Management's Discussion and Analysis for the third quarter ended September 30, 2016

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. Periodically we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2015, dated February 25, 2016 (the 2015 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, 2016, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2015 and the 2015 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated February 25, 2016 (the 2015 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, unless otherwise noted. Certain prior year amounts in the Consolidated Statements of Comprehensive (Loss) Income have been reclassified to conform to the current year's presentation.

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

Comparative figures have been reclassified to conform to the current year financial statement presentation for the revenues and expenses for the company's ethanol business that is presented in the Refining and Marketing (R&M) segment, and was previously presented in Corporate, Energy Trading and Eliminations.

Certain financial measures in this MD&A – namely operating earnings (loss), cash flow from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, free cash flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings (loss), Oil Sands operations 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. Cash flow from (used in) operations, ROCE and free cash flow 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)	2016		2015		2016		2015

Net earnings (loss)

Oil Sands	162		(50	)	(1 425	)	(240	)

Exploration and Production	144		(1	)	136		505

Refining and Marketing	436		625		1 366		1 800

Corporate, Energy Trading and Eliminations	(350	)	(950	)	(163	)	(2 053	)

Total	392		(376	)	(86	)	12

Operating earnings (loss)⁽¹⁾

Oil Sands	162		(50	)	(1 425	)	119

Exploration and Production	(36	)	(1	)	(44	)	57

Refining and Marketing	436		625		1 366		1 768

Corporate, Energy Trading and Eliminations	(216	)	(164	)	(616	)	(453	)

Total	346		410		(719	)	1 491

Cash flow from (used in) operations⁽¹⁾

Oil Sands	1 236		785		1 297		2 368

Exploration and Production	365		253		928		1 129

Refining and Marketing	595		814		1 884		2 316

Corporate, Energy Trading and Eliminations	(171	)	30		(486	)	(301	)

Total	2 025		1 882		3 623		5 512

Capital and Exploration Expenditures⁽²⁾

Sustaining	555		698		1 778		1 650

Growth	985		923		2 798		2 669

Total	1 540		1 621		4 576		4 319


	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015

Production volumes by segment

Oil Sands (mbbls/d)	617.5	458.4	466.0	461.0

Exploration and Production (mboe/d)	110.6	107.7	118.2	115.1

Total	728.1	566.1	584.2	576.1

Production mix

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

Refinery utilization (%)	101	96	93	94

Refinery crude oil processed (mbbls/d)	465.6	444.8	429.0	432.7

Suncor's consolidated net earnings for the third quarter of 2016 were $392 million, compared with a net loss of $376 million for the prior year quarter. The net loss for the first nine months of 2016 was $86 million, compared to net earnings of $12 million in the prior year period. 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)	2016		2015		2016		2015

Net earnings (loss)	392		(376	)	(86	)	12

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	112		786		(746	)	1 548

Impact of income tax rate adjustments on deferred taxes⁽²⁾	(180	)	—		(180	)	17

Non-cash mark to market loss on interest rate swaps⁽³⁾	22		—		182		—

Non-cash loss on early payment of long-term debt⁽⁴⁾	—		—		73		—

COS acquisition and integration costs⁽⁵⁾	—		—		38		—

Gain on significant disposal⁽⁶⁾	—		—		—		(68	)

Restructuring charges⁽⁷⁾	—		—		—		57

Insurance proceeds⁽⁸⁾	—		—		—		(75	)

Operating earnings (loss)⁽¹⁾	346		410		(719	)	1 491

(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): 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 10% decrease in the U.K. tax rate on oil and gas profits from the North Sea. The nine-month period ended September 30, 2015 was impacted by a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea, offset by a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(3): Non-cash loss on interest rate swaps resulting from a decrease in long-term interest rates in the Corporate segment.
(4): Charges associated with early repayment of debt in the Corporate segment.
(5): Transaction and related charges associated with the acquisition of COS in the Corporate segment.
(6): After-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the R&M segment.
(7): Restructuring charges related to cost reduction initiatives in the Corporate segment.
(8): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

Suncor's consolidated operating earnings for the third quarter 2016 were $346 million, compared to $410 million in the prior year quarter. Highlights of the quarter included an increased share of Syncrude operating earnings, attributed to improved upgrader reliability and lower per unit operating costs combined with the acquisition of additional working interests in 2016, a lower R&M FIFO loss, lower operating costs at Oil Sands operations, record refinery crude throughput and higher production from both Oil Sands operations and E&P. These factors more than offset the unfavourable impact of both lower benchmark crack spreads and crude pricing. Operating earnings also included a non-cash charge for a non-commercial exploration well off the east coast of Canada.

