Management's Discussion and Analysis for the third quarter ended September 30, 2017

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 and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts. We also operate a renewable energy business as part of our overall portfolio of assets.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2016, dated March 1, 2017 (the 2016 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-month and nine-month periods ended September 30, 2017, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2016 and the 2016 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 March 1, 2017 (the 2016 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

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, which is within the framework of International Financial Reporting Standards (IFRS).

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. Certain prior year amounts in the Consolidated Statements of Comprehensive Income (Loss) have been reclassified to conform to the current year's presentation.

References to Oil Sands operations exclude Suncor's interest in Syncrude operations.

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, Syncrude cash operating costs, refining margin, refining operating expense, discretionary free cash flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings (loss), Oil Sands operations 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 GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Funds from (used in) operations, ROCE, discretionary free cash flow, refining margin and refining operating expense are defined and reconciled to 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.

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)	2017		2016		2017		2016

Net earnings (loss)

Oil Sands	314		162		339		(1 425	)

Exploration and Production	161		144		515		136

Refining and Marketing	597		436		1 772		1 366

Corporate, Energy Trading and Eliminations	217		(350	)	450		(163	)

Total	1 289		392		3 076		(86	)

Operating earnings (loss)⁽¹⁾

Oil Sands	314		162		339		(1 425	)

Exploration and Production	161		(36	)	515		(44	)

Refining and Marketing	597		436		1 418		1 366

Corporate, Energy Trading and Eliminations	(205	)	(216	)	(394	)	(616	)

Total	867		346		1 878		(719	)

Funds from (used in) operations⁽¹⁾

Oil Sands	1 276		1 236		2 958		1 297

Exploration and Production	375		365		1 294		928

Refining and Marketing	827		595		1 906		1 884

Corporate, Energy Trading and Eliminations	(6	)	(171	)	(35	)	(486	)

Total	2 472		2 025		6 123		3 623

Capital and Exploration Expenditures⁽²⁾

Sustaining	816		555		2 109		1 778

Growth	697		985		2 269		2 798

Total	1 513		1 540		4 378		4 576


	Three months ended September 30		Nine months ended September 30
	2017	2016	2017	2016

Production volumes by segment

Oil Sands (mbbls/d)	628.4	617.5	544.3	466.0

Exploration and Production (mboe/d)	111.5	110.6	123.8	118.2

Total (mboe/d)	739.9	728.1	668.1	584.2

Production mix

Crude oil and liquids / natural gas (%)	100/0	99/1	99/1	99/1

Refinery utilization (%)	101	101	96	93

Refinery crude oil processed (mbbls/d)	466.8	465.6	444.2	429.0

Suncor's consolidated net earnings for the third quarter of 2017 were $1.289 billion, compared to net earnings of $392 million 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. Other items affecting net earnings over these periods included:


	Three months ended September 30				Nine months ended September 30
($ millions)	2017		2016		2017		2016

Net earnings (loss)	1,289		392		3 076		(86	)

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(412	)	112		(793	)	(746	)

Non-cash mark to market (gain) loss on interest rate swaps and foreign currency derivatives⁽²⁾	(10	)	22		22		182

Impact of income tax rate adjustment on deferred taxes⁽³⁾	—		(180	)	—		(180	)

Loss on early payment of long-term debt⁽⁴⁾	—		—		10		73

Gain on significant disposals⁽⁵⁾	—		—		(437	)	—

COS acquisition and integration costs⁽⁶⁾	—		—		—		38

Operating earnings (loss)⁽¹⁾	867		346		1 878		(719	)

(1): Operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash mark to market (gain) loss on forward interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates in the Corporate segment.
(3): The three- and nine-month periods ended September 30, 2016 were impacted by an adjustment to the company's deferred income taxes resulting from a decrease from 50% to 40% in the U.K. tax rate on oil and gas profits from the North Sea.
(4): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains, in the Corporate segment.
(5): Gain of $354 million related to the sale of the company's lubricants business in the R&M segment, combined with a gain of $83 million related to the sale of the company's interest in the Cedar Point wind facility in the Corporate segment.
(6): Transaction and related charges associated with the acquisition of COS in the Corporate segment.

Suncor's consolidated operating earnings for the third quarter of 2017 were $867 million, compared to $346 million in the prior year quarter, with the increase attributed to improved benchmark crack spreads and crude oil pricing, lower exploration expense, with the prior year quarter including a charge for a non-commercial well off the east coast of Canada, record refinery throughput and retail and wholesale sales volumes in Canada and also record Oil Sands operations production, partially offset by a stronger Canadian dollar, increased maintenance expense at Syncrude and higher planned maintenance expense and increased costs associated with improved production at Oil Sands operations.

Suncor's consolidated operating earnings were $1.878 billion for the first nine months of 2017, compared to an operating loss of $719 million in the prior year period. The increase was attributable to improved crude price realizations and benchmark crack spreads, higher upstream production and improved refinery crude throughput, partially offset by the impact of the disposal of the company's lubricants business and higher operating expenses.


	Three months ended September 30		Nine months ended September 30
($ millions)	2017	2016	2017	2016

Oil Sands	31	15	52	48

Exploration and Production	4	1	7	4

Refining and Marketing	15	8	27	30

Corporate, Energy Trading and Eliminations	53	27	108	100

Total share-based compensation expense	103	51	194	182

The after-tax share-based compensation expense increased to $103 million during the third quarter of 2017, compared to $51 million during the prior year quarter, as a result of a greater share price increase during the current period when compared to the share price increase in the prior year quarter.

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

Average for the
Three months ended
September 30

Average for the
Nine months ended
September 30

2017

2016

2017

2016

WTI crude oil at Cushing

US$/bbl

48.20

44.95

49.45

41.35

Dated Brent crude

US$/bbl

52.05

45.85

51.90

41.80

Dated Brent/Maya crude oil FOB price differential

US$/bbl

6.30

6.80

7.05

7.50

MSW at Edmonton

Cdn$/bbl

57.05

55.10

61.20

50.90

WCS at Hardisty

US$/bbl

38.25

31.45

37.60

27.70

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

US$/bbl

9.95

13.50

11.90

13.65

Condensate at Edmonton

US$/bbl

47.60

43.05

49.45

40.55

Natural gas (Alberta spot) at AECO

Cdn$/mcf

1.45

2.30

2.30

1.85

Alberta Power Pool Price

Cdn$/MWh

24.55

17.90

22.05

17.00

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

22.35

14.00

17.05

13.95

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

19.25

14.15

14.90

13.30

Portland 3-2-1 crack⁽¹⁾

US$/bbl

26.80

18.75

22.15

17.00

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

21.45

14.50

17.40

12.50

Exchange rate

US$/Cdn$

0.80

0.77

0.77

0.76

Exchange rate (end of period)

US$/Cdn$

0.80

0.76

0.80

0.76

(1): 3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

Suncor's 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. Price realizations in the third quarter of 2017 for sweet SCO were positively impacted by a higher WTI price of US$48.20/bbl, compared to US$44.95/bbl in the prior year quarter, as well as a favourable differential for SCO relative to WTI. Suncor also produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $57.05/bbl compared to $55.10/bbl in the prior year quarter and prices for WCS at Hardisty increased to US$38.25/bbl from US$31.45/bbl in the third quarter of 2016.

