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 Libya, 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 July 22, 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 experienced unprecedented volatility this quarter in all facets of our business as the COVID-19 pandemic and OPEC+ supply issues continued to impact the industry," said Mark Little, president and chief executive officer. "The company took decisive action to respond to both these issues, enabling us to manage through this period of volatility and maintain financial resilience for the future. As we move forward, we will remain agile in the execution of our strategy as we continue to focus on the long-term financial health of the company and our plans to generate increasing shareholder returns."

Suncor's second quarter 2020 operating loss was $1.489 billion ($0.98 per common share), compared to operating earnings of $1.253 billion ($0.80 per common share) in the prior year quarter. In the second quarter of 2020, crude oil and refined product realizations decreased significantly, with crude oil and crack spread benchmarks declining by more than 50% compared to the prior year quarter due to the impacts of the COVID-19 pandemic and OPEC+ supply issues. The decline in consumer demand for refined products resulted in lower crude oil demand and lower overall upstream production volumes and refinery crude throughput as the company managed its operations to meet demand levels. Operating losses were minimized by the decrease in costs associated with lower production as well as cost reduction initiatives executed in the second quarter of 2020. The second quarter of 2020 was also impacted by the realization of $397 million in after-tax hydrocarbon inventory losses, recognized in net earnings in the first quarter of 2020, and a FIFO inventory valuation loss of $146 million after-tax on the decline in value of refinery feedstock.

Suncor's net loss was $614 million ($0.40 per common share) in the second quarter of 2020, compared to net earnings of $2.729 billion ($1.74 per common share) in the prior year quarter. In addition to the factors impacting operating (loss) earnings discussed above, the net loss for the second quarter of 2020 included a $478 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt but excluded the $397 million after-tax hydrocarbon inventory loss that was recognized in net earnings in the first quarter of 2020.

Net earnings in the prior year quarter included a one-time deferred income tax recovery of $1.116 billion associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022, an after-tax gain of $139 million on the sale of the company's interest in Canbriam Energy Inc. (Canbriam) and a $221 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt.

Funds from Operations and Cash Flow (Used In) Provided By Operating Activities

Funds from operations were $488 million ($0.32 per common share) in the second quarter of 2020, compared to $3.005 billion ($1.92 per common share) in the second quarter of 2019, and were influenced by the same factors impacting operating (loss) earnings noted above.

Cash flow used in operating activities, which includes changes in non-cash working capital, was $768 million ($0.50 per common share) for the second quarter of 2020, compared to cash flow provided by operating activities of $3.433 billion ($2.19 per common share) for the second quarter of 2019. In addition to the items impacting operating (loss) earnings noted above, cash flow used in operating activities was further impacted by a use of cash from working capital in the current quarter as compared to a source of cash in the prior year quarter. The use of cash was primarily due to a decrease in accounts payable balances associated with lower operating costs and an increase in income taxes receivable balances due to tax losses incurred.

The collapse of the OPEC+ supply agreement and the impacts of the COVID-19 pandemic continued to present challenges to our operations and business environment in the second quarter of 2020. The continued volatility in the business environment highlights the importance of the company's integrated operations and value over volume approach across the company's assets. This approach leverages the flexibility of the company's integrated assets to respond to the changing market conditions and needs of our customers in order to maximize the value of Suncor's production.

"We continue to focus on maximizing the value from our assets, leveraging our midstream expertise and logistics network and flexing our upstream and downstream assets to manage our operations and optimize our product mix in response to shifting demand," said Little. "We are on track to achieve our previously announced cost reduction targets that yielded significantly lower capital and operating costs in the second quarter."

In the upstream, Suncor maximized price realizations with approximately 80% of production weighted to light oil in the second quarter of 2020, although it varied through the quarter as the business environment evolved. In the downstream, approximately 45% of the refinery feedstock was physically integrated with our upstream production as we continued to take advantage of the operational flexibility at our refineries as demand shifted throughout the quarter.

Suncor's total upstream production was 655,500 boe/d during the second quarter of 2020, compared to 803,900 boe/d in the prior year quarter, due to the significant decline in crude oil demand. With lower demand, the company continued to maximize upgrading to produce higher value synthetic crude oil (SCO) barrels, which maximized the company's per barrel margin and cash flow, despite leading to lower overall production and higher unit costs. In the second quarter of 2020, the company achieved total SCO production of 436,600 barrels per day (bbls/d) compared to 484,200 bbls/d in the second quarter of 2019, on combined upgrader utilization rates of 81% and 88%, respectively, reflecting lower volumes at Syncrude as planned maintenance activities were optimized resulting in reduced production in response to a weaker business environment, partially offset by improved upgrader reliability at Oil Sands operations.

Non-upgraded bitumen production decreased to 117,100 bbls/d in the second quarter of 2020 from 208,000 bbls/d in the second quarter of 2019, as the company reduced production in response to a weaker business environment, including temporarily transitioning to a one-train operation at Fort Hills, Firebag bitumen being diverted to the upgrader to maximize value over volume and the ramp up at MacKay River, which returned to operations late in the second quarter of 2020.

Exploration and Production (E&P) production during the second quarter of 2020 decreased to 101,800 boe/d from 111,700 boe/d in the prior year quarter, primarily due to lower volumes at Terra Nova, reflecting the regulatory order to shut in production in the fourth quarter of 2019, and unplanned maintenance and natural declines in the United Kingdom. This decrease was partially offset by higher production at Hebron, as seven new production wells have come online since the second quarter of 2019, and at Oda, which ramped up production after achieving first oil in the first quarter of 2019.

Refinery crude throughput was 350,400 bbls/d and refinery utilization was 76% in the second quarter of 2020, despite the impacts of the COVID-19 pandemic, compared to crude throughput of 399,100 bbls/d and refinery utilization of 86% in the prior year quarter. Refined product sales were strong relative to the significant decline in industry demand at 438,800 bbls/d, compared to 508,100 bbls/d in the prior year quarter, primarily due to the company's secure sales channels. During the second quarter of 2020, the company responded to shifting demand with agility by leveraging its midstream logistics and storage capacity and diversified sales channels, exiting the quarter with a refinery utilization rate of greater than 85%.

The company's total operating, selling and general expenses decreased to $2.156 billion in the second quarter of 2020 from $2.799 billion in the prior year quarter, primarily due to lower overall upstream and downstream sales volumes, cost reduction initiatives executed in the second quarter of 2020, reduced maintenance activities and the benefit of the

Government of Canada's Emergency Wage Subsidy. Both periods also 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. At Fort Hills, we have temporarily transitioned to a one-train operation as a result of the decline in the business environment. This move increased free funds flow during the quarter, compared to running at full rates, as we were able to significantly reduce costs.

Due to potential health and safety concerns as a result of COVID-19, Suncor's planned maintenance schedules continue to be optimized. During the second quarter of 2020, planned maintenance activities at Syncrude were revised to focus on strategic maintenance, changing the scope of the work to reduce costs and comply with COVID-19 safety measures, and, at Oil Sands Base, certain maintenance activities were extended due to COVID-19 safety protocols. In the second quarter of 2020, the decision was made to disconnect the Terra Nova floating, production, storage and offloading (FPSO) vessel and dock shoreside in Newfoundland. Suncor is currently evaluating alternate options for a return to operations and the Terra Nova Asset Life Extension project.

At the onset of the COVID-19 pandemic in the first quarter of 2020 and with the collapse of the OPEC+ supply agreement, the company took decisive action in response to the changing business environment. We are focused on maximizing our upstream production integration with our upgraders and refineries, shifting our refined product mix to meet demand, and leveraging our midstream trading and marketing expertise and logistics. As a result, the company is positioned to respond quickly to changing market conditions, including keeping its refinery assets ready and available and ensuring a secure outlet for its product.

Looking ahead, the company will continue to take a proactive approach and be agile with our response through this period of continued volatility. As economies begin to reopen and shelter-in-place orders are lifted across most jurisdictions, the company will continue to take measured steps to respond to the COVID-19 pandemic and remains committed to the health and safety of all personnel and customers, and to the safety and continuation of our operations.

"Suncor's business model is built on capturing the full value of our produced barrels through our physical integration. This model, paired with disciplined adherence to financial management and capital allocation, has consistently delivered value to shareholders," said Little. "As we move forward, we will continue to execute on our operating and capital cost reduction targets and take the measured actions required to ensure the long-term financial health of our business."

Our team has made significant progress in reducing capital and operating costs across the company, moving expeditiously to execute the business decisions we announced in the first quarter of 2020 and remain on track to achieve our $1 billion operating cost reduction target by the end of 2020 through base business reductions and reductions in variable costs tied to the Fort Hills operations.

The company continued to exercise financial discipline, reducing capital expenditures significantly in the second quarter of 2020 and remains on track to achieve our targeted $1.9 billion reduction by shifting the focus to sustaining projects designed to maintain safe and reliable operations. The company also continued to advance select projects and investments intended to incrementally and sustainably grow annual free funds flow. This includes strategically investing in projects that are expected to provide immediate returns and result in structural changes to operating costs, while moving the company forward in the areas of safety, reliability and sustainability.

The company continued to accelerate the transition to its AHS at Fort Hills in the second quarter of 2020, which is expected to result in enhanced safety, environmental and operating performance and lower operating costs. By the fourth quarter of 2020, the company anticipates that the AHS truck fleet at Fort Hills will be fully operational, which is expected to also drive further cost reductions. Construction on the interconnecting pipelines between Suncor's Oil Sands Base and Syncrude continued in anticipation of an in-service date in the fourth quarter of 2020. The bi-directional pipelines are expected to enhance integration between these assets and increase reliability and utilization rates, as well as product flexibility. In addition, the company has accelerated its tailings technology deployment timeline, which is expected to result in operating cost reductions and reclamation savings.

Despite these volatile market conditions, the company remains committed to creating long-term value for our shareholders, which includes leveraging and generating returns from existing assets and accelerating our digital transformation. Half of our $2 billion free funds flow target remains on track for delivery by 2023 through the deployment of AHS trucks at Fort Hills, the Syncrude interconnecting pipelines, tailings technology advancements and investments in technology for our marketing and trading business and core business systems. Full achievement of the $2 billion free funds flow target is anticipated to be realized in 2025.

During the second quarter of 2020, Suncor made an equity investment in LanzaJet Inc., a company that is working to bring sustainable aviation fuel and renewable diesel to the commercial market. This strategic investment, together with the equity investment in Enerkem Inc., a waste-to-biofuels and chemicals producer, in 2019, complement Suncor's existing product mix, supports our greenhouse gas emissions intensity reduction efforts and demonstrates Suncor's active involvement in the evolving energy transition. We plan to continue to reduce emissions intensity through projects such as the Forty Mile Wind Power Project and our decision to replace the coke-fired boilers at Oil Sands Base with cogeneration units to provide the steam we need for our operations and lower carbon power supply to the Alberta grid, replacing coal-fired power. Through continued innovation, sustainable investments and collaborative solutions, we are committed to reducing our environmental footprint.

In the second quarter of 2020, the company took significant steps to bolster its liquidity by issuing $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 secured an additional $300 million of credit facilities and, as at June 30, 2020, had $8.65 billion of liquidity. We expect that this increased financial flexibility will help ensure the company has access to adequate financial resources should it be required. As commodity prices improve, the company plans to reduce debt in conjunction with a measured pace of increasing shareholder returns and economic investments. During the second quarter of 2020, the company distributed $320 million in dividends.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings	(614	)	2 729		(4 139	)	4 199

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(478	)	(221	)	543		(482	)

Asset impairment⁽²⁾	—		—		1 798		—

Impact of inventory write-down to net realizable value recorded in the first quarter⁽³⁾	(397	)	—		—		—

Impact of income tax rate adjustment on deferred taxes⁽⁴⁾	—		(1 116	)	—		(1 116	)

Gain on significant disposal⁽⁵⁾	—		(139	)	—		(139	)

Operating (loss) earnings⁽¹⁾	(1 489	)	1 253		(1 798	)	2 462

(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 on this item.
(3): During the first quarter of 2020, the company recorded an after-tax hydrocarbon inventory write-down to net realizable value of $177 million in the Oil Sands segment and $220 million in the Refining and Marketing segment as a result of a significant decline in benchmarks and demand for crude oil and refined products due to COVID-19 mitigation efforts. The full hydrocarbon inventory write-down amount of $397 million after-tax was excluded from operating earnings and funds from operations in the first quarter of 2020, and realized through operating earnings and funds from operations in the second quarter of 2020 when the product was sold.
(4): 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% over the next four years.
(5): 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.

