Management's Discussion and Analysis for the third quarter ended September 30, 2019

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, 2018, dated February 28, 2019 (the 2018 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2019, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2018 and the 2018 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 28, 2019 (the 2018 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.

References to "we", "our", "Suncor", or "the company" mean Suncor Energy Inc., and the company's subsidiaries and interests in associates and jointly controlled entities, unless the context otherwise requires.

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.

Effective January 1, 2019, the company adopted IFRS 16 Leases (IFRS 16), which replaced the previous leasing standard IAS 17 Leases (IAS 17), and requires the recognition of all leases on the balance sheet, with optional exemptions for short-term leases where the term is twelve months or less and for leases of low value. IFRS 16 effectively removes the classification of leases as either finance or operating leases and treats all leases as finance leases for lessees. The accounting treatment for lessors remains essentially unchanged, with the requirement to classify leases as either finance or operating. Please refer to note 3 in the company's unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2019 for further information. The company has selected the modified retrospective transition approach, electing to adjust opening retained earnings with no re-statement of comparative figures. As such, comparative information continues to be reported under IAS 17 and International Financial Reporting Interpretations Committee (IFRIC) 4.

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 entitlement basis.

Beginning in the first quarter of 2019, results from the company's Energy Trading business have been included within each of the respective operating business segments to which the respective trading activity relates. The Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change.

Also beginning in the first quarter of 2019, the company revised the classification of its capital expenditures into "asset sustainment and maintenance" and "economic investment" to better reflect the types of capital investments being made by the company. There is no impact to overall capital expenditures, and comparative periods have been restated to reflect this change. Refer to the Capital Investment Update section of this MD&A for further details.

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

Certain financial measures in this MD&A – 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 margin, refining operating expense, free funds flow, discretionary free funds flow, and last-in, first-out (LIFO) inventory valuation methodology and related per share 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, refining 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 financial and operational performance is potentially affected by a number of factors, including, but not limited to, the factors described 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 provided to assist readers in understanding the company's future plans and expectations and may not be appropriate for other purposes. 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.

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

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


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Net earnings (loss)

Oil Sands	505		822		2 255		1 322

Exploration and Production	219		222		1 167		922

Refining and Marketing	668		932		2 442		2 392

Corporate and Eliminations	(357	)	(164	)	(630	)	(1 063	)

Total	1 035		1 812		5 234		3 573

Operating earnings (loss)⁽²⁾

Oil Sands	505		762		1 345		1 262

Exploration and Production	171		222		910		789

Refining and Marketing	668		932		2 354		2 392

Corporate and Eliminations	(230	)	(359	)	(1 033	)	(711	)

Total	1 114		1 557		3 576		3 732

Funds from (used in) operations⁽²⁾

Oil Sands	1 606		1 884		4 656		4 357

Exploration and Production	379		443		1 588		1 448

Refining and Marketing	885		1 122		3 070		2 925

Corporate and Eliminations	(195	)	(310	)	(1 049	)	(565	)

Total	2 675		3 139		8 265		8 165

Decrease (increase) in non-cash working capital	461		1 231		(148	)	(625	)

Cash flow provided by operating activities	3 136		4 370		8 117		7 540

Capital and exploration expenditures⁽³⁾

Asset sustainment and maintenance	966		753		2 201		2 693

Economic investment	521		427		1 497		1 438

Total	1 487		1 180		3 698		4 131


	Three months ended September 30		Nine months ended September 30
($ millions)	2019	2018	2019	2018

Discretionary free funds flow⁽²⁾	1 043	1 789	4 050	3 668

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A. Discretionary free funds flow for the three and nine months ended September 30, 2018 have been restated for the impact of the change to the company's classification of asset sustainment and maintenance capital expenditures. Refer to the Capital and Investment Update section of this MD&A for further details.
(3): Excludes capitalized interest of $29 million in the third quarter of 2019 and $26 million in the third quarter of 2018 and reflects the company's revised capital expenditure classification. Refer to the Capital and Investment Update section of this MD&A for further details.


	Three months ended September 30		Nine months ended September 30
	2019	2018	2019	2018

Production volumes by segment

Oil Sands (mbbls/d)	670.0	651.7	673.1	591.0

Exploration and Production (mboe/d)	92.3	92.1	103.6	107.9

Total (mboe/d)	762.3	743.8	776.7	698.9

Refinery utilization (%)	100	99	94	91

Refinery crude oil processed (mbbls/d)	463.7	457.2	436.0	418.3

Suncor's consolidated net earnings for the third quarter of 2019 were $1.035 billion, compared to $1.812 billion for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A.


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Net earnings	1 035		1 812		5 234		3 573

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	127		(195	)	(355	)	352

Impact of income tax rate adjustment on deferred taxes⁽²⁾	—		—		(1 116	)	—

Gain on significant disposal⁽³⁾	(48	)	(60	)	(187	)	(193	)

Operating earnings⁽¹⁾	1 114		1 557		3 576		3 732

(1): Operating 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): 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.
(3): The third quarter of 2019 included an after-tax gain of $48 million in the E&P segment related to the sale of certain non-core assets. In the second quarter of 2019, Suncor sold its 37% interest in Canbriam Energy Inc. (Canbriam) for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows. The equity interest in Canbriam was acquired during the first quarter of 2018 in exchange for the company's mineral landholdings in northeast British Columbia, at which time a gain of $133 million after-tax was recorded on the transaction. The third quarter of 2018 included an after-tax gain of $60 million on the sale of the company's interest in the Joslyn Oil Sands mining project.

Suncor's third quarter 2019 operating earnings were $1.114 billion ($0.72 per common share), compared to $1.557 billion ($0.96 per common share) in the prior year quarter. Highlights of the third quarter included higher overall crude oil production and refinery crude throughput as compared to the prior year quarter. Higher production at Syncrude and the ramp up of Fort Hills and Hebron production over the last year increased crude output during the third quarter of 2019, which was partially offset by planned maintenance, the impact of the Alberta government's mandatory production curtailments and an unplanned outage at Hibernia, which was resolved by the end of the third quarter. In addition, operating earnings were positively impacted by the realization of intersegment profit on inventory transfers, compared to the elimination of intersegment profit in the prior year quarter.

The decrease in operating earnings was primarily related to a weaker business environment, which drove lower overall crude price realizations and lower refining margins, as well as an increase in operating and transportation expenses.


	Three months ended September 30		Nine months ended September 30
($ millions)	2019	2018	2019	2018

Oil Sands	15	8	53	63

Exploration and Production	2	1	6	6

Refining and Marketing	8	4	30	32

Corporate and Eliminations	27	19	107	130

Total share-based compensation expense	52	32	196	231

The after-tax share-based compensation expense increased to $52 million during the third quarter of 2019, compared to an expense of $32 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 September 30

Average for the nine
months ended September 30

2019

2018

2019

2018

WTI crude oil at Cushing

US$/bbl

56.45

69.50

57.05

66.80

Dated Brent crude

US$/bbl

61.90

75.25

64.65

72.15

Dated Brent/Maya FOB price differential

US$/bbl

5.20

10.20

5.45

10.75

MSW at Edmonton

Cdn$/bbl

68.35

82.10

69.60

77.85

WCS at Hardisty

US$/bbl

44.20

47.35

45.30

44.90

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

US$/bbl

(12.25

)

(22.15

)

(11.75

)

(21.90

)

SYN-WTI differential

US$/bbl

0.40

(0.90

)

(0.55

)

(1.00

)

