 | ​ | 213.95 | ​ | 221.40 | ​ | 122.45 | ​ | 90.00 | ​
New York Harbor 2-1-1 crack(1) |  | US$/bbl |  | 28.60 | ​ | 39.95 | ​ | 32.30 | ​ | 36.70 | ​ | 52.75 | ​ | 46.70 | ​ | 60.05 | ​ | 28.25 | ​
Chicago 2-1-1 crack(1) |  | US$/bbl |  | 17.10 | ​ | 27.45 | ​ | 28.60 | ​ | 31.55 | ​ | 39.20 | ​ | 43.30 | ​ | 49.40 | ​ | 20.20 | ​
Portland 2-1-1 crack(1) |  | US$/bbl |  | 29.35 | ​ | 55.90 | ​ | 37.30 | ​ | 37.40 | ​ | 50.70 | ​ | 57.30 | ​ | 63.45 | ​ | 33.80 | ​
Gulf Coast 2-1-1 crack(1) |  | US$/bbl |  | 23.00 | ​ | 39.10 | ​ | 29.15 | ​ | 37.65 | ​ | 40.20 | ​ | 41.85 | ​ | 52.55 | ​ | 26.80 | ​
U.S. Renewable Volume Obligation | ​ | US$/bbl | ​ | 4.75 | ​ | 7.45 | ​ | 7.70 | ​ | 8.20 | ​ | 8.55 | ​ | 8.10 | ​ | 7.80 | ​ | 6.45 | ​
Suncor custom 5-2-2-1 index(2) | ​ | US$/bbl | ​ | 33.45 | ​ | 36.00 | ​ | 34.20 | ​ | 42.80 | ​ | 51.90 | ​ | 45.45 | ​ | 51.45 | ​ | 32.25 | ​
Exchange rate (average) |  | US$/Cdn$ |  | 0.73 | ​ | 0.75 | ​ | 0.74 | ​ | 0.74 | ​ | 0.74 | ​ | 0.77 | ​ | 0.78 | ​ | 0.79 | ​
Exchange rate (end of period) |  | US$/Cdn$ |  | 0.76 | ​ | 0.74 | ​ | 0.76 | ​ | 0.74 | ​ | 0.74 | ​ | 0.73 | ​ | 0.78 | ​ | 0.80 | ​

(1) | 2-1-1 crack spreads are indicators of the refining margin generated by converting two barrels of WTI into one barrel of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

(2) | Suncor has developed an indicative 5-2-2-1 index based on publicly available pricing data to more accurately reflect the company’s realized refining and marketing gross margin.

Significant or Unusual Items Impacting Net Earnings (Loss)

Trends in Suncor’s quarterly revenue, net earnings (loss) and adjusted funds from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events, changes in commodity prices and crude differentials, refining crack spreads and foreign exchange rates as described in the Financial Information section of this MD&A. Trends in Suncor’s quarterly net earnings (loss) and adjusted funds from operations are also affected by other significant events impacting operations, such as operational incidents.

In addition to the impacts of changes in production volumes and business environment, net earnings (loss) over the last eight quarters were affected by the following events or significant adjustments:

● | During the fourth quarter of 2023, the company recorded a non-cash gain of $1.125 billion in the Oil Sands segment as a result of the acquisition of TotalEnergies Canada.

● | During the fourth quarter of 2023, Suncor recorded a non-cash impairment of $158 million against an equity investment in the Corporate and Eliminations segment.

● | During the third quarter of 2023, the company recorded non-cash derecognition charges of $253 million on its Meadow Creek development properties in the Oil Sands segment.

● | During the second quarter of 2023, Suncor recorded a gain of $607 million on the sale of its U.K. E&P portfolio.

● | In the second quarter of 2023, the company recorded a restructuring charge of $275 million in OS&G expenses in the Corporate and Eliminations segment, related to the company’s workforce reductions.

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● | During the first quarter of 2023, the company recorded a gain of $302 million on the sale of its wind and solar assets in the Corporate and Eliminations segment.

● | During the third quarter of 2022, the company recorded a non-cash impairment of $3.397 billion before-tax against its share of the Fort Hills assets in the Oil Sands segment.

● | During the third quarter of 2022, Suncor recognized $147 million of property damage insurance proceeds, in other income, related to the company’s assets in Libya in the E&P segment.

● | During the third quarter of 2022, the company recorded a $65 million foreign exchange loss related to the sale of the company’s share of its assets in Norway in the E&P segment.

● | During the second quarter of 2022, Suncor recorded a non-cash impairment reversal of $715 million on its share of the White Rose assets in the E&P segment, and a non-cash impairment of $70 million against its share of its assets in Norway in the E&P segment.

8. Capital Investment Update

Capital and Exploration Expenditures by Type, Excluding Capitalized Interest

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Year ended
​ | ​ | December 31, 2023 | ​ | December 31, 2022
($ millions) |  | Asset Sustainment and Maintenance(1) |  | Economic Investment(2) |  | Total |  | Total
Oil Sands |  | ​ | ​ | ​ |  | ​ | ​ | ​
Oil Sands Base |  | 1 345 | ​ | 627 |  | 1 972 | ​ | 1 673
In Situ |  | 160 | ​ | 357 |  | 517 | ​ | 543
Fort Hills |  | 376 | ​ | 21 |  | 397 | ​ | 337
Syncrude | ​ | 738 | ​ | 252 |  | 990 | ​ | 852
E&P(3) |  | — | ​ | 635 |  | 635 | ​ | 420
R&M |  | 876 | ​ | 124 |  | 1 000 | ​ | 816
Corporate and Eliminations(4) |  | 48 | ​ | 14 |  | 62 | ​ | 178
​ |  | 3 543 |  | 2 030 |  | 5 573 | ​ | 4 819
Capitalized interest on debt |  | ​ | ​ | ​ | ​ | 255 | ​ | 168
Total capital and exploration expenditures |  | ​ | ​ | ​ | ​ | 5 828 | ​ | 4 987

(1) | Asset sustainment and maintenance capital expenditures include capital investments that deliver on existing value by ensuring compliance or maintaining relations with regulators and other stakeholders, maintaining current processing capacity and delivering existing developed reserves.

(2) | Economic investment capital expenditures include capital investments that result in an increase in value by adding reserves or improving processing capacity, utilization, cost or margin, including associated infrastructure.

(3) | Excludes capital expenditures related to assets previously held for sale of $108 million in 2023, compared to $57 million in 2022.

(4) | Excludes capital expenditures related to assets previously held for sale of $76 million in 2022.

In 2023 Suncor’s capital expenditures, excluding capitalized borrowing costs, were $5.573 billion, compared to $4.819 billion in 2022. The increase was due to increased economic expenditures, primarily at E&P, related to the West White Rose Project and Terra Nova ALE Project, at Oil Sands Base, related to the new cogeneration facility, and at Syncrude, related to Mildred Lake West Extension mining project, which was partially offset by decreased economic expenditures in the Corporate and Eliminations segment in 2023, primarily due higher investment in digital technologies and the Forty Mile Wind Power Project in the prior year. The increase was also due to increased asset sustainment and maintenance capital expenditures at Oil Sands Base and R&M.

Activity in 2023 included the following:

Oil Sands Base

Oil Sands Base asset sustainment and maintenance capital expenditures were $1.345 billion in 2023 and were primarily focused on ensuring continued safe, reliable and efficient operations. The company’s planned maintenance program in 2023

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included mine and tailings development, significant planned turnaround activities at Upgrader 2 and planned annual coker maintenance at Upgrader 1.

Oil Sands Base economic capital of $627 million in 2023 was primarily focused on progressing the investment in low-carbon power generation by replacing the coke-fired boilers with a new cogeneration facility, which is expected to be in service in late 2024.

In Situ

In Situ capital expenditures were $517 million in 2023, of which $357 million was directed towards economic investment activities, which focused on the ongoing design and construction of well pads to develop additional reserves that are expected to maintain existing production levels at Firebag and MacKay River in future years. Asset sustainment and maintenance capital expenditures of $160 million were primarily directed towards the company’s planned maintenance program.

Fort Hills

Fort Hills capital expenditures were $397 million in 2023, the majority of which were directed towards asset sustainment related to mine and tailings development to support ongoing operations, including the execution of the mine improvement plan, as well as its first full plant turnaround and planned maintenance activities.

Syncrude

Syncrude capital expenditures were $990 million in 2023, the majority of which were directed toward asset sustainment and maintenance capital expenditures that focused on its planned turnaround, planned maintenance activities, mine equipment replacements and tailings development. Economic investment activities were directed towards progressing the Mildred Lake West Extension mining project.

Exploration and Production

E&P capital and exploration expenditures were $635 million in 2023, and were focused on economic investment projects, primarily development work on the West White Rose Project and the Terra Nova ALE Project.

Refining and Marketing

R&M capital expenditures were $1.000 billion in 2023, of which $876 million was directed toward asset sustainment and maintenance capital expenditures of refinery and retail operations. This included planned turnaround and maintenance activities at each of the company’s refineries during the year.

R&M economic capital expenditures of $124 million in 2023 was primarily directed towards expanding and strengthening the company’s sales and marketing business, including investment into the enhancement of its retail operations.

Corporate

Corporate capital expenditures were $62 million in 2023, primarily directed towards investment in digital technologies.

Suncor anticipates 2024 capital expenditures to be directed to the following projects and initiatives:

Oil Sands operations

Plans for economic investment in 2024 include capital related to the Upgrader 1 coke drum replacement and the safe commissioning of the new cogeneration facility to replace the coke-fired boilers at Oil Sands Base. Additional investment includes the ongoing design and construction of well pads to develop additional reserves that are expected to maintain existing production levels at Firebag and MacKay River in future years.

Asset sustainment and maintenance capital expenditures for 2024 are expected to include expenditures relating to the company’s planned maintenance program, including the significant planned turnaround at Upgrader 1, planned annual coker maintenance at Upgrader 2 and planned turnaround activities at MacKay River, as well as mine and tailings development activities, and mine equipment replacements.

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Fort Hills

Asset sustainment and maintenance capital expenditures for 2024 are expected to focus on ongoing development of mining and tailings management projects to preserve production capacity and execute on the mine improvement plan, as well as planned maintenance activities. Plans for economic investment in 2024 include mine equipment purchases and replacements, including haul trucks, and the second North Pit mine development.

Syncrude

Asset sustainment and maintenance capital expenditures for 2024 are expected to include expenditures relating to the Syncrude’s planned maintenance program, including the significant planned spring turnaround, as well as other planned maintenance activities. Additionally, asset sustainment and maintenance expenditures in 2024 are expected to include expenditures related to tailings development and mine equipment replacements.

For 2024, plans for economic investment are primarily focused on progressing the Mildred Lake West Extension mining project.

Exploration and Production

Economic investment for 2024 is expected to be primarily focused on development work at the SeaRose FPSO Asset Life Extension Project and the West White Rose Project, as well as development activities to extend the productive life of existing fields, including development drilling at Hebron and Hibernia.

Refining and Marketing

Sustaining capital expenditures for 2024 are expected to focus on ongoing sustainment of refinery, logistics and retail operations, including planned refinery turnaround maintenance.

Economic investment projects in 2024 are expected to be primarily directed towards expanding and strengthening the company’s sales and marketing business, including investment into the enhancement of its retail and wholesale operations.

​

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9. Financial Condition and Liquidity

Liquidity and Capital Resources

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At December 31 ($ millions, except as noted) |  | 2023 |  | 2022 |  | 2021 |
Cash flow provided by (used in) |  |  |  |  |  |  | ​
Operating activities |  | 12 344 |  | 15 680 |  | 11 764 | ​
Investing activities |  | (6 511) |  | (4 789) |  | (3 977) | ​
Financing activities |  | (5 990) |  | (11 228) |  | (7 464) | ​
Foreign exchange loss on cash and cash equivalents |  | (94) |  | 112 |  | (3) | ​
(Decrease) increase in cash and cash equivalents |  | (251) |  | (225) |  | 320 | ​
Cash and cash equivalents, end of year |  | 1 729 |  | 1 980 |  | 2 205 | ​
ROCE(1)(2) (%) |  | 15.6 |  | 19.4 |  | 8.6 | ​
Net debt to adjusted funds from operations(1) (times) |  | 1.0 |  | 0.8 |  | 1.6 | ​
Total debt to total debt plus shareholders’ equity(1) (%) |  | 26.3 |  | 28.4 |  | 33.4 | ​
Net debt to net debt plus shareholders’ equity(1) (%) |  | 24.0 |  | 25.7 |  | 30.6 | ​
Net debt to net debt plus shareholders’ equity - excluding leases(1) (%) |  | 18.5 |  | 21.3 |  | 26.6 | ​

(1) | Non-GAAP financial measures or contains non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

(2) | For the twelve months ended December 31, 2023, there were no impairments or impairment reversals. As a result, ROCE excluding impairments was equal to ROCE. ROCE would have been 13.6% for the twelve months ended December 31, 2023, excluding the impact of the $1.125 billion non-cash gain on acquisition of TotalEnergies Canada. ROCE would have been 22.9% for the twelve months ended December 31, 2022, excluding the impact of the impairment reversal of $715 million ($542 million after-tax) and impairment of $70 million ($47 million after-tax) in the second quarter of 2022, and the impact of the impairment of $3.397 billion ($2.586 billion after-tax) in the third quarter of 2022. ROCE would have been 8.2% for the twelve months ended December 31, 2021, excluding the impact of the impairment reversal of $221 million ($168 million after-tax) in the third quarter of 2021.

Cash Flow Provided by Operating Activities

Cash flow provided by operating activities was $12.344 billion in 2023, compared to $15.680 billion in 2022. The decrease was primarily due to a weaker business environment in the current year, resulting in decreased crude oil and refined product price realizations, and decreased sales volumes in E&P due to international asset divestments, partially offset by lower income taxes and royalties, and increased sales volumes in Oil Sands.

The current period cash flow provided by operating activities reflects a use of cash in working capital, primarily due to significantly lower net income taxes payable, and a decrease in accounts payable and accrued liabilities, partially offset by a decrease in accounts receivable balances related to the decrease in commodity prices in 2023. The prior period cash flow provided by operating activities reflects a significant use of cash in working capital, primarily due to an increase in inventory balances and accounts receivable related to the increase in commodity prices and crude oil price realizations in 2022, and a net decrease in taxes payable due to income tax instalments paid throughout the year, partially offset by an increase in accounts payable and accrued liabilities.