The COVID-19 pandemic is an evolving situation which continues to have widespread implications for our business environment, operations and financial condition. The pace of an economic recovery is challenging to determine with the overall outlook for crude oil demand dependent on how successful nations are at combating the pandemic and changes to current social restrictions. We have maintained our previous guidance assumptions for sales volumes, production volumes and operating costs which reflect the strengthening of consumer demand, managed upstream production and our target to reduce capital and operating costs by $1.9 billion and $1.0 billion, respectively.

Suncor has updated its Corporate Guidance for the full year business environment outlook assumptions previously updated May 5, 2020 for Brent Sullom Voe from US$34.00/bbl to US$42.00/bbl, WTI at Cushing from US$30.00/bbl to US$39.00/bbl, WCS at Hardisty from US$16.00/bbl to US$25.00/bbl, AECO-C Spot from $2.25/GJ to $2.00/GJ and the Cdn$/US$ exchange rate from 0.72 to 0.74, due to improvements 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 decreased from $900 million – $1.2 billion to $500 million – $800 million.

The company's guidance is reliant on our current outlook for the demand for our products; however, there are a number of external factors beyond our control that could significantly influence this outlook, including the status of the COVID-19 pandemic and potential future waves, and any associated policies around current business restrictions, shelter-in-place orders, or gatherings of individuals. As a result of the volatile business environment and the uncertain pace of an economic recovery it is challenging to determine the overall outlook for crude oil and refined product demand, which remains dependent on the status of the COVID-19 pandemic.

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 six months ended June 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 that 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 that 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 Libya, 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 earnings (loss) 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 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 global outbreak of the COVID-19 pandemic and the ongoing uncertainty as to the extent and duration of the pandemic. This 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 continue to be volatile. 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 June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings

Oil Sands	(1 019	)	1 561		(2 972	)	1 750

Exploration and Production	(51	)	456		(478	)	948

Refining and Marketing	269		765		214		1 774

Corporate and Eliminations	187		(53	)	(903	)	(273	)

Total	(614	)	2 729		(4 139	)	4 199

Operating (loss) earnings⁽¹⁾

Oil Sands	(1 196	)	651		(1 596	)	840

Exploration and Production	(51	)	247		(56	)	739

Refining and Marketing	49		677		214		1 686

Corporate and Eliminations	(291	)	(322	)	(360	)	(803	)

Total	(1 489	)	1 253		(1 798	)	2 462

Funds from (used in) operations⁽¹⁾

Oil Sands	10		1 866		701		3 050

Exploration and Production	309		507		482		1 209

Refining and Marketing	475		932		699		2 185

Corporate and Eliminations	(306	)	(300	)	(393	)	(854	)

Total	488		3 005		1 489		5 590

(Increase) decrease in non-cash working capital	(1 256	)	428		(873	)	(609	)

Cash flow (used in) provided by operating activities	(768	)	3 433		616		4 981

Capital and exploration expenditures⁽²⁾

Asset sustainment and maintenance	410		816		1 149		1 235

Economic investment	261		520		804		976

Total	671		1 336		1 953		2 211

Suncor's consolidated net loss for the second quarter of 2020 was $614 million, compared to net earnings of $2.729 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, but excludes the $397 million after-tax hydrocarbon inventory losses that were recognized in net earnings in the first quarter of 2020.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Net (loss) earnings	(614	)	2 729		(4 139	)	4 199

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(478	)	(221	)	543		(482	)

Asset impairment⁽²⁾	—		—		1 798		—

Impact of inventory write-down to net realizable value recorded in the first quarter⁽³⁾	(397	)	—		—		—

Impact of income tax rate adjustment on deferred taxes⁽⁴⁾	—		(1 116	)	—		(1 116	)

Gain on significant disposal⁽⁵⁾	—		(139	)	—		(139	)

Operating (loss) earnings⁽¹⁾	(1 489	)	1 253		(1 798	)	2 462

(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 Exploration and Production (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 on this item.
(3): During the first quarter of 2020, the company recorded an after-tax hydrocarbon inventory write-down to net realizable value of $177 million in the Oil Sands segment and $220 million in the R&M segment as a result of a significant decline in benchmarks and demand for crude oil and refined products due to COVID-19 mitigation efforts. The full hydrocarbon inventory write-down amount of $397 million after-tax was excluded from operating earnings and funds from operations in the first quarter of 2020, and realized through operating earnings and funds from operations in the second quarter of 2020 when the product was sold.
(4): 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% over the next four years.
(5): 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.

The after-tax share-based compensation expense increased to $30 million during the second quarter of 2020, compared to an expense of $20 million during the prior year quarter, as a result of an increase in the company's share price through the period, compared to a decrease 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
June 30

Average for the six months ended
June 30

2020

2019

2020

2019

WTI crude oil at Cushing

US$/bbl

27.85

59.85

36.95

57.40

Dated Brent crude

US$/bbl

29.20

68.85

39.65

66.05

Dated Brent/Maya crude oil FOB price differential

US$/bbl

2.70

6.90

9.30

5.95

MSW at Edmonton

Cdn$/bbl

30.20

73.40

41.10

69.95

WCS at Hardisty

US$/bbl

16.35

49.20

20.95

45.90

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

US$/bbl

(11.50

)

(10.65

)

(16.00

)

(11.50

)

SYN-WTI differential

US$/bbl

(4.55

)

0.15

(3.60

)

(1.05

)

Condensate at Edmonton

US$/bbl

22.20

55.90

34.20

53.25

Natural gas (Alberta spot) at AECO

Cdn$/mcf

2.00

1.05

2.00

1.70

Alberta Power Pool Price

Cdn$/MWh

29.90

56.35

48.45

63.55

New York Harbor 2-1-1 crack⁽¹⁾

US$/bbl

12.20

22.40

13.45

20.20

Chicago 2-1-1 crack⁽¹⁾

US$/bbl

6.75

21.55

8.25

18.45

Portland 2-1-1 crack⁽¹⁾

US$/bbl

12.20

29.15

15.25

23.10

Gulf Coast 2-1-1 crack⁽¹⁾

US$/bbl

9.00

21.70

11.00

19.80

Exchange rate

US$/Cdn$

0.72

0.75

0.73

0.75

Exchange rate (end of period)

US$/Cdn$

0.73

0.76

0.73

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 and, combined with elevated global inventory levels, resulted in a decrease in crude oil and crack spread benchmarks of more than 50% 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, which influences SCO differentials. Price realizations in the second quarter of 2020 for sweet SCO were unfavourably impacted by a decrease in WTI at Cushing to US$27.85/bbl, compared to US$59.85/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 $30.20/bbl in the second quarter of 2020 compared to $73.40/bbl in the prior year quarter, and prices for WCS at Hardisty decreased to an average of US$16.35/bbl in the second quarter of 2020, from US$49.20/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 were unfavourably impacted by the widening of heavy crude oil differentials in the second 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$29.20/bbl in the second quarter of 2020, compared to US$68.85/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 designed an indicative 5-2-2-1 index based on publicly available pricing data to more accurately reflect Suncor's actual realized refining and marketing margins. The internal index is a single value that approximates the gross margin on five barrels of crude oil of varying grades that is refined to produce two barrels of both gasoline and distillate and one barrel of secondary product to reflect Suncor's unique set of refinery configurations and overall crude slate and product mix, as well as 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 first-in, first out (FIFO) accounting. The product value is influenced by New York Harbor 2-1-1 crack, Chicago 2-1-1 crack, WTI benchmarks and seasonal factors. The seasonal factor is an estimate of 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 is influenced by 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 second 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 in the second quarter of 2020. The Suncor 5-2-2-1 index was US$19.00/bbl in the second quarter of 2020, compared to US$26.75/bbl in the second quarter of 2019, as widening crude differentials were more than offset by lower benchmark cracking margins.

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 $2.00/mcf in the second quarter of 2020, from $1.05/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 $29.90/MWh in the second quarter of 2020, compared to $56.35/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 second quarter of 2020, as the average exchange rate decreased to US$0.72 per one Canadian dollar from US$0.75 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the second 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 June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Gross revenues	1 652		5 140		4 969		9 321

Less: Royalties	(16	)	(341	)	(41	)	(539	)

Operating revenues, net of royalties	1 636		4 799		4 928		8 782

Net (loss) earnings	(1 019	)	1 561		(2 972	)	1 750

Adjusted for:

Impairment⁽¹⁾	—		—		1 376		—

Impact of inventory write-down to net realizable value recorded in the first quarter⁽²⁾	(177	)	—		—		—

Impact of income tax rate adjustment on deferred taxes⁽³⁾	—		(910	)	—		(910	)

Operating (loss) earnings⁽⁴⁾	(1 196	)	651		(1 596	)	840

Funds from operations⁽⁴⁾	10		1 866		701		3 050

(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): During the first quarter of 2020, Oil Sands recorded an after-tax hydrocarbon inventory write-down to net realizable value of $177 million as a result of a significant decline in benchmarks and demand for crude oil and refined products due to COVID-19 mitigation efforts. The hydrocarbon inventory write-down of $177 million after-tax was excluded from operating earnings and funds from operations in the first quarter of 2020, and realized through operating earnings and funds from operations in the second quarter of 2020 when the product was sold.
(3): 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% over the next four years.
(4): 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 $1.196 billion in the second quarter of 2020, compared to operating earnings of $651 million in the prior year quarter. The decrease was primarily due to lower realized crude prices associated with declining crude oil demand as a result of the COVID-19 pandemic and global inventory oversupply, as crude oil benchmarks decreased by more than 60% compared to the prior year quarter. Operating earnings were also unfavourably impacted by lower production volumes as the company managed production to keep pace with downstream demand, including temporarily transitioning to a one train operation at Fort Hills, and as the company optimized Oil Sands maintenance activities in response to a weaker business environment. These factors were partially offset by the decrease in costs associated with lower production as well as cost reduction initiatives executed in the second quarter of 2020. The second quarter of 2020 was also impacted by the realization of $177 million in after-tax hydrocarbon inventory losses, recognized in net earnings in the first quarter of 2020.


	Three months ended June 30				Six months ended June 30
(mbbls/d)	2020		2019		2020		2019

SCO and diesel production	446.3		495.4		481.3		515.2

Internally consumed diesel	(9.7	)	(11.2	)	(11.2	)	(11.5	)

Upgraded production	436.6		484.2		470.1		503.7

Non-upgraded bitumen production	117.1		208.0		121.8		171.1

Total Oil Sands production	553.7		692.2		591.9		674.8

(1): Bitumen production from Oil Sands Base is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries, with SCO and diesel yields of approximately 79% of bitumen feedstock input. Fort Hills finished bitumen is sold directly to customers, including Suncor's own refineries. Essentially all of the bitumen produced at Syncrude is upgraded to sweet SCO and a small amount of diesel, at an approximate yield of 85%.
(2): 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.

The company continued to maximize upgrading to produce higher value SCO barrels, which maximized the company's per barrel margin and cash flow, despite leading to lower overall production and higher unit costs.

In the second quarter of 2020, the company achieved total SCO production of 436,600 barrels per day (bbls/d) compared to 484,200 bbls/d in the second quarter of 2019, on combined upgrader utilization rates of 81% and 88%, respectively, reflecting lower volumes at Syncrude as planned maintenance activities were optimized resulting in reduced production in response to a weaker business environment, partially offset by improved upgrader reliability at Oil Sands operations.

SCO and diesel sales volumes decreased to 443,100 bbls/d, in the second quarter of 2020, from 497,200 bbls/d in the prior year quarter, consistent with the decrease in production and a larger draw in inventory in the prior year quarter.

Non-upgraded bitumen sales volumes were 116,400 bbls/d in the second quarter of 2020, compared to 197,100 bbls/d in the prior year quarter, and were influenced by the same factors influencing production, partially offset by a larger build in inventory in the prior year quarter.


