SU 6-K, filed Feb 3, 2022, 0001104659-22-010988

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a - 16 or 15d - 16 of

the Securities Exchange Act of 1934

For the month of: February, 2022	Commission File Number: 1-12384

SUNCOR ENERGYINC**.**

(Name of registrant)

150 – 6th Avenue S.W.

P.O. Box 2844

Calgary, Alberta

Canada**,T2P 3E3**

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F	¨	Form 40-F	x

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SUNCOR ENERGY INC.
Date:	By:
February 2, 2022		“Shawn<br> Poirier”
		Shawn Poirier<br><br> Assistant Corporate Secretary

EXHIBIT INDEX

Exhibit	Description of Exhibit
99.1	Report to Shareholders for the fourth quarter ended December 31, 2021

tm221483-1\_nonfiling - none - 29.7657961s

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Exhibit 99.1

All financial figures are unaudited and presented in Canadian dollars unless noted otherwise. Production volumes are presented on a working-interest basis, before royalties, except for production volumes from Suncor Energy Inc.’s (Suncor or the company) Libya operations, which are presented on an economic basis. Certain financial measures in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these non-GAAP financial measures, see the Non-GAAP Financial Measures Advisory section of this document. See also the Advisories section of this document. References to Oil Sands operations exclude Suncor’s interests in Fort Hills and Syncrude.

“Suncor generated $3.1 billion, or $2.17 per common share, in adjusted funds from operations during the fourth quarter of 2021, despite operational challenges late in the quarter. These results represent the highest quarterly adjusted funds from operations in the company’s history and an 11% increase on a per common share basis compared to the last per share quarterly record,” said Mark Little, president and chief executive officer. “Our increased cash flows in 2021 enabled us to exceed our shareholder return targets for the year through increased dividends and accelerated share repurchases, while at the same time strengthening our balance sheet through accelerated debt reduction.”

•

Adjusted funds from operations(1)(2) increased to $3.144 billion ($2.17 per common share) in the fourth quarter of 2021, compared to $1.221 billion ($0.80 per common share) in the prior year quarter. Cash flow provided by operating activities, which includes changes in non-cash working capital, was $2.615 billion ($1.80 per common share) in the fourth quarter of 2021, compared to $814 million ($0.53 per common share) in the prior year quarter.

•

The company recorded adjusted operating earnings(1)(2)(3) of $1.294 billion ($0.89 per common share) in the fourth quarter of 2021, compared to an adjusted operating loss of $109 million ($0.07 per common share) in the prior year quarter. The company had net earnings of $1.553 billion ($1.07 per common share) in the fourth quarter of 2021, compared to a net loss of $168 million ($0.11 per common share) in the prior year quarter.

•

Suncor’s total upstream production was 743,300 barrels of oil equivalent per day (boe/d) in the fourth quarter of 2021, compared to 769,200 boe/d in the prior year quarter, with the decrease primarily due to decreased production from the company’s Exploration and Production (E&P) assets, including the absence of production from the Golden Eagle Area Development, as the sale of the asset was completed early in the fourth quarter of 2021. The company’s synthetic crude oil (SCO) production was 515,000 barrels per day (bbls/d) in the fourth quarter of 2021, comparable to 514,300 bbls/d in the fourth quarter of 2020, driven by combined upgrader utilization of 96%.

•

Fort Hills resumed two-train operations late in the fourth quarter of 2021. The company is on track to operate the Fort Hills asset at average utilization rates of 90% throughout 2022.

•

Buzzard Phase 2, which is expected to extend production life of the existing Buzzard field, achieved first oil in the fourth quarter of 2021. Buzzard Phase 2 is expected to reach its peak production in 2022, adding approximately 12,000 boe/d gross (approximately 3,500 boe/d net to Suncor) to existing Buzzard production.

•

Refining and Marketing (R&M) delivered $765 million in adjusted funds from operations in the fourth quarter of 2021, compared to $415 million in the prior year quarter, including a first-in, first-out (FIFO) inventory valuation gain of $106 million after-tax in the current period compared to a gain of $44 million after-tax in the prior year quarter. Refinery utilization averaged 96% and crude throughput was 447,000 bbls/d in the current quarter, compared to 95% and 438,000 bbls/d respectively in the prior year quarter. The company’s Canadian refineries continued to outperform the national refining industry average by approximately 15%.(4)

•

In 2021, Suncor executed on its net debt(1) reduction targets, reducing debt at the highest ever annual pace, resulting in a reduction of net debt by $3.7 billion to $16.1 billion, returning to 2019 net debt levels. The company continues to reduce its debt, and subsequent to the fourth quarter of 2021, completed an early redemption of its outstanding US$182 million 4.50% notes, originally scheduled to mature in the second quarter of 2022.

•

Suncor returned $3.9 billion to shareholders in 2021 through $2.3 billion in share repurchases and $1.6 billion in dividends paid, including an increased dividend in the fourth quarter of 2021, returning it to 2019 levels. Since the start of its current normal course issuer bid program (NCIB) in February 2021, the company has repurchased approximately 84 million of its common shares at an average price of $27.45 per common share, or the equivalent of 5.5% of Suncor’s public float as at January 31, 2021.

•

Subsequent to the fourth quarter of 2021, Suncor’s Board of Directors (the Board) approved a renewal of the company’s NCIB for the repurchase of approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2022, over a twelve-month period, and concurrently, the Toronto Stock Exchange (TSX) accepted a notice filed by Suncor to renew its NCIB in respect of the repurchase of such shares.

(1)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document and the Adjusted Operating Earnings (Loss) Reconciliation below for a reconciliation of net earnings (loss) to adjusted operating earnings (loss).

(2)

Beginning in the fourth quarter of 2021, the company revised the label of operating earnings (loss) and funds from (used in) operations to adjusted operating earnings (loss) and adjusted funds from (used in) operations, respectively, to better distinguish the non-GAAP financial measures from the comparable GAAP measures and better reflect the purpose of the measures. The composition of the measures remains unchanged and therefore no prior periods were restated.

(3)

Beginning in the first quarter of 2021, the company revised its calculation of adjusted operating earnings (loss), a non-GAAP financial measure, to exclude unrealized (gains) losses on derivative financial instruments that are recorded at fair value in other income (loss) to better align the earnings impact of the activity with the underlying items being risk-managed. Prior period comparatives have been restated to reflect this change.

(4)

Source: Canada Energy Regulator – https://www.cer-rec.gc.ca/en/data-analysis/energy-commodities/crude-oil-petroleum-products/statistics/weekly- crude-run-summary-data/index.html.

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(1)

Non-GAAP financial measures or contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document and the Adjusted Operating Earnings (Loss) Reconciliation below for a reconciliation of net earnings (loss) to adjusted operating earnings (loss).

(2)

Beginning in the first quarter of 2021, the company revised its calculation of adjusted operating earnings, a non-GAAP financial measure, to exclude unrealized (gains) losses on derivative financial instruments that are recorded at fair value in other income (loss) to better align the earnings impact of the activity with the underlying items being risk-managed. Prior period comparatives have been restated to reflect this change.

(3)

Includes the impacts of the COVID-19 pandemic for all periods presented.

(4)

Includes impairment charges of $1.798 billion after-tax related to the first quarter of 2020, $423 million after-tax related to the fourth quarter of 2020 and an impairment reversal of $168 million after-tax related to the third quarter of 2021.

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Financial Results

Adjusted Operating Earnings (Loss)

Suncor’s adjusted operating earnings increased to $1.294 billion ($0.89 per common share) in the fourth quarter of 2021, from an adjusted operating loss of $109 million ($0.07 per common share) in the prior year quarter. The increase in adjusted operating earnings was primarily related to higher crude oil and refined product realizations reflecting the improved business environment. Adjusted operating earnings were partially offset by an increase in royalties associated with higher crude price realizations and increased operating costs. The prior year quarter adjusted operating earnings were negatively impacted by the significant decline in transportation fuel demand, which led to lower price realizations, partially offset by lower operating costs.

Bridge Analysis of Operating (Loss) Earnings ($ millions)(1)(2)

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(1)

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

The bridge factor for Inventory Valuation is comprised of changes in the FIFO inventory valuation and the realized portion of short-term commodity risk management activities reported in the R&M segment, and changes in the intersegment elimination of profit reported in the Corporate and Eliminations segment.

Net Earnings (Loss)

Suncor’s net earnings were $1.553 billion ($1.07 per common share) in the fourth quarter of 2021, compared to a net loss of $168 million ($0.11 per common share) in the prior year quarter. In addition to the factors impacting adjusted operating earnings (loss) discussed above, net earnings for the fourth quarter of 2021 included a $25 million ($21 million after-tax) unrealized foreign exchange gain on the revaluation of U.S. dollar denominated debt recorded in financing expenses, a $227 million ($227 million after-tax) gain on the sale of the company’s interest in the Golden Eagle Area Development and a $14 million ($11 million after-tax) unrealized gain on risk management activities recorded in other income (loss). The net loss in the prior year quarter included a $559 million ($423 million after-tax) non-cash asset impairment charge against the White Rose assets, a $186 million ($142 million after-tax) transportation provision related to the Keystone XL pipeline project and a $44 million ($33 million after-tax) unrealized loss on risk management activities recorded in other income (loss), partially offset by a $602 million ($539 million after-tax) unrealized foreign exchange gain on the revaluation of U.S. dollar denominated debt recorded in financing expenses.

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Adjusted Operating Earnings (Loss) Reconciliation(1)(2)

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Net earnings (loss)		1 553		(168)		4 119		(4 319)
Unrealized foreign exchange gain on U.S. dollar denominated debt		(21)		(539)		(101)		(286)
Unrealized (gain) loss on risk management activities(2)		(11)		33		(4)		29
Restructuring charge(3)		—		—		126		—
Asset impairment (reversal)(4)		—		423		(168)		2 221
Loss on early repayment of long-term debt(5)		—		—		60		—
Gain on significant disposal(6)		(227)		—		(227)		—
Provision for pipeline project(7)		—		142		—		142
Adjusted operating earnings (loss)(1)(2)		1 294		(109)		3 805		(2 213)

(1)

Adjusted operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

Restructuring charge of $168 million before-tax recorded in operating, selling and general expenses in the Corporate and Eliminations segment in the first quarter of 2021.

(4)

During the third quarter of 2021, the company recorded a non-cash impairment reversal of $221 million ($168 million after-tax) on its share of the Terra Nova assets, in the E&P segment, as a result of the Asset Life Extension Project moving forward and the benefit of royalty and financial support from the Government of Newfoundland and Labrador. During the first quarter of 2020, the company recorded non-cash impairment charges of $1.821 billion ($1.376 billion after-tax) on its share of the Fort Hills assets, in the Oil Sands segment, and $560 million ($422 million after-tax) against its share of the White Rose and Terra Nova assets, in the E&P segment, due to a decline in forecasted crude oil prices as a result of decreased global demand due to the COVID-19 pandemic and changes to their respective capital, operating and production plans. During the fourth quarter of 2020, the company recorded non-cash impairment charges of $559 million ($423 million after-tax) against its share of the White Rose assets, in the E&P segment, as a result of the high degree of uncertainty surrounding the future of the West White Rose Project.

(5)

Charges of $80 million before-tax recorded in financing expenses associated with the early repayment of debt in the third quarter of 2021, recorded in the Corporate and Eliminations segment.

(6)

During the fourth quarter of 2021, the company recorded a $227 million ($227 million after-tax) gain on the sale of the company’s interest in the Golden Eagle Area Development in the E&P segment.

(7)

In the fourth quarter of 2020, the company recorded a provision to transportation expense for $186 million ($142 million after-tax) in the Oil Sands segment related to the Keystone XL pipeline project.

Adjusted Funds from Operations and Cash Flow Provided by Operating Activities

Adjusted funds from operations were $3.144 billion ($2.17 per common share) in the fourth quarter of 2021, compared to $1.221 billion ($0.80 per common share) in the fourth quarter of 2020. Adjusted funds from operations were influenced by the same factors impacting adjusted operating earnings (loss) noted above.

Cash flow provided by operating activities, which includes changes in non-cash working capital, was $2.615 billion ($1.80 per common share) for the fourth quarter of 2021, compared to $814 million ($0.53 per common share) in the prior year quarter. In addition to the factors noted above, cash flow provided by operating activities was further impacted by a use of cash associated with the company’s working capital balances in both periods. The use of cash in the fourth quarter of 2021 was primarily due to an increase in accounts receivable related to increased sales and an increase in crude oil price realizations during the quarter, and a decrease in accounts payable and accrued liabilities, partially offset by an increase in taxes payable related to the company’s 2021 income tax expense, which is payable in early 2022.

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Operating Results

Suncor’s total upstream production was 743,300 boe/d in the fourth quarter of 2021, compared to 769,200 boe/d in the prior year quarter.

The company’s net SCO production of 515,000 bbls/d in the fourth quarter of 2021 was comparable to 514,300 bbls/d in the prior year quarter, resulting in a combined upgrader utilization rate of 96% in the fourth quarter of 2021 compared to 95% in the prior year quarter. Increased SCO production at Oil Sands Base, with increased In Situ bitumen production being diverted to upgrading to maximize higher value SCO production, was largely offset by lower production at Syncrude due to unplanned maintenance, which was completed subsequent to the quarter. Production in the prior year quarter was impacted by planned maintenance at Oil Sands Base, which was completed early in the quarter.

The company’s non-upgraded bitumen production was 150,900 bbls/d in the fourth quarter of 2021, compared to 157,200 bbls/d in the prior year quarter, with the decrease primarily due to lower production at Fort Hills, which resumed two-train operations late in the fourth quarter of 2021. The company is on track to operate the Fort Hills asset at average utilization rates of 90% throughout 2022.

In the fourth quarter of 2021, non-upgraded bitumen production from the company’s In Situ assets was comparable to the prior year quarter, with an overall increase in production volumes being offset by increased Firebag bitumen production being diverted to upgrading. The fourth quarter of 2021 was impacted by fewer maintenance activities at Firebag compared to the prior year quarter.

E&P produced 77,400 boe/d during the fourth quarter of 2021, compared to 97,700 boe/d in the prior year quarter. The decreased production was primarily due to natural declines and the absence of production from the Golden Eagle Area Development, as the sale of the asset was completed early in the fourth quarter of 2021. Both periods were impacted by the absence of production from Terra Nova.

Refinery crude throughput increased to 447,000 bbls/d and refinery utilization was 96% in the fourth quarter of 2021, compared to refinery crude throughput of 438,000 bbls/d and refinery utilization of 95% in the prior year quarter, reflecting strong utilizations across all refineries. Refined product sales in the fourth quarter of 2021 increased to 550,100 bbls/d, compared to 508,800 bbls/d in the prior year quarter. Strong utilizations during the quarter, increased demand and secured sales channels positioned the company to capture the improved business environment.

“In the fourth quarter of 2021, we achieved combined upgrader utilization of 96%, maximizing the value of our barrels, and continued to deliver industry-leading downstream refinery utilizations of 96%,” said Little. “At Fort Hills, we restarted our second primary extraction train at the end of the quarter and are now operating at planned production rates.”

The company’s total operating, selling and general expenses were $2.978 billion in the fourth quarter of 2021, compared to $2.494 billion in the prior year quarter. The increase was primarily due to a significant increase in natural gas prices and increased maintenance in the current quarter, and cost reductions in response to the COVID-19 pandemic in the prior year quarter. The increase was partially offset by cost reductions related to the company’s strategic initiatives. The company’s exposure to higher natural gas costs is partially mitigated by increased revenue from power sales.

Strategy Update

In 2021, Suncor exceeded its return to shareholder targets for the year, repurchasing the company’s common shares at the highest annual rate in the company’s history and increasing the dividend by 100% during the fourth quarter, while reducing debt at the highest annual pace in the company’s history. During the year, the company returned a total of $3.9 billion to shareholders through $1.6 billion in dividends paid and, since the start of its NCIB in February 2021, $2.3 billion in share repurchases, representing 5.5% of Suncor’s public float as at January 31, 2021. The company also reduced net debt by $3.7 billion to $16.1 billion, accelerating its initial goal to return to 2019 net debt levels.

In the fourth quarter, the company paid $607 million of dividends, representing the increased quarterly dividend of $0.42 per share which was doubled and reinstated back to 2019 levels. In addition, the company repurchased approximately 21 million common shares for $639 million under its NCIB, representing 1.4% of Suncor’s public float as at January 31, 2021, while reducing its net debt by $522 million.

Subsequent to the fourth quarter of 2021, the company completed an early redemption of its outstanding US$182 million 4.50% notes, originally scheduled to mature in the second quarter of 2022. In addition, the Board approved a renewal of the company’s NCIB for the repurchase of approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2022, over a twelve month period, and concurrently, the TSX accepted a notice filed by Suncor to renew its NCIB in respect of the repurchase of such shares. The company continues to make progress towards its 2025 targeted net debt range of $12–$15 billion and its shareholder return targets demonstrating its commitment to fortifying the balance sheet and returning cash to shareholders.

“In 2021, we reduced our debt at the highest annual pace in the company’s history and maximized the returns to our shareholders through accelerated share repurchases and dividends, including the doubling of our dividend in the fourth quarter,” said Little.

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“The execution of this strategy has allowed us to exit the year with a strengthened balance sheet, and we are well positioned to execute on our 2022 strategic initiatives, which are focused on operational excellence, shareholder returns and optimizing our existing base business while progressing the reduction of carbon emissions across our value chain.”

Suncor’s value of safety above all else and its focus on operational excellence, underpinned by asset reliability, operating cost and capital discipline, remains its top priority. The company remains focused on maximizing upgrader utilization at Syncrude and Oil Sands operations, capturing the higher margin on SCO production by capitalizing on the regional strength of our Oil Sands assets, and leveraging the flexibility of the integrated model to optimize refinery throughput. With the completion of the largest annual maintenance program in the company’s history in 2021, Fort Hills resuming two-train operations, and the industry-leading refinery utilizations in the downstream supported by secured sales channels, the company is positioned to increase production and refined product sales in 2022.

Looking forward, the company is committed to a focus on capital and operating cost discipline, and lowering the cash operating costs per barrel by continuing to progress its strategic initiatives and planned synergies. In the fourth quarter, as operator at Syncrude, the company continued to make progress towards the realization of synergies for the joint venture owners and is on track to achieve the expected $100 million of annual gross synergies by early 2022, with an additional $200 million expected in 2022–2023.

The company’s 2021 capital expenditures were heavily focused on the safety, long-term reliability and efficiency of the company’s operating assets. Looking ahead, enabled by efficiencies achieved across the business and the company’s commitment to capital discipline, in 2022 the company expects to achieve capital expenditures of $4.7 billion, or $300 million (6%) lower than the previously announced ceiling of $5.0 billion, with a program largely focused on sustaining capital including planned maintenance and tailings optimizations. Economic capital spend will continue to be focused on advancing projects and investments that are expected to enhance value within our existing integrated asset base, and incrementally and sustainably grow annual free funds flow.(1)

The company continued to execute its incremental free funds flow initiatives in 2021, resulting in increased revenue and margin, and increased productivity of tailings management spend, achieving incremental free funds flow of approximately $465 million. The company continues to advance a number of strategic initiatives that are expected to contribute to the company’s incremental free funds flow, including digital mine optimization, the cogeneration facility at Oil Sands Base plant, the Forty Mile Wind Power Project and investments in technology for our core business systems aimed at improving operational efficiencies. Suncor believes the implementation of digital technologies will bolster operational excellence and drive additional value for the company. As the company continues to advance its initiatives to increase free funds flow, it plans to allocate incremental funds to increasing shareholder returns.

Within the offshore business in the E&P segment, the company continued to focus on strategic production growth of existing assets including developing step-out opportunities and asset extensions. In the U.K., Buzzard Phase 2, which is expected to extend production life of the existing Buzzard field, achieved first oil in the fourth quarter of 2021. Buzzard Phase 2 is expected to reach its peak production in 2022, adding approximately 12,000 boe/d gross (approximately 3,500 boe/d net to Suncor) to existing Buzzard production. The Terra Nova Floating, Production, Storage and Offloading facility is dry docked in Spain undergoing maintenance work and is expected to sail back to Canada and return to operations before the end of 2022. The Terra Nova Asset Life Extension Project, which extends the life of the Terra Nova field by approximately a decade, is expected to provide significant returns to Suncor. During the fourth quarter of 2021, the company completed the sale of its 26.69% working interest in the Golden Eagle Area Development for gross proceeds of US$250 million net of closing adjustments and other closing costs, in addition to future contingent consideration of up to US$50 million. The effective date of the sale was January 1, 2021.

Suncor continues to expand its low-emissions energy business, practicing capital discipline by pursuing strategic investments that complement its existing business and leverage core capabilities. In the fourth quarter of 2021, Suncor increased its investment in the Varennes Carbon Recycling facility, a biofuel plant in Varennes, Quebec, that is designed to convert commercial and industrial non-recyclable waste into biofuels and renewable chemicals. Suncor believes this investment complements its existing biofuels business, and the increased investment further demonstrates Suncor’s commitment to being a leader in the global energy expansion.

The company also owns an equity investment in LanzaJet, Inc., a company working to bring sustainable aviation fuel and renewable diesel to the commercial market. Fabrication of a commercial biorefinery plant near Soperton, Georgia, is well underway and is expected to be on-stream in late-2022, and will allow Suncor to supply sustainable low-emissions aviation fuel to customers.

(1)

Non-GAAP financial measure. See Non-GAAP Financial Measures Advisory section of this document.