Cash Flow Used in Investing Activities

Cash flow used in investing activities was $6.511 billion in 2023, compared to $4.789 billion in 2022. The increase was primarily due to the impacts of the acquisition of an additional 45.89% working interest in Fort Hills in 2023, and increased capital expenditures, partially offset by proceeds from the sale of the company’s U.K. E&P portfolio and wind and solar assets in 2023.

Cash Flow Used in Financing Activities

Cash flow used in financing activities was $5.990 billion in 2023, compared to $11.228 billion in 2022. The decrease was primarily due to a significant decrease in long-term debt in the prior year, a decrease in share repurchases and the issuance of long-term debt in the current year, partially offset by a net decrease in short-term debt in 2023 compared to an increase in 2022.

Capital Resources

Suncor’s capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, and available credit facilities, including commercial paper. Suncor’s management believes the company will have the capital

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resources required to fund its planned 2024 capital spending program of $6.3 billion to $6.5 billion, and to meet current and future working capital requirements through cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, accessing capital markets. The company’s cash flow provided by operating activities depends on several factors, including commodity prices, production, sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

The company has invested cash in short-term financial instruments that are presented as cash and cash equivalents. The objectives of the company’s short-term investment portfolio are to ensure the preservation of capital, maintain adequate liquidity to meet Suncor’s cash flow requirements and deliver competitive returns derived from the quality and diversification of investments within acceptable risk parameters. The maximum weighted average term to maturity of the short-term investment portfolio is not expected to exceed six months, and all investments are with counterparties with investment grade debt ratings.

Available Sources of Liquidity

Cash and Cash Equivalents

Included in cash and cash equivalents of $1.729 billion at December 31, 2023, are short-term investments with weighted average days to maturity of approximately 20 days. In 2023, the company earned approximately $3 million of interest income on these investments.

​

Financing Activities

Suncor’s interest on debt and lease liabilities (before capitalized interest) in 2023 was $981 million, comparable to $982 million in 2022, with interest expense on debt decreasing as a result of debt reductions in 2022, offset by an increase in interest on leases.

Available lines of credit at December 31, 2023, increased to $4.957 billion compared to $2.900 billion as at December 31, 2022. The increase in liquidity was primarily due to a decrease in short-term indebtedness, partially offset by a reduction in the size of the company’s syndicated credit facilities. In the second quarter of 2023, the company extended the maturity of its syndicated credit facilities from June 2024 and June 2025 to June 2026, and reduced the size of its $3.0 billion tranche to $2.8 billion. As of December 31, 2023, Suncor had approximately $6.7 billion of liquidity.

A summary of total and unutilized credit facilities at December 31, 2023, is as follows:

​ | ​ | ​ | ​
($ millions) |  | 2023 |
Fully revolving and expiring in 2026 |  | 5 451 | ​
Can be terminated at any time at the option of the lenders |  | 1 520 | ​
Total credit facilities |  | 6 971 | ​
Credit facilities supporting outstanding commercial paper |  | (494) | ​
Credit facilities supporting standby letters of credit |  | (944) | ​
Total unutilized credit facilities(1) |  | 5 533 | ​

(1) | Available credit facilities for liquidity purposes were $4.957 billion at December 31, 2023 (December 31, 2022 – $2.900 billion).

​

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Total Debt to Total Debt Plus Shareholders’ Equity

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an “event of default” as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders’ equity. At December 31, 2023, total debt to total debt plus shareholders’ equity was 26.3% (December 31, 2022 – 28.4%), a decrease from the prior year due primarily to higher shareholders’ equity as a result of increased net earnings. The company is currently in compliance with all operating covenants as at December 31, 2023.

Change in Debt

​ | ​ | ​ | ​
($ millions) |  | 2023 |
Total debt(1) – December 31, 2022 |  | 15 619 | ​
Increase in long-term debt |  | 1 495 | ​
Decrease in short-term debt |  | (2 343) | ​
Increase in lease liability | ​ | 1 156 | ​
Lease payments | ​ | (331) | ​
Foreign exchange on debt, and other | ​ | (189) | ​
Total debt(1) – December 31, 2023 |  | 15 407 | ​
Less: Cash and cash equivalents – December 31, 2023 |  | 1 729 | ​
Net debt(1) – December 31, 2023 |  | 13 678 | ​

(1) | Non-GAAP financial measures. See the Advisories – Non-GAAP and Other Financial Measures section of this MD&A.

The company’s total debt decreased in the twelve months ended December 31, 2023, primarily due to a decrease in short-term indebtedness, principal lease payments made during the period and favourable foreign exchange rates on U.S. dollar denominated debt compared to December 31, 2022, partially offset by the issuance of long-term debt, as discussed below, and an increase in net leases assumed with the Fort Hills acquisitions, and entered into, during the period.

During the fourth quarter of 2023, the company issued $1.0 billion principal amount of 5.60% senior unsecured medium term notes and $500 million principal amount of 5.40% senior unsecured medium term notes, due on November 17, 2025, and November 17, 2026, respectively, to finance the acquisition of TotalEnergies Canada.

As at December 31, 2023, Suncor’s net debt was $13.678 billion, compared to $13.639 billion at December 31, 2022. The change in net debt was primarily due to the factors discussed above, and a decrease in cash and cash equivalents.

For the year ended December 31, 2023, the company’s net debt to adjusted funds from operations measure was 1.0 times, which is lower than management’s maximum target of less than 3.0 times.

Credit Ratings

The company’s credit ratings affect its cost of funds and liquidity. In particular, the company’s ability to access unsecured funding markets and to engage in certain activities on a cost-effective basis is primarily dependent upon maintaining a strong credit rating. A lowering of the company’s credit rating may also have potentially adverse consequences for the company’s funding capacity or access to the capital markets, may affect the company’s ability, and the cost, to enter into normal course derivative or hedging transactions, and may require the company to post additional collateral under certain contracts.

As at March 21, 2024, the company’s long-term senior debt ratings are:

​ | ​ | ​ | ​ | ​ | ​
​ |  | ​ |  | Long-Term |
Long-Term Senior Debt | ​ | Rating | ​ | Outlook |
S&P Global Ratings |  | BBB | ​ | Negative | ​
Morningstar DBRS |  | A (low) | ​ | Stable | ​
Moody’s Investors Service |  | Baa1 | ​ | Stable | ​
Fitch Ratings | ​ | BBB+ | ​ | Stable | ​

​

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As at March 21, 2024, the company’s commercial paper ratings are:

​ | ​ | ​ | ​ | ​ | ​
​ |  | Cdn Program |  | U.S. Program |
Commercial Paper | ​ | Rating | ​ | Rating |
S&P Global Ratings |  | Not rated | ​ | A-2 | ​
Morningstar DBRS |  | R-1 (low) | ​ | Not rated | ​
Moody’s Investors Service |  | Not rated | ​ | P-2 | ​
Fitch Ratings | ​ | Not rated | ​ | F-1 | ​

​

Refer to the Description of Capital Structure – Credit Ratings section of Suncor’s 2023 AIF for a description of credit ratings listed above.

Common Shares

Outstanding Shares

​ | ​ | ​ | ​
(thousands) |  | December 31, 2023 |
Common shares |  | 1 290 100 | ​
Common share options – exercisable |  | 14 300 | ​
Common share options – non-exercisable |  | 2 736 | ​

​

As at March 20, 2024, the total number of common shares outstanding was 1,287,023,119 and the total number of exercisable and non-exercisable common share options outstanding was 15,467,647. Once vested, each outstanding common share option is exercisable for one common share.

Share Repurchases

During the first quarter of 2023, the TSX accepted a notice filed by Suncor to renew its normal course issuer bid (NCIB) to repurchase the company’s common shares through the facilities of the TSX, NYSE and/or alternative trading systems. The notice provides that, beginning February 17, 2023, and ending February 16, 2024, Suncor may purchase for cancellation up to 132,900,000 common shares, which is equal to approximately 10% of Suncor’s public float as of February 3, 2023. On February 3, 2023, Suncor had 1,330,006,760 common shares issued and outstanding.

Subsequent to the fourth quarter of 2023, the TSX accepted a notice filed by Suncor to renew its NCIB to purchase the company's common shares through the facilities of the TSX, NYSE and/or alternative trading systems. The notice provides that, beginning February 26, 2024, and ending February 25, 2025, Suncor may purchase for cancellation up to 128,700,000 common shares, which is equal to approximately 10% of Suncor's public float as of February 12, 2024. On February 12, 2024, Suncor had 1,287,461,183 common shares issued and outstanding.

Between February 17, 2023, and February 16, 2024, pursuant to Suncor’s previous NCIB, Suncor repurchased 47,106,802 common shares on the open market, representing the equivalent of 3.5% of its common shares as at February 3, 2023, for $2.019 billion, at a weighted average price of $42.87 per share.

Between February 26, 2024, and March 20, 2024, pursuant to Suncor’s current NCIB (as renewed), Suncor repurchased 2,266,200 common shares on the open market, representing the equivalent of 0.2% of its common shares as at February 12, 2024, for $107 million, at a weighted average price of $47.32 per share.

The actual number of common shares that may be repurchased under the NCIB and the timing of any such purchases will be determined by Suncor. The company believes that, depending on the trading price of its common shares and other relevant factors, repurchasing its common shares represents an attractive investment opportunity and is in the best interests of the company and its shareholders. The company does not expect that the decision to allocate cash to repurchase its common shares will affect its long-term strategy.

​ | ​ | ​ | ​ | ​ | ​ | ​
At December 31 |  | ​ |  | ​ |  | ​
($ millions, except as noted) | ​ | 2023 | ​ | 2022 | ​ | 2021
Share repurchase activities (thousands of common shares) |  | 51 982 |  | 116 908 |  | 83 959
Weighted average repurchase price per share (dollars per share) |  | 42.96 |  | 43.92 |  | 27.45
Share repurchase cost |  | 2 233 |  | 5 135 |  | 2 304

​

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Contractual Obligations, Commitments, Guarantees and Off-Balance Sheet Arrangements

In addition to the enforceable and legally binding obligations in the table below, Suncor has other obligations for goods and services that were entered into in the normal course of business, which may terminate on short notice, including commitments for the purchase of commodities for which an active, highly liquid market exists, and which are expected to be resold shortly after purchase.

The company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company’s financial condition or financial performance, including liquidity and capital resources.

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Payment due by period |
​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |
($ millions) | ​ | 2024 | ​ | 2025 | ​ | 2026 | ​ | 2027 | ​ | 2028 | ​ | Thereafter | ​ | Total |
Long-term debt(1) |  | 638 |  | 1 638 | ​ | 1 546 |  | 577 |  | 848 |  | 14 175 |  | 19 422 | ​
Decommissioning and restoration costs(2) |  | 471 |  | 437 |  | 563 |  | 602 |  | 540 |  | 20 887 |  | 23 500 | ​
Long-term contracts, pipeline capacity and energy services commitments(3) |  | 2 199 |  | 1 917 |  | 1 688 |  | 1 561 |  | 1 460 |  | 12 777 |  | 21 602 | ​
Exploration work commitments(3) |  | — |  | 53 |  | 1 |  | — |  | — |  | 475 |  | 529 | ​
Lease obligations(4) | ​ | 561 | ​ | 524 | ​ | 467 | ​ | 435 | ​ | 411 | ​ | 4 038 | ​ | 6 436 | ​
Other long-term obligations(5) |  | 26 |  | 26 |  | 26 |  | 2 |  | 63 |  | — |  | 143 | ​
Total |  | 3 895 |  | 4 595 |  | 4 291 |  | 3 177 |  | 3 322 |  | 52 352 |  | 71 632 | ​

(1) | Includes long-term debt and interest payments on long-term debt. Refer to note 21 and note 27 of Suncor’s 2023 audited Consolidated Financial Statements.

(2) | Represents the undiscounted and uninflated amount of decommissioning and restoration costs. Refer to note 24 of Suncor’s 2023 audited Consolidated Financial Statements.

(3) | Refer to note 32 of Suncor’s 2023 audited Consolidated Financial Statements.

(4) | Refer to note 21 and note 27 of Suncor’s 2023 audited Consolidated Financial Statements.

(5) | Includes Libya exploration and production sharing agreement signature bonus and merger consent. Refer to note 22 of Suncor's 2023 audited Consolidated Financial Statements.

​

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Transactions with Related Parties

Suncor enters into transactions with related parties in the normal course of business, which includes purchases of feedstock, distribution of refined products and the sale of refined products and byproducts. These transactions are with joint ventures and associated entities in the company’s R&M operations, including pipeline, refined product and petrochemical companies. For more information on these transactions and for a summary of Compensation of Key Management Personnel, refer to note 31 of the 2023 audited Consolidated Financial Statements.

Financial Instruments

The company uses derivative financial instruments, such as physical and financial contracts, to manage certain exposures to fluctuations in interest rates, commodity prices and foreign currency exchange rates as part of its overall risk management program, as well as for trading purposes. For the year ended December 31, 2023, the pre-tax earnings impact of risk management and trading activities was $25 million (2022 – pre-tax loss of $187 million).

Gains or losses related to derivatives are recorded as Other Income in the Consolidated Statements of Comprehensive Income.

​ | ​ | ​ | ​ | ​ | ​
​ |  | ​ | ​ | ​ | ​
($ millions) | ​ | 2023 | ​ | 2022 |
Fair value outstanding, beginning of year |  | (65) |  | (98) | ​
Changes in fair value recognized in earnings during the year |  | 25 | ​ | (187) | ​
Cash settlements - paid (received) during the year |  | 20 | ​ | 220 | ​
Fair value outstanding, end of year |  | (20) |  | (65) | ​

​

The fair value of derivative financial instruments is recorded on the Consolidated Balance Sheets.

​ | ​ | ​ | ​ | ​ | ​
Fair value of derivative contracts at |  | ​ |  | ​ |
December 31 ($ millions) | ​ | 2023 | ​ | 2022 |
Accounts receivable |  | 65 |  | 143 | ​
Accounts payable |  | (85) |  | (208) | ​
​ |  | (20) |  | (65) | ​

​

Risks Associated with Derivative Financial Instruments

Suncor may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to fulfil their obligations under these contracts. The company minimizes this risk by entering into agreements with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties. Suncor’s exposure is limited to those counterparties holding derivative contracts with net positive fair values at a reporting date.