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.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing increased to an average of US$52.05/bbl in the third quarter of 2017, compared to US$45.85/bbl in the prior year quarter.

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 $1.45/mcf in the third quarter of 2017, from $2.30/mcf in the prior year quarter.

Suncor's refining margins are influenced primarily by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour crude differentials. More complex refineries can earn greater refining margins by processing less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins of a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual refining margins are based on 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 further impacted by actual crude purchase costs, refinery configuration, production mix and realized prices for refined products sales in markets unique to each refinery.

Excess electricity produced in Suncor's Oil Sands operations business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the Oil Sands operations cash operating cost per barrel metric. The Alberta power pool price increased to an average of $24.55/MWh in the third quarter of 2017, compared to $17.90/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. The majority of Suncor's expenditures are realized in Canadian dollars. In the third quarter of 2017, the Canadian dollar strengthened in relation to the U.S. dollar as the average exchange rate increased to US$0.80 per one Canadian dollar from US$0.77 per one Canadian dollar in the prior year quarter. This rate increase had a negative impact on price realizations for the company during the third quarter of 2017 when compared to the prior year quarter.

Suncor also has assets and liabilities, notably approximately 75% 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. An increase in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date 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)	2017		2016		2017		2016

Gross revenues	3 233		2 967		9 021		6 166

Less: Royalties	(82	)	(20	)	(180	)	(48	)

Operating revenues, net of royalties	3 151		2 947		8 841		6 118

Net earnings (loss)	314		162		339		(1 425	)

Operating earnings (loss)⁽¹⁾	314		162		339		(1 425	)

Oil Sands operations	*265*		(13	)	*595*		(1 327	)

Oil Sands ventures	49		175		*(256*	)	(98	)

Funds from operations⁽¹⁾	1 276		1 236		2 958		1 297

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

Operating earnings for Oil Sands operations were $265 million in the third quarter of 2017, compared to an operating loss of $13 million in the prior year quarter. The improvement was due to higher crude price realizations, increased crude oil production, with a new quarterly record achieved in the period, and lower DD&A, partially offset by the impact of a stronger Canadian dollar, higher planned maintenance expense and increased costs associated with improved production.

Operating earnings for Oil Sands ventures were $49 million in the third quarter of 2017, compared to operating earnings of $175 million in the prior year quarter. The decrease was a result of lower crude oil production, increased maintenance expense, the impact of a stronger Canadian dollar and higher royalties, partially offset by improved benchmark crude pricing.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2017	2016	2017	2016

Upgraded product (SCO and diesel)	324.4	301.1	315.3	236.8

Non-upgraded bitumen	144.9	132.6	108.2	118.2

Oil Sands operations	469.3	433.7	423.5	355.0

Oil Sands ventures – Syncrude	159.1	183.8	120.8	111.0

Total	628.4	617.5	544.3	466.0

(1): Bitumen production from Oil Sands Base operations is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries. Yields of SCO and diesel from Suncor's upgrading process are approximately 79% of bitumen feedstock input. All of the bitumen produced at Syncrude is upgraded to sweet SCO.

Oil Sands operations production was 469,300 bbls/d in the third quarter of 2017, compared to 433,700 bbls/d in the prior year quarter, with the increase driven by strong upgrader reliability and increased Firebag production. Both periods included planned upgrader maintenance, with production in the prior year period also being impacted by unplanned upgrader maintenance. Upgrader utilization at Oil Sands operations was 93% in the third quarter of 2017, compared to 86% in the prior year quarter.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2017	2016	2017	2016

Oil Sands operations sales volumes

Sweet SCO	105.9	100.8	111.7	87.4

Diesel	30.4	27.9	30.1	18.7

Sour SCO	183.2	162.5	173.2	137.2

Upgraded product	319.5	291.2	315.0	243.3

Non-upgraded bitumen	120.3	123.5	103.8	122.1

Oil Sands operations	439.8	414.7	418.8	365.4

Oil Sands ventures – Syncrude	159.1	183.8	120.8	111.0

Total	598.9	598.5	539.6	476.4

Sales volumes for Oil Sands operations increased to 439,800 bbls/d in the third quarter of 2017 from 414,700 bbls/d in the prior year quarter due to the same factors as the increase in production.

Suncor's share of Syncrude production was 159,100 bbls/d in the third quarter of 2017, compared to 183,800 bbls/d in the prior year quarter. The decrease was attributed to the outage associated with the facility incident from the first quarter of 2017 and planned coker maintenance, which both impacted the early part of the quarter. Syncrude upgrader reliability was 84% in the third quarter of 2017, compared to 95% in the prior year quarter. Following the facility repairs from the incident and completion of planned maintenance in the period, Syncrude's upgrader utilization was approximately 100%.

The overall sales mix was unfavourably impacted by the decrease in Syncrude sweet SCO, which was only partially offset by the increase in sour SCO from Oil Sands operations.


	Three months ended September 30		Nine months ended September 30
	2017	2016	2017	2016

Oil Sands Base

Bitumen production (mbbls/d)	328.1	295.1	308.3	222.3

Bitumen ore mined (thousands of tonnes per day)	490.0	433.2	469.3	328.6

Bitumen ore grade quality (bbls/tonne)	0.67	0.68	0.66	0.68

In Situ

Bitumen production – Firebag (mbbls/d)	203.6	197.6	172.5	172.9

Bitumen production – MacKay River (mbbls/d)	30.8	26.6	32.1	25.5

Total In Situ bitumen production (mbbls/d)	234.4	224.2	204.6	198.4

Total Oil Sands Operations bitumen production (mbbls/d)	562.5	519.3	512.9	420.7

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

Steam-to-oil ratio – MacKay River	3.0	3.4	3.1	3.1

Bitumen production at Oil Sands operations in the third quarter of 2017 increased to 562,500 bbls/d, compared to 519,300 bbls/d in the prior year quarter, due to improved upgrader reliability at Oil Sands Base, and increased production from Firebag following the return to service after completion of the first five-year turnaround of the expanded Firebag central facilities in the second quarter of 2017. Production at MacKay River was impacted by third-party outages in both the third quarters of 2017 and 2016, with the unavailability of a pipeline in 2016 having a more significant impact than the cogeneration facility outage in 2017.


Net of transportation costs, but before royalties	Three months ended September 30				Nine months ended September 30
($/bbl)	2017		2016		2017		2016

Oil Sands operations

SCO and diesel	56.04		53.73		59.64		46.37

Bitumen	34.32		21.87		31.33		15.15

Crude sales basket (all products)	50.10		44.24		52.61		35.94

Crude sales basket, relative to WTI	(10.15	)	(14.14	)	(11.61	)	(18.47	)

Oil Sands ventures

Syncrude – sweet SCO	60.30		58.33		62.54		53.79

Syncrude, relative to WTI	0.05		(0.05	)	(1.68	)	(0.62	)

Average price realizations at Oil Sands operations increased to $50.10/bbl in the third quarter of 2017 from $44.24/bbl in the prior year quarter, due to narrower heavy crude differentials, higher WTI benchmark prices, and a higher proportion of SCO production in the third quarter of 2017, partially offset by a stronger Canadian dollar.