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Corporate Guidance

Suncor has updated its full-year business environment outlook assumptions for Brent Sullom Voe from US$73.00/bbl to US$84.00/bbl, WTI at Cushing from US$70.00/bbl to US$80.00/bbl, WCS at Hardisty from US$55.00/bbl to US$68.00/bbl, New York Harbor 2-1-1 crack from US$21.00/bbl to US$24.00/bbl and AECO-C Spot from $3.80/GJ to $3.75/GJ due to changes in key forward curve pricing for the remainder of the year. As a result of these updates, the full-year current income tax expense range has increased from $1.4 billion–$1.7 billion to $2.1 billion–$2.4 billion.

In addition, Oil Sands operations Crown royalties have been updated from 9%–12% to 13%–16%, Fort Hills Crown royalties from 2%–4% to 3%–5%, Syncrude Crown royalties have been updated from 10%–13% to 16%–19% and East Coast Canada Crown royalties have been updated from 11%–15% to 12%–16%, with the increase in royalty rates attributed to higher forecasted benchmark prices.

For further details and advisories regarding Suncor’s 2022 corporate guidance, see www.suncor.com/guidance.

Normal Course Issuer Bid

Subsequent to the fourth quarter of 2021, 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, New York Stock Exchange and/or alternative trading systems. The notice provides that, beginning February 8, 2022, and ending February 7, 2023, Suncor may purchase for cancellation up to 71,650,000 common shares, which is equal to approximately 5% of Suncor’s issued and outstanding common shares as at the date hereof. As at January 31, 2022, Suncor had 1,435,748,494 common shares issued and outstanding.

The actual number of common shares that may be purchased under the NCIB and the timing of any such purchases will be determined by Suncor. Suncor believes 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. The company does not expect the decision to allocate cash to repurchase shares will affect its long-term strategy.

Pursuant to Suncor’s previous NCIB, as amended on October 29, 2021, Suncor agreed that it would not purchase more than 106,700,000 common shares between February 8, 2021, and February 7, 2022. Between February 8, 2021, and January 31, 2022, and pursuant to Suncor’s previous NCIB (as amended), Suncor repurchased 89,703,156 shares on the open market for approximately $2.504 billion, at a weighted average price of $27.92 per share.

Subject to the block purchase exemption that is available to Suncor for regular open market purchases under the NCIB, Suncor will limit daily purchases of Suncor common shares on the TSX in connection with the NCIB to no more than 25% (2,483,448 common shares) of the average daily trading volume of Suncor’s common shares on the TSX during the previous six-month period (9,933,793 common shares). Purchases under the NCIB will be made through open market purchases at market price, as well as by other means as may be permitted by securities regulatory authorities. Suncor expects to enter into an automatic share purchase plan in relation to purchases made in connection with the NCIB on February 8, 2022.

Measurement Conversions

Certain natural gas volumes in this report to shareholders have been converted to boe on the basis of one bbl to six mcf. See the Advisories section of this document.

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Fourth Quarter Discussion

February 2, 2022

Suncor Energy Inc. (Suncor or the company) is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world’s largest petroleum resource basins – Canada’s Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil in Canada and internationally; we transport and refine crude oil; and we market petroleum and petrochemical products primarily in Canada. We also operate a renewable energy business and conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas, byproducts, refined products and power.

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 February 24, 2021 (the 2020 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

Suncor Energy Inc. has numerous direct and indirect subsidiaries, partnerships and joint arrangements (collectively, affiliates), which own and operate assets and conduct activities in different jurisdictions. The terms “we”, “our”, “Suncor”, or “the company” are used herein for simplicity of communication and only mean there is an affiliation with Suncor Energy Inc., without necessarily identifying the specific nature of the affiliation. The use of such terms in any statement herein does not mean they apply to Suncor Energy Inc. or any particular affiliate, and does not waive the corporate separateness of any affiliate. For further clarity, Suncor Energy Inc. does not directly operate or own assets in the U.S.

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	1.<br><br> <br>Advisories<br><br> <br>					9
	2.<br><br> <br>Fourth Quarter Highlights<br><br> <br>					10
	3.<br><br> <br>Consolidated Financial Information<br><br> <br>					12
	4.<br><br> <br>Segment Results and Analysis<br><br> <br>					18
	5.<br><br> <br>Capital Investment Update<br><br> <br>					28
	6.<br><br> <br>Financial Condition and Liquidity<br><br> <br>					30
	7.<br><br> <br>Quarterly Financial Data<br><br> <br>					33
	8.<br><br> <br>Other Items<br><br> <br>					35
	9.<br><br> <br>Non-GAAP Financial Measures Advisory<br><br> <br>					36
	10.<br><br> <br>Common Abbreviations<br><br> <br>					44
	11.<br><br> <br>Forward-Looking Information<br><br> <br>					45

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Advisories

Basis of Presentation

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB), which is within the framework of International Financial Reporting Standards (IFRS) as issued by the 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 is on an economic basis.

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

Beginning in the first quarter of 2021, the company revised the presentation of its expenses from “transportation” to “transportation and distribution” and reclassified certain operating, selling and general expenses to transportation and distribution to better reflect the nature of these expenses. There is no impact to net earnings (loss) and comparative periods have been restated to reflect this change.

Non-GAAP Financial Measures

Certain financial measures in this document – namely adjusted operating earnings (loss), adjusted funds from (used in) operations, measures contained in return on capital employed (ROCE) and ROCE excluding impairments, price realizations, Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining and marketing gross margin, refining operating expense, free funds flow, discretionary free funds flow (deficit), net debt, total debt, last-in, first-out (LIFO) inventory valuation methodology and related per share or per barrel amounts or metrics that contain such measures – are not prescribed by GAAP. Adjusted operating earnings (loss) is defined in the Non-GAAP Financial Measures Advisory section of this document and reconciled to the most directly comparable GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this document. Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs and LIFO inventory valuation methodology are defined in the Non-GAAP Financial Measures Advisory section of this document and reconciled to the most directly comparable GAAP measures in the Segment Results and Analysis section of this document. Adjusted funds from (used in) operations, ROCE, ROCE excluding impairments, price realizations, free funds flow, discretionary free funds flow (deficit), net debt, total debt, refining and marketing gross margin and refining operating expense are defined and reconciled, where applicable, to the most directly comparable GAAP measures in the Non-GAAP Financial Measures Advisory section of this document.

Beginning in the fourth quarter of 2021, the company changed the label of operating earnings (loss) and funds from (used in) operations to adjusted operating earnings (loss) and adjusted funds from (used in) operations, respectively, to better distinguish the non-GAAP financial measures from the comparable GAAP measures and better reflect the purpose of the measures. The composition of the measures remains unchanged and therefore no prior periods were restated.

Risk Factors and Forward-Looking Information

The company’s business, reserves, financial condition and results of operations may be affected by a number of factors, including, but not limited to, the factors described within the Forward-Looking Information section of this document. This document contains forward-looking information based on Suncor’s current expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, including those discussed in this document, Management’s Discussion and Analysis for the year ended December 31, 2020 (the 2020 annual MD&A), and Suncor’s other disclosure documents filed with Canadian securities regulatory authorities and the SEC, many of which are beyond the company’s control. Users of this information are cautioned that actual results may differ materially. Refer to the Forward-Looking Information section of this document for information on the material risk factors and assumptions underlying our forward-looking information contained in this document.

Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe 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, 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 represent a 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

For a list of abbreviations that may be used in this document, refer to the Common Abbreviations section of this document.

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Fourth Quarter Discussion

Fourth Quarter Highlights

•

Fourth quarter financial results

•

Suncor’s adjusted operating earnings(1)(2)(3) increased to $1.294 billion ($0.89 per common share) in the fourth quarter of 2021, from an adjusted operating loss of $109 million ($0.07 per common share) in the prior year quarter. The increase in adjusted operating earnings was primarily related to higher crude oil and refined product realizations reflecting the improved business environment. Adjusted operating earnings were partially offset by an increase in royalties associated with higher crude price realizations and increased operating costs. The prior year quarter adjusted operating earnings were negatively impacted by the significant decline in transportation fuel demand, which led to lower price realizations, partially offset by lower operating costs.

•

Adjusted funds from operations(1)(2) were $3.144 billion ($2.17 per common share) in the fourth quarter of 2021, compared to $1.221 billion ($0.80 per common share) in the fourth quarter of 2020. Adjusted funds from operations were influenced by the same factors impacting adjusted operating earnings (loss) noted above. Cash flow provided by operating activities, which includes changes in non-cash working capital, was $2.615 billion ($1.80 per common share) for the fourth quarter of 2021, compared to $814 million ($0.53 per common share) in the prior year quarter. In addition to the factors noted above, cash flow provided by operating activities was further impacted by a use of cash associated with the company’s working capital balances in both periods. The use of cash in the fourth quarter of 2021 was primarily due to an increase in accounts receivable related to increased sales and an increase in crude oil price realizations during the quarter, and a decrease in accounts payable and accrued liabilities, partially offset by an increase in taxes payable related to the company’s 2021 income tax expense, which is payable in early 2022.

•

Upstream achieved upgrader utilization of 96%. Suncor’s total upstream production was 743,300 boe/d in the fourth quarter of 2021, compared to 769,200 boe/d in the prior year quarter, with the decrease primarily due to decreased production from the company’s Exploration and Production (E&P) assets, including the absence of production from the Golden Eagle Area Development, as the sale of the asset was completed early in the fourth quarter of 2021. The company’s SCO production was 515,000 bbls/d in the fourth quarter of 2021, comparable to 514,300 bbls/d in the fourth quarter of 2020, driven by combined upgrader utilization of 96%.

•

Fort Hills resumes two-train operations. Fort Hills resumed two-train operations late in the fourth quarter of 2021. The company is on track to operate the Fort Hills asset at average utilization rates of 90% throughout 2022.

•

First oil at Buzzard Phase 2. Buzzard Phase 2, which is expected to extend production life of the existing Buzzard field, achieved first oil in the fourth quarter of 2021. Buzzard Phase 2 is expected to reach its peak production in 2022, adding approximately 12,000 boe/d gross (approximately 3,500 boe/d net to Suncor) to existing Buzzard production.

(1)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

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•

Continued industry-leading refinery utilizations. Refining and Marketing (R&M) delivered $765 million in adjusted funds from operations in the fourth quarter of 2021, compared to $415 million in the prior year quarter, including a first-in, first-out (FIFO) inventory valuation gain of $106 million after-tax in the current period compared to a gain of $44 million after-tax in the prior year quarter. Refinery utilization averaged 96% and crude throughput was 447,000 bbls/d in the current quarter, compared to 95% and 438,000 bbls/d respectively in the prior year quarter. The company’s Canadian refineries continued to outperform the national refining industry average by approximately 15%(1).

•

Strengthened balance sheet. In 2021, Suncor executed on its net debt(2) reduction targets, reducing debt at the highest ever annual pace, resulting in a reduction of net debt by $3.7 billion to $16.1 billion, returning to 2019 net debt levels. The company continues to reduce its debt, and subsequent to the fourth quarter of 2021, completed an early redemption of its outstanding US$182 million 4.50% notes, originally scheduled to mature in the second quarter of 2022.

•

Maximized shareholder returns. Suncor returned $3.9 billion to shareholders in 2021 through $2.3 billion in share repurchases and $1.6 billion in dividends paid, including an increased dividend in the fourth quarter of 2021, returning it to 2019 levels. Since the start of its current normal course issuer bid program (NCIB) in February 2021, the company has repurchased approximately 84 million of its common shares at an average price of $27.45 per common share, or the equivalent of 5.5% of Suncor’s public float as at January 31, 2021.

•

Renewal of share repurchase program. Subsequent to the fourth quarter of 2021, Suncor’s Board of Directors (the Board) approved a renewal of the company’s NCIB for the repurchase of approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2022, over a twelve-month period, and concurrently, the Toronto Stock Exchange (TSX) accepted a notice filed by Suncor to renew its NCIB in respect of the repurchase of such shares.

(1)

Source: Canada Energy Regulator – https://www.cer-rec.gc.ca/en/data-analysis/energy-commodities/crude-oil-petroleum-products/statistics/weekly- crude-run-summary-data/index.html.

(2)

Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

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Fourth Quarter Discussion

Consolidated Financial Information

Financial Highlights

				Three months ended<br>December 31												Twelve months ended<br>December 31
	($ millions)			2021						2020						2021						2020
	Net earnings (loss)
	Oil Sands					896						(293)						2 147						(3 796)
	Exploration and Production					465						(379)						1 285						(832)
	Refining and Marketing					450						268						2 178						866
	Corporate and Eliminations					(258)						236						(1 491)						(557)
	Total					1 553						(168)						4 119						(4 319)
	Adjusted operating earnings (loss)(1)(2)
	Oil Sands					898						(130)						2 151						(2 265)
	Exploration and Production					238						44						890						13
	Refining and Marketing					437						280						2 170						882
	Corporate and Eliminations					(279)						(303)						(1 406)						(843)
	Total					1 294						(109)						3 805						(2 213)
	Adjusted funds from (used in) operations(1)
	Oil Sands					2 175						729						6 846						1 986
	Exploration and Production					425						312						1 478						1 054
	Refining and Marketing					765						415						3 255						1 708
	Corporate and Eliminations					(221)						(235)						(1 322)						(872)
	Total					3 144						1 221						10 257						3 876
	Change in non-cash working capital					(529)						(407)						1 507						(1 201)
	Cash flow provided by operating activities					2 615						814						11 764						2 675
	Capital and exploration expenditures(3)
	Asset sustainment and maintenance					748						586						3 057						2 388
	Economic investment					398						355						1 354						1 418
	Total					1 146						941						4 411						3 806
				Three months ended<br>December 31												Twelve months ended<br>December 31
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	($ millions)			2021						2020						2021						2020
	Discretionary free funds flow (deficit)(1)					1 776						310						5 590						(228)

(1)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

Excludes capitalized interest of $38 million in the fourth quarter of 2021 and $26 million in the fourth quarter of 2020.

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Operating Highlights

	Three months ended<br>December 31				Twelve months ended<br>December 31
	2021		2020		2021		2020
Production volumes by segment
Oil Sands – SCO (mbbls/d)		515.0		514.3		468.6		466.2
Oil Sands – Non-upgraded bitumen (mbbls/d)		150.9		157.2		175.6		127.2
Exploration and Production (mboe/d)		77.4		97.7		87.5		101.7
Total (mboe/d)		743.3		769.2		731.7		695.1
Refinery utilization (%)		96		95		89		88
Refinery crude oil processed (mbbls/d)		447.0		438.0		415.5		407.0

Net Earnings (Loss)

Suncor’s consolidated net earnings for the fourth quarter of 2021 were $1.553 billion, compared to a net loss of $168 million for the prior year quarter. Net earnings were primarily influenced by the same factors that impacted adjusted operating earnings described subsequently in this section.

Other items affecting net earnings (loss) over these periods included:

•

The unrealized foreign exchange gain on the revaluation of U.S. dollar denominated debt recorded in financing expenses was $25 million ($21 million after-tax) for the fourth quarter of 2021, compared to a gain of $602 million ($539 million after-tax) for the fourth quarter of 2020.

•

The unrealized gain on risk management activities recorded in other income (loss) was $14 million ($11 million after-tax) for the fourth quarter of 2021, compared to a $44 million ($33 million after-tax) loss for the fourth quarter of 2020.

•

The gain of $227 million ($227 million after-tax) on the sale of the company’s interest in the Golden Eagle Area Development, which was completed early in the fourth quarter of 2021 and recorded in the E&P segment.

•

During the fourth quarter of 2020, the company recorded non-cash impairment charges of $559 million ($423 million after-tax) against its share of the White Rose assets, in the E&P segment, as a result of the high degree of uncertainty surrounding the future of the West White Rose Project.

•

In the fourth quarter of 2020, the company recorded a provision to transportation expense for $186 million ($142 million after-tax) related to the Keystone XL pipeline project in the Oil Sands segment.

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Fourth Quarter Discussion

Adjusted Operating Earnings (Loss) Reconciliation(1)(2)

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Net earnings (loss)		1 553		(168)		4 119		(4 319)
Unrealized foreign exchange gain on U.S. dollar denominated debt		(21)		(539)		(101)		(286)
Unrealized (gain) loss on risk management activities(2)		(11)		33		(4)		29
Restructuring charge(3)		—		—		126		—
Asset impairment (reversal)(4)		—		423		(168)		2 221
Loss on early repayment of long-term debt(5)		—		—		60		—
Gain on significant disposal(6)		(227)		—		(227)		—
Provision for pipeline project(7)		—		142		—		142
Adjusted operating earnings (loss)(1)(2)		1 294		(109)		3 805		(2 213)

(1)

Adjusted operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

Restructuring charge of $168 million before-tax recorded in operating, selling and general expenses in the Corporate and Eliminations segment in the first quarter of 2021.

(4)

(5)

Charges of $80 million before-tax recorded in financing expenses associated with the early repayment of debt in the third quarter of 2021 recorded in the Corporate and Eliminations segment.

(6)

During the fourth quarter of 2021, the company recorded a $227 million ($227 million after-tax) gain on the sale of the company’s interest in the Golden Eagle Area Development in the E&P segment.

(7)

Bridge Analysis of Adjusted Operating (Loss) Earnings ($ millions)(1)(2)

[MISSING IMAGE: tm221483d1-bc_financialpn.jpg]

(1)

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this document.

(2)

(3)

The bridge factor for Inventory Valuation is comprised of changes in the FIFO inventory valuation and realized short-term commodity risk management activities reported in the R&M segment, and changes in the intersegment elimination of profit reported in the Corporate and Eliminations segment.

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After-Tax Share-Based Compensation Expense by Segment

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Oil Sands		28		19		72		6
Exploration and Production		2		2		7		—
Refining and Marketing		16		11		42		3
Corporate and Eliminations		50		42		128		2
Total share-based compensation expense		96		74		249		11

The after-tax share-based compensation expense increased to $96 million during the fourth quarter of 2021, compared to $74 million during the prior year quarter, as a result of an increase in the company’s share price through the fourth quarter of 2021, compared to the prior year quarter.

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Fourth Quarter Discussion

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<br>three months ended<br>December 31				Average for the<br>twelve months ended<br>December 31
		2021		2020		2021		2020
WTI crude oil at Cushing	US$/bbl		77.15		42.65		67.95		39.40
Dated Brent crude	US$/bbl		79.70		44.20		70.75		41.65
Dated Brent/Maya crude oil FOB price differential	US$/bbl		8.60		3.30		6.85		6.35
MSW at Edmonton	Cdn$/bbl		93.25		50.25		80.30		45.60
WCS at Hardisty	US$/bbl		62.50		33.35		54.90		26.85
Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl		(14.65)		(9.30)		(13.05)		(12.55)
SYN-WTI differential	US$/bbl		(1.80)		(3.05)		(1.65)		(3.15)
Condensate at Edmonton	US$/bbl		79.10		42.55		68.25		37.15
Natural gas (Alberta spot) at AECO	Cdn$/mcf		4.70		2.65		3.65		2.25
Alberta Power Pool Price	Cdn$/MWh		107.30		46.15		101.95		46.70
New York Harbor 2-1-1 crack(1)	US$/bbl		20.65		9.85		19.40		11.75
Chicago 2-1-1 crack(1)	US$/bbl		16.90		7.95		17.75		8.05
Portland 2-1-1 crack(1)	US$/bbl		25.35		13.15		23.15		14.05
Gulf Coast 2-1-1 crack(1)	US$/bbl		19.65		9.00		18.00		9.90
Exchange rate	US$/Cdn$		0.79		0.77		0.80		0.75
Exchange rate (end of period)	US$/Cdn$		0.79		0.78		0.79		0.78

(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.

In the fourth quarter of 2021, crude oil and crack spread benchmarks improved compared to the prior year quarter, which was significantly impacted by lower demand for crude oil and refined products due to the impacts of the COVID-19 pandemic.

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 the fourth quarter of 2021 reflected an increase in WTI at Cushing, which averaged US$77.15/bbl compared to US$42.65/bbl in the prior year quarter. 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, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $93.25/bbl in the fourth quarter of 2021 compared to $50.25/bbl in the prior year quarter, and prices for WCS at Hardisty increased to US$62.50/bbl in the fourth quarter of 2021, from US$33.35/bbl in the prior year quarter.

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. Bitumen price realizations can also be affected by bitumen quality premiums and discounts and spot sales, and the price differential between Hardisty, Alberta, and U.S. Gulf Coast benchmarks.

The company leverages the expertise of its marketing and logistics business to optimize midstream capacity to the U.S. Gulf Coast and this is reflected in bitumen and sour SCO price realizations. Bitumen prices were unfavourably impacted by the widening of heavy crude oil differentials in the fourth quarter of 2021, but were higher than the prior year on an absolute basis due to the increase in WTI prices.

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 increased to US$79.70/bbl in the fourth quarter of 2021 compared to US$44.20/bbl in the prior year quarter.

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

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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 actual crude oil feedstock costs, refinery configuration, product mix and realized market prices unique to Suncor’s refining and marketing business. In addition, the U.S. regulatory renewable blending obligations influence the benchmark cracks, which may increase their volatility, while 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 more accurately reflect Suncor’s realized refining and marketing gross margin. This internal index is a single value calculated based on a notional five barrels 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; and the benefit of its location, quality and grade differentials, and marketing margins. The internal 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 seasonal factors. 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 and 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 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 the fourth quarter of 2021, the New York Harbor 2-1-1 and Chicago 2-1-1 benchmark crack spreads increased compared to the prior year quarter due to increased demand for transportation fuels and to compensate for increased costs associated with renewable blending regulatory obligations. The Suncor 5-2-2-1 index was US$28.05/bbl in the fourth quarter of 2021 compared to US$18.55/bbl in the fourth quarter of 2020, primarily related to the increase 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 increased to $4.70/mcf in the fourth quarter of 2021, from $2.65/mcf in the prior year quarter.