Condensate at Edmonton

US$/bbl

52.00

66.80

52.80

66.30

Natural gas (Alberta spot) at AECO

Cdn$/mcf

0.95

1.20

1.50

1.50

Alberta Power Pool Price

Cdn$/MWh

46.85

54.45

57.55

48.40

New York Harbor 2-1-1 crack⁽¹⁾

US$/bbl

20.45

20.25

20.45

19.20

Chicago 2-1-1 crack⁽¹⁾

US$/bbl

17.05

20.00

17.95

16.75

Portland 2-1-1 crack⁽¹⁾

US$/bbl

23.90

22.05

24.15

23.20

Gulf Coast 2-1-1 crack⁽¹⁾

US$/bbl

20.00

19.35

19.85

18.20

Exchange rate

US$/Cdn$

0.76

0.77

0.75

0.78

Exchange rate (end of period)

US$/Cdn$

0.76

0.77

0.76

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 company previously quoted 3-2-1 crack margin benchmarks based on wider use and familiarity with these benchmarks and, although the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which better reflects the approximate composition of Suncor's overall refined product mix. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

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 third quarter of 2019 for sweet SCO were unfavourably impacted by a decrease in WTI at Cushing to US$56.45/bbl, compared to US$69.50/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 $68.35/bbl compared to $82.10/bbl in the prior year quarter, and prices for WCS at Hardisty decreased to US$44.20/bbl in the third quarter of 2019, from US$47.35/bbl in the prior year quarter, which was less than the decrease in WTI as a result of narrowing heavy crude differentials in part due to mandatory production curtailments in Alberta. Sweet and sour SCO differentials in the third quarter of 2019 were favourable when compared to the third quarter of 2018.

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. Bitumen prices were favourably impacted by narrower heavy crude oil differentials in the third quarter of 2019.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude, which decreased to US$61.90/bbl in the third quarter of 2019, compared to US$75.25/bbl in the prior year quarter.

Suncor's refining margins are primarily influenced by industry benchmark crack spreads and although the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which more appropriately reflects the company's refined product mix of gasoline and distillates. Benchmark crack spreads are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates. More complex refineries can earn greater refining margin by processing less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins at a specific refinery. Crack spreads are based on current crude feedstock prices, whereas actual earnings are based on first-in, first-out (FIFO) inventory accounting where a delay exists between the time that feedstock is purchased and when it is processed and 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. Specific refinery margins are determined by actual crude purchase costs, refinery configuration, production mix and realized prices for refined product sales in markets unique to each refinery.

The cost of natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $0.95/mcf in the third quarter of 2019, from $1.20/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 $46.85/MWh in the third quarter of 2019, compared to $54.45/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 during the third quarter of 2019, as the average exchange rate decreased to US$0.76 per one Canadian dollar from US$0.77 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the third quarter of 2019.

Suncor also has assets and liabilities, including approximately 65% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. A decrease in the value of the Canadian dollar, relative to the U.S. dollar, from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations, while an increase in the value of the Canadian dollar, relative to the U.S. dollar, decreases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Gross revenues	4 601		4 815		13 922		12 594

Less: Royalties	(235	)	(161	)	(774	)	(331	)

Operating revenues, net of royalties	4 366		4 654		13 148		12 263

Net earnings	505		822		2 255		1 322

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

Gain on significant disposal⁽³⁾	—		(60	)	—		(60	)

Operating earnings⁽⁴⁾	505		762		1 345		1 262

Funds from operations⁽⁴⁾	1 606		1 884		4 656		4 357

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): In the second quarter of 2019, the company recorded a $910 million deferred income tax recovery in the Oil Sands segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): The third quarter of 2018 included an after-tax gain of $60 million on the sale of the company's interest in the Joslyn Oil Sands mining project.
(4): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Oil Sands segment had operating earnings of $505 million in the third quarter of 2019, compared to $762 million in the prior year quarter. The decrease was primarily due to lower benchmark crude prices, higher operating, selling and general expenses, and an increase in royalties. The decrease was partially offset by higher overall production volumes due to stronger Syncrude production and the ramp up of Fort Hills production, as well as higher bitumen crude price realizations due to mandatory production curtailments.


	Three months ended September 30				Nine months ended September 30
(mbbls/d)	2019		2018		2019		2018

Upgraded product (SCO and diesel)	325.3		338.5		326.5		291.1

Internally consumed diesel⁽²⁾	(8.3	)	(8.4	)	(8.7	)	(8.4	)

Total Oil Sands operations upgraded product	317.0		330.1		317.8		282.7

In Situ non-upgraded bitumen	105.2		146.0		93.3		130.9

Total Oil Sands operations production	422.2		476.1		411.1		413.6

Fort Hills bitumen	85.5		69.4		84.4		56.9

Internally upgraded bitumen from froth	—		—		—		(1.7	)

Total Fort Hills bitumen production	85.5		69.4		84.4		55.2

Syncrude (sweet SCO and diesel)	164.7		107.6		180.1		124.3

Internally consumed diesel⁽²⁾	(2.4	)	(1.4	)	(2.5	)	(2.1	)

Total Syncrude production	162.3		106.2		177.6		122.2

Total Oil Sands production	670.0		651.7		673.1		591.0

(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 and bitumen froth from Fort Hills can be sent to Oil Sands Base for further processing into SCO. 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): 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. Of the 8,300 bbls/d of internally consumed diesel at Oil Sands operations in the third quarter of 2019, 6,600 bbls/d was consumed at Oil Sands Base and 1,700 bbls/d, net, was consumed at Fort Hills. Oil Sands operations utilization rates are calculated net of Oil Sands Base internally consumed diesel, but inclusive of diesel consumed internally at Fort Hills. Syncrude utilization rates are calculated using intermediate sour production.

Oil Sands operations production decreased to 422,200 bbls/d in the third quarter of 2019, from 476,100 bbls/d in the prior year quarter, primarily due to planned maintenance and mandatory production curtailments in the province of Alberta, which resulted in upgrader utilization declining to 91% in the third quarter of 2019, compared to 95% in the prior year period. The company sought to minimize the impact of mandatory production curtailments by allocating curtailment allotment credits between Oil Sands assets on an opportunistic basis, as well as maximizing the production to the upgrader to produce higher value SCO barrels in the third quarter of 2019, resulting in decreased production of In Situ non-upgraded bitumen. Given our planned maintenance, there was limited availability and opportunity to purchase production quotas from other operators in the quarter.

Fort Hills production, net to Suncor, increased to 85,500 bbls/d of bitumen in the third quarter of 2019, compared to 69,400 bbls/d in the prior year quarter. The increase was due to the successful ramp up of operations throughout 2018, partially offset by the impact of mandatory production curtailments.

Suncor's share of Syncrude production was 162,300 bbls/d in the third quarter of 2019, compared to 106,200 bbls/d in the prior year quarter. The increase in production was primarily due to improved reliability at Syncrude, partially offset by planned maintenance that commenced in the quarter and the impact of mandatory production curtailments. Production in the prior year quarter was impacted by extended planned maintenance and a power disruption that occurred late in the second quarter of 2018.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2019	2018	2019	2018

Oil Sands operations sales volumes

Sweet SCO	116.1	129.5	116.0	91.3

Diesel	20.1	34.7	24.7	29.2

Sour SCO	184.6	162.8	177.3	166.6

Upgraded product	320.8	327.0	318.0	287.1

In Situ non-upgraded bitumen	110.2	131.4	93.0	121.2

Oil Sands operations	431.0	458.4	411.0	408.3

Fort Hills bitumen	91.6	61.6	84.1	44.8

Syncrude	162.3	106.2	177.6	122.2

Total	684.9	626.2	672.7	575.3

Sales volumes for Oil Sands operations were 431,000 bbls/d in the third quarter of 2019, compared to 458,400 bbls/d in the prior year quarter, and were influenced by the same factors influencing production as noted above, partially offset by a draw of crude inventory.