Suncor’s risk management activities are subject to periodic reviews by management to determine appropriate hedging requirements based on the company’s tolerance for exposure to market volatility, as well as the need for stable cash flow to finance future growth. Commodity risk management and trading activities are governed by a separate risk management group that reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including assumptions made in the calculation of fair value, a sensitivity analysis of the effect of changes in commodity prices on our derivative financial instruments, and additional discussion of exposure to risks and mitigation activities, refer to note 27 of the company’s 2023 audited Consolidated Financial Statements.

​

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10. Material Accounting Policies and Critical Accounting Estimates

Suncor’s material accounting policies are described in note 3 of the audited Consolidated Financial Statements for the year ended December 31, 2023.

Adoption of New IFRS Standards

The standards, amendments and interpretations that are adopted up to the date of authorization of the company’s Consolidated Financial Statements, and that may have an impact on the disclosures and financial position of the company, are disclosed below.

Disclosure Initiative – Accounting Policies

In February 2021, the IASB issued Disclosure Initiative – Accounting Policies. The amendment requires companies to disclose material rather than significant accounting policies to provide more relevant, company-specific accounting policy disclosures. The company adopted the amendments prospectively on the effective date January 1, 2023, and there were impacts that have been reflected in note 3 of the Consolidated Financial Statements as a result of the initial application.

Recently Announced Accounting Pronouncements

The standards, amendments and interpretations that are issued, but not yet effective up to the date of authorization of the company’s Consolidated Financial Statements, and that may have an impact on the disclosures and financial position of the company, are disclosed below. The company intends to adopt these standards, amendments and interpretations when they become effective.

General Sustainability-related Disclosures and Climate-related Disclosures

In March 2024, the Canadian Sustainability Standards Board proposed Canadian-specific modifications to IFRS S1: General Sustainability-related Disclosures and IFRS S2: Climate-related disclosures, which were issued by the International Sustainability Standards Board (ISSB) in June 2023. The new standards add sustainability and climate disclosure requirements for annual reporting purposes. The Canadian-specific versions of IFRS S1 and S2 are expected to be available for voluntary adoption starting January 1, 2025; however, the Canadian Securities Administrators have not yet confirmed whether the new standards will be mandated for Canadian reporting issuers. The company is currently disclosing sustainability and climate-related information in its annual Report on Sustainability and Climate Report and anticipates changes resulting from these new standards on the Consolidated Financial Statements as a result of future application.

Significant and Other Accounting Estimates and Judgments

The preparation of financial statements in accordance with IFRS requires management to make estimates and judgments that affect reported assets, liabilities, revenues, expenses, gains, losses and disclosures of contingencies. These estimates and judgments are subject to change based on experience and new information.

Climate Change

Suncor supports the goals of the Paris Agreement and is committed to achieving the long-term objective of net-zero GHG emissions from its operations by 2050, including those in which it has a working interest. Addressing climate change and providing the secure, affordable and reliable energy the world needs requires investment, technological advancement, product innovation, regulatory support and collaborative partnerships, such as the Pathways Alliance. The rate of change of public policy, consumer behaviour and resulting demand for low-carbon options is not certain. Suncor is committed to reducing emissions in our base business, while expanding in complementary low-emissions businesses and working with our customers, governments and partners to realize our shared climate objectives.

Climate change and the transition to a low-emissions economy was considered in preparing the Consolidated Financial Statements, primarily in estimating commodity prices used in impairment and reserves analysis. These may have significant impacts on the currently reported amounts of the company’s assets and liabilities discussed below and on similar assets and liabilities that may be recognized in the future. As part of its ongoing business planning, Suncor estimates future costs associated with GHG emissions in its operations and in the evaluation of future projects. The company uses future climate scenarios to test and assess the resilience of its strategy. Changes in market and regulatory conditions and assumptions, as

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well as climate change, and the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels, can materially impact the estimation of net reserves, asset valuation and reclamation and timing and requirements. The timing and pace at which global energy markets transition from carbon-based sources to alternative energy is highly uncertain.

Oil and Gas Reserves

The company’s estimate of oil and gas reserves is considered in the measurement of depletion, depreciation, impairment, decommissioning and restoration obligations and business combinations. The estimation of reserves is an inherently complex process and involves professional judgment. All reserves have been evaluated at December 31, 2023, by independent qualified reserves evaluators. Oil and gas reserves estimates are based on a range of geological, technical and economic factors, including projected future rates of production, projected future commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Estimates reflect market and regulatory conditions existing at December 31, 2023, which could differ significantly from other points in time throughout the year, or future periods.

Exploration and Evaluation Costs

Certain exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The company is required to make judgments about future events and circumstances and applies estimates to assess the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop the project. The level of drilling success or changes to project economics, resource quantities, expected production techniques, production costs and required capital expenditures are important judgments when making this determination. Management uses judgment to determine when these costs are reclassified to Property, Plant and Equipment based on several factors, including the existence of reserves, appropriate approvals from regulatory bodies, joint arrangement partners and the company’s internal project approval process.

Determination of Cash Generating Units (CGUs)

A CGU is the lowest grouping of integrated assets that generates identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructure and the way in which management monitors the operations.

Asset Impairment and Reversals

Management applies judgment in assessing the existence of impairment and impairment reversal indicators based on various internal and external factors.

The recoverable amount of CGUs and individual assets is determined based on the higher of fair value less costs of disposal or value-in-use calculations. The key estimates the company applies to determine the recoverable amount normally include estimated future commodity prices, discount rates, expected production volumes, future operating and development costs, income taxes and refining margins. In determining the recoverable amount, management may also be required to make judgments regarding the likelihood of occurrence of a future event. Changes to these estimates and judgments will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value.

Decommissioning and Restoration Costs

The company recognizes liabilities for the future decommissioning and restoration of Exploration and Evaluation assets and Property, Plant and Equipment based on estimated future decommissioning and restoration costs. Management applies judgment in assessing the future regulatory requirements, the existence and extent as well as the expected method of reclamation of the company’s decommissioning and restoration obligations at the end of each reporting period. Management also uses judgment to determine whether the nature of the activities performed is related to decommissioning and restoration activities or normal operating activities.

Actual costs are uncertain, and estimates may vary as a result of changes to relevant laws and regulations related to the use of certain technologies, the emergence of new technology, operating experience, prices and closure plans. The estimated timing of future decommissioning and restoration may change due to certain factors, including reserves life. Changes to

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estimates related to future expected costs, discount rates, inflation assumptions and timing may have a material impact on the amounts presented.

Employee Future Benefits

The company provides benefits to employees, including pensions and other post-retirement benefits. The cost of defined benefit pension plans and other post-retirement benefits received by employees is estimated based on actuarial valuation methods that require professional judgment. Estimates typically used in determining these amounts include, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, the return on plan assets, mortality rates and future medical costs. Changes to these estimates may have a material impact on the amounts presented.

Income Taxes

Management evaluates tax positions, annually or when circumstances require, which involves judgment and could be subject to differing interpretations of applicable tax legislation. The company recognizes a tax provision when a payment to tax authorities is considered probable. However, the results of audits and reassessments and changes in the interpretations of standards may result in changes to those positions and, potentially, a material increase or decrease in the company’s assets, liabilities and net earnings.

11. Risk Factors

Suncor is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification and assessment of risks inherent to its assets, activities and operations. Some of these risks are common to operations in the oil and gas industry as a whole, while some are unique to Suncor. The realization of any of the following risks could have a material adverse effect on Suncor’s business, financial condition, reserves and results of operations.

Volatility of Commodity Prices

Suncor’s financial performance is closely linked to prices for crude oil, refined petroleum products and, to a lesser extent, natural gas and electricity prices. The prices for all of these commodities can be influenced by global and regional supply and demand factors, which are beyond the company’s control and can result in a high degree of price volatility.

Crude oil prices are also affected by, among other things, global economic health (particularly in emerging markets), market access constraints, regional and international supply and demand imbalances, political developments and government action, decisions by OPEC+ regarding quotas on its members, compliance or non-compliance with quotas agreed upon by OPEC+ members and other countries, and weather. These factors impact the various types of crude oil and refined products differently and can impact differentials between light and heavy grades of crude oil (including blended bitumen), and between conventional oil and SCO.

Refined petroleum product prices and refining margins are also affected by, among other things, crude oil prices, the availability of crude oil and other feedstock, levels of refined product inventories, regional refinery availability, market access, marketplace competitiveness, regulatory compliance costs and other local market factors. Natural gas prices in North America are affected by, among other things, supply and demand, inventory levels, weather and prices for alternative energy sources.

In addition, oil and natural gas producers in North America, and particularly in Canada, may receive discounted prices for their production relative to certain international prices, due in part to constraints on the ability to transport and sell such products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers. Suncor’s production from Oil Sands includes significant quantities of bitumen and SCO that may trade at a discount to light and medium crude oil. Bitumen and SCO are typically more expensive to produce and process. In addition, the market prices for these products may differ from the established market indices for light and medium grades of crude oil. As a result, the price received for bitumen and SCO may differ from the benchmark they are priced against.

Wide differentials or a prolonged period of low and/or volatile commodity prices, particularly for crude oil may lead to the impairment of assets, or to the cancellation or deferral of Suncor’s growth projects.

Commodity prices could be materially and adversely affected by the outbreak of epidemics, pandemics and other public health crises in geographic areas in which Suncor has operations, suppliers, customers or employees. A prolonged period of

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decreased demand for, and prices of, these commodities, and any applicable storage constraints, could also result in voluntary curtailment or shutting in production and a decrease in Suncor’s refined product volumes and refinery utilization rates.

Carbon Risk

Public support for climate change action and receptivity to alternative or renewable energy technologies has grown in recent years. There has also been increased activism and public opposition to fossil fuels, and oil sands in particular. Existing and future laws and regulations in support of a transition to low-carbon energy and climate change action may impose significant constraints on fossil fuel development. Concerns over climate change, fossil fuel extraction, GHG emissions, and water and land-use practices could lead governments to enact additional or more stringent laws and regulations applicable to Suncor and other companies in the energy industry in general, and in the oil sands industry in particular.

Changes to environmental regulations, including regulations relating to climate change, could impact the demand for the company’s products or could require increased capital expenditures, operating expenses, abandonment and reclamation obligations, and distribution costs. These potential added costs may not be recoverable in the marketplace and may result in some current operations or growth projects becoming less profitable or uneconomic. Such regulatory changes could require significant Suncor investment into the development of technologies or other energy products.

Suncor continues to monitor international and domestic efforts to address climate change. While GHG regulations and targets will continue to become more stringent, and while Suncor continues its efforts to reduce its GHG emissions, the absolute operational GHG emissions of the company may rise as a result of growth, mergers and acquisition activities, and changes in the operatorship of assets by Suncor or affiliates. This is particularly relevant with Suncor’s increase in emissions as a result of Suncor’s purchase of additional working interest in Fort Hills in 2023. Increases in GHG emissions may impact the profitability of the company’s projects, as Suncor will be subject to incremental levies and taxes. There is also a risk that Suncor could face litigation initiated by third parties relating to climate change, including litigation pertaining to GHG emissions, the production, sale, or promotion of fossil fuels and petroleum products, and/or disclosure.

These developments and future developments could adversely impact the demand for Suncor’s products, the ability of Suncor to maintain and grow its production and reserves, and Suncor’s reputation.

Greenhouse Gas Emissions and Targets

Among other sustainability goals, Suncor’s strategic objective is to be a net-zero GHG emissions from operations company by 2050 and the company has set ambitious near-term goals to reduce emissions across its value chain. The company’s ability to deliver GHG emissions reductions is subject to numerous risks and uncertainties, and actions taken to implement these objectives may also expose Suncor to certain additional and/or heightened financial and operational risks.

A reduction in GHG emissions relies on, among other things, Suncor’s ability to implement and improve energy efficiency at all of its facilities, future development and growth opportunities, development and deployment of new technologies, the ability to sequester and capture carbon and investment in low-carbon power, as well as a transition to low-carbon fuels. In the event that Suncor is unable to implement these strategies and technologies as planned without negatively impacting our expected operations or business plans, or in the event that such strategies or technologies do not perform as expected, Suncor may be unable to meet its GHG targets on the current timelines, or at all.

In addition, achieving the company’s GHG emissions reduction targets could require significant capital expenditures and resources, with the potential that the costs required to achieve our target and goals materially differ from our original estimates and expectations, and these differences may be material. While the intent is to improve efficiency and increase the offering of low-carbon energy, the shift in resources and focus towards emissions reduction could have a negative impact on our operating results.

Environmental Compliance

Tailings Management and Water Release

Each oil sands mine is required under the Alberta Energy Regulator’s Directive 085 – Fluid Tailings Management for Oil Sands Mining Projects to seek approval for its fluid tailings management plan. If a Suncor mine fails to meet a condition of its approved plan, the company could be subject to enforcement actions, including production curtailment, and financial consequences, such as compliance levies or being required to post additional security under the Mine Financial Security

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Program. The consequences of not meeting approval conditions are not yet fully known, as certain associated policy and regulation reviews and updates are still under development. Such updates could impact the technologies that the company plans to employ for tailings management and reclamation, which could adversely impact the company’s business plans. There could also be risks if the company’s tailings management operations fail to operate as anticipated.

Suncor uses pit lakes and supports an integrated water and tailings management approach for effective operations, successful reclamation and closure, and positive environmental outcomes. The inability to release treated mine water to the environment continues to result in an increase to both water quality concerns and water containment concerns at Suncor mine sites, which impacts current operations and reclamation and closure planning. The absence of an effective regulatory framework in this area could significantly impact operations and the success and timing of closure and reclamation plans.

Alberta’s Land-Use Framework

The implementation of, and compliance with, the terms of Alberta’s Land-Use Framework through the Lower Athabasca Regional Plan (LARP) may adversely impact Suncor’s current properties and projects in northern Alberta due to, among other things, environmental limits and thresholds. The impact of the LARP on Suncor’s operations may be outside of the control of the company, as Suncor’s operations could be impacted as a result of restrictions imposed due to the cumulative impact of development by the other operators in the area and not solely in relation to Suncor’s direct impact.

Water Management Regulations

Suncor currently relies on water obtained under licences and permits from government and regulators in its operating areas. Water licences and permits contain conditions to be met in order to maintain compliance with the licence. There can be no assurance that the licences to withdraw and use water will not be rescinded or restricted, or that additional conditions will not be added. It is also possible that regional water management approaches may require water-sharing agreements between stakeholders. In addition, any changes or expansions of the company’s projects may rely on securing licences and permits for additional water withdrawal and use, and there can be no assurance that these licences will be granted in a timely manner or that they will be granted on terms favourable to Suncor. There is also a risk that future laws or changes to existing laws or regulations relating to water access or water management could cause capital expenditures and operating expenses relating to water licence compliance to increase.