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 increased to an average of $107.30/MWh in the fourth quarter of 2021 compared to $46.15/MWh in the prior year quarter.

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. The Canadian dollar strengthened in relation to the U.S. dollar in the fourth quarter of 2021, as the average exchange rate increased to US$0.79 per one Canadian dollar from US$0.77 per one Canadian dollar in the prior year quarter. This rate increase had a negative impact on price realizations for the company during the fourth quarter of 2021 when compared to the prior year quarter.

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. 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.

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Fourth Quarter Discussion

Segment Results and Analysis

Oil Sands

Financial Highlights

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Gross revenues		5 956		3 081		19 920		10 617
Less: Royalties		(641)		(18)		(1 523)		(95)
Operating revenues, net of royalties		5 315		3 063		18 397		10 522
Net earnings (loss)		896		(293)		2 147		(3 796)
Adjusted for:
Unrealized loss on risk management activities(1)		2		21		4		13
Impairment(2)		—		—		—		1 376
Provision for pipeline project(3)		—		142		—		142
Adjusted operating earnings (loss)(4)		898		(130)		2 151		(2 265)
Adjusted funds from operations(4)		2 175		729		6 846		1 986

(1)

(2)

During the first quarter of 2020, the company recorded non-cash impairment charges of $1.821 billion ($1.376 billion after-tax) on its share of the Fort Hills assets due to a decline in forecasted crude oil prices as a result of decreased global demand due to the COVID-19 pandemic and changes to its respective capital, operating and production plans.

(3)

In the fourth quarter of 2020, the company recorded a provision to transportation expense for $186 million ($142 million after-tax) related to the Keystone XL pipeline project.

(4)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Bridge Analysis of Adjusted Operating (Loss) Earnings ($ millions)(1)(2)

[MISSING IMAGE: tm221483d1-bc_oilsandpn.jpg]

(1)

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this document.

(2)

The Oil Sands segment had adjusted operating earnings of $898 million in the fourth quarter of 2021, compared to an adjusted operating loss of $130 million in the prior year quarter. The increase was primarily due to higher realized crude prices, as crude benchmarks were lower in the prior year quarter as a result of the COVID-19 pandemic, partially offset by an increase in royalties and operating expenses.

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Production Volumes(1)

	Three months ended<br>December 31				Twelve months ended<br>December 31
(mbbls/d)	2021		2020		2021		2020
SCO and diesel production(2)		532.4		526.5		483.5		477.5
Internally consumed diesel and internal transfers(3)(4)		(17.4)		(12.2)		(14.9)		(11.3)
Upgraded production		515.0		514.3		468.6		466.2
Bitumen production		157.3		157.2		178.8		127.2
Internal bitumen transfers(4)		(6.4)		—		(3.2)		—
Non-upgraded bitumen production		150.9		157.2		175.6		127.2
Total Oil Sands production		665.9		671.5		644.2		593.4

(1)

Bitumen production from Oil Sands Base is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor’s own refineries, with SCO and diesel yields of approximately 79% of bitumen feedstock input. Fort Hills finished bitumen is sold directly to customers, including Suncor’s own refineries. Essentially all of the bitumen produced at Syncrude is upgraded to sweet SCO and a small amount of diesel, at an approximate yield of 85%.

(2)

Combined 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, and Fort Hills and Syncrude use internally produced diesel from Oil Sands Base within their mining operations. In the fourth quarter of 2021, Oil Sands operations production volumes included 10,500 bbls/d of internallyconsumed diesel, of which 7,700 bbls/d was consumed at Oil Sands Base, 1,900 bbls/d was consumed at Fort Hills and 900 bbls/d was consumed at Syncrude. Syncrude production volumes included 2,600 bbls/d of internally consumed diesel.

(4)

Internal feedstock transfers between Oil Sands operations and Syncrude through the interconnecting pipelines are included in gross SCO and bitumen production volumes. In the fourth quarter of 2021, Oil Sands operations included 4,000 bbls/d of SCO that were transferred to Suncor’s share of Syncrude through the interconnecting pipelines. Syncrude production included 300bbls/d of SCO and 6,400 bbls/d of bitumen that were transferred to Oil Sands Base through the interconnecting pipelines.

Sales Volumes

	Three months ended<br>December 31				Twelve months ended<br>December 31
(mbbls/d)	2021		2020		2021		2020
SCO and diesel		496.1		495.6		465.7		467.9
Non-upgraded bitumen		176.7		139.6		183.8		125.6
Total		672.8		635.2		649.5		593.5

SCO and diesel sales volumes were 496,100 bbls/d in the fourth quarter of 2021, compared to 495,600 bbls/d in the prior year quarter, consistent with the increase in upgraded production.

Non-upgraded bitumen sales volumes increased to 176,700 bbls/d in the fourth quarter of 2021, compared to 139,600 bbls/d in the prior year quarter, due to a draw in inventory in the fourth quarter of 2021 compared to a build of inventory in the prior year quarter, partially offset by the decrease in production in the current quarter.

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Fourth Quarter Discussion

Price Realizations(1)

Net of transportation costs, but before royalties	Three months ended<br>December 31				Twelve months ended<br>December 31
($/bbl)	2021		2020		2021		2020
SCO and diesel		89.38		47.59		77.73		43.83
Non-upgraded bitumen		62.05		28.90		53.80		22.37
Crude sales basket (all products)		82.20		43.48		70.96		39.29
Crude sales basket, relative to WTI		(15.00)		(12.09)		(14.20)		(13.51)

(1)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Oil Sands price realizations increased in the fourth quarter of 2021 from the prior year quarter, in line with the improved commodity price environment. The prior period was impacted by the decline in demand due to the impacts of the COVID-19 pandemic. Price realizations have improved in line with increased demand, optimism relating to vaccine rollouts and OPEC+ supply management.

Royalties

Royalties for the Oil Sands segment were higher in the fourth quarter of 2021 compared to the prior year quarter, primarily due to higher crude price realizations and increased sales volumes in the current period compared to the prior year quarter.

Expenses and Other Factors

Total Oil Sands operating and transportation expenses increased in the fourth quarter of 2021 compared to the prior year quarter. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and a breakdown of non-production costs by asset.

At Oil Sands operations, operating costs increased compared to the prior year quarter, primarily due to increased natural gas prices and maintenance costs.

At Fort Hills, operating costs in the fourth quarter of 2021 increased when compared to the prior year quarter, reflecting increased overburden mining activity in the quarter in preparation for the transition back to a two-train operation late in the quarter and increased natural gas prices.

Suncor’s share of Syncrude operating costs in the fourth quarter of 2021 increased when compared with the prior year quarter, primarily due to increased maintenance costs and natural gas prices.

DD&A expense for the fourth quarter of 2021 was higher compared to the prior year quarter, as the current year quarter included higher derecognition charges of property, plant and equipment.

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Cash Operating Costs

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions, except as noted)	2021		2020		2021		2020
Oil Sands operating, selling and general expense (OS&G)		2 134		1 739		8 056		7 169
Oil Sands operations cash operating costs(1) reconciliation
Oil Sands operations OS&G		1 232		1 014		4 710		4 292
Non-production costs(2)		(41)		(17)		(199)		(107)
Excess power capacity and other(3)		(101)		(55)		(375)		(248)
Inventory changes		55		72		21		(3)
Oil Sands operations cash operating costs(1)		1 145		1 014		4 157		3 934
Oil Sands operations production volumes (mbbls/d)		442.6		413.9		439.2		380.9
Oil Sands operations cash operating costs(1) ($/bbl)		28.10		26.50		25.90		28.20
Fort Hills cash operating costs(1) reconciliation
Fort Hills OS&G		273		163		897		761
Non-production costs(2)		(35)		(7)		(118)		(52)
Inventory changes		(5)		26		(15)		(11)
Fort Hills cash operating costs(1)		233		182		764		698
Fort Hills production volumes (mbbls/d)		55.5		62.4		50.7		58.1
Fort Hills cash operating costs(1) ($/bbl)		45.55		31.55		41.35		32.80
Syncrude cash operating costs(1) reconciliation
Syncrude OS&G		629		562		2 449		2 116
Non-production costs(2)		(38)		(19)		(234)		(66)
Syncrude cash operating costs(1)		591		543		2 215		2 050
Syncrude production volumes (mbbls/d)		191.6		207.4		172.4		165.7
Syncrude cash operating costs(1) ($/bbl)		33.50		28.45		35.20		33.80

(1)

Non-GAAP financial measures. Related per barrel amounts contain non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

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. In addition, non-production costs include safe-mode costs associated with the deferral of capital projects and additional costs incurred in response to the COVID-19 pandemic. Non-production costs for 2020 include the relief provided under the Government of Canada’s Emergency Wage Subsidy (CEWS) program. Non-production costs at Fort Hills and Syncrude also include, but are not limited to, excess power revenue from cogeneration units and an adjustment to reflect internally produced diesel from Oil Sands operations at the cost of production.

(3)

Oil Sands operations excess power capacity and other includes, but is not limited to, the operational revenue impacts of excess power from cogeneration units and 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) were $28.10 in the fourth quarter of 2021, compared to $26.50 in the prior year quarter, due to higher operating, selling and general expenses, as detailed above, partially offset by increased production.

Excess power capacity and other costs at Oil Sands operations for the fourth quarter of 2021 were higher than the prior year quarter, due mainly to an increase in excess power revenues resulting from higher power prices.

Oil Sands operations inventory changes in the fourth quarter of 2021 reflect a build of higher-cost SCO inventory, partially offset by a draw of lower-cost bitumen inventory, compared to a build of inventory in the prior year quarter.

(1)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

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Fourth Quarter Discussion

Fort Hills cash operating costs per barrel(1) were $45.55 in the fourth quarter of 2021, compared to $31.55 in the prior year quarter, reflecting higher operating, selling and general expenses, as detailed above, and decreased production, partially offset by excess power revenues resulting from higher power prices. In the fourth quarter of 2021, non-production costs were higher compared to the prior year quarter mainly due to a larger adjustment for internally sourced diesel, which is adjusted to reflect internally produced diesel from Oil Sands operations at the cost of production, and an increase in excess power revenues resulting from higher power prices. Inventory changes in the fourth quarter of 2021 reflect changes to inventory valuation, compared to a build of inventory in the prior year quarter.

Syncrude cash operating costs per barrel(1) were $33.50 in the fourth quarter of 2021, compared to $28.45 in the prior year quarter, due to higher operating, selling and general expenses, as detailed above, and decreased production.

Planned Maintenance Update

Planned maintenance at Syncrude is scheduled to commence late in the first quarter of 2022. The impact of this maintenance event has been reflected in the company’s 2022 guidance.

(1)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

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Exploration and Production

Financial Highlights

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Gross revenues(1)		684		507		2 736		1 851
Less: Royalties(1)		(53)		(37)		(236)		(95)
Operating revenues, net of royalties		631		470		2 500		1 756
Net earnings (loss)		465		(379)		1 285		(832)
Adjusted for:
Asset impairment (reversal)(2)		—		423		(168)		845
Gain on significant disposal(3)		(227)		—		(227)		—
Adjusted operating earnings(4)		238		44		890		13
Adjusted funds from operations(4)		425		312		1 478		1 054

(1)

Production, revenues and royalties from the company’s Libya operations have been presented in the E&P section of this document on an economic basis and exclude an equal and offsetting gross-up of revenues and royalties of $54 million in the fourth quarter of 2021 and $242 million in the twelve months ended December 31, 2021, which is required for presentation purposes in the company’s financial statements under the working-interest basis. The fourth quarter of 2020 and twelve months ended December 31, 2020, exclude an equal and offsetting gross-up of revenues and royalties of $48 million.

(2)

During the third quarter of 2021, the company recorded a non-cash impairment reversal of $221 million ($168 million after-tax) on its share of the Terra Nova assets as a result of the Asset Life Extension Project moving forward and the benefit of royalty and financial support from the Government of Newfoundland and Labrador. During the first quarter of 2020, the company recorded non-cash impairment charges of $560 million ($422 million after-tax) against its share of the White Rose and Terra Nova assets due to a decline in forecasted crude oil prices as a result of decreased global demand due to the COVID-19 pandemic and changes to their respective capital, operating and production plans. During the fourth quarter of 2020, the company recorded non-cash impairment charges of $559 million ($423 million after-tax) against its share of the White Rose assets, as a result of the high degree of uncertainty surrounding the future of the West White Rose Project.

(3)

During the fourth quarter of 2021, the company recorded a $227 million ($227 million after-tax) gain on the sale of the company’s interest in the Golden Eagle Area Development.

(4)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Bridge Analysis of Adjusted Operating Earnings ($ millions)(1)

[MISSING IMAGE: tm221483d1-bc_consolidpn.jpg]

(1)

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this document.

Adjusted operating earnings for the E&P segment in the fourth quarter of 2021 increased to $238 million compared to $44 million in the prior year quarter, with the increase primarily due to higher realized crude prices and lower DD&A, partially offset by lower sales volumes.

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Fourth Quarter Discussion

Volumes

	Three months ended<br>December 31				Twelve months ended<br>December 31
	2021		2020		2021		2020
E&P Canada (mbbls/d)		47.6		56.8		54.4		59.7
E&P International (mboe/d)		29.8		40.9		33.1		42.0
Total production (mboe/d)		77.4		97.7		87.5		101.7
Total sales volumes (mboe/d)		67.2		98.8		82.8		102.6

Production volumes for E&P Canada were 47,600 bbls/d in the fourth quarter of 2021, compared to 56,800 bbls/d in the prior year quarter, primarily due to natural declines. Both periods were impacted by the absence of production from Terra Nova as the asset has remained off-line since the fourth quarter of 2019. The Terra Nova Floating, Production, Storage and Offloading facility is dry docked in Spain undergoing maintenance work and is expected to sail back to Canada and return to operations before the end of 2022.

E&P International production was 29,800 boe/d in the fourth quarter of 2021, compared to 40,900 boe/d in the prior year quarter. Production volumes decreased in the current quarter primarily due to the absence of production from the Golden Eagle Area Development, as the sale of the asset was completed early in the fourth quarter of 2021, and natural declines.

E&P sales volumes decreased to 67,200 boe/d in the fourth quarter of 2021, compared to 98,800 boe/d in the prior year quarter, due to the decrease in production and a build of inventory at E&P Canada associated with the timing of cargo sales at year-end.

Price Realizations(1)

	Three months ended<br>December 31				Twelve months ended<br>December 31
Net of transportation costs, but before royalties	2021		2020		2021		2020
E&P Canada – Crude oil and natural gas liquids ($/bbl)		98.42		54.25		84.70		49.69
E&P International(2) ($/boe)		100.14		52.83		82.16		50.28

(1)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

E&P International price realizations exclude Libya.

Price realizations at E&P Canada and E&P International increased in the fourth quarter of 2021 from the prior year quarter, in line with the improved commodity price environment. The prior period was impacted by the significant decline in transportation fuel demand due to the impacts of the COVID-19 pandemic. Price realizations have improved in line with increased demand, optimism relating to vaccine rollouts and OPEC+ supply management.

Royalties

E&P royalties in the fourth quarter of 2021 were higher than the prior year quarter primarily due to the increase in price realizations.

Expenses and Other Factors

Operating and transportation expenses for the fourth quarter of 2021 decreased from the prior year quarter, primarily due to the decrease in production and sales volumes.

DD&A and exploration expense in the fourth quarter of 2021 decreased from the prior year quarter as a result of lower sales volumes and the absence of DD&A on the Golden Eagle Area Development in the fourth quarter of 2021 as a result of the sale of the asset.

Planned Maintenance Update for Operated Assets

There are no significant maintenance events scheduled for the first quarter of 2022.

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Refining and Marketing

Financial Highlights

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Operating revenues		6 623		3 876		22 915		15 272
Net earnings		450		268		2 178		866
Adjusted for:
Unrealized (gain) loss on risk management activities(1)		(13)		12		(8)		16
Adjusted operating earnings(2)		437		280		2 170		882
Adjusted funds from operations(2)		765		415		3 255		1 708

(1)

(2)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Bridge Analysis of Adjusted Operating Earnings ($ millions)(1)(2)

[MISSING IMAGE: tm221483d1-bc_refiningpn.jpg]

(1)

For an explanation of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this document.

(2)

R&M adjusted operating earnings in the fourth quarter of 2021 increased to $437 million from $280 million in the prior year quarter. The increase was primarily due to higher refining and marketing margins as a result of significantly higher crack spread benchmarks in the fourth quarter of 2021 compared to the prior year quarter. Adjusted operating earnings included a FIFO inventory valuation gain of $106 million after-tax on the increase in crude and refined product benchmarks in the fourth quarter of 2021, compared to a $44 million after-tax gain in the prior year quarter. Adjusted operating earnings were unfavourably impacted by increased operating expenses in the fourth quarter of 2021 compared to the prior year quarter.

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Fourth Quarter Discussion

Volumes

	Three months ended<br>December 31				Twelve months ended<br>December 31
	2021		2020		2021		2020
Crude oil processed (mbbls/d)
Eastern North America		214.3		212.6		202.8		201.0
Western North America		232.7		225.4		212.7		206.0
Total		447.0		438.0		415.5		407.0
Refinery utilization(1)(2) (%)
Eastern North America		97		96		91		91
Western North America		95		94		87		86
Total		96		95		89		88
Refined product sales (mbbls/d)
Gasoline		232.7		212.9		225.8		214.1
Distillate		237.9		222.9		228.5		215.7
Other		79.5		73.0		74.1		73.6
Total		550.1		508.8		528.4		503.4
Refining and marketing gross margin – FIFO(3) ($/bbl)		33.60		25.75		36.85		25.30
Refining and marketing gross margin – LIFO(3) ($/bbl)		30.00		25.05		30.90		28.65
Refining operating expense(3) ($/bbl)		6.10		5.20		5.95		5.50

(1)

Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.

(2)

The Edmonton refinery crude processing capacity has increased to 146,000 bbls/d in 2021 from 142,000 bbls/d in 2020.

(3)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

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 increased to $30.00/bbl in the fourth quarter of 2021, from $25.05/bbl in the prior year quarter, due to improved benchmark crack spreads, increased demand and the widening of heavy crude oil differentials. Suncor’s refining and marketing gross margin also reflects Suncor’s feedstock advantage, which enables the company to process heavier crude oil, marketing and logistics capabilities and strong sales channels within its integrated retail and wholesale networks.

•

On a FIFO basis, Suncor’s refining and marketing gross margin increased to $33.60/bbl in the fourth quarter of 2021, from $25.75/bbl in the prior year quarter, due to the same factors noted above, in addition to FIFO inventory valuation impacts. In the fourth quarter of 2021, the FIFO method of inventory valuation, relative to an estimated LIFO(2) accounting method, resulted in an after-tax gain of $106 million. In the prior year quarter, FIFO resulted in an after-tax gain of $44 million, for a favourable quarter-over-quarter impact of $43 million, after-tax, including the impact of short-term commodity risk management activities.

(1)

Contains non-GAAP financial measures. See the non-GAAP Financial Measures Advisory section of this document.

(2)

The estimated impact of the LIFO method is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

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Expenses and Other Factors

Operating expenses and DD&A in the fourth quarter of 2021 increased compared to the prior year quarter, primarily due to increased natural gas prices, power prices and throughput in the current period, and cost reductions in response to the COVID-19 pandemic in the prior year quarter. Refining operating expense per barrel(1) was $6.10 in the fourth quarter of 2021, compared to $5.20 in the prior year quarter, due to increased operating expenses partially offset by increased throughput.

Planned Maintenance

There are no significant planned maintenance events scheduled for the first quarter of 2022.

Corporate and Eliminations

Financial Highlights

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Net (loss) earnings		(258)		236		(1 491)		(557)
Adjusted for:
Unrealized foreign exchange gain on U.S. dollar denominated debt		(21)		(539)		(101)		(286)
Restructuring charge(1)		—		—		126		—
Loss on early repayment of long-term debt(2)		—		—		60		—
Adjusted operating loss(3)		(279)		(303)		(1 406)		(843)
Corporate		(304)		(282)		(1 262)		(936)
Eliminations		25		(21)		(144)		93
Adjusted funds used in operations(3)		(221)		(235)		(1 322)		(872)

(1)

During the first quarter of 2021, the company recorded a $168 million before-tax restructuring charge in operating, selling and general expenses related to the previously announced workforce reductions.

(2)

Charges of $80 million before-tax recorded in financing expenses associated with the early repayment of debt during the third quarter of 2021.

(3)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Corporate incurred an adjusted operating loss of $304 million for the fourth quarter of 2021, compared to an adjusted operating loss of $282 million for the prior year quarter, with the increased loss attributable to favourable tax settlements in the prior year quarter, partially offset by a decrease in interest expense on long-term debt as a result of debt repayments that occurred throughout 2021. Suncor capitalized $38 million of its borrowing costs in the fourth quarter of 2021 as part of the cost of major development assets and construction projects in progress, compared to $26 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 2021, the company realized $25 million of after-tax intersegment profit compared to a deferral of $21 million of after-tax intersegment profit in the prior year quarter.

Corporate and Eliminations adjusted funds used in operations were $221 million for the fourth quarter of 2021, compared to $235 million in the fourth quarter of 2020, and were influenced by the same factors impacting adjusted operating loss described above.

(1)

Contains non-GAAP financial measures. See the non-GAAP Financial Measures Advisory section of this document.