Bitumen sales at Fort Hills increased to 91,600 bbls/d, net to Suncor, in the third quarter of 2019, from 61,600 bbls/d in the prior year quarter, consistent with the increase in production combined with a draw of inventory.


	Three months ended September 30		Nine months ended September 30
	2019	2018	2019	2018

Oil Sands Base

Bitumen production (mbbls/d)	301.0	323.4	289.8	252.2

Bitumen ore mined (thousands of tonnes per day)	460.3	449.6	431.1	366.5

Bitumen ore grade quality (bbls/tonne)	0.65	0.72	0.67	0.69

In Situ

Bitumen production – Firebag (mbbls/d)	194.6	211.0	184.1	206.2

Steam-to-oil ratio – Firebag	2.7	2.7	2.7	2.6

Bitumen production – MacKay River (mbbls/d)	23.1	37.1	31.5	35.6

Steam-to-oil ratio – MacKay River	2.9	2.8	3.0	2.9

Total In Situ bitumen production (mbbls/d)	217.7	248.1	215.6	241.8

Total Oil Sands operations bitumen production (mbbls/d)	518.7	571.5	505.4	494.0

Fort Hills

Bitumen production (mbbls/d)	85.5	69.4	84.4	56.9

Bitumen ore mined (thousands of tonnes per day)	126.1	114.1	134.0	91.2

Bitumen ore grade quality (bbls/tonne)	0.68	0.61	0.63	0.62

Syncrude

Bitumen production (mbbls/d)	194.4	130.9	211.2	148.8

Bitumen ore mined (thousands of tonnes per day)	313.5	213.3	341.9	241.5

Bitumen ore grade quality (bbls/tonne)	0.62	0.61	0.62	0.62

Total Oil Sands bitumen production	798.6	771.8	801.0	699.7

Bitumen production at Oil Sands operations decreased in the third quarter of 2019 to 518,700 bbls/d, compared to 571,500 bbls/d in the prior year quarter. The decrease was primarily due to planned upgrader maintenance and mandatory production curtailments.

Fort Hills bitumen production increased in the third quarter of 2019 to 85,500 bbls/d, net to Suncor, from 69,400 bbls/d in the prior year quarter. The increase was primarily due to a ramp up of production throughout 2018, partially offset by the impact of mandatory production curtailments.

Bitumen production at Syncrude in the third quarter of 2019 increased to 194,400 bbls/d, net to Suncor, from 130,900 bbls/d in the prior year quarter. The increase was primarily due to improved upgrader reliability, partially offset by planned maintenance and the impact of mandatory production curtailments.


Net of transportation costs, but before royalties	Three months ended September 30				Nine months ended September 30
($/bbl)	2019		2018		2019		2018

Oil Sands operations

SCO and diesel	68.11		82.95		69.24		78.06

Bitumen	42.21		36.62		44.59		35.65

Crude sales basket (all products)	61.49		69.67		63.67		65.47

Crude sales basket, relative to WTI	(13.07	)	(20.59	)	(12.15	)	(20.17	)

Fort Hills bitumen	48.50		53.43		51.74		51.44

Syncrude – sweet SCO	74.07		88.80		73.84		83.12

Syncrude, relative to WTI	(0.49	)	(1.46	)	(1.98	)	(2.52	)

Average price realizations at Oil Sands operations decreased to $61.49/bbl in the third quarter of 2019 from $69.67/bbl in the prior year quarter due to a decrease in the WTI benchmark, partially offset by narrower heavy crude oil differentials resulting from mandatory production curtailments in the province of Alberta, strengthening SCO differentials, and the impact of a weaker Canadian dollar.

Average price realizations for Fort Hills bitumen were $48.50/bbl in the third quarter of 2019 and were higher than In Situ bitumen realizations due to a higher proportion of sales being made in the U.S. mid-continent and the U.S. Gulf Coast, where Suncor is able to utilize its logistics network to access favourable pricing in the U.S. market, combined with the higher quality associated with paraffinic froth-treated bitumen produced at Fort Hills. Average price realizations were lower than the prior year quarter due to narrower location differentials in the third quarter of 2019.

Average price realizations at Syncrude decreased to $74.07/bbl in the third quarter of 2019 from $88.80/bbl in the prior year quarter due to the decrease in the WTI benchmark price, partially offset by the impact of a weaker Canadian dollar and narrower SCO differentials. Average Syncrude realizations were lower than the average quarterly benchmark due to a higher proportion of quarterly sales volumes occurring prior to planned maintenance, when the differential was at a discount.

Royalties for the Oil Sands segment were higher in the third quarter of 2019 compared to the prior year quarter, primarily due to higher production at Syncrude.

Oil Sands operating and transportation expenses for the third quarter of 2019 increased when 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.

At Oil Sands operations, operating costs increased as a result of an increase in maintenance, contractor mining, and research and development costs.

At Fort Hills, operating costs in the third quarter of 2019 increased when compared to the prior year quarter primarily due to higher mining costs associated with increased production volumes, partially offset by a decrease in project startup expenses.

Suncor's share of Syncrude operating costs were comparable to the prior year quarter.

Oil Sands transportation costs increased primarily as a result of higher overall production and sales volumes, as compared to the prior year quarter.

DD&A and impairment expenses and exploration expense for the third quarter of 2019 were lower compared to the prior year quarter as the prior year period included a write-down of certain assets no longer being utilized by the company, partially offset by additional depreciation associated with the transition to IFRS 16.


	Three months ended September 30				Nine months ended September 30
($ millions, except as noted)	2019		2018		2019		2018

Oil Sands Operating, selling and general expense (OS&G)	2 009		1 855		6 042		5 579

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	1 156		1 006		3 496		3 133

Non-production costs⁽²⁾	(73	)	(15	)	(168	)	(96	)

Excess power capacity and other⁽³⁾	(64	)	(50	)	(181	)	(157	)

Inventory changes	19		28		16		11

Oil Sands operations cash operating costs⁽¹⁾	1 038		969		3 163		2 891

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	26.60		22.00		28.10		25.50

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	224		214		673		542

Non-production costs⁽²⁾	(23	)	(26	)	(95	)	(96	)

Inventory changes	(10	)	26		5		98

Fort Hills cash operating costs⁽¹⁾	191		214		583		543

Fort Hills cash operating costs ($/bbl)⁽¹⁾	24.25		33.45		25.30		34.90

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	629		635		1 873		1 904

Non-production costs⁽²⁾	(24	)	(11	)	(62	)	(26	)

Syncrude cash operating costs⁽¹⁾	605		624		1 811		1 878

Syncrude cash operating costs ($/bbl)⁽¹⁾	40.50		63.85		37.35		56.25

(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. Non-production costs at Fort Hills also include, but are not limited to, project startup costs, 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.