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

SCO and diesel	26.48		76.14		40.80		71.04

Non-upgraded bitumen⁽²⁾	13.96		50.90		17.65		49.66

Crude sales basket (all products)	23.87		68.98		36.10		65.77

Crude sales basket, relative to WTI	(14.72	)	(10.82	)	(14.32	)	(10.76	)

(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. Prior period amounts have been restated to reflect this change.

In the second quarter of 2020, Oil Sands price realizations were impacted by a significant decline in demand due to the impacts of the COVID-19 pandemic and OPEC+ supply issues at the beginning of the quarter. Price realizations increased near the end of the quarter as global crude oil benchmarks improved with OPEC+'s plans to reduce global oil supply and Canadian crude oil differentials narrowed. The decline in price realizations was partially mitigated by Suncor's marketing expertise and logistics network, where the company was able to capture additional value by placing product in the most advantageous market.

Royalties for the Oil Sands segment were lower in the second 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 second 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 second 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 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 reductions and lower unplanned maintenance, partially offset by costs related to a product mix more weighted towards higher value but higher cost SCO sales and an increase in natural gas prices.

At Fort Hills, operating costs in the second quarter of 2020 decreased when compared to the prior year quarter, primarily due to cost savings associated with the temporary transition to a one-train operation as a result of the decline in the business environment in the second quarter of 2020.

Suncor's share of Syncrude operating costs decreased compared to the prior year quarter, as planned maintenance activities were optimized resulting in reduced production in response to a weaker business environment. Planned maintenance activities at Syncrude were revised to focus on strategic maintenance, changing the scope of the work to reduce costs and comply with COVID-19 safety measures.

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


	Three months ended June 30				Six months ended June 30
($ millions, except as noted)	2020		2019		2020		2019

Oil Sands operating, selling and general expense (OS&G)	1 528		2 060		3 780		4 033

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	975		1 219		2 278		2 340

Non-production costs⁽²⁾	(13	)	(38	)	(95	)	(95	)

Excess power capacity and other⁽³⁾	(48	)	(42	)	(139	)	(117	)

Inventory changes	17		(88	)	(74	)	(3	)

Oil Sands operations cash operating costs⁽¹⁾	931		1 051		1 970		2 125

Oil Sands operations production volumes (mbbls/d)⁽⁴⁾⁽⁵⁾	396.3		416.0		392.1		407.1

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	25.80		27.80		27.60		28.85

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	148		216		468		449

Non-production costs⁽²⁾	(9	)	(25	)	(37	)	(72	)

Inventory changes	12		(8	)	(52	)	15

Fort Hills cash operating costs⁽¹⁾	151		183		379		392

Fort Hills production volumes (mbbls/d)	47.3		89.3		64.0		83.9

Fort Hills cash operating costs ($/bbl)⁽¹⁾	35.35		22.50		32.60		25.80

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	405		625		1 034		1 244

Non-production costs⁽²⁾	11		(43	)	(36	)	(83	)

Syncrude cash operating costs⁽¹⁾⁽⁶⁾	416		582		998		1 161

Syncrude production volumes (mbbls/d)⁽⁴⁾⁽⁵⁾	119.5		188.7		146.9		185.5

Syncrude cash operating costs ($/bbl)⁽¹⁾	38.35		33.90		37.30		34.60

(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 quarter 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 uses internally produced diesel from Oil Sands Base within its mining operations. In the second quarter of 2020, Oil Sands operations production volumes included 7,400 bbls/d of internally consumed diesel, of which 6,400 bbls/d was consumed at Oil Sands Base and 1,000 bbls/d was consumed at Fort Hills. Syncrude production volumes included 2,300 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 and consumed at Fort Hills and Oil Sands Base, while all the prior periods presented exclude internally consumed diesel at Oil Sands Base from production volumes. Prior periods were not restated due to the immaterial impact. 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.
(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 decreased to $25.80 in the second quarter of 2020, compared to $27.80 in the prior year quarter, primarily due to cost reductions and lower unplanned maintenance activities, partially offset by higher natural gas costs. 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. In the second 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. Oil Sands operations inventory changes reflects changes to inventory valuation that are excluded from cash cost per barrel and a draw of crude inventory volumes in the prior year quarter.

Fort Hills cash operating costs⁽¹⁾ per barrel were $35.35 in the second quarter of 2020, compared to $22.50 in the prior year quarter, reflecting lower production due to the decision to temporarily transition Fort Hills to a one-train operation as a result of the decline in the business environment in the second quarter of 2020, partially offset by a significant reduction in costs. Non-production costs were lower primarily due to the CEWS, partially offset by additional costs incurred in response to the COVID-19 pandemic. In the second quarter of 2020, inventory changes at Fort Hills reflected changes to inventory valuation that are excluded from cash operating costs per barrel.

Syncrude cash operating costs⁽¹⁾ per barrel were $38.35 in the second quarter of 2020, compared to $33.90 in the prior year quarter, with the increase due primarily to the decrease in production volumes, partially offset by a reduction in costs.

Oil Sands net loss was $2.972 billion for the first six months of 2020, compared to net earnings of $1.750 billion in the prior year period. In addition to the factors explained in operating (loss) earnings below, the net loss for the first six 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 of 1% each year from 2019 to 2022.

Oil Sands operating loss for the first six months of 2020 was $1.596 billion, compared to operating earnings of $840 million for the same period in 2019. Oil Sands operating loss for the first six months of 2020 was primarily as a result of significantly lower crude price realizations and lower production volumes, partially offset by a decrease in royalties and operating, selling and general expense, as detailed below. The decrease in realized crude prices and production volumes was driven by declining crude oil demand due to the COVID-19 pandemic and OPEC+ supply issues.

Funds from operations for the first six months of 2020 were $701 million for the Oil Sands segment, compared to $3.050 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 $27.60 for the first six months of 2020, a decrease from an average of $28.85 for the first six months of 2019 due to a decrease in operating, selling and general expense related to lower maintenance activities and other cost savings initiatives, partially offset by higher natural gas costs. 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 $32.60 for the first six months of 2020, compared to $25.80 for the same period of 2019, with the current period reflecting lower production due to the temporary transition to a one-train operation as a result of the decline in the business environment in the second quarter of 2020, partially offset by a significant reduction in costs. The prior year period reflected fully ramped up operations, although production was limited by mandatory production curtailments.

Syncrude cash operating costs per barrel averaged $37.30 for the first six months of 2020, an increase compared to $34.60 in the first six months of 2019, primarily due to the decrease in production volumes, partially offset by a reduction in costs.

The company began maintenance activities at Oil Sands operations Upgraders 1 and 2 and at Syncrude during the second quarter of 2020, which will continue in the third quarter of 2020, with maintenance activity at Oil Sands operations Upgrader 1 extending into the fourth quarter of 2020. The anticipated impact of these maintenance events have been reflected in the company's 2020 guidance. As a result of the COVID-19 pandemic, the company continues to assess planned maintenance schedules.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Gross revenues⁽¹⁾	293		904		832		1 780

Less: Royalties⁽¹⁾	(6	)	(75	)	(28	)	(187	)

Operating revenues, net of royalties	287		829		804		1 593

Net (loss) earnings	(51	)	456		(478	)	948

Adjusted for:

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

Asset impairment⁽³⁾	—		—		422		—

Gain on asset disposal⁽⁴⁾	—		(139	)	—		(139	)

Operating (loss) earnings⁽⁵⁾	(51	)	247		(56	)	739

Funds from operations⁽⁵⁾	309		507		482		1 209

(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 $90 million in the second quarter of 2019, which is required for presentation purposes in the company's financial statements under the working-interest basis. In the second 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% over the next four years.
(3): During the first quarter of 2020, the company recorded 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): 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 loss for the E&P segment in the second quarter of 2020 was $51 million, compared to operating earnings of $247 million in the prior year quarter, with the decline primarily due to significantly lower realized crude prices due to the COVID-19 pandemic and high global inventory levels, which resulted in crude oil benchmarks decreasing by more than 50%, partially offset by lower royalties, DD&A and exploration expenses.

Production volumes for E&P Canada were 62,300 bbls/d in the second quarter of 2020, compared to 61,900 bbls/d in the prior year quarter. Production volumes increased in the second quarter of 2020, primarily due to higher production at Hebron as seven new production wells have come online since the second quarter of 2019, and the impacts of White Rose's staged return to full operations in the prior year quarter, partially offset by lower volumes at Terra Nova reflecting the regulatory order to shut in production in the fourth quarter of 2019. In the second quarter of 2020, the decision was made to disconnect the Terra Nova floating, production, storage and offloading (FPSO) vessel and dock shoreside in Newfoundland. Suncor is currently evaluating alternate options for return to operations and the Terra Nova Asset Life Extension project.

E&P International production was 39,500 boe/d in the second quarter of 2020, compared to 49,800 boe/d in the prior year quarter. The decrease in the second quarter of 2020 reflected unplanned maintenance and natural production declines in the U.K. and no Libya liftings, partially offset by increased production at Oda.

E&P sales volumes increased slightly to 108,700 boe/d in the second quarter of 2020, compared to 106,100 boe/d in the prior year quarter, due to the timing of sales volumes.

Price realizations at E&P Canada and E&P International in the second quarter of 2020 were significantly lower than in the prior year quarter, with the second quarter of 2020 impacted by the significant decline in benchmarks and demand for crude oil as a result of the COVID-19 pandemic and OPEC+ supply issues.

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

Operating and transportation expenses for the second quarter of 2020 increased as higher transportation expenses associated with the increase in sales volumes more than offset the decline in operating, selling and general expenses.

DD&A expense in the second quarter of 2020 was favourable when compared to the second quarter of 2019, primarily due to lower production rates in the U.K., partially offset by an increase in production at Oda.

Exploration expense in the second quarter of 2020 was lower than the prior year quarter which included charges for non-commercial drilling results off the east coast of Canada and the U.K. North Sea.

E&P's net loss was $478 million for the first six months of 2020, compared to net earnings of $948 million in the prior year period. In addition to the factors explained in the operating loss paragraph below, the net loss for the six months of 2020 included 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 six months of 2019 included an after-tax gain of $139 million on the sale of the company's interest in Canbriam and a one-time deferred income tax recovery of $70 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022.

E&P's operating loss for the first six months of 2020 was $56 million, compared to operating earnings of $739 million in the first six 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 $482 million for the first six months of 2020, compared to $1.209 billion for the first six months of 2019, due to the same reasons noted in operating (loss) earnings above.

There are no significant maintenance events scheduled for the third quarter of 2020. Suncor is currently evaluating alternate options for returning to operations at Terra Nova and its Asset Life Extension project. As a result of the COVID-19 pandemic, the company continues to assess planned maintenance schedules.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020	2019

Operating revenues	2 759		5 626		7 346	10 830

Net earnings	269		765		214	1 774

Adjusted for:

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

Impact of inventory write-down to net realizable value recorded in the first quarter⁽²⁾	(220	)	—		—	—

Operating earnings⁽³⁾	49		677		214	1 686

Funds from operations⁽³⁾	475		932		699	2 185

(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% over the next four years.
(2): During the first quarter of 2020, the company recorded an after-tax hydrocarbon inventory write-down to net realizable value of $220 million as a result of a significant decline in benchmarks and demand for crude oil and refined products due to COVID-19 mitigation efforts. The hydrocarbon inventory write-down of $220 million after-tax was excluded from operating earnings and funds from operations in the first quarter of 2020, and realized through operating earnings and funds from operations in the second quarter of 2020 when the product was sold.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings in the second quarter of 2020 were $49 million, compared to $677 million in the prior year quarter. The decrease was primarily due to lower refining and marketing margins as a result of significantly lower benchmark crack spreads, which decreased by more than 50% compared to the prior year quarter, and lower crude throughput and refined product sales as the company managed its operations to meet decreased demand levels for transportation fuels due to the COVID-19 pandemic. Operating earnings were further impacted by the realization of $220 million in after-tax hydrocarbon inventory losses that were recorded in net earnings in the first quarter of 2020, and a FIFO inventory valuation loss of $146 million after-tax on the decline in crude and product benchmarks. The prior year quarter included a FIFO inventory valuation gain of $38 million after-tax.