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Fourth Quarter Discussion

Capital Investment Update

Capital and Exploration Expenditures by Segment

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Oil Sands		860		628		3 168		2 736
Exploration and Production		73		80		270		489
Refining and Marketing		188		181		825		515
Corporate and Eliminations		63		78		292		186
Total capital and exploration expenditures		1 184		967		4 555		3 926
Less: capitalized interest on debt		(38)		(26)		(144)		(120)
		1 146		941		4 411		3 806

Capital and Exploration Expenditures by Type, Excluding Capitalized Interest

	Three months ended<br>December 31, 2021						Twelve months ended<br>December 31, 2021
($ millions)	Asset Sustainment and<br>Maintenance(1)		Economic<br>Investment(2)		Total		Asset Sustainment and<br>Maintenance(1)		Economic<br>Investment(2)		Total
Oil Sands
Oil Sands Base		310		125		435		1 216		420		1 636
In Situ		38		90		128		132		298		430
Fort Hills		73		—		73		253		—		253
Syncrude		160		38		198		652		97		749
Exploration and Production		—		66		66		—		242		242
Refining and Marketing		153		35		188		751		73		824
Corporate and Eliminations		14		44		58		53		224		277
		748		398		1 146		3 057		1 354		4 411

(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 through adding reserves, improving processing capacity, utilization, cost or margin, including associated infrastructure.

The company’s 2021 capital expenditures were focused on the safety and reliability of the company’s operations, heavily weighted towards asset sustainment and maintenance, which included significant planned turnaround activities across all of its refineries, at Oil Sands operations, including a significant planned turnaround at Oil Sands Base plant Upgrader 2, and a planned turnaround at Syncrude’s largest coker. In 2021, the company spent $4.411 billion on capital expenditures, excluding capitalized interest, of which 30% was directed towards economic investment activities and 70% towards asset sustainment and maintenance activities, meeting its planned capital spending program guidance for the year.

During the fourth quarter of 2021, the company spent $1.146 billion on capital expenditures, excluding capitalized interest, compared to $941 million in the prior year quarter. In 2020, due to the impacts of the COVID-19 pandemic, the company deferred, suspended and cancelled certain capital projects or changed the scope of work to reduce costs and to comply with COVID-19 safety measures.

Activity in the fourth quarter of 2021 is summarized by business unit below.

Oil Sands

Oil Sands Base capital expenditures were $435 million in the fourth quarter of 2021 and were primarily focused on asset sustainment and maintenance activities relating to the company’s planned maintenance program, as well as economic investment to progress low-carbon power cogeneration to replace the coke-fired boilers.

In Situ capital expenditures were $128 million in the fourth quarter of 2021 and were primarily directed towards economic investment activities, including the continued investment in well pad projects, and asset sustainment and maintenance activities.

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Capital expenditures at Fort Hills were $73 million in the fourth quarter of 2021, primarily directed towards asset sustainment and maintenance activities in mine and tailings development.

Syncrude capital expenditures were $198 million in the fourth quarter of 2021, the majority of which were for asset sustainment and maintenance expenditures relating to the company’s planned maintenance program.

Exploration and Production

Capital and exploration expenditures at E&P were $66 million in the fourth quarter of 2021 and were related to economic investment projects, including development work at the Fenja project, development drilling at Hebron and development work at Terra Nova related to the Asset Life Extension Project. The Terra Nova Floating, Production, Storage and Offloading facility is dry docked in Spain undergoing maintenance work and is expected to sail back to Canada and return to operations before the end of 2022.

Refining and Marketing

R&M capital expenditures were $188 million in the fourth quarter of 2021 and were primarily related to asset sustainment and maintenance activities.

Corporate and Eliminations

Corporate capital expenditures were $58 million in the fourth quarter of 2021 and were primarily directed towards the company’s digital transformation and the Forty Mile Wind Power Project.

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Fourth Quarter Discussion

Financial Condition and Liquidity

Indicators

	Twelve months ended<br>December 31
	2021		2020
Return on capital employed(1)(2) (%)		8.6		(6.9)
Net debt to adjusted funds from operations(1) (times)		1.6		5.1
Total debt to total debt plus shareholders’ equity(1) (%)		33.4		37.8
Net debt to net debt plus shareholders’ equity(1)(3) (%)		30.6		35.7
Net debt to net debt plus shareholders’ equity – excluding leases(1)(3) (%)		26.6		32.1

(1)

Non-GAAP financial measures or contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

(2)

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. ROCE would have been (2.9%) for the twelve months ended December 31, 2020, excluding the impact of impairments of $559 million ($423 million after-tax) in the fourth quarter of 2020 and $1.821 billion ($1.376 billion after-tax) and $560 million ($422 million after-tax) in the first quarter of 2020.

(3)

Beginning in the first quarter of 2021, the company has added two supplemental debt metrics that reflect additional information that management uses to evaluate capital management.

Capital Resources

Suncor’s capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, and available lines of credit. Suncor’s management believes the company will have the capital resources to fund its planned 2022 capital spending program of $4.7 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 a number of factors, including commodity prices, production and sales volumes, refining and marketing gross 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 will be with counterparties with investment grade debt ratings.

Available Sources of Liquidity

For the three months ended December 31, 2021, cash and cash equivalents decreased to $2.205 billion from $2.309 billion at September 30, 2021, with the uses of cash in respect to the company’s capital and exploration expenditures, the payment of $607 million in dividends, the repurchase of $639 million of Suncor’s common shares under its NCIB and the company’s debt reduction in the fourth quarter of 2021 marginally exceeding cash flow provided by operating activities.

For the twelve months ended December 31, 2021, cash and cash equivalents increased relative to $1.885 billion at December 31, 2020, due to cash flow provided by operating activities exceeding the company’s capital and exploration expenditures, debt reduction, dividend payments and the repurchase of Suncor’s common shares under its NCIB.

As at December 31, 2021, the weighted average days to maturity of the company’s short-term investment portfolio was approximately 20 days.

Available credit facilities for liquidity purposes at December 31, 2021, decreased to $4.247 billion, compared to $6.043 billion at December 31, 2020. The decrease in liquidity was primarily due to the cancellation of $2.8 billion in bi-lateral credit facilities that were no longer required as they were entered into in March and April of 2020 to ensure access to adequate financial resources in connection with the COVID-19 pandemic, and a reduction in the size of the company’s syndicated credit facilities. The decrease was partially offset by increased credit availability as a result of a lower commercial paper balance.

Financing Activities

Management of debt levels and liquidity continues to be a priority for Suncor given the company’s long-term plans and future expected volatility in the current business environment. Suncor believes a phased and flexible approach to existing and future projects should assist the company in maintaining its ability to manage project costs and debt levels.

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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, 2021, total debt to total debt plus shareholders’ equity was 33.4% (December 31, 2020 – 37.8%). The company continues to be in compliance with all operating covenants under its debt agreements.

Change in Debt

	Three months ended		Twelve months ended
($ millions)	December 31, 2021		December 31, 2021
Total debt(1) – beginning of period		18 980		21 699
Decrease in long-term debt		(371)		(1 028)
Decrease in short-term debt		(195)		(2 256)
Increase in lease liability		56		308
Lease payments		(88)		(325)
Foreign exchange on debt, and other		(28)		(44)
Total debt(1) – December 31, 2021		18 354		18 354
Less: Cash and cash equivalents – December 31, 2021		2 205		2 205
Net debt(1) – December 31, 2021		16 149		16 149

(1)

Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

The company’s total debt decreased in the fourth quarter of 2021 due to the repayment of long-term debt, the reduction in short-term debt and principal lease payments made during the fourth quarter of 2021, partially offset by leases entered into in the fourth quarter of 2021.

On a year-to-date basis, the company’s total debt decreased in 2021 due to the significant reduction of short-term debt, the repayment of long-term debt and principal lease payments made in 2021, partially offset by the issuance of long-term debt and leases entered into in 2021.

The company continues to reduce its net debt, and subsequent to the fourth quarter of 2021, completed an early redemption of its outstanding US$182 million 4.50% notes, originally scheduled to mature in the second quarter of 2022.

Common Shares

	December 31,
(thousands)	2021
Common shares		1 441 251
Common share options – exercisable		28 421
Common share options – non-exercisable		8 669

As at January 31, 2022, the total number of common shares outstanding was 1,435,748,494 and the total number of exercisable and non-exercisable common share options outstanding was 36,698,537. Once exercisable, each outstanding common share option is convertible into one common share.

Share Repurchases

In the first quarter of 2021, the TSX accepted a notice filed by Suncor to commence an NCIB to repurchase common shares through the facilities of the TSX, New York Stock Exchange and/or alternative trading systems. The notice provided that, beginning February 8, 2021, and ending February 7, 2022, Suncor may purchase for cancellation up to 44,000,000 common shares, which is equal to approximately 2.9% of Suncor’s 1,525,150,794 issued and outstanding common shares as at January 31, 2021.

During the third quarter of 2021, and following the Board’s approval to increase the company’s share repurchase program to approximately 5% of the company’s outstanding common shares, Suncor received approval from the TSX to amend its existing NCIB effective as of the close of markets on July 30, 2021, to repurchase common shares through the facilities of the TSX, New York Stock Exchange and/or alternative trading systems. The amended notice provided that Suncor may increase the maximum number of common shares that may be repurchased in the period beginning February 8, 2021, and ending February 7, 2022,

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Fourth Quarter Discussion

from 44,000,000 common shares, or approximately 2.9% of Suncor’s issued and outstanding common shares as at January 31, 2021, to 76,250,000 common shares, or approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2021.

During the fourth quarter of 2021, and following the Board’s approval to increase the company’s share repurchase program to approximately 7% of the company’s public float, Suncor received approval from the TSX to amend its existing NCIB effective as of the close of markets on October 29, 2021, to purchase common shares through the facilities of the TSX, New York Stock Exchange and/or alternative trading systems. The notice provided that Suncor may increase the maximum number of common shares that may be repurchased in the period beginning February 8, 2021, and ending February 7, 2022, from 76,250,000 shares, or approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2021, to 106,700,000, or approximately 7% of Suncor’s public float as at January 31, 2021.

Subsequent to the fourth quarter of 2021, and following the Board’s approval to renew the company’s share repurchase program to approximately 5% of the company’s common shares, 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, New York Stock Exchange and/or alternative trading systems. The notice provides that, beginning February 8, 2022, and ending February 7, 2023, Suncor may purchase for cancellation up to 71,650,000 common shares, which is equal to approximately 5% of Suncor’s issued and outstanding common shares as at the date hereof. As at January 31, 2022, Suncor had 1,435,748,494 common shares issued and outstanding.

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. Suncor 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 shares will affect its long-term strategy.

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions, except as noted)	2021		2020		2021		2020
Share repurchase activities (thousands of common shares)		20 858		—		83 959		7 527
Weighted average repurchase price per share (dollars per share)		30.65		—		27.45		40.83
Share repurchase cost		639		—		2 304		307

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

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of the 2020 annual MD&A with no material updates to note during the first twelve months of 2021. Suncor 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 performance or financial condition, results of operations, liquidity or capital expenditures.

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Quarterly Financial Data

Trends in Suncor’s quarterly revenue, earnings 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, foreign exchange rates and other significant events impacting operations, such as the COVID-19 pandemic beginning in the first quarter of 2020, operational incidents and the Government of Alberta’s mandatory production curtailments that were implemented during 2019 and suspended effective December 2020.

Financial Summary

Three months ended <br>($ millions, unless otherwise noted)
Total production (mboe/d)
Oil Sands	665.9	605.1	615.7	690.6	671.5	519.0	553.7	630.1
Exploration and Production	77.4	93.5	84.0	95.3	97.7	97.2	101.8	109.7
	743.3	698.6	699.7	785.9	769.2	616.2	655.5	739.8
Revenues and other income
Operating revenues, net of royalties	11 149	10 145	9 159	8 679	6 615	6 427	4 229	7 391
Other income (loss)	10	68	(66)	(43)	(21)	30	16	365
	11 159	10 213	9 093	8 636	6 594	6 457	4 245	7 756
Net earnings (loss)	1 553	877	868	821	(168)	(12)	(614)	(3 525)
per common share – basic (dollars)	1.07	0.59	0.58	0.54	(0.11)	(0.01)	(0.40)	(2.31)
per common share – diluted (dollars)	1.07	0.59	0.58	0.54	(0.11)	(0.01)	(0.40)	(2.31)
Adjusted operating earnings (loss)(1)(2)	1 294	1 043	722	746	(109)	(338)	(1 345)	(421)
per common share – basic(2)(3) (dollars)	0.89	0.71	0.48	0.49	(0.07)	(0.22)	(0.88)	(0.28)
Adjusted funds from operations(1)	3 144	2 641	2 362	2 110	1 221	1 166	488	1 001
per common share – basic(3) (dollars)	2.17	1.79	1.57	1.39	0.80	0.76	0.32	0.66
Cash flow provided by (used in) operating activities	2 615	4 718	2 086	2 345	814	1 245	(768)	1 384
per common share – basic (dollars)	1.80	3.19	1.39	1.54	0.53	0.82	(0.50)	0.91
ROCE(3) (%) for the twelve months ended	8.6	4.5	1.9	(1.4)	(6.9)	(10.2)	(7.5)	(1.3)
ROCE excluding impairments(3)(4) (%) for the twelve months ended	8.2	4.9	2.6	(0.6)	(2.9)	(1.3)	1.0	7.0
After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	21	(257)	156	181	539	290	478	(1 021)
Common share information (dollars)
Dividend per common share	0.42	0.21	0.21	0.21	0.21	0.21	0.21	0.47
Share price at the end of trading
Toronto Stock Exchange (Cdn$)	31.65	26.26	29.69	26.27	21.35	16.26	22.89	22.46
New York Stock Exchange (US$)	25.03	20.74	23.97	20.90	16.78	12.23	16.86	15.80

(1)

Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document. Adjusted operating earnings (loss) for each quarter are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures 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. Adjusted funds from operations for each quarter are defined and reconciled to GAAP measures in the Non-GAAP 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.sedar.com.

(2)

(3)

Contains non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document. Non-GAAP measures included in ROCE and ROCE excluding impairments are defined and reconciled to GAAP measures in the Non-GAAP 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.sedar.com.

(4)

ROCE excluding impairments would have been 5.1% for the first quarter of 2020, excluding the impacts of the $1.116 billion deferred tax recovery for the Alberta corporate income tax rate change in the second quarter of 2019.

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Business Environment

(average for the three months ended)
WTI crude oil at Cushing	US$/bbl	77.15	70.55	66.05	57.80	42.65	40.95	27.85	46.10
Dated Brent crude	US$/bbl	79.70	73.45	68.85	60.85	44.20	43.00	29.20	50.15
Dated Brent/Maya FOB price differential	US$/bbl	8.60	7.80	6.20	4.70	3.30	3.50	2.70	15.95
MSW at Edmonton	Cdn$/bbl	93.25	83.75	77.25	66.55	50.25	51.30	30.20	52.00
WCS at Hardisty	US$/bbl	62.50	56.95	54.60	45.40	33.35	31.90	16.35	25.60
Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(14.65)	(13.60)	(11.45)	(12.40)	(9.30)	(9.05)	(11.50)	(20.50)
SYN-WTI (differential) premium	US$/bbl	(1.80)	(1.60)	0.35	(3.50)	(3.05)	(2.45)	(4.55)	(2.70)
Condensate at Edmonton	US$/bbl	79.10	69.20	66.40	58.00	42.55	37.55	22.20	46.20
Natural gas (Alberta spot) at AECO	Cdn$/mcf	4.70	3.60	3.10	3.15	2.65	2.25	2.00	2.05
Alberta Power Pool Price	Cdn$/MWh	107.30	100.35	104.50	95.45	46.15	43.85	29.90	67.05
New York Harbor 2-1-1 crack(1)	US$/bbl	20.65	20.90	20.35	15.60	9.85	10.20	12.20	14.75
Chicago 2-1-1 crack(1)	US$/bbl	16.90	20.45	20.25	13.40	7.95	7.75	6.75	9.75
Portland 2-1-1 crack(1)	US$/bbl	25.35	26.70	24.55	15.80	13.15	12.55	12.20	18.30
Gulf Coast 2-1-1 crack(1)	US$/bbl	19.65	19.55	18.25	14.45	9.00	8.55	9.00	13.00
Exchange rate	US$/Cdn$	0.79	0.79	0.81	0.79	0.77	0.75	0.72	0.74
Exchange rate (end of period)	US$/Cdn$	0.79	0.78	0.81	0.80	0.78	0.75	0.73	0.71

(1)

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Other Items

Accounting Policies and New IFRS Standards

Suncor’s significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor’s 2020 annual MD&A and in notes 3 and 5 of Suncor’s audited Consolidated Financial Statements for the year ended December 31, 2020.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are those that require management to make assumptions about matters that are highly uncertain at the time the estimate is made. Critical accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the company’s financial condition, changes in financial condition or financial performance. Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of Suncor’s critical accounting estimates is provided in note 4 to the audited Consolidated Financial Statements for the year ended December 31, 2020, and in the Accounting Policies and Critical Accounting Estimates section of Suncor’s 2020 annual MD&A.

On January 30, 2020, the World Health Organization declared the COVID-19 outbreak a Public Health Emergency of International Concern and, on March 10, 2020, declared it to be a pandemic. Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, quarantines in certain areas, and forced closures for certain types of public places and businesses. These measures have and will continue to have significant disruption to business operations and a significant increase in economic uncertainty, with reduced demand for commodities leading to volatile prices and currency exchange rates, and a decline in long-term interest rates. Our operations and business are particularly sensitive to a reduction in the demand for, and prices of, commodities that are closely linked to Suncor’s financial performance, including crude oil, refined petroleum products (such as jet fuel and gasoline), natural gas and electricity. The potential direct and indirect impacts of the economic volatility have been considered in management’s estimates, and assumptions at period-end have been reflected in our results with any significant changes described in the relevant notes to the company’s unaudited interim Consolidated Financial Statements for the three and twelve months ended December 31, 2021.

The COVID-19 pandemic is an evolving situation that is expected to continue to have widespread implications for our business environment, operations and financial condition. Management cannot reasonably estimate the length or severity of this pandemic, or the extent to which the disruption may materially impact our consolidated statements of comprehensive income (loss), consolidated balance sheets and consolidated statements of cash flows.

Financial Instruments

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company’s position with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor’s financial instruments and the related financial risk factors, see note 27 of the audited Consolidated Financial Statements for the year ended December 31, 2020, note 10 to the unaudited interim Consolidated Financial Statements for the three months and twelve months ended December 31, 2021, and the Financial Condition and Liquidity section of the 2020 annual MD&A.

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Non-GAAP Financial Measures Advisory

Certain financial measures in this document – namely adjusted operating earnings (loss), adjusted funds from (used in) operations, measures contained in ROCE and ROCE excluding impairments, price realizations, free funds flow, discretionary free funds flow (deficit), Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining and marketing gross 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, as applicable, 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.

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. Adjusted operating earnings (loss) is reconciled to net earnings (loss) in the Consolidated Financial Information and Segment Results and Analysis sections of this document.

Beginning in the first quarter of 2021, the company revised its calculation of adjusted operating earnings (loss) to exclude unrealized (gains) losses on derivative financial instruments that are recorded at fair value in other income (loss) to better align the earnings impact of the activity with the underlying items being risk-managed. Prior period comparatives have been restated to reflect this change.

Bridge Analyses of Adjusted Operating Earnings (Loss)

Throughout this document, 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 particular sections of this document. These bridge analyses are presented because management uses this presentation to evaluate performance.

•

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

•

The factor for Price, Margin and Other Revenue includes upstream price realizations before royalties, with the exception of Libya, which is net of royalties, and realized short-term commodity risk management activities. Also included are refining and marketing gross 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 includes the after-tax impact of the FIFO method of inventory valuation in the company’s 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, as both represent inventory valuation adjustments, and downstream realized short-term commodity risk management activities.

•

The factor for Operating and Transportation Expense includes project startup costs, operating, selling and general expense, and transportation expense.

•

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

•

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

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Return on Capital Employed (ROCE) and ROCE Excluding Impairments

ROCE is a measure 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 are 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.

For the twelve months ended December 31
($ millions, except as noted)		2021		2020
Adjustments to net earnings (loss)
Net earnings (loss)			4 119		(4 319)
(Deduct) add after-tax amounts for:
Unrealized foreign exchange gain on U.S. dollar denominated debt			(101)		(286)
Net interest expense			645		698
Adjusted net earnings (loss)(1)	A		4 663		(3 907)
Capital employed – beginning of twelve-month period
Net debt(2)			19 814		16 010
Shareholders’ equity			35 757		42 042
			55 571		58 052
Capital employed – end of twelve-month period
Net debt(2)			16 149		19 814
Shareholders’ equity			36 614		35 757
			52 763		55 571
Average capital employed	B		54 069		56 270
ROCE (%)(3)	A/B		8.6		(6.9)

(1)

Total before-tax impact of adjustments is $738 million for the twelve months ended December 31, 2021, and $618 million for the twelve months ended December 31, 2020.

(2)

Net debt is a non-GAAP financial measure.

(3)

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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, commodity price volatility, 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, which management believes reduces comparability between periods.

Adjusted funds from (used in) operations for each quarter are separately defined and reconciled to the cash flow provided by the operating activities measure in the Non-GAAP Financial Measures Advisory section of each respective management’s discussion and analysis or quarterly report to shareholders, as applicable, for the related quarter, with such information being incorporated by reference herein and available on SEDAR at www.sedar.com.

