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 the company's 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 Suncor Energy Inc.'s (Suncor or the company) Management's Discussion and Analysis (MD&A) dated October 28, 2020. See also the Advisories section of the MD&A. References to Oil Sands operations exclude Suncor's interests in Fort Hills and Syncrude.

"We remain steadfast in our commitment to the safety and reliability of our operations as we continue to navigate the impact of the COVID-19 pandemic," said Mark Little, president and chief executive officer. "Although the pandemic continues to have adverse impacts on our industry, we remain focused on items within our control, including the safety of our workforce and communities, and structural changes that lower our cost base, preserve the financial resiliency of the company and set the foundation for long-term value creation."

Suncor's third quarter 2020 operating loss was $302 million ($0.20 per common share), compared to operating earnings of $1.114 billion ($0.72 per common share) in the prior year quarter. In the third quarter of 2020, crude oil and refined product realizations decreased significantly from the prior year quarter, with crude oil and crack spread benchmarks declining by more than 25%, primarily due to the impacts of the COVID-19 pandemic. Upstream production decreased as the company experienced an operational incident at Oil Sands Base Plant and Fort Hills continued operating on one primary extraction train. Refinery crude throughput decreased compared to the prior year quarter due to planned maintenance activities and lower demand for transportation fuels as a result of the COVID-19 pandemic. Operating losses in the third quarter of 2020 were minimized by the decrease in operating, selling and general expenses associated with lower production and the continued execution of the company's cost reduction initiatives.

Suncor's net loss was $12 million ($0.01 per common share) in the third quarter of 2020, compared to net earnings of $1.035 billion ($0.67 per common share) in the prior year quarter. In addition to the factors impacting operating (loss) earnings discussed above, the net loss for the third quarter of 2020 included a $290 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt. Net earnings in the prior year quarter included a $127 million unrealized after-tax foreign exchange loss on the revaluation of U.S. dollar denominated debt and an after-tax gain of $48 million in the Exploration and Production (E&P) segment related to the sale of certain non-core assets.

Funds from operations were $1.166 billion ($0.76 per common share) in the third quarter of 2020, compared to $2.675 billion ($1.72 per common share) in the third quarter of 2019, and were influenced by the same factors impacting operating (loss) earnings noted above.

Cash flow provided by operating activities, which includes changes in non-cash working capital, was $1.245 billion ($0.82 per common share) for the third quarter of 2020, compared to $3.136 billion ($2.02 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 lower source of cash associated with the company's working capital balances in the third quarter of 2020 compared to the prior year quarter. The source of cash was primarily due to an increase in accrued liabilities relative to the second quarter of 2020, partially offset by an increase in income taxes receivable due to tax losses incurred, which are expected to be received in 2021.

Suncor's total upstream production was 616,200 boe/d during the third quarter of 2020, compared to 762,300 boe/d in the prior year quarter. Synthetic crude oil (SCO) production decreased to 410,800 bbls/d in the third quarter of 2020 from 479,300 bbls/d in the third quarter of 2019, resulting in combined upgrader utilization rates of 75% and 87%, respectively, with both periods impacted by planned maintenance at Oil Sands operations and Syncrude and, in the third quarter of 2020, by an operational incident at the secondary extraction facilities at Oil Sands Base Plant. Production was restored to 165,000 bbls/d of mined bitumen, within approximately two weeks of the incident, as production was restricted to manage bitumen quality into the upgraders. Subsequent to the third quarter of 2020, repairs were substantially completed and production is anticipated to ramp up to full rates by early November 2020. To mitigate the impact of this event, the company diverted bitumen production from Firebag to the upgraders to maximize the production of higher value SCO barrels. As a result, overall Oil Sands production was also reduced by the yield loss associated with upgrading In Situ bitumen to SCO.

Non-upgraded bitumen production decreased to 108,200 bbls/d in the third quarter of 2020 from 190,700 bbls/d in the third quarter of 2019, as bitumen production from Firebag was diverted to the upgrader to maximize value over volume and as Fort Hills continued operating on one primary extraction train throughout the third quarter of 2020. At the end of the third quarter of 2020, the company also accelerated a portion of Firebag maintenance originally scheduled for 2022, to expand the capacity of the facility through the installation of new incremental emulsion handling and steam infrastructure and also address plant restrictions that developed during the quarter. This maintenance was substantially completed subsequent to the third quarter of 2020.

At Fort Hills, the second primary extraction train was restarted in the third quarter of 2020. Subsequent to the third quarter of 2020, the restart was completed with Fort Hills now on track to achieve its updated gross production guidance of between 120,000 and 130,000 bbls/d in the fourth quarter of 2020. This lays the foundation for improved cost effectiveness through optimization of the mine fleet and includes the completion of the full deployment of autonomous haul trucks by the end of 2020. At this initial production level, Suncor expects to retain approximately 90% of the estimated cost reductions.

"We are disappointed with our recent operational performance so we are strengthening our focus on the company's commitment to reliability," said Little. "We remain focused on operational excellence and on continuing to make the right long-term decisions to advance our asset sustainment and strategic initiatives aimed at improving reliability, increasing margins and reducing operating costs across our assets."

E&P production during the third quarter of 2020 increased to 97,200 boe/d from 92,300 boe/d in the prior year quarter, primarily due to improved reliability at Hibernia, and increased production at Hebron as six new production wells have come online since the third quarter of 2019, partially offset by Terra Nova, which remained offline, and natural declines in the United Kingdom.

Refinery crude throughput was 399,700 bbls/d and refinery utilization was 87% in the third quarter of 2020, compared to refinery crude throughput of 463,700 bbls/d and refinery utilization of 100% in the prior year quarter, with the decline due to the completion of the eight-week planned maintenance event at the Edmonton refinery and lower demand for refined products during the third quarter of 2020. Refined product sales decreased in the third quarter of 2020 to 534,000 bbls/d, compared to 572,000 bbls/d in the prior year quarter, as a result of the COVID-19 pandemic.

The company's total operating, selling and general expenses decreased to $2.275 billion in the third quarter of 2020 from $2.793 billion in the prior year quarter, primarily due to lower overall upstream and downstream sales volumes, continued cost reduction initiatives executed in 2020, as well as a share-based compensation recovery incurred in the third quarter of 2020, as compared to a share-based compensation expense in the prior year quarter. Operating, selling and general expenses for the nine months ended September 30, 2020 decreased by approximately $1 billion compared to the prior year period.

"Suncor continues to reduce operating and capital costs across our business," said Little. "Building on our commitment to reliability, the work at our Oil Sands Base Plant, Firebag and Fort Hills operations is substantially complete and the facilities are in the process of ramping up to normal operating rates by early November. With our full complement of refinery assets back on stream after planned maintenance, the company is positioned for strong performance exiting 2020."

In response to the COVID-19 pandemic and global supply imbalances, the company took decisive action to lower production to meet demand, lower operating costs and capital, and preserve its financial strength while laying the foundation to deliver long-term value in support of increasing shareholder returns. This approach is underpinned by Suncor's commitment to operational excellence, including its unwavering commitment to operate in a safe, reliable, cost-efficient and environmentally responsible manner.

Suncor has made progress in reducing operating costs across the company and remains on track to achieve the previously announced $1 billion operating cost reduction target by the end of 2020. In 2020, the company has achieved savings through base business reductions, enhancements to our supply chain model and reductions in costs as Fort Hills temporarily transitioned to one primary extraction train. In addition to the progress Suncor has made thus far on reducing operating and capital costs, the company has made the decision to accelerate structural reductions to its workforce over the next 18 months by approximately 10 to 15%, which were anticipated as part of the company's transformation and $2 billion incremental free funds flow⁽¹⁾ target.

The company also remains on track to achieve its $1.9 billion capital reduction target by the end of 2020, shifting the focus to sustaining projects designed to maintain safe and reliable operations, while advancing select projects in the core of our business that are expected to provide near-term returns and result in structural reductions to operating costs. Suncor continues to exercise capital discipline, carefully evaluating future projects and being disciplined in the deployment of capital in a constrained environment. This includes reducing spending across various E&P assets, including at Terra Nova, West White Rose and Fenja. The operator of the West White Rose Project has announced the cancellation of the 2021 construction season and is moving the project into safekeeping mode. The company is exercising capital discipline by undertaking activities to safely preserve the Terra Nova floating production storage and offloading unit quayside and deferring the asset life extension (ALE) project until an economically viable path forward with a safe and reliable return to operations can be determined. The ALE project is currently being evaluated with all stakeholders to determine the best option to recover remaining resources from the Terra Nova field.

In the third quarter of 2020, the company continued to advance the transition to its Autonomous Haulage System (AHS) at Fort Hills, which is expected to result in enhanced safety, environmental and operating performance, and lower operating costs. The company anticipates that the AHS truck fleet at Fort Hills will be fully operational in the fourth quarter of 2020. Starting late in the third quarter of 2020, Firebag In-Situ production rates were reduced to 110,000 bbls/d to enable Suncor to expand the capacity of the facility by fully integrating the new incremental emulsion handling and steam infrastructure. Following completion of this work, Firebag nameplate capacity will increase by 12,000 bbls/d to 215,000 bbls/d. The interconnecting pipelines between Suncor's Oil Sands Base Plant and Syncrude are nearing completion of construction, and will be commissioned in the fourth quarter of 2020. The bi-directional pipelines are expected to enhance integration between these assets and provide increased operational flexibility.

These initiatives are anticipated to deliver structural, sustained free funds flow growth through margin improvements, operating and sustaining capital cost reductions, and production growth from existing assets, which will contribute to Suncor's $2 billion free funds flow target. Technology investments in the company's marketing and trading business and the advancement of supply chain optimization initiatives are also expected to contribute towards this target while unlocking value that is largely independent of commodity prices. These projects will be underscored by digital technology adoption as the company continues to accelerate its digital transformation strategy aimed at improving the reliability, safety and environmental performance of its operations and which the company anticipates will enable operational efficiencies that will provide further structural cost savings.

"Through our integrated model and the value-driven projects we've advanced, including the AHS at Fort Hills and the Syncrude interconnecting pipelines, we believe Suncor is well positioned to add incremental and sustainable free funds flow in 2021," said Little. "We are confident that the steps we have taken this year will contribute to creating long-term value for our shareholders."

While the focus in 2020 has been on maintaining the financial strength and resiliency of the balance sheet through this period of volatile market conditions, the company remains committed to returning value to our shareholders and, in the third quarter of 2020, the company paid $321 million in dividends. As the company continues to execute on its plan to add sustainable annual free funds flow, the company plans to follow its capital allocation framework with a combination of future debt repayments, increasing shareholder returns and measured investments in economic projects.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings	(12	)	1 035		(4 151	)	5 234

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(290	)	127		253		(355	)

Asset impairment⁽²⁾	—		—		1 798		—

Impact of income tax rate adjustment on deferred taxes⁽³⁾	—		—		—		(1 116	)

Gain on significant disposal⁽⁴⁾	—		(48	)	—		(187	)

Operating (loss) earnings⁽¹⁾	(302	)	1 114		(2 100	)	3 576

(1): Operating (loss) earnings 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 the MD&A.
(2): During the first quarter of 2020, the company recorded non-cash after-tax impairment charges of $1.376 billion on its share of the Fort Hills assets, in the Oil Sands segment, and $422 million 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. Refer to the Segment Results and Analysis section of the MD&A for further details.
(3): In the second quarter of 2019, the company recorded a $1.116 billion deferred income tax recovery associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(4): The third quarter of 2019 included an after-tax gain of $48 million in the E&P segment related to the sale of certain non-core assets. In the second quarter of 2019, Suncor sold its 37% interest in Canbriam Energy Inc. for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.

Suncor has updated its Corporate Guidance for the full year business environment outlook assumptions previously updated on September 7, 2020 for Brent Sullom Voe from US$43.00/bbl to US$41.00/bbl, WTI at Cushing from US$40.00/bbl to US$38.00/bbl, WCS at Hardisty from US$26.00/bbl to US$25.00/bbl and AECO-C Spot from $2.25/GJ to $2.00/GJ, due to declines in key forward curve pricing for the remainder of the year. As a result of these updates, the full year current income tax recovery assumptions have changed from $500 million – $800 million to $650 million – $950 million.

For further details and advisories regarding Suncor's 2020 annual guidance, see www.suncor.com/guidance.

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 the MD&A.

Suncor 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.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2019, dated February 26, 2020 (the 2019 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2020, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2019 and the 2019 annual MD&A.

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 26, 2020 (the 2019 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 MD&A, and is not incorporated into this document by reference.

Suncor Energy Inc. has numerous direct and indirect subsidiaries, partnerships and joint arrangements (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.

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.

Certain financial measures in this MD&A – namely operating (loss) earnings, 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 margin, refining operating expense, free funds flow, discretionary free funds flow (deficit), and last-in, first-out (LIFO) inventory valuation methodology and related per share or per barrel amounts – are not prescribed by GAAP. Operating (loss) earnings is defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to the most directly comparable GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. 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 MD&A and reconciled to the most directly comparable GAAP measures in the Segment Results and Analysis section of this MD&A. Funds from (used in) operations, ROCE, free funds flow, discretionary free funds flow (deficit), refining and marketing 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 MD&A.

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 below and within the Forward-Looking Information section of this MD&A. This MD&A 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 MD&A, the 2019 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 MD&A for information on the material risk factors and assumptions underlying our forward-looking information contained in this MD&A.

Suncor's business, financial condition and results of operations could be materially and adversely affected by the outbreak of epidemics, pandemics and other public health crises in geographic areas in which we have operations, suppliers, customers or employees, including the COVID-19 pandemic and the ongoing uncertainty as to the extent and duration of the pandemic. The ongoing COVID-19 pandemic, and actions that have and may be taken by governmental authorities in response thereto, has resulted, and may continue to result in, among other things: increased volatility in financial markets and foreign currency exchange rates; disruptions to global supply chains; labour shortages; reductions in trade volumes; temporary operational restrictions and restrictions on gatherings greater than a certain number of individuals, shelter-in-place declarations and quarantine orders, business closures and travel bans; an overall slowdown in the global economy; political and economic instability; and civil unrest. In particular, the COVID-19 pandemic has resulted in, and may continue to result in, 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, and also increases the risk that storage for crude oil and refined petroleum products could reach capacity in certain geographic locations in which we operate. The recent resurgence of COVID-19 cases in certain geographic areas, and the possibility that a resurgence may occur in other areas, has resulted in the re-imposition of certain restrictions noted above by local authorities. This further increases the risk and uncertainty as to the extent and duration of the COVID-19 pandemic and the resultant impact on commodity demand and prices. A prolonged period of decreased demand for, and prices of, these commodities, and any applicable storage constraints, could also result in us voluntarily curtailing or shutting in production and a decrease in our refined product

volumes and refinery utilization rates, which could adversely impact our business, financial condition and results of operations. Suncor is also subject to risks relating to the health and safety of our people, as well as the potential for a slowdown or temporary suspension of our operations in locations impacted by an outbreak, increased labour and fuel costs, and regulatory changes. Such a suspension in operations could also be mandated by governmental authorities in response to the COVID-19 pandemic. This could negatively impact Suncor's production or refined product volumes and refinery utilization rates for a sustained period of time, which would adversely impact our business, financial condition and results of operations.