	Three months ended June 30		Six months ended June 30
	2020	2019	2020	2019

Crude oil processed (mbbls/d)

Eastern North America	169.2	170.0	191.1	193.0

Western North America	181.2	229.1	203.8	228.9

Total	350.4	399.1	394.9	421.9

Refinery utilization⁽¹⁾ (%)

Eastern North America	76	77	86	87

Western North America	76	95	85	95

Total	76	86	85	91

Refined product sales (mbbls/d)

Gasoline	175.6	235.3	204.9	241.0

Distillate	190.3	206.1	209.5	213.9

Other	72.9	66.7	70.7	70.5

Total	438.8	508.1	485.1	525.4

Refining and marketing margin – FIFO⁽²⁾⁽³⁾ ($/bbl)	20.95	41.30	22.30	45.60

Refining and marketing margin – LIFO⁽²⁾⁽³⁾ ($/bbl)	28.55	39.70	32.45	37.40

Refining operating expense⁽²⁾ ($/bbl)	5.80	5.90	5.70	5.75

(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.

Refinery crude throughput was 350,400 bbls/d in the second quarter of 2020, compared to 399,100 bbls/d in the prior year quarter. Utilization rates decreased to 76% in the second quarter of 2020 from 86% in the second quarter of 2019 as the company reduced refinery throughput as a result of a decrease in consumer demand for transportation fuels due to the COVID-19 pandemic. During the second quarter of 2020, as market conditions evolved and the demand profile shifted, the company was able to leverage its midstream storage capacity and diversified sales channels to respond quickly by ramping up throughput and changing product mix, which enabled the company to exit the quarter at greater than 85% utilization for its refineries.

Refined product sales were strong relative to the significant decline in industry demand at 438,800 bbls/d, compared to 508,100 bbls/d in the prior year quarter, primarily due to the company's secure sales channels.

Operating expenses in the second 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 throughput and sales volumes.

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

R&M's net earnings were $214 million for the first six months of 2020, compared to $1.774 billion in the prior year period. In addition to the factors explained in operating earnings below, net earnings for the first six 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 of 1% each year from 2019 to 2022.

Operating earnings for R&M in the first six months of 2020 were $214 million, compared to $1.686 billion in the first six 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. For the first six 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 $592 million after-tax, compared to a favourable $505 million after-tax impact in the first six months of 2019.

Funds from operations were $699 million in the first six months of 2020, compared to $2.185 billion in the first six months of 2019, and decreased primarily due to the same factors that influenced operating earnings described above.

Subsequent to the quarter, an eight-week maintenance event commenced at the Edmonton refinery. The anticipated impact of this maintenance event has been reflected in the company's 2020 guidance.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Net earnings (loss)	187		(53	)	(903	)	(273	)

Adjusted for:

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

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(478	)	(221	)	543		(482	)

Operating loss⁽²⁾	(291	)	(322	)	(360	)	(803	)

Corporate	*(240*	)	(261	)	*(451*	)	(563	)

Eliminations	*(51*	)	(61	)	91		(240	)

Funds used in operations⁽²⁾	(306	)	(300	)	(393	)	(854	)

(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% over the next four years.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Corporate incurred an operating loss of $240 million for the second quarter of 2020, compared to an operating loss of $261 million for the prior year quarter, with the decreased operating loss primarily due to CEWS, partially offset by higher interest expense associated with increased debt in 2020. Suncor capitalized $27 million of its borrowing costs in the second quarter of 2020 as part of the cost of major development assets and construction projects in progress, compared to $28 million in the prior year quarter.

Eliminations reflect the deferral or realization of profit or loss on crude oil sales from Oil Sands to Suncor's refineries. Consolidated profits and losses are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the second quarter of 2020, the company's elimination of profit amounted to $51 million after-tax, compared to the elimination of $61 million of after-tax intersegment profit in the prior year quarter. The elimination of profit in the second quarter of 2020 was driven by the increase in Oil Sands price realizations over the quarter, as lower margin crude refinery feedstock inventory sourced internally from Oil Sands was sold and replaced by higher margin feedstock inventory. The deferral of profit in the prior year quarter was due to an increase in intersegment inventory volumes.

The net loss for Corporate and Eliminations was $903 million for the first six months of 2020, compared to $273 million in the prior year period. In addition to the factors explained in operating loss below, the net loss for the first six months of 2020 included a $543 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 $482 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 of 1% each year from 2019 to 2022.

The operating loss for Corporate and Eliminations for the first six months of 2020 was $360 million, compared to $803 million in the first six months of 2019. The decreased loss was attributed to intercompany loss elimination in intercompany inventory, as compared to an elimination of profit in the prior year period, a share-based compensation recovery in the current year, as compared to a share-based compensation expense in the prior year period, and an operational foreign exchange gain, as compared to an operational foreign exchange loss in the prior year period, partially offset by higher interest expense associated with the increased debt balance in 2020. The elimination of unrealized losses 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 $65 million of its borrowing costs in the first six months of 2020, compared with $56 million in the first six months of 2019.

Corporate and Eliminations funds used in operations for the first six months of 2020 were $393 million, compared to $854 million in the prior year period. In addition to the factors noted above in operating loss, funds from operations in the first six months of 2020 were favourably impacted by a decrease in share-based compensation payments.

Capital and Exploration Expenditures by Type, excluding capitalized interest


	Three months ended June 30, 2020			Six months ended June 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	188	16	*204*	574	92	*666*

In Situ	42	43	85	179	241	*420*

Fort Hills	15	7	22	102	15	*117*

Syncrude	94	14	*108*	157	48	*205*

Exploration and Production	2	123	125	5	285	290

Refining and Marketing	64	20	84	113	61	174

Corporate and Eliminations	5	38	43	19	62	81

	410	261	671	1 149	804	1 953

(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 $671 million on capital expenditures, excluding capitalized interest, in the second quarter of 2020, a decrease from $1.336 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 R&M, as well as decreased In Situ and E&P economic investment capital expenditures in the second quarter of 2020.

Oil Sands Base capital expenditures were $204 million in the second 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 in anticipation of an in-service date in the fourth quarter of 2020.

In Situ capital expenditures were $85 million in the second quarter of 2020, and were primarily directed towards the rebuild at the MacKay River central processing facility, which returned to operations during the second quarter.

Capital expenditures at Fort Hills were $22 million in the second 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 $108 million in the second 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 $125 million in the second quarter of 2020 and were primarily focused on economic investment projects, including development drilling at Hibernia, Hebron and Buzzard, and limited development work on Fenja and the West White Rose Projects.

In the second quarter of 2020, the decision was made to disconnect the Terra Nova FPSO vessel and dock shoreside in Newfoundland. Suncor is currently evaluating alternate options for return to operations and the Terra Nova Asset Life Extension project.

R&M capital expenditures were $84 million and were primarily related to the ongoing sustainment and enhancement to refinery and retail operations.

Corporate capital expenditures were $43 million, primarily directed towards the company's information technology initiatives.


	Twelve months ended June 30
	2020		2019

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress⁽²⁾	(7.9	)	10.6

Including major projects in progress	(7.5	)	10.4

Net debt to funds from operations⁽³⁾⁽⁴⁾ (times)	3.0		1.5

Interest coverage on long-term debt (times)

Earnings basis⁽⁵⁾	(5.1	)	7.7

Funds from operations basis⁽⁴⁾⁽⁶⁾	7.4		14.1

Total debt to total debt plus shareholders' equity (%)	37.5		28.5

(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 1.1% for the twelve months ended June 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 second 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. The company expects its financial results for the year to experience a material decline relative to the results for the year ended December 31, 2019.

In response to the COVID-19 pandemic and OPEC+ supply issues, the company previously announced that it had decided to reduce its 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 the second quarter of 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 an additional $300 million of credit facilities and, as at June 30, 2020, had $8.65 billion of liquidity. 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 economic investments and shareholder returns.

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 June 30, 2020, cash and cash equivalents decreased to $1.846 billion, from $2.226 billion at March 31, 2020, due to an increase in cash flow used in operating activities, the use of cash related to the company's capital and exploration expenditures, dividend payments, repayment of short-term debt and increase in investing non-cash working capital partially offset by an increase in long-term debt.

For the six months ended June 30, 2020, cash and cash equivalents decreased to $1.846 billion, from $1.960 billion at December 31, 2019, with the use of cash related to the company's capital and exploration expenditures, and dividend payments, more than offsetting the cash flow provided by operating activities and the increase in short-term and long-term debt.

As at June 30, 2020, the weighted average days to maturity of the company's short-term investment portfolio was approximately 10 days.

Available credit facilities for liquidity purposes at June 30, 2020 increased to $6.804 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 the first half of 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 will help ensure the company has access to adequate financial resources should it be required.

In the second quarter of 2020, Moody's Investors Service affirmed the company's Baa1 rating, with a Stable Outlook, on long-term debt. Additionally, Dominion Bond Rating Service resolved the Under Review with Negative Implications status and affirmed the company's A (low) rating with a Negative outlook, on long-term debt, and affirmed the company's R-1 (low) rating, on its Canadian short-term debt.

Management of debt levels and liquidity continues to be a priority for Suncor given the company's long-term growth plans and future expected volatility in the business environment. Suncor believes a phased and flexible approach to existing and future growth projects should assist the company in maintaining its ability to manage project costs and debt levels. We believe that the disciplined actions around liquidity and capital spending that 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 June 30, 2020, total debt to total debt plus shareholders' equity was 37.5% (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)	June 30 2020	December 31 2019

Short-term debt	3 018	2 155

Current portion of long-term debt	—	—

Current portion of long-term lease liabilities	288	310

Long-term debt	15 969	12 884

Long-term lease liabilities	2 605	2 621

Total debt	21 880	17 970

Less: Cash and cash equivalents	1 846	1 960

Net debt	20 034	16 010

Shareholders' equity	36 516	42 042

Total debt plus shareholders' equity	58 396	60 012

Total debt to total debt plus shareholders' equity (%)	37.5	29.9


($ millions)	Three months ended June 30, 2020		Six months ended June 30, 2020

Total debt – beginning of period	20 438		17 970

Increase in long-term debt	2 634		2 634

(Decrease) increase in short-term debt	(662	)	724

Increase in lease liability	54		111

Lease payments	(89	)	(171	)

Foreign exchange on debt, and other	(495	)	612

Total debt – June 30, 2020	21 880		21 880

Less: Cash and cash equivalents – June 30, 2020	1 846		1 846

Net debt – June 30, 2020	20 034		20 034

The company's total debt increased in the second quarter of 2020 due to an increase in long-term indebtedness and leases entered into during the period, partially offset by the repayment of short-term debt, favourable foreign exchange rates on U.S. dollar denominated debt compared to March 31, 2020 and lease principal payments made during the second quarter of 2020.

The company's total debt increased in the first six months of 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 six months of 2020, partially offset by lease principal payments made during the first half of the year.

As at July 20, 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 38,928,816. Once exercisable, each outstanding common share option is convertible into one common share.

In May 2019, Suncor renewed its normal course issuer bid (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 that 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.

In the second quarter of 2020, the company increased its commitments as a result of debt issued in the second quarter of 2020. In the second quarter of 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.

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, and the Government of Alberta's mandatory production curtailments implemented during 2019.