Three months ended December 31	Oil Sands				Exploration and<br>Production				Refining and<br>Marketing				Corporate and<br>Eliminations				Total
($ millions)	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
Net earnings (loss)		896		(293)		465		(379)		450		268		(258)		236		1 553		(168)
Adjustments for:
Depreciation, depletion, amortization <br>and impairment		1 237		1 058		129		835		243		207		21		20		1 630		2 120
Deferred income taxes		(11)		(154)		(2)		(160)		45		(53)		(28)		43		4		(324)
Accretion		61		55		15		13		1		1		—		—		77		69
Unrealized foreign exchange gain on <br>U.S. dollar denominated debt		—		—		—		—		—		—		(25)		(602)		(25)		(602)
Change in fair value of financial instruments and trading inventory		8		49		42		5		—		(9)		—		—		50		45
(Gain) loss on disposal of assets		(4)		1		(227)		—		(1)		(18)		—		9		(232)		(8)
Loss on extinguishment of long-term <br>debt		—		—		—		—		—		—		—		—		—		—
Share-based compensation		36		25		4		3		21		15		64		52		125		95
Exploration		—		—		—		—		—		—		—		—		—		—
Settlement of decommissioning and restoration liabilities		(71)		(41)		1		—		(6)		(7)		—		—		(76)		(48)
Other		23		29		(2)		(5)		12		11		5		7		38		42
Adjusted funds from (used in) operations		2 175		729		425		312		765		415		(221)		(235)		3 144		1 221
Change in non-cash working capital																		(529)		(407)
Cash flow provided by operating activities																		2 615		814

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Twelve months ended December 31	Oil Sands				Exploration and<br>Production				Refining and<br>Marketing				Corporate and<br>Eliminations				Total
($ millions)	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
Net earnings (loss)		2 147		(3 796)		1 285		(832)		2 178		866		(1 491)		(557)		4 119		(4 319)
Adjustments for:
Depreciation, depletion, amortization and impairment		4 585		6 430		324		2 147		853		867		88		82		5 850		9 526
Deferred income taxes		(51)		(797)		33		(321)		113		(24)		(39)		23		56		(1 119)
Accretion		240		224		58		48		6		6		—		—		304		278
Unrealized foreign exchange gain on U.S. dollar denominated debt		—		—		—		—		—		—		(113)		(312)		(113)		(312)
Change in fair value of financial <br>instruments and trading <br>inventory		(66)		81		3		(17)		50		44		—		—		(13)		108
(Gain) loss on disposal of assets		(4)		(1)		(227)		—		(19)		(24)		(7)		9		(257)		(16)
Loss on extinguishment of long-term debt		—		—		—		—		—		—		80		—		80		—
Share-based compensation		61		(59)		5		(9)		34		(36)		105		(134)		205		(238)
Exploration		—		—		—		80		—		—		—		—		—		80
Settlement of decommissioning and restoration liabilities		(245)		(212)		(1)		(7)		(17)		(12)		—		—		(263)		(231)
Other		179		116		(2)		(35)		57		21		55		17		289		119
Adjusted funds from (used in) operations		6 846		1 986		1 478		1 054		3 255		1 708		(1 322)		(872)		10 257		3 876
Change in non-cash working capital																		1 507		(1 201)
Cash flow provided by operating <br>activities																		11 764		2 675

Free Funds Flow and Discretionary Free Funds Flow (Deficit)

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. Discretionary free funds flow (deficit) is a non-GAAP financial measure that is calculated by taking adjusted funds from operations and subtracting asset sustainment and maintenance capital, inclusive of associated capitalized interest, and dividends. Both free funds flow and discretionary free funds flow (deficit) reflect cash available for increasing distributions to shareholders and to fund growth investments. Management uses free funds flow and discretionary free funds flow (deficit) to measure the capacity of the company to increase returns to shareholders and to grow Suncor’s business.

	Three months ended<br>Dec 31				Twelve months ended<br>Dec 31
($ millions)	2021		2020		2021		2020
Cash flow provided by operating activities		2 615		814		11 764		2 675
(Add) deduct change in non-cash working capital		(529)		(407)		1 507		(1 201)
Adjusted funds from operations		3 144		1 221		10 257		3 876
Asset sustaining and maintenance capital and dividends(1)		(1 368)		(911)		(4 667)		(4 104)
Discretionary free funds flow (deficit)		1 776		310		5 590		(228)

(1)

Includes capitalized interest on sustaining capital of $13 million in the fourth quarter of 2021 and $5 million in the fourth quarter of 2020.

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Oil Sands Operations, Fort Hills and Syncrude Cash Operating Costs

Cash operating costs are calculated by adjusting Oil Sands segment OS&G expense for i) non-production costs that management believes do not relate to production performance, including, but not limited to, share-based compensation adjustments, CEWS and COVID-19-related costs, research costs and the expense recorded as part of a non-monetary arrangement involving a third-party processor; ii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; iii) project startup costs; and iv) the impacts of changes in inventory levels and valuation, such that the company is able to present cost information based on production volumes. Oil Sands operations and Syncrude production volumes are gross of internally consumed diesel and feedstock transfers between assets through the interconnecting pipelines. Oil Sands operations, Fort Hills and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this document. Management uses cash operating costs to measure operating performance.

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, CEWS, 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.

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions, except as noted)	2021		2020		2021		2020
Refining and marketing gross margin reconciliation
Operating revenues		6 623		3 876		22 915		15 272
Purchases of crude oil and products		(5 110)		(2 744)		(16 807)		(11 243)
		1 513		1 132		6 108		4 029
Other (loss) income		(2)		(10)		(50)		48
Non-refining and marketing margin		(14)		(14)		(54)		(57)
Refining and marketing gross margin – FIFO		1 497		1 108		6 004		4 020
Refinery production(1) (mbbls)		44 575		43 036		162 862		158 991
Refining and marketing gross margin – FIFO ($/bbl)		33.60		25.75		36.85		25.30
FIFO and short-term risk management activities adjustment		(161)		(30)		(972)		532
Refining and marketing gross margin – LIFO		1 336		1 078		5 032		4 552
Refining and marketing gross margin – LIFO ($/bbl)		30.00		25.05		30.90		28.65
Refining operating expense reconciliation
Operating, selling and general expense(2)		566		472		2 019		1 759
Non-refining costs(2)		(294)		(248)		(1 051)		(885)
Refining operating expense		272		224		968		874
Refinery production(1) (mbbls)		44 575		43 036		162 862		158 991
Refining operating expense ($/bbl)		6.10		5.20		5.95		5.50

(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.

(2)

Prior period amounts of OS&G have been reclassified to align with the current year presentation of transportation and distribution expense. This reclassification had no effect on the refining operating expense.

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Impact of First-in, First-out (FIFO) Inventory Valuation on Refining and Marketing Net Earnings (Loss)

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 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 (which can be several weeks for foreign offshore crude purchases), 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 United States GAAP (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.

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).

	December 31		December 31
($ millions, except as noted)	2021		2020
Short-term debt		1 284		3 566
Current portion of long-term debt		231		1 413
Current portion of long-term lease liabilities		310		272
Long-term debt		13 989		13 812
Long-term lease liabilities		2 540		2 636
Total debt		18 354		21 699
Less: Cash and cash equivalents		2 205		1 885
Net debt		16 149		19 814
Shareholders’ equity		36 614		35 757
Total debt plus shareholders’ equity		54 968		57 456
Total debt to total debt plus shareholders’ equity (%)		33.4		37.8
Net debt to net debt plus shareholders’ equity (%)		30.6		35.7
Net debt to net debt plus shareholders’ equity – excluding leases (%)		26.6		32.1

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.

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Oil Sands Price Realizations

	For the three months ended			December 31, 2021																								December 31, 2020
	($ millions, except as noted)			Bitumen						SCO and<br>Diesel						Crude<br>Sales<br>Basket						Oil<br>Sands<br>Segment						Bitumen						SCO and<br>Diesel						Crude<br>Sales<br>Basket						Oil<br>Sands<br>Segment
	Operating revenues, net of royalties					1 344						3 971						5 315						5 315						634						2 429						3 063						3 063
	Add: Royalties					155						486						641						641						4						14						18						18
	Operating revenues					1 499						4 457						5 956						5 956						638						2 443						3 081						3 081
	Other (loss) income					7						4						11						11						(9)						(4)						(13)						(13)
	Purchases of crude oil and products					(320)						(87)						(407)						(407)						(128)						(47)						(175)						(175)
	Gross realization adjustment(1)					(88)						(92)						(180)												(63)						(51)						(114)
	Gross realizations					1 098						4 282						5 380												438						2 341						2 779
	Transportation and distribution					(88)						(205)						(293)						(293)						(256)						(170)						(426)						(426)
	Transportation and distribution adjustment(2)					—						—						—												189						—						189
	Net transportation and distribution					(88)						(205)						(293)												(67)						(170)						(237)
	Price realization					1 010						4 077						5 087												371						2 171						2 542
	Sales volumes (mbbls)					16 260						45 644						61 904												12 837						45 601						58 438
	Price realization per barrel					62.05						89.38						82.20												28.90						47.59						43.48
	For the twelve months ended			December 31, 2021																								December 31, 2020
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	($ millions, except as noted)			Bitumen						SCO and<br>Diesel						Crude<br>Sales<br>Basket						Oil<br>Sands<br>Segment						Bitumen						SCO and<br>Diesel						Crude<br>Sales<br>Basket						Oil<br>Sands<br>Segment
	Operating revenues, net of royalties					5 092						13 305						18 397						18 397						2 024						8 498						10 522						10 522
	Add: Royalties					376						1 147						1 523						1 523						19						76						95						95
	Operating revenues					5 468						14 452						19 920						19 920						2 043						8 574						10 617						10 617
	Other (loss) income					(56)						62						6						6						21						277						298						298
	Purchases of crude oil and products					(1 231)						(213)						(1 444)						(1 444)						(702)						(142)						(844)						(844)
	Gross realization adjustment(1)					(210)						(325)						(535)												(54)						(458)						(512)
	Gross realizations					3 971						13 976						17 947												1 308						8 251						9 559
	Transportation and distribution					(359)						(767)						(1 126)						(1 126)						(476)						(747)						(1 223)						(1 223)
	Transportation and distribution adjustment(2)					—						—						—												197						—						197
	Net transportation and distribution					(359)						(767)						(1 126)												(279)						(747)						(1 026)
	Price realization					3 612						13 209						16 821												1 029						7 504						8 533
	Sales volumes (mbbls)					67 094						169 983						237 077												45 980						171 211						217 191
	Price realization per barrel					53.80						77.73						70.96												22.37						43.83						39.29

(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.

(2)

Reflects adjustments for expenses or credits not directly related to the transportation of the crude product to its deemed point of sale.

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E&P Price Realizations

	For the three months ended			December 31, 2021																								December 31, 2020
	($ millions, except as noted)			International						East<br>Coast<br>Canada						Other(1)						E&P<br>Segment						International						East<br>Coast<br>Canada						Other(1)						E&P<br>Segment
	Operating revenues, net of royalties					215						324						92						631						193						263						14						470
	Add: Royalties					—						54						53						107						—						36						49						85
	Operating revenues					215						378						145						738						193						299						63						555
	Transportation and distribution					(6)						(11)						—						(17)						(7)						(12)						(1)						(20)
	Price realization					209						367						145												186						287						62
	Sales volumes (mbbls)					2 111						3 724																		3 511						5 294
	Price realization per barrel					100.14						98.42																		52.83						54.25
	For the twelve months ended			December 31, 2021																								December 31, 2020
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	($ millions, except as noted)			International						East<br>Coast<br>Canada						Other(1)						E&P<br>Segment						International						East<br>Coast<br>Canada						Other(1)						E&P<br>Segment
	Operating revenues, net of royalties					815						1 447						238						2 500						809						1 058						(111)						1 756
	Add: Royalties					—						237						241						478						—						94						49						143
	Operating revenues					815						1 684						479						2 978						809						1 152						(62)						1 899
	Transportation and distribution					(25)						(44)						(43)						(112)						(34)						(65)						(1)						(100)
	Price realization					790						1 640						436												775						1 087						(63)
	Sales volumes (mbbls)					9 616						19 386																		15 406						21 879
	Price realization per barrel					82.16						84.70																		50.28						49.69

(1)

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

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Common Abbreviations

The following is a list of abbreviations that may be used in this document:

Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
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	Financial and Business Environment
		Q4	Three months ended December 31
GJ	Gigajoule	DD&A	Depreciation, depletion and amortization
		WTI	West Texas Intermediate
mcf	thousands of cubic feet of natural gas	WCS	Western Canadian Select
mcfe	thousands of cubic feet of natural gas equivalent	SCO	Synthetic crude oil
mmcf	millions of cubic feet of natural gas	SYN	Synthetic crude oil benchmark
mmcf/d	millions of cubic feet of natural gas per day	MSW	Mixed Sweet Blend
mmcfe	millions of cubic feet of natural gas equivalent	NYMEX	New York Mercantile Exchange
mmcfe/d	millions of cubic feet of natural gas equivalent	YTD	Year to date
	per day
MW	megawatts
MWh	megawatts per hour

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Forward-Looking Information

This document contains certain forward-looking information and forward-looking statements (collectively referred to herein as “forward-looking statements”) within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information are 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; the current and potential adverse impacts of the COVID-19 pandemic, including the status of the pandemic and future waves and any associated policies around current business restrictions, shelter-in-place orders or gatherings of individuals; 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 other 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”, “future”, “potential”, “opportunity”, “would”, “priority”, “strategy” and similar expressions. Forward-looking statements in this document include references to:

•

Suncor’s expectation that it will operate the Fort Hills asset at average utilization rates of 90% throughout 2022;

•

statements about Buzzard Phase 2, including the expectation that it will extend the production life of the existing field and reach its peak production of 12,000 boe/d gross (approximately 3,500 boe/d net to Suncor) in 2022;

•

statements regarding Suncor’s capital allocation strategy and targets, including with respect to shareholder return, debt reduction and dividends, including: the expectation that Suncor will continue to accelerate its net debt reduction; that the company continues to make progress towards its 2025 targeted net debt range of $12–$15 billion and shareholder returns targets demonstrating its commitment to fortifying the balance sheet and returning cash to shareholders;

•

Suncor’s focus on capital and operating cost discipline and lowering its cash operating costs per barrel;

•

Suncor’s belief that it is well positioned to execute on its 2022 strategic initiatives, which are focused on operational excellence, shareholder returns and optimizing its existing base business while progressing the reduction of carbon emissions across its value chain and that its value of safety above all else and its focus on operational excellence, underpinned by asset reliability, operating cost and capital discipline, will remain its top priority;

•

the expectation that the company will remain focused on maximizing upgrader utilization at Syncrude and Oil Sands operations, capturing the higher margin on SCO production by capitalizing on the regional strength of its Oil Sands assets and leveraging the flexibility of the integrated model to optimize refinery throughput;

•

Suncor’s belief that it is positioned to increase production and refined product sales in 2022 and the basis for such belief;

•

that Suncor is on track towards the realization of synergies for the Syncrude joint venture owners to achieve $100 million of annual gross synergies by early 2022 with an additional $200 million expected in 2022–2023;

•

Suncor’s expectations with respect to the Terra Nova project, including with respect to the Asset Life Extension Project that is expected to extend production life by approximately a decade and the timing of maintenance work on the Floating, Production, Storage and Offloading facility;

•

statements regarding Suncor’s strategic initiatives and investments, including the expectation that they will contribute to the company’s incremental free funds flow, Suncor’s belief that the implementation of digital technologies will bolster operational excellence and drive additional value for the company and Suncor’s belief that its investment in the Varennes Carbon Recycling facility will complement its existing biofuels business;

•

statements regarding Suncor’s investment in LanzaJet, Inc. including the expectation that the commercial biorefinery plant will be on-stream in late 2022 and allow Suncor to supply sustainable low-emissions aviation fuel to customers;

•

statements with respect to planned maintenance events and the timing thereof, including the planned turnaround maintenance at Syncrude;

•

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

•

statements regarding Suncor’s planned 2022 capital spending program of $4.7 billion, including Suncor’s belief that it will have the capital resources to fund the capital spending program and to meet current and future working capital requirements through

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cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, accessing capital markets and Suncor’s expectations regarding the allocation of its capital spending program and its expected benefits therefrom;

•

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

•

the company’s priority regarding the management of debt levels and liquidity given the company’s long-term plans and future expected volatility in the pricing environment and Suncor’s belief that a phased and flexible approach to existing and future projects should assist Suncor in its ability to manage project costs and debt levels;

•

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 performance or financial condition, results of operations, liquidity or capital expenditures;

•

statements about the NCIB, including the amount, timing and manner of purchases under the NCIB, 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 interest of the company and its shareholders, and the expectation that the decision to allocate cash to repurchase shares will not affect its long-term growth strategy and Suncor’s expectation that it will enter into an automatic share purchase plan in relation to purchased made in connection with the NCIB on February 8, 2022; and

•

Suncor’s full-year outlook range on Oil Sands operations Crown royalties, Fort Hills Crown royalties, Syncrude Crown royalties, East Coast Canada Crown royalties and full-year current income tax expenses as well as business environment outlook assumptions for Brent Sullom Voe, WTI at Cushing, WCS at Hardisty, New York Harbor 2-1-1 crack and AECO-C Spot.

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 socioeconomic 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 our 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.

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 COVID-19

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pandemic and 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 major 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 and other government-imposed compliance costs; 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, resources and future production estimates; market instability affecting Suncor’s ability to borrow in the capital debt 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 marketing and logistics 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 Aboriginal 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 document, and in the company’s 2020 annual MD&A, the 2020 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com 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 MD&As that Suncor files from time to time with securities regulatory authorities. Copies of these MD&As are available without charge from the company.

The forward-looking statements contained in this document are made as of the date of this document. 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.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited)

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Revenues and Other Income
Operating revenues, net of royalties (note 3)		11 149		6 615		39 132		24 662
Other income (loss) (note 4)		10		(21)		(31)		390
		11 159		6 594		39 101		25 052
Expenses
Purchases of crude oil and products		4 070		2 157		13 791		9 112
Operating, selling and general(1)		2 978		2 494		11 366		9 794
Transportation and distribution(1)		380		507		1 479		1 551
Depreciation, depletion, amortization and impairment (note 11)		1 630		2 120		5 850		9 526
Exploration		16		10		47		186
Gain on disposal of assets (note 14)		(232)		(8)		(257)		(16)
Financing expenses (income) (note 6)		263		(245)		1 255		996
		9 105		7 035		33 531		31 149
Earnings (Loss) before Income Taxes		2 054		(441)		5 570		(6 097)
Income Tax Expense (Recovery)
Current		497		51		1 395		(659)
Deferred		4		(324)		56		(1 119)
		501		(273)		1 451		(1 778)
Net Earnings (Loss)		1 553		(168)		4 119		(4 319)
Other Comprehensive Income (Loss)
Items That May be Subsequently Reclassified to Earnings:
Foreign currency translation adjustment		(28)		(102)		(63)		(22)
Items That Will Not be Reclassified to Earnings:
Actuarial gain (loss) on employee retirement benefit plans, net of income taxes (note 13)		46		(1)		856		(196)
Other Comprehensive Income (Loss)		18		(103)		793		(218)
Total Comprehensive Income (Loss)		1 571		(271)		4 912		(4 537)
Per Common Share (dollars) (note 8)
Net earnings (loss) – basic and diluted		1.07		(0.11)		2.77		(2.83)
Cash dividends		0.42		0.21		1.05		1.10

(1)

Prior period amounts have been reclassified to align with the current year presentation of transportation and distribution expense. For the three months and twelve months ended December 31, 2020, $35 million and $133 million, respectively, was reclassified from operating, selling and general expense to transportation and distribution expense. This reclassification had no effect on net earnings (loss).

See accompanying notes to the condensed interim consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS

(unaudited)

($ millions)
Assets
Current assets
Cash and cash equivalents	2 205	1 885
Accounts receivable	4 534	3 157
Inventories	4 110	3 617
Income taxes receivable	128	727
Total current assets	10 977	9 386
Property, plant and equipment, net (notes 11 and 14)	65 546	68 130
Exploration and evaluation	2 226	2 286
Other assets	1 307	1 277
Goodwill and other intangible assets	3 523	3 328
Deferred income taxes	160	209
Total assets	83 739	84 616
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	1 284	3 566
Current portion of long-term debt (note 6)	231	1 413
Current portion of long-term lease liabilities	310	272
Accounts payable and accrued liabilities	6 503	4 684
Current portion of provisions	779	527
Income taxes payable	1 292	87
Total current liabilities	10 399	10 549
Long-term debt (note 6)	13 989	13 812
Long-term lease liabilities	2 540	2 636
Other long-term liabilities (note 13)	2 180	2 840
Provisions (note 12)	8 776	10 055
Deferred income taxes	9 241	8 967
Equity	36 614	35 757
Total liabilities and shareholders’ equity	83 739	84 616

See accompanying notes to the condensed interim consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three months ended<br>December 31				Twelve months ended<br>December 31
($ millions)	2021		2020		2021		2020
Operating Activities
Net Earnings (Loss)		1 553		(168)		4 119		(4 319)
Adjustments for:
Depreciation, depletion, amortization and impairment (note 11)		1 630		2 120		5 850		9 526
Deferred income tax expense (recovery)		4		(324)		56		(1 119)
Accretion (note 6)		77		69		304		278
Unrealized foreign exchange gain on U.S. dollar denominated debt (note 6)		(25)		(602)		(113)		(312)
Change in fair value of financial instruments and trading <br>inventory		50		45		(13)		108
Gain on disposal of assets (note 14)		(232)		(8)		(257)		(16)
Loss on extinguishment of long-term debt (note 6)		—		—		80		—
Share-based compensation		125		95		205		(238)
Exploration		—		—		—		80
Settlement of decommissioning and restoration liabilities		(76)		(48)		(263)		(231)
Other		38		42		289		119
(Increase) decrease in non-cash working capital (note 7)		(529)		(407)		1 507		(1 201)
Cash flow provided by operating activities		2 615		814		11 764		2 675
Investing Activities
Capital and exploration expenditures		(1 184)		(967)		(4 555)		(3 926)
Proceeds from disposal of assets		317		60		335		72
Other investments and acquisitions		(39)		(23)		(28)		(113)
Decrease (increase) in non-cash working capital (note 7)		86		(143)		271		(557)
Cash flow used in investing activities		(820)		(1 073)		(3 977)		(4 524)
Financing Activities
Net (decrease) increase in short-term debt		(195)		1 091		(2 256)		1 445
Repayment of long-term debt (note 6)		(371)		—		(2 451)		—
Issuance of long-term debt (note 6)		—		—		1 423		2 634
Lease liability payments		(88)		(81)		(325)		(335)
Issuance of common shares under share option plans		5		—		8		29
Repurchase of common shares (note 9)		(639)		—		(2 304)		(307)
Distributions relating to non-controlling interest		(2)		(2)		(9)		(10)
Dividends paid on common shares		(607)		(320)		(1 550)		(1 670)
Cash flow (used in) provided by financing activities		(1 897)		688		(7 464)		1 786
(Decrease) Increase in Cash and Cash Equivalents		(102)		429		323		(63)
Effect of foreign exchange on cash and cash equivalents		(2)		(33)		(3)		(12)
Cash and cash equivalents at beginning of period		2 309		1 489		1 885		1 960
Cash and Cash Equivalents at End of Period		2 205		1 885		2 205		1 885
Supplementary Cash Flow Information
Interest paid		345		380		980		1 028
Income taxes paid (received)		73		(1)		(532)		695

See accompanying notes to the condensed interim consolidated financial statements.