Continued Weakness and Volatility in Commodity and Petroleum Products Prices

Recent market events and conditions, including excess global crude oil and petroleum products supply as a result of decreased global demand due to the COVID-19 pandemic, have caused significant weakness and volatility in commodity and petroleum products prices. Commodity prices could remain under pressure for a prolonged period and which could cause continued weakness and volatility. This could result in reduced utilization and/or the suspension of operations at certain of our facilities, buyers of our products declaring force majeure or bankruptcy, the unavailability of storage, and disruptions of pipeline and other transportation systems for our products, which would further negatively impact Suncor's production or refined product volumes, and could adversely impact our business, financial condition and results of operations.

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.

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


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings

Oil Sands	(531	)	505		(3 503	)	2 255

Exploration and Production	25		219		(453	)	1 167

Refining and Marketing	384		668		598		2 442

Corporate and Eliminations	110		(357	)	(793	)	(630	)

Total	(12	)	1 035		(4 151	)	5 234

Operating (loss) earnings⁽¹⁾

Oil Sands	(531	)	505		(2 127	)	1 345

Exploration and Production	25		171		(31	)	910

Refining and Marketing	384		668		598		2 354

Corporate and Eliminations	(180	)	(230	)	(540	)	(1 033	)

Total	(302	)	1 114		(2 100	)	3 576

Funds from (used in) operations⁽¹⁾

Oil Sands	556		1 606		1 257		4 656

Exploration and Production	260		379		742		1 588

Refining and Marketing	594		885		1 293		3 070

Corporate and Eliminations	(244	)	(195	)	(637	)	(1 049	)

Total	1 166		2 675		2 655		8 265

Decrease (increase) in non-cash working capital	79		461		(794	)	(148	)

Cash flow provided by operating activities	1 245		3 136		1 861		8 117

Capital and exploration expenditures⁽²⁾

Asset sustainment and maintenance	653		966		1 802		2 201

Economic investment	259		521		1 063		1 497

Total	912		1 487		2 865		3 698

Suncor's consolidated net loss for the third quarter of 2020 was $12 million, compared to net earnings of $1.035 billion for the prior year quarter. The net loss was primarily caused by the same factors that resulted in the operating loss described subsequently in this section of this MD&A.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings	(12	)	1 035		(4 151	)	5 234

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(290	)	127		253		(355	)

Asset impairment⁽²⁾	—		—		1 798		—

Impact of income tax rate adjustment on deferred taxes⁽³⁾	—		—		—		(1 116	)

Gain on significant disposal⁽⁴⁾	—		(48	)	—		(187	)

Operating (loss) earnings⁽¹⁾	(302	)	1 114		(2 100	)	3 576

(1): Operating (loss) earnings 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 MD&A.
(2): During the first quarter of 2020, the company recorded non-cash after-tax impairment charges of $1.376 billion on its share of the Fort Hills assets, in the Oil Sands segment, and $422 million 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. Refer to the Segment Results and Analysis section of this MD&A for further details.
(3): In the second quarter of 2019, the company recorded a $1.116 billion deferred income tax recovery associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(4): The third quarter of 2019 included an after-tax gain of $48 million in the E&P segment related to the sale of certain non-core assets. In the second quarter of 2019, Suncor sold its 37% interest in Canbriam Energy Inc. (Canbriam) for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.

The after-tax share-based compensation impact on results was a recovery of $31 million during the third quarter of 2020, compared to an expense of $52 million during the prior year quarter, as a result of a decrease in the company's share price through the current quarter, compared to an increase in the prior year quarter.

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

Average for the three months
ended September 30

Average for the nine months
ended September 30

2020

2019

2020

2019

WTI crude oil at Cushing

US$/bbl

40.95

56.45

38.30

57.05

Dated Brent crude

US$/bbl

43.00

61.90

40.80

64.65

Dated Brent/Maya crude oil FOB price differential

US$/bbl

3.50

5.20

7.35

5.45

MSW at Edmonton

Cdn$/bbl

51.30

68.35

44.50

69.60

WCS at Hardisty

US$/bbl

31.90

44.20

24.65

45.30

Light/heavy differential for WTI at Cushing less WCS at Hardisty

US$/bbl

(9.05

)

(12.25

)

(13.65

)

(11.75

)

SYN-WTI differential

US$/bbl

(2.45

)

0.40

(3.20

)

(0.55

)

Condensate at Edmonton

US$/bbl

37.55

52.00

35.30

52.80

Natural gas (Alberta spot) at AECO

Cdn$/mcf

2.25

0.95

2.10

1.50

Alberta Power Pool Price

Cdn$/MWh

43.85

46.85

46.90

57.55

New York Harbor 2-1-1 crack⁽¹⁾

US$/bbl

10.20

19.70

12.40

20.40

Chicago 2-1-1 crack⁽¹⁾

US$/bbl

7.75

17.05

8.10

18.00

Portland 2-1-1 crack⁽¹⁾

US$/bbl

12.55

23.90

14.30

24.15

Gulf Coast 2-1-1 crack⁽¹⁾

US$/bbl

8.55

20.00

10.20

19.90

Exchange rate

US$/Cdn$

0.75

0.76

0.74

0.75

Exchange rate (end of period)

US$/Cdn$

0.75

0.76

0.75

0.76

(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.

The COVID-19 pandemic has significantly lowered demand for crude oil and refined products, resulting in a decrease in crude oil and crack spread benchmarks of more than 25% compared to the prior year quarter.

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 third quarter of 2020 reflected a significant decrease in WTI at Cushing, which averaged US$40.95/bbl, compared to US$56.45/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 decreased to $51.30/bbl in the third quarter of 2020 compared to $68.35/bbl in the prior year quarter, and prices for WCS at Hardisty decreased to an average of US$31.90/bbl in the third quarter of 2020, from US$44.20/bbl in the prior year quarter.

Bitumen production that Suncor does not upgrade is blended with diluent or SCO to facilitate delivery on 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 and spot sales, and the price variance between Hardisty, Alberta and U.S. Gulf Coast heavy pricing. 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 price realizations. Bitumen prices benefited from the narrowing of heavy crude oil differentials in the third quarter of 2020.

Suncor's price realizations for production from E&P Canada and E&P International assets are influenced primarily by the price for Brent crude, which decreased to US$43.00/bbl in the third quarter of 2020, compared to US$61.90/bbl in the prior year quarter.

Suncor's refining and marketing margins are primarily influenced by 2-1-1 benchmark crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates. Market crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel and do not necessarily reflect the margins at a specific refinery. Suncor's realized refining and marketing 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.

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 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 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 third quarter of 2020, the 2-1-1 benchmark crack spreads declined significantly compared to the prior year quarter due to decreased demand for transportation fuels. The Suncor 5-2-2-1 index was US$16.80/bbl in the third quarter of 2020, compared to US$24.40/bbl in the third quarter of 2019, impacted by lower benchmark cracking margins and narrowing crude differentials.

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 $2.25/mcf in the third quarter of 2020, from $0.95/mcf in the prior year quarter.

Excess electricity produced in Suncor's Oil Sands operations and at Fort Hills is sold to the Alberta Electric System Operator, with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $43.85/MWh in the third quarter of 2020, compared to $46.85/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 weakened in relation to the U.S. dollar in the third quarter of 2020, as the average exchange rate decreased to US$0.75 per one Canadian dollar from US$0.76 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the third quarter of 2020 when compared to the prior year quarter.

Suncor also has assets and liabilities, including approximately 64% 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.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Gross revenues	2 567		4 601		7 536		13 922

Less: Royalties	(36	)	(235	)	(77	)	(774	)

Operating revenues, net of royalties	2 531		4 366		7 459		13 148

Net (loss) earnings	(531	)	505		(3 503	)	2 255

Adjusted for:

Impairment⁽¹⁾	—		—		1 376		—

Impact of income tax rate adjustment on deferred taxes⁽²⁾	—		—		—		(910	)

Operating (loss) earnings⁽³⁾	(531	)	505		(2 127	)	1 345

Funds from operations⁽³⁾	556		1 606		1 257		4 656

(1): During the first quarter of 2020, the company recorded non-cash after-tax impairment charges of $1.376 billion 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.
(2): In the second quarter of 2019, the company recorded a $910 million deferred income tax recovery in the Oil Sands segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Oil Sands segment had an operating loss of $531 million in the third quarter of 2020, compared to operating earnings of $505 million in the prior year quarter. The decrease was primarily due to lower realized crude prices, as crude benchmarks decreased by approximately 25% compared to the prior year quarter as a result of the COVID-19 pandemic, lower production volumes, due to an operational incident at Oil Sands Base Plant and Fort Hills continuing to operate on one primary extraction train, as well as higher DD&A. These factors were partially offset by the decrease in operating, selling and general expenses, associated with lower production and the company's continued cost reduction initiatives, and lower royalties.


	Three months ended September 30				Nine months ended September 30
(mbbls/d)	2020		2019		2020		2019

SCO and diesel production	421.1		490.0		461.2		506.6

Internally consumed diesel	(10.3	)	(10.7	)	(10.9	)	(11.2	)

Upgraded production	410.8		479.3		450.3		495.4

Non-upgraded bitumen production	108.2		190.7		117.2		177.7

Total Oil Sands production	519.0		670.0		567.5		673.1

(1): Bitumen production from Oil Sands Base Plant 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): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its production volumes to aggregate production from each asset into the categories of "Upgraded production" and "Non-upgraded bitumen production" to better reflect the integration among the company's assets with no impact to overall production volumes. Comparative periods have been updated to reflect this change.

SCO production decreased to 410,800 bbls/d in the third quarter of 2020 from 479,300 bbls/d in the third quarter of 2019, resulting in combined upgrader utilization rates of 75% and 87%, respectively, with both periods impacted by planned maintenance at Oil Sands operations and Syncrude and, in the third quarter of 2020, by an operational incident at the secondary extraction facilities at Oil Sands Base Plant. Production was restored to 165,000 bbls/d of mined bitumen within approximately two weeks of the incident, as production was restricted to manage bitumen quality into the upgraders. Subsequent to the third quarter of 2020, repairs were substantially completed and production is anticipated to ramp up to full rates by early November 2020. To mitigate the impact of this event, the company diverted bitumen production from Firebag to the upgraders to maximize the production of higher value SCO barrels. As a result, overall Oil Sands production was also reduced by the yield loss associated with upgrading In Situ bitumen to SCO.

SCO and diesel sales volumes decreased to 420,100 bbls/d, in the third quarter of 2020, from 483,100 bbls/d in the prior year quarter, consistent with the decrease in production, partially offset by a draw in inventory.

Non-upgraded bitumen sales volumes were 119,100 bbls/d in the third quarter of 2020, compared to 201,800 bbls/d in the prior year quarter, and were influenced by the same factors influencing production, partially offset by a draw in inventory.


Net of transportation costs, but before royalties	Three months ended September 30				Nine months ended September 30
($/bbl)	2020		2019		2020		2019

SCO and diesel	46.18		69.63		42.45		70.57

Non-upgraded bitumen⁽²⁾	24.28		47.11		19.83		48.69

Crude sales basket (all products)	41.34		63.00		37.73		64.82

Crude sales basket, relative to WTI	(13.19	)	(11.28	)	(14.10	)	(11.25	)

(1): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its price realizations to aggregate price realizations from each asset into the categories of "SCO and diesel" and "Non-upgraded bitumen" to better reflect the integration among the company's assets with no impact to overall price realizations. Comparative periods have been updated to reflect this change.
(2): Beginning in the second quarter of 2020, the company revised its Non-upgraded bitumen price realization to include midstream activities employed to optimize its logistics capacity and more accurately reflect the performance of the product stream. Comparative periods have been restated to reflect this change.

In the third quarter of 2020, Oil Sands price realizations continued to be impacted by the decline in demand due to the impacts of the COVID-19 pandemic.

Royalties for the Oil Sands segment were lower in the third quarter of 2020 compared to the prior year quarter, primarily due to lower crude price realizations and lower overall sales volumes.

Total Oil Sands operating and transportation expenses decreased significantly in the third quarter of 2020 compared to the prior year quarter, as described in detail below. 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.

In the third quarter of 2020, the relief provided under the Government of Canada's Emergency Wage Subsidy (CEWS) program, in addition to safe-mode costs associated with the deferral of capital projects and additional costs incurred in response to the COVID-19 pandemic, have been included in operating and transportation expense by asset. These recoveries and costs, however, have been excluded from cash operating costs per barrel for comparability purposes.

At Oil Sands operations, operating costs decreased compared to the prior year quarter, primarily due to lower sales volumes, cost reduction initiatives and lower planned maintenance costs, partially offset by an increase in natural gas prices.

At Fort Hills, operating costs in the third quarter of 2020 decreased when compared to the prior year quarter, primarily due to cost savings associated with the transition to one primary extraction train.

Suncor's share of Syncrude operating costs in the third quarter of 2020 decreased compared to the prior year quarter, primarily due to cost reduction initiatives and lower planned maintenance costs.

DD&A expense for the third quarter of 2020 was higher compared to the prior year quarter due to higher derecognition charges of property, plant and equipment and exploration and evaluation assets in the third quarter of 2020.


	Three months ended September 30				Nine months ended September 30
($ millions, except as noted)	2020		2019		2020		2019

Oil Sands operating, selling and general expense (OS&G)	1 650		2 009		5 430		6 042

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	1 000		1 156		3 278		3 496

Non-production costs⁽²⁾	5		(73	)	(90	)	(168	)

Excess power capacity and other⁽³⁾	(54	)	(64	)	(193	)	(181	)

Inventory changes	(1	)	19		(75	)	16

Oil Sands operations cash operating costs⁽¹⁾	950		1 038		2 920		3 163

Oil Sands operations production volumes (mbbls/d)⁽⁴⁾⁽⁵⁾	325.6		423.9		369.8		412.8

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	31.75		26.60		28.80		28.10

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	130		224		598		673

Non-production costs⁽²⁾	(8	)	(23	)	(45	)	(95	)

Inventory changes	15		(10	)	(37	)	5

Fort Hills cash operating costs⁽¹⁾	137		191		516		583

Fort Hills production volumes (mbbls/d)	42.6		85.5		56.8		84.4

Fort Hills cash operating costs ($/bbl)⁽¹⁾	35.20		24.25		33.25		25.30

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	520		629		1 554		1 873

Non-production costs⁽²⁾	(11	)	(38	)	(47	)	(121	)

Syncrude cash operating costs⁽¹⁾⁽⁶⁾	509		591		1 507		1 752

Syncrude production volumes (mbbls/d)⁽⁴⁾⁽⁵⁾	161.1		162.3		151.7		177.6

Syncrude cash operating costs ($/bbl)⁽¹⁾	34.35		39.65		36.25		36.15

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Significant non-production costs include, but are not limited to, share-based compensation expense and research expenses. In addition, for 2020, 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 in the second and third quarters of 2020 include the relief provided under the CEWS program. Non-production costs at Fort Hills 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 a cogeneration unit and the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.
(4): 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 Plant within its mining operations. In the third quarter of 2020, Oil Sands operations production volumes included 7,700 bbls/d of internally consumed diesel, of which 6,100 bbls/d was consumed at Oil Sands Base Plant, 1,000 bbls/d was consumed at Fort Hills and 600 bbls/d was consumed at Syncrude. Syncrude production volumes included 2,600 bbls/d of internally consumed diesel.
(5): Beginning in the first quarter of 2020, Oil Sands operations cash operating costs are based on production volumes, which include internally consumed diesel produced at Oil Sands Base Plant and consumed at Fort Hills, Syncrude and Oil Sands Base, while all the prior periods presented exclude internally consumed diesel at Oil Sands Base Plant from production volumes. Prior periods were not restated due to the immaterial impact of the change in presentation. Also, beginning in the first quarter of 2020, Syncrude cash operating costs are based on production volumes, which include internally consumed diesel, while all the prior periods presented here exclude internally consumed diesel from production. Prior periods were not restated due to the immaterial impact of the change in presentation.
(6): Beginning in the first quarter of 2020, the company revised Syncrude cash operating costs to better align with the Oil Sands operations and Fort Hills cash operating costs methodology. Prior period Syncrude cash operating costs had previously included future development costs and have been restated to reflect this change.