Biodiversity

Species at risk exist in the areas where Suncor conducts its operations. For example, existing, planned and potential future projects in Alberta are located within the range of woodland caribou, which have been identified as “threatened” under the Species at Risk Act (Canada). In response to the Government of Canada’s Recovery Strategy for the Woodland Caribou, provincial caribou range plans are being developed through sub-regional planning. The development and implementation of sub-regional plans may have an impact on the pace and amount of development in these areas and could potentially increase costs due to restoration or offsetting requirements.

Pursuant to the Alberta Wetland Policy, future development in wetland areas may be obligated to avoid wetlands or mitigate the development’s effects on wetlands. Certain Suncor operations and growth projects where wetlands are regionally abundant will be affected by aspects of the policy where avoidance is not possible and wetland reclamation or replacement may be required. Wetland replacement costs are based on wetland value and may be especially high for future oil sands projects and expansions due to the limited opportunity to avoid or minimize impacts to wetlands.

Air and Water Quality Management

A number of Canadian federal and provincial, and U.S. federal and state, air and water quality regulations and frameworks are in place currently and being developed, changed and/or implemented, which could have an impact on the company’s existing operations and planned projects, such as requiring the company to invest additional capital or incur additional operating and compliance expenses, including, among other things, potentially requiring the company to retrofit equipment to meet new requirements and increase monitoring and mitigation plans. The full impact of these regulations and frameworks is not yet known.

Major Operational Incidents (Safety, Environmental and Reliability)

Each of Suncor’s primary operating businesses carries economic risk associated with operating reliably or enduring a protracted operational outage. The breadth and level of integration of Suncor’s operations adds complexity.

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The company’s businesses also carry the risks associated with poor or substandard environmental and safety performance, which is closely scrutinized by governments, the public and the media, and could result in a suspension of or inability to obtain regulatory approvals and permits, or, in the case of a major environmental or safety incident, delays in resuming normal operations, fines, civil suits or criminal charges against the company.

In general, Suncor’s operations are subject to operational hazards and risks such as, among others, fires (including forest fires), explosions, blow-outs, power outages, prolonged periods of extreme cold or extreme heat, severe winter climate conditions, flooding, droughts and other extreme weather conditions, railcar incidents or derailments, the migration of harmful substances such as, among others, oil spills, gaseous leaks or a release of deleterious substances, loss of tailings dam integrity, pollution and other environmental risks, and accidents, any of which can interrupt operations or cause personal injury or death, or damage to property, equipment (including information technology and related data and controls systems), and the environment.

The reliable operation of production and processing facilities at planned levels and Suncor’s ability to produce higher-value products can also be impacted by, among other things, failure to follow the company’s policies, standards and operating procedures or operate within established operating parameters, equipment failure through inadequate maintenance, unanticipated erosion or corrosion of facilities, manufacturing and engineering flaws, and labour shortage or interruption. The company is also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software, network or cyberattacks.

In addition to the foregoing factors that affect Suncor’s business generally, each business unit is susceptible to additional risks due to the nature of its business, including, among others, the following:

● | Suncor’s Oil Sands business is susceptible to loss of production, slowdowns, shutdowns or restrictions on its ability to produce higher-value products, due to the failure of any one or more interdependent component systems, and other risks inherent to oil sands operations;

● | For Suncor’s E&P businesses, there are risks and uncertainties associated with drilling for oil and natural gas, the operation and development of such properties and wells (including encountering unexpected formations, pressures or the presence of hydrogen sulphide), premature declines of reservoirs, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids and other accidents;

● | Suncor’s E&P offshore operations occur in areas subject to hurricanes and other extreme weather conditions, such as winter storms, pack ice, icebergs and fog. The occurrence of any of these events could result in production shut-ins, the suspension of drilling operations and damage to or destruction of the equipment involved. Harsh weather conditions, particularly in the winter season, may also impact the successful execution of maintenance and startup of operations. Suncor’s E&P offshore operations could be indirectly affected by catastrophic events occurring at other third-party offshore operations, which could give rise to liability, damage to the company’s equipment, harm to individuals, force a shutdown of facilities or operations, or result in a shortage of appropriate equipment or specialists required to perform planned operations; and

● | Suncor’s R&M operations are subject to all of the risks normally inherent in the operation of refineries, terminals, pipelines and other distribution facilities and service stations, including, among others, loss of production, slowdowns or shutdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock, or other incidents.

Suncor is also subject to risks relating to the health and safety of its people, and the potential for a slowdown or temporary suspension of its operations in locations impacted by an outbreak of an epidemic, pandemic or other public health crisis. This could negatively impact Suncor’s production or refined product volumes and refinery utilization rates for a sustained period of time.

Government/Regulatory Policy

Suncor’s businesses operate under federal, provincial, territorial, state and municipal laws in numerous countries. The company is subject to regulation and intervention by governments in oil and gas industry matters, such as, among others, land tenure; royalties; taxes (including income taxes); government fees; production rates; environmental protection; water; wildlife; fish; air quality; safety performance; the reduction of GHG and other emissions; the export of crude oil, natural gas and other products; cybersecurity; interactions with foreign governments; the awarding or acquisition of exploration and production rights, oil sands leases or other interests; the imposition of specific drilling obligations; control over the development, reclamation and abandonment of fields and mine sites; mine financial security requirements; approval of

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logistics infrastructure; and possibly expropriation or cancellation of contract rights. As part of ongoing operations, the company is also required to comply with a significant number of environmental, health and safety regulations under a variety of Canadian, U.S. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. Failure to comply with applicable laws and regulations may result in, among other things, the imposition of fines and penalties, production constraints, a compulsory shutdown of facilities or suspension of operations (temporarily or permanently), reputational damage, delays, increased costs, denial of operation and growth permit applications, censure, liability for cleanup costs and damages, and the loss of important licenses and permits.

Before proceeding with certain projects, including changes to existing operations, Suncor must obtain permits, regulatory approvals, and licences to operate certain assets. These processes can involve, among other things, Indigenous and stakeholder consultation, government intervention, environmental impact assessments and public hearings and may be subject to conditions, including security deposit obligations and other commitments. In some cases, abandonment and reclamation obligations may remain with the company even after disposition of an asset to a third party. Compliance can be affected by the loss of skilled staff, inadequate internal processes and compliance auditing.

Failure to obtain, comply with, satisfy the conditions of or maintain regulatory permits, licences and approvals, or failure to obtain them on a timely basis or on satisfactory terms, could result in prosecution, fines and penalties, delays, abandonment or restructuring of projects, impacts to production, reputational damage and increased costs, denial of operating and growth permit applications and public censure. Suncor’s businesses can also be indirectly impacted by a third-party’s inability to obtain regulatory approval for a shared infrastructure project or a third-party infrastructure project on which a portion of Suncor’s business depends.

Changes in government policy, regulation or other laws, or the interpretation thereof, or the revocation of existing approvals or permits by the government or opposition to Suncor’s projects or third-party pipeline and infrastructure projects that delay or prevent necessary permits or regulatory approvals, or that make current operations or growth projects less profitable or uneconomic could materially impact Suncor’s operations, existing and planned projects.

Digital and Cybersecurity

The efficient operation of Suncor’s business is dependent on computer hardware, software and a large and complex information framework, including the systems of cloud providers and third parties with which Suncor conducts business. Digital transformation continues to increase the number of, and complexity of, such systems. In the ordinary course of Suncor’s business, Suncor collects and stores sensitive data, including intellectual property, proprietary business information and personal information of the company’s employees and retail customers. Suncor relies on industry-accepted security measures, controls and technology to protect Suncor’s information systems and securely maintain confidential and proprietary information stored on the company’s information systems, and has adopted a continuous process to identify, assess and manage threats to the company’s information systems.

As a result of the critical nature of the energy supply chain and Suncor’s use of information systems and other digital technologies to control its assets, Suncor faces a heightened risk of cyber-attacks. While Suncor has an information and cybersecurity program in place, the measures, controls and technology on which the company relies may not be adequate due to the increasing volume, sophistication and rapidly evolving nature of cyber threats. Suncor’s information technology and infrastructure, including process control systems, has and will likely continue to face attacks by malicious persons or entities motivated by, among other things, geopolitical, financial or activist reasons, or may be breached due to employee error or malfeasance, or otherwise vulnerable due to other disruptions. Although the company maintains a risk management program, which includes an insurance component that may provide coverage for the operational impacts from an attack to, or breach of, Suncor’s information technology and infrastructure, including process control systems, the company does not maintain stand-alone cyber insurance. Furthermore, not all cyber risks are insurable. As a result, Suncor’s existing insurance may not provide adequate coverage for losses stemming from a cyberattack to, or breach of, its information technology and infrastructure.

Any such attack or breach could compromise Suncor’s networks, and the information Suncor stores could be accessed, publicly disclosed, lost, stolen or compromised. Any such attack, breach, access, disclosure or loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruptions to Suncor’s operations, decreased performance and production, increased costs, damage to Suncor’s reputation, physical harm to people or the environment or other negative consequences to Suncor or third parties.

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Market Access

The markets for bitumen blends and heavy crude oil are limited compared to those for light crude oil, making them more susceptible to supply and demand changes and imbalances (whether as a result of the availability, proximity and capacity of pipeline facilities, railcars or otherwise). Heavy crude oil generally receives lower market prices than light crude oil, due principally to the lower quality and value of the refined product yield and the higher cost to transport the more viscous product on pipelines, and this price differential can be amplified due to supply and demand imbalances.

Market access for Suncor’s oil sands production may be constrained by insufficient pipeline takeaway capacity. In order to secure future market access, financial commitments could be made for projects that do not proceed. There is a risk that constrained market access for oil sands production, growing inland production and refinery outages could create widening price differentials that could impact the profitability of product sales. Market access for refined products may also be constrained by insufficient takeaway capacity, which could create a supply/demand imbalance.

Competition

The global petroleum industry is highly competitive in many aspects, including the exploration for and the development of new sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and marketing of refined petroleum products. Suncor competes in virtually every aspect of its business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. The increasing volatility of the political and social landscape adds complexity.

For Suncor’s Oil Sands and E&P businesses, it is difficult to assess the number, level of production and ultimate timing of all potential new projects or when existing production levels of competitors may increase. Although increased regulatory requirements have slowed certain larger projects in the short term, an increase in the level of activity may have an impact on regional infrastructure, including pipelines, and could place stress on the availability and cost of all resources required to build and run new and existing oil sands operations.

For Suncor’s R&M business, management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue.

There is a risk that increased competition could cause costs to increase, put further strain on existing infrastructure and cause margins for refined and unrefined products to be volatile, and impact demand for Suncor’s products.

Portfolio Development and Execution

There are certain risks associated with the development and execution of Suncor’s complex and integrated portfolio of projects and the commissioning and integration of new facilities within its existing asset base. This includes development, engineering, construction, commissioning and startup.

Portfolio development and execution can also be impacted by, among other things, the effect of changing government regulations; the company’s ability to obtain the necessary environmental and other regulatory approvals; the complexity and diversity of Suncor’s portfolio; the ability to negotiate with joint venture partners; the accuracy of project cost and schedule estimates; the availability and cost of materials, equipment, qualified personnel and logistics infrastructure; weather; unanticipated technical challenges; or general business conditions.

Technology Risk

There are risks associated with sustainability, growth and capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations, including that the results of the application of new technologies may differ from simulated, test or pilot environments, or that third-party intellectual property protections may impede the development and implementation of new technology. The success of projects incorporating new technologies cannot be assured and advantages accrue to companies that can develop and adopt emerging technologies in advance of competitors. The inability to develop, implement and monitor new technologies may impact the company’s ability to develop its new or existing operations in a profitable manner or comply with regulatory requirements.

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Cumulative Impact and Pace of Change

The energy industry is evolving at a rapid pace and change is necessary to meet business objectives. These business objectives compete for resources and may negatively impact the company should there be inadequate consideration of the cumulative impacts of prior and parallel initiatives on people, processes and systems. There is a risk that measures undertaken to achieve these objectives may exceed Suncor’s capacity to adopt and implement change.

Skills, Resource Shortage and Reliance on Key Personnel

The successful operation of Suncor’s businesses will depend upon the availability of, and competition for skilled labour and materials supply. There is a risk that the company may have difficulty sourcing and retaining the skilled labour in certain talent segments for current and future operations. The availability of competent and skilled contractors for current and future operations is also a risk depending on market conditions and continued cost reduction initiatives. Suncor’s ability to operate safely and effectively and complete all projects on time and on budget has the potential to be significantly impacted by these risks and this impact could be material. The company’s success also depends in large measure on certain key personnel. The contributions of the existing management team to the immediate and near-term operations of the company are likely to continue to be of central importance for the foreseeable future.

Labour Relations

Hourly employees at Suncor’s oil sands facilities (excluding MacKay River and Fort Hills), all of the company’s refineries and the majority of the company’s terminal and distribution operations and certain of the company’s E&P operations are represented by labour unions or employee associations. Any work interruptions involving the company’s employees, contract trades utilized in the company’s projects or operations, or any jointly owned facilities operated by another entity present a significant risk to the company.

Joint Arrangement Risk

Suncor has entered into joint arrangements and other contractual arrangements with third parties, including arrangements where other entities operate assets in which Suncor has ownership or other interests and arrangements where Suncor operates assets in which other entities have ownership or other interests. The success and timing of activities relating to assets and projects operated by others, or developed jointly with others, depend upon a number of factors that are outside of Suncor’s control, including, among others, the timing and amount of capital expenditures, operational and maintenance expenditures; misalignment of partner interests, the operator’s expertise, financial resources and risk management practices; the approval of other participants; and the selection of technology.

Financial Risks

Access to Capital

Suncor expects that future capital expenditures will be financed out of cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, accessing capital markets. This ability is dependent on, among other factors, commodity prices, the overall state of the capital markets, and financial institutions and investor appetite for investments in the energy industry generally, and the company’s securities in particular. The company’s ability to access capital may also be adversely affected in the event that financial institutions, investors, rating agencies and/or lenders adopt more restrictive decarbonization policies. To the extent that external sources of capital become limited or unavailable or available on unfavourable terms, the ability to make capital investments and maintain existing properties may be constrained.