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)

($ millions)
At December 31, 2019	25 167	566	899	15 410	42 042	1 531 874
Net loss	—	—	—	(4 319)	(4 319)	—
Foreign currency translation adjustment	—	—	(22)	—	(22)	—
Actuarial loss on employee retirement benefit plans, net of income taxes of $62	—	—	—	(196)	(196)	—
Total comprehensive loss	—	—	(22)	(4 515)	(4 537)	—
Issued under share option plans	36	(7)	—	—	29	804
Repurchase of common shares for cancellation <br>(note 9)	(124)	—	—	(183)	(307)	(7 527)
Change in liability for share repurchase commitment	65	—	—	103	168	—
Share-based compensation	—	32	—	—	32	—
Dividends paid on common shares	—	—	—	(1 670)	(1 670)	—
At December 31, 2020	25 144	591	877	9 145	35 757	1 525 151
Net earnings	—	—	—	4 119	4 119	—
Foreign currency translation adjustment	—	—	(63)	—	(63)	—
Actuarial gain on employee retirement benefit <br>plans, net of income taxes of $277 (note 13)	—	—	—	856	856	—
Total comprehensive (loss) income	—	—	(63)	4 975	4 912	—
Issued under share option plans	8	—	—	—	8	245
Common shares forfeited	—	—	—	—	—	(186)
Repurchase of common shares for cancellation <br>(note 9)	(1 382)	—	—	(922)	(2 304)	(83 959)
Change in liability for share repurchase commitment	(120)	—	—	(110)	(230)	—
Share-based compensation	—	21	—	—	21	—
Dividends paid on common shares	—	—	—	(1 550)	(1 550)	—
At December 31, 2021	23 650	612	814	11 538	36 614	1 441 251

See accompanying notes to the condensed interim consolidated financial statements.

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Notes to the Consolidated Financial Statements

(unaudited)

Reporting Entity and Description of the Business

Suncor Energy Inc. (Suncor or the company) is an integrated energy company headquartered in Calgary, Alberta. The company is focused on developing one of the world’s largest petroleum resource basins – Canada’s Athabasca oil sands. In addition, the company explores for, acquires, develops, produces and markets crude oil in Canada and internationally; transports and refines crude oil; and markets petroleum and petrochemical products primarily in Canada. The company also operates a renewable energy business and conducts energy trading activities focused principally on the marketing and trading of crude oil, natural gas, byproducts, refined products and power.

The address of the company’s registered office is 150 – 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3E3.

Basis of Preparation

(a) Statement of Compliance

These condensed interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards, specifically International Accounting Standard 34 Interim Financial Reporting as issued by the International Accounting Standards Board. They are condensed as they do not include all of the information required for full annual financial statements, and they should be read in conjunction with the audited consolidated financial statements of the company for the year ended December 31, 2020. Beginning in the first quarter of 2021, the company has revised the presentation of certain expenses from “transportation” to “transportation and distribution” and reclassified certain operating, selling and general expenses to transportation and distribution to better reflect the nature of these expenses. There is no impact on net earnings (loss) and comparative periods have been restated to reflect this change.

(b) Basis of Measurement

The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in the company’s audited consolidated financial statements for the year ended December 31, 2020.

These consolidated financial statements are presented in Canadian dollars, which is the company’s functional currency.

(d) Use of Estimates, Assumptions and Judgments

The timely preparation of financial statements requires that management make estimates and assumptions and use judgment. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates and judgment used in the preparation of the financial statements are described in the company’s audited consolidated financial statements for the year ended December 31, 2020.

On January 30, 2020, the World Health Organization declared the COVID-19 outbreak a Public Health Emergency of International Concern and, on March 10, 2020, declared it to be a pandemic. Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, quarantines in certain areas, and forced closures for certain types of public places and businesses. These measures have and may continue to have significant disruption to business operations and a significant increase in economic uncertainty, with fluctuating demand for commodities leading to volatile prices and currency exchange rates, and a decline in long-term interest rates. Our operations and business are particularly sensitive to a reduction in the demand for, and prices of, commodities that are closely linked to Suncor’s financial performance, including crude oil, refined petroleum products (such as jet fuel and gasoline), natural gas and electricity. The potential direct and indirect impacts of the economic volatility have been considered in management’s estimates, and assumptions at period-end have been reflected in our results with any significant changes described in the relevant notes to the company’s unaudited interim Consolidated Financial Statements for the three months and twelve months ended December 31, 2021.

(e) Income Taxes

The company recognizes the impacts of income tax rate changes in earnings in the period that the applicable rate change is enacted or substantively enacted.

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Segmented Information

The company’s operating segments are reported based on the nature of their products and services and management responsibility.

Intersegment sales of crude oil and natural gas are accounted for at market values and are included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer. Intersegment amounts are eliminated on consolidation.

Three months ended December 31	Oil Sands				Exploration and<br>Production				Refining and<br>Marketing				Corporate and<br>Eliminations				Total
($ millions)	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
Revenues and Other Income
Gross revenues		4 553		2 301		738		555		6 598		3 853		8		9		11 897		6 718
Intersegment revenues		1 403		780		—		—		25		23		(1 428)		(803)		—		—
Less: Royalties		(641)		(18)		(107)		(85)		—		—		—		—		(748)		(103)
Operating revenues, net of royalties		5 315		3 063		631		470		6 623		3 876		(1 420)		(794)		11 149		6 615
Other income (loss)		11		(13)		3		6		(2)		(10)		(2)		(4)		10		(21)
		5 326		3 050		634		476		6 621		3 866		(1 422)		(798)		11 159		6 594
Expenses
Purchases of crude oil and products		407		175		—		—		5 110		2 744		(1 447)		(762)		4 070		2 157
Operating, selling and general(1)		2 134		1 739		96		114		566		472		182		169		2 978		2 494
Transportation and distribution(1)		293		426		17		20		80		72		(10)		(11)		380		507
Depreciation, depletion, amortization and impairment		1 237		1 058		129		835		243		207		21		20		1 630		2 120
Exploration		5		(3)		11		13		—		—		—		—		16		10
(Gain) loss on disposal of assets		(4)		1		(227)		—		(1)		(18)		—		9		(232)		(8)
Financing expenses (income)		85		82		5		16		24		11		149		(354)		263		(245)
		4 157		3 478		31		998		6 022		3 488		(1 105)		(929)		9 105		7 035
Earnings (Loss) before Income Taxes		1 169		(428)		603		(522)		599		378		(317)		131		2 054		(441)
Income Tax Expense (Recovery)
Current		284		19		140		17		104		163		(31)		(148)		497		51
Deferred		(11)		(154)		(2)		(160)		45		(53)		(28)		43		4		(324)
		273		(135)		138		(143)		149		110		(59)		(105)		501		(273)
Net Earnings (Loss)		896		(293)		465		(379)		450		268		(258)		236		1 553		(168)
Capital and Exploration Expenditures		860		628		73		80		188		181		63		78		1 184		967

(1)

Prior period amounts of the Refining and Marketing segment have been reclassified to align with the current year presentation of transportation and distribution expense. For the three months ended December 31, 2020, $35 million was reclassified from operating, selling and general expense to transportation and distribution expense. This reclassification had no effect on net earnings (loss).

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Notes to the Consolidated Financial Statements

Twelve months ended December 31	Oil Sands				Exploration and<br>Production				Refining and<br>Marketing				Corporate and<br>Eliminations				Total
($ millions)	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
Revenues and Other Income
Gross revenues		15 319		7 792		2 978		1 899		22 808		15 180		28		29		41 133		24 900
Intersegment revenues		4 601		2 825		—		—		107		92		(4 708)		(2 917)		—		—
Less: Royalties		(1 523)		(95)		(478)		(143)		—		—		—		—		(2 001)		(238)
Operating revenues, net of royalties		18 397		10 522		2 500		1 756		22 915		15 272		(4 680)		(2 888)		39 132		24 662
Other income (loss)		6		298		17		54		(50)		48		(4)		(10)		(31)		390
		18 403		10 820		2 517		1 810		22 865		15 320		(4 684)		(2 898)		39 101		25 052
Expenses
Purchases of crude oil and products		1 444		844		—		—		16 807		11 243		(4 460)		(2 975)		13 791		9 112
Operating, selling and general(1)		8 056		7 169		429		476		2 019		1 759		862		390		11 366		9 794
Transportation and distribution(1)		1 126		1 223		112		100		282		271		(41)		(43)		1 479		1 551
Depreciation, depletion, amortization and impairment		4 585		6 430		324		2 147		853		867		88		82		5 850		9 526
Exploration		12		57		35		129		—		—		—		—		47		186
(Gain) loss on disposal of assets		(4)		(1)		(227)		—		(19)		(24)		(7)		9		(257)		(16)
Financing expenses		359		336		53		47		56		37		787		576		1 255		996
		15 578		16 058		726		2 899		19 998		14 153		(2 771)		(1 961)		33 531		31 149
Earnings (Loss) before Income Taxes		2 825		(5 238)		1 791		(1 089)		2 867		1 167		(1 913)		(937)		5 570		(6 097)
Income Tax Expense (Recovery)
Current		729		(645)		473		64		576		325		(383)		(403)		1 395		(659)
Deferred		(51)		(797)		33		(321)		113		(24)		(39)		23		56		(1 119)
		678		(1 442)		506		(257)		689		301		(422)		(380)		1 451		(1 778)
Net Earnings (Loss)		2 147		(3 796)		1 285		(832)		2 178		866		(1 491)		(557)		4 119		(4 319)
Capital and Exploration Expenditures		3 168		2 736		270		489		825		515		292		186		4 555		3 926

(1)

Prior period amounts of the Refining and Marketing segment have been reclassified to align with the current year presentation of transportation and distribution expense. For the twelve months ended December 31, 2020, $133 million was reclassified from operating, selling and general expense to transportation and distribution expense. This reclassification had no effect on net earnings (loss).

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Disaggregation of Revenue from Contracts with Customers and Intersegment Revenue

The company derives revenue from the transfer of goods mainly at a point in time in the following major commodities, revenue streams and geographical regions:

	Three months ended December 31			2021																		2020
	($ millions)			North America						International						Total						North America						International						Total
	Oil Sands
	Synthetic crude oil and diesel					4 457						—						4 457						2 443						—						2 443
	Bitumen					1 499						—						1 499						638						—						638
						5 956						—						5 956						3 081						—						3 081
	Exploration and Production
	Crude oil and natural gas liquids					378						354						732						299						255						554
	Natural gas					—						6						6						—						1						1
						378						360						738						299						256						555
	Refining and Marketing
	Gasoline					2 771						—						2 771						1 606						—						1 606
	Distillate					2 956						—						2 956						1 727						—						1 727
	Other					896						—						896						543						—						543
						6 623						—						6 623						3 876						—						3 876
	Corporate and Eliminations
						(1 420)						—						(1 420)						(794)						—						(794)
	Total Revenue from Contracts with Customers					11 537						360						11 897						6 462						256						6 718
	Twelve months ended December 31			2021																		2020
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	($ millions)			North America						International						Total						North America						International						Total
	Oil Sands
	Synthetic crude oil and diesel					14 452						—						14 452						8 574						—						8 574
	Bitumen					5 468						—						5 468						2 043						—						2 043
						19 920						—						19 920						10 617						—						10 617
	Exploration and Production
	Crude oil and natural gas liquids					1 709						1 257						2 966						1 089						806						1 895
	Natural gas					—						12						12						—						4						4
						1 709						1 269						2 978						1 089						810						1 899
	Refining and Marketing
	Gasoline					9 983						—						9 983						6 585						—						6 585
	Distillate					9 832						—						9 832						6 525						—						6 525
	Other					3 100						—						3 100						2 162						—						2 162
						22 915						—						22 915						15 272						—						15 272
	Corporate and Eliminations
						(4 680)						—						(4 680)						(2 888)						—						(2 888)
	Total Revenue from Contracts with Customers					39 864						1 269						41 133						24 090						810						24 900

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Notes to the Consolidated Financial Statements

Other Income (Loss)

Other income (loss) consists of the following:

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Energy trading activities
(Losses) gains recognized in earnings		(7)		(26)		43		126
(Losses) gains on inventory valuation		(11)		3		(10)		(25)
Short-term commodity risk management		(4)		(72)		(198)		49
Investment and interest income		7		16		64		94
Insurance proceeds(1)		31		47		69		96
Other		(6)		11		1		50
		10		(21)		(31)		390

(1)

The three months ended and twelve months ended December 31, 2021, includes insurance proceeds for the outage at MacKay River, and the twelve months ended December 31, 2021, includes insurance proceeds from the secondary extraction facilities at Oil Sands Base Plant, both within the Oil Sands segment. The twelve months ended December 31, 2020, includes insurance proceeds for the outage at MacKay River within the Oil Sands segment.

Share-Based Compensation

The following table summarizes the share-based compensation expense (recovery) for all plans recorded within operating, selling and general expense:

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Equity-settled plans		4		6		21		32
Cash-settled plans		121		92		301		(28)
		125		98		322		4

Financing Expenses

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Interest on debt		195		218		834		884
Interest on lease liabilities		39		40		161		166
Capitalized interest		(38)		(26)		(144)		(120)
Interest expense		196		232		851		930
Interest on partnership liability		12		13		51		52
Interest on pension and other post-retirement benefits		15		13		59		54
Accretion		77		69		304		278
Foreign exchange gain on U.S. dollar denominated debt		(25)		(602)		(113)		(312)
Operational foreign exchange and other		(12)		30		23		(6)
Loss on extinguishment of long-term debt		—		—		80		—
		263		(245)		1 255		996

Subsequent to the fourth quarter of 2021, the company completed an early redemption of its outstanding US$182 million 4.50% notes, originally scheduled to mature in the second quarter of 2022.

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During the fourth quarter of 2021, the company repaid its US$300 million (book value of $371 million) senior unsecured notes at maturity with a coupon of 9.25%, for US$314 million ($388 million), including US$14 million ($17 million) of accrued interest.

During the third quarter of 2021, the company completed an early redemption of its US$750 million (book value of $951 million) senior unsecured notes with a coupon interest of 3.60% originally scheduled to mature on December 1, 2024, for US$822 million ($1.0 billion), including US$9 million ($11 million) of accrued interest, resulting in a debt extinguishment loss of $80 million ($60 million after-tax).

In the second quarter of 2021, the company reduced the size of each tranche of its syndicated credit facilities by US$500 million and $500 million to US$2.0 billion and $3.0 billion, respectively, and extended the maturity from April 2022 and April 2023 to June 2024 and June 2025, respectively.

On March 4, 2021, the company issued US$750 million of senior unsecured notes maturing on March 4, 2051. The notes have a coupon of 3.75% and were priced at US$99.518 per US$100 principal amount for an effective yield of 3.777%. The company also issued $500 million of senior unsecured Series 8 medium-term notes on March 4, 2021, maturing on March 4, 2051. The notes have a coupon of 3.95% and were priced at $98.546 per $100 principal amount for an effective yield of 4.034%. Interest on the 3.75% and 3.95% notes is paid semi-annually.

During the first quarter of 2021, the company completed an early redemption of its $750 million senior unsecured Series 5 medium-term notes with a coupon of 3.10%, originally scheduled to mature on November 26, 2021, for $770 million, including $8 million of accrued interest, resulting in a debt extinguishment loss of $12 million ($9 million after-tax).

The company also completed an early redemption of its US$220 million (book value of $278 million) senior unsecured notes with a coupon of 9.40%, originally scheduled to mature on September 1, 2021, for US$230 million ($290 million), including US$2 million ($2 million) of accrued interest, resulting in a debt extinguishment loss of $10 million ($8 million after-tax).

Effective March 5, 2021, the company terminated $2.8 billion of bilateral credit facilities as these credit facilities were no longer required. The terminated credit facilities had a two-year term and were entered into in March and April of 2020 to ensure access to adequate financial resources in connection with the COVID-19 pandemic should they have been required.

Supplemental Cash Flow Information

The (increase) decrease in non-cash working capital is comprised of:

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Accounts receivable		(557)		(259)		(1 324)		954
Inventories		(7)		(270)		(551)		121
Accounts payable and accrued liabilities(1)		(303)		(213)		1 588		(1 605)
Current portion of provisions(1)		20		111		235		122
Income taxes payable (net)(2)		404		81		1 830		(1 350)
		(443)		(550)		1 778		(1 758)
Relating to:
Operating activities		(529)		(407)		1 507		(1 201)
Investing activities		86		(143)		271		(557)
		(443)		(550)		1 778		(1 758)

(1)

Prior period amounts of the current portion of provisions have been reclassified to conform to the current year presentation. For the year ended December 31, 2020, $133 million was reclassified from accounts payable and accrued liabilities to current portion of provisions. This reclassification had no effect on the non-cash working capital.

(2)

During the three and twelve months ended December 31, 2021, the increase in taxes payable was primarily related to the company’s 2021 current income tax expense, which is payable in early 2022.

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Notes to the Consolidated Financial Statements

Earnings (Loss) per Common Share

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions)	2021		2020		2021		2020
Net earnings (loss)		1 553		(168)		4 119		(4 319)
(millions of common shares)
Weighted average number of common shares		1 452		1 525		1 488		1 526
Dilutive securities:
Effect of share options		1		—		1		—
Weighted average number of diluted common shares		1 453		1 525		1 489		1 526
(dollars per common share)
Basic and diluted earnings (loss) per share		1.07		(0.11)		2.77		(2.83)

Normal Course Issuer Bid

During the first quarter of 2021, the company announced its intention to commence a new Normal Course Issuer Bid (the 2021 NCIB) to repurchase common shares through the facilities of the Toronto Stock Exchange (TSX), New York Stock Exchange (NYSE) and/or alternative trading systems. Pursuant to the 2021 NCIB, the company may repurchase for cancellation up to 44,000,000 common shares between February 8, 2021, and February 7, 2022.

During the third quarter of 2021, Suncor received approval from the TSX to amend the 2021 NCIB effective as of the close of markets on July 30, 2021. The amended notice provides that Suncor may increase the maximum number of common shares that may be repurchased under the 2021 NCIB from February 8, 2021, and ending February 7, 2022, from 44,000,000 common shares, or approximately 2.9% of Suncor’s issued and outstanding common shares as at January 31, 2021, to 76,250,000 common shares, or approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2021. No other terms of the NCIB were amended.

During the fourth quarter of 2021, Suncor received approval from the TSX to amend its existing NCIB effective as of the close of markets on October 29, 2021. The notice provides that Suncor may increase the maximum number of common shares that may be repurchased in the period beginning February 8, 2021, and ending February 7, 2022, from 76,250,000 shares, or approximately 5% of Suncor’s issued and outstanding common shares as at January 31, 2021, to 106,700,000, or approximately 7% of Suncor’s public float as at January 31, 2021. No other terms of the NCIB have been amended.

For the three months ended December 31, 2021, the company repurchased 20.9 million common shares under the 2021 NCIB at an average price of $30.65 per share, for a total repurchase cost of $639 million. For the twelve months ended December 31, 2021, the company repurchased 84.0 million common shares under the 2021 NCIB at an average price of $27.45 per share, for a total repurchase cost of $2.3 billion.

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The following table summarizes the share repurchase activities during the period:

	Three months ended <br>December 31				Twelve months ended <br>December 31
($ millions, except as noted)	2021		2020		2021		2020
Share repurchase activities (thousands of common shares)
Shares repurchased		20 858		—		83 959		7 527
Amounts charged to:
Share capital		343		—		1 382		124
Retained earnings		296		—		922		183
Share repurchase cost		639		—		2 304		307

Under an automatic repurchase plan agreement with an independent broker, the company has recorded the following liability for share repurchases that may take place during its internal blackout period:

($ millions)
Amounts charged to:
Share capital	120	—
Retained earnings	110	—
Liability for share purchase commitment	230	—

Financial Instruments

Derivative Financial Instruments

(a) Non-Designated Derivative Financial Instruments

The company uses derivative financial instruments, such as physical and financial contracts, to manage certain exposures to fluctuations in interest rates, short-term commodity prices and foreign currency exchange rates, as part of its overall risk management program, as well as for trading purposes.