Oil Sands operations cash operating costs⁽¹⁾ per barrel increased to $31.75 in the third quarter of 2020, compared to $26.60 in the prior year quarter, primarily due to lower production volumes, higher natural gas costs as well as costs related to a product mix more weighted towards higher value but higher cost SCO sales, partially offset by lower maintenance costs and cost reductions. In the third quarter, non-production costs, which are excluded from Oil Sands operations cash operating costs, were lower than the prior year quarter, primarily due to CEWS, partially offset by safe-mode and COVID-19 response costs.

Fort Hills cash operating costs⁽¹⁾ per barrel were $35.20 in the third quarter of 2020, compared to $24.25 in the prior year quarter, reflecting lower production as Fort Hills continued to operate on one primary extraction train, partially offset by a significant reduction in costs. Non-production costs were lower primarily due to CEWS, partially offset by additional costs incurred in response to the COVID-19 pandemic.

Syncrude cash operating costs⁽¹⁾ per barrel were $34.35 in the third quarter of 2020, compared to $39.65 in the prior year quarter, with the decrease primarily due to cost reduction initiatives and lower maintenance costs. Non-production costs were lower primarily due to CEWS.

Oil Sands net loss was $3.503 billion for the first nine months of 2020, compared to net earnings of $2.255 billion in the prior year period. In addition to the factors impacting operating (loss) earnings discussed below, the net loss for the first nine months of 2020 included $1.376 billion of non-cash after-tax asset impairment charges. Net earnings in the prior year quarter included a one-time deferred income tax recovery of $910 million associated with a staged reduction to the Alberta corporate income tax rate from 12% to 8% from 2019 to 2022.

Oil Sands operating loss for the first nine months of 2020 was $2.127 billion, compared to operating earnings of $1.345 billion for the same period in 2019. Oil Sands operating loss for the first nine months of 2020 was primarily a result of significantly lower crude price realizations, lower production volumes and higher DD&A, partially offset by a decrease in operating, selling and general expense, as detailed below, transportation expense and royalties. The decrease in realized crude prices and production volumes was driven by declining crude oil demand due to the COVID-19 pandemic and supply issues driven by OPEC+ decisions earlier in 2020.

Funds from operations for the first nine months of 2020 were $1.257 billion for the Oil Sands segment, compared to $4.656 billion in the prior year period, with the decrease primarily due to the same factors that influenced operating earnings noted above.

Oil Sands operations cash operating costs per barrel averaged $28.80 for the first nine months of 2020, compared to an average of $28.10 for the first nine months of 2019, reflecting lower production volumes and higher natural gas costs, partially offset by lower maintenance costs and other cost savings initiatives. Both periods reflected the impact of optimizing the product mix to higher value but higher cost SCO barrels relative to lower cost but lower value bitumen production.

Fort Hills cash operating costs per barrel averaged $33.25 for the first nine months of 2020, compared to $25.30 for the same period of 2019, with the current period reflecting lower production due to the temporary transition to one primary extraction train, partially offset by a reduction in costs. The prior year period reflected fully ramped up operations, although production was limited by the Government of Alberta's mandatory production curtailments.

Syncrude cash operating costs per barrel of $36.25 for the first nine months of 2020 was comparable to $36.15 in the first nine months of 2019.

Planned maintenance activity in the fourth quarter of 2020 includes maintenance events at Oil Sands operations Upgrader 1 and maintenance at Firebag originally scheduled for 2022 that has been accelerated to coincide with the installation of incremental emulsion handling and steam infrastructure. Subsequent to the third quarter of 2020, maintenance at Firebag and repairs at Oil Sands Base Plant were substantially complete with production anticipated to ramp up to normal operating rates by early November 2020. The anticipated production impact of these maintenance events has been reflected in the company's 2020 guidance.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Gross revenues⁽¹⁾	512		681		1 344		2 461

Less: Royalties⁽¹⁾	(30	)	(32	)	(58	)	(219	)

Operating revenues, net of royalties	482		649		1 286		2 242

Net earnings (loss)	25		219		(453	)	1 167

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	—		—		—		(70	)

Asset impairment⁽³⁾	—		—		422		—

Gain on asset disposal⁽⁴⁾	—		(48	)	—		(187	)

Operating earnings (loss)⁽⁵⁾	25		171		(31	)	910

Funds from operations⁽⁵⁾	260		379		742		1 588

(1): Production, revenues and royalties from the company's Libya operations have been presented in the E&P section of this MD&A on an economic basis and exclude an equal and offsetting gross up of revenues and royalties of $65 million in the third quarter of 2019, which is required for presentation purposes in the company's financial statements under the working-interest basis. In the third quarter of 2020, there were no Libya sales included in production, revenues or royalties.
(2): In the second quarter of 2019, the company recorded a $70 million deferred income tax recovery in the E&P segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(3): During the first quarter of 2020, the company recorded total non-cash after-tax impairment charges of $422 million 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.
(4): The third quarter of 2019 included an after-tax gain of $48 million in the E&P segment related to the sale of certain non-core assets. In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.
(5): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings for the E&P segment in the third quarter of 2020 decreased to $25 million, from $171 million in the prior year quarter, with the decline primarily due to significantly lower realized crude prices due to the COVID-19 pandemic, which resulted in crude oil benchmarks decreasing by more than 25% and higher DD&A, partially offset by higher sales volumes.

Production volumes for E&P Canada were 57,100 bbls/d in the third quarter of 2020, compared to 49,600 bbls/d in the prior year quarter. Production volumes increased in the third quarter of 2020, primarily due to increased reliability at Hibernia, higher production at Hebron as six new production wells have come online since the third quarter of 2019, partially offset by lower volumes at Terra Nova, which remained offline.

The company is exercising capital discipline by undertaking activities to safely preserve the Terra Nova floating production storage and offloading (FPSO) unit quayside and deferring the asset life extension (ALE) project until an economically viable path forward with a safe and reliable return to operations can be determined. The ALE project is currently being evaluated with all stakeholders to determine the best option to recover remaining resources from the Terra Nova field. The operator of the West White Rose Project has announced the cancellation of the 2021 construction season and is moving the project into safekeeping mode.

E&P International production was 40,100 boe/d in the third quarter of 2020, compared to 42,700 boe/d in the prior year quarter. The decrease in the third quarter of 2020 reflected natural production declines in the U.K. and no Libya liftings, partially offset by increased production at Oda.

E&P sales volumes increased to 96,000 boe/d in the third quarter of 2020, compared to 92,500 boe/d in the prior year quarter, commensurate with the increase in production.

Price realizations at E&P Canada and E&P International in the third quarter of 2020 were lower than in the prior year quarter, with the third quarter of 2020 impacted by the significant decline in benchmarks and demand for crude oil as a result of the COVID-19 pandemic. The decline in price realizations was partially mitigated by Suncor's marketing and logistics expertise, where the company was able to capture additional value by optimizing the timing of cargo sales and expanding the company's market reach.

E&P royalties in the third quarter of 2020 were lower than the prior year quarter due to the decrease in price realizations.

Operating and transportation expenses for the third quarter of 2020 were comparable to the prior year quarter.

DD&A expense in the third quarter of 2020 increased when compared to the third quarter of 2019, primarily due to an increase in production volumes.

Exploration expense in the third quarter of 2020 was comparable to the prior year quarter.

E&P's net loss was $453 million for the first nine months of 2020, compared to net earnings of $1.167 billion in the prior year period. In addition to the factors impacting operating loss discussed below, the net loss for the nine months of 2020 included total non-cash after-tax impairment charges of $422 million against the company's 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. Net earnings for the first nine months of 2019 included an after-tax gain of $139 million on the sale of the company's interest in Canbriam, a one-time deferred income tax recovery of $70 million associated with a staged reduction to the Alberta corporate income tax rate from 12% to 8% from 2019 to 2022 and a $48 million after-tax gain on the sale of certain non-core assets during the third quarter of 2019.

E&P's operating loss for the first nine months of 2020 was $31 million, compared to operating earnings of $910 million in the first nine months of 2019, with the decline primarily due to the significantly lower crude price realizations, due to the COVID-19 pandemic and global inventory oversupply, and the absence of insurance proceeds related to the company's assets in Libya, which were recognized in the prior year period, partially offset by lower royalties.

Funds from operations were $742 million for the first nine months of 2020, compared to $1.588 billion for the first nine months of 2019, due to the factors impacting operating (loss) earnings discussed above.

There are no significant maintenance events scheduled for the fourth quarter of 2020.


	Three months ended September 30		Nine months ended September 30
($ millions)	2020	2019	2020	2019

Operating revenues	4 050	5 929	11 396	16 759

Net earnings	384	668	598	2 442

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽¹⁾	—	—	—	(88	)

Operating earnings⁽²⁾	384	668	598	2 354

Funds from operations⁽²⁾	594	885	1 293	3 070

(1): In the second quarter of 2019, the company recorded an $88 million deferred income tax recovery in the R&M segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings in the third quarter of 2020 were $384 million, compared to $668 million in the prior year quarter. The decrease was primarily due to lower refining and marketing margins as a result of significantly lower crack spread benchmarks and lower crude throughput and refined product sales due to the completion of planned maintenance and lower demand for transportation fuels due to the COVID-19 pandemic. Operating earnings were favourably impacted by a FIFO inventory valuation gain of $164 million after-tax on the increase in crude and refined product benchmarks in the third quarter of 2020, compared to a FIFO inventory valuation loss of $30 million after-tax in the prior year quarter.


	Three months ended September 30		Nine months ended September 30
	2020	2019	2020	2019

Crude oil processed (mbbls/d)

Eastern North America	208.7	209.5	197.0	198.6

Western North America	191.0	254.2	199.5	237.4

Total	399.7	463.7	396.5	436.0

Refinery utilization⁽¹⁾ (%)

Eastern North America	94	94	89	89

Western North America	80	106	83	99

Total	87	100	86	94

Refined product sales (mbbls/d)

Gasoline	233.4	256.8	214.5	246.3

Distillate	220.6	230.8	213.2	219.6

Other	80.0	84.4	73.9	75.1

Total	534.0	572.0	501.6	541.0

Refining and marketing margin – FIFO⁽²⁾⁽³⁾ ($/bbl)	30.75	35.65	25.10	42.05

Refining and marketing margin – LIFO⁽²⁾⁽³⁾ ($/bbl)	25.00	36.10	29.95	36.90

Refining operating expense⁽²⁾ ($/bbl)	5.40	4.90	5.60	5.45

(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): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3): Beginning in the first quarter of 2020, refining and marketing margins have been revised to better reflect the refining, product supply and rack forward businesses. Prior periods have been restated to reflect this change.

Refined product sales decreased in the third quarter of 2020 to 534,000 bbls/d, compared to 572,000 bbls/d in the prior year quarter, as a result of the COVID-19 pandemic.

Operating expenses in the third quarter of 2020 decreased compared to the prior year quarter, primarily due to the impact of the company's cost reduction initiatives, CEWS and a decrease in variable costs associated with the decrease in crude throughput and sales volumes. Refining operating expense⁽¹⁾ per barrel was $5.40 in the third quarter of 2020, compared to $4.90 in the prior year quarter, with the increase primarily due to lower crude throughput and sales volumes.

DD&A expense for the third quarter of 2020 was comparable to the prior year quarter.

R&M's net earnings were $598 million for the first nine months of 2020, compared to $2.442 billion in the prior year period. In addition to the factors explained in operating earnings below, net earnings for the first nine months of 2019 included a one-time deferred income tax recovery of $88 million associated with a staged reduction to the Alberta corporate income tax rate from 12% to 8% from 2019 to 2022.

Operating earnings for R&M in the first nine months of 2020 were $598 million, compared to $2.354 billion in the first nine months of 2019, with the decrease primarily due to a FIFO inventory valuation loss as a result of a significant decline in crude and refined product benchmarks compared to the prior year period, which included a FIFO inventory valuation gain. Operating earnings in the first nine months of 2020 were further impacted by lower refining and marketing margins due to lower benchmark crack spreads due to the COVID-19 pandemic. For the first nine months of 2020, the impact of the FIFO method of inventory valuation, relative to an estimated LIFO method, had a negative impact to operating earnings and funds from operations of $428 million after-tax, compared to a favourable $477 million after-tax impact in the first nine months of 2019.

Funds from operations were $1.293 billion in the first nine months of 2020, compared to $3.070 billion in the first nine months of 2019, and decreased primarily due to the same factors that influenced operating earnings described above.

The company has completed all major planned refinery maintenance for 2020 and there are no major maintenance events scheduled for the fourth quarter of 2020.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Net earnings (loss)	110		(357	)	(793	)	(630	)

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽¹⁾	—		—		—		(48	)

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(290	)	127		253		(355	)

Operating loss⁽²⁾	(180	)	(230	)	(540	)	(1 033	)

Corporate	*(203*	)	(255	)	*(654*	)	(818	)

Eliminations	23		25		*114*		(215	)

Funds used in operations⁽²⁾	(244	)	(195	)	(637	)	(1 049	)

(1): In the second quarter of 2019, the company recorded a $48 million deferred income tax recovery in the Corporate and Eliminations segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% from 2019 to 2022.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Corporate incurred an operating loss of $203 million for the third quarter of 2020, compared to an operating loss of $255 million for the prior year quarter, with the decreased operating loss primarily due a share-based compensation recovery in the current quarter, as compared to a share-based compensation expense in the prior period, partially offset by an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year quarter, and higher interest expense associated with increased debt in 2020. In the third quarter of 2020, Suncor's capitalization of borrowing costs as part of the cost of major development assets and construction projects in progress were comparable to 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. The realization of profit for the third quarter of 2020 was comparable to the prior year quarter.

Corporate and Eliminations funds used in operations were $244 million for the third quarter of 2020, compared to $195 million in the third quarter of 2019, and were influenced by the same factors impacting operating loss described above, excluding the impact of share-based compensation expense.

The net loss for Corporate and Eliminations was $793 million for the first nine months of 2020, compared to $630 million in the prior year period. In addition to the factors explained in operating loss below, the net loss for the first nine months of 2020 included a $253 million unrealized after-tax foreign exchange loss on the revaluation of U.S. dollar denominated debt. Net loss in the prior year period included a $355 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt and a one-time deferred income tax recovery of $48 million associated with a staged reduction to the Alberta corporate income tax rate from 12% to 8% from 2019 to 2022.

The operating loss for Corporate and Eliminations for the first nine months of 2020 was $540 million, compared to $1.033 billion in the first nine months of 2019. The decreased loss was attributed to the profit realization in intercompany inventory during the current year, as compared to an elimination of intercompany profit in the prior year period, and a share-based compensation recovery in the current year, as compared to a share-based compensation expense in the prior year period, partially offset by higher interest expense associated with the increased debt balance in 2020. The realization of intercompany profit was due to the decrease in Oil Sands price realizations, as higher crude refinery feedstock inventory sourced internally from Oil Sands was sold and replaced by lower margin feedstock inventory. The company capitalized $94 million of its borrowing costs in the first nine months of 2020, compared with $85 million in the first nine months of 2019.