Oil Sands operations cash operating costs⁽¹⁾ per barrel were $26.60 in the third quarter of 2019, compared to $22.00 in the prior year quarter, primarily as a result of the impact of the mandatory production curtailments and conscious changes in our production mix to maximize value, planned maintenance at Upgrader 2, which commenced late in the third quarter of 2019, and an increase in contractor mining costs. Total Oil Sands operations cash operating costs were $1.038 billion, compared to $969 million in the prior year quarter due to the same factors discussed above.

In the third quarter of 2019, non-production costs, which are excluded from Oil Sands operations cash operating costs, were higher than the prior year quarter, primarily due to an increase in research and development costs.

Fort Hills cash operating costs⁽¹⁾ per barrel averaged $24.25 in the third quarter of 2019, compared to $33.45 in the prior year quarter, reflecting the impact of higher production volumes in the current period and lower cash operating costs.

Syncrude cash operating costs⁽¹⁾ per barrel were $40.50 in the third quarter of 2019, compared to $63.85 in the prior year quarter, with the decrease attributable to the increase in production noted above.

Oil Sands net earnings were $2.255 billion for the first nine months of 2019, compared to $1.322 billion in the prior year period. In addition to the factors explained in operating earnings below, net earnings for the first nine months of 2019 included a one-time deferred income tax recovery of $910 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022. Net earnings for the first nine months of 2018 included an after-tax gain on the sale of the company's interest in the Joslyn Oil Sands mining project of $60 million in the third quarter of 2018.

Oil Sands operating earnings⁽¹⁾ for the first nine months of 2019 were $1.345 billion, compared to $1.262 billion for the same period in 2018. Operating earnings improved as a result of increased production volumes, partially offset by an increase in operating, selling and general expenses, as detailed below. Production improved as a result of the ramp up of Fort Hills operations and higher production at Syncrude, partially offset by the impact of mandatory production curtailments in 2019. Both periods were impacted by planned upgrader maintenance.

Funds from operations⁽¹⁾ for the first nine months of 2019 were $4.656 billion for the Oil Sands segment, compared to $4.357 billion in the prior year period, with the increase primarily due to the same factors that influenced operating earnings noted above.

Oil Sands operations cash operating costs⁽¹⁾ per barrel averaged $28.10 for the first nine months of 2019, an increase from an average of $25.50 for the first nine months of 2018 due to the impact of mandatory production curtailments and conscious changes in our production mix to maximize value, and an increase in operating, selling and general expense related to higher contractor mining, commodity consumption, and maintenance costs.

Fort Hills cash operating costs⁽¹⁾ per barrel averaged $25.30 for the first nine months of 2019, compared to $34.90 for the same period of 2018, reflecting increased production, although production was limited by mandatory production curtailments.

Syncrude cash operating costs⁽¹⁾ per barrel averaged $37.35 for the first nine months of 2019, a decrease compared to $56.25 in the first nine months of 2018, due to an increase in production, although limited by mandatory production curtailments, with the prior year period impacted by a power disruption and extended planned maintenance, as well as a decrease in cash operating costs, which was primarily attributable to lower maintenance costs.

Planned maintenance activity in the fourth quarter of 2019 includes maintenance events at Oil Sands operations Upgrader 2, Fort Hills and Syncrude. Planned maintenance at Fort Hills was completed subsequent to the third quarter. The impact of this maintenance is reflected in the company's 2019 guidance.


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Gross revenues⁽²⁾	681		875		2 461		2 823

Less: Royalties⁽²⁾	(32	)	(91	)	(219	)	(238	)

Operating revenues, net of royalties	649		784		2 242		2 585

Net earnings	219		222		1 167		922

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽³⁾	—		—		(70	)	—

Gain on asset disposal⁽⁴⁾	(48	)	—		(187	)	(133	)

Operating earnings⁽⁵⁾	171		222		910		789

Funds from operations⁽⁵⁾	379		443		1 588		1 448

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): Production, revenues and royalties from the company's Libya operations have been presented in the E&P section of this MD&A on an entitlement basis and exclude an equal and offsetting gross up of revenues and royalties of $65 million in the third quarter of 2019 and $74 million in the third quarter of 2018, which is required for presentation purposes in the company's financial statements under the working-interest basis.
(3): 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.
(4): The third quarter of 2019 included an after-tax gain of $48 million in the E&P segment related to the sale of certain non-core assets. In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.
(5): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings for the E&P segment in the third quarter of 2019 decreased to $171 million, from $222 million in the prior year quarter, primarily as a result of lower crude price realizations and lower U.K. sales volumes, partially offset by lower royalties and financing expense and other. Financing and other expenses in the third quarter of 2019 were lower when compared to the third quarter of 2018, primarily due to a loss related to our equity investment in Canbriam that was recorded in the prior year quarter.


	Three months ended September 30		Nine months ended September 30
	2019	2018	2019	2018

E&P Canada

Terra Nova (mbbls/d)	13.9	8.6	12.8	12.5

Hibernia (mbbls/d)	5.9	17.9	18.4	23.2

White Rose (mbbls/d)	6.2	8.0	3.5	7.6

Hebron (mbbls/d)	23.6	14.4	21.9	12.1

North America Onshore (mboe/d)	—	—	—	0.7

	49.6	48.9	56.6	56.1

E&P International

Buzzard (mboe/d)	29.2	29.6	33.6	36.4

Golden Eagle (mboe/d)	8.7	12.0	9.0	12.9

United Kingdom (mboe/d)	37.9	41.6	42.6	49.3

Norway – Oda (mboe/d)	2.7	—	2.3	—

Libya (mbbls/d)	2.1	1.6	2.1	2.5

	42.7	43.2	47.0	51.8

Total Production (mboe/d)	92.3	92.1	103.6	107.9

Total Sales Volumes (mboe/d)	92.5	96.5	103.4	109.4

Production volumes for E&P Canada were 49,600 boe/d in the third quarter of 2019, compared to 48,900 boe/d in the prior year quarter. The increase in production was primarily due to increased production from Hebron, partially offset by an unplanned outage at Hibernia which was resolved by the end of the third quarter, and the continued staged return of White Rose to normal operating rates.

E&P International production decreased to 42,700 boe/d, from 43,200 boe/d in the prior year quarter, primarily due to natural declines in the U.K., partially offset by increased production from the Oda project offshore Norway, which began production near the end of the first quarter of 2019 and averaged 2,700 boe/d in the third quarter of 2019.

E&P sales volumes decreased to 92,500 boe/d in the third quarter of 2019, compared to 96,500 boe/d in the prior year quarter, due to lift schedules.


	Three months ended September 30		Nine months ended September 30
Net of transportation costs, but before royalties	2019	2018	2019	2018

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	79.39	97.22	85.04	91.28

E&P Canada – Natural gas ($/mcfe)	—	—	—	1.94

E&P International ($/boe)	75.10	92.24	82.17	88.01

Price realizations at both E&P Canada and E&P International in the third quarter of 2019 were lower than the prior year quarter due to the decrease in Brent crude benchmark pricing during the third quarter of 2019, partially offset by the impact of a weaker Canadian dollar on U.S. dollar denominated sales.

E&P royalties in the third quarter of 2019 were lower due to lower royalty rates associated with production mix and lower crude price realizations.

Operating and transportation expenses for the third quarter of 2019 were comparable to the prior year quarter.

DD&A and impairment expense in the third quarter of 2019 was lower when compared to the third quarter of 2018, primarily due to lower U.K. and Hibernia production, partially offset by an increase in Hebron production.