The changes in the fair value of non-designated derivatives are as follows:

	($ millions)			Total
	Fair value outstanding at December 31, 2020					(121)
	Cash settlements – paid during the year					178
	Changes in fair value recognized in earnings during the year					(155)
	Fair value outstanding at December 31, 2021					(98)

(b) Fair Value Hierarchy

To estimate the fair value of derivatives, the company uses quoted market prices when available, or third-party models and valuation methodologies that utilize observable market data. In addition to market information, the company incorporates transaction-specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

•

Level 1 consists of instruments with a fair value determined by an unadjusted quoted price in an active market for identical assets or liabilities. An active market is characterized by readily and regularly available quoted prices where the prices are representative of actual and regularly occurring market transactions to assure liquidity.

•

Level 2 consists of instruments with a fair value that is determined by quoted prices in an inactive market, prices with observable inputs or prices with insignificant non-observable inputs. The fair value of these positions is determined using observable inputs from exchanges, pricing services, third-party independent broker quotes and published transportation tolls. The observable inputs may be adjusted using certain methods, which include extrapolation over the quoted price term and quotes for comparable assets and liabilities.

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Notes to the Consolidated Financial Statements

•

Level 3 consists of instruments with a fair value that is determined by prices with significant unobservable inputs. As at December 31, 2021, the company does not have any derivative instruments measured at fair value Level 3.

In forming estimates, the company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement.

The following table presents the company’s derivative financial instruments measured at fair value for each hierarchy level as at December 31, 2021:

($ millions)
Accounts receivable	35	88	—	123
Accounts payable	(134)	(87)	—	(221)
	(99)	1	—	(98)

During the fourth quarter of 2021, there were no transfers between Level 1 and Level 2 fair value measurements.

A substantial portion of the company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risk. While the industry has experienced credit downgrades due to the COVID-19 pandemic, Suncor has not been significantly affected as the majority of Suncor’s customers are large and established downstream companies with investment grade credit ratings.

Non-Derivative Financial Instruments

At December 31, 2021, the carrying value of fixed-term debt accounted for under amortized cost was $14.2 billion (December 31, 2020 – $15.2 billion) and the fair value was $17.4 billion (December 31, 2020 – $18.8 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

Asset Impairment

Oil Sands
Fort Hills assets:

During the fourth quarter of 2021, the company performed an asset impairment test on its Fort Hills cash generating unit (CGU) due to changes in its mine plan. The impairment test was performed using recoverable amounts based on fair value less cost of disposal. An expected cash flow approach was used with the following asset-specific assumptions (Level 3 fair value inputs):

•

Western Canada Select (WCS) price forecast of US$55.00/bbl in 2022, US$54.57/bbl in 2023, and an average price of US$50.86/bbl from 2024 to 2031, escalating at 2% per year thereafter over the life of the project up to 2058, adjusted for asset-specific location and quality differentials;

•

the company’s share of production ranging from 94,000 to 111,000 bbls/d over the life of the project;

•

cash operating costs averaging $22.00/bbl to $23.00/bbl over the life of the project (expressed in real dollars), which reflects operating, selling and general expenses adjusted for non-production costs, including share-based compensation, research costs, and excess power revenue;

•

foreign exchange rate of US$0.80 per one Canadian dollar; and

•

risk-adjusted discount rate of 7.5% (after-tax).

Factors including an improved WCS price forecast in the next two years and optimization of the mine plan to exclude high strip ratio zones were offset by higher operating and capital costs. The recoverable amount of the Fort Hills CGU was $5.5 billion as at December 31, 2021, which indicated that no impairment loss or reversal was required.

The recoverable amount estimate is most sensitive to price and discount rate. A 5% average decrease in price over the life of the project would have resulted in an impairment charge of approximately $1.0 billion (after-tax) on the company’s share of the Fort Hills assets. A 1% increase in the discount rate would have resulted in an impairment charge of approximately $0.5 billion (after-tax) on the company’s share of the Fort Hills assets.

During the first quarter of 2020, the company recorded an impairment of $1.38 billion (net of taxes of $0.44 billion) on its share of the Fort Hills assets in the Oil Sands segment.

Exploration and Production
Terra Nova assets:

In the third quarter of 2021, the company finalized an agreement with the co-owners of the Terra Nova Project to restructure the project ownership and move forward with the Asset Life Extension project. The agreement increased the company’s working

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interest to approximately 48% (previously approximately 38%) and includes royalty and financial support from the Government of Newfoundland and Labrador. The company received $26 million (net of taxes of $8 million) in cash consideration to acquire the additional 10% working interest, which was primarily allocated to the asset retirement obligation and property, plant and equipment of the project. As a result of these events, the company performed an impairment reversal test on the Terra Nova CGU as the recoverable amount of this CGU was sensitive to the financial support from the Government of Newfoundland and Labrador and revised royalty structure resulting in increased profitability and economic value. The impairment reversal test was performed using recoverable amounts based on the fair value less cost of disposal. An expected cash flow approach was used with the key assumptions discussed below (Level 3 fair value inputs – note 10).

As a result of the impairment reversal test, the recoverable amounts were determined to be greater than the carrying values of the Terra Nova CGU and the company recorded an impairment reversal of $168 million (net of taxes of $53 million) on its share of the Terra Nova assets in the Exploration and Production segment in the third quarter of 2021. In addition to the financial support from the government, the recoverable amount was determined based on the following asset-specific assumptions:

•

Brent price forecast of US$65.00/bbl in 2023 and US$68.00/bbl in 2024, escalating at 2% per year thereafter over the life of the project to 2033 and adjusted for asset-specific location and quality differentials;

•

the anticipated return to operations before the end of 2022 and the company’s share of production of approximately 6,000 bbls/d (based on its previous 38% working interest) over the life of the project; and

•

risk-adjusted discount rate of 9.0% (after-tax).

The recoverable amount of the Terra Nova CGU was $177 million as at September 30, 2021.

No indicators of impairment or reversals of impairment were identified at December 31, 2021.

During the first quarter of 2020, the company recorded an impairment of $285 million (net of taxes of $93 million) on its share of the Terra Nova assets in the Exploration and Production segment.

White Rose assets:

In the first quarter of 2020, the company recorded an impairment of $137 million (net of taxes of $45 million) on its share of the White Rose assets in the Exploration and Production segment.

In the fourth quarter of 2020, the company reassessed the likelihood of completing the West White Rose Project. As a result of this reassessment, the company performed another impairment test of the White Rose CGU. An after-tax impairment charge of $423 million (net of taxes of $136 million) was recognized and the White Rose CGU was fully impaired at December 31, 2020.

No indicators of impairment reversal were identified at December 31, 2021.

Provisions

Suncor’s decommissioning and restoration provision decreased by $1.3 billion for the twelve months ended December 31, 2021. The decrease was primarily due to an increase in the credit-adjusted risk-free interest rate to 3.70% (December 31, 2020 – 3.10%).

Pensions and Other Post-Retirement Benefits

For the twelve months ended December 31, 2021, the actuarial gain on employee retirement benefit plans was $856 million (net of taxes of $277 million) mainly due to an increase in the discount rate to 2.90% (December 31, 2020 – 2.50%).

Sale of Golden Eagle Area Development

During the fourth quarter of 2021, the company completed the sale of its 26.69% working interest in the Golden Eagle Area Development for gross proceeds of US$250 million net of closing adjustments and other closing costs, resulting in an after-tax gain on sale of $227 million ($227 million after-tax). In addition, contingent consideration of up to US$50 million is receivable in the second half of 2023, if between July 2021 and June 2023 the Dated Brent average crude price equals or exceeds US$55/bbl, upon which US$25 million is receivable; or if the Dated Brent average crude price equals or exceeds US$65/bbl, upon which US$50 million is receivable.

The company completed the sale on October 22, 2021 with an effective date of January 1, 2021. The Golden Eagle Area Development is reported within the Exploration and Production segment.

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SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION QUARTERLY FINANCIAL SUMMARY

(unaudited)

				Three months ended																													Twelve months ended
	($ millions, except per share amounts)			Dec 31 <br>2021						Sep 30 <br>2021						Jun 30 <br>2021						Mar 31 <br>2021						Dec 31 <br>2020					Dec 31 <br>2021		Dec 31 <br>2020
	Revenues, net of royalties, and other income					11 159						10 213						9 093						8 636						6 594				39 101		25 052
	Net earnings (loss)
	Oil Sands					896						484						441						326						(293)				2 147		(3 796)
	Exploration and Production					465						407						250						163						(379)				1 285		(832)
	Refining and Marketing					450						646						375						707						268				2 178		866
	Corporate and Eliminations					(258)						(660)						(198)						(375)						236				(1 491)		(557)
	Total					1 553						877						868						821						(168)				4 119		(4 319)
	Adjusted operating earnings (loss)(A)(B)(C)
	Oil Sands					898						489						465						299						(130)				2 151		(2 265)
	Exploration and Production					238						239						250						163						44				890		13
	Refining and Marketing					437						658						361						714						280				2 170		882
	Corporate and Eliminations					(279)						(343)						(354)						(430)						(303)				(1 406)		(843)
	Total					1 294						1 043						722						746						(109)				3 805		(2 213)
	Adjusted funds from (used in) operations(A)(B)
	Oil Sands					2 175						1 591						1 680						1 400						729				6 846		1 986
	Exploration and Production					425						357						411						285						312				1 478		1 054
	Refining and Marketing					765						947						581						962						415				3 255		1 708
	Corporate and Eliminations					(221)						(254)						(310)						(537)						(235)				(1 322)		(872)
	Total					3 144						2 641						2 362						2 110						1 221				10 257		3 876
	Change in non-cash working capital					(529)						2 077						(276)						235						(407)				1 507		(1 201)
	Cash flow provided by (used in) operating activities					2 615						4 718						2 086						2 345						814				11 764		2 675
	Per common share
	Net earnings (loss) – basic					1.07						0.59						0.58						0.54						(0.11)				2.77		(2.83)
	Adjusted operating earnings (loss) – basic(A)(B)(C)					0.89						0.71						0.48						0.49						(0.07)				2.56		(1.45)
	Cash dividends – basic					0.42						0.21						0.21						0.21						0.21				1.05		1.10
	Adjusted funds from operations – basic(A)(B)					2.17						1.79						1.57						1.39						0.80				6.89		2.54
	Cash flow provided by (used in) operating activities – basic					1.80						3.19						1.39						1.54						0.53				7.91		1.75
	Capital and exploration expenditures (including capitalized interest)
	Oil Sands					860						935						834						539						628				3 168		2 736
	Exploration and Production					73						64						64						69						80				270		489
	Refining and Marketing					188						142						375						120						181				825		515
	Corporate and Eliminations					63						80						74						75						78				292		186
	Total capital and exploration expenditures					1 184						1 221						1 347						803						967				4 555		3 926
				For the twelve months ended
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
				Dec 31<br>2021						Sep 30<br>2021						Jun 30<br>2021						Mar 31<br>2021						Dec 31<br>2020
	Return on capital employed(A) (%)					8.6						4.5						1.9						(1.4)						(6.9)
	Return on capital employed – excluding impairments and impairment reversals(A) (%)					8.2						4.9						2.6						(0.6)						(2.9)

(A)

Non-GAAP financial measures or contains non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Beginning in the fourth quarter of 2021, the company revised the label of operating earnings (loss) and funds from (used in) operations to adjusted operating earnings (loss) and adjusted funds from (used in) operations respectively, to better distinguish the non-GAAP financial measures from the comparable GAAP measures and better reflect the purpose of the measures. The composition of the measures remains unchanged and therefore no prior periods were restated.

(C)

Beginning in the first quarter of 2021, the company revised its adjusted operating earnings non-GAAP financial measure to exclude unrealized (gains) losses on derivative financial instruments that are recorded at fair value in other income (loss) to better align the earnings impact of the activity with the underlying items being risk-managed. Prior period comparatives have been restated to reflect this change.

See accompanying footnotes and definitions to the quarterly operating summaries.

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QUARTERLY OPERATING SUMMARY

(unaudited)

	Three months ended										Twelve months ended
Oil Sands	Dec 31<br>2021		Sep 30<br>2021		Jun 30<br>2021		Mar 31<br>2021		Dec 31<br>2020		Dec 31<br>2021		Dec 31<br>2020
Production Volumes (mbbls/d)
Upgraded product (SCO and diesel) production
Oil Sands operations		332.7		221.0		326.8		329.6		309.7		301.6		303.1
Syncrude		182.3		184.5		110.4		190.3		204.6		167.0		163.1
Total upgraded production		515.0		405.5		437.2		519.9		514.3		468.6		466.2
Non-upgraded bitumen production
Oil Sands operations		95.4		148.8		133.2		119.5		94.8		124.9		69.1
Fort Hills		55.5		50.8		45.3		51.2		62.4		50.7		58.1
Total Oil Sands non-upgraded bitumen production		150.9		199.6		178.5		170.7		157.2		175.6		127.2
Total Oil Sands production volumes		665.9		605.1		615.7		690.6		671.5		644.2		593.4
Oil Sands sales volumes (mbbls/d)
Upgraded product (SCO and diesel)		496.1		418.6		433.9		515.2		495.6		465.7		467.9
Non-upgraded bitumen		176.7		194.4		183.5		180.2		139.6		183.8		125.6
Total Oil Sands sales volumes		672.8		613.0		617.4		695.4		635.2		649.5		593.5
Oil Sands operations cash operating costs(1)(A) ($ millions)
Cash costs		952		884		910		858		900		3 603		3 571
Natural gas		193		135		111		115		114		554		363
		1 145		1 019		1 021		973		1 014		4 157		3 934
Oil Sands operations cash operating costs(1)(A) ($/bbl)*
Cash costs		23.40		25.20		21.25		20.60		23.50		22.45		25.60
Natural gas		4.70		3.85		2.60		2.70		3.00		3.45		2.60
		28.10		29.05		23.85		23.30		26.50		25.90		28.20
Fort Hills cash operating costs(1)(A) ($ millions)
Cash costs		214		178		159		156		169		706		657
Natural gas		19		14		11		14		13		58		41
		233		192		170		170		182		764		698
Fort Hills cash operating costs(1)(A) ($/bbl)*
Cash costs		41.85		38.00		38.60		33.95		29.40		38.20		30.90
Natural gas		3.70		2.90		2.75		3.10		2.15		3.15		1.90
		45.55		40.90		41.35		37.05		31.55		41.35		32.80
Syncrude cash operating costs(1)(A) ($ millions)
Cash costs		561		521		493		537		521		2 111		1 974
Natural gas		30		22		27		24		22		104		76
		591		543		520		561		543		2 215		2 050
Syncrude cash operating costs(1)(A) ($/bbl)*
Cash costs		31.80		29.75		47.65		30.85		27.30		33.55		32.55
Natural gas		1.70		1.30		2.60		1.40		1.15		1.65		1.25
		33.50		31.05		50.25		32.25		28.45		35.20		33.80

(A)

Non-GAAP financial measures or contains non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 63

TABLE OF CONTENTS

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	Three months ended										Twelve months ended
Oil Sands Segment Operating Netbacks(A)(B)	Dec 31<br>2021		Sep 30<br>2021		Jun 30<br>2021		Mar 31<br>2021		Dec 31<br>2020		Dec 31<br>2021		Dec 31<br>2020
Bitumen ($/bbl)
Average price realized		67.47		65.53		55.54		47.57		34.06		59.16		28.44
Royalties		(9.50)		(7.99)		(3.65)		(0.83)		(0.25)		(5.53)		(0.32)
Transportation and distribution costs		(5.42)		(5.62)		(5.34)		(5.04)		(5.16)		(5.36)		(6.07)
Net operating expenses		(20.92)		(18.10)		(15.55)		(13.88)		(19.84)		(17.13)		(20.14)
Operating netback		31.63		33.82		31.00		27.82		8.81		31.14		1.91
SCO and diesel ($/bbl)
Average price realized		93.87		84.80		81.34		69.40		51.34		82.24		48.19
Royalties		(10.64)		(9.33)		(4.01)		(3.10)		(0.31)		(6.75)		(0.45)
Transportation and distribution costs		(4.49)		(4.59)		(4.84)		(4.18)		(3.75)		(4.51)		(4.36)
Net operating expenses		(29.34)		(33.44)		(32.04)		(26.64)		(26.94)		(30.16)		(29.45)
Operating netback		49.40		37.44		40.45		35.48		20.34		40.82		13.93
Average Oil Sands segment ($/bbl)
Average price realized		86.94		78.69		73.67		63.73		47.54		75.71		44.01
Royalties		(10.36)		(8.91)		(3.90)		(2.50)		(0.31)		(6.41)		(0.44)
Transportation and distribution costs		(4.74)		(4.91)		(4.99)		(4.41)		(4.06)		(4.75)		(4.72)
Net operating expenses		(27.13)		(28.58)		(27.14)		(23.34)		(25.38)		(26.48)		(27.48)
Operating netback		44.71		36.29		37.64		33.48		17.79		38.07		11.37

(A)

Contains non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Netbacks are based on sales volumes. Impact of inventory write-down is excluded until product is sold.

See accompanying footnotes and definitions to the quarterly operating summaries.

64 2021 Fourth Quarter Suncor Energy Inc.

TABLE OF CONTENTS

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	Three months ended										Twelve months ended
Exploration and Production	Dec 31<br>2021		Sep 30<br>2021		Jun 30<br>2021		Mar 31<br>2021		Dec 31<br>2020		Dec 31<br>2021		Dec 31<br>2020
Production Volumes
Exploration and Production Canada (mbbls/d)		47.6		54.4		57.5		58.0		56.8		54.4		59.7
Exploration and Production International (mboe/d)		29.8		39.1		26.5		37.3		40.9		33.1		42.0
Total production volumes (mboe/d)		77.4		93.5		84.0		95.3		97.7		87.5		101.7

Total Sales Volumes (mboe/d)		67.2		76.3		103.8		84.2		98.8		82.8		102.6
Operating Netbacks(A)(B)
East Coast Canada ($/bbl)
Average price realized		101.87		92.88		82.24		76.09		56.44		87.04		52.62
Royalties		(14.59)		(11.88)		(13.26)		(9.24)		(6.83)		(12.20)		(4.30)
Transportation and distribution costs		(3.45)		(2.65)		(1.59)		(2.18)		(2.19)		(2.34)		(2.93)
Operating costs		(13.42)		(12.87)		(10.27)		(11.27)		(12.21)		(11.74)		(12.23)
Operating netback		70.41		65.48		57.12		53.40		35.21		60.76		33.16
International excluding Libya ($/boe)
Average price realized		102.80		89.19		80.41		72.05		54.93		84.76		52.51
Transportation and distribution costs		(2.66)		(3.90)		(1.59)		(2.54)		(2.10)		(2.60)		(2.23)
Operating costs		(10.19)		(10.30)		(13.20)		(8.05)		(7.51)		(10.40)		(7.06)
Operating netback		89.95		74.99		65.62		61.46		45.32		71.76		43.22

(A)

Contains non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Netbacks are based on sales volumes.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 65

TABLE OF CONTENTS

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	Three months ended										Twelve months ended
Refining and Marketing	Dec 31 <br>2021		Sep 30 <br>2021		Jun 30 <br>2021		Mar 31 <br>2021		Dec 31 <br>2020		Dec 31 <br>2021		Dec 31 <br>2020
Refined product sales (mbbls/d)		550.1		551.5		463.3		548.1		508.8		528.4		503.4
Crude oil processed (mbbls/d)		447.0		460.3		325.3		428.4		438.0		415.5		407.0
Rack forward sales volume (ML)		5 359		5 414		4 791		4 866		4 918		20 430		19 503
Utilization of refining capacity (%)		96		99		70		92		95		89		88
Refining and marketing gross margin – first-in, <br>first-out (FIFO) ($/bbl)(A)		33.60		35.75		38.00		40.75		25.75		36.85		25.30
Refining and marketing gross margin – last-in, <br>first-out (LIFO) ($/bbl)(A)		30.00		33.80		29.05		30.30		25.05		30.90		28.65
Rack forward gross margin (cpl)(A)(B)		6.40		7.10		8.30		6.75		7.70		7.10		7.10
Refining operating expense ($/bbl)(A)		6.10		5.45		6.65		5.75		5.20		5.95		5.50
Rack forward operating expense (cpl)(A)(B)		2.95		2.80		3.10		2.80		3.00		2.90		2.95
Eastern North America
Refined product sales (mbbls/d)
Transportation fuels
Gasoline		113.5		114.1		97.5		115.6		105.5		110.2		103.6
Distillate		103.1		93.7		86.4		95.8		94.9		94.7		91.9
Total transportation fuel sales		216.6		207.8		183.9		211.4		200.4		204.9		195.5
Petrochemicals		13.8		10.3		12.4		12.9		8.9		12.4		9.1
Asphalt		20.6		22.4		16.5		12		15.9		17.9		14.9
Other		21.2		21.7		15.4		25.6		24.3		21.0		23.5
Total refined product sales		272.2		262.2		228.2		261.9		249.5		256.2		243.0
Crude oil supply and refining
Processed at refineries (mbbls/d)		214.3		212.3		183.7		200.5		212.6		202.8		201.0
Utilization of refining capacity (%)		97		96		83		90		96		91		91
Western North America
Refined product sales (mbbls/d)
Transportation fuels
Gasoline		119.2		122.4		103.5		117.0		107.4		115.6		110.5
Distillate		134.8		140.1		110.5		149.9		128.0		133.8		123.8
Total transportation fuel sales		254.0		262.5		214.0		266.9		235.4		249.4		234.3
Asphalt		10.1		13.8		8.8		6.0		9.9		9.7		12.6
Other		13.8		13.0		12.3		13.3		14.0		13.1		13.5
Total refined product sales		277.9		289.3		235.1		286.2		259.3		272.2		260.4
Crude oil supply and refining
Processed at refineries (mbbls/d)		232.7		248.0		141.6		227.9		225.4		212.7		206.0
Utilization of refining capacity(C) (%)		95		102		58		93		94		87		86

(A)

Contains non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

In Q2 2021, the company began disclosing refinery rack forward margin and operating expenses to increase transparency into Suncor’s integrated model and align with how management evaluates the performance of the business. Rack forward encompasses Suncor’s retail and wholesale business. As an integrated oil and gas company, transfer prices are used to attribute margin to the value chain. The company’s transfer prices affecting the refining, supply and rack forward businesses employ replacement cost methodology, which may differ from those subject to supply agreements negotiated by independent market participants. Rack forward margins may include any incremental location differentials above replacement supply cost, as well as the applicable retail and wholesale channel margins generated within those markets.