Corporate and Eliminations funds used in operations for the first nine months of 2020 were $637 million, compared to $1.049 billion in the prior year period, and were influenced by the same factors impacting operating loss noted above, excluding the impact of share-based compensation.

Capital and Exploration Expenditures by Type, excluding capitalized interest

Three months ended
September 30, 2020

Nine months ended
September 30, 2020

($ millions)

Asset
Sustainment and
Maintenance(1)

Economic
Investment(2)

Total

Asset
Sustainment and
Maintenance(1)

Economic
Investment(2)

Total

Oil Sands

Oil Sands Base

377

434

951

149

1 100

In Situ

189

289

478

Fort Hills

124

142

Syncrude

114

125

271

330

Exploration and Production

377

383

Refining and Marketing

125

152

238

326

Corporate and Eliminations

106

653

259

912

1 802

1 063

2 865

(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.

In the second quarter of 2020, the company announced plans to reduce its planned 2020 capital expenditures to a range of $3.6 billion to $4.0 billion to preserve the financial health and resiliency of the company and navigate the current business environment. In order to achieve this, the company is concentrating on asset sustainment and maintenance projects that are designed to maintain safe and reliable operations, as well as proceeding with select late stage, high-value and low capital economic investment projects with other economic investments significantly reduced in 2020 or deferred.

The company made significant progress towards its revised cost reduction target, and spent $912 million on capital expenditures, excluding capitalized interest, in the third quarter of 2020, a decrease from $1.487 billion in the prior year quarter. The reduction is primarily due to the decrease in capital associated with the completion of maintenance in the prior year quarter at Oil Sands and Syncrude, as well as decreased In Situ and E&P economic investment capital expenditures in the third quarter of 2020.

Oil Sands Base capital expenditures were $434 million in the third quarter of 2020, the majority of which was focused on asset sustainment and maintenance activities related to the company's planned maintenance program. Oil Sands Base expenditures also included the continued development of tailings infrastructure and continued construction of the bi-directional interconnecting pipelines between Syncrude and Oil Sands Base Plant. The interconnecting pipelines between Suncor's Oil Sands Base Plant and Syncrude are nearing completion of construction, and will be commissioned in the fourth quarter of 2020. The third quarter of 2020 also included capital expenditures related to the rebuild at the Oil Sands Base Plant secondary extraction facility, which are also included within the corporate capital guidance. The majority of the repair costs are expected to be reimbursed through insurance proceeds expected to be received in 2021.

In Situ capital expenditures were $58 million in the third quarter of 2020, and were primarily directed toward economic activities, including the continued investment in well pad projects.

Capital expenditures at Fort Hills were $25 million in the third quarter of 2020, primarily directed towards asset sustainment capital activities in the mine and tailings development. The AHS program at Fort Hills is progressing and on pace to achieve full deployment in the fourth quarter of 2020.

Syncrude capital expenditures were $125 million in the third quarter of 2020, the majority of which was for asset sustainment expenditures focused on maintaining existing assets, scheduled turnaround and planned maintenance activities.

Capital and exploration expenditures at E&P were $93 million in the third quarter of 2020 and were primarily focused on economic investment projects, including development drilling at Hebron and Buzzard, and limited development work on the Fenja and the West White Rose projects. The operator of the West White Rose Project has announced the cancellation of the 2021 construction season and is moving the project into safekeeping mode.

The company is exercising capital discipline by undertaking activities to safely preserve the Terra Nova FPSO quayside and deferring the ALE project until an economically viable path forward with a safe and reliable return to operations can be determined. The ALE project is currently being evaluated with all stakeholders to determine the best option to recover remaining resources from the Terra Nova field.

R&M capital expenditures were $152 million in the third quarter of 2020 and were primarily related to asset sustainment and maintenance activities.

Corporate capital expenditures were $25 million in the third quarter of 2020 and were primarily directed towards the company's information technology initiatives.


	Twelve months ended September 30
	2020		2019

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress⁽²⁾	(10.8	)	9.9

Including major projects in progress	(10.2	)	9.7

Net debt to funds from operations⁽³⁾⁽⁴⁾ (times)	3.8		1.5

Interest coverage on long-term debt (times)

Earnings basis⁽⁵⁾	(7.5	)	6.6

Funds from operations basis⁽⁴⁾⁽⁶⁾	5.4		12.9

Total debt to total debt plus shareholders' equity (%)	36.8		28.1

(1): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): ROCE excluding major projects in progress would have been (1.4%) for the twelve months ended September 30, 2020, excluding the impact of impairments of $1.798 billion after-tax in the first quarter of 2020 and the impacts of impairments of $3.352 billion after-tax in the fourth quarter of 2019.
(3): Net debt is equal to total debt less cash and cash equivalents.
(4): Funds from operations and metrics that use funds from operations are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(5): Equal to net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(6): Equal to funds from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

The COVID-19 pandemic has had a significant impact on global capital markets and the availability of liquidity. Although access to capital improved throughout the third quarter of 2020, the disruption and volatility in global capital markets is expected to continue for some time which could continue to have an impact on the company's cost of capital and affect the company's ability to access the capital markets on a timely basis.

In response to the COVID-19 pandemic and OPEC+ supply issues, the company previously announced a reduction in planned 2020 capital expenditures to a range of $3.6 billion to $4.0 billion, and to reduce operating costs across the business by $1 billion or approximately 10% compared to 2019 levels.

In 2020, the company issued $1.25 billion of 5.00% senior 10-year unsecured medium term notes, US$450 million of 2.80% senior 3-year unsecured notes and US$550 million of 3.10% senior 5-year unsecured notes. The company also enhanced its liquidity by securing $2.8 billion of credit facilities resulting in $8.6 billion of liquidity as at September 30, 2020. This increased financial flexibility will help ensure the company has access to adequate financial resources should it be required. As economic activity increases and commodity prices improve, management plans to reduce debt in conjunction with a measured pace of increasing shareholder returns and economic investments.

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 2020 capital spending program of $3.6 billion to $4.0 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 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.

For the three months ended September 30, 2020, cash and cash equivalents decreased to $1.489 billion, from $1.846 billion at June 30, 2020, with the use of cash related to the company's capital and exploration expenditures, dividend payments and the repayment of short-term debt, more than offsetting the cash flow provided by operating activities.

For the nine months ended September 30, 2020, cash and cash equivalents decreased relative to $1.960 billion at December 31, 2019, with the use of cash related to the company's capital and exploration expenditures, dividend and principal lease payments, and the repurchase of Suncor's own shares under its normal course issuer bid (NCIB) in the first quarter of 2020, more than offsetting the cash flow provided by operating activities and the increase in short-term and long-term debt.

As at September 30, 2020, the weighted average days to maturity of the company's short-term investment portfolio was approximately 13 days.

Available credit facilities for liquidity purposes at September 30, 2020 increased to $7.128 billion, compared to $4.701 billion at December 31, 2019. The increase in liquidity was primarily due to an additional $2.8 billion of credit facilities secured in 2020 and the weakening of the Canadian dollar compared to the U.S. dollar since December 31, 2019, partially offset by increased short-term indebtedness. This increased financial flexibility is expected to help ensure the company has access to adequate financial resources should it be required.

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. We believe the disciplined actions around liquidity and capital spending the company has taken to address the recent economic downturn will help sustain the financial health of the company.

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 September 30, 2020, total debt to total debt plus shareholders' equity was 36.8% (December 31, 2019 – 29.9%) and increased due to higher debt levels and lower shareholders' equity as a result of net losses, including impairment charges recorded in the first quarter of 2020. The company continues to be in compliance with all operating covenants under its debt agreements.


($ millions, except as noted)	September 30 2020	December 31 2019

Short-term debt	2 586	2 155

Current portion of long-term debt	293	—

Current portion of long-term lease liabilities	273	310

Long-term debt	15 424	12 884

Long-term lease liabilities	2 623	2 621

Total debt	21 199	17 970

Less: Cash and cash equivalents	1 489	1 960

Net debt	19 710	16 010

Shareholders' equity	36 344	42 042

Total debt plus shareholders' equity	57 543	60 012

Total debt to total debt plus shareholders' equity (%)	36.8	29.9


($ millions)	Three months ended September 30, 2020		Nine months ended September 30, 2020

Total debt – beginning of period	21 880		17 970

Increase in long-term debt	—		2 634

(Decrease) increase in short-term debt	(370	)	354

Increase in lease liability	108		219

Lease payments	(83	)	(254	)

Foreign exchange on debt, and other	(336	)	276

Total debt – September 30, 2020	21 199		21 199

Less: Cash and cash equivalents – September 30, 2020	1 489		1 489

Net debt – September 30, 2020	19 710		19 710

The company's total debt decreased in the third quarter of 2020 due to the repayment of short-term debt, favourable foreign exchange rates on U.S. dollar denominated debt compared to June 30, 2020 and principal lease payments made during the third quarter of 2020, partially offset by leases entered into during the period.

On a year-to-date basis, the company's total debt increased in 2020 due to an increase in short-term and long-term indebtedness, unfavourable foreign exchange rates on U.S. dollar denominated debt compared to December 31, 2019 and leases entered into during the first nine months of 2020, partially offset by principal lease payments made during the first nine months of 2020.

As at October 26, 2020, the total number of common shares outstanding was 1,525,150,794 and the total number of exercisable and non-exercisable common share options outstanding was 38,571,913. Once exercisable, each outstanding common share option is convertible into one common share.

In May 2019, Suncor renewed its NCIB to continue to repurchase its common shares through the facilities of the Toronto Stock Exchange (TSX), New York Stock Exchange and/or alternative trading platforms between May 6, 2019 and May 5, 2020. The TSX subsequently accepted a notice filed by Suncor of its intention to amend the NCIB effective as of December 30, 2019 pursuant to which Suncor was permitted to increase the maximum number of common shares that may be purchased for cancellation.

Given the current business environment and aligned with our disciplined capital allocation strategy, share repurchases have been suspended and the company has decided not to renew its NCIB at this time.

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 2019 annual MD&A. 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.

Trends in Suncor's quarterly revenue, earnings and funds from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events, changes in commodity prices, including widening of 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, which led to planned production cuts, operational incidents and the Government of Alberta's mandatory production curtailments implemented during 2019.


Three months ended ($ millions, unless otherwise noted)	Sep 30 2020		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sept 30 2019		Jun 30 2019	Mar 31 2019	Dec 31 2018

Total production (mboe/d)

Oil Sands	519.0		553.7		630.1		662.3		670.0		692.2	657.2	740.8

Exploration and Production	97.2		101.8		109.7		115.9		92.3		111.7	107.1	90.2

	616.2		655.5		739.8		778.2		762.3		803.9	764.3	831.0

Revenues and other income

Operating revenues, net of royalties	6 427		4 229		7 391		9 487		9 803		10 071	8 983	8 561

Other income	30		16		365		111		93		27	414	384

	6 457		4 245		7 756		9 598		9 896		10 098	9 397	8 945

Net (loss) earnings	(12	)	(614	)	(3 525	)	(2 335	)	1 035		2 729	1 470	(280	)

per common share – basic (dollars)	(0.01	)	(0.40	)	(2.31	)	(1.52	)	0.67		1.74	0.93	(0.18	)

per common share – diluted (dollars)	(0.01	)	(0.40	)	(2.31	)	(1.52	)	0.67		1.74	0.93	(0.18	)

Operating (loss) earnings⁽¹⁾	(302	)	(1 489	)	(309	)	782		1 114		1 253	1 209	580

per common share – basic⁽¹⁾ (dollars)	(0.20	)	(0.98	)	(0.20	)	0.51		0.72		0.80	0.77	0.36

Funds from operations⁽¹⁾	1 166		488		1 001		2 553		2 675		3 005	2 585	2 007

per common share – basic⁽¹⁾ (dollars)	0.76		0.32		0.66		1.66		1.72		1.92	1.64	1.26

Cash flow provided by (used in) operating activities	1 245		(768	)	1 384		2 304		3 136		3 433	1 548	3 040

per common share – basic (dollars)	0.82		(0.50	)	0.91		1.50		2.02		2.19	0.98	1.90

ROCE⁽¹⁾ (%) for the twelve months ended	(10.2	)	(7.5	)	(1.3	)	4.9		9.7		10.4	8.2	8.0

ROCE⁽¹⁾⁽²⁾, excluding major projects in progress (%) for the twelve months ended	(10.8	)	(7.9	)	(1.4	)	5.1		9.9		10.6	8.3	8.2

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	290		478		(1 021	)	235		(127	)	221	261	(637	)

Common share information (dollars)

Dividend per common share	0.21		0.21		0.465		0.42		0.42		0.42	0.42	0.36

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	16.26		22.89		22.46		42.56		41.79		40.85	43.31	38.13

New York Stock Exchange (US$)	12.23		16.86		15.80		32.80		31.58		31.16	32.43	27.97

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): ROCE excluding major projects in progress would have been (1.4%) for the twelve months ended September 30, 2020, excluding the impact of impairments of $1.798 billion after-tax in the first quarter of 2020 and the impacts of impairments of $3.352 billion after-tax in the fourth quarter of 2019.


(average for the three months ended)		Sep 30 2020		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sept 30 2019		Jun 30 2019		Mar 31 2019		Dec 31 2018

WTI crude oil at Cushing	US$/bbl	40.95		27.85		46.10		56.95		56.45		59.85		54.90		58.85

Dated Brent crude	US$/bbl	43.00		29.20		50.15		63.30		61.90		68.85		63.20		67.80

Dated Brent/Maya FOB price differential	US$/bbl	3.50		2.70		15.95		9.30		5.20		6.75		4.45		4.35

MSW at Edmonton	Cdn$/bbl	51.30		30.20		52.00		68.10		68.35		73.90		66.45		42.70

WCS at Hardisty	US$/bbl	31.90		16.35		25.60		41.10		44.20		49.20		42.50		19.50

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(9.05	)	(11.50	)	(20.50	)	(15.85	)	(12.25	)	(10.65	)	(12.40	)	(39.35	)

SYN-WTI (differential) premium	US$/bbl	(2.45	)	(4.55	)	(2.70	)	(0.70	)	0.40		0.15		(2.30	)	(21.60	)

Condensate at Edmonton	US$/bbl	37.55		22.20		46.20		53.00		52.00		55.85		50.50		45.30

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.25		2.00		2.05		2.50		0.95		1.05		2.60		1.60

Alberta Power Pool Price	Cdn$/MWh	43.85		29.90		67.05		46.95		46.85		56.55		69.45		55.55

New York Harbor 2-1-1 crack⁽¹⁾	US$/bbl	10.20		12.20		14.75		18.45		19.70		22.40		19.10		18.75

Chicago 2-1-1 crack⁽¹⁾	US$/bbl	7.75		6.75		9.75		14.35		17.05		21.50		15.40		16.25

Portland 2-1-1 crack⁽¹⁾	US$/bbl	12.55		12.20		18.30		25.45		23.90		29.10		19.35		24.25

Gulf Coast 2-1-1 crack⁽¹⁾	US$/bbl	8.55		9.00		13.00		17.00		20.00		21.70		17.90		17.45

Exchange rate	US$/Cdn$	0.75		0.72		0.74		0.76		0.76		0.75		0.75		0.76

Exchange rate (end of period)	US$/Cdn$	0.75		0.73		0.71		0.77		0.76		0.76		0.75		0.73

(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.

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 2019 annual MD&A and in note 2 of Suncor's unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2020.

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, 2019 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2019 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 downturn 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 nine months ended September 30, 2020.