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

Total production (mboe/d)

Oil Sands	553.7		630.1		662.3		670.0		692.2	657.2	740.8		651.7

Exploration and Production	101.8		109.7		115.9		92.3		111.7	107.1	90.2		92.1

	655.5		739.8		778.2		762.3		803.9	764.3	831.0		743.8

Revenues and other income

Operating revenues, net of royalties	4 229		7 391		9 487		9 803		10 071	8 983	8 561		10 847

Other income	16		365		111		93		27	414	384		16

	4 245		7 756		9 598		9 896		10 098	9 397	8 945		10 863

Net (loss) earnings	(614	)	(3 525	)	(2 335	)	1 035		2 729	1 470	(280	)	1 812

per common share – basic (dollars)	(0.40	)	(2.31	)	(1.52	)	0.67		1.74	0.93	(0.18	)	1.12

per common share – diluted (dollars)	(0.40	)	(2.31	)	(1.52	)	0.67		1.74	0.93	(0.18	)	1.11

Operating (loss) earnings⁽¹⁾	(1 489	)	(309	)	782		1 114		1 253	1 209	580		1 557

per common share – basic⁽¹⁾ (dollars)	(0.98	)	(0.20	)	0.51		0.72		0.80	0.77	0.36		0.96

Funds from operations⁽¹⁾	488		1 001		2 553		2 675		3 005	2 585	2 007		3 139

per common share – basic⁽¹⁾ (dollars)	0.32		0.66		1.66		1.72		1.92	1.64	1.26		1.94

Cash flow (used in) provided by operating activities	(768	)	1 384		2 304		3 136		3 433	1 548	3 040		4 370

per common share – basic (dollars)	(0.50	)	0.91		1.50		2.02		2.19	0.98	1.90		2.70

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

ROCE⁽¹⁾⁽²⁾, excluding major projects in progress (%) for the twelve months ended	(7.9	)	(1.4	)	5.1		9.9		10.6	8.3	8.2		10.4

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	478		(1 021	)	235		(127	)	221	261	(637	)	195

Common share information (dollars)

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

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	22.89		22.46		42.56		41.79		40.85	43.31	38.13		49.98

New York Stock Exchange (US$)	16.86		15.80		32.80		31.58		31.16	32.43	27.97		38.69

(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 1.1% for the twelve months ended June 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)		Jun 30 2020		Mar 31 2020		Dec 31 2019		Sept 30 2019		Jun 30 2019		Mar 31 2019		Dec 31 2018		Sept 30 2018

WTI crude oil at Cushing	US$/bbl	27.85		46.10		56.95		56.45		59.85		54.90		58.85		69.50

Dated Brent crude	US$/bbl	29.20		50.15		63.30		61.90		68.85		63.20		67.80		75.25

Dated Brent/Maya FOB price differential	US$/bbl	2.70		15.95		9.30		5.20		6.90		5.00		4.35		10.20

MSW at Edmonton	Cdn$/bbl	30.20		52.00		68.10		68.35		73.40		66.45		42.70		82.10

WCS at Hardisty	US$/bbl	16.35		25.60		41.10		44.20		49.20		42.50		19.50		47.35

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(11.50	)	(20.50	)	(15.85	)	(12.25	)	(10.65	)	(12.40	)	(39.35	)	(22.15	)

SYN-WTI (differential) premium	US$/bbl	(4.55	)	(2.70	)	(0.70	)	0.40		0.15		(2.30	)	(21.60	)	(0.90	)

Condensate at Edmonton	US$/bbl	22.20		46.20		53.00		52.00		55.90		50.55		45.30		66.80

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.00		2.05		2.50		0.95		1.05		2.55		1.60		1.20

Alberta Power Pool Price	Cdn$/MWh	29.90		67.05		46.95		46.85		56.35		70.75		55.55		54.45

New York Harbor 2-1-1 crack⁽¹⁾	US$/bbl	12.20		14.75		18.50		19.75		22.40		19.10		18.75		19.50

Chicago 2-1-1 crack⁽¹⁾	US$/bbl	6.75		9.75		14.45		17.05		21.55		15.30		16.25		19.90

Portland 2-1-1 crack⁽¹⁾	US$/bbl	12.20		18.30		25.75		23.85		29.15		19.35		24.25		22.05

Gulf Coast 2-1-1 crack⁽¹⁾	US$/bbl	9.00		13.00		17.10		20.00		21.70		17.85		17.45		19.30

Exchange rate	US$/Cdn$	0.72		0.74		0.76		0.76		0.75		0.75		0.76		0.77

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

(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 six months ended June 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 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 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 six months ended June 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 six months ended June 30, 2020, and the Financial Condition and Liquidity section of the 2019 annual MD&A.

Based on their evaluation as at June 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 June 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 June 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 and May 5, 2020), as set forth in Suncor's press release dated July 22, 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 June 30 ($ millions, except as noted)		2020		2019

Adjustments to net earnings

Net (loss) earnings		(5 439	)	5 731

Add (deduct) after-tax amounts for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt		435		(40	)

Net interest expense		650		616

	A	(4 354	)	6 307

Capital employed – beginning of twelve-month period

Net debt		16 121		16 163

Shareholders' equity		45 509		45 543

		61 630		61 706

Capital employed – end of twelve-month period

Net debt		20 034		16 121

Shareholders' equity		36 516		45 509

		56 550		61 630

Average capital employed	B	58 179		60 702

ROCE – including major projects in progress (%)	A/B	(7.5	)	10.4

Average capitalized costs related to major projects in progress	C	3 329		1 135

ROCE – excluding major projects in progress (%)⁽¹⁾	A/(B-C)	(7.9	)	10.6

(1): ROCE excluding major projects in progress would have been 1.1% for the twelve months ended June 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 (used in) 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 June 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	(1 019	)	1 561		(51	)	456		269		765		187		(53	)	(614	)	2 729

Adjustments for:

Depreciation, depletion, amortization and impairment	1 065		1 060		223		235		214		200		20		18		1 522		1 513

Deferred income taxes	(58	)	(797	)	(24	)	(89	)	27		(66	)	(36	)	(48	)	(91	)	(1 000	)

Accretion	56		56		12		11		1		1		—		—		69		68

Unrealized foreign exchange gain on U.S. dollar denominated debt	—		—		—		—		—		—		(499	)	(231	)	(499	)	(231	)

Change in fair value of financial instruments and trading inventory	(78	)	39		142		10		(37	)	27		—		—		27		76

Loss (gain) on disposal of assets	1		(6	)	—		(151	)	(1	)	(1	)	(1	)	—		(1	)	(158	)

Share-based compensation expense	11		9		1		1		6		5		19		9		37		24

Exploration	—		—		10		37		—		—		—		—		10		37

Settlement of decommissioning and restoration liabilities	(34	)	(68	)	(2	)	(4	)	(2	)	(4	)	—		—		(38	)	(76	)

Other	66		12		(2	)	1		(2	)	5		4		5		66		23

Funds from (used in) operations	10		1 866		309		507		475		932		(306	)	(300	)	488		3 005

(Increase) decrease in non-cash working capital																	(1 256	)	428

Cash flow (used in) provided by operating activities																	(768	)	3 433


Six months ended June 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	(2 972	)	1 750		(478	)	948		214		1 774		(903	)	(273	)	(4 139	)	4 199

Adjustments for:

Depreciation, depletion, amortization and impairment	4 130		2 052		1 051		482		446		403		41		38		5 668		2 975

Deferred income taxes	(502	)	(737	)	(152	)	(122	)	17		(61	)	26		(77	)	(611	)	(997	)

Accretion	112		114		23		22		3		3		—		—		138		139

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		597		(511	)	597		(511	)

Change in fair value of financial instruments and trading inventory	85		45		6		6		61		97		—		—		152		148

Gain on disposal of assets	—		(10	)	—		(151	)	(4	)	(2	)	(1	)	—		(5	)	(163	)

Share-based compensation recovery	(75	)	(25	)	(10	)	(4	)	(45	)	(19	)	(159	)	(37	)	(289	)	(85	)

Exploration	—		—		80		39		—		—		—		—		80		39

Settlement of decommissioning and restoration liabilities	(133	)	(180	)	(6	)	(5	)	(5	)	(5	)	—		—		(144	)	(190	)

Other	56		41		(32	)	(6	)	12		(5	)	6		6		42		36

Funds from (used in) operations	701		3 050		482		1 209		699		2 185		(393	)	(854	)	1 489		5 590

Increase in non-cash working capital																	(873	)	(609	)

Cash flow provided in operating activities																	616		4 981

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) reflects 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 June 30				Six months ended June 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	1 058		1 647		1 687		3 787

Other (loss) income	(26	)	14		60		29

Non-refining margin	(312	)	(14	)	(29	)	(27	)

Refining and marketing margin	720		1 647		1 718		3 789

Refinery production⁽¹⁾ (mbbls)	34 369		39 901		77 098		83 044

Refining and marketing margin – FIFO⁽²⁾ ($/bbl)	20.95		41.30		22.30		45.60

Refining and marketing margin – LIFO⁽²⁾ ($/bbl)	28.55		39.70		32.45		37.40

Refining operating expense reconciliation

Operating, selling and general expense	417		530		928		1 066

Non-refining costs	(218	)	(295	)	(488	)	(589	)

Refining operating expense	199		235		440		477

Refinery production⁽¹⁾ (mbbls)	34 369		39 901		77 098		83 044

Refining operating expense ($/bbl)	5.80		5.90		5.70		5.75

(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.


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
		Q2	Three months ended June 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

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 June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Revenues and Other Income

Operating revenues, net of royalties (note 3)	4 229		10 071		11 620		19 054

Other income (note 4)	16		27		381		441

	4 245		10 098		12 001		19 495

Expenses

Purchases of crude oil and products	1 419		3 286		4 599		5 907

Operating, selling and general (note 10)	2 156		2 799		5 123		5 631

Transportation	329		361		665		697

Depreciation, depletion, amortization and impairment (note 11)	1 522		1 513		5 668		2 975

Exploration	25		76		164		189

Gain on disposal of assets	(1	)	(158	)	(5	)	(163	)

Financing (income) expenses (note 6)	(136	)	97		1 206		129

	5 314		7 974		17 420		15 365

(Loss) Earnings before Income Taxes	(1 069	)	2 124		(5 419	)	4 130

Income Tax (Recovery) Expense

Current	(364	)	395		(669	)	928

Deferred	(91	)	(1 000	)	(611	)	(997	)

	(455	)	(605	)	(1 280	)	(69	)

Net (Loss) Earnings	(614	)	2 729		(4 139	)	4 199

Other Comprehensive Loss

Items That May be Subsequently Reclassified to Earnings:

Foreign currency translation adjustment	(109	)	(80	)	132		(148	)

Items That Will Not be Reclassified to Earnings:

Actuarial loss on employee retirement benefit plans, net of income taxes	(412	)	(177	)	(399	)	(313	)

Other Comprehensive Loss	(521	)	(257	)	(267	)	(461	)

Total Comprehensive (Loss) Income	(1 135	)	2 472		(4 406	)	3 738

Per Common Share (dollars) (note 7)

Net (loss) earnings – basic	(0.40	)	1.74		(2.71	)	2.67

Net (loss) earnings – diluted	(0.40	)	1.74		(2.71	)	2.66

Cash dividends	0.21		0.42		0.68		0.84

See accompanying notes to the condensed interim consolidated financial statements.


($ millions)	June 30 2020	December 31 2019

Assets

Current assets

Cash and cash equivalents	1 846	1 960

Accounts receivable	2 656	4 052

Inventories (note 10)	3 228	3 761

Income taxes receivable	646	133

Total current assets	8 376	9 906

Property, plant and equipment, net (note 11)	68 514	72 640

Exploration and evaluation	2 484	2 428

Other assets	1 242	1 194

Goodwill and other intangible assets	3 057	3 058

Deferred income taxes	156	209

Total assets	83 829	89 435

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	3 018	2 155

Current portion of long-term lease liabilities	288	310

Accounts payable and accrued liabilities	4 161	6 555

Current portion of provisions	634	631

Income taxes payable	97	886

Total current liabilities	8 198	10 537

Long-term debt	15 969	12 884

Long-term lease liabilities	2 605	2 621

Other long-term liabilities	2 993	2 499

Provisions (note 12)	8 169	8 676

Deferred income taxes	9 379	10 176

Equity	36 516	42 042

Total liabilities and shareholders' equity	83 829	89 435

See accompanying notes to the condensed interim consolidated financial statements.