Net earnings for E&P were $1.167 billion for the first nine months of 2019, compared to $922 million in the prior year period. In addition to the factors influencing operating earnings as discussed below, net earnings for the first nine months of 2019 included an after-tax gain of $139 million on the sale of the company's interest in Canbriam 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 and a $48 million after-tax gain on the sale of certain non-core assets during the third quarter of 2019.

Operating earnings for E&P for the first nine months of 2019 were $910 million, compared to $789 million in the first nine months of 2018. The increase was primarily due to the receipt of $264 million, after-tax, for insurance proceeds related to the company's Libyan assets and lower DD&A, partially offset by lower crude price realizations and higher exploration expense. The insurance proceeds received may be subject to provisional repayment that may be dependent on future performance and cash flows from Suncor's Libyan assets.

Funds from operations were $1.588 billion for the first nine months of 2019, compared to $1.448 billion for the first nine months of 2018, due to the same reasons influencing operating earnings noted above, adjusted for the impact of non-cash DD&A expense.

There are no significant maintenance events scheduled for the fourth quarter of 2019.


	Three months ended September 30		Nine months ended September 30
($ millions)	2019	2018	2019		2018

Operating revenues	5 929	6 752	16 759		18 111

Net earnings	668	932	2 442		2 392

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	—	—	(88	)	—

Operating earnings⁽³⁾	668	932	2 354		2 392

Funds from operations⁽³⁾	885	1 122	3 070		2 925

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): In the second quarter of 2019, the company recorded a $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.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings in the third quarter of 2019 were $668 million, compared to $932 million in the prior year quarter. Higher refinery production and increased refined sales volumes were more than offset by lower refining margins, lower marketing margins, and increased DD&A and operating costs.


	Three months ended September 30		Nine months ended September 30
	2019	2018	2019	2018

Crude oil processed (mbbls/d)

Eastern North America	209.5	211.6	198.6	203.8

Western North America	254.2	245.6	237.4	214.5

Total	463.7	457.2	436.0	418.3

Refinery utilization⁽¹⁾ (%)

Eastern North America	94	95	89	92

Western North America	106	102	99	89

Total	100	99	94	91

Refined product sales (mbbls/d)

Gasoline	256.8	261.0	246.3	245.7

Distillate	230.8	217.7	219.6	201.3

Other	84.4	86.8	75.1	79.3

Total	572.0	565.5	541.0	526.3

Refining margin⁽²⁾ ($/bbl)	28.35	34.45	32.60	31.90

Refining operating expense⁽²⁾ ($/bbl)	4.90	5.00	5.45	5.30

(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. Refining margins include the impact of the FIFO method of inventory valuation.

Refinery crude throughput was 463,700 bbls/d in the third quarter of 2019, compared to 457,200 bbls/d in the prior year quarter. Both periods achieved high utilization rates at 100% and 99%, respectively.

Refined product sales increased in the third quarter of 2019 to 572,000 bbls/d, compared to 565,500 bbls/d in the prior year quarter, reflecting record retail sales volumes.

Realized refined product gross margins were lower in the third quarter of 2019, compared to the prior year quarter, and were influenced by the following:

Marketing gross margins in the third quarter of 2019 were lower than in the prior year quarter, primarily due to the impact of continued competitive pricing, partially offset by an increase in Canadian retail volumes.

Operating expenses in the third quarter of 2019 increased compared to the prior year quarter, primarily due to higher refinery maintenance and business development costs.

DD&A increased in the third quarter of 2019 due to the accounting treatment of capital leases under IFRS 16.

Net earnings for R&M were $2.442 billion for the first nine months of 2019, compared to $2.392 billion in the prior year period. In addition to the factors influencing operating earnings explained below, net earnings for the first nine months of 2019 included a one-time deferred income tax recovery of $88 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022.

Operating earnings for R&M in the first nine months of 2019 were $2.354 billion, compared to $2.392 billion in the first nine months of 2018, with the decrease attributable to narrower crude differentials and unfavourable product location differentials, higher operating, selling and general expense and an increase in DD&A, partially offset by a larger FIFO gain in the current period, an increase in refinery crude throughput, and refined product sales volumes. For the first nine months of 2019, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO method, had a positive impact to operating earnings and funds from operations of $477 million after-tax, compared to $181 million after-tax in the first nine months of 2018.

Funds from operations were $3.070 billion in the first nine months of 2019, compared to $2.925 billion in the first nine months of 2018, and increased primarily due to the same factors that influenced operating earnings described above, adjusted for the impact of non-cash DD&A expense.

The company has completed all major planned refinery maintenance for 2019 and there are no major events scheduled for the fourth quarter of 2019.


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Net loss	(357	)	(164	)	(630	)	(1 063	)

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	—		—		(48	)	—

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	127		(195	)	(355	)	352

Operating loss⁽³⁾	(230	)	(359	)	(1 033	)	(711	)

Corporate	*(255*	)	(278	)	*(818*	)	(698	)

Eliminations	25		(81	)	*(215*	)	(13	)

Funds used in operations⁽³⁾	(195	)	(310	)	(1 049	)	(565	)

(1): Beginning in the first quarter of 2019, results from the company's Energy Trading business will be included within each of the respective operating business segments to which the respective trading activity relates. The Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change. The results from the company's Renewable Energy business are included within Corporate results.
(2): 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.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Corporate operating loss was $255 million for the third quarter of 2019, compared to an operating loss of $278 million for the prior year quarter, with the improvement attributable to an operational foreign exchange gain, as compared to an operational foreign exchange loss in the prior year quarter, and lower interest expense, partially offset by an increase in share-based compensation expense. Suncor capitalized $29 million of its borrowing costs in the third quarter of 2019 as part of the cost of major development assets and construction projects in progress, compared to $26 million in the prior year quarter.

Eliminations reflect the deferral or realization of profit on crude oil sales from Oil Sands to Suncor's refineries. Consolidated profits are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the third quarter of 2019, the company realized $25 million of after-tax intersegment profit due to a decrease in the proportion of Oil Sands inventory volumes at the company's refineries, compared to an elimination of $81 million of after-tax intersegment profit in the prior year quarter due to an increase in intersegment inventory volumes.

The net loss for Corporate and Eliminations was $630 million for the first nine months of 2019, compared to $1.063 billion in the prior year period. In addition to the factors influencing operating earnings explained below, net earnings for the first nine months of 2019 included a $355 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt and a one-time deferred income tax recovery of $48 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022. Net earnings in the prior year period included an unrealized after-tax foreign exchange loss of $352 million on the revaluation of U.S. dollar denominated debt.

The operating loss for Corporate and Eliminations for the first nine months of 2019 was $1.033 billion, compared to $711 million in the first nine months of 2018. The increased loss was attributed to a significant elimination of profit held in intercompany inventory, an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year period, the prior period including the receipt of interest income related to a prior period tax settlement, lower capitalized interest and an increase in interest costs associated with IFRS 16, partially offset by lower share-based compensation accruals. The company capitalized $85 million of its borrowing costs in the first nine months of 2019, compared to $128 million in the first nine months of 2018, with the decrease resulting from the staged commissioning of Fort Hills in 2018. The elimination of intercompany profit in inventory was due to an increase in crude margins, partially offset by a decrease in intercompany inventory volumes.

Corporate and Eliminations funds used in operations for the first nine months of 2019 were $1.049 billion, compared to $565 million in the prior year period. In addition to the cash factors influencing operating earnings noted above, funds from operations in the first nine months of 2019 were favourably impacted by a decrease in share-based compensation payments.