Average price realizations at Syncrude increased to $60.30/bbl in the third quarter of 2017 from $58.33/bbl in the prior year quarter due to the increase in the WTI benchmark price, partially offset by the impact of a stronger Canadian dollar.

Royalties for the Oil Sands segment were higher in the third quarter of 2017 compared to the prior year quarter, primarily due to improved bitumen pricing and higher production.

Operating and transportation expenses for the third quarter of 2017 increased from the prior year quarter as a result of increased operating expenses at Syncrude related to higher maintenance costs and continued work to address the facility incident from the first quarter of 2017 and support future reliability. In addition, operating expenses at Oil Sands operations increased due to higher planned maintenance expenses and additional operating costs associated with the increase in production in the third quarter. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs.

DD&A and exploration expenses for the third quarter of 2017 were lower in comparison to the same period of 2016, due to lower depreciation associated with a reduced asset cost base at Oil Sands operations and a decrease in exploration expense.


	Three months ended September 30				Nine months ended September 30
($ millions)	2017		2016		2017		2016

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Operating, selling and general expense (OS&G)	1 513		1 420		4 641		4 143

Syncrude OS&G	(525	)	(474	)	(1 659	)	(1 172	)

Non-production costs⁽²⁾	(36	)	(17	)	(68	)	(82	)

Excess power capacity and other⁽³⁾	(58	)	(65	)	(180	)	(146	)

Inventory changes	37		20		1		(105	)

Oil Sands operations cash operating costs⁽¹⁾	931		884		2 735		2 638

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	21.60		22.15		23.65		27.15

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	525		474		1 659		1 172

Non-production costs⁽²⁾	(13	)	(7	)	(27	)	(22	)

Syncrude cash operating costs⁽¹⁾	512		467		1 632		1 150

Syncrude cash operating costs ($/bbl)⁽¹⁾	35.00		27.65		49.50		37.85

(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.
(3): 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.

In the third quarter of 2017, Oil Sands operations cash operating costs per barrel were $21.60, compared to $22.15 in the prior year quarter. This is the lowest Oil Sands operations cash operating costs per barrel in over a decade and is the result of record Oil Sands operations production more than offsetting increased pre-stripping costs and operating expenses associated with the higher production. Total Oil Sands operations cash operating costs increased to $931 million from $884 million in the prior year quarter.

In the third quarter of 2017, 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 share-based compensation expense.

Excess power capacity and other for the third quarter of 2017 represents a smaller reduction to Oil Sands operations cash operating costs than the third quarter of 2016, primarily attributed to lower non-monetary expenses related to a gas swap arrangement with a third-party processor due to lower availability.

Inventory changes in the third quarter of 2017 represent a larger build of inventory than in the prior year quarter, due to increased shipments to the U.S. Gulf Coast in the current period and the additional time required for product delivery.

In the third quarter of 2017, Syncrude cash operating costs per barrel were $35.00, compared to $27.65 in the prior year period, with the increase attributed to lower production combined with an increase in operating expenses related to

higher maintenance costs and continued work to address the facility incident from the first quarter of 2017 and support future reliability. Suncor's share of Syncrude cash operating costs increased to $512 million from $467 million in the previous year quarter.

Oil Sands segment operating earnings for the first nine months of 2017 were $339 million, compared to an operating loss of $1.425 billion for the same period in 2016. Operating earnings improved as a result of higher production, with the prior year period being impacted by the forest fires in the Fort McMurray area and higher crude price realizations, partially offset by the impact of planned major maintenance events at the majority of the company's Oil Sands assets in the second quarter of 2017, the facility incident at Syncrude occurring in the first quarter of 2017 and increased operating and maintenance expenses at both Syncrude and Oil Sands operations, including higher natural gas costs due to an increase in natural gas benchmark pricing and consumption.

Funds from operations for the first nine months of 2017 were $2.958 billion for the segment, compared to $1.297 billion for the same period in 2016, with the increase primarily due to the same factors that influenced operating earnings noted above.

Oil Sands operations cash operating costs per barrel averaged $23.65 for the first nine months of 2017, a decrease from an average of $27.15 for the first nine months of 2016. The decrease was largely driven by higher production due to the impact of the forest fires in the Fort McMurray area in the prior year, partially offset by the impact of planned maintenance activities in the second quarter of 2017 and higher natural gas pricing and consumption.

Syncrude cash operating costs per barrel averaged $49.50 for the first nine months of 2017, an increase from an average of $37.85 for the first nine months of 2016, due to increased operating and maintenance costs and the production impacts of the facility incident and the planned upgrader turnaround combined with accelerated coker maintenance originally scheduled for the fourth quarter of 2017, partially offset by higher overall production due to the impact of the forest fires in the Fort McMurray area during the second quarter of 2016.

The company commenced planned upgrader maintenance in the third quarter of 2017 as well as planned maintenance at MacKay River, and both are expected to be completed early in the fourth quarter. The impact of this maintenance has been included in the company's 2017 guidance.


	Three months ended September 30				Nine months ended September 30
($ millions)	2017		2016		2017		2016

Gross revenues	766		547		2 538		1 702

Less: Royalties	(132	)	(44	)	(376	)	(118	)

Operating revenues, net of royalties	634		503		2 162		1 584

Net earnings	161		144		515		136

Impact of income tax rate adjustment on deferred taxes⁽¹⁾	—		(180	)	—		(180	)

Operating earnings (loss)⁽²⁾	161		(36	)	515		(44	)

E&P Canada	22		(81	)	82		(60	)

E&P International	*139*		45		*433*		16

Funds from operations⁽²⁾	375		365		1 294		928

(1): Adjustments to the company's deferred income taxes from a decrease from 50% to 40% in the U.K. tax rate on oil and gas profits from the North Sea in the third quarter of 2016.
(2): Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings of $22 million for E&P Canada increased from an operating loss of $81 million in the prior year quarter, as a result of lower exploration expense, due to the prior period incurring a charge for a non-commercial well off the east coast of Canada, and higher price realizations, partially offset by lower production at Terra Nova and the impact of a stronger Canadian dollar.