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Operating Activities

Net (Loss) Earnings	(614	)	2 729		(4 139	)	4 199

Adjustments for:

Depreciation, depletion, amortization and impairment (note 11)	1 522		1 513		5 668		2 975

Deferred income tax recovery	(91	)	(1 000	)	(611	)	(997	)

Accretion (note 6)	69		68		138		139

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt (note 6)	(499	)	(231	)	597		(511	)

Change in fair value of financial instruments and inventory	27		76		152		148

Gain on disposal of assets	(1	)	(158	)	(5	)	(163	)

Share-based compensation	37		24		(289	)	(85	)

Exploration	10		37		80		39

Settlement of decommissioning and restoration liabilities	(38	)	(76	)	(144	)	(190	)

Other	66		23		42		36

(Increase) decrease in non-cash working capital	(1 256	)	428		(873	)	(609	)

Cash flow (used in) provided by operating activities	(768	)	3 433		616		4 981

Investing Activities

Capital and exploration expenditures	(698	)	(1 364	)	(2 018	)	(2 267	)

Proceeds from disposal of assets	2		159		7		166

Other investments	(66	)	(42	)	(87	)	(99	)

(Increase) decrease in non-cash working capital	(364	)	28		(544	)	(6	)

Cash flow used in investing activities	(1 126	)	(1 219	)	(2 642	)	(2 206	)

Financing Activities

Net (decrease) increase in short-term debt	(662	)	(1 281	)	724		(955	)

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

Lease liability payments	(89	)	(72	)	(171	)	(142	)

Issuance of common shares under share option plans	—		6		29		41

Repurchase of common shares (note 8)	—		(552	)	(307	)	(1 066	)

Distributions relating to non-controlling interest	(3	)	(2	)	(5	)	(4	)

Dividends paid on common shares	(320	)	(658	)	(1 029	)	(1 320	)

Cash flow provided by (used in) financing activities	1 560		(2 002	)	1 875		(2 889	)

(Decrease) Increase in Cash and Cash Equivalents	(334	)	212		(151	)	(114	)

Effect of foreign exchange on cash and cash equivalents	(46	)	(26	)	37		(46	)

Cash and cash equivalents at beginning of period	2 226		1 875		1 960		2 221

Cash and Cash Equivalents at End of Period	1 846		2 061		1 846		2 061

Supplementary Cash Flow Information

Interest paid	361		352		508		506

Income taxes (received) paid	(173	)	282		578		398

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	—		—		—		4 199		4 199		—

Foreign currency translation adjustment	—		—		(148	)	—		(148	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $107	—		—		—		(313	)	(313	)	—

Total comprehensive (loss) income	—		—		(148	)	3 886		3 738		—

Issued under share option plans	53		(11	)	—		—		42		1 197

Repurchase of common shares for cancellation (note 8)	(406	)	—		—		(660	)	(1 066	)	(24 952	)

Change in liability for share repurchase commitment	30		—		—		33		63		—

Share-based compensation	—		33		—		—		33		—

Dividends paid on common shares	—		—		—		(1 320	)	(1 320	)	—

At June 30, 2019	25 587		562		928		18 432		45 509		1 560 729

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

Net loss	—		—		—		(4 139	)	(4 139	)	—

Foreign currency translation adjustment	—		—		132		—		132		—

Actuarial loss on employee retirement benefit plans, net of income taxes of $124	—		—		—		(399	)	(399	)	—

Total comprehensive income (loss)	—		—		132		(4 538	)	(4 406	)	—

Issued under share option plans	36		(7	)	—		—		29		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	—		19		—		—		19		—

Dividends paid on common shares	—		—		—		(1 029	)	(1 029	)	—

At June 30, 2020	25 144		578		1 031		9 763		36 516		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.

Market conditions have improved over the course of the second quarter of 2020 as nations began easing lockdown restrictions; however, the COVID-19 pandemic continues to present challenges to our operations and business environment. Management cannot reasonably estimate the length or severity of this pandemic but continues to monitor its impact on our operations.

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 June 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	1 215		3 985		293		994		2 737		5 592		6		6		4 251		10 577

Intersegment revenues	437		1 155		—		—		22		34		(459	)	(1 189	)	—		—

Less: Royalties	(16	)	(341	)	(6	)	(165	)	—		—		—		—		(22	)	(506	)

Operating revenues, net of royalties	1 636		4 799		287		829		2 759		5 626		(453	)	(1 183	)	4 229		10 071

Other income (loss)	23		1		24		9		(26	)	14		(5	)	3		16		27

	1 659		4 800		311		838		2 733		5 640		(458	)	(1 180	)	4 245		10 098

Expenses

Purchases of crude oil and products	91		404		—		—		1 701		3 979		(373	)	(1 097	)	1 419		3 286

Operating, selling and general	1 528		2 060		111		114		417		530		100		95		2 156		2 799

Transportation	272		326		33		21		34		27		(10	)	(13	)	329		361

Depreciation, depletion, amortization and impairment	1 065		1 060		223		235		214		200		20		18		1 522		1 513

Exploration	1		10		24		66		—		—		—		—		25		76

Loss (gain) on disposal of assets	1		(6	)	—		(151	)	(1	)	(1	)	(1	)	—		(1	)	(158	)

Financing expenses (income)	92		74		14		14		15		14		(257	)	(5	)	(136	)	97

	3 050		3 928		405		299		2 380		4 749		(521	)	(1 002	)	5 314		7 974

(Loss) Earnings before Income Taxes	(1 391	)	872		(94	)	539		353		891		63		(178	)	(1 069	)	2 124

Income Tax (Recovery) Expense

Current	(314	)	108		(19	)	172		57		192		(88	)	(77	)	(364	)	395

Deferred	(58	)	(797	)	(24	)	(89	)	27		(66	)	(36	)	(48	)	(91	)	(1 000	)

	(372	)	(689	)	(43	)	83		84		126		(124	)	(125	)	(455	)	(605	)

Net (Loss) Earnings	(1 019	)	1 561		(51	)	456		269		765		187		(53	)	(614	)	2 729

Capital and Exploration Expenditures	437		856		131		268		86		220		44		20		698		1 364


Six months ended June 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	3 542		7 204		832		1 931		7 300		10 782		15		14		11 689		19 931

Intersegment revenues	1 427		2 117		—		—		46		48		(1 473	)	(2 165	)	—		—

Less: Royalties	(41	)	(539	)	(28	)	(338	)	—		—		—		—		(69	)	(877	)

Operating revenues, net of royalties	4 928		8 782		804		1 593		7 346		10 830		(1 458	)	(2 151	)	11 620		19 054

Other income (loss)	271		11		57		395		60		29		(7	)	6		381		441

	5 199		8 793		861		1 988		7 406		10 859		(1 465	)	(2 145	)	12 001		19 495

Expenses

Purchases of crude oil and products	498		677		—		—		5 659		7 043		(1 558	)	(1 813	)	4 599		5 907

Operating, selling and general	3 780		4 033		244		262		928		1 066		171		270		5 123		5 631

Transportation	561		624		56		40		70		56		(22	)	(23	)	665		697

Depreciation, depletion, amortization and impairment	4 130		2 052		1 051		482		446		403		41		38		5 668		2 975

Exploration	58		112		106		77		—		—		—		—		164		189

Gain on disposal of assets	—		(10	)	—		(151	)	(4	)	(2	)	(1	)	—		(5	)	(163	)

Financing expenses (income)	173		143		17		28		15		27		1 001		(69	)	1 206		129

	9 200		7 631		1 474		738		7 114		8 593		(368	)	(1 597	)	17 420		15 365

(Loss) Earnings before Income Taxes	(4 001	)	1 162		(613	)	1 250		292		2 266		(1 097	)	(548	)	(5 419	)	4 130

Income Tax (Recovery) Expense

Current	(527	)	149		17		424		61		553		(220	)	(198	)	(669	)	928

Deferred	(502	)	(737	)	(152	)	(122	)	17		(61	)	26		(77	)	(611	)	(997	)

	(1 029	)	(588	)	(135	)	302		78		492		(194	)	(275	)	(1 280	)	(69	)

Net (Loss) Earnings	(2 972	)	1 750		(478	)	948		214		1 774		(903	)	(273	)	(4 139	)	4 199

Capital and Exploration Expenditures	1 447		1 440		310		496		178		302		83		29		2 018		2 267

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

Oil Sands⁽¹⁾

SCO and diesel	1 312		—	1 312		3 699		—	3 699

Bitumen	340		—	340		1 441		—	1 441

	1 652		—	1 652		5 140		—	5 140

Exploration and Production

Crude oil and natural gas liquids	160		132	292		507		486	993

Natural gas	—		1	1		—		1	1

	160		133	293		507		487	994

Refining and Marketing

Gasoline	1 132		—	1 132		2 660		—	2 660

Distillate	1 148		—	1 148		2 255		—	2 255

Other	479		—	479		711		—	711

	2 759		—	2 759		5 626		—	5 626

Corporate and Eliminations

	(453	)	—	(453	)	(1 183	)	—	(1 183	)

Total Revenue from Contracts with Customers	4 118		133	4 251		10 090		487	10 577

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


Six months ended June 30	2020					2019
($ millions)	North America		International	Total		North America		International	Total

Oil Sands⁽¹⁾

SCO and diesel	4 091		—	4 091		7 040		—	7 040

Bitumen	878		—	878		2 281		—	2 281

	4 969		—	4 969		9 321		—	9 321

Exploration and Production

Crude oil and natural gas liquids	479		351	830		998		930	1 928

Natural gas	—		2	2		—		3	3

	479		353	832		998		933	1 931

Refining and Marketing

Gasoline	3 026		—	3 026		4 766		—	4 766

Distillate	3 264		—	3 264		4 638		—	4 638

Other	1 056		—	1 056		1 426		—	1 426

	7 346		—	7 346		10 830		—	10 830

Corporate and Eliminations

	(1 458	)	—	(1 458	)	(2 151	)	—	(2 151	)

Total Revenue from Contracts with Customers	11 336		353	11 689		18 998		933	19 931

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


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Energy trading activities

(Losses) gains recognized in earnings	(69	)	15		167		110

Gains (losses) on inventory valuation	87		(12	)	(10	)	(35	)

Short-term commodity risk management	(86	)	11		99		(46	)

Investment and interest income	13		—		49		50

Insurance proceeds⁽¹⁾	49		34		49		397

Other	22		(21	)	27		(35	)

	16		27		381		441

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

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


	Three months ended June 30				Six months ended June 30
($ millions)	2020		2019		2020		2019

Interest on debt	225		202		441		412

Interest on lease liabilities	42		43		84		88

Capitalized interest	(27	)	(28	)	(65	)	(56	)

Interest expense	240		217		460		444

Interest on partnership liability	13		14		26		28

Interest on pension and other post-retirement benefits	13		15		27		30

Accretion	69		68		138		139

Foreign exchange (gain) loss on U.S. dollar denominated debt	(499	)	(231	)	597		(511	)

Operational foreign exchange and other	28		14		(42	)	(1	)

	(136	)	97		1 206		129

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 June 30			Six months ended June 30
($ millions)	2020		2019	2020		2019

Net (loss) earnings	(614	)	2 729	(4 139	)	4 199

(millions of common shares)

Weighted average number of common shares	1 525		1 569	1 527		1 574

Dilutive securities:

Effect of share options	—		3	—		3

Weighted average number of diluted common shares	1 525		1 572	1 527		1 577

(dollars per common share)

Basic (loss) earnings per share	(0.40	)	1.74	(2.71	)	2.67

Diluted (loss) earnings per share	(0.40	)	1.74	(2.71	)	2.66

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 capital allocation strategy, the share buyback program has been suspended.

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 June 30, 2020:

During the second 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 June 30, 2020, the carrying value of fixed-term debt accounted for under amortized cost was $16.0 billion (December 31, 2019 – $12.9 billion) and the fair value was $18.7 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.

As a result of lower crude oil and refined products prices, the company recorded a $61 million ($45 million after-tax) write-down of crude oil inventories to their respective net realizable values during the three months ended June 30, 2020 within purchases of crude oil products, operating, selling and general, and depreciation, depletion, amortization and impairment expenses.

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 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.

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.

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.

Suncor's decommissioning and restoration provision decreased by $526 million for the six months ended June 30, 2020. The decrease was primarily due to an increase in the credit-adjusted risk-free interest rate to 3.60% (December 31, 2019 – 3.30%).