If the company finances capital expenditures in whole or in part with debt, that may increase its debt levels above industry standards for oil and gas companies of similar size. Depending on future development and growth plans, additional debt financing may be required that may not be available or, if available, may not be available on favourable terms. Neither the Articles of Suncor nor its bylaws limit the amount of indebtedness that may be incurred; however, Suncor is subject to covenants in its existing credit facilities and seeks to avoid an unfavourable cost of debt. The level of the company’s indebtedness, and the level of indebtedness relative to the company’s ability to generate cash flow, from time to time, could impair its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively affect its credit ratings.

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Suncor is required to comply with financial and operating covenants under existing credit facilities and debt securities. Covenants are reviewed based on actual and forecast results and the company has the ability to make changes to its development plans, capital structure and/or dividend policy to comply with covenants under the credit facilities. If Suncor does not comply with the applicable covenants under its credit facilities and debt securities, there is a risk that repayment could be accelerated and/or the company’s access to capital could be restricted or only be available on unfavourable terms.

Rating agencies regularly evaluate the company, including its subsidiaries. Their ratings of Suncor’s long-term and short-term debt are based on a number of factors, including the company’s financial strength, as well as factors not entirely within its control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. Credit ratings may be important to customers or counterparties when Suncor competes in certain markets and when it seeks to engage in certain transactions, including some commodity sales or purchase transactions or those involving over-the-counter derivatives. There is a risk that one or more of Suncor’s credit ratings could be downgraded, which could potentially limit its access to private and public credit markets and increase the company’s cost of borrowing.

Inflation

The company purchases materials and commodities for use in its business and uses contractors to supplement its workforce in many areas of the organization. Due to the lingering impacts of the COVID-19 pandemic and the limited availability of labour, many supply chains have been stretched, resulting in an increase in inflation. While many central banks have increased interest rates in an attempt to reduce inflation, there is no certainty that attempts to control inflation will be successful, or if they are successful, the pace at which inflation may subside.

Even a short period of higher-than-average inflation can lead to structural cost increases in Suncor’s business, which may impact its business plans going forward. Furthermore, governmental actions, such as the imposition of higher interest rates or wage or price controls may also negatively impact the company’s costs and magnify the impacts of other risks identified in this Risk Factors section of the MD&A, including those set out below under Financial Risks – Interest Rate Risks.

Energy Trading and Risk Management Activities and the Exposure to Counterparties

The nature of Suncor’s energy trading and risk management activities, which may make use of derivative financial instruments to manage its exposure to commodity price and other market risks, creates exposure to financial risks, which include, but are not limited to, unfavourable movements in commodity prices, interest rates or foreign exchange that could result in a financial or opportunity loss to the company; a lack of counterparties, due to market conditions or other circumstances that could leave the company unable to liquidate or offset a position, or unable to do so at or near the previous market price; and counterparty default risk.

Exchange Rate Fluctuations

The majority of Suncor’s revenues from the sale of oil and natural gas commodities are based on prices that are determined by, or referenced to, U.S. dollar benchmark prices, while the majority of Suncor’s expenditures are realized in Canadian dollars. Suncor also has assets and liabilities, including approximately 60% of the company’s debt, that are denominated in U.S. dollars and translated to Suncor’s reporting currency (Canadian dollars) at each balance sheet date. Suncor’s financial results, therefore, can be affected significantly by the exchange rates between the Canadian dollar and the U.S. dollar. These exchange rates may vary substantially and may give rise to favourable or unfavourable foreign currency exposure. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of commodities. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease revenues received from the sale of commodities. A decrease in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.

Interest Rate Risk

The company is exposed to fluctuations in short-term Canadian and U.S. interest rates as Suncor maintains a portion of its debt capacity in revolving and floating rate credit facilities and commercial paper, and invests surplus cash in short-term debt instruments and money market instruments, which are off-setting exposures to some degree. Throughout 2023, benchmark interest rates rose in both Canada and the United States. Suncor may also be exposed to higher interest rates when debt instruments are maturing and require refinancing, or when new debt capital needs to be raised. The company is also exposed to changes in interest rates if derivative instruments are used to manage the debt portfolio.

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Royalties and Taxes

Suncor is subject to royalties and taxes imposed by governments in numerous jurisdictions. Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, sales volumes, and capital and operating costs, by changes to existing legislation or production sharing contracts; and by results of regulatory audits of prior year filings and other such events. The final determination of these events may have a material impact on the company’s royalties expense. A failure to fully realize anticipated tax-benefits, including the expected tax benefit relating to the acquisition of TotalEnergies Canada, or an increase in Suncor’s royalties expense, income taxes, property taxes, carbon taxes, levies, tariffs, duties, quotas, border taxes, other taxes and government-imposed compliance costs may increase our cost of tax compliance.

Dividends and Share Repurchases

Suncor’s payment of future dividends on its common shares and future share repurchases by Suncor of its common shares will be dependent on, among other things, legislative and stock exchange requirements, the prevailing business environment, the company’s financial condition, results of operations, cash flow, the need for funds to finance ongoing operations and growth projects, debt covenants and other business considerations as the company’s Board considers relevant. There can be no assurance that Suncor will continue to pay dividends or repurchase shares in the future.

E&P Reserves Replacement

Suncor’s future offshore production, and therefore its cash flows and results of operations from E&P, are highly dependent upon success in exploiting its current reserves base and acquiring or discovering additional reserves. Without additions to its E&P reserves through exploration, acquisition or development activities, Suncor’s production from its offshore assets will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent Suncor’s cash flows is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, Suncor’s ability to make the necessary capital investments to maintain and expand its reserves will be impaired. In addition, Suncor may be unable to develop or acquire additional reserves to replace its crude oil production at acceptable costs.

Uncertainties Affecting Reserves Estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the company’s control. Suncor’s actual production, revenues, royalties, taxes, and development and operating expenditures with respect to the company’s reserves will vary from its estimates, and such variances could be material.

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external influences. Revisions are often required as a result of newly acquired technical data, technology improvements or changes in performance, pricing, economic conditions, market availability or regulatory requirements. Additional technical information regarding geology, hydrogeology, reservoir properties and reservoir fluid properties is obtained through seismic programs, drilling programs, updated reservoir performance studies and analysis and production history, and may result in revisions to reserves. Pricing, market availability and economic conditions affect the profitability of reserves development. Royalty regimes and environmental regulations and other regulatory changes cannot be predicted but may have positive or negative effects on reserves. Future technology improvements would be expected to have a favourable impact on the economics of reserves development and exploitation, and therefore may result in an increase to reserves. Political unrest, such as is occurring in Syria and Libya, has resulted in volumes that would otherwise be classified as reserves being classified as contingent resources.

There are numerous uncertainties inherent in estimating the quantities and quality of these reserves, including many factors beyond the company’s control. In general, estimates of reserves and the future net cash flows from these reserves are based upon a number of factors and assumptions – such as production forecasts, regulations, pricing, the timing and amount of capital expenditures, future royalties, future operating costs, yield rates for upgraded production of SCO from bitumen, and future abandonment and reclamation costs – all of which may vary considerably from actual results. The accuracy of any reserves estimate is a matter of interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. For these reasons, estimates of reserves and categorization of such reserves based on the certainty of recovery, prepared by different engineers or by the same engineers at different times, may vary.

Reserves estimates are based upon geological assessment, including drilling and laboratory tests. Mining reserves estimates also consider production capacity and upgrading yields, mine plans, operating life and regulatory constraints. In Situ reserves estimates are also based upon the testing of core samples and seismic operations and demonstrated commercial success of

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in situ processes. Suncor’s actual production, revenues, royalties, taxes, and development and operating expenditures with respect to the company’s reserves will vary from such estimates, and such variances could be material. Production performance subsequent to the date of the estimate may justify future revision, either upward or downward, if material.

Reserves evaluations are based in part on the assumed success of activities the company intends to undertake in future years. Estimated reserves and associated cash flows may be increased or reduced to the extent that such activities do or do not achieve the level of success assumed in the reserves evaluations.

Third-Party Service Providers

Suncor’s businesses are reliant on the operational integrity of a large number of third-party service providers, including input and output commodity transport (pipelines, rail, trucking, marine) and utilities associated with various Suncor and jointly owned facilities. A disruption in service or limited availability by one of these third parties can have a dramatic impact on Suncor’s operations and growth plans. Pipeline constraints that affect takeaway capacity or supply of inputs, such as hydrogen and power, could impact the company’s ability to produce at capacity levels. Disruptions in pipeline service could adversely affect commodity prices, Suncor’s price realizations, refining operations and sales volumes, or limit the company’s ability to produce and deliver production. These interruptions may be caused by the inability of the pipeline to operate or by the oversupply of feedstock into the system that exceeds pipeline capacity. Short-term operational constraints on pipeline systems arising from pipeline interruption and/or increased supply of crude oil have occurred in the past and could occur in the future. There is a risk that third-party outages could impact Suncor’s production or price realizations.

Foreign Operations

The company has operations in countries with different political, economic and social systems. As a result, the company’s operations and related assets are subject to a number of risks and other uncertainties arising from foreign government sovereignty over the company’s international operations, which may include, among other things, currency restrictions and restrictions on repatriation of funds; loss of revenue, property and equipment as a result of expropriation, nationalization, terrorism, war, insurrection, and geopolitical and other political risks; increases in taxes and government royalties; compliance with existing and emerging anti-corruption laws, including the Corruption of Foreign Public Officials Act (Canada) and the Foreign Corrupt Practices Act (United States); renegotiation of contracts with government entities and quasi-government agencies; changes in laws and policies governing operations of foreign-based companies; and economic and legal sanctions (such as restrictions against countries experiencing political violence, or countries that other governments may deem to sponsor terrorism).

If a dispute arises in the company’s foreign operations, the company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S. In addition, as a result of activities in these areas and a continuing evolution of an international framework for corporate responsibility and accountability for international crimes, there is a risk the company could be exposed to potential claims for alleged breaches of international or local law.

The impact that future potential terrorist attacks, regional hostilities or political violence, such as that experienced in Libya and Syria, may have on the oil and gas industry, and on Suncor’s operations in particular, is not known at this time. Suncor may be required to incur significant costs in the future to safeguard its assets against terrorist activities or to remediate potential damage to its facilities. There can be no assurance that Suncor will be successful in protecting itself against these risks and the related safety and financial consequences.

Despite Suncor’s training and policies around bribery and other forms of corruption, there is a risk that Suncor, or some of its employees or contractors, could be charged with bribery or corruption. Any of these violations could result in onerous penalties. Even allegations of such behaviour could impair Suncor’s ability to work with governments or non-government organizations and could result in the formal exclusion of Suncor from a country or area, sanctions, fines, project cancellations or delays, the inability to raise or borrow capital, reputational impacts and increased investor concern.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact Suncor’s personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or activist incident targeted at a facility or office owned or operated by Suncor could result in the interruption or cessation of key elements of Suncor's operations and may result in property damage.

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Land Claims and Indigenous Consultation

Indigenous Peoples have claimed Indigenous title and rights to portions of Western Canada. In addition, Indigenous Peoples have filed claims against industry participants relating in part to land claims, which may affect the company’s business.

Consulting requirements with Indigenous Peoples in respect of oil and gas projects and related infrastructure have increased in recent years, and the Canadian federal government and the provincial government in Alberta have committed to renew their relationships with the Indigenous Peoples of Canada. In particular, on June 21, 2021, Canada’s United Nations Declaration on the Rights of Indigenous Peoples Act (the UNDRIP Act) received Royal Assent and came into force. It is unknown how the UNDRIP Act will ultimately be implemented and interpreted as a part of Canadian law, and it therefore also remains unclear what its corresponding impact will be on the Crown’s duty to consult with and accommodate Indigenous Peoples.

At this point Suncor is unable to assess the effect, if any, that any such land claims, consultation requirements with Indigenous Peoples or the implementation of the UNDRIP Act may have on Suncor’s business.

Litigation Risk

There is a risk that Suncor or entities in which it has an interest may be subject to litigation and claims under such litigation may be material. Various types of claims may be raised in these proceedings, including, but not limited to, environmental damage, climate change and the impacts thereof, breach of contract, common law duties, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement, disclosure, employment matters and in relation to an attack, breach or unauthorized access to Suncor’s information technology and infrastructure. Litigation is subject to uncertainty, and it is possible that there could be material adverse developments in pending or future cases. Unfavourable outcomes or settlements of litigation could encourage the commencement of additional litigation. Suncor may also be subject to adverse publicity and reputational impacts associated with such matters, regardless of whether Suncor is ultimately found liable. There is a risk that the outcome of such litigation may be materially adverse to the company and/or the company may be required to incur significant expenses or devote significant resources in defence against such litigation, the success of which cannot be guaranteed.

Control Environment

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have an impact on how Suncor’s business, financial condition and results of operations are reported.

Insurance Coverage

Suncor maintains insurance coverage as part of its risk management program. However, such insurance may not provide comprehensive coverage in all circumstances, nor are all such risks insurable. The company self-insures some risks, and the company’s insurance coverage does not cover all the costs arising out of the allocation of liabilities and risk of loss arising from Suncor operations.

In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Significantly increased costs could lead the company to decide to reduce, or possibly eliminate, coverage. In addition, insurance is purchased from a number of third-party insurers, often in layered insurance arrangements, some of whom may discontinue providing insurance coverage for their own policy or strategic reasons. Should any of these insurers refuse to continue to provide insurance coverage, the company’s overall risk exposure could be increased.

12. Other Items

Control Environment

Based on their evaluation as of December 31, 2023, Suncor’s Chief Executive Officer and Chief Financial Officer concluded that the company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded,

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processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In April 2022, the company implemented a new enterprise resource planning system across the entire organization; accordingly, the company has modified and added a number of internal controls, including verifications, and testing to ensure data accuracy. Additionally, the company confirmed that it had experienced a cybersecurity incident on June 25, 2023, which also impacted the early part of the third quarter of 2023. The incident resulted in a breach of customer data from the Petro-Points program and impacted certain transactional systems for a short period following the incident; however, the event did not have a material impact on the company’s 2023 financial results. Suncor has taken actions to monitor and maintain appropriate internal controls during the period following the cybersecurity incident and, accordingly, has implemented interim, or modified certain existing, internal controls. There were no other changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the period ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting. Management will continue to periodically evaluate the company’s disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

The effectiveness of our internal control over financial reporting as at December 31, 2023, was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2023.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Corporate Guidance

There have been no changes to the corporate guidance ranges previously issued on December 5, 2023. For further details and advisories regarding Suncor’s 2024 corporate guidance, see www.suncor.com/guidance.