The COVID-19 pandemic is an evolving situation that will 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 (loss) income, consolidated balance sheets and consolidated statements of cash flows in fiscal 2020.

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 26 of the audited Consolidated Financial Statements for the year ended December 31, 2019, note 9 to the unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2020, and the Financial Condition and Liquidity section of the 2019 annual MD&A.

Based on their evaluation as at September 30, 2020, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)) are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at September 30, 2020, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three-month period ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

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

Suncor has further updated its previously issued 2020 guidance (which was originally disclosed via press release on December 2, 2019, as updated via press release on March 23, 2020, May 5, 2020, July 22, 2020 and September 7, 2020), as set forth in Suncor's press release dated October 28, 2020. All of these press releases are available on www.sedar.com.

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

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 operating earnings (loss) to evaluate operating performance because management believes it provides better comparability between periods. Operating earnings (loss) are reconciled to net earnings (loss) in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A.

Throughout this MD&A, the company presents charts that illustrate the change in operating earnings (loss) from the comparative period through key variance factors. These factors are analyzed in the Operating Earnings (Loss) narratives following the bridge analyses in particular sections of this MD&A. These bridge analyses are presented because management uses this presentation to evaluate performance.

ROCE is a non-GAAP financial measure that management uses to analyze operating performance and the efficiency of Suncor's capital allocation process. 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.

The company presents two ROCE calculations – one including and one excluding the impacts on capital employed for major projects in progress. Major projects in progress includes accumulated capital expenditures and capitalized interest for significant projects still under construction or in the process of being commissioned, and acquired assets that are still being evaluated. Management uses ROCE excluding the impacts of major projects in progress on capital employed to assess the performance of operating assets.


For the twelve months ended September 30 ($ millions, except as noted)		2020		2019

Adjustments to net earnings

Net (loss) earnings		(6 486	)	4 954

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		18		282

Net interest expense		665		625

	A	(5 803	)	5 861

Capital employed – beginning of twelve-month period

Net debt		15 601		14 345

Shareholders' equity		45 184		45 800

		60 785		60 145

Capital employed – end of twelve-month period

Net debt		19 710		15 601

Shareholders' equity		36 344		45 184

		56 054		60 785

Average capital employed	B	57 022		60 729

ROCE – including major projects in progress (%)	A/B	(10.2	)	9.7

Average capitalized costs related to major projects in progress	C	3 316		1 774

ROCE – excluding major projects in progress (%)⁽¹⁾	A/(B-C)	(10.8	)	9.9

(1): ROCE excluding major projects in progress would have been (1.4%) for the twelve months ended September 30, 2020, excluding the impact of impairments of $1.798 billion after-tax in the first quarter of 2020 and the impacts of impairments of $3.352 billion after-tax in the fourth quarter of 2019.

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

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.


Three months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2020		2019		2020		2019		2020		2019		2020		2019		2020		2019

Net (loss) earnings	(531	)	505		25		219		384		668		110		(357	)	(12	)	1 035

Adjustments for:

Depreciation, depletion, amortization and impairment	1 242		1 036		261		220		214		209		21		19		1 738		1 484

Deferred income taxes	(141	)	62		(9	)	19		12		19		(46	)	(19	)	(184	)	81

Accretion	57		54		12		11		2		1		—		—		71		66

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(307	)	133		(307	)	133

Change in fair value of financial instruments and trading inventory	(53	)	(3	)	(28	)	(4	)	(8	)	(21	)	—		—		(89	)	(28	)

(Gain) loss on disposal of assets	(2	)	(3	)	—		(77	)	(2	)	(1	)	1		—		(3	)	(81	)

Share-based compensation	(9	)	19		(2	)	2		(6	)	11		(27	)	34		(44	)	66

Exploration	—		—		—		—		—		—		—		—		—		—

Settlement of decommissioning and restoration liabilities	(38	)	(105	)	(1	)	(11	)	—		(7	)	—		—		(39	)	(123	)

Other	31		41		2		—		(2	)	6		4		(5	)	35		42

Funds from (used in) operations	556		1 606		260		379		594		885		(244	)	(195	)	1 166		2 675

Decrease in non-cash working capital																	79		461

Cash flow provided by operating activities																	1 245		3 136


Nine months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2020		2019		2020		2019		2020		2019		2020		2019		2020		2019

Net (loss) earnings	(3 503	)	2 255		(453	)	1 167		598		2 442		(793	)	(630	)	(4 151	)	5 234

Adjustments for:

Depreciation, depletion, amortization and impairment	5 372		3 088		1 312		702		660		612		62		57		7 406		4 459

Deferred income taxes	(643	)	(675	)	(161	)	(103	)	29		(42	)	(20	)	(96	)	(795	)	(916	)

Accretion	169		167		35		33		5		5		—		—		209		205

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		290		(378	)	290		(378	)

Change in fair value of financial instruments and trading inventory	32		41		(22	)	3		53		76		—		—		63		120

Gain on disposal of assets	(2	)	(13	)	—		(228	)	(6	)	(3	)	—		—		(8	)	(244	)

Share-based compensation	(84	)	(6	)	(12	)	(2	)	(51	)	(8	)	(186	)	(3	)	(333	)	(19	)

Exploration	—		—		80		39		—		—		—		—		80		39

Settlement of decommissioning and restoration liabilities	(171	)	(285	)	(7	)	(16	)	(5	)	(12	)	—		—		(183	)	(313	)

Other	87		84		(30	)	(7	)	10		—		10		1		77		78

Funds from (used in) operations	1 257		4 656		742		1 588		1 293		3 070		(637	)	(1 049	)	2 655		8 265

Increase in non-cash working capital																	(794	)	(148	)

Cash flow provided by operating activities																	1 861		8 117

Free funds flow is a non-GAAP financial measure that is calculated by taking 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 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.

Oil Sands operations, Syncrude and Fort Hills cash operating costs are non-GAAP financial measures. Oil Sands operations cash operating costs are calculated by adjusting Oil Sands segment OS&G expense (a GAAP measure based on sales volumes) for i) costs pertaining to Fort Hills and Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, CEWS and COVID-19 related costs, research and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; iv) project startup costs; and v) the impacts of changes in inventory levels and valuation, such that the company is able to present cost information based on production volumes. Beginning in the first quarter of 2020, the

company revised Syncrude cash operating costs to better align with the Oil Sands operations and Fort Hills cash operating costs methodology. Prior period Syncrude cash operating costs had previously included future development costs and have been restated to exclude these costs. Syncrude and Fort Hills cash operating costs are calculated by adjusting Syncrude OS&G expense and Fort Hills OS&G expense, respectively, for non-production costs that management believes do not relate to the production performance of Syncrude operations or Fort Hills operations, respectively, including, but not limited to, share-based compensation, research and project startup costs, CEWS and COVID-19 related costs, if applicable. Oil Sands operations, Fort Hills and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this MD&A. Management uses cash operating costs to measure operating performance.

Refining and marketing margin and refining operating expense are non-GAAP financial measures. Refining and marketing margin 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 non-refining margin pertaining to the company's supply, marketing and ethanol businesses, as well as removing the impact of marketing and logistics gains and losses. Refinery operating expense is calculated by adjusting R&M segment OS&G for i) non-refining costs pertaining to the company's supply, marketing and ethanol businesses; and ii) non-refining costs that management believes do not relate to the production of refined products, including, but not limited to, share-based compensation and enterprise shared service allocations. Management uses refining and marketing margin and refining operating expense to measure operating performance on a production barrel basis.


	Three months ended September 30				Nine months ended September 30
($ millions, except as noted)	2020		2019		2020		2019

Refining and marketing margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 210		1 653		2 897		5 440

Other (loss) income	(2	)	13		58		42

Non-refining margin	(14	)	(17	)	(43	)	(44	)

Refining and marketing margin	1 194		1 649		2 912		5 438

Refinery production⁽¹⁾ (mbbls)	38 857		46 239		115 955		129 283

Refining and marketing margin – FIFO⁽²⁾ ($/bbl)	30.75		35.65		25.10		42.05

LIFO adjustment	(223	)	19		562		(665	)

Refining and marketing margin – LIFO	971		1 668		3 474		4 773

Refining and marketing margin – LIFO⁽²⁾ ($/bbl)	25.00		36.10		29.95		36.90

Refining operating expense reconciliation

Operating, selling and general expense	457		531		1 385		1 597

Non-refining costs	(247	)	(305	)	(735	)	(894	)

Refining operating expense	210		226		650		703

Refinery production⁽¹⁾ (mbbls)	38 857		46 239		115 955		129 283

Refining operating expense ($/bbl)	5.40		4.90		5.60		5.45

(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): Beginning in the first quarter of 2020, refining and marketing margins have been revised to better reflect the refining, product supply and rack forward businesses. Prior periods have been restated to reflect this change.

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.

This MD&A 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 MD&A include references to:

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them. The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, E&P, and R&M, may be affected by a number of factors.

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

the company's ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools).

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

Factors that affect 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 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 MD&A, and in the company's 2019 annual MD&A, the 2019 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 MD&A are made as of the date of this MD&A. Except as required by applicable securities laws, we assume no obligation to update publicly or otherwise revise any forward-looking statements or the foregoing risks and assumptions affecting such forward-looking statements, whether as a result of new information, future events or otherwise.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Revenues and Other Income

Operating revenues, net of royalties (note 3)	6 427		9 803		18 047		28 857

Other income (note 4)	30		93		411		534

	6 457		9 896		18 458		29 391

Expenses

Purchases of crude oil and products	2 356		3 402		6 955		9 309

Operating, selling and general (note 10)	2 275		2 793		7 398		8 424

Transportation	281		378		946		1 075

Depreciation, depletion, amortization and impairment (note 11)	1 738		1 484		7 406		4 459

Exploration	12		15		176		204

Gain on disposal of assets	(3	)	(81	)	(8	)	(244	)

Financing expenses (note 6)	35		433		1 241		562

	6 694		8 424		24 114		23 789

(Loss) Earnings before Income Taxes	(237	)	1 472		(5 656	)	5 602

Income Tax (Recovery) Expense

Current	(41	)	356		(710	)	1 284

Deferred	(184	)	81		(795	)	(916	)

	(225	)	437		(1 505	)	368

Net (Loss) Earnings	(12	)	1 035		(4 151	)	5 234

Other Comprehensive Income (Loss)

Items That May be Subsequently Reclassified to Earnings:

Foreign currency translation adjustment	(52	)	4		80		(144	)

Items That Will Not be Reclassified to Earnings:

Actuarial gain (loss) on employee retirement benefit plans, net of income taxes	204		55		(195	)	(258	)

Other Comprehensive Income (Loss)	152		59		(115	)	(402	)

Total Comprehensive Income (Loss)	140		1 094		(4 266	)	4 832

Per Common Share (dollars) (note 7)

Net (loss) earnings – basic and diluted	(0.01	)	0.67		(2.72	)	3.34

Cash dividends	0.21		0.42		0.89		1.26

See accompanying notes to the condensed interim consolidated financial statements.


($ millions)	September 30 2020	December 31 2019

Assets

Current assets

Cash and cash equivalents	1 489	1 960

Accounts receivable	2 742	4 052

Inventories (note 10)	3 325	3 761

Income taxes receivable	791	133

Total current assets	8 347	9 906

Property, plant and equipment, net (note 11)	67 976	72 640

Exploration and evaluation	2 442	2 428

Other assets	1 271	1 194

Goodwill and other intangible assets	3 266	3 058

Deferred income taxes	200	209

Total assets	83 502	89 435

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	2 586	2 155

Current portion of long-term debt	293	—

Current portion of long-term lease liabilities	273	310

Accounts payable and accrued liabilities	4 642	6 555

Current portion of provisions	642	631

Income taxes payable	69	886

Total current liabilities	8 505	10 537

Long-term debt	15 424	12 884

Long-term lease liabilities	2 623	2 621

Other long-term liabilities	2 753	2 499

Provisions (note 12)	8 552	8 676

Deferred income taxes	9 301	10 176

Equity	36 344	42 042

Total liabilities and shareholders' equity	83 502	89 435

See accompanying notes to the condensed interim consolidated financial statements.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Operating Activities

Net (Loss) Earnings	(12	)	1 035		(4 151	)	5 234

Adjustments for:

Depreciation, depletion, amortization and impairment (note 11)	1 738		1 484		7 406		4 459

Deferred income tax (recovery) expense	(184	)	81		(795	)	(916	)

Accretion (note 6)	71		66		209		205

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (note 6)	(307	)	133		290		(378	)

Change in fair value of financial instruments and inventory	(89	)	(28	)	63		120

Gain on disposal of assets	(3	)	(81	)	(8	)	(244	)

Share-based compensation	(44	)	66		(333	)	(19	)

Exploration	—		—		80		39

Settlement of decommissioning and restoration liabilities	(39	)	(123	)	(183	)	(313	)

Other	35		42		77		78

Decrease (increase) in non-cash working capital	79		461		(794	)	(148	)

Cash flow provided by operating activities	1 245		3 136		1 861		8 117

Investing Activities

Capital and exploration expenditures	(941	)	(1 516	)	(2 959	)	(3 783	)

Proceeds from disposal of assets	5		96		12		262

Other investments	(3	)	(35	)	(90	)	(134	)

Decrease (increase) in non-cash working capital	130		389		(414	)	383

Cash flow used in investing activities	(809	)	(1 066	)	(3 451	)	(3 272	)

Financing Activities

Net (decrease) increase in short-term debt	(370	)	(572	)	354		(1 527	)

Net increase in long-term debt	—		—		2 634		557

Lease liability payments	(83	)	(88	)	(254	)	(230	)

Issuance of common shares under share option plans	—		18		29		59

Repurchase of common shares (note 8)	—		(756	)	(307	)	(1 822	)

Distributions relating to non-controlling interest	(3	)	(2	)	(8	)	(6	)

Dividends paid on common shares	(321	)	(650	)	(1 350	)	(1 970	)

Cash flow (used in) provided by financing activities	(777	)	(2 050	)	1 098		(4 939	)

(Decrease) Increase in Cash and Cash Equivalents	(341	)	20		(492	)	(94	)

Effect of foreign exchange on cash and cash equivalents	(16	)	8		21		(38	)

Cash and cash equivalents at beginning of period	1 846		2 061		1 960		2 221

Cash and Cash Equivalents at End of Period	1 489		2 089		1 489		2 089

Supplementary Cash Flow Information

Interest paid	140		133		648		639

Income taxes paid	118		482		696		880

See accompanying notes to the condensed interim consolidated financial statements.