Suncor's consolidated operating loss was $719 million for the first nine months of 2016, compared to operating earnings of $1.491 billion for the prior year period. The decrease was primarily due to lower upstream price realizations, consistent with the decline in benchmark crude prices, weaker benchmark crack spreads, the impact of shut-in production associated with the forest fires in the Fort McMurray area and higher operating expenses due to the acquisition of additional Syncrude working interests in 2016, partially offset by a lower R&M FIFO loss, increased production from Syncrude, favourable refined product location differentials and lower operating costs after removing the impact of the Syncrude acquisitions.


	Three months ended September 30		Nine months ended September 30
($ millions)	2016	2015	2016	2015

Oil Sands	15	20	48	50

Exploration and Production	1	3	4	6

Refining and Marketing	8	12	30	30

Corporate, Energy Trading and Eliminations	27	42	100	89

Total share-based compensation expense	51	77	182	175

The after-tax share-based compensation expense decreased to $51 million during the third quarter of 2016, compared to $77 million during the prior year quarter, as a result of a lower share price increase in the third quarter of 2016 when compared to 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 three months ended
September 30

Average for nine months ended
September 30

2016

2015

2016

2015

WTI crude oil at Cushing

US$/bbl

44.95

46.45

41.35

51.00

Dated Brent crude

US$/bbl

45.85

50.30

41.80

56.55

Dated Brent/Maya crude oil FOB price differential

US$/bbl

6.80

8.50

7.50

9.20

MSW at Edmonton

Cdn$/bbl

55.10

56.55

50.90

58.95

WCS at Hardisty

US$/bbl

31.45

33.25

27.70

37.80

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

US$/bbl

13.50

13.20

13.65

13.20

Condensate at Edmonton

US$/bbl

43.05

44.20

40.55

49.25

Natural gas (Alberta spot) at AECO

Cdn$/mcf

2.30

2.90

1.85

2.75

Alberta Power Pool Price

Cdn$/MWh

17.90

26.05

17.00

37.50

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

14.00

22.25

13.95

21.75

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

14.15

23.95

13.30

20.05

Portland 3-2-1 crack⁽¹⁾

US$/bbl

18.75

28.75

17.00

27.60

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

14.50

21.55

12.50

20.80

Exchange rate

US$/Cdn$

0.77

0.76

0.76

0.79

Exchange rate (end of period)

US$/Cdn$

0.76

0.75

0.76

0.75

(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 2016 for sweet SCO were negatively affected by a lower WTI price of US$44.95/bbl, compared to US$46.45/bbl in the prior year quarter, partially offset by a favourable differential for SCO relative to WTI. Suncor produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton decreased to $55.10/bbl compared to $56.55/bbl in the prior year quarter and prices for WCS at Hardisty decreased to US$31.45/bbl from US$33.25 in the third quarter of 2015.

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 decreased to an average of US$45.85/bbl in the third quarter of 2016, compared to US$50.30/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 $2.30/mcf in the third quarter of 2016, from $2.90/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 business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $17.90/MWh in the third quarter of 2016 from $26.05/MWh in the prior year quarter.

The majority of Suncor's revenue 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 2016, the Canadian dollar strengthened in relation to the U.S. dollar as the average exchange rate increased to US$0.77 per one Canadian dollar from US$0.76 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 2016 when compared to the prior year quarter.

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


	Three months ended September 30				Nine months ended September 30
($ millions)	2016		2015		2016		2015

Gross revenues	2 967		2 272		6 166		7 315

Less: Royalties	(20	)	(48	)	(48	)	(104	)

Operating revenues, net of royalties	2 947		2 224		6 118		7 211

Net earnings (loss)	162		(50	)	(1 425	)	(240	)

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	—		—		—		359

Operating earnings (loss)⁽²⁾	162		(50	)	(1 425	)	119

Oil Sands operations	*(13*	)	(21	)	*(1 327*	)	198

Oil Sands ventures	*175*		(29	)	*(98*	)	(79	)

Cash flow from operations⁽²⁾	1 236		785		1 297		2 368

(1): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The operating loss for Oil Sands operations was $13 million, compared to an operating loss of $21 million in the prior year quarter. Lower operating and maintenance expenses attributable to the company's cost reduction initiatives, lower natural gas prices and higher production volumes more than offset the impact of lower price realizations associated with weaker crude oil benchmark pricing.