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13. Advisories

Non-GAAP and Other Financial Measures

Certain financial measures in this MD&A – namely adjusted operating earnings (loss), adjusted funds from (used in) operations, measures contained in ROCE and ROCE excluding impairments and impairment reversals, price realizations, free funds flow, Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining and marketing margin, refining operating expense, net debt, total debt, LIFO inventory valuation methodology and related per share or per barrel amounts or metrics that contain such measures – are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze business performance, leverage and liquidity, and it may be useful to investors on the same basis. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP financial measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Except as otherwise indicated, these non-GAAP financial measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

(a) | Adjusted Operating Earnings (Loss)

Adjusted operating earnings (loss) is a non-GAAP financial measure that adjusts net earnings (loss) for significant items that are not indicative of operating performance. Management uses adjusted operating earnings (loss) to evaluate operating performance because management believes it provides better comparability between periods. For the years ended December 31, 2023, December 31, 2022, and December 31, 2021, consolidated adjusted operating earnings (loss) are reconciled to net earnings (loss) in the Financial Information section of this MD&A and adjusted operating earnings (loss) for each segment are reconciled to net earnings (loss) in the Segment Results and Analysis section of this MD&A. Adjusted operating earnings (loss) for the three months ended December 31, 2023, and December 31, 2022, are reconciled to net earnings (loss) below.

Beginning in the first quarter of 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change has no effect on consolidated adjusted operating earnings (loss). Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

(b) | Bridge Analyses of Adjusted Operating Earnings (Loss)

Throughout this MD&A, the company presents charts that illustrate the change in adjusted operating earnings (loss) from the comparative period through key variance factors. These factors are analyzed in the Adjusted Operating Earnings (Loss) narratives following the bridge analyses in specific sections of this MD&A. These bridge analyses are presented because management uses this presentation to evaluate performance. All reconciling items are presented on a before-tax basis and adjusted for income taxes in the Income Tax bridge factor.

● | The factor for Sales Volumes and Mix is calculated based on sales volumes and mix for the Oil Sands and E&P segments and refinery production volumes for the R&M segment.

● | The factor for Price, Margin and Other Revenue includes upstream price realizations before royalties, except for Libya, which is net of royalties, and upstream marketing and logistics. Also included are refining and marketing margins, other operating revenue, and the net impacts of sales and purchases of third-party crude, including product purchased for use as diluent in the company’s Oil Sands operations and subsequently sold as part of diluted bitumen.

● | The factor for Royalties excludes the impact of Libya, as royalties in Libya are taken into account in Price, Margin and Other Revenue as described above.

● | The factor for Inventory Valuation is comprised of changes in the FIFO inventory valuation and the realized portion of commodity risk management activities reported in the R&M segment, as well as the impact of the deferral or realization of profit or loss on crude oil sales from the Oil Sands segment to Suncor’s refineries reported in the Corporate and Eliminations segment.

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● | The factor for Operating and Transportation Expense includes project startup costs, OS&G expense and transportation expense.

● | The factor for Financing Expense and Other includes financing expenses, other income, operational foreign exchange gains and losses, and changes in gains and losses on disposal of assets that are not adjusted operating earnings (loss) adjustments.

● | The factor for DD&A and Exploration Expense includes depreciation, depletion and amortization expense, and exploration expense.

● | The factor for Income Tax includes the company’s current and deferred income tax expense on adjusted operating earnings, changes in statutory income tax rates and other income tax adjustments.

(c) | Return on Capital Employed (ROCE) and ROCE Excluding Impairments and Impairment Reversals

ROCE is a non-GAAP ratio that management uses to analyze operating performance and the efficiency of Suncor’s capital allocation process. ROCE is calculated using the non-GAAP financial measures adjusted net earnings and average capital employed. Adjusted net earnings is calculated by taking net earnings (loss) and adjusting after-tax amounts for unrealized foreign exchange on U.S. dollar denominated debt and net interest expense. Average capital employed is calculated as a twelve-month average of the capital employed balance at the beginning of the twelve-month period and the month-end capital employed balances throughout the remainder of the twelve-month period. Figures for capital employed at the beginning and end of the twelve-month period are presented to show the changes in the components of the calculation over the twelve-month period.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |  | ​ |
($ millions, except as noted) | ​ | ​ | ​ | 2023 | ​ | 2022 | ​ | 2021 |
Adjustments to net earnings |  |  |  |  |  |  |  |  | ​
Net earnings |  |  |  | 8 295 |  | 9 077 |  | 4 119 |
(Deduct) add after-tax amounts for: |  |  |  | ​ |  | ​ |  | ​ |
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt |  |  |  | (179) |  | 679 |  | (101) |
Net interest expense |  |  |  | 543 |  | 642 |  | 645 |
Adjusted net earnings(1) |  | A |  | 8 659 |  | 10 398 |  | 4 663 |
Capital employed – beginning of twelve-month period |  |  |  |  |  |  |  | ​ |
Net debt(2) |  |  |  | 13 639 |  | 16 149 |  | 19 814 |
Shareholders’ equity |  |  |  | 39 367 |  | 36 614 |  | 35 757 |
​ |  |  |  | 53 006 |  | 52 763 |  | 55 571 |
Capital employed – end of twelve-month period |  |  |  |  |  |  |  | ​ |
Net debt(2) |  |  |  | 13 678 |  | 13 639 |  | 16 149 |
Shareholders’ equity |  |  |  | 43 279 |  | 39 367 |  | 36 614 |
​ |  |  |  | 56 957 |  | 53 006 |  | 52 763 |
Average capital employed |  | B |  | 55 462 |  | 53 651 |  | 54 069 |
ROCE (%)(3) |  | A/B |  | 15.6 |  | 19.4 |  | 8.6 |

(1) | Total before-tax impact of adjustments is $530 million for the year ended December 31, 2023, $1.575 billion for the year ended December 31, 2022, and $738 million for the year ended December 31, 2021.

(2) | Net debt is a non-GAAP financial measure.

(3) | For the twelve months ended December 31, 2023, there were no impairments or impairment reversals. As a result, ROCE excluding impairments was equal to ROCE. ROCE would have been 13.6% for the twelve months ended December 31, 2023, excluding the impact of the $1.125 billion non-cash gain on acquisition of TotalEnergies Canada. ROCE would have been 22.9% for the twelve months ended December 31, 2022, excluding the impact of the impairment reversal of $715 million ($542 million after-tax) and impairment of $70 million ($47 million after-tax) in the second quarter of 2022, and the impact of the impairment of $3.397 billion ($2.586 billion after-tax) in the third quarter of 2022. ROCE would have been 8.2% for the twelve months ended December 31, 2021, excluding the impact of the impairment reversal of $221 million ($168 million after-tax) in the third quarter of 2021.

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(d) | Adjusted Funds from (Used in) Operations

Adjusted funds from (used in) operations is a non-GAAP financial measure that adjusts a GAAP measure – cash flow provided by operating activities – for changes in non-cash working capital, which management uses to analyze operating performance and liquidity. Changes to non-cash working capital can be impacted by, among other factors, the timing of offshore feedstock purchases and payments for commodity and income taxes, the timing of cash flows related to accounts receivable and accounts payable, and changes in inventory that management believe reduces comparability between periods.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Exploration and | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | Oil Sands | ​ | Production | ​ | Refining and Marketing |
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |
Earnings (loss) before income taxes(1) |  | 6 811 |  | 5 633 |  | 2 825 |  | 1 691 |  | 3 221 |  | 1 791 |  | 3 383 |  | 5 694 |  | 2 867 | ​
Adjustments for: |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depreciation, depletion, amortization and impairment |  | 4 902 |  | 7 927 |  | 4 585 |  | 483 |  | (105) |  | 324 |  | 934 |  | 844 |  | 853 | ​
Accretion |  | 460 |  | 249 |  | 240 |  | 64 |  | 60 |  | 58 |  | 8 |  | 8 |  | 6 | ​
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — | ​
Change in fair value of financial instruments and trading inventory |  | 27 |  | 18 |  | (66) |  | (3) |  | (6) |  | 3 |  | (29) |  | (50) |  | 50 | ​
Bargain purchase gain and revaluations | ​ | (1 125) | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​
(Gain) loss on disposal of assets |  | (39) |  | (7) |  | (4) |  | (600) |  | 66 |  | (227) |  | (28) |  | (11) |  | (19) | ​
Loss on extinguishment of long-term debt | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​
Share-based compensation |  | 71 |  | 139 |  | 61 |  | 12 |  | 6 |  | 5 |  | 25 |  | 50 |  | 34 | ​
Exploration | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​
Settlement of decommissioning and restoration liabilities |  | (326) |  | (264) |  | (245) |  | (29) |  | (21) |  | (1) |  | (35) |  | (23) |  | (17) | ​
Other |  | (56) |  | 136 |  | 179 |  | (6) |  | (43) |  | (2) |  | 10 |  | 49 |  | 57 | ​
Current income tax expense | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​
Adjusted funds from (used in) operations(1) |  | 10 725 |  | 13 831 |  | 7 575 |  | 1 612 |  | 3 178 |  | 1 951 |  | 4 268 |  | 6 561 |  | 3 831 | ​
Change in non-cash working capital | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Cash flow provided by operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

​

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​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Corporate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | and Eliminations | ​ | Income Taxes(1) | ​ | Total |
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |
Earnings (loss) before income taxes(1) |  | (1 296) |  | (2 232) |  | (1 913) |  | — |  | — |  | — |  | 10 589 |  | 12 316 |  | 5 570 | ​
Adjustments for: |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Depreciation, depletion, amortization and impairment |  | 116 |  | 120 |  | 88 |  | — |  | — |  | — |  | 6 435 |  | 8 786 |  | 5 850 | ​
Accretion |  | — |  | (1) |  | — |  | — |  | — |  | — |  | 532 |  | 316 |  | 304 | ​
Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt |  | (184) |  | 729 |  | (113) |  | — |  | — |  | — |  | (184) |  | 729 |  | (113) | ​
Change in fair value of financial instruments and trading inventory |  | — |  | — |  | — |  | — |  | — |  | — |  | (5) |  | (38) |  | (13) | ​
Bargain purchase gain and revaluations | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | (1 125) | ​ | — | ​ | — | ​
(Gain) loss on disposal of assets |  | (325) |  | (3) |  | (7) |  | — |  | — |  | — |  | (992) |  | 45 |  | (257) | ​
Loss on extinguishment of long-term debt | ​ | — | ​ | 32 | ​ | 80 | ​ | — | ​ | — | ​ | — | ​ | — | ​ | 32 | ​ | 80 | ​
Share-based compensation |  | — |  | 133 |  | 105 |  | — |  | — |  | — |  | 108 |  | 328 |  | 205 | ​
Exploration |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — | ​
Settlement of decommissioning and restoration liabilities |  | — |  | (6) |  | — |  | — |  | — |  | — |  | (390) |  | (314) |  | (263) | ​
Other |  | 143 |  | (12) |  | 55 |  | — |  | — |  | — |  | 91 |  | 130 |  | 289 | ​
Current income tax expense | ​ | — | ​ | — | ​ | — | ​ | (1 734) | ​ | (4 229) | ​ | (1 395) | ​ | (1 734) | ​ | (4 229) | ​ | (1 395) | ​
Adjusted funds from (used in) operations(1) |  | (1 546) |  | (1 240) |  | (1 705) |  | (1 734) |  | (4 229) |  | (1 395) |  | 13 325 |  | 18 101 |  | 10 257 | ​
Change in in non-cash working capital | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | ​ |  | ​ | ​ | (981) |  | (2 421) |  | 1 507 | ​
Cash flow provided by operating activities | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | ​ |  | ​ | ​ | 12 344 |  | 15 680 |  | 11 764 | ​

(1) | Beginning in 2022, to align with how management evaluates segment performance, the company revised its segment presentation to reflect segment results before income tax expense and present tax at a consolidated level. This presentation change had no effect on consolidated adjusted funds from operations. Comparative periods have been revised to reflect this change. See the Income Tax section of this MD&A for a discussion of income taxes.

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(e) | Free Funds Flow

Free funds flow is a non-GAAP financial measure that is calculated by taking adjusted funds from operations and subtracting capital expenditures, including capitalized interest. Free funds flow reflects cash available for increasing distributions to shareholders and reducing debt. Management uses free funds flow to measure the capacity of the company to increase returns to shareholders and to grow Suncor’s business.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | Exploration and | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | Oil Sands | ​ | Production | ​ | Refining and Marketing |
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |
Adjusted funds from (used in) operations |  | 10 725 |  | 13 831 |  | 7 575 |  | 1 612 |  | 3 178 |  | 1 951 |  | 4 268 |  | 6 561 |  | 3 831 | ​
Capital expenditures including capitalized interest(1) | ​ | (4 096) | ​ | (3 540) | ​ | (3 168) | ​ | (668) | ​ | (443) | ​ | (270) | ​ | (1 002) | ​ | (816) | ​ | (825) | ​
Free funds flow (deficit) | ​ | 6 629 | ​ | 10 291 | ​ | 4 407 | ​ | 944 | ​ | 2 735 | ​ | 1 681 | ​ | 3 266 | ​ | 5 745 | ​ | 3 006 | ​

​

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | Corporate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | and Eliminations | ​ | Income Taxes | ​ | Total |
Year ended December 31 ($ millions) |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |  | 2023 |  | 2022 |  | 2021 |
Adjusted funds from (used in) operations |  | (1 546) |  | (1 240) |  | (1 705) |  | (1 734) |  | (4 229) |  | (1 395) |  | 13 325 |  | 18 101 |  | 10 257 | ​
Capital expenditures including capitalized interest(1) | ​ | (62) | ​ | (188) | ​ | (292) | ​ | — | ​ | — | ​ | — | ​ | (5 828) | ​ | (4 987) | ​ | (4 555) | ​
Free funds flow (deficit) | ​ | (1 608) | ​ | (1 428) | ​ | (1 997) | ​ | (1 734) | ​ | (4 229) | ​ | (1 395) | ​ | 7 497 | ​ | 13 114 | ​ | 5 702 | ​

(1) | Excludes capital expenditures related to assets previously held for sale of $108 million in 2023 and $133 million in 2022.