	Three months ended September 30				Nine months ended September 30
($ millions)	2019		2018		2019		2018

Oil Sands	1 000		770		2 440		2 883

Exploration and Production	293		245		789		661

Refining and Marketing	202		180		504		667

Corporate and Eliminations	21		11		50		48

Total capital and exploration expenditures	1 516		1 206		3 783		4 259

Less: capitalized interest on debt	(29	)	(26	)	(85	)	(128	)

	1 487		1 180		3 698		4 131

Capital and Exploration Expenditures by Type, excluding capitalized interest⁽¹⁾

Three months ended
September 30, 2019

Nine months ended
September 30, 2019

($ millions)

Asset
Sustainment and
Maintenance(2)

Economic
Investment(3)

Total

Asset
Sustainment and
Maintenance(2)

Economic
Investment(3)

Total

Oil Sands

Oil Sands Base

507

525

1 126

1 183

In Situ

110

125

446

528

Fort Hills

111

265

327

Syncrude

206

227

337

359

Exploration and Production

—

278

278

748

751

Refining and Marketing

134

200

366

133

499

Corporate and Eliminations

966

521

1 487

2 201

1 497

3 698

(1): The classification of the company's capital expenditures has been updated to "asset sustainment and maintenance" and "economic investment" to better reflect the types of capital investments being made by the company.
(2): 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.
(3): Economic investment capital expenditures include capital investments that result in an increase in value through adding reserves, improving processing capacity, utilization, cost or margin, including associated infrastructure.

The company spent $1.487 billion on capital expenditures in the third quarter of 2019, excluding capitalized interest, an increase from $1.180 billion in the prior year quarter, with the increase driven by increased economic investment capital expenditures at In Situ, as well as increased asset sustainment and maintenance capital expenditures related to an increase in planned maintenance activities at Oil Sands Base.

Oil Sands Base capital and exploration expenditures were $525 million in the third quarter of 2019, the majority of which was focused on asset sustainment and maintenance activities related to the company's planned maintenance program, which included the commencement of planned maintenance at Upgrader 2, the continued development of tailings infrastructure, and other reliability and sustainment projects across the operations.

In Situ capital and exploration expenditures were $125 million in the third quarter of 2019 and were primarily directed towards economic investment activities, including well pad construction and drilling activities that are expected to maintain existing production levels at Firebag and MacKay River.

Capital expenditures at Fort Hills were $111 million in the third quarter of 2019, with the majority related to tailings infrastructure projects to sustain operations.

Syncrude capital and exploration expenditures were $227 million in the third quarter of 2019, the majority of which was for asset sustainment and maintenance capital expenditures focused on improving asset reliability.

Capital and exploration expenditures at E&P were $278 million in the third quarter of 2019 and were primarily focused on economic investment projects, including development drilling at Hibernia, Buzzard and Terra Nova, and development work on Fenja and the West White Rose Project.

R&M capital expenditures were $200 million and were primarily related to the ongoing sustainment and enhancement to refinery and retail operations.

Corporate capital expenditures were $21 million, primarily directed towards the company's information technology initiatives.


	Previous leasing	Twelve months ended
	standard September 30 2019	IFRS 16 impact		IFRS 16 September 30 2019	September 30 2018

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress⁽²⁾	10.2	(0.3	)	9.9	10.4

Including major projects in progress	9.9	(0.2	)	9.7	9.7

Net debt to funds from operations⁽³⁾ (times)	1.3	0.2		1.5	1.3

Interest coverage on long-term debt (times)

Earnings basis⁽⁴⁾	6.8	(0.2	)	6.6	8.3

Funds from operations basis⁽³⁾⁽⁵⁾	13.4	(0.5	)	12.9	14.7

Total debt to total debt plus shareholders' equity (%)	26.0	2.1		28.1	26.7

(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 8.0% in the third quarter of 2019 excluding the $1.116 billion deferred tax recovery for the Alberta corporate income tax rate change, which the company recorded in the second quarter of 2019.
(3): 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.
(4): Equal to net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(5): Equal to funds from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

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 2019 capital spending program of $4.9 to $5.4 billion and to meet current and future working capital requirements, through cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

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

For the three months ended September 30, 2019, cash and cash equivalents increased to $2.089 billion, from $2.061 billion at June 30, 2019, due to cash flow provided by operating activities exceeding the company's capital and exploration expenditures, dividend requirements, the repurchase of $756 million of Suncor's own shares under its NCIB, and a net decrease of short-term debt of $572 million.

For the nine months ended September 30, 2019, cash and cash equivalents decreased to $2.089 billion, from $2.221 billion at December 31, 2018, with uses of cash in respect of the company's capital and exploration expenditures, dividend requirements, the repurchase of $1.822 billion of Suncor's own shares under its NCIB, and a net decrease of short-term and long-term debt of $970 million, marginally exceeding cash flow provided by operating activities.

As at September 30, 2019, the weighted average term to maturity of the company's short-term investment portfolio was approximately 16 days.

Available credit facilities for liquidity purposes at September 30, 2019 increased to $5.282 billion, compared to $3.608 billion at December 31, 2018, primarily as a result of a significant reduction in short-term indebtedness noted above.

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans and future expected volatility in the pricing 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.

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an "event of default" as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders' equity. At September 30, 2019, total debt to total debt plus shareholders' equity was 28.1% (December 31, 2018 – 28.3%) and now reflects the impact of additional lease liabilities of $1.792 billion recorded on January 1, 2019 as part of the adoption of IFRS 16. The company continues to be in compliance with all operating covenants.


($ millions, except as noted)	September 30 2019	December 31 2018(1)

Short-term debt	1 643	3 231

Current portion of long-term debt	—	191

Current portion of long-term lease liabilities	297	38

Long-term debt	13 098	12 668

Long-term lease liabilities	2 652	1 222

Total debt	17 690	17 350

Less: Cash and cash equivalents	2 089	2 221

Net debt	15 601	15 129

Shareholders' equity	45 184	44 005

Total debt plus shareholders' equity	62 874	61 355

Total debt to total debt plus shareholders' equity (%)	28.1	28.3

(1): Excludes the impact of IFRS 16, which was prospectively adopted on January 1, 2019 in accordance with the standard.


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

Total debt – beginning of period	18 182		17 350

Increase in long-term debt	—		557

Decrease in short-term debt	(572	)	(1 527	)

January 1, 2019 increase in lease liabilities associated with IFRS 16	—		1 792

Increase in lease liability	31		123

Lease payments	(88	)	(230	)

Foreign exchange on debt, and other	137		(375	)

Total debt – September 30, 2019	17 690		17 690

Less: Cash and cash equivalents – September 30, 2019	2 089		2 089

Net debt – September 30, 2019	15 601		15 601

The company's total debt decreased in the third quarter of 2019 due to a significant reduction of short-term indebtedness and lease principal payments made during the third quarter of 2019, partially offset by unfavourable foreign exchange rates on U.S. dollar denominated debt compared to June 30, 2019 and leases entered into during the period.

On a year-to-date basis, the company's total debt increased in 2019 due primarily to the impact of the adoption of IFRS 16, which added $1.792 billion in lease liability to the company's balance sheet, a net increase in long-term debt and leases entered into during the first nine months of 2019, partially offset by the repayment of $1.527 billion of short-term debt, favourable foreign exchange rates on U.S. dollar denominated debt, as compared to December 31, 2018, and lease principal payments made during the first nine months of 2019.

As at October 28, 2019, the total number of common shares outstanding was 1,537,072,943 and the total number of exercisable and non-exercisable common share options outstanding was 34,789,633. Once exercisable, each outstanding common share option is convertible into one common share.