($ millions)	Share Capital		Contributed Surplus		Accumulated Other Comprehensive Income		Retained Earnings		Total		Number of Common Shares (thousands)

At December 31, 2018	25 910		540		1 076		16 479		44 005		1 584 484

Adoption of IFRS 16 impact	—		—		—		14		14		—

At January 1, 2019, adjusted	25 910		540		1 076		16 493		44 019		1 584 484

Net earnings	—		—		—		5 234		5 234		—

Foreign currency translation adjustment	—		—		(144	)	—		(144	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $89	—		—		—		(258	)	(258	)	—

Total comprehensive (loss) income	—		—		(144	)	4 976		4 832		—

Issued under share option plans	76		(16	)	—		—		60		1 737

Repurchase of common shares for cancellation (note 8)	(722	)	—		—		(1 100	)	(1 822	)	(44 158	)

Change in liability for share repurchase commitment	17		—		—		6		23		—

Share-based compensation	—		42		—		—		42		—

Dividends paid on common shares	—		—		—		(1 970	)	(1 970	)	—

At September 30, 2019	25 281		566		932		18 405		45 184		1 542 063

At December 31, 2019	25 167		566		899		15 410		42 042		1 531 874

Net loss	—		—		—		(4 151	)	(4 151	)	—

Foreign currency translation adjustment	—		—		80		—		80		—

Actuarial loss on employee retirement benefit plans, net of income taxes of $60	—		—		—		(195	)	(195	)	—

Total comprehensive income (loss)	—		—		80		(4 346	)	(4 266	)	—

Issued under share option plans	36		(5	)	—		—		31		804

Repurchase of common shares for cancellation (note 8)	(124	)	—		—		(183	)	(307	)	(7 527	)

Change in liability for share repurchase commitment	65		—		—		103		168		—

Share-based compensation	—		26		—		—		26		—

Dividends paid on common shares	—		—		—		(1 350	)	(1 350	)	—

At September 30, 2020	25 144		587		979		9 634		36 344		1 525 151

See accompanying notes to the condensed interim consolidated financial statements.

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.

These condensed interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board (IASB). 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 consolidated financial statements of the company for the year ended December 31, 2019.

The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in the company's consolidated financial statements for the year ended December 31, 2019.

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

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 consolidated financial statements for the year ended December 31, 2019.

On January 30, 2020, the World Health Organization declared the Coronavirus disease (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 caused 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 downturn 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 financial statement note.

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.

Government grants are recognized when the company has reasonable assurance that it has complied with the relevant conditions of the grant and that it will be received. The company recognizes the grant against the financial statement line item that it is intended to compensate, or to Other income if the grant is recognized in a different period than the underlying transaction.

In October 2018, the IASB issued Definition of a Business (Amendments to IFRS 3). The amendments narrowed and clarified the definition of a business. The amendments include an election to use a concentration test. This is a simplified assessment that results in treatment of an acquisition as an asset acquisition if substantially all of the fair value of the gross assets is concentrated in a single identifiable asset or a group of similar identifiable assets. If an election to use a concentration test is not made, or the test failed, then the assessment focuses on the existence of a substantive process. One important distinction is that "goodwill" can only be recognized as a result of acquiring a business, but not as a result of an asset acquisition. The company adopted the amendments prospectively on the effective date of January 1, 2020, and there was no impact to the company's consolidated financial statements as a result of the initial application.

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 September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2020		2019		2020		2019		2020		2019		2020		2019		2020		2019

Revenues and Other Income

Gross revenues	1 949		3 472		512		746		4 027		5 912		5		5		6 493		10 135

Intersegment revenues	618		1 129		—		—		23		17		(641	)	(1 146	)	—		—

Less: Royalties	(36	)	(235	)	(30	)	(97	)	—		—		—		—		(66	)	(332	)

Operating revenues, net of royalties	2 531		4 366		482		649		4 050		5 929		(636	)	(1 141	)	6 427		9 803

Other income (loss)	40		63		(9	)	15		(2	)	13		1		2		30		93

	2 571		4 429		473		664		4 048		5 942		(635	)	(1 139	)	6 457		9 896

Expenses

Purchases of crude oil and products	171		284		—		—		2 840		4 276		(655	)	(1 158	)	2 356		3 402

Operating, selling and general	1 650		2 009		118		129		457		531		50		124		2 275		2 793

Transportation	236		344		24		19		31		30		(10	)	(15	)	281		378

Depreciation, depletion, amortization and impairment	1 242		1 037		261		220		214		209		21		18		1 738		1 484

Exploration	2		2		10		13		—		—		—		—		12		15

(Gain) Loss on disposal of assets	(2	)	(3	)	—		(77	)	(2	)	(1	)	1		—		(3	)	(81	)

Financing expenses (income)	81		94		14		20		11		6		(71	)	313		35		433

	3 380		3 767		427		324		3 551		5 051		(664	)	(718	)	6 694		8 424

(Loss) Earnings before Income Taxes	(809	)	662		46		340		497		891		29		(421	)	(237	)	1 472

Income Tax (Recovery) Expense

Current	(137	)	95		30		102		101		204		(35	)	(45	)	(41	)	356

Deferred	(141	)	62		(9	)	19		12		19		(46	)	(19	)	(184	)	81

	(278	)	157		21		121		113		223		(81	)	(64	)	(225	)	437

Net (Loss) Earnings	(531	)	505		25		219		384		668		110		(357	)	(12	)	1 035

Capital and Exploration Expenditures	661		1 000		99		293		156		202		25		21		941		1 516


Nine months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2020		2019		2020		2019		2020		2019		2020		2019		2020		2019

Revenues and Other Income

Gross revenues	5 491		10 676		1 344		2 677		11 327		16 694		20		19		18 182		30 066

Intersegment revenues	2 045		3 246		—		—		69		65		(2 114	)	(3 311	)	—		—

Less: Royalties	(77	)	(774	)	(58	)	(435	)	—		—		—		—		(135	)	(1 209	)

Operating revenues, net of royalties	7 459		13 148		1 286		2 242		11 396		16 759		(2 094	)	(3 292	)	18 047		28 857

Other income (loss)	311		74		48		410		58		42		(6	)	8		411		534

	7 770		13 222		1 334		2 652		11 454		16 801		(2 100	)	(3 284	)	18 458		29 391

Expenses

Purchases of crude oil and products	669		961		—		—		8 499		11 319		(2 213	)	(2 971	)	6 955		9 309

Operating, selling and general	5 430		6 042		362		391		1 385		1 597		221		394		7 398		8 424

Transportation	797		968		80		59		101		86		(32	)	(38	)	946		1 075

Depreciation, depletion, amortization and impairment	5 372		3 089		1 312		702		660		612		62		56		7 406		4 459

Exploration	60		114		116		90		—		—		—		—		176		204

Gain on disposal of assets	(2	)	(13	)	—		(228	)	(6	)	(3	)	—		—		(8	)	(244	)

Financing expenses	254		237		31		48		26		33		930		244		1 241		562

	12 580		11 398		1 901		1 062		10 665		13 644		(1 032	)	(2 315	)	24 114		23 789

(Loss) Earnings before Income Taxes	(4 810	)	1 824		(567	)	1 590		789		3 157		(1 068	)	(969	)	(5 656	)	5 602

Income Tax (Recovery) Expense

Current	(664	)	244		47		526		162		757		(255	)	(243	)	(710	)	1 284

Deferred	(643	)	(675	)	(161	)	(103	)	29		(42	)	(20	)	(96	)	(795	)	(916	)

	(1 307	)	(431	)	(114	)	423		191		715		(275	)	(339	)	(1 505	)	368

Net (Loss) Earnings	(3 503	)	2 255		(453	)	1 167		598		2 442		(793	)	(630	)	(4 151	)	5 234

Capital and Exploration Expenditures	2 108		2 440		409		789		334		504		108		50		2 959		3 783

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 September 30	2020					2019
($ millions)	North America		International	Total		North America		International	Total

Oil Sands⁽¹⁾

SCO and diesel	2 040		—	2 040		3 344		—	3 344

Bitumen	527		—	527		1 257		—	1 257

	2 567		—	2 567		4 601		—	4 601

Exploration and Production

Crude oil and natural gas liquids	311		200	511		393		352	745

Natural gas	—		1	1		—		1	1

	311		201	512		393		353	746

Refining and Marketing

Gasoline	1 953		—	1 953		2 704		—	2 704

Distillate	1 534		—	1 534		2 401		—	2 401

Other	563		—	563		824		—	824

	4 050		—	4 050		5 929		—	5 929

Corporate and Eliminations

	(636	)	—	(636	)	(1 141	)	—	(1 141	)

Total Revenue from Contracts with Customers	6 292		201	6 493		9 782		353	10 135

(1): Prior period amounts have been reclassified to conform with current period presentation.


Nine months ended September 30	2020					2019
($ millions)	North America		International	Total		North America		International	Total

Oil Sands⁽¹⁾

SCO and diesel	6 131		—	6 131		10 384		—	10 384

Bitumen	1 405		—	1 405		3 538		—	3 538

	7 536		—	7 536		13 922		—	13 922

Exploration and Production

Crude oil and natural gas liquids	790		551	1 341		1 391		1 282	2 673

Natural gas	—		3	3		—		4	4

	790		554	1 344		1 391		1 286	2 677

Refining and Marketing

Gasoline	4 979		—	4 979		7 470		—	7 470

Distillate	4 798		—	4 798		7 039		—	7 039

Other	1 619		—	1 619		2 250		—	2 250

	11 396		—	11 396		16 759		—	16 759

Corporate and Eliminations

	(2 094	)	—	(2 094	)	(3 292	)	—	(3 292	)

Total Revenue from Contracts with Customers	17 628		554	18 182		28 780		1 286	30 066

(1): Prior period amounts have been reclassified to conform with current period presentation.


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Energy trading activities

(Losses) gains recognized in earnings	(15	)	49		152		159

Losses on inventory valuation	(18	)	(11	)	(28	)	(46	)

Short-term commodity risk management	22		44		121		(2	)

Investment and interest income	29		36		78		86

Insurance proceeds⁽¹⁾	—		—		49		397

Other	12		(25	)	39		(60	)

	30		93		411		534

(1): Nine months ended September 30, 2020 includes insurance proceeds for MacKay River within the Oil Sands segment, and nine months ended September 30, 2019 includes insurance proceeds for Syncrude and Libyan assets within the Oil Sands segment and Exploration and Production segment respectively.

The following table summarizes the share-based compensation (recovery) expense for all plans recorded within Operating, Selling and General expense:


	Three months ended September 30				Nine months ended September 30
($ millions)	2020		2019		2020		2019

Interest on debt	225		205		666		617

Interest on lease liabilities	42		42		126		130

Capitalized interest	(29	)	(29	)	(94	)	(85	)

Interest expense	238		218		698		662

Interest on partnership liability	13		13		39		41

Interest on pension and other post-retirement benefits	14		15		41		45

Accretion	71		66		209		205

Foreign exchange (gain) loss on U.S. dollar denominated debt	(307	)	133		290		(378	)

Operational foreign exchange and other	6		(12	)	(36	)	(13	)

	35		433		1 241		562

The company issued $1.25 billion of senior unsecured Series 7 Medium Term Notes maturing on April 9, 2030 during the second quarter of 2020. The Series 7 Medium Term Notes have a coupon of 5.00% and were priced at $99.697 per $100 principal amount for an effective yield of 5.039%. Interest on the Series 7 Medium Term Notes is paid semi-annually.

During the second quarter of 2020, the company issued US$450 million of senior unsecured notes maturing on May 15, 2023. The notes have a coupon of 2.80% and were priced at US$99.903 per US$100 principal amount for an effective yield of 2.834%. The company also issued US$550 million of senior unsecured notes maturing on May 15, 2025. The notes have a coupon of 3.10% and were priced at US$99.949 per US$100 principal amount for an effective yield of 3.111%. Interest on the 2.80% and 3.10% notes is paid semi-annually.

The company secured an additional $2.5 billion and $300 million of credit facilities in the first and second quarters of 2020, respectively, with its key banking partners under new credit agreements. These agreements have the same terms and covenants as our existing credit facilities.


	Three months ended September 30			Nine months ended September 30
($ millions)	2020		2019	2020		2019

Net (loss) earnings	(12	)	1 035	(4 151	)	5 234

(millions of common shares)

Weighted average number of common shares	1 525		1 552	1 526		1 566

Dilutive securities:

Effect of share options	—		2	—		3

Weighted average number of diluted common shares	1 525		1 554	1 526		1 569

(dollars per common share)

Basic and diluted (loss) earnings per share	(0.01	)	0.67	(2.72	)	3.34

On May 1, 2019, the company announced its intention to renew its existing normal course issuer bid (the 2019 NCIB) to continue to repurchase shares under its previously announced buyback program through the facilities of the Toronto Stock Exchange, the New York Stock Exchange and/or alternative trading platforms. Pursuant to the 2019 NCIB, the company was permitted to purchase for cancellation up to 50,252,231 of its common shares between May 6, 2019 and May 5, 2020. On December 23, 2019, Suncor announced an amendment to the 2019 NCIB, effective as of December 30, 2019, which allowed the company to increase the maximum number of common shares that could have been repurchased between May 6, 2019 and May 5, 2020 to 78,549,178. The COVID-19 pandemic has created significant uncertainly in the business environment and, consistent with our disciplined capital allocation strategy, share purchases have been suspended and the company decided not to renew the 2019 NCIB at this time.

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

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.

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:

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 non-designated derivative financial instruments measured at fair value for each hierarchy level as at September 30, 2020:

During the third quarter of 2020, 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.

At September 30, 2020, the carrying value of fixed-term debt accounted for under amortized cost was $15.7 billion (December 31, 2019 – $12.9 billion) and the fair value was $18.5 billion (December 31, 2019 – $16.1 billion). The increase in carrying value and fair value of debt is mainly due to issuance of new debt during the second quarter of this year. The estimated fair value of long-term debt is based on pricing sourced from market data.

At June 30, 2020, the company recorded a hydrocarbon inventory write-down to net realizable value of $61 million ($45 million after-tax) which was subsequently sold in the third quarter.

At March 31, 2020, the company recorded a hydrocarbon inventory write-down to net realizable value of $536 million ($397 million after-tax) which was subsequently sold in the second quarter.

The COVID-19 pandemic has resulted in a significant decrease in global demand for crude oil and commodity prices. In response, the company announced plans to reduce capital and operating costs. As a result of these events, the company performed asset impairment tests on certain cash generating units (CGUs) in its Oil Sands and Exploration and Production segments as at March 31, 2020 and September 30, 2020 as the recoverable amounts of these CGUs were most sensitive to the combined reduction in crude oil prices and changes to their respective capital and operating plans. The impairment tests were 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):

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 project in the Oil Sands segment using the following asset-specific assumptions:

The recoverable amount of the Fort Hills CGU was $6.4 billion as at March 31, 2020. 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 increase to the impairment charge of approximately $1.1 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 increase to the impairment charge of approximately $1.1 billion (after-tax) on the company's share of the Fort Hills assets.

No indicators of impairment or reversals of impairment were identified as at September 30, 2020.

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 and $137 million (net of taxes of $45 million) on its share of the White Rose assets in the Exploration and Production segment using the following asset-specific assumptions:

The recoverable amount of the Terra Nova CGU was $24 million as at March 31, 2020.

No indicators of impairment or reversals of impairment were identified as at September 30, 2020.

The recoverable amount of the White Rose CGU was $185 million as at March 31, 2020. 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 increase to the impairment charge of approximately $83 million (after-tax) on the company's share of the White Rose assets. A 1% increase in the discount rate would have resulted in an increase to the impairment charge of approximately $45 million (after-tax) on the company's share of the White Rose assets.

In the third quarter of 2020, the operator of the West White Rose expansion project announced plans to evaluate the project scope, schedule and cost. As at September 30, 2020, the company performed an impairment test for the White Rose CGU and the estimated recoverable amount approximated its carrying value, as the impact of deferring production and capital by one year had offsetting impacts on the recoverable amount, thus no impairment or reversal of impairment was required.

Suncor's decommissioning and restoration provision decreased by $145 million for the nine months ended September 30, 2020. The decrease was primarily due to an increase in the credit-adjusted risk-free interest rate to 3.40% (December 31, 2019 – 3.30%).