​

(f) | Oil Sands Operations, Fort Hills and Syncrude Cash Operating Costs

Cash operating costs are calculated by adjusting Oil Sands segment OS&G expense for non-production costs and excess power capacity. Significant non-production costs include, but are not limited to, share based compensation adjustments, research costs, project startup costs and adjustments to reflect the cost of internal transfers in the receiving asset at the cost of production versus the cost of purchase. Non-production costs at Fort Hills and Syncrude also include, but are not limited to, an adjustment to reflect internally produced diesel from Oil Sands operations at the cost of production. Excess power capacity represents excess power revenue from cogeneration units that is recorded in operating revenues. Oil Sands operations excess power capacity and other also includes, but is not limited to, the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor. Oil Sands operations, Fort Hills and Syncrude production volumes are gross of internally consumed diesel and feedstock transfers between assets. Oil Sands operations, Fort Hills and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands – Cash Operating Costs section of this MD&A. Management uses cash operating costs to measure operating performance.

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(g) | Refining and Marketing Gross Margin and Refining Operating Expense

Refining and marketing gross margins and refining operating expense are non-GAAP financial measures. Refining and marketing gross margin, on a FIFO basis, is calculated by adjusting R&M segment operating revenue, other income and purchases of crude oil and products (all of which are GAAP measures) for intersegment marketing fees recorded in intersegment revenues and the impact of inventory write-downs recorded in purchases of crude oil and products. Refining and marketing gross margin, on a LIFO basis, is further adjusted for the impacts of FIFO inventory valuation recorded in purchases of crude oil and products and short-term risk management activities recorded in other income (loss). Refinery operating expense is calculated by adjusting R&M segment OS&G for i) non-refining costs pertaining to the company’s supply, marketing and ethanol businesses; and ii) non-refining costs that management believes do not relate to the production of refined products, including, but not limited to, share-based compensation and enterprise shared service allocations. Management uses refining and marketing gross margin and refining operating expense to measure operating performance on a production barrel basis.

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
Year ended December 31 |  | ​ |  | ​ |  | ​ |
($ millions, except as noted) | ​ | 2023 | ​ | 2022 | ​ | 2021 |
Refining and marketing gross margin reconciliation |  |  |  |  |  |  | ​
Operating revenues |  | 31 068 |  | 36 728 |  | 22 915 | ​
Purchases of crude oil and products | ​ | (23 867) | ​ | (27 261) | ​ | (16 807) | ​
​ | ​ | 7 201 | ​ | 9 467 | ​ | 6 108 | ​
Other income (loss) |  | 224 |  | (60) |  | (50) | ​
Non-refining and marketing margin |  | (50) |  | (20) |  | (54) | ​
Refining and marketing gross margin – FIFO |  | 7 375 |  | 9 387 |  | 6 004 | ​
Refinery production(1) (mbbls) |  | 163 895 |  | 168 149 |  | 162 862 | ​
Refining and marketing gross margin – FIFO ($/bbl) |  | 45.00 |  | 55.85 |  | 36.85 | ​
FIFO and risk management activities adjustment | ​ | 330 | ​ | (230) | ​ | (972) | ​
Refining and marketing gross margin – LIFO | ​ | 7 705 | ​ | 9 157 | ​ | 5 032 | ​
Refining and marketing gross margin – LIFO ($/bbl) | ​ | 47.00 | ​ | 54.45 | ​ | 30.90 | ​
Refining operating expense reconciliation |  | ​ | ​ | ​ | ​ | ​ | ​
Operating, selling and general expense |  | 2 558 |  | 2 427 |  | 2 019 | ​
Non-refining costs |  | (1 340) |  | (1 246) |  | (1 051) | ​
Refining operating expense |  | 1 218 |  | 1 181 |  | 968 | ​
Refinery production(1) |  | 163 895 |  | 168 149 |  | 162 862 | ​
Refining operating expense ($/bbl) |  | 7.45 |  | 7.00 |  | 5.95 | ​

(1) | Refinery production is the output of the refining process and differs from crude oil processed as a result of volumetric adjustments for non-crude feedstock, volumetric gain associated with the refining process and changes in unfinished product inventories.

(h) | Impact of FIFO Inventory Valuation on Refining and Marketing Net Earnings

GAAP requires the use of a FIFO inventory valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflects market conditions at the time when the feedstock was purchased. This lag between purchase and sale can be anywhere from several weeks to several months and is influenced by the time to receive crude after purchase, regional crude inventory levels, the completion of refining processes, transportation time to distribution channels and regional refined product inventory levels.

Suncor prepares and presents an estimate of the impact of using a FIFO inventory valuation methodology compared to a LIFO methodology, because management uses the information to analyze operating performance and compare itself against refining peers that are permitted to use LIFO inventory valuation under U.S. GAAP.

The company’s estimate is not derived from a standardized calculation and, therefore, may not be directly comparable to similar measures presented by other companies, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP or U.S. GAAP.

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(i) | Net Debt and Total Debt

Net debt and total debt are non-GAAP financial measures that management uses to analyze the financial condition of the company. Total debt includes short-term debt, current portion of long-term debt, current portion of long-term lease liabilities, long-term debt and long-term lease liabilities (all of which are GAAP measures). Net debt is equal to total debt less cash and cash equivalents (a GAAP measure).

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
At December 31 |  | ​ |  | ​ |  | ​ |
($ millions, except as noted) | ​ | 2023 | ​ | 2022 |  | 2021 |
Short-term debt |  | 494 |  | 2 807 |  | 1 284 | ​
Current portion of long-term debt |  | — |  | — |  | 231 | ​
Current portion of long-term lease liabilities | ​ | 348 |  | 317 |  | 310 | ​
Long-term debt | ​ | 11 087 |  | 9 800 |  | 13 989 | ​
Long-term lease liabilities |  | 3 478 |  | 2 695 |  | 2 540 | ​
Total debt |  | 15 407 |  | 15 619 |  | 18 354 | ​
Less: Cash and cash equivalents |  | 1 729 |  | 1 980 |  | 2 205 | ​
Net debt |  | 13 678 |  | 13 639 |  | 16 149 | ​
Shareholders’ equity |  | 43 279 |  | 39 367 |  | 36 614 | ​
Total debt plus shareholders’ equity |  | 58 686 |  | 54 986 |  | 54 968 | ​
Total debt to total debt plus shareholders’ equity (%) |  | 26.3 |  | 28.4 |  | 33.4 | ​
Net debt to net debt plus shareholders’ equity (%) |  | 24.0 |  | 25.7 |  | 30.6 | ​
Net debt to net debt plus shareholders’ equity – excluding leases (%) |  | 18.5 |  | 21.3 |  | 26.6 | ​

​

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(j) | Price Realizations

Price realizations are a non-GAAP measure used by management to measure profitability. Oil Sands price realizations are presented on a crude product basis and are derived from the Oil Sands segmented statement of net earnings (loss), after adjusting for items not directly attributable to the revenues associated with production. E&P price realizations are presented on an asset location basis and are derived from the E&P segmented statement of net earnings (loss), after adjusting for other E&P assets, such as Libya, for which price realizations are not provided.

Oil Sands Price Realizations

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the year ended | December 31, 2023 | ​ | December 31, 2022
($ millions, except as noted) | Non-Upgraded Bitumen | Upgraded – Net SCO and Diesel | Average Crude | Oil Sands Segment | ​ | Non-Upgraded Bitumen | Upgraded – Net SCO and Diesel | Average Crude | Oil Sands Segment
Operating revenues | 7 218 | 18 817 | 26 035 | 26 035 | ​ | 7 892 | 22 539 | 30 431 | 30 431
Other income (loss) | 1 519 | (50) | 1 469 | 1 469 | ​ | (80) | 27 | (53) | (53)
Purchases of crude oil and products | (1 758) | (177) | (1 935) | (1 935) | ​ | (1 673) | (377) | (2 050) | (2 050)
Gross realization adjustment(1) | (1 463) | (294) | (1 757) | ​ | ​ | (119) | (420) | (539) | ​
Gross realizations | 5 516 | 18 296 | 23 812 | ​ | ​ | 6 020 | 21 769 | 27 789 | ​
Transportation and distribution | (567) | (646) | (1 213) | (1 213) | ​ | (438) | (772) | (1 210) | (1 210)
Price realization | 4 949 | 17 650 | 22 599 | ​ | ​ | 5 582 | 20 997 | 26 579 | ​
Sales volumes (mbbls) | 72 795 | 177 601 | 250 396 | ​ | ​ | 65 960 | 176 632 | 242 592 | ​
Price realization per barrel | 67.97 | 99.40 | 90.27 | ​ | ​ | 84.63 | 118.88 | 109.57 | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the year ended | December 31, 2021 | ​ | ​
($ millions, except as noted) | Non-Upgraded Bitumen | Upgraded – Net SCO and Diesel | Average Crude | Oil Sands Segment | ​ | ​ | ​ | ​ | ​
Operating revenues | 5 468 | 14 452 | 19 920 | 19 920 | ​ | ​ | ​ | ​ | ​
Other (loss) income | (56) | 62 | 6 | 6 | ​ | ​ | ​ | ​ | ​
Purchases of crude oil and products | (1 231) | (213) | (1 444) | (1 444) | ​ | ​ | ​ | ​ | ​
Gross realization adjustment(1) | (210) | (325) | (535) | ​ | ​ | ​ | ​ | ​ | ​
Gross realizations | 3 971 | 13 976 | 17 947 | ​ | ​ | ​ | ​ | ​ | ​
Transportation and distribution | (359) | (767) | (1 126) | (1 126) | ​ | ​ | ​ | ​ | ​
Price realization | 3 612 | 13 209 | 16 821 | ​ | ​ | ​ | ​ | ​ | ​
Sales volumes (mbbls) | 67 094 | 169 983 | 237 077 | ​ | ​ | ​ | ​ | ​ | ​
Price realization per barrel | 53.80 | 77.73 | 70.96 | ​ | ​ | ​ | ​ | ​ | ​

(1) | Reflects the items not directly attributed to revenues received from the sale of proprietary crude and net non-proprietary activity at its deemed point of sale.

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E&P Price Realizations

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the year ended | December 31, 2023 | ​ | December 31, 2022
($ millions, except as noted) | E&P International | E&P Canada | Other(1)(2) | E&P Segment | ​ | E&P International | E&P Canada | Other(1)(2) | E&P Segment
Operating revenues | 306 | 1 689 | 694 | 2 689 | ​ | 1 222 | 2 464 | 645 | 4 331
Transportation and distribution | (9) | (58) | (9) | (76) | ​ | (24) | (61) | (16) | (101)
Price realization | 297 | 1 631 | 685 | ​ | ​ | 1 198 | 2 403 | 629 | ​
Sales volumes (mbbls) | 2 729 | 15 149 | ​ | ​ | ​ | 9 453 | 18 753 | ​ | ​
Price realization per barrel | 109.00 | 107.62 | ​ | ​ | ​ | 126.61 | 128.07 | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
For the year ended | December 31, 2021 | ​ | ​
($ millions, except as noted) | E&P International | E&P Canada | Other(1)(2) | E&P Segment | ​ | ​ | ​ | ​ | ​
Operating revenues | 815 | 1 684 | 479 | 2 978 | ​ | ​ | ​ | ​ | ​
Transportation and distribution | (25) | (44) | (43) | (112) | ​ | ​ | ​ | ​ | ​
Price realization | 790 | 1 640 | 436 | ​ | ​ | ​ | ​ | ​ | ​
Sales volumes (mbbls) | 9 616 | 19 386 | ​ | ​ | ​ | ​ | ​ | ​ | ​
Price realization per barrel | 82.16 | 84.70 | ​ | ​ | ​ | ​ | ​ | ​ | ​

(1) | Reflects other E&P assets, such as Libya, for which price realizations are not provided.

(2) | Production from the company’s Libya operations has been presented in the E&P section of this MD&A on an economic basis. Revenue and royalties from the company’s Libya operations are presented under the working-interest basis, which is required for presentation purposes in the company’s financial statements. In 2023, revenue included a gross-up amount of $528 million, with an offsetting amount of $282 million in royalties in the E&P segment and $246 million in income tax expense recorded at the consolidated level. In 2022, revenue included a gross-up amount of $486 million, with an offsetting amount of $266 million in royalties in the E&P segment and $220 million in income tax expense recorded at the consolidated level. In 2021, revenue included a gross-up amount of $345 million, with an offsetting amount of $241 million in royalties in the E&P segment and $104 million in income tax expense recorded at the consolidated level.

(k) | Adjusted Operating Earnings (Loss) Reconciliations – Fourth Quarter 2023 and 2022

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | ​ | ​ | ​ | ​ | Exploration and | ​ | Refining and | ​ | Corporate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
For the quarter ended December 31 | ​ | Oil Sands | ​ | Production | ​ | Marketing | ​ | and Eliminations | ​ | Income Taxes | ​ | Total |
($ millions) |  | 2023 |  | 2022 |  | 2023 |  | 2022 |  | 2023 |  | 2022 |  | 2023 |  | 2022 | ​ | 2023 |  | 2022 |  | 2023 |  | 2022 |
Net earnings (loss) |  | 2 660 |  | 1 625 |  | 133 |  | 578 |  | 598 |  | 1 517 |  | (1) |  | (182) | ​ | (570) | ​ | (797) |  | 2 820 |  | 2 741 | ​
Unrealized foreign exchange gain on U.S. dollar denominated debt |  | — |  | — |  | — |  | — |  | — |  | — |  | (199) |  | (200) | ​ | — |  | — |  | (199) |  | (200) | ​
Unrealized (gain) loss on risk management activities | ​ | (9) | ​ | 94 | ​ | — | ​ | — | ​ | — | ​ | 12 | ​ | — | ​ | — | ​ | — |  | — | ​ | (9) | ​ | 106 | ​
Gain on significant acquisition | ​ | (1 125) | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | (1 125) | ​ | — | ​
Asset impairment | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | 158 | ​ | — | ​ | — | ​ | — | ​ | 158 | ​ | — | ​
Income tax recovery on adjusted operating earnings adjustments | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | (10) |  | (215) | ​ | (10) | ​ | (215) | ​
Adjusted operating earnings (loss) |  | 1 526 |  | 1 719 |  | 133 |  | 578 |  | 598 |  | 1 529 |  | (42) |  | (382) | ​ | (580) |  | (1 012) |  | 1 635 |  | 2 432 | ​

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(l) | Adjusted Funds from (Used in) Operations Reconciliations – Fourth Quarter 2023 and 2022