Operating earnings of $139 million for E&P International improved from $45 million in the prior year quarter, due to increased U.K. and Libya production, higher price realizations, and lower DD&A at Buzzard resulting from an increase in reserves, partially offset by the impact of a stronger Canadian dollar.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2017	2016	2017	2016

E&P Canada

Terra Nova (mbbls/d)	5.8	14.7	10.5	11.0

Hibernia (mbbls/d)	26.6	28.2	28.9	25.6

White Rose (mbbls/d)	9.0	7.5	11.7	11.0

North America Onshore (mboe/d)	1.5	2.7	2.0	2.8

	42.9	53.1	53.1	50.4

E&P International

Buzzard (mboe/d)	44.3	40.8	46.2	48.9

Golden Eagle (mboe/d)	20.5	16.2	20.3	18.5

United Kingdom (mboe/d)	64.8	57.0	66.5	67.4

Libya (mbbls/d)	3.8	0.5	4.2	0.4

	68.6	57.5	70.7	67.8

Total Production (mboe/d)	111.5	110.6	123.8	118.2

Production mix (liquids/gas) (%)	98/2	96/4	97/3	96/4

E&P Canada production averaged 42,900 boe/d in the third quarter of 2017, compared to 53,100 boe/d in the prior year quarter. The decrease was primarily due to planned and unplanned maintenance at Terra Nova.

E&P International production increased to 68,600 boe/d in the third quarter of 2017, compared to 57,500 boe/d in the prior year quarter, due to higher production from Buzzard and Golden Eagle as a result of planned maintenance at both properties during the prior year period, and higher production from Libya.


	Three months ended September 30		Nine months ended September 30
Net of transportation costs, but before royalties	2017	2016	2017	2016

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	65.06	59.26	66.00	53.69

E&P Canada – Natural gas ($/mcfe)	0.60	1.94	2.08	1.47

E&P International ($/boe)	60.88	55.27	62.89	49.56

Price realizations for crude oil from E&P Canada and E&P International were higher in the third quarter of 2017, compared to the prior year quarter, primarily due to an increase in benchmark crude pricing, partially offset by a stronger Canadian dollar.

Royalties were higher in the third quarter of 2017, compared to the prior year quarter, due to improved crude prices, partially offset by decreased production from E&P Canada.

Operating and transportation expenses were comparable to the prior year quarter. Continued focus on cost reduction and favourable foreign exchange that reduced expenses in the U.K. was offset by increased activity in Libya.

DD&A expense decreased in the third quarter of 2017, compared to the prior year quarter, due to lower depletion rates at Buzzard, partially offset by higher U.K. production.

Exploration expense decreased in the third quarter of 2017 due to the prior period incurring a charge for a non-commercial well off the east coast of Canada.

Operating earnings for E&P in the first nine months of 2017 were $515 million, compared to an operating loss of $44 million for the first nine months of 2016. The increase was primarily due to higher crude price realizations, increased production, lower DD&A, lower exploration expense due to the prior period including a charge for a non-commercial well off the east coast of Canada, and decreased operating costs, partially offset by higher royalties, attributed to higher crude pricing and production increases.

Funds from operations were $1.294 billion for the first nine months of 2017, compared to $928 million for the same period in 2016, and increased due to higher price realizations, increased production and lower operating costs, partially offset by higher royalties.

The planned maintenance event at Terra Nova was completed within the third quarter of 2017 and there are no planned events for the fourth quarter of 2017.


	Three months ended September 30		Nine months ended September 30
($ millions)	2017	2016	2017		2016

Operating revenues	5 140	4 711	14 537		12 892

Net earnings	597	436	1 772		1 366

Adjusted for:

Gain on significant disposal⁽¹⁾	—	—	(354	)	—

Operating earnings⁽²⁾	597	436	1 418		1 366

Refining and Supply	*527*	332	*1 183*		1 088

Marketing	70	104	*235*		278

Funds from operations⁽²⁾	827	595	1 906		1 884

(1): After-tax gain related to the sale of the company's lubricants business.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings on a FIFO basis were $597 million, compared to $436 million in the prior year quarter, with the increase described below. Using a LIFO⁽¹⁾ method of inventory valuation, which management uses to assess performance, earnings were $624 million compared to $485 million in the prior year quarter, after removing the impact of the sale of the company's lubricants business in the first quarter of 2017.

Refining and Supply operating earnings were $527 million in the third quarter of 2017, compared to $332 million in the prior year quarter. The increase was attributed to higher benchmark crack spreads, partially offset by the impact of the stronger Canadian dollar. Strong reliability resulting in record refinery crude throughput, a third-party recovery of previously incurred environmental expenses, which has been recorded in Financing Expense and Other, and a smaller FIFO loss also contributed to the increase in operating earnings.

Marketing activities contributed $70 million to operating earnings in the third quarter of 2017, compared to $104 million in the prior year quarter, which included $23 million of operating earnings from the lubricants business divested in the first quarter of 2017. After removing the impact of the lubricants business, marketing operating earnings were lower quarter-over-quarter, due to decreased retail and wholesale margins as a result of competitive pricing, partially offset by record retail and wholesale sales volumes in Canada.

During the first quarter of 2017, Suncor completed the sale of its Petro-Canada lubricants business, which contributed $41 million in net earnings and $43 million in funds from operations in the third quarter of 2016. The impact of the lubricants sale has been reflected in Financing Expense and Other in the bridge analysis above.


	Three months ended September 30		Nine months ended September 30
	2017	2016	2017	2016

Crude oil processed (mbbls/d)

Eastern North America	213.9	213.5	212.3	202.4

Western North America	252.9	252.1	231.9	226.6

Total	466.8	465.6	444.2	429.0

Refinery utilization⁽¹⁾ (%)

Eastern North America	96	96	96	91

Western North America	105	105	97	94

Total	101	101	96	93

Refined product sales (mbbls/d)

Gasoline	257.6	254.4	241.6	245.3

Distillate	212.5	195.2	198.7	185.9

Other	94.4	99.1	91.4	92.5

Total	564.5	548.7	531.7	523.7

Refining margin⁽²⁾ ($/bbl)	23.80	17.75	21.70	19.40

Refining operating expense⁽²⁾ ($/bbl)	4.50	4.55	5.00	5.00

(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.

Refinery crude throughput in the third quarter of 2017 increased to 466,800 bbls/d, compared to 465,600 bbls/d in the prior year quarter, reflecting strong reliability at all refineries.

Total refined product sales increased to 564,500 bbls/d in the third quarter of 2017, compared to 548,700 bbls/d in the prior year quarter, with the increase attributed to stronger demand.

Refined product margins in Refining and Supply were higher in the third quarter of 2017 compared to the prior year quarter, and were impacted primarily by the following factors:

Marketing margins in the third quarter of 2017, excluding the impact of the sale of the lubricants business in the first quarter of 2017, were lower than margins in the prior year quarter, primarily due to competitive pricing, which decreased retail and wholesale margins, partially offset by record retail and wholesale sales volumes in Canada.

After removing the impact of the lubricants business, which was sold in the first quarter of 2017, operating expenses in the third quarter of 2017 were higher than the prior year quarter, due to increased maintenance expenses, increased share-based compensation and increased variable selling costs associated with the increase in sales volumes.

Financing Expense and Other includes the net impact of the sale of the lubricants business in the first quarter of 2017, offset by a third-party recovery of previously recorded environmental expenses.