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
QUARTERLY FINANCIAL SUMMARY
(unaudited)


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

Revenues, net of royalties, and other income		4 245			7 756			9 598			9 896			10 098			12 001			19 495			38 989

Net (loss) earnings

Oil Sands		(1 019	)		(1 953	)		(2 682	)		505			1 561			(2 972	)		1 750			(427	)

Exploration and Production		(51	)		(427	)		(162	)		219			456			(478	)		948			1005

Refining and Marketing		269			(55	)		558			668			765			214			1 774			3 000

Corporate and Eliminations		187			(1 090	)		(49	)		(357	)		(53	)		(903	)		(273	)		(679	)

Total		(614	)		(3 525	)		(2 335	)		1 035			2 729			(4 139	)		4 199			2 899

Operating (loss) earnings^(A)

Oil Sands		(1 196	)		(400	)		277			505			651			(1 596	)		840			1 622

Exploration and Production		(51	)		(5	)		231			171			247			(56	)		739			1 141

Refining and Marketing		49			165			558			668			677			214			1 686			2 912

Corporate and Eliminations		(291	)		(69	)		(284	)		(230	)		(322	)		(360	)		(803	)		(1 317	)

Total		(1 489	)		(309	)		782			1 114			1 253			(1 798	)		2 462			4 358

Funds from (used in) operations^(A)

Oil Sands		10			691			1 405			1 606			1 866			701			3 050			6 061

Exploration and Production		309			173			555			379			507			482			1 209			2 143

Refining and Marketing		475			224			793			885			932			699			2 185			3 863

Corporate and Eliminations		(306	)		(87	)		(200	)		(195	)		(300	)		(393	)		(854	)		(1 249	)

Total		488			1 001			2 553			2 675			3 005			1 489			5 590			10 818

Change in non-cash working capital		(1 256	)		383			(249	)		461			428			(873	)		(609	)		(397	)

Cash flow (used in) provided by operating activities		(768	)		1 384			2 304			3 136			3 433			616			4 981			10 421

Per common share

Net (loss) earnings – basic		(0.40	)		(2.31	)		(1.52	)		0.67			1.74			(2.71	)		2.67			1.86

Operating (loss) earnings – basic^(A)		(0.98	)		(0.20	)		0.51			0.72			0.80			(1.18	)		1.56			2.80

Cash dividends – basic		0.21			0.47			0.42			0.42			0.42			0.68			0.84			1.68

Funds from operations – basic^(A)		0.32			0.66			1.66			1.72			1.92			0.98			3.55			6.94

Cash flow (used in) provided by operating activities – basic		(0.50	)		0.91			1.50			2.02			2.19			0.41			3.16			6.69

Capital and exploration expenditures (including capitalized interest)

Oil Sands		437			1 010			1 082			1 000			856			1 447			1 440			3 522

Exploration and Production		131			179			281			293			268			310			496			1 070

Refining and Marketing		86			92			314			202			220			178			302			818

Corporate and Eliminations		44			39			98			21			20			83			29			148

Total capital and exploration expenditures		698			1 320			1 775			1 516			1 364			2 018			2 267			5 558

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Production Volumes^(B)

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

Oil Sands operations		319.4		331.8		300.0		317.0		295.5		325.6		318.2		313.3

Syncrude		117.2		171.8		156.3		162.3		188.7		144.5		185.5		172.3

Total upgraded production		436.6		503.6		456.3		479.3		484.2		470.1		503.7		485.6

Non-upgraded bitumen production (mbbls/d)

Oil Sands operations		69.8		45.8		118.1		105.2		118.7		57.8		87.2		99.5

Fort Hills		47.3		80.7		87.9		85.5		89.3		64.0		83.9		85.3

Total Oil Sands non-upgraded bitumen production		117.1		126.5		206.0		190.7		208.0		121.8		171.1		184.8

Total Oil Sands production volumes (mbbls/d)		553.7		630.1		662.3		670.0		692.2		591.9		674.8		670.4

Oil Sands Sales Volumes (mbbls/d)

Upgraded product (SCO and diesel)		443.1		512.5		447.6		483.1		497.2		477.9		502.3		483.6

Non-upgraded bitumen		116.4		127.5		218.1		201.8		197.1		121.9		164.6		187.5

Total Oil Sands sales volumes		559.5		640.0		665.7		684.9		694.3		599.8		666.9		671.1

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

Cash costs		23.55		27.15		26.00		25.65		26.80		25.35		27.15		26.35

Natural gas		2.25		2.30		2.55		0.95		1.00		2.25		1.70		1.85

		25.80		29.45		28.55		26.60		27.80		27.60		28.85		28.20

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

Cash costs		33.40		29.40		27.05		23.65		21.80		30.90		24.55		24.95

Natural gas		1.95		1.60		1.60		0.60		0.70		1.70		1.25		1.20

		35.35		31.00		28.65		24.25		22.50		32.60		25.80		26.15

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

Cash costs		36.70		35.30		37.30		38.95		33.40		35.90		33.60		35.65

Natural gas		1.65		1.35		1.55		0.70		0.50		1.40		1.00		1.10

		38.35		36.65		38.85		39.65		33.90		37.30		34.60		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															Six months ended						Twelve months ended
Oil Sands Segment Netbacks^(A)(D)(E)	Jun 30 2020			Mar 31 2020			Dec 31 2019			Sep 30 2019			Jun 30 2019			Jun 30 2020			Jun 30 2019			Dec 31 2019

Bitumen ($/bbl)

Average price realized		20.69			28.24			44.04			53.38			57.92			24.64			56.64			52.05

Royalties		(0.21	)		(0.44	)		(1.22	)		(1.86	)		(2.29	)		(0.33	)		(1.94	)		(1.70	)

Transportation costs		(6.73	)		(7.22	)		(5.47	)		(6.27	)		(7.02	)		(6.99	)		(6.98	)		(6.34	)

Net operating expenses		(20.97	)		(21.90	)		(15.87	)		(14.73	)		(15.33	)		(21.45	)		(16.59	)		(15.88	)

Operating netback		(7.22	)		(1.32	)		21.48			30.52			33.28			(4.13	)		31.13			28.13

SCO and diesel ($/bbl)

Average price realized		31.39			57.54			76.15			74.67			80.48			45.41			75.46			75.43

Royalties		(0.35	)		(0.35	)		(2.89	)		(4.52	)		(6.63	)		(0.35	)		(5.20	)		(4.49	)

Transportation costs		(4.91	)		(4.35	)		(5.14	)		(5.04	)		(4.34	)		(4.61	)		(4.42	)		(4.75	)

Net operating expenses		(29.58	)		(30.11	)		(31.92	)		(29.78	)		(31.59	)		(29.86	)		(30.72	)		(30.76	)

Operating netback		(3.45	)		22.73			36.20			35.33			37.92			10.59			35.12			35.43

Average Oil Sands Segment ($/bbl)

Average price realized		29.16			51.70			65.63			68.40			74.08			41.19			70.82			68.89

Royalties		(0.32	)		(0.42	)		(2.34	)		(3.74	)		(5.40	)		(0.38	)		(4.46	)		(3.74	)

Transportation costs		(5.29	)		(4.92	)		(5.25	)		(5.40	)		(5.10	)		(5.09	)		(5.05	)		(5.19	)

Net operating expenses		(27.79	)		(28.47	)		(26.66	)		(25.34	)		(26.97	)		(28.15	)		(27.23	)		(26.61	)

Operating netback		(4.24	)		17.89			31.38			33.92			36.61			7.57			34.08			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										Six months ended				Twelve months ended
Exploration and Production	Jun 30 2020		Mar 31 2020		Dec 31 2019		Sep 30 2019		Jun 30 2019		Jun 30 2020		Jun 30 2019		Dec 31 2019

Production Volumes^(F)

Exploration and Production Canada (mbbs/d)	62.3		62.2		69.6		49.6		61.9		62.3		60.0		59.9

Exploration and Production International (mboe/d)	39.5		47.5		46.3		42.7		49.8		43.5		49.3		46.9

Total production volumes (mboe/d)	101.8		109.7		115.9		92.3		111.7		105.8		109.3		106.8

Total Sales Volumes (mboe/d)	108.7		107.2		113.5		92.5		106.1		107.9		108.9		106.0

Netbacks^(A)(D)

East Coast Canada ($/bbl)

Average price realized	27.55		69.50		86.07		81.25		92.42		47.97		89.23		86.62

Royalties	(0.96	)	(4.06	)	(13.46	)	(6.54	)	(13.65	)	(2.47	)	(16.76	)	(13.62	)

Transportation costs	(4.68	)	(2.13	)	(1.71	)	(1.86	)	(1.94	)	(3.44	)	(1.75	)	(1.76	)

Operating costs	(10.40	)	(13.23	)	(11.28	)	(16.49	)	(10.96	)	(11.78	)	(13.34	)	(13.45	)

Operating netback	11.51		50.08		59.62		56.36		65.87		30.28		57.38		57.79

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

Average price realized	32.63		66.22		82.92		77.15		90.13		49.77		87.68		84.17

Transportation costs	(1.83	)	(2.50	)	(2.23	)	(1.97	)	(2.24	)	(2.17	)	(2.23	)	(2.17	)

Operating costs	(7.01	)	(6.56	)	(8.57	)	(5.29	)	(7.08	)	(6.79	)	(6.05	)	(6.43	)

Operating netback^(A)	23.79		57.16		72.12		69.89		80.81		40.81		79.40		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					Six months ended		Twelve months ended
Refining and Marketing	Jun 30 2020	Mar 31 2020	Dec 31 2019	Sep 30 2019	Jun 30 2019	Jun 30 2020	Jun 30 2019	Dec 31 2019

Refined product sales (mbbls/d)	438.8	531.5	534.6	572.0	508.1	485.1	525.4	539.4

Crude oil processed (mbbls/d)	350.4	439.5	447.5	463.7	399.1	394.9	421.9	438.9

Utilization of refining capacity (%)	76	95	97	100	86	85	91	95

Refining and marketing margin – first-in, first-out (FIFO) ($/bbl)^(A)(H)	20.95	23.35	35.70	35.65	41.30	22.30	45.60	40.45

Refining and marketing margin – last-in, first-out (LIFO) ($/bbl)^(A)(H)	28.55	35.60	36.50	36.10	39.70	32.45	37.40	36.80

Refining operating expense ($/bbl)^(A)	5.80	5.65	5.05	4.90	5.90	5.70	5.75	5.35

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	76.0	112.7	121.6	122.9	114.1	94.3	117.4	119.8

Distillate	84.2	94.8	102.8	107.4	98.2	89.5	100.6	102.9

Total transportation fuel sales	160.2	207.5	224.4	230.3	212.3	183.8	218.0	222.7

Petrochemicals	9.4	9.9	7.9	9.4	12.5	9.6	12.7	10.6

Asphalt	13.4	11.0	17.3	21.6	12.7	12.2	12.6	16.1

Other	23.4	27.8	25.3	21.1	14.6	25.6	21.0	22.1

Total refined product sales	206.4	256.2	274.9	282.4	252.1	231.2	264.3	271.5

Crude oil supply and refining

Processed at refineries (mbbls/d)	169.2	213.1	217.3	209.5	170.0	191.1	193.0	203.3

Utilization of refining capacity (%)	76	96	98	94	77	86	87	92

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	99.6	121.6	125.8	133.9	121.2	110.6	123.6	126.8

Distillate	106.1	133.9	110.9	123.4	107.9	120.0	113.3	115.2

Total transportation fuel sales	205.7	255.5	236.7	257.3	229.1	230.6	236.9	242.0

Asphalt	14.4	8.7	11.4	18.1	11.4	11.6	9.5	12.1

Other	12.3	11.1	11.6	14.2	15.5	11.7	14.7	13.8

Total refined product sales	232.4	275.3	259.7	289.6	256.0	253.9	261.1	267.9

Crude oil supply and refining

Processed at refineries (mbbls/d)	181.2	226.4	230.2	254.2	229.1	203.8	228.9	235.6

Utilization of refining capacity (%)	76	94	96	106	95	85	95	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.