​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
​ | ​ | ​ | ​ | ​ | ​ | Exploration and | ​ | Refining and | ​ | Corporate | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ |
For the quarter ended December 31 | ​ | Oil Sands | ​ | Production | ​ | Marketing | ​ | and Eliminations | ​ | Income Taxes | ​ | Total |
($ millions) |  | 2023 |  | 2022 |  | 2023 |  | 2022 |  | 2023 |  | 2022 |  | 2023 |  | 2022 | ​ | 2023 |  | 2022 |  | 2023 |  | 2022 |
Earnings (loss) before income taxes |  | 2 660 |  | 1 625 |  | 133 |  | 578 |  | 598 |  | 1 517 |  | (1) |  | (182) | ​ | — | ​ | — |  | 3 390 |  | 3 538 | ​
Adjustments for: |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ | ​ | ​ | ​ | ​ | ​ | ​ |  | ​ | ​
Depreciation, depletion, amortization and impairment |  | 1 214 |  | 1 080 |  | 99 |  | 130 |  | 256 |  | 226 |  | 29 |  | 29 | ​ | — | ​ | — |  | 1 598 |  | 1 465 | ​
Accretion |  | 116 |  | 64 |  | 15 |  | 15 |  | 2 |  | 2 |  | — |  | — | ​ | — | ​ | — |  | 133 |  | 81 | ​
Unrealized foreign exchange gain on U.S. dollar denominated debt |  | — |  | — |  | — |  | — |  | — |  | — |  | (199) |  | (200) | ​ | — | ​ | — |  | (199) |  | (200) | ​
Change in fair value of financial instruments and trading inventory |  | (65) |  | 105 |  | (1) |  | (11) |  | (30) |  | (121) |  | — |  | — | ​ | — | ​ | — |  | (96) |  | (27) | ​
Bargain purchase gain and revaluations | ​ | (1 125) | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | (1 125) | ​ | — | ​
(Gain) loss on disposal of assets |  | — |  | (5) |  | 8 |  | 1 |  | (2) |  | (1) |  | (3) |  | (3) | ​ | — | ​ | — |  | 3 |  | (8) | ​
Loss on extinguishment of long-term debt | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | 32 | ​ | — | ​ | — | ​ | — | ​ | 32 | ​
Share-based compensation |  | 30 |  | 66 |  | 4 |  | 5 |  | 10 |  | 30 |  | 24 |  | 66 | ​ | — | ​ | — |  | 68 |  | 167 | ​
Settlement of decommissioning and restoration liabilities |  | (70) |  | (61) |  | (24) |  | (2) |  | (16) |  | (11) |  | — |  | (5) | ​ | — | ​ | — |  | (110) |  | (79) | ​
Other |  | (109) |  | 55 |  | (6) |  | 3 |  | (7) |  | 21 |  | 160 |  | (10) | ​ | — | ​ | — |  | 38 |  | 69 | ​
Current income tax recovery (expense) | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | 334 | ​ | (849) | ​ | 334 | ​ | (849) | ​
Adjusted funds from (used in) operations |  | 2 651 |  | 2 929 |  | 228 |  | 719 |  | 811 |  | 1 663 |  | 10 |  | (273) | ​ | 334 | ​ | (849) |  | 4 034 |  | 4 189 | ​
Change in non-cash working capital |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ | ​ | ​ | ​ | ​ |  | 284 |  | (265) | ​
Cash flow provided by operating activities |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ | ​ | ​ | ​ | ​ |  | 4 318 |  | 3 924 | ​

​

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Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, mmcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, conversion on a 6:1 basis may be misleading as an indication of value.

Common Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

​ | ​
Measurement
​ | ​
bbl | barrel
bbls/d | barrels per day
mbbls/d | thousands of barrels per day
boe | barrels of oil equivalent
boe/d | barrels of oil equivalent per day
​ | ​
mboe | thousands of barrels of oil equivalent
mboe/d | thousands of barrels of oil equivalent per day
mcf | thousands of cubic feet of natural gas
mcfe | thousands of cubic feet of natural gas equivalent
mmcf | millions of cubic feet of natural gas
mmcf/d | millions of cubic feet of natural gas per day
mmcfe | millions of cubic feet of natural gas equivalent
mmcfe/d | millions of cubic feet of natural gas equivalent per day
m3 | cubic metres
​ | ​
MW | megawatts
MWh | megawatt hour
​
Places and Currencies
​ | ​
U.S. | United States
U.K. | United Kingdom
B.C. | British Columbia
​ | ​
$ or Cdn$ | Canadian dollars
US$ | United States dollars
£ | Pounds sterling
€ | Euros
​
Financial and Business Environment
​ | ​
DD&A | Depreciation, depletion and amortization
​ | ​
WTI | West Texas Intermediate
WCS | Western Canadian Select
SCO | Synthetic crude oil
SYN MSW | Synthetic crude oil benchmark Mixed Sweet Blend
NYMEX | New York Mercantile Exchange

​

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Forward-Looking Statements

This MD&A contains certain forward-looking statements and forward-looking information (collectively, forward-looking statements) within the meaning of applicable Canadian and U.S. securities laws and other information based on Suncor’s current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor’s experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves estimates; commodity prices and interest and foreign exchange rates; the performance of assets and equipment; capital efficiencies and cost savings; applicable laws and government policies; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour, services and infrastructure; the satisfaction by third parties of their obligations to Suncor; the development and execution of projects; and the receipt, in a timely manner, of regulatory and third-party approvals. All statements and information that address expectations or projections about the future, and statements and information about Suncor’s strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements may be identified by words like “expects”, “anticipates”, “will”, “estimates”, “plans”, “scheduled”, “intends”, “believes”, “projects”, “indicates”, “could”, “focus”, “vision”, “goal”, “outlook”, “proposed”, “target”, “objective”, “continue”, “should”, “may”, “potential”, “future”, “opportunity”, “would”, “priority” and similar expressions.

Forward-looking statements in this MD&A include references to:

● | Suncor's strategy, including its aim to deliver competitive and sustainable returns to shareholders, its plans on how to achieve this strategy, and its expectation that execution of the company’s strategy and key priorities will grow free funds flow per share and enable the delivery of industry leading shareholder returns;

● | expectations about the West White Rose Project and the SeaRose FPSO Asset Life Extension Project, including the expectation that the projects will extend the production life of White Rose, providing long-term value for the company, and the expectation that production will commence at White Rose upon completion of the SeaRose FPSO Asset Life Extension Project, and at the West White Rose Project in 2026;

● | expectations about Terra Nova, including the expectations that Terra Nova will continue to safely ramp up production in the beginning of 2024 and that the production restart at Terra Nova will provide long-term value to shareholders and many benefits to the Newfoundland and Labrador and Canadian economies;

● | statements about Suncor's strategic objective to be a net-zero GHG emissions from operations company by 2050 and its near-term GHG emissions reduction goal;

● | statements regarding the Pathways Alliance, including its aims, expectations regarding timing and the expected pathways the alliance will take to address GHG emissions, the expectation that the proposed CO2 storage hub will enable safe and permanent storage for CO2 from over 20 oil sands facilities in northern Alberta and that it expects to submit a regulatory application for the storage hub in 2024;

● | the expectation that the Varennes Carbon Recycling facility will be operational in 2026 and that LanzaJet’s Freedom Pines Fuel facility will be operational in early 2024;

● | Suncor's expectations for the coke-fired boiler replacement project, including the expectation that the cogeneration units will provide reliable steam generation required for Suncor's extraction and upgrading operations at a lower cost and with significantly lower emissions, the expectation that the project will generate lower carbon-intensive electricity that will be transmitted to Alberta’s power grid, and the expectation that the project will be in service in late 2024;

● | expectations regarding the Upgrader 1 coke drum replacement project, including that the project will be in service in late 2025 and that the project will extend the life of Upgrader 1 by 30 years and will reduce the facilities future operating and capital cost requirements;

● | the expectation that the company will have 91 autonomous haul trucks in its Oil Sands Base operations by the end of 2024;

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● | the expectation that the Mildred Lake Extension project will sustain Syncrude’s current production levels by extending the life of the North Mine using existing extraction and upgrading facilities, and that the project will commence production in late 2025;

● | the expectation that the company will continue to leverage its integrated regional asset base to generate incremental value by maximizing upgrader utilizations and by directing higher quantities of Fort Hills bitumen to upgrading at Oil Sands Base;

● | the expectation that the three-year mine improvement plan at Fort Hills will continue, accelerating a sequence of mine development, opening two sections of the North Pit and that upon completion of the three-year mine improvement plan opportunities for future value optimization will be implemented for the remaining life of mine;

● | the expectation that the company will continue efforts to decarbonize its Oil Sands business;

● | expectations for the E&P segment, including that the segment will continue to focus on ongoing development activities intended to extend the productive life of existing fields and that these development activities are planned to continue in 2024, including development drilling at Hebron and Hibernia;

● | expectations for the R&M segment, including that the company will continue to optimize the Petro-Canada™ retail business, as well as expected economic investment spending and sustaining capital in 2024;

● | expectations that the Petro-Canada™ and Canadian Tire Corporation partnership will result in the rebranding of over 200 retail fuel network sites to the Petro-Canada™ brand and an increase in the presence of Petro-Canada’s brand across the country, that the partnering of the two iconic brands’ loyalty programs will benefit millions of loyalty members, and that Suncor will become the primary fuel provider for Canadian Tire Corporation’s retail fuel network;

● | the expectation that the company will continue to invest in sustainment and enhancement of refining operations to improve efficiency and maintain safe and reliable downstream operations and industry leading profitability;

● | the expectation that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue for the company’s R&M business;

● | the expectation that while the company’s net debt levels are between $12 billion and $15 billion, it expects to allocate excess funds equally towards share repurchases and debt reductions, and that once net debt is reduced to $12 billion, it expects to allocate 75% of excess funds towards share repurchases and 25% towards debt repayment; and

● | the expectation that well pads under construction will maintain existing production levels at Firebag and MacKay River in future years as production from existing well pads declines.

The anticipated duration and impact of planned maintenance events, including:

● | planned turnaround activities at Syncrude, Oil Sands Base, Upgrader 1 and McKay River and the Montreal and Sarnia refineries; and

● | planned maintenance at Fort Hills, Upgrader 2 and Commerce City.

Also:

● | economic sensitivities;

● | Suncor’s belief that its indicative 5-2-2-1 index will continue to be an appropriate measure against Suncor’s actual results;

● | statements about Suncor's share repurchase program, including its belief that, depending on the trading price of its common shares and other relevant factors, purchasing its own shares represents an attractive investment opportunity and is in the best interests of the company and its shareholders, and Suncor's expectation that the decision to allocate cash to repurchase shares will not affect its long-term strategy;

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● | the company’s belief that it does not have any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company’s financial condition or financial performance, including liquidity and capital resources;

● | Suncor’s planned 2024 capital spending program of $6.3 billion to $6.5 billion and the belief that the company will have the capital resources to fund its planned 2024 capital spending program and to meet current and future working capital requirements through cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and accessing capital markets;

● | Suncor's expectations as to how its 2024 capital expenditures will be directed and the expected benefits therefrom;

● | the objectives of the company’s short-term investment portfolio and the expectation that the maximum weighted average term to maturity of the company’s short-term investment portfolio will not exceed six months, and all investments will be with counterparties with investment grade debt ratings;

● | Suncor's intention to adopt certain accounting standards, amendments and interpretations when they become effective; and

● | expectations with respect to changes to law and government policy.

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them.

The financial and operating performance of the company’s reportable operating segments, specifically Oil Sands, E&P and R&M, may be affected by a number of factors.

Factors that affect Suncor’s Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process the company’s proprietary production will be closed, experience equipment failure or other accidents; Suncor’s ability to operate its Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance of which may be difficult to predict during initial operations; Suncor’s dependence on pipeline capacity and other logistical constraints, which may affect the company’s ability to distribute products to market and which may cause the company to delay or cancel planned growth projects in the event of insufficient takeaway capacity; Suncor’s ability to finance Oil Sands economic investment and asset sustainment and maintenance capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; changes in operating costs, including the cost of labour, natural gas and other energy sources used in oil sands processes; and the company’s ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta’s Wood Buffalo region and the surrounding area (including housing, roads and schools).

Factors that affect Suncor’s E&P segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor’s foreign operations, including the unpredictability of operating in Libya due to ongoing political unrest; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect Suncor’s R&M segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company’s margins; market competition, including potential new market entrants; the company’s ability to reliably operate refining and marketing facilities in order to meet production or sales targets; and risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.

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Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor’s operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates (including as a result of demand and supply effects resulting from the actions of OPEC+); fluctuations in supply and demand for Suncor’s products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; risks associated with the development and execution of Suncor’s projects and the commissioning and integration of new facilities; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; the risk that projects and initiatives intended to achieve cash flow growth and/or reductions in operating costs may not achieve the expected results in the time anticipated or at all; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties, tariffs, quotas and other government-imposed compliance costs, and mandatory production curtailment orders and changes thereto; changes to laws and government policies that could impact the company’s business, including environmental (including climate change), royalty and tax laws and policies; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to the company; the unavailability of, or outages to, third-party infrastructure that could cause disruptions to production or prevent the company from being able to transport its products; the occurrence of a protracted operational outage, a major safety or environmental incident, or unexpected events such as fires (including forest fires), equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor’s information technology and infrastructure by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; security threats and terrorist or activist activities; the risk that competing business objectives may exceed Suncor’s capacity to adopt and implement change; risks and uncertainties associated with obtaining regulatory, third-party and stakeholder approvals outside of Suncor’s control for the company’s operations, projects, initiatives, and exploration and development activities and the satisfaction of any conditions to approvals; the potential for disruptions to operations and construction projects as a result of Suncor’s relationships with labour unions that represent employees at the company’s facilities; the company’s ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor’s reserves and future production estimates; Suncor’s ability to access capital markets at acceptable rates or to issue other securities at acceptable prices; maintaining an optimal debt to cash flow ratio; the success of the company’s risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset or oil and gas property, including estimates of the final consideration to be paid or received; the ability of counterparties to comply with their obligations in a timely manner; risks associated with joint arrangements in which the company has an interest; risks associated with land claims and Indigenous consultation requirements; the risk that the company may be subject to litigation; the impact of technology and risks associated with developing and implementing new technologies; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor’s forward-looking statements are discussed in further detail throughout this MD&A, including under the heading Risk Factors, and the company’s 2023 AIF and Form 40-F on file with Canadian securities commissions at www.sedarplus.ca and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

The forward-looking statements contained in this MD&A are made as of the date of this MD&A. Except as required by applicable securities laws, we assume no obligation to update publicly or otherwise revise any forward-looking statements or the foregoing risks and assumptions affecting such forward-looking statements, whether as a result of new information, future events or otherwise.

72 ANNUAL REPORT 2023 SUNCOR ENERGY INC.