Operating earnings for Oil Sands ventures were $175 million in the third quarter of 2016, compared to an operating loss of $29 million in the prior year quarter, with the increase mainly due to improved Syncrude upgrader utilization and lower operating costs combined with a higher share of Syncrude operating earnings as a result of the acquisition of additional working interests in 2016. These factors more than offset declines in benchmark crude pricing.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2016	2015	2016	2015

Upgraded product (SCO and diesel)	301.1	314.9	236.8	329.6

Non-upgraded bitumen	132.6	115.4	118.2	102.0

Oil Sands operations	433.7	430.3	355.0	431.6

Oil Sands ventures – Syncrude	183.8	28.1	111.0	29.4

Total	617.5	458.4	466.0	461.0

(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.


	Three months ended September 30		Nine months ended September 30
(mbbls/d)	2016	2015	2016	2015

Oil Sands operations sales volumes

Sweet SCO	100.8	112.9	87.4	109.3

Diesel	27.9	30.0	18.7	32.0

Sour SCO	162.5	180.7	137.2	192.0

Upgraded product	291.2	323.6	243.3	333.3

Non-upgraded bitumen	123.5	106.3	122.1	98.0

Oil Sands operations	414.7	429.9	365.4	431.3

Oil Sands ventures – Syncrude	183.8	28.1	111.0	29.4

Total	598.5	458.0	476.4	460.7

Production volumes for Oil Sands operations increased to 433,700 bbls/d in the third quarter of 2016, comparable to 430,300 bbls/d in the prior year quarter, with increased production from Firebag offsetting lower SCO production. Planned upgrader maintenance began in the third quarter of 2016 and was completed in the fourth quarter of 2016. Planned maintenance also impacted the third quarter of the prior year.

Sales volumes for Oil Sands operations decreased to an average of 414,700 bbls/d in the third quarter of 2016, down from 429,900 bbls/d in the prior year quarter, due to replenishing product inventory after the significant draw in the second quarter of 2016 due to the shut-in associated with the forest fires, partially offset by higher production volumes.

Suncor's share of Syncrude production was 183,800 bbls/d in the third quarter of 2016, compared to 28,100 bbls/d in the prior year quarter. Syncrude upgrader reliability improved to 98%, compared to 67% in the prior year quarter, which included the impact of an upgrader fire. The increase is attributed to additional working interests acquired in 2016, combined with strong reliability in the period and the processing of unfinished inventory which was accumulated as a result of planned maintenance and impacted by the forest fires during the second quarter of 2016.


	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015

Oil Sands Base

Bitumen production (mbbls/d)	295.1	303.3	222.3	312.3

Bitumen ore mined (thousands of tonnes per day)	433.2	471.0	328.6	470.6

Bitumen ore grade quality (bbls/tonne)	0.68	0.64	0.68	0.66

In Situ

Bitumen production – Firebag (mbbls/d)	197.6	191.7	172.9	182.9

Bitumen production – MacKay River (mbbls/d)	26.6	27.4	25.5	29.4

Total In Situ bitumen production	224.2	219.1	198.4	212.3

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

Steam-to-oil ratio – MacKay River	3.4	2.8	3.1	2.9

Oil Sands Base bitumen production from mining and extraction activities averaged 295,100 bbls/d in the third quarter of 2016, compared to 303,300 bbls/d in the prior year quarter. The decrease was primarily due to unplanned maintenance in the third quarter of 2016.

In Situ bitumen production increased to 224,200 bbls/d in the third quarter of 2016, compared to 219,100 bbls/d in the prior year quarter. The increase was primarily driven by continued strong reliability at Firebag. Production at MacKay River

decreased to 26,600 bbls/d in the third quarter of 2016 from 27,400 bbls/d in the prior year quarter, with the decrease primarily due to a slower than anticipated return to normal levels due to the unavailability of a third-party pipeline after the forest fires as a result of restart issues incurred by the pipeline operator. Planned maintenance at MacKay River occurred in both periods.

Firebag's steam-to-oil ratio of 2.6 was comparable with the prior year quarter. The steam-to-oil ratio at MacKay River increased to 3.4 from 2.8 in the prior year quarter due to additional steam requirements for a new well pad.