Under the company's NCIB that commenced in the second quarter of 2019, Suncor may repurchase up to 50,252,231 common shares through the facilities of the Toronto Stock Exchange, the New York Stock Exchange and/or alternative trading platforms between May 6, 2019 and May 5, 2020. Under the company's NCIB, 29,266,840 common shares have been purchased to date, 1.9% of the total outstanding common shares.

During the third quarter of 2019, Suncor repurchased and cancelled 19,206,250 common shares, representing 1.2% of the total outstanding common shares, at an average price of $39.38 per common share, for a total of $756 million, compared to the prior year quarter when the company repurchased and cancelled 16,841,078 common shares at an average price of $52.77 per common share, for a total of $889 million.

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 2018 annual MD&A with no significant updates to note during the first nine months of 2019. 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.

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 Government of Alberta's mandatory production curtailments implemented in the first nine months of 2019.


Three months ended ($ millions, unless otherwise noted)	Sept 30 2019		June 30 2019	Mar 31 2019	Dec 31 2018		Sept 30 2018	June 30 2018		Mar 31 2018		Dec 31 2017

Total production (mboe/d)

Oil Sands	670.0		692.2	657.2	740.8		651.7	547.6		571.7		621.2

Exploration and Production	92.3		111.7	107.1	90.2		92.1	114.1		117.7		115.2

	762.3		803.9	764.3	831.0		743.8	661.7		689.4		736.4

Revenues and other income

Operating revenues, net of royalties	9 803		10 071	8 983	8 561		10 847	10 327		8 807		9 000

Other income (loss)	93		27	414	384		16	101		(57	)	41

	9 896		10 098	9 397	8 945		10 863	10 428		8 750		9 041

Net earnings (loss)	1 035		2 729	1 470	(280	)	1 812	972		789		1 382

per common share – basic (dollars)	0.67		1.74	0.93	(0.18	)	1.12	0.60		0.48		0.84

per common share – diluted (dollars)	0.67		1.74	0.93	(0.18	)	1.11	0.59		0.48		0.84

Operating earnings⁽¹⁾	1 114		1 253	1 209	580		1 557	1 190		985		1 310

per common share – basic⁽¹⁾ (dollars)	0.72		0.80	0.77	0.36		0.96	0.73		0.60		0.79

Funds from operations⁽¹⁾	2 675		3 005	2 585	2 007		3 139	2 862		2 164		3 016

per common share – basic⁽¹⁾ (dollars)	1.72		1.92	1.64	1.26		1.94	1.75		1.32		1.83

Cash flow provided by operating activities	3 136		3 433	1 548	3 040		4 370	2 446		724		2 755

per common share – basic (dollars)	2.02		2.19	0.98	1.90		2.70	1.50		0.44		1.67

ROCE⁽¹⁾ (%) for the twelve months ended	9.7		10.4	8.2	8.0		9.7	8.3		6.5		6.7

ROCE⁽¹⁾, excluding major projects in progress (%) for twelve months ended	9.9		10.6	8.3	8.2		10.4	9.5		7.8		8.6

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(127	)	221	261	(637	)	195	(218	)	(329	)	(91	)

Common share information (dollars)

Dividend per common share	0.42		0.42	0.42	0.36		0.36	0.36		0.36		0.32

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	41.79		40.85	43.31	38.13		49.98	53.50		44.49		46.15

New York Stock Exchange (US$)	31.58		31.16	32.43	27.97		38.69	40.68		34.54		36.72

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.


(average for the three months ended)		Sept 30 2019		June 30 2019		Mar 31 2019		Dec 31 2018		Sept 30 2018		June 30 2018		Mar 31 2018		Dec 31 2017

WTI crude oil at Cushing	US$/bbl	56.45		59.85		54.90		58.85		69.50		67.90		62.90		55.40

Dated Brent crude	US$/bbl	61.90		68.85		63.20		67.80		75.25		74.40		66.80		61.40

Dated Brent/Maya FOB price differential	US$/bbl	5.20		6.90		5.00		4.35		10.20		12.40		7.70		9.60

MSW at Edmonton	Cdn$/bbl	68.35		73.40		66.45		42.70		82.10		80.95		72.45		69.30

WCS at Hardisty	US$/bbl	44.20		49.20		42.50		19.50		47.35		48.65		38.60		43.10

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(12.25	)	(10.65	)	(12.40	)	(39.35	)	(22.15	)	(19.25	)	(24.30	)	(12.30	)

SYN-WTI differential	US$/bbl	0.40		0.15		(2.30	)	(21.60	)	(0.90	)	(0.65	)	(1.45	)	3.25

Condensate at Edmonton	US$/bbl	52.00		55.90		50.55		45.30		66.80		68.50		63.15		57.95

Natural gas (Alberta spot) at AECO	Cdn$/mcf	0.95		1.05		2.55		1.60		1.20		1.20		1.75		1.70

Alberta Power Pool Price	Cdn$/MWh	46.85		56.35		70.75		55.55		54.45		56.00		34.95		22.35

New York Harbor 2-1-1 crack⁽¹⁾	US$/bbl	20.45		22.20		18.25		19.15		20.25		21.10		16.70		20.50

Chicago 2-1-1 crack⁽¹⁾	US$/bbl	17.05		21.45		15.35		16.35		20.00		19.05		14.25		21.40

Portland 2-1-1 crack⁽¹⁾	US$/bbl	23.90		26.85		19.35		22.25		22.05		28.65		21.00		23.55

Gulf Coast 2-1-1 crack⁽¹⁾	US$/bbl	20.00		21.70		17.85		17.65		19.35		20.45		16.30		19.10

Exchange rate	US$/Cdn$	0.76		0.75		0.75		0.76		0.77		0.77		0.79		0.79

Exchange rate (end of period)	US$/Cdn$	0.76		0.76		0.75		0.73		0.77		0.76		0.78		0.80

(1): 2-1-1 crack spreads are indicators of the refining margin generated by converting two barrels of WTI into one barrel of gasoline and one barrel of diesel. The company previously quoted 3-2-1 crack margin benchmarks based on wider use and familiarity with these benchmarks and though the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which better reflects the approximate composition of Suncor's overall refined product mix. 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 2018 annual MD&A and in note 3 of Suncor's unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2019.

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, 2018 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2018 annual MD&A.

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 25 of the audited Consolidated Financial Statements for the year ended December 31, 2018, note 10 to the unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2019, and the Financial Condition and Liquidity section of the 2018 annual MD&A.

Based on their evaluation as at September 30, 2019, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at September 30, 2019, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three-month period ended September 30, 2019 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 updated its previously issued 2019 corporate guidance, as set forth in Suncor's press release dated October 30, 2019, which is 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, Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense, LIFO inventory valuation methodology and related per share 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 from the comparative period through key variance factors. These factors are analyzed in the Operating Earnings 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 performance of operating assets.


For the twelve months ended September 30 ($ millions, except as noted)		2019	2018

Adjustments to net earnings

Net earnings		4 954	4 955

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		282	443

Net interest expense		625	445

	A	5 861	5 843

Capital employed – beginning of twelve-month period

Net debt		14 345	13 090

Shareholders' equity		45 800	45 378

		60 145	58 468

Capital employed – end of twelve-month period

Net debt		15 601	14 345

Shareholders' equity		45 184	45 800

		60 785	60 145

Average capital employed	B	60 729	60 146

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

Average capitalized costs related to major projects in progress	C	1 774	4 150

ROCE – excluding major projects in progress (%)	A/(B-C)	9.9	10.4

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 operating activities measure in the Non-GAAP Financial Measures Advisory section of each respective management's discussion and analysis or quarterly report to shareholders, as applicable, for the related quarter.