For the first nine months of 2017, Refining and Marketing segment operating earnings were $1.418 billion, which was comparable to $1.366 billion for the first nine months of 2016, with improved benchmark crack spreads combined with favourable product location differentials, higher refinery throughput and increased sales, including record year-to-date retail and wholesale sales volumes in Canada, more than offsetting the impact of the sale of the lubricants business in the first quarter of 2017, narrower crude differentials and a larger FIFO loss. For the first nine months of 2017, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO method, had a negative impact to operating earnings and funds from operations of $22 million after-tax, compared to the negative impact to net earnings and funds from operations of $3 million after-tax in the first nine months of 2016.

Funds from operations were $1.906 billion for the first nine months of 2017, compared to $1.884 billion for the first nine months of 2016, and decreased primarily due to the same factors that influenced operating earnings.

Suncor completed the sale of its Petro-Canada lubricants business during the first quarter of 2017, which contributed $8 million in net earnings and $11 million in funds from operations for the first nine months of 2017, compared to $99 million in net earnings and $143 million in funds from operations for the first nine months of 2016.


	Three months ended September 30				Nine months ended September 30
($ millions)	2017		2016		2017		2016

Net earnings (loss)	217		(350	)	450		(163	)

Adjusted for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(412	)	112		(793	)	(746	)

Non-cash mark to market (gain) loss on interest rate swaps and foreign currency derivatives⁽¹⁾	(10	)	22		22		182

Non-cash loss on early payment of long-term debt⁽²⁾	—		—		10		73

Gain on significant disposal⁽³⁾	—		—		(83	)	—

COS acquisition and related costs⁽⁴⁾	—		—		—		38

Operating (loss) earnings⁽⁵⁾	(205	)	(216	)	(394	)	(616	)

Renewable Energy	(2	)	2		(3	)	15

Energy Trading	*(32*	)	(7	)	*(47*	)	(15	)

Corporate	*(129*	)	(195	)	*(344*	)	(603	)

Eliminations	*(42*	)	(16	)	—		(13	)

Funds (used in) from operations⁽⁵⁾	(6	)	(171	)	(35	)	(486	)

(1): Non-cash mark to market after-tax (gain) loss on interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates.
(2): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains.
(3): After-tax gain related to the sale of the company's interest in the Cedar Point wind facility.
(4): After-tax transaction and related charges associated with the acquisition of COS.
(5): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Renewable Energy had an operating loss of $2 million in the third quarter of 2017, compared to operating earnings of $2 million in the prior year quarter. The decrease was due to lower production associated with the sale of the company's interest in the Cedar Point wind facility, which was effective January 1, 2017, and the sale of the Ripley wind facility, which was effective July 10, 2017.

During the quarter, Suncor completed the sale of its interest in the Ripley wind facility for proceeds of $48 million, with proceeds being equal to net book value.

The operating loss for Energy Trading was $32 million in the quarter, compared to an operating loss of $7 million in the prior year quarter, due to weak crude location spreads.

The Corporate operating loss was $129 million for the third quarter of 2017, compared to an operating loss of $195 million for the prior year quarter. The decrease was primarily due to tax recoveries and reassessments from prior periods, higher capitalized interest, a decrease in functional costs attributed to the company's continued cost reduction efforts and lower interest expense as a result of debt repayments in the second quarter of 2017, partially offset by an increase in share-based compensation expense. The company capitalized $182 million of its borrowing costs in the third quarter of 2017 as part of the cost of major development assets and construction projects in progress, compared to $153 million in the prior year quarter.

Eliminations reflect the elimination of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Supply. 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 2017, the company eliminated $42 million of after-tax intersegment profit, compared to eliminating $16 million of after-tax intersegment profit in the prior year quarter, with the change attributed to higher crude margins and an increase in intersegment inventory levels following the completion of Oil Sands maintenance.

Corporate, Energy Trading and Eliminations funds used in operations for the third quarter of 2017 were $6 million, compared to funds used in operations of $171 million in the prior year period. In addition to the factors noted above in operating earnings, funds from operations were favourably impacted by current tax recoveries and reassessments from prior periods.

The operating loss for Corporate, Energy Trading and Eliminations for the first nine months of 2017 was $394 million, compared to an operating loss of $616 million for the first nine months of 2016. In addition to the factors noted in the quarterly summary above, the operating loss for the first nine months of 2017 was favourably impacted by a realized gain on forward interest rate swaps. The company capitalized $552 million of its borrowing costs in the first nine months of 2017 as part of the cost of major development assets and construction projects, compared to $434 million of capitalized borrowing costs in the first nine months of 2016, with the increase due to higher accumulated expenditures on major growth projects.

Corporate, Energy Trading and Eliminations funds used in operations for the first nine months of 2017 were $35 million, compared to $486 million in the prior year period. In addition to the factors noted above in operating earnings, funds from operations were favourably impacted by tax recoveries associated with the early repayment of debt in the second quarter of 2017 and tax recoveries and reassessments relating to prior periods.


	Three months ended September 30				Nine months ended September 30
($ millions)	2017		2016		2017		2016

Oil Sands	1 340		1 306		3 899		3 667

Exploration and Production	189		283		631		829

Refining and Marketing	159		101		385		502

Corporate, Energy Trading and Eliminations	7		3		15		12

Total capital and exploration expenditures	1 695		1 693		4 930		5 010

Less: capitalized interest on debt	(182	)	(153	)	(552	)	(434	)

	1 513		1 540		4 378		4 576

Three months ended September 30, 2017

Nine months ended September 30, 2017

($ millions)

Sustaining(2)

Growth(3)

Total

Sustaining(2)

Growth(3)

Total

Oil Sands

Oil Sands Base

451

483

1 024

167

1 191

In Situ

—

246

252

Oil Sands ventures

122

531

653

426

1 623

2 049

Exploration and Production

134

140

473

487

Refining and Marketing

158

—

158

384

—

384

Corporate, Energy Trading and Eliminations

—

816

697

1 513

2 109

2 269

4 378

(1): Capital expenditures in this table exclude capitalized interest on debt.
(2): Sustaining capital expenditures include capital investments that i) ensure compliance or maintain relations with regulators and other stakeholders; ii) improve efficiency and reliability of operations or maintain productive capacity by replacing component assets at the end of their useful lives; iii) deliver existing proved developed reserves for E&P operations; or iv) maintain current production capacities at existing Oil Sands and R&M operations.
(3): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands and R&M operations; ii) new facilities or operations that increase overall production; iii) new infrastructure that is required to support higher production levels; iv) new reserves or a positive change in the company's reserves profile in E&P operations; or v) margin improvement, by increasing revenues or reducing costs.

In the third quarter of 2017, total capital and exploration expenditures were $1.513 billion (excluding capitalized interest). Capital and exploration expenditures in the third quarter of 2017 were lower than the prior year quarter, due to a decrease in growth expenditures, predominantly associated with Fort Hills and Hebron as peak construction activity for those projects has passed, partially offset by increased sustaining capital related to major maintenance activities.

Oil Sands Base capital and exploration expenditures were $483 million in the third quarter of 2017, the majority of which were directed towards sustaining activities primarily focused on planned upgrader maintenance. Capital expenditures also included various reliability and sustainment projects across the operations. Growth capital at Oil Sands Base was focused on the East Tank Farm Development, which was commissioned in the third quarter of 2017 and will support market access for Fort Hills bitumen production.