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
QUARTERLY FINANCIAL SUMMARY
(unaudited)


	Three months ended															Nine months ended						Twelve months ended
($ millions, except per share amounts)	Sep 30 2020			Jun 30 2020			Mar 31 2020			Dec 31 2019			Sep 30 2019			Sep 30 2020			Sep 30 2019			Dec 31 2019

Revenues, net of royalties, and other income		6 457			4 245			7 756			9 598			9 896			18 458			29 391			38 989

Net (loss) earnings

Oil Sands		(531	)		(1 019	)		(1 953	)		(2 682	)		505			(3 503	)		2 255			(427	)

Exploration and Production		25			(51	)		(427	)		(162	)		219			(453	)		1 167			1 005

Refining and Marketing		384			269			(55	)		558			668			598			2 442			3 000

Corporate and Eliminations		110			187			(1 090	)		(49	)		(357	)		(793	)		(630	)		(679	)

Total		(12	)		(614	)		(3 525	)		(2 335	)		1 035			(4 151	)		5 234			2 899

Operating (loss) earnings^(A)

Oil Sands		(531	)		(1 196	)		(400	)		277			505			(2 127	)		1 345			1 622

Exploration and Production		25			(51	)		(5	)		231			171			(31	)		910			1 141

Refining and Marketing		384			49			165			558			668			598			2 354			2 912

Corporate and Eliminations		(180	)		(291	)		(69	)		(284	)		(230	)		(540	)		(1 033	)		(1 317	)

Total		(302	)		(1 489	)		(309	)		782			1 114			(2 100	)		3 576			4 358

Funds from (used in) operations^(A)

Oil Sands		556			10			691			1 405			1 606			1 257			4 656			6 061

Exploration and Production		260			309			173			555			379			742			1 588			2 143

Refining and Marketing		594			475			224			793			885			1 293			3 070			3 863

Corporate and Eliminations		(244	)		(306	)		(87	)		(200	)		(195	)		(637	)		(1 049	)		(1 249	)

Total		1 166			488			1 001			2 553			2 675			2 655			8 265			10 818

Change in non-cash working capital		79			(1 256	)		383			(249	)		461			(794	)		(148	)		(397	)

Cash flow provided by (used in) operating activities		1 245			(768	)		1 384			2 304			3 136			1 861			8 117			10 421

Per common share

Net (loss) earnings – basic		(0.01	)		(0.40	)		(2.31	)		(1.52	)		0.67			(2.72	)		3.34			1.86

Operating (loss) earnings – basic^(A)		(0.20	)		(0.98	)		(0.20	)		0.51			0.72			(1.38	)		2.28			2.80

Cash dividends – basic		0.21			0.21			0.47			0.42			0.42			0.89			1.26			1.68

Funds from operations – basic^(A)		0.76			0.32			0.66			1.66			1.72			1.74			5.28			6.94

Cash flow provided by (used in) operating activities – basic		0.82			(0.50	)		0.91			1.50			2.02			1.22			5.19			6.69

Capital and exploration expenditures (including capitalized interest)

Oil Sands		661			437			1 010			1 082			1 000			2 108			2 440			3 522

Exploration and Production		99			131			179			281			293			409			789			1 070

Refining and Marketing		156			86			92			314			202			334			504			818

Corporate and Eliminations		25			44			39			98			21			108			50			148

Total capital and exploration expenditures		941			698			1 320			1 775			1 516			2 959			3 783			5 558

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Nine months ended				Twelve months ended
Oil Sands	Sep 30 2020		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sep 30 2019		Sep 30 2020		Sep 30 2019		Dec 31 2019

Production Volumes^(B)

Upgraded product (SCO and diesel) production (mbbls/d)

Oil Sands operations		252.3		319.4		331.8		300.0		317.0		301.1		317.8		313.3

Syncrude		158.5		117.2		171.8		156.3		162.3		149.2		177.6		172.3

Total upgraded production		410.8		436.6		503.6		456.3		479.3		450.3		495.4		485.6

Non-upgraded bitumen production (mbbls/d)

Oil Sands operations		65.6		69.8		45.8		118.1		105.2		60.4		93.3		99.5

Fort Hills		42.6		47.3		80.7		87.9		85.5		56.8		84.4		85.3

Total Oil Sands non-upgraded bitumen production		108.2		117.1		126.5		206.0		190.7		117.2		177.7		184.8

Total Oil Sands production volumes (mbbls/d)		519.0		553.7		630.1		662.3		670.0		567.5		673.1		670.4

Oil Sands Sales Volumes (mbbls/d)

Upgraded product (SCO and diesel)		420.1		443.1		512.5		447.6		483.1		458.4		495.6		483.6

Non-upgraded bitumen		119.1		116.4		127.5		218.1		201.8		121.0		177.1		187.5

Total Oil Sands sales volumes		539.2		559.5		640.0		665.7		684.9		579.4		672.7		671.1

Oil Sands operations cash operating costs – Average^(1)(A) ($/bbl)*

Cash costs		28.85		23.55		27.15		26.00		25.65		26.35		26.60		26.35

Natural gas		2.90		2.25		2.30		2.55		0.95		2.45		1.50		1.85

		31.75		25.80		29.45		28.55		26.60		28.80		28.10		28.20

Fort Hills bitumen cash operating costs^(1)(A) ($/bbl)*

Cash costs		33.05		33.40		29.40		27.05		23.65		31.45		24.25		24.95

Natural gas		2.15		1.95		1.60		1.60		0.60		1.80		1.05		1.20

		35.20		35.35		31.00		28.65		24.25		33.25		25.30		26.15

Syncrude SCO cash operating costs^(1)(A)(C) ($/bbl)*

Cash costs		33.30		36.70		35.30		37.30		38.95		34.95		35.25		35.65

Natural gas		1.05		1.65		1.35		1.55		0.70		1.30		0.90		1.10

		34.35		38.35		36.65		38.85		39.65		36.25		36.15		36.75

(A): 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): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company's assets.
(C): Syncrude cash operating costs have been restated for 2019 to better align with the Oil Sands operations and Fort Hills cash operating costs methodology. Beginning in 2020, Syncrude cash operating costs are based on production volumes, including internally consumed diesel, while all the prior periods presented here exclude internally consumed diesel.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended															Nine months ended						Twelve months ended
Oil Sands Segment Netbacks^(A)(D)(E)	Sep 30 2020			Jun 30 2020			Mar 31 2020			Dec 31 2019			Sep 30 2019			Sep 30 2020			Sep 30 2019			Dec 31 2019

Bitumen ($/bbl)

Average price realized		29.56			20.69			28.24			44.04			53.38			26.26			55.40			52.05

Royalties		(0.36	)		(0.21	)		(0.44	)		(1.22	)		(1.86	)		(0.34	)		(1.91	)		(1.70	)

Transportation costs		(5.28	)		(6.73	)		(7.22	)		(5.47	)		(6.27	)		(6.43	)		(6.71	)		(6.34	)

Net operating expenses		(17.85	)		(20.97	)		(21.90	)		(15.87	)		(14.73	)		(20.23	)		(15.88	)		(15.88	)

Operating netback		6.07			(7.22	)		(1.32	)		21.48			30.52			(0.74	)		30.90			28.13

SCO and diesel ($/bbl)

Average price realized		50.72			31.39			57.54			76.15			74.67			47.04			75.20			75.43

Royalties		(0.82	)		(0.35	)		(0.35	)		(2.89	)		(4.52	)		(0.49	)		(4.98	)		(4.49	)

Transportation costs		(4.54	)		(4.91	)		(4.35	)		(5.14	)		(5.04	)		(4.59	)		(4.63	)		(4.75	)

Net operating expenses		(31.49	)		(29.58	)		(30.11	)		(31.92	)		(29.78	)		(30.35	)		(30.41	)		(30.76	)

Operating netback		13.87			(3.45	)		22.73			36.20			35.33			11.61			35.18			35.43

Average Oil Sands Segment ($/bbl)

Average price realized		46.04			29.16			51.70			65.63			68.40			42.70			69.99			68.89

Royalties		(0.72	)		(0.32	)		(0.42	)		(2.34	)		(3.74	)		(0.48	)		(4.21	)		(3.74	)

Transportation costs		(4.70	)		(5.29	)		(4.92	)		(5.25	)		(5.40	)		(4.97	)		(5.17	)		(5.19	)

Net operating expenses		(28.47	)		(27.79	)		(28.47	)		(26.66	)		(25.34	)		(28.24	)		(26.59	)		(26.61	)

Operating netback		12.15			(4.24	)		17.89			31.38			33.92			9.01			34.02			33.35

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(D): Netbacks are based on sales volumes. Impact of inventory write-down is excluded until product is sold.
(E): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company's assets. Also, the company leverages the expertise of its marketing and logistics business to optimize midstream capacity to the Gulf Coast and this is reflected in bitumen price realizations. Prior period amounts have been restated to reflect these changes.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended															Nine months ended						Twelve months ended
Exploration and Production	Sep 30 2020			Jun 30 2020			Mar 31 2020			Dec 31 2019			Sep 30 2019			Sep 30 2020			Sep 30 2019			Dec 31 2019

Production Volumes^(F)

Exploration and Production Canada (mbbs/d)		57.1			62.3			62.2			69.6			49.6			60.6			56.6			59.9

Exploration and Production International (mboe/d)		40.1			39.5			47.5			46.3			42.7			42.3			47.0			46.9

Total production volumes (mboe/d)		97.2			101.8			109.7			115.9			92.3			102.9			103.6			106.8

Total Sales Volumes (mboe/d)		96.0			108.7			107.2			113.5			92.5			103.9			103.4			106.0

Netbacks^(A)(D)

East Coast Canada ($/bbl)

Average price realized		58.77			27.55			69.50			86.07			81.25			51.41			86.82			86.62

Royalties		(5.70	)		(0.96	)		(4.06	)		(13.46	)		(6.54	)		(3.50	)		(13.68	)		(13.62	)

Transportation costs		(2.56	)		(4.68	)		(2.13	)		(1.71	)		(1.86	)		(3.16	)		(1.78	)		(1.76	)

Operating costs		(13.23	)		(10.40	)		(13.23	)		(11.28	)		(16.49	)		(12.24	)		(14.29	)		(13.45	)

Operating netback		37.28			11.51			50.08			59.62			56.36			32.51			57.07			57.79

International excluding Libya^(G) ($/boe)

Average price realized		56.56			32.63			66.22			82.92			77.15			51.80			84.52			84.17

Transportation costs		(2.50	)		(1.83	)		(2.50	)		(2.23	)		(1.97	)		(2.27	)		(2.15	)		(2.17	)

Operating costs		(7.29	)		(7.01	)		(6.56	)		(8.57	)		(5.29	)		(6.93	)		(5.82	)		(6.43	)

Operating netback^(A)		46.77			23.79			57.16			72.12			69.89			42.60			76.55			75.57

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(D): Netbacks are based on sales volumes.
(F): Beginning in the second quarter of 2020, the company revised the presentation of its production volumes to aggregate production from each asset into the categories of Exploration and Production Canada and Exploration and Production International to simplify the presentation. Comparative periods have been updated to reflect this change.
(G): Beginning in 2020, operating netback includes Norway and all the prior periods presented here exclude Norway.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Nine months ended				Twelve months ended
Refining and Marketing	Sep 30 2020		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sep 30 2019		Sep 30 2020		Sep 30 2019		Dec 31 2019

Refined product sales (mbbls/d)		534.0		438.8		531.5		534.6		572.0		501.6		541.0		539.4

Crude oil processed (mbbls/d)		399.7		350.4		439.5		447.5		463.7		396.5		436.0		438.9

Utilization of refining capacity (%)		87		76		95		97		100		86		94		95

Refining and marketing margin – first-in, first-out (FIFO) ($/bbl)^(A)(H)		30.75		20.95		23.35		35.70		35.65		25.10		42.05		40.45

Refining and marketing margin – last-in, first-out (LIFO) ($/bbl)^(A)(H)		25.00		28.55		35.60		36.50		36.10		29.95		36.90		36.80

Refining operating expense ($/bbl)^(A)		5.40		5.80		5.65		5.05		4.90		5.60		5.45		5.35

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		120.2		76.0		112.7		121.6		122.9		103.0		119.2		119.8

Distillate		93.4		84.2		94.8		102.8		107.4		90.8		102.9		102.9

Total transportation fuel sales		213.6		160.2		207.5		224.4		230.3		193.8		222.1		222.7

Petrochemicals		8.2		9.4		9.9		7.9		9.4		9.2		11.6		10.6

Asphalt		19.1		13.4		11.0		17.3		21.6		14.6		15.6		16.1

Other		18.7		23.4		27.8		25.3		21.1		23.2		21.0		22.1

Total refined product sales		259.6		206.4		256.2		274.9		282.4		240.8		270.3		271.5

Crude oil supply and refining

Processed at refineries (mbbls/d)		208.7		169.2		213.1		217.3		209.5		197.0		198.6		203.3

Utilization of refining capacity (%)		94		76		96		98		94		89		89		92

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		113.2		99.6		121.6		125.8		133.9		111.5		127.1		126.8

Distillate		127.2		106.1		133.9		110.9		123.4		122.4		116.7		115.2

Total transportation fuel sales		240.4		205.7		255.5		236.7		257.3		233.9		243.8		242.0

Asphalt		17.4		14.4		8.7		11.4		18.1		13.5		12.4		12.1

Other		16.6		12.3		11.1		11.6		14.2		13.4		14.5		13.8

Total refined product sales		274.4		232.4		275.3		259.7		289.6		260.8		270.7		267.9

Crude oil supply and refining

Processed at refineries (mbbls/d)		191.0		181.2		226.4		230.2		254.2		199.5		237.4		235.6

Utilization of refining capacity (%)		80		76		94		96		106		83		99		98

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(H): Refining and marketing margin has been restated for 2019 to better reflect the refining, product supply and rack forward businesses. Impact of inventory write-down is excluded until product is sold.

See accompanying footnotes and definitions to the quarterly operating summaries.


	September 30, 2020						June 30, 2020
For the quarter ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	527		2 040		2 567		340		1 312		1 652

Other income (loss)	23		17		40		(19	)	42		23

Purchases of crude oil and products	(143	)	(28	)	(171	)	(69	)	(22	)	(91	)

Gross realization adjustment⁽²⁾	(83	)	(69	)			(34	)	(65	)

Gross realizations	324		1 960				218		1 267

Royalties	(4	)	(32	)	(36	)	(2	)	(14	)	(16	)

Transportation	(61	)	(175	)	(236	)	(73	)	(199	)	(272	)

Transportation adjustment⁽³⁾	3		—				2		—

Net transportation	(58	)	(175	)			(71	)	(199	)

Operating, selling and general (OS&G)	(190	)	(1 460	)	(1 650	)	(194	)	(1 334	)	(1 528	)

OS&G adjustment⁽⁴⁾	(5	)	243				(28	)	141

Net operating expenses	(195	)	(1 217	)			(222	)	(1 193	)

Gross profit (loss)	67		536				(77	)	(139	)

Sales volumes (mbbls)	10 949		38 646				10 589		40 326

Operating netback per barrel	6.07		13.87				(7.22	)	(3.45	)


	March 31, 2020						December 31, 2019
For the quarter ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	538		2 779		3 317		1 242		3 183		4 425

Other income	26		222		248		7		91		98

Purchases of crude oil and products	(362	)	(45	)	(407	)	(337	)	(109	)	(446	)

Gross realization adjustment⁽²⁾	126		(273	)			(28	)	(29	)

Gross realizations	328		2 683				884		3 136

Royalties	(9	)	(16	)	(25	)	(24	)	(119	)	(143	)

Royalties adjustment⁽⁵⁾	3		—				—		—

Net royalties	(6	)	(16	)			(24	)	(119	)

Transportation	(86	)	(203	)	(289	)	(112	)	(213	)	(325	)

Transportation adjustment⁽³⁾	3		—				2		2

Net transportation	(83	)	(203	)			(110	)	(211	)

OS&G	(384	)	(1 868	)	(2 252	)	(335	)	(1 650	)	(1 985	)

OS&G adjustment⁽⁴⁾	130		465				17		336

Net operating expenses	(254	)	(1 403	)			(318	)	(1 314	)

Gross (loss) profit	(15	)	1 061				432		1 492

Sales volumes (mbbls)	11 605		46 638				20 067		41 174

Operating netback per barrel	(1.32	)	22.73				21.48		36.20

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(D): Impact of inventory write-down is excluded until product is sold.
(E): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company's assets. Also, the company leverages the expertise of its marketing and logistics business to optimize midstream capacity to the Gulf Coast and this is reflected in bitumen price realizations. Prior period amounts have been restated to reflect these changes.