(C)

The Edmonton refinery crude processing capacity has increased to 146,000 bbls/d in 2021 from 142,000 bbls/d in 2020.

See accompanying footnotes and definitions to the quarterly operating summaries.

66 2021 Fourth Quarter Suncor Energy Inc.

TABLE OF CONTENTS

QUARTERLY OPERATING METRICS RECONCILIATION

(unaudited)

Oil Sands Operating Netbacks(A)(B)

($ millions, except per barrel amounts)

				December 31, 2021																		September 30, 2021
	For the quarter ended			Bitumen						SCO and<br>Diesel						Oil Sands<br>Segment						Bitumen						SCO and<br>Diesel						Oil Sands<br>Segment
	Operating revenues, net of royalties					1 344						3 971						5 315						1 478						2 995						4 473
	Add: royalties					155						486						641						145						359						504
	Operating revenues					1 499						4 457						5 956						1 623						3 354						4 977
	Other (loss) income					7						4						11						1						75						76
	Purchases of crude oil and products					(320)						(87)						(407)						(387)						(55)						(442)
	Gross realization adjustment(2)					(88)						(92)												(65)						(109)
	Gross realizations					1 098						4 282												1 172						3 265
	Royalties					(155)						(486)						(641)						(145)						(359)						(504)
	Transportation and distribution					(88)						(205)						(293)						(100)						(177)						(277)
	Operating, selling and general					(434)						(1 700)						(2 134)						(422)						(1 582)						(2 004)
	Operating, selling and general adjustment(4)					94						361												99						294
	Net operating expenses					(340)						(1 339)												(323)						(1 288)
	Operating netback					515						2 252												604						1 441
	Sales volumes (mbbls)					16 260						45 644												17 888						38 507
	Operating netback per barrel					31.63						49.40												33.82						37.44
				June 30, 2021																		March 31, 2021
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	For the quarter ended			Bitumen						SCO and<br>Diesel						Oil Sands<br>Segment						Bitumen						SCO and<br>Diesel						Oil Sands<br>Segment
	Operating revenues, net of royalties					1 280						3 136						4 416						990						3 203						4 193
	Add: royalties					62						158						220						14						144						158
	Operating revenues					1 342						3 294						4 636						1 004						3 347						4 351
	Other (loss) income					(71)						(8)						(79)						7						(9)						(2)
	Purchases of crude oil and products					(321)						(24)						(345)						(203)						(47)						(250)
	Gross realization adjustment(2)					(22)						(50)												(35)						(74)
	Gross realizations					928						3 212												773						3 217
	Royalties					(62)						(158)						(220)						(14)						(144)						(158)
	Transportation and distribution					(89)						(191)						(280)						(82)						(194)						(276)
	Operating, selling and general					(360)						(1 585)						(1 945)						(325)						(1 648)						(1 973)
	Operating, selling and general adjustment(4)					101						317												100						413
	Net operating expenses					(259)						(1 268)												(225)						(1 235)
	Operating netback					518						1 595												452						1 644
	Sales volumes (mbbls)					16 700						39 489												16 246						46 343
	Operating netback per barrel					31.00						40.45												27.82						35.48

(A)

Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Impact of inventory write-down is excluded until product is sold.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 67

TABLE OF CONTENTS

QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Oil Sands Operating Netbacks(A)(B)

($ millions, except per barrel amounts)

	December 31, 2020
For the quarter ended	Bitumen		SCO and<br>Diesel		Oil Sands<br>Segment
Operating revenues, net of royalties		634		2 429		3 063
Add: royalties		4		14		18
Operating revenues		638		2 443		3 081
Other (loss) income		(9)		(4)		(13)
Purchases of crude oil and products		(128)		(47)		(175)
Gross realization adjustment(2)		(63)		(51)
Gross realizations		438		2 341
Royalties		(4)		(14)		(18)
Transportation and distribution		(256)		(170)		(426)
Transportation and distribution adjustment(3)		189		—
Net transportation and distribution		(67)		(170)
Operating, selling and general		(261)		(1 478)		(1 739)
Operating, selling and general adjustment(4)		6		250
Net operating expenses		(255)		(1 228)
Operating netback		112		929
Sales volumes (mbbls)		12 837		45 601
Operating netback per barrel		8.81		20.34

(A)

Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Impact of inventory write-down is excluded until product is sold.

See accompanying footnotes and definitions to the quarterly operating summaries.

68 2021 Fourth Quarter Suncor Energy Inc.

TABLE OF CONTENTS

QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Oil Sands Operating Netbacks(A)(B)

($ millions, except per barrel amounts)

	December 31, 2021						December 31, 2020
For the twelve months ended	Bitumen		SCO and<br>Diesel		Oil Sands<br>Segment		Bitumen		SCO and<br>Diesel		Oil Sands<br>Segment
Operating revenues, net of royalties		5 092		13 305		18 397		2 024		8 498		10 522
Add: royalties		376		1 147		1 523		19		76		95
Operating revenues		5 468		14 452		19 920		2 043		8 574		10 617
Other (loss) income		(56)		62		6		21		277		298
Purchases of crude oil and products		(1 231)		(213)		(1 444)		(702)		(142)		(844)
Gross realization adjustment(2)		(210)		(325)				(54)		(458)
Gross realizations		3 971		13 976				1 308		8 251
Royalties		(376)		(1 147)		(1 523)		(19)		(76)		(95)
Royalties adjustment		—		—				4		—
Net royalties		(376)		(1 147)				(15)		(76)
Transportation and distribution		(359)		(767)		(1 126)		(476)		(747)		(1 223)
Transportation and distribution adjustment(3)		—		—				197		—
Net transportation and distribution		(359)		(767)				(279)		(747)
Operating, selling and general		(1 541)		(6 515)		(8 056)		(1 029)		(6 140)		(7 169)
Operating, selling and general adjustment(4)		394		1 385				103		1 099
Net operating expenses		(1 147)		(5 130)				(926)		(5 041)
Operating netback		2 089		6 932				88		2 387
Sales volumes (mbbls)		67 094		169 983				45 980		171 211
Operating netback per barrel		31.14		40.82				1.91		13.93

(A)

Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Impact of inventory write-down is excluded until product is sold.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 69

TABLE OF CONTENTS

QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Exploration and Production Operating Netbacks(A)

($ millions, except per barrel amounts)

				December 31, 2021																								September 30, 2021
	For the quarter ended			International						East Coast<br>Canada						Other(5)						E&P<br>Segment						International						East Coast<br>Canada						Other(5)						E&P<br>Segment
	Operating revenues, net of royalties					215						324						92						631						185						372						78						635
	Add: royalties					—						54						53						107						—						55						54						109
	Operating revenues					215						378						145						738						185						427						132						744
	Royalties					—						(54)						(53)						(107)						—						(55)						(54)						(109)
	Transportation and distribution					(6)						(11)						—						(17)						(8)						(13)						(2)						(23)
	Operating, selling and general					(28)						(61)						(7)						(96)						(29)						(66)						(6)						(101)
	Non-production costs(6)					8						11																		7						9
	Operating netback					189						263																		155						302
	Sales volumes (mboe)					2 111						3 724																		2 058						4 613
	Operating netback per barrel					89.95						70.41																		74.99						65.48
				June 30, 2021																								March 31, 2021
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	For the quarter ended			International						East Coast<br>Canada						Other(5)						E&P<br>Segment						International						East Coast<br>Canada						Other(5)						E&P<br>Segment
	Operating revenues, net of royalties					211						434						43						688						204						317						25						546
	Add: royalties					—						84						134						218						—						44						—						44
	Operating revenues					211						518						177						906						204						361						25						590
	Royalties					—						(84)						(134)						(218)						—						(44)						—						(44)
	Transportation and distribution					(4)						(10)						(6)						(20)						(7)						(10)						(35)						(52)
	Operating, selling and general					(43)						(75)						(4)						(122)						(33)						(66)						(11)						(110)
	Non-production costs(6)					8						11																		10						12
	Operating netback					172						360																		174						253
	Sales volumes (mboe)					2 619						6 301																		2 828						4 748
	Operating netback per barrel					65.62						57.12																		61.46						53.40
				December 31, 2020
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
	For the quarter ended			International						East Coast<br>Canada						Other(5)						E&P<br>Segment
	Operating revenues, net of royalties					193						263						14						470
	Add: royalties					—						36						49						85
	Operating revenues					193						299						63						555
	Royalties					—						(36)						(49)						(85)
	Transportation and distribution					(7)						(12)						(1)						(20)
	Operating, selling and general					(32)						(71)						(11)						(114)
	Non-production costs(6)					5						6
	Operating netback					159						186
	Sales volumes (mboe)					3 511						5 294
	Operating netback per barrel					45.32						35.21

(A)

Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

70 2021 Fourth Quarter Suncor Energy Inc.

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QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Exploration and Production Operating Netbacks(A)

($ millions, except per barrel amounts)

	December 31, 2021								December 31, 2020
For the twelve months ended	International		East Coast<br>Canada		Other(5)		E&P<br>Segment		International		East Coast<br>Canada		Other(5)		E&P<br>Segment
Operating revenues, net of royalties		815		1 447		238		2 500		809		1 058		(111)		1 756
Add: royalties		—		237		241		478		—		94		49		143
Operating revenues		815		1 684		479		2 978		809		1 152		(62)		1 899
Royalties		—		(237)		(241)		(478)		—		(94)		(49)		(143)
Transportation and distribution		(25)		(44)		(43)		(112)		(34)		(65)		(1)		(100)
Operating, selling and general		(133)		(268)		(28)		(429)		(131)		(301)		(44)		(476)
Non-production costs(6)		33		43						21		33
Operating netback		690		1 178						665		725
Sales volumes (mboe)		9 616		19 386						15 406		21 879
Operating netback per barrel		71.76		60.76						43.22		33.16

(A)

Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 71

TABLE OF CONTENTS

QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Refining and Marketing

($ millions, except as noted)

		Three months ended										Twelve months ended
Refining and marketing gross margin reconciliation		Dec 31<br>2021		Sep 30<br>2021		Jun 30<br>2021		Mar 31<br>2021		Dec 31<br>2020		Dec 31<br>2021		Dec 30<br>2020
Operating revenues			6 623		6 341		4 938		5 013		3 876		22 915		15 272
Purchases of crude oil and products			(5 110)		(4 710)		(3 712)		(3 275)		(2 744)		(16 807)		(11 243)
			1 513		1 631		1 226		1 738		1 132		6 108		4 029
Other (loss) income			(2)		(9)		6		(45)		(10)		(50)		48
Non-refining and marketing margin(7)			(14)		(13)		(14)		(13)		(14)		(54)		(57)
Refining and marketing gross margin – FIFO(A)			1 497		1 609		1 218		1 680		1 108		6 004		4 020
Refinery production (mbbls)(8)			44 575		45 026		32 050		41 211		43 036		162 862		158 991
Refining and marketing gross margin – <br>FIFO ($/bbl)(A)			33.60		35.75		38.00		40.75		25.75		36.85		25.30
FIFO and short-term risk management activities adjustment(B)			(161)		(91)		(288)		(432)		(30)		(972)		532
Refining and marketing gross margin – LIFO(A)			1 336		1 518		930		1 248		1 078		5 032		4 552
Refining and marketing gross margin – <br>LIFO ($/bbl)(A)(B)(C)			30.00		33.80		29.05		30.30		25.05		30.90		28.65
Rack forward gross margin(D)
Refining and marketing gross margin – FIFO(A)			1 497		1 609		1 218		1 680		1 108		6 004		4 020
Refining and supply gross margin			(1 154)		(1 225)		(820)		(1 351)		(728)		(4 550)		(2 634)
Rack forward gross margin(A)(9)			343		384		398		329		380		1 454		1 386
Sales volume (ML)			5 359		5 414		4 791		4 866		4 918		20 430		19 503
Rack forward gross margin (cpl)(A)			6.40		7.10		8.30		6.75		7.70		7.10		7.10
Refining and rack forward operating expense reconciliation
Operating, selling and general(E)			566		502		472		479		472		2 019		1 759
Less: Rack forward operating expense(A)(D)(10)	A		159		151		148		136		148		594		572
Less: Other operating expenses(11)			135		105		111		106		100		457		313
Refining operating expense(A)	B		272		246		213		237		224		968		874
Refinery production (mbbls)(8)	C		44 575		45 026		32 050		41 211		43 036		162 862		158 991
Refining operating expense ($/bbl)(A)	B/C		6.10		5.45		6.65		5.75		5.20		5.95		5.50
Sales volume (ML)	D		5 359		5 414		4 791		4 866		4 918		20 430		19 503
Rack forward operating expense (cpl)(A)(D)	A/D		2.95		2.80		3.10		2.80		3.00		2.90		2.95

(A)

Non-GAAP financial measures or contains non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

(B)

Refining and marketing margin – LIFO excludes the impact of short-term risk management activities.

(C)

The Suncor 5-2-2-1 index is most comparable to the company’s realized refining and marketing margin presented on a LIFO basis.

(D)

(E)

Prior period amounts of operating, selling and general expense have been reclassified to align with the current year presentation of transportation and distribution expense. This reclassification had no effect on the refining operating expense.

See accompanying footnotes and definitions to the quarterly operating summaries.

72 2021 Fourth Quarter Suncor Energy Inc.

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QUARTERLY OPERATING METRICS RECONCILIATION (continued)

(unaudited)

Refining and Marketing
Suncor custom 5-2-2-1 index(A)(12)

(US$/bbl, except as noted)		Three months ended										Twelve months ended
(average for the three months and twelve months ended)		Dec 31<br>2021		Sep 30<br>2021		Jun 30<br>2021		Mar 31<br>2021		Dec 31<br>2020		Dec 31<br>2021		Dec 31<br>2020
WTI crude oil at Cushing			77.15		70.55		66.05		57.80		42.65		67.95		39.40
SYN crude oil at Edmonton			75.35		68.95		66.40		54.30		39.60		66.30		36.25
WCS at Hardisty			62.50		56.95		54.60		45.40		33.35		54.90		26.85
New York Harbor 2-1-1 crack(B)			20.65		20.90		20.35		15.60		9.85		19.40		11.75
Chicago 2-1-1 crack(B)			16.90		20.45		20.25		13.40		7.95		17.75		8.05
Product value
New York Harbor 2-1-1 crack(C)	40%		39.10		36.60		34.55		29.35		21.00		34.95		20.45
Chicago 2-1-1 crack(D)	40%		37.60		36.40		34.50		28.50		20.25		34.30		19.00
WTI	20%		15.45		14.10		13.20		11.55		8.55		13.60		7.90
Seasonality factor			6.50		5.00		5.00		6.50		6.50		5.75		5.75
			98.65		92.10		87.25		75.90		56.30		88.60		53.10
Crude value
SYN	40%		30.15		27.60		26.55		21.70		15.85		26.50		14.50
WCS	40%		25.00		22.80		21.85		18.15		13.35		21.95		10.75
WTI	20%		15.45		14.10		13.20		11.55		8.55		13.60		7.90
			70.60		64.50		61.60		51.40		37.75		62.05		33.15
Suncor custom 5-2-2-1 index			28.05		27.60		25.65		24.50		18.55		26.55		19.95
Suncor custom 5-2-2-1 index (Cdn$/bbl)(A)			35.35		34.80		31.50		31.05		24.50		33.30		26.75

(A)

The Suncor 5-2-2-1 index is most comparable to the company’s realized refining and marketing margin presented on a LIFO basis.

(B)

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.

(C)

Product value of the New York Harbor 2-1-1 crack is calculated by adding the values of the New York Harbor 2-1-1 crack and WTI, multiplying it by 40% and rounding to the nearest nickel.

(D)

Product value of the Chicago 2-1-1 crack is calculated by adding the values of the Chicago 2-1-1 crack and WTI, multiplying it by 40% and rounding to the nearest nickel.

See accompanying footnotes and definitions to the quarterly operating summaries.

2021 Fourth Quarter Suncor Energy Inc. 73

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Operating Summary Information

Non-GAAP Financial Measures

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining and marketing gross margin, rack forward gross margin, refining operating expense, rack forward operating expense and netbacks – are not prescribed by generally accepted accounting principles (GAAP). Suncor uses this information to analyze business performance, leverage and liquidity and includes these financial measures because investors may find such measures useful 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. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

Operating earnings (loss), Oil Sands operations cash operating costs, Fort Hills cash operating costs and Syncrude cash operating costs are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of each respective quarterly Report to Shareholders issued by Suncor in respect of the relevant quarter (Quarterly Reports). Funds from (used in) operations and ROCE are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective Quarterly Report. Refining and marketing gross margin, rack forward gross margin, refining operating expense and rack forward operating expense are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Operating Metrics Reconciliation section of each respective Quarterly Report. Netbacks are defined below and are reconciled to GAAP measures in the Quarterly Operating Metrics Reconciliation section of each respective Quarterly Report. The remainder of the non-GAAP financial measures not otherwise mentioned in this paragraph are defined and reconciled in this Quarterly Report.

Oil Sands Netbacks

Oil Sands operating netbacks are a non-GAAP measure, presented on a crude product and sales barrel basis, and are derived from the Oil Sands segmented statement of net earnings (loss), after adjusting for items not directly attributable to the revenues and costs associated with production and delivery. Management uses Oil Sands operating netbacks to measure crude product profitability on a sales barrel basis.

Exploration and Production (E&P) Netbacks

E&P netbacks are a non-GAAP measure, presented on an asset location and sales barrel basis, and are derived from the E&P segmented statement of net earnings (loss), after adjusting for items not directly attributable to the revenues and costs associated with production and delivery. Management uses E&P netbacks to measure asset profitability by location on a sales barrel basis.

Definitions

(1)

Cash operating costs are calculated by adjusting Oil Sands segment operating, selling and general expense for i) non-production costs that management believes do not relate to production performance, including, but not limited to, share-based compensation adjustments, Canada’s Emergency Wage Subsidy (CEWS) and COVID-19 related costs, research costs, adjustments to reflect the cost of internal transfers in the receiving asset at the cost of production and the expense recorded as part of a non-monetary arrangement involving a third-party processor; ii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; iii) project startup costs; and iv) the impacts of changes in inventory levels and valuation, such that the company is able to present cost information based on production volumes. Oil Sands operations and Syncrude production volumes are gross of internally consumed diesel and feedstock transfers between assets through the interconnecting pipelines.

(2)

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.

(3)

Reflects adjustments for expenses or credits not directly related to the transportation of the crude product to its deemed point of sale.

(4)

Reflects adjustments for general and administrative costs not directly attributed to the production of each crude product type, as well as the revenues associated with excess power from cogeneration units.

(5)

Reflects adjustments for royalties not related to crude products.

(6)

Reflects other E&P assets, such as Libya, for which netbacks are not provided.

(7)

Reflects adjustments for general and administrative costs not directly attributed to production.

(8)

Reflects adjustments for intersegment marketing fees and impact of inventory write-downs.

(9)

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.

(10)

Rack forward operating revenues, other income less purchases of crude oil and products.

(11)

Reflects operating, selling and general expenses associated with the company’s ethanol businesses, certain general and administrative costs not directly attributable to refinery production, and CEWS amounts.

74 2021 Fourth Quarter Suncor Energy Inc.

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(12)

The custom 5-2-2-1 index is designed to represent Suncor’s Refining and Marketing business based on publicly available pricing data and approximates the gross margin on five barrels of crude oil of varying grades that is refined to produce two barrels of both gasoline and distillate and one barrel of secondary product. The index is a single value that is calculated by taking the product value of refined products less the crude value of refinery feedstock incorporating the company’s refining, product supply and rack forward businesses, but excluding the impact of first-in, first-out accounting. The product value is influenced by New York Harbor 2-1-1 crack, Chicago 2-1-1 crack, WTI benchmarks and seasonal factors. The seasonal factor is an estimate and reflects the location, quality and grade differentials for refined products sold in the company’s core markets during the winter and summer months. The crude value is influenced by SYN, WCS and WTI benchmarks.

Explanatory Notes

Users are cautioned that the Oil Sands operations, Fort Hills and Syncrude cash operating costs per barrel measures may not be fully comparable to one another or to similar information calculated by other entities due to differing operations of each entity as well as other entities’ respective accounting policy choices.

Abbreviations

	bbl			– barrel
	bbls/d			– barrels per day
	mbbls			– thousands of barrels
	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
	cpl			– cents per litre
	ML			– million of litres
	WTI			– West Texas intermediate
	SYN			– sweet synthetic crude oil
	WCS			– Western Canadian Select

Metric Conversion

1 m3 (cubic metre) = approximately 6.29 barrels

2021 Fourth Quarter Suncor Energy Inc. 75

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Suncor Energy Inc 6-K, filed Feb 3, 2022

About this 6-K