In Situ capital and exploration expenditures were $72 million and were directed towards sustaining activities, including planned maintenance at MacKay River which is expected to be completed early in the fourth quarter, and ongoing well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Oil Sands ventures capital and exploration expenditures were $653 million, of which growth capital expenditures were $531 million and sustaining capital expenditures were $122 million.

Growth capital was primarily for the Fort Hills mining project, which was approximately 95% complete at the end of the third quarter of 2017. The front end of the plant has been successfully tested as part of the commissioning phase, significantly de-risking the planned ramp up through 2018. Progress continued on secondary extraction during the quarter, with all other asset areas having now been handed over to operations. The project remains on target for first oil at the end of 2017.

Sustaining capital expenditures in the third quarter of 2017 at Fort Hills continued to focus on early-works sustaining activities that will support the execution of the Fort Hills mine and tailings plan following first oil.

Syncrude sustaining capital in the third quarter of 2017 was primarily focused on permanent repairs associated with the facility incident from the first quarter of 2017, for which Suncor expects to receive some insurance proceeds as early as the fourth quarter of 2017, and the completion of planned coker maintenance in the early part of the quarter. The coker maintenance completed in the period was originally scheduled for the fourth quarter of 2017 and was advanced to coincide with the unplanned outage, which impacted the second quarter of 2017, in order to mitigate the impact to annual production. Capital expenditures also included various reliability and sustainment projects across the operations to support the execution of the mine-tailings plan.

During the third quarter of 2017, drilling of the first production well at Hebron commenced on schedule and first oil remains on track for late 2017. Other E&P activity in the third quarter included development drilling at Hibernia, White Rose, as well as development work on the West White Rose Project and the Norwegian Oda project.

R&M capital expenditures were $158 million and were primarily related to ongoing sustainment of operations, including planned refinery maintenance, enhancements to retail operations and information technology upgrades.

Corporate capital expenditures were $7 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended September 30
	2017	2016

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	7.0	(4.6	)

Including major projects in progress	5.5	(3.9	)

Net debt to funds from operations⁽²⁾ (times)	1.6	3.0

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	5.2	(3.0	)

Funds from operations basis⁽²⁾⁽⁴⁾	10.2	5.4

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): 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.
(3): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(4): 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, available lines of credit and the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2017 capital spending program of $5.4 to $5.6 billion and to meet current and future working capital requirements, including $1.449 billion of long-term debt due in the second quarter of 2018, through cash balances and cash equivalents, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper, divesting of non-core assets and 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.

Cash and cash equivalents decreased to $2.757 billion during the first nine months of 2017 from $3.016 billion at December 31, 2016. The decrease is primarily due to the repayment of US$1.250 billion in long-term indebtedness, the purchase of the company's own shares under the normal course issuer bid (NCIB), and capital and exploration expenditures and dividend requirements exceeding cash flow provided by operating activities, partially offset by the proceeds from the sales of the company's lubricants business, its interest in the Cedar Point wind facility and the Ripley wind facility, as well as an increase in short-term indebtedness.

As capital spending on major growth projects starts to ramp down, the company expects that less cash will be required for funding purposes in the future, supporting the repayment of long-term debt and returning cash to shareholders, subject to prevailing economic conditions and other relevant factors.

As at September 30, 2017, the weighted average term to maturity of the short-term investment portfolio was approximately 18 days.

Available credit facilities for liquidity purposes at September 30, 2017 decreased to $5.546 billion, compared to $7.467 billion at December 31, 2016, as a result of the cancellation of a $950 million credit facility that was acquired through the acquisition of COS combined with an increase in short-term indebtedness. The cancelled credit facility is no longer expected to be required for liquidity purposes and the termination will reduce future financing expense.

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans and the current 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.

During the second quarter of 2017, Suncor repaid US$1.250 billion of 6.10% notes originally scheduled to mature June 1, 2018 to reduce financing costs and provide ongoing balance sheet flexibility. A premium was paid to early settle the debt, with future interest savings more than offsetting this amount. The repayment was primarily funded with the proceeds from asset divestments realized in the first quarter of 2017.

Progress continued on the sale of a combined 49% interest in the East Tank Farm Development with the Fort McKay and Mikisew Cree First Nations for estimated proceeds of approximately $500 million. The company expects to close the arrangement in the fourth quarter of 2017.

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, 2017, total debt to total debt plus shareholders' equity was 25.9% (December 31, 2016 – 28.1%). The company continues to be in compliance with all operating covenants.


($ millions, except as noted)	September 30 2017	December 31 2016

Short-term debt	2 060	1 273

Current portion of long-term debt	1 509	54

Long-term debt	12 278	16 103

Total debt	15 847	17 430

Less: Cash and cash equivalents	2 757	3 016

Net debt	13 090	14 414

Shareholders' equity	45 378	44 630

Total debt plus shareholders' equity	61 225	62 060

Total debt to total debt plus shareholders' equity (%)	25.9	28.1


	Three and nine months ended September 30, 2017
($ millions)	Q3		YTD

Total debt – beginning of period	16 132		17 430

Decrease in long-term debt	(14	)	(1 768	)

Increase in short-term debt	98		925

Foreign exchange on debt, and other	(369	)	(740	)

Total debt – September 30, 2017	15 847		15 847

Less: Cash and cash equivalents – September 30, 2017	2 757		2 757

Net debt – September 30, 2017	13 090		13 090

The company's total debt position improved in the third quarter due to the impact of favourable foreign exchange rates on U.S. dollar denominated debt, partially offset by an increase in short-term borrowings.

On a year-to-date basis, the company's total debt position improved due to the early repayment of US$1.250 billion of 6.10% notes originally scheduled to mature on June 1, 2018 and the impact of favourable foreign exchange rates on U.S. dollar denominated debt, partially offset by an increase in short-term borrowings.

As at October 23, 2017, the total number of common shares outstanding was 1,654,857,919 and the total number of exercisable and non-exercisable common share options outstanding was 33,930,867. Once exercisable, each outstanding common share option is convertible into one common share.

The company may repurchase shares pursuant to the NCIB through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative trading platforms. Under the NCIB, the company may purchase for cancellation up to approximately $2.0 billion worth of its common shares from May 2, 2017 to May 1, 2018 and has agreed that it will not purchase more than 50,079,795 common shares, which was equal to approximately 3% of Suncor's issued and outstanding common shares.

During the third quarter of 2017, the company repurchased 7,219,782 common shares at an average price of $39.19 per share, for $282 million. During the nine months ended September 30, 2017, the company repurchased 14,440,535 common shares at an average price of $40.06 per share, for $578 million. Suncor did not purchase any of its shares pursuant to a normal course issuer bid during the three months ended September 30, 2016 or the first nine months of 2016.

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 its 2016 annual MD&A and has provided an update below. The company 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.