	June 30, 2020						March 31, 2020
For the quarter ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	340		1 312		1 652		538		2 779		3 317

Other (loss) income	(19	)	42		23		26		222		248

Purchases of crude oil and products	(69	)	(22	)	(91	)	(362	)	(45	)	(407	)

Gross realization adjustment⁽²⁾	(34	)	(65	)			126		(273	)

Gross realizations	218		1 267				328		2 683

Royalties	(2	)	(14	)	(16	)	(9	)	(16	)	(25	)

Royalties adjustment⁽³⁾	—		—				3		—

Net royalties	(2	)	(14	)			(6	)	(16	)

Transportation	(73	)	(199	)	(272	)	(86	)	(203	)	(289	)

Transportation adjustment⁽⁴⁾	2		—				3		—

Net transportation	(71	)	(199	)			(83	)	(203	)

Operating, selling and general (OS&G)	(194	)	(1 334	)	(1 528	)	(384	)	(1 868	)	(2 252	)

OS&G adjustment⁽⁵⁾	(28	)	141				130		465

Net operating expenses	(222	)	(1 193	)			(254	)	(1 403	)

Gross (loss) profit	(77	)	(139	)			(15	)	1 061

Sales volumes (mbbls)	10 589		40 326				11 605		46 638

Operating netback per barrel	(7.22	)	(3.45	)			(1.32	)	22.73


	December 31, 2019						September 30, 2019
For the quarter ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	1 242		3 183		4 425		1 257		3 344		4 601

Other income	7		91		98		—		63		63

Purchases of crude oil and products	(337	)	(109	)	(446	)	(259	)	(25	)	(284	)

Gross realization adjustment⁽²⁾	(28	)	(29	)			(7	)	(64	)

Gross realizations	884		3 136				991		3 318

Royalties	(24	)	(119	)	(143	)	(34	)	(201	)	(235	)

Transportation	(112	)	(213	)	(325	)	(118	)	(226	)	(344	)

Transportation adjustment⁽⁴⁾	2		2				2		2

Net transportation	(110	)	(211	)			(116	)	(224	)

OS&G	(335	)	(1 650	)	(1 985	)	(319	)	(1 690	)	(2 009	)

OS&G adjustment⁽⁵⁾	17		336				46		367

Net operating expenses	(318	)	(1 314	)			(273	)	(1 323	)

Gross profit	432		1 492				568		1 570

Sales volumes (mbbls)	20 067		41 174				18 567		44 433

Operating netback per barrel	21.48		36.20				30.52		35.33

(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.


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

Operating revenues	1 441		3 699		5 140

Other (loss) income	(4	)	5		1

Purchases of crude oil and products	(354	)	(50	)	(404	)

Gross realization adjustment⁽²⁾	(44	)	(12	)

Gross realizations	1 039		3 642

Royalties	(41	)	(300	)	(341	)

Transportation	(127	)	(199	)	(326	)

Transportation adjustment⁽⁴⁾	1		3

Net transportation	(126	)	(196	)

OS&G	(317	)	(1 743	)	(2 060	)

OS&G adjustment⁽⁵⁾	42		313

Net operating expenses	(275	)	(1 430	)

Gross profit	597		1 716

Sales volumes (mbbls)	17 932		45 247

Operating netback per barrel	33.28		37.92


	June 30, 2020						June 30, 2019
For the six months ended	Bitumen		SCO and Diesel		Oil Sands Segment		Bitumen		SCO and Diesel		Oil Sands Segment

Operating revenues	878		4 091		4 969		2 281		7 040		9 321

Other income (loss)	7		264		271		(45	)	56		11

Purchases of crude oil and products	(431	)	(67	)	(498	)	(568	)	(109	)	(677	)

Gross realization adjustment⁽²⁾	92		(338	)			21		(126	)

Gross realizations	546		3 950				1 689		6 861

Royalties	(11	)	(30	)	(41	)	(66	)	(473	)	(539	)

Royalties adjustment⁽³⁾	3		—				8		—

Net royalties	(8	)	(30	)			(58	)	(473	)

Transportation	(159	)	(402	)	(561	)	(219	)	(405	)	(624	)

Transportation adjustment⁽⁴⁾	5		—				11		3

Net transportation	(154	)	(402	)			(208	)	(402	)

OS&G	(578	)	(3 202	)	(3 780	)	(588	)	(3 445	)	(4 033	)

OS&G adjustment⁽⁵⁾	102		606				94		652

Net operating expenses	(476	)	(2 596	)			(494	)	(2 793	)

Gross (loss) profit	(92	)	922				929		3 193

Sales volumes (mbbls)	22 194		86 964				29 796		90 887

Operating netback per barrel	(4.13	)	10.59				31.13		35.12

(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⁽³⁾	8		—

Net royalties	(116	)	(793	)

Transportation	(449	)	(844	)	(1 293	)

Transportation adjustment⁽⁴⁾	15		7

Net transportation	(434	)	(837	)

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

OS&G adjustment⁽⁵⁾	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)


	June 30, 2020								March 31, 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	133		160		—		293		282		382		(125	)	539

Royalties	—		(6	)	—		(6	)	—		(22	)	—		(22	)

Transportation	(7	)	(26	)	—		(33	)	(11	)	(12	)	—		(23	)

OS&G	(34	)	(68	)	(9	)	(111	)	(32	)	(85	)	(16	)	(133	)

Non-production costs⁽⁷⁾	5		7						4		12

Gross profit	97		67						243		275

Sales volumes (mboe)	4 086		5 803						4 257		5 501

Operating netback per barrel	23.79		11.51						57.16		50.08


	December 31, 2019								September 30, 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	273		532		193		998		269		393		84		746

Royalties	—		(83	)	(87	)	(170	)	—		(32	)	(65	)	(97	)

Transportation	(7	)	(10	)	(4	)	(21	)	(7	)	(9	)	(3	)	(19	)

OS&G	(32	)	(78	)	(24	)	(134	)	(22	)	(93	)	(14	)	(129	)

Non-production costs⁽⁷⁾	4		8						4		13

Gross profit	238		369						244		272

Sales volumes (mboe)	3 289		6 176						3 488		4 832

Operating netback per barrel	72.12		59.62						69.89		56.36


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

Operating revenues	354		507		133		994

Royalties	—		(75	)	(90	)	(165	)

Transportation	(9	)	(11	)	(1	)	(21	)

OS&G	(32	)	(69	)	(13	)	(114	)

Non-production costs⁽⁷⁾	5		9

Gross profit	318		361

Sales volumes (mboe)	3 923		5 489

Operating netback per barrel	80.81		65.87

(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)


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

Operating revenues	415		542		(125	)	832		714		998		219		1 931

Royalties	—		(28	)	—		(28	)	—		(187	)	(151	)	(338	)

Transportation	(18	)	(38	)	—		(56	)	(18	)	(20	)	(2	)	(40	)

OS&G	(66	)	(153	)	(25	)	(244	)	(58	)	(175	)	(29	)	(262	)

Non-production costs⁽⁷⁾	9		19						9		25

Gross profit	340		342						647		641

Sales volumes (mboe)	8 343		11 304						8 140		11 182

Operating netback per barrel	40.81		30.28						79.40		57.38


	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										Six months ended				Twelve months ended
	Jun 30 2020		Mar 31 2020		Dec 31 2019		Sep 30 2019		Jun 30 2019		Jun 30 2020		Jun 30 2019		Dec 31 2019

Gross margin⁽⁸⁾	1 058		629		1 568		1 653		1 647		1 687		3 787		7 008

Other (loss) income	(26	)	86		33		13		14		60		29		75

Non-refining margin⁽⁹⁾	(312	)	283		(16	)	(17	)	(14	)	(29	)	(27	)	(60	)

Refining and marketing margin^(A)	720		998		1 585		1 649		1 647		1 718		3 789		7 023

Refinery production (mbbls)⁽¹⁰⁾	34 369		42 729		44 422		46 239		39 901		77 098		83 044		173 705

Refining and marketing margin – FIFO ($/bbl)^(A)	20.95		23.35		35.70		35.65		41.30		22.30		45.60		40.45

LIFO adjustment	261		524		37		19		(63	)	785		(684	)	(628	)

Refining and marketing margin – LIFO^(A)	981		1 522		1 622		1 668		1 584		2 503		3 105		6 395

Refining and marketing margin – LIFO ($/bbl)^(A)(I)^(J)	28.55		35.60		36.50		36.10		39.70		32.45		37.40		36.80

OS&G	417		511		576		531		530		928		1 066		2 173

Non-refining costs⁽¹¹⁾	(218	)	(270	)	(352	)	(305	)	(295	)	(488	)	(589	)	(1 246	)

Refining operating expense	199		241		224		226		235		440		477		927

Refinery production (mbbls)⁽¹⁰⁾	34 369		42 729		44 422		46 239		39 901		77 098		83 044		173 705

Refining operating expense ($/bbl)^(A)	5.80		5.65		5.05		4.90		5.90		5.70		5.75		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					Six months ended		Twelve months ended
(average for the three months, six months and twelve months ended)		Jun 30 2020	Mar 31 2020	Dec 31 2019	Sep 30 2019	Jun 30 2019	Jun 30 2020	Jun 30 2019	Dec 31 2019

WTI crude oil at Cushing (US$/bbl)		27.85	46.10	56.95	56.45	59.85	37.00	57.40	57.05

SYN crude oil at Edmonton (US$/bbl)		23.30	43.40	56.25	56.85	60.00	33.35	56.30	56.45

WCS at Hardisty (US$/bbl)		16.35	25.60	41.10	44.20	49.20	21.00	45.85	44.25

New York Harbor 2-1-1 crack (US$/bbl)^(K)		12.20	14.75	18.50	19.75	22.40	13.50	20.75	19.95

Chicago 2-1-1 crack (US$/bbl)^(K)		6.75	9.75	14.45	17.05	21.55	8.25	18.45	17.10

Product value (US$/bbl)

New York Harbor 2-1-1 crack^(L)	40%	16.00	24.35	30.20	30.50	32.90	20.20	31.25	30.80

Chicago 2-1-1 crack^(M)	40%	13.85	22.35	28.55	29.40	32.55	18.10	30.35	29.65

WTI	20%	5.55	9.20	11.40	11.30	11.95	7.40	11.50	11.40

Seasonality factor		5.00	6.50	6.50	5.00	5.00	5.75	5.75	5.75

		40.40	62.40	76.65	76.20	82.40	51.45	78.85	77.60

Crude value (US$/bbl)

SYN	40%	9.30	17.35	22.50	22.75	24.00	13.35	22.50	22.60

WCS	40%	6.55	10.25	16.45	17.70	19.70	8.40	18.35	17.70

WTI	20%	5.55	9.20	11.40	11.30	11.95	7.40	11.50	11.40

		21.40	36.80	50.35	51.75	55.65	29.15	52.35	51.70

Suncor custom 5-2-2-1 index (US$/bbl)		19.00	25.60	26.30	24.45	26.75	22.30	26.50	25.90

Suncor custom 5-2-2-1 index (Cdn$/bbl)^(J)		26.35	34.40	34.70	32.30	35.80	30.45	35.30	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.


	Three months ended June 30		Six months ended June 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)	22.87	90.48	44.53	87.48

E&P International ($/boe)	30.80	87.56	47.60	85.30


(thousands)		June 30, 2020

Common shares		1 525 151

Common share options – exercisable		26 811

Common share options – non-exercisable		12 194


1.	Advisories	9
2.	Second Quarter Highlights	11
3.	Consolidated Financial Information	12
4.	Segment Results and Analysis	18
5.	Capital Investment Update	30
6.	Financial Condition and Liquidity	32
7.	Quarterly Financial Data	36
8.	Other Items	38
9.	Non-GAAP Financial Measures Advisory	39
10.	Common Abbreviations	44
11.	Forward-Looking Information	45


($ millions)	Total

Fair value outstanding at December 31, 2019	(39	)

Cash Settlements – received during the year	(363	)

Changes in fair value recognized in earnings during the year	266

Fair value outstanding at June 30, 2020	(136	)


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

Accounts receivable	74		71		—	145

Accounts payable	(140	)	(141	)	—	(281	)

	(66	)	(70	)	—	(136	)


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

Return on capital employed^(A)

– excluding major projects in progress (%)		(7.9	)		(1.4	)		5.1		9.9		10.6

– including major projects in progress (%)		(7.5	)		(1.3	)		4.9		9.7		10.4


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