Three months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2019		2018		2019		2018		2019		2018		2019		2018		2019		2018

Net earnings (loss)	505		822		219		222		668		932		(357	)	(164	)	1 035		1 812

Adjustments for:

Depreciation, depletion, amortization and impairment	1 036		1 077		220		240		209		172		19		15		1 484		1 504

Deferred income taxes	62		121		19		(30	)	19		42		(19	)	27		81		160

Accretion	54		52		11		12		1		1		—		2		66		67

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		133		(216	)	133		(216	)

Change in fair value of financial instruments and trading inventory	(3	)	10		(4	)	(16	)	(21	)	13		—		—		(28	)	7

Gain on disposal of assets	(3	)	(106	)	(77	)	—		(1	)	(1	)	—		—		(81	)	(107	)

Share-based compensation	19		6		2		2		11		7		34		23		66		38

Exploration	—		—		—		—		—		—		—		—		—		—

Settlement of decommissioning and restoration liabilities	(105	)	(99	)	(11	)	1		(7	)	(7	)	—		(1	)	(123	)	(106	)

Other	41		1		—		12		6		(37	)	(5	)	4		42		(20	)

Funds from (used in) operations	1 606		1 884		379		443		885		1 122		(195	)	(310	)	2 675		3 139

Decrease in non-cash working capital																	461		1 231

Cash flow provided by operating activities																	3 136		4 370

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.


Nine months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2019		2018		2019		2018		2019		2018		2019		2018		2019		2018

Net earnings (loss)	2 255		1 322		1 167		922		2 442		2 392		(630	)	(1 063	)	5 234		3 573

Adjustments for:

Depreciation, depletion, amortization and impairment	3 088		3 005		702		768		612		500		57		46		4 459		4 319

Deferred income taxes	(675	)	262		(103	)	(115	)	(42	)	91		(96	)	42		(916	)	280

Accretion	167		156		33		36		5		5		—		2		205		199

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(378	)	402		(378	)	402

Change in fair value of financial instruments and trading inventory	41		25		3		(52	)	76		(5	)	—		1		120		(31	)

Gain on disposal of assets	(13	)	(107	)	(228	)	(162	)	(3	)	(5	)	—		—		(244	)	(274	)

Share-based compensation	(6	)	(6	)	(2	)	(2	)	(8	)	(9	)	(3	)	(12	)	(19	)	(29	)

Exploration	—		—		39		—		—		—		—		—		39		—

Settlement of decommissioning and restoration liabilities	(285	)	(337	)	(16	)	(15	)	(12	)	(12	)	—		(1	)	(313	)	(365	)

Other	84		37		(7	)	68		—		(32	)	1		18		78		91

Funds from (used in) operations	4 656		4 357		1 588		1 448		3 070		2 925		(1 049	)	(565	)	8 265		8 165

Increase in non-cash working capital																	(148	)	(625	)

Cash flow provided by operating activities																	8 117		7 540

(1): The three and nine months ended September 30, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trading activity relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.

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 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 reflects cash available for increasing distributions to shareholders and to fund growth investments. Management uses free funds flow and discretionary free funds flow to measure the capacity of the company to increase returns to shareholders and to grow Suncor's business.


	Three months ended Sept 30				Nine months ended Sept 30
($ millions)	2019		2018		2019		2018

Funds from operations	2 675		3 139		8 265		8 165

Asset sustainment and maintenance capital and dividends⁽¹⁾	(1 632	)	(1 350	)	(4 215	)	(4 497	)

Discretionary free funds flow	1 043		1 789		4 050		3 668

(1): The classification of the company's capital expenditures has been updated to "asset sustainment and maintenance" to better reflect the types of capital investments being made by the company. Comparative periods have been updated to reflect this change.

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, 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, such that the company is able to present cost information based on production volumes. 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, 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 margin and refining operating expense are non-GAAP financial measures. Refining 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 risk management 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 margin and refining operating expense to measure operating performance on a production barrel basis.


	Three months ended September 30				Nine months ended September 30
($ millions, except as noted)	2019		2018		2019		2018

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 653		1 987		5 440		5 411

Other income (loss)	13		10		42		(22	)

Non-refining margin	(353	)	(431	)	(1 266	)	(1 466	)

Refining margin	1 313		1 566		4 216		3 923

Refinery production⁽¹⁾ (mbbls)	46 239		45 465		129 283		122 993

Refining margin ($/bbl)	28.35		34.45		32.60		31.90

Refining operating expense reconciliation

Operating, selling and general expense	531		519		1 597		1 505

Non-refining costs	(305	)	(292	)	(894	)	(854	)

Refining operating expense	226		227		703		651

Refinery production⁽¹⁾ (mbbls)	46 239		45 465		129 283		122 993

Refining operating expense ($/bbl)	4.90		5.00		5.45		5.30

(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.

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

GAAP requires the use of a FIFO inventory valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflects market conditions at the time 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
		Q3	Three months ended September 30
GJ	Gigajoule	DD&A	Depreciation, depletion and amortization
		WTI	West Texas Intermediate
mcf	thousands of cubic feet of natural gas	WCS	Western Canadian Select
mcfe	thousands of cubic feet of natural gas equivalent	SCO	Synthetic crude oil
mmcf	millions of cubic feet of natural gas	SYN	Synthetic crude oil benchmark
mmcf/d	millions of cubic feet of natural gas per day	MSW	Mixed Sweet Blend
mmcfe	millions of cubic feet of natural gas equivalent	NYMEX	New York Mercantile Exchange
mmcfe/d	millions of cubic feet of natural gas equivalent per day	YTD	Year to date
MW	megawatts
MWh	megawatts per hour

The 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 and resources estimates; commodity prices and interest and foreign exchange rates; the performance of assets and equipment; capital efficiencies and cost-savings; applicable laws and government policies; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour, services and infrastructure; the satisfaction by third parties of their obligations to Suncor; the development and execution of projects; and the receipt, in a timely manner, of regulatory and third-party approvals. All statements and information that address expectations or projections about the future, and 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 the 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; 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 risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset or oil and gas property, including estimates of the final consideration to be paid or received; the ability of counterparties to comply with their obligations in a timely manner; risks associated with joint arrangements in which the company has an interest; risks associated with land claims and 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 2018 annual MD&A, the 2018 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.


(thousands)		September 30, 2019

Common shares		1 542 063

Common share options – exercisable		22 463

Common share options – non-exercisable		12 376


	Three months ended September 30		Nine months ended September 30
($ millions, except as noted)	2019	2018	2019	2018

Share repurchase activities (thousands of common shares)	19 206	16 841	44 158	37 700

Weighted average repurchase price per share (dollars per share)	39.38	52.77	41.26	50.05

Share repurchase cost	756	889	1 822	1 887


1.	Advisories	6
2.	Third Quarter Highlights	8
3.	Consolidated Financial Information	9
4.	Segment Results and Analysis	14
5.	Capital Investment Update	27
6.	Financial Condition and Liquidity	29
7.	Quarterly Financial Data	33
8.	Other Items	35
9.	Non-GAAP Financial Measures Advisory	36
10.	Common Abbreviations	41
11.	Forward-Looking Information	42