During the nine months ended September 30, 2017, the company decreased its commitments by approximately $1.3 billion (undiscounted), which is primarily related to the early repayment of US$1.250 billion of 6.10% notes originally scheduled to mature on June 1, 2018 and the reduction in commitments associated with the sale of Suncor's lubricants business, partially offset by a lodging services commitment that supports Suncor's Oil Sands Base operations and the recognition of incremental Hebron decommissioning costs following the milestones achieved during the second quarter of 2017.

Trends in Suncor's quarterly revenue, earnings and funds from operations⁽¹⁾ are driven primarily by production volumes, which can be significantly impacted by major maintenance events, changes in commodity prices, refining crack spreads, foreign exchange rates and other significant events impacting operations, such as the Syncrude facility incident that occurred late in the first quarter of 2017, which significantly impacted the second quarter of 2017, and the forest fires in the Fort McMurray area in the second quarter of 2016.


Three months ended ($ millions, unless otherwise noted)	Sep 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016		Sep 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015

Total production (mboe/d)

Oil Sands	628.4	413.6	590.6	620.4		617.5		213.1		565.8		470.6

Exploration and Production	111.5	125.5	134.5	118.1		110.6		117.6		125.6		112.3

	739.9	539.1	725.1	738.5		728.1		330.7		691.4		582.9

Revenues and other income

Operating revenues, net of royalties	7 986	7 247	7 818	7 840		7 409		5 914		5 644		6 499

Other income (loss)	43	16	25	301		(15	)	(58	)	(67	)	94

	8 029	7 263	7 843	8 141		7 394		5 856		5 577		6 593

Net earnings (loss)	1 289	435	1 352	531		392		(735	)	257		(2 007	)

per common share – basic (dollars)	0.78	0.26	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)

per common share – diluted (dollars)	0.78	0.26	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)

Operating earnings (loss)⁽¹⁾	867	199	812	636		346		(565	)	(500	)	(26	)

per common share – basic⁽¹⁾ (dollars)	0.52	0.12	0.49	0.38		0.21		(0.36	)	(0.33	)	(0.02	)

Funds from operations⁽¹⁾	2 472	1 627	2 024	2 365		2 025		916		682		1 294

per common share – basic⁽¹⁾ (dollars)	1.49	0.98	1.21	1.42		1.22		0.58		0.45		0.90

Cash flow provided by operating activities	2 912	1 671	1 628	2 791		1 979		862		48		1 443

per common share – basic (dollars)	1.75	1.00	0.98	1.68		1.19		0.54		0.03		1.00

ROCE⁽¹⁾ (%) for the twelve months ended	7.0	6.2	4.4	0.5		(4.6	)	(4.9	)	(2.2	)	0.6

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	412	278	103	(222	)	(112	)	(27	)	885		(382	)

Common share information (dollars)

Dividend per common share	0.32	0.32	0.32	0.29		0.29		0.29		0.29		0.29

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	43.73	37.89	40.83	43.90		36.42		35.84		36.17		35.72

New York Stock Exchange (US$)	35.03	29.20	30.75	32.69		27.78		27.73		27.81		25.80

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A. ROCE excludes capitalized costs related to major projects in progress.


Three months ended (average for the period ended, except as noted)		Sep 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016	Sep 30 2016	Jun 30 2016	Mar 31 2016	Dec 31 2015

WTI crude oil at Cushing	US$/bbl	48.20	48.30	51.85	49.35	44.95	45.60	33.50	42.15

Dated Brent crude	US$/bbl	52.05	49.85	53.75	49.50	45.85	45.60	33.90	43.70

Dated Brent/Maya FOB price differential	US$/bbl	6.30	5.80	9.05	6.70	6.80	7.65	8.95	10.35

MSW at Edmonton	Cdn$/bbl	57.05	62.30	64.25	62.00	55.10	55.80	34.50	53.55

WCS at Hardisty	US$/bbl	38.25	37.20	37.30	35.00	31.45	32.30	19.30	27.70

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	9.95	11.10	14.55	14.35	13.50	13.30	14.25	14.50

Condensate at Edmonton	US$/bbl	47.60	48.45	52.20	48.35	43.05	44.10	34.45	41.65

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.45	2.80	2.70	3.10	2.30	1.40	1.85	2.45

Alberta Power Pool Price	Cdn$/MWh	24.55	19.30	22.40	21.95	17.90	14.90	18.10	21.20

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	22.35	16.35	12.55	14.35	14.00	16.10	11.75	13.60

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	19.25	14.40	11.15	10.55	14.15	16.65	9.10	13.90

Portland 3-2-1 crack⁽¹⁾	US$/bbl	26.80	21.25	18.45	14.95	18.75	19.30	13.00	17.90

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	21.45	16.80	14.00	13.15	14.50	14.85	11.05	11.05

Exchange rate	US$/Cdn$	0.80	0.74	0.76	0.75	0.77	0.78	0.73	0.75

Exchange rate (end of period)	US$/Cdn$	0.80	0.77	0.75	0.74	0.76	0.77	0.77	0.72

(1): 3-2-1 crack spreads are indicators of the refining margin generated by converting three barrels of WTI into two barrels of gasoline and one barrel of diesel. The crack spreads presented here generally approximate the regions into which the company sells refined products through retail and wholesale channels.

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

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 2016 annual MD&A.

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, 2016 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2016 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 28 of the audited Consolidated Financial Statements for the year ended December 31, 2016, note 11 to the unaudited interim Consolidated Financial Statements for the three months ended September 30, 2017, and the Financial Condition and Liquidity section of Suncor's 2016 annual MD&A.

In the fourth quarter of 2016, the Government of Quebec enacted a decrease in the corporate income tax rate from 11.9% to 11.5% evenly over the next four years, effective January 1, 2017. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax recovery of $10 million.

In the third quarter of 2016, the U.K. government enacted a decrease in the supplementary charge rate on oil and gas profits in the North Sea that reduced the statutory tax rate on Suncor's earnings in the U.K. from 50% to 40%. The company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income taxes of $180 million in the E&P segment.

Based on their evaluation as at September 30, 2017, 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, 2017, 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- and nine-month periods ended September 30, 2017 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 2017 corporate guidance, as set forth in Suncor's press release dated October 25, 2017, which is also available on www.sedar.com.

Certain financial measures in this MD&A – namely operating earnings (loss), ROCE, funds from (used in) operations, discretionary free cash flow, Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense and LIFO – 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.

revenue, and the net impacts of sales and purchases of third-party crude, including product purchased for use as diluent in the company's Oil Sands operations and subsequently sold as part of diluted bitumen.

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 of 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)		2017		2016

Adjustments to net earnings

Net earnings (loss)		3 607		(2 103	)

Add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(568	)	(362	)

Net interest expense		181		306

	A	3 220		(2 159	)

Capital employed – beginning of twelve-month period

Net debt		14 729		9 551

Shareholders' equity		43 976		41 148

		58 705		50 699

Capital employed – end of twelve-month period

Net debt		13 090		14 729

Shareholders' equity		45 378		43 976

		58 468		58 705

Average capital employed	B	58 726		56 010

ROCE – including major projects in progress (%)	A/B	5.5		(3.9	)

Average capitalized costs related to major projects in progress	C	12 778		9 351

ROCE – excluding major projects in progress (%)	A/(B–C)	7.0		(4.6	)

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 include, among other factors, the timing of offshore feedstock purchases and payments for commodity and income taxes, and the timing of cash flows related to accounts receivable and accounts payable, which management believes reduces comparability between periods.