See accompanying footnotes and definitions to the quarterly operating summaries.


	September 30, 2019
For the quarter ended	Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	1 257		3 344		4 601

Other income	—		63		63

Purchases of crude oil and products	(259	)	(25	)	(284	)

Gross realization adjustment⁽²⁾	(7	)	(64	)

Gross realizations	991		3 318

Royalties	(34	)	(201	)	(235	)

Transportation	(118	)	(226	)	(344	)

Transportation adjustment⁽³⁾	2		2

Net transportation	(116	)	(224	)

OS&G	(319	)	(1 690	)	(2 009	)

OS&G adjustment⁽⁴⁾	46		367

Net operating expenses	(273	)	(1 323	)

Gross profit	568		1 570

Sales volumes (mbbls)	18 567		44 433

Operating netback per barrel	30.52		35.33


	September 30, 2020						September 30, 2019
For the nine months ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	1 405		6 131		7 536		3 538		10 384		13 922

Other income (loss)	30		281		311		(45	)	119		74

Purchases of crude oil and products	(574	)	(95	)	(669	)	(827	)	(134	)	(961	)

Gross realization adjustment⁽²⁾	9		(407	)			14		(190	)

Gross realizations	870		5 910				2 680		10 179

Royalties	(15	)	(62	)	(77	)	(100	)	(674	)	(774	)

Royalties adjustment⁽⁵⁾	3		—				8		—

Net royalties	(12	)	(62	)			(92	)	(674	)

Transportation	(220	)	(577	)	(797	)	(337	)	(631	)	(968	)

Transportation adjustment⁽³⁾	8		—				13		5

Net transportation	(212	)	(577	)			(324	)	(626	)

OS&G	(768	)	(4 662	)	(5 430	)	(907	)	(5 135	)	(6 042	)

OS&G adjustment⁽⁴⁾	97		849				140		1 019

Net operating expenses	(671	)	(3 813	)			(767	)	(4 116	)

Gross (loss) profit	(25	)	1 458				1 497		4 763

Sales volumes (mbbls)	33 143		125 610				48 363		135 320

Operating netback per barrel	(0.74	)	11.61				30.90		35.18

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(D): Impact of inventory write-down is excluded until product is sold.
(E): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company's assets. Also, the company leverages the expertise of its marketing and logistics business to optimize midstream capacity to the Gulf Coast and this is reflected in bitumen price realizations. Prior period amounts have been restated to reflect these changes.

See accompanying footnotes and definitions to the quarterly operating summaries.


	December 31, 2019
For the year ended	Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	4 780		13 567		18 347

Other (loss) income	(38	)	210		172

Purchases of crude oil and products	(1 164	)	(243	)	(1 407	)

Gross realization adjustment⁽²⁾	(14	)	(219	)

Gross realizations	3 564		13 315

Royalties	(124	)	(793	)	(917	)

Royalties adjustment⁽⁵⁾	8		—

Net royalties	(116	)	(793	)

Transportation	(449	)	(844	)	(1 293	)

Transportation adjustment⁽³⁾	15		7

Net transportation	(434	)	(837	)

OS&G	(1 242	)	(6 785	)	(8 027	)

OS&G adjustment⁽⁴⁾	157		1 355

Net operating expenses	(1 085	)	(5 430	)

Gross profit	1 929		6 255

Sales volumes (mbbls)	68 430		176 494

Operating netback per barrel	28.13		35.43

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(D): Impact of inventory write-down is excluded until product is sold.
(E): Beginning in the second quarter of 2020, due to increasing integration of the company's assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company's assets. Also, the company leverages the expertise of its marketing and logistics business to optimize midstream capacity to the Gulf Coast and this is reflected in bitumen price realizations. Prior period amounts have been restated to reflect these changes.

See accompanying footnotes and definitions to the quarterly operating summaries.

Exploration and Production Netbacks(A)
($ millions, except per barrel amounts)


	September 30, 2020								June 30, 2020
For the quarter ended	International(G)		East Coast Canada		Other(6)		E&P Segment		International(G)		East Coast Canada		Other(6)		E&P Segment

Operating revenues	201		311		—		512		133		160		—		293

Royalties	—		(30	)	—		(30	)	—		(6	)	—		(6	)

Transportation	(9	)	(15	)	—		(24	)	(7	)	(26	)	—		(33	)

OS&G	(33	)	(77	)	(8	)	(118	)	(34	)	(68	)	(9	)	(111	)

Non-production costs⁽⁷⁾	7		8						5		7

Gross profit	166		197						97		67

Sales volumes (mboe)	3 552		5 281						4 086		5 803

Operating netback per barrel	46.77		37.28						23.79		11.51


	March 31, 2020								December 31, 2019
For the quarter ended	International(G)		East Coast Canada		Other(6)		E&P Segment		International(G)		East Coast Canada		Other(6)		E&P Segment

Operating revenues	282		382		(125	)	539		273		532		193		998

Royalties	—		(22	)	—		(22	)	—		(83	)	(87	)	(170	)

Transportation	(11	)	(12	)	—		(23	)	(7	)	(10	)	(4	)	(21	)

OS&G	(32	)	(85	)	(16	)	(133	)	(32	)	(78	)	(24	)	(134	)

Non-production costs⁽⁷⁾	4		12						4		8

Gross profit	243		275						238		369

Sales volumes (mboe)	4 257		5 501						3 289		6 176

Operating netback per barrel	57.16		50.08						72.12		59.62


	September 30, 2019
For the quarter ended	International(G)		East Coast Canada		Other(6)		E&P Segment

Operating revenues	269		393		84		746

Royalties	—		(32	)	(65	)	(97	)

Transportation	(7	)	(9	)	(3	)	(19	)

OS&G	(22	)	(93	)	(14	)	(129	)

Non-production costs⁽⁷⁾	4		13

Gross profit	244		272

Sales volumes (mboe)	3 488		4 832

Operating netback per barrel	69.89		56.36

(A): (A) Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(G): Beginning in 2020, International operating netback includes Norway and all the prior periods presented here exclude Norway.

See accompanying footnotes and definitions to the quarterly operating summaries.

Exploration and Production Netbacks(A)
($ millions, except per barrel amounts)


	September 30, 2020								September 30, 2019
For the nine months ended	International(G)		East Coast Canada		Other(6)		E&P Segment		International(G)		East Coast Canada		Other(6)		E&P Segment

Operating revenues	616		853		(125	)	1 344		983		1 391		303		2 677

Royalties	—		(58	)	—		(58	)	—		(219	)	(216	)	(435	)

Transportation	(27	)	(53	)	—		(80	)	(25	)	(29	)	(5	)	(59	)

OS&G	(99	)	(230	)	(33	)	(362	)	(80	)	(267	)	(44	)	(391	)

Non-production costs⁽⁷⁾	16		27						13		38

Gross profit	506		539						891		914

Sales volumes (mboe)	11 895		16 585						11 628		16 014

Operating netback per barrel	42.60		32.51						76.55		57.07


	December 31, 2019
For the year ended	International(G)		East Coast Canada		Other(6)		E&P Segment

Operating revenues	1 256		1 923		496		3 675

Royalties	—		(302	)	(303	)	(605	)

Transportation	(32	)	(39	)	(9	)	(80	)

OS&G	(112	)	(346	)	(67	)	(525	)

Non-production costs⁽⁷⁾	17		46

Gross profit	1 129		1 282

Sales volumes (mboe)	14 917		22 190

Operating netback per barrel	75.57		57.79

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(G): Beginning in 2020, International operating netback includes Norway and all the prior periods presented here exclude Norway.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Nine months ended				Twelve months ended
	Sep 30 2020		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sep 30 2019		Sep 30 2020		Sep 30 2019		Dec 31 2019

Gross margin⁽⁸⁾	1 210		1 058		629		1 568		1 653		2 897		5 440		7 008

Other (loss) income	(2	)	(26	)	86		33		13		58		42		75

Non-refining margin⁽⁹⁾	(14	)	(312	)	283		(16	)	(17	)	(43	)	(44	)	(60	)

Refining and marketing margin^(A)	1 194		720		998		1 585		1 649		2 912		5 438		7 023

Refinery production (mbbls)⁽¹⁰⁾	38 857		34 369		42 729		44 422		46 239		115 955		129 283		173 705

Refining and marketing margin – FIFO ($/bbl)^(A)	30.75		20.95		23.35		35.70		35.65		25.10		42.05		40.45

LIFO adjustment	(223	)	261		524		37		19		562		(665	)	(628	)

Refining and marketing margin – LIFO^(A)	971		981		1 522		1 622		1 668		3 474		4 773		6 395

Refining and marketing margin – LIFO ($/bbl)^(A)(I)(J)	25.00		28.55		35.60		36.50		36.10		29.95		36.90		36.80

OS&G	457		417		511		576		531		1 385		1 597		2 173

Non-refining costs⁽¹¹⁾	(247	)	(218	)	(270	)	(352	)	(305	)	(735	)	(894	)	(1 246	)

Refining operating expense	210		199		241		224		226		650		703		927

Refinery production (mbbls)⁽¹⁰⁾	38 857		34 369		42 729		44 422		46 239		115 955		129 283		173 705

Refining operating expense ($/bbl)^(A)	5.40		5.80		5.65		5.05		4.90		5.60		5.45		5.35

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.
(H): Refining and marketing margin has been restated for 2019 to better reflect the refining, product supply and rack forward businesses. Impact of inventory write-down is excluded until product is sold.
(I): Refining and marketing margin – LIFO excludes the impact of short-term risk management activities.
(J): The Suncor 5-2-2-1 index is most comparable to the company's realized refining and marketing margins presented on a LIFO basis.

See accompanying footnotes and definitions to the quarterly operating summaries.


		Three months ended					Nine months ended		Twelve months ended
(average for the three months, nine months and twelve months ended)		Sep 30 2020	Jun 30 2020	Mar 31 2020	Dec 31 2019	Sep 30 2019	Sep 30 2020	Sep 30 2019	Dec 31 2019

WTI crude oil at Cushing (US$/bbl)		40.95	27.85	46.10	56.95	56.45	38.30	57.05	57.05

SYN crude oil at Edmonton (US$/bbl)		38.50	23.30	43.40	56.25	56.85	35.10	56.50	56.45

WCS at Hardisty (US$/bbl)		31.90	16.35	25.60	41.10	44.20	24.65	45.30	44.25

New York Harbor 2-1-1 crack (US$/bbl)^(K)		10.20	12.20	14.75	18.45	19.70	12.40	20.40	19.90

Chicago 2-1-1 crack (US$/bbl)^(K)		7.75	6.75	9.75	14.35	17.05	8.10	18.00	17.05

Product value (US$/bbl)

New York Harbor 2-1-1 crack^(L)	40%	20.45	16.00	24.35	30.15	30.45	20.30	31.00	30.80

Chicago 2-1-1 crack^(M)	40%	19.50	13.85	22.35	28.50	29.40	18.55	30.00	29.65

WTI	20%	8.20	5.55	9.20	11.40	11.30	7.65	11.40	11.40

Seasonality factor		5.00	5.00	6.50	6.50	5.00	5.50	5.50	5.75

		53.15	40.40	62.40	76.55	76.15	52.00	77.90	77.60

Crude value (US$/bbl)

SYN	40%	15.40	9.30	17.35	22.50	22.75	14.05	22.60	22.60

WCS	40%	12.75	6.55	10.25	16.45	17.70	9.85	18.10	17.70

WTI	20%	8.20	5.55	9.20	11.40	11.30	7.65	11.40	11.40

		36.35	21.40	36.80	50.35	51.75	31.55	52.10	51.70

Suncor custom 5-2-2-1 index (US$/bbl)		16.80	19.00	25.60	26.20	24.40	20.45	25.80	25.90

Suncor custom 5-2-2-1 index (Cdn$/bbl)^(J)		22.35	26.35	34.40	34.60	32.25	27.70	34.30	34.35

(J): The Suncor 5-2-2-1 index is most comparable to the company's realized refining and marketing margins presented on a LIFO basis.
(K): 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.
(L): 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.
(M): 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.

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 margin, refining 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 margin, and refining 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 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 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.

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.


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
SCO		– synthetic crude oil
WTI		– West Texas intermediate
SYN		– sweet synthetic crude oil
WCS		– Western Canadian Select


	Three months ended September 30		Nine months ended September 30
Net of transportation costs, but before royalties	2020	2019	2020	2019

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	56.21	79.39	48.25	85.04

E&P International ($/boe)	54.06	75.10	49.53	82.17


(thousands)		September 30, 2020

Common shares		1 525 151

Common share options – exercisable		27 194

Common share options – non-exercisable		11 566


($ millions)	September 30 2020	December 31 2019

Crude Oil⁽¹⁾	1 422	1 689

Refined products	1 043	1 290

Materials, supplies and merchandise	860	782

	3 325	3 761


1.	Advisories	8
2.	Third Quarter Highlights	10
3.	Consolidated Financial Information	11
4.	Segment Results and Analysis	16
5.	Capital Investment Update	28
6.	Financial Condition and Liquidity	30
7.	Quarterly Financial Data	34
8.	Other Items	36
9.	Non-GAAP Financial Measures Advisory	38
10.	Common Abbreviations	43
11.	Forward-Looking Information	44


	Three months ended Sep 30				Nine months ended Sep 30
($ millions)	2020		2019		2020		2019

Funds from operations	1 166		2 675		2 655		8 265

Asset sustaining and maintenance capital and dividends⁽¹⁾	(987	)	(1 632	)	(3 193	)	(4 215	)

Discretionary free funds flow (deficit)	179		1 043		(538	)	4 050


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
		Q3	Three months ended September 30
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 per day	YTD	Year to date
MW	megawatts
MWh	megawatts per hour


($ millions)	Total

Fair value outstanding at December 31, 2019	(39	)

Cash Settlements – received during the year	(286	)

Changes in fair value recognized in earnings during the year	273

Fair value outstanding at September 30, 2020	(52	)


($ millions)	Level 1		Level 2		Level 3	Total Fair Value

Accounts receivable	56		56		—	112

Accounts payable	(128	)	(36	)	—	(164	)

	(72	)	20		—	(52	)


	For the twelve months ended
	Sep 30 2020			Jun 30 2020			Mar 31 2020			Dec 31 2019		Sep 30 2019

Return on capital employed^(A)

– excluding major projects in progress (%)		(10.8	)		(7.9	)		(1.4	)		5.1		9.9

– including major projects in progress (%)		(10.2	)		(7.5	)		(1.3	)		4.9		9.7