Funds from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the funds from (used in) operations for the particular quarter ended September 30 and each of the three preceding quarters. Funds from (used in) operations for each quarter are separately defined and reconciled to the consolidated GAAP measure in the Non-GAAP Financial Measures Advisory section of each respective MD&A for the applicable quarter.


Three months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net earnings (loss)	314		162		161		144		597		436		217		(350	)	1 289		392

Adjustments for:

Depreciation, depletion, amortization and impairment	859		971		236		270		161		164		25		34		1 281		1 439

Deferred income taxes	53		62		(21	)	(198	)	36		(8	)	102		7		170		(137	)

Accretion	48		54		12		11		2		1		—		1		62		67

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(441	)	121		(441	)	121

Change in fair value of financial instruments and trading inventory	8		6		—		—		13		5		24		(16	)	45		(5	)

Gain on disposal of assets	(3	)	—		—		—		(1	)	(13	)	—		—		(4	)	(13	)

Loss on debt extinguishment	—		—		—		—		—		—		—		—		—		—

Share-based compensation	41		20		5		3		21		11		72		33		139		67

Exploration	—		—		—		139		—		—		—		—		—		139

Settlement of decommissioning and restoration liabilities	(49	)	(43	)	(13	)	—		(4	)	(5	)	—		—		(66	)	(48	)

Other	5		4		(5	)	(4	)	2		4		(5	)	(1	)	(3	)	3

Funds from (used in) operations	1 276		1 236		375		365		827		595		(6	)	(171	)	2 472		2 025

(Increase) Decrease in non-cash working capital	(860	)	(502	)	(272	)	(56	)	1 167		(395	)	405		907		440		(46	)

Cash flow provided by (used in) operating activities	416		734		103		309		1 994		200		399		736		2 912		1 979


Nine months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net earnings (loss)	339		(1 425	)	515		136		1 772		1 366		450		(163	)	3 076		(86	)

Adjustments for:

Depreciation, depletion, amortization and impairment	2 727		2 826		809		1 087		489		506		88		97		4 113		4 516

Deferred income taxes	(11	)	(64	)	(118	)	(462	)	23		15		252		69		146		(442	)

Accretion	146		155		33		43		5		5		—		1		184		204

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(845	)	(771	)	(845	)	(771	)

Change in fair value of financial instruments and trading inventory	—		19		—		—		—		28		112		218		112		265

Gain on disposal of assets	(4	)	(33	)	—		—		(352	)	(14	)	(70	)	—		(426	)	(47	)

Loss on debt extinguishment	—		—		—		—		—		—		25		99		25		99

Share-based compensation	(37	)	(16	)	2		5		(13	)	(11	)	(37	)	(37	)	(85	)	(59	)

Exploration	—		—		41		139		—		—		—		—		41		139

Settlement of decommissioning and restoration liabilities	(229	)	(193	)	(16	)	—		(10	)	(13	)	—		—		(255	)	(206	)

Other	27		28		28		(20	)	(8	)	2		(10	)	1		37		11

Funds from (used in) operations	2 958		1 297		1 294		928		1 906		1 884		(35	)	(486	)	6 123		3 623

Decrease (increase) in non-cash working capital	58		(600	)	(114	)	(96	)	1 067		(195	)	(923	)	157		88		(734	)

Cash flow provided by (used in) operating activities	3 016		697		1 180		832		2 973		1 689		(958	)	(329	)	6 211		2 889

Discretionary free cash flow is a non-GAAP financial measure that is calculated by taking funds from operations and subtracting sustaining capital, inclusive of associated capitalized interest, and dividends. Discretionary free cash flow reflects cash available for increasing distributions to shareholders and to fund growth investments. Management uses discretionary free cash flow to measure the capacity of the company to increase returns to shareholders and grow the business.

Oil Sands operations and Syncrude 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 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 start-up 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 cash operating costs are calculated by adjusting Syncrude OS&G for non-production costs that management believes do not relate to the production performance of Syncrude operations, including, but not limited to, share-based compensation, research and project start-up costs. Oil Sands operations and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this MD&A. Management uses Oil Sands operations and Syncrude cash operating costs to measure Oil Sands 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 (GAAP measures) for non-refining margin pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business. 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 the company's former lubricants business; 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)	2017		2016		2017		2016

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 520		1 377		4 081		4 233

Other income	48		13		86		26

Non-refining margin	(463	)	(572	)	(1 333	)	(1 811	)

Refining margin	1 105		818		2 834		2 448

Refinery production⁽¹⁾ (mbbls)	46 491		46 119		130 660		126 288

Refining margin ($/bbl)	23.80		17.75		21.70		19.40

Refining operating expense reconciliation

Operating, selling and general expense	481		549		1 462		1 617

Non-refining costs	(272	)	(339	)	(809	)	(988	)

Refining operating expense	209		210		653		629

Refinery production⁽¹⁾ (mbbls)	46 491		46 119		130 660		126 288

Refining operating expense ($/bbl)	4.50		4.55		5.00		5.00

(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 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	MSW	Mixed Sweet Blend
mmcf/d	millions of cubic feet of natural gas per day	NYMEX	New York Mercantile Exchange
mmcfe	millions of cubic feet of natural gas equivalent	YTD	Year to date
mmcfe/d	millions of cubic feet of natural gas equivalent
	per day
MW	megawatts
MWh	megawatts per hour

The document contains certain forward-looking information and forward-looking statements (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information are based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves 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, including royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; the satisfaction by third parties of their obligations to Suncor; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other 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" and similar expressions. Forward-looking statements in the document 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 our 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 our proprietary production will be closed, experience equipment failure or other accidents; our ability to operate our 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; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; our dependence on pipeline capacity and other logistical constraints, which may affect our ability to distribute our products to market; our ability to finance Oil Sands growth and sustaining 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; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; our 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); risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; changes to royalty and tax legislation and related agreements that could impact our business; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and changes to environmental regulations or legislation.

Factors that affect our 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; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; 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 that operations in Syria continue to be impacted by sanctions and political unrest; risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; 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; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; 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; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

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; 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 in environmental and other regulations and policies; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of 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 computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our 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; 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 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 and the receipt of any required regulatory or other third-party approvals outside of Suncor's control; risks associated with land claims and Aboriginal consultation requirements; risks relating to litigation; 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 2016 annual MD&A, 2016 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 documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

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


(thousands)		September 30, 2017

Common shares		1 656 455

Common share options – exercisable		20 496

Common share options – non-exercisable		14 016


1.	Advisories	5
2.	Third Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	24
6.	Financial Condition and Liquidity	26
7.	Quarterly Financial Data	30
8.	Other Items	32
9.	Non-GAAP Financial Measures Advisory	33
10.	Common Abbreviations	38
11.	Forward-Looking Information	39