Net of transportation costs, but before royalties	Three months ended September 30				Nine months ended September 30
($/bbl)	2016		2015		2016		2015

Oil Sands operations

SCO and diesel	53.73		53.50		46.37		57.91

Bitumen	21.87		26.99		15.15		29.37

Crude sales basket (all products)	44.24		46.95		35.94		51.43

Crude sales basket, relative to WTI	(14.14	)	(14.17	)	(18.47	)	(13.13	)

Oil Sands ventures

Syncrude – sweet SCO	58.33		60.53		53.79		62.32

Syncrude, relative to WTI	(0.05	)	(0.59	)	(0.62	)	(2.24	)

Average price realizations from Oil Sands operations decreased to $44.24/bbl in the third quarter of 2016 from $46.95/bbl in the prior year quarter, primarily due to the lower WTI benchmark prices and a wider WCS differential, partially offset by improved SCO differentials.

Average price realizations at Syncrude decreased to $58.33/bbl in the third quarter of 2016 from $60.53/bbl in the prior year quarter due to the decrease in the WTI benchmark price, partially offset by improved SCO differentials.

Royalties for the Oil Sands segment were lower in the third quarter of 2016 compared to the prior year quarter, primarily due to lower bitumen prices, partially offset by higher production.

Operating and transportation expenses for the third quarter of 2016 increased from the prior year quarter, primarily due to the company's increased working interest in Syncrude, partially offset by the impact of Suncor's cost reduction initiatives at Oil Sands operations, lower transportation charges at Oil Sands operations and lower natural gas prices. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs for Oil Sands operations.

DD&A expense for the third quarter of 2016 was higher in comparison to the same period of 2015, mainly due to the increased working interest in Syncrude and a larger asset base at Oil Sands operations.


	Three months ended September 30				Nine months ended September 30
($ millions)	2016		2015		2016		2015

Oil Sands operations cash operating cost reconciliation

Operating, selling and general expense (OS&G)	1 420		1 246		4 143		3 903

Syncrude OS&G	(474	)	(110	)	(1 172	)	(353	)

Non-production costs⁽¹⁾	(17	)	(23	)	(82	)	(69	)

Excess power capacity and other⁽²⁾	(65	)	(49	)	(146	)	(185	)

Inventory changes	20		5		(105	)	(21	)

Oil Sands operations cash operating costs⁽³⁾	884		1 069		2 638		3 275

Oil Sands operations cash operating costs ($/bbl)⁽³⁾	22.15		27.00		27.15		27.80

Syncrude cash operating costs

Syncrude cash operating costs⁽⁴⁾	467		108		1 158		348

Syncrude cash operating costs ($/bbl)	27.65		41.65		37.85		43.40

(1): Significant non-production costs include, but are not limited to, share-based compensation expense and research and development expenses.
(2): 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.
(3): Oil Sands operations cash operating costs and cash operating costs per barrel are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(4): Syncrude cash operating costs are presented on a sales basis, after deducting non-production costs, primarily relating to research and development.

In the third quarter of 2016, Oil Sands operations cash operating costs per barrel decreased to $22.15, compared to $27.00 in the prior year quarter, due to lower operating and maintenance costs associated with the company's cost reduction initiatives and lower natural gas input costs, combined with higher production volumes. Total Oil Sands operations cash operating costs decreased to $884 million from $1.069 billion in the prior year quarter.

In the third quarter of 2016, non-production costs, which are excluded from Oil Sands operations cash operating costs, were lower than the prior year quarter, primarily due to lower share-based compensation expense.

Excess power capacity and other recoveries for the third quarter of 2016 were higher than the third quarter of 2015 due to increases in other costs primarily related to support services, as well as increased recoveries from cogeneration power sales.

Inventory changes in the third quarter of 2016 represent a larger product build than the prior year quarter, as the company replenished crude inventory in response to the significant draw in the second quarter of 2016 due to production being shut in as a result of the Fort McMurray and area forest fires.

Syncrude cash operating costs per barrel in the third quarter of 2016 decreased to $27.65 from $41.65 in the previous year quarter due to higher production, associated with improved reliability, and lower cash operating expenses. Suncor's share of Syncrude cash operating costs increased to $467 million from $108 million in the previous year quarter due to the additional Syncrude working interests acquired in 2016, partially offset by reduced operating and maintenance expenses.

Oil Sands segment operating loss for the first nine months of 2016 was $1.425 billion, compared to operating earnings of $119 million for the same period in 2015. Operating earnings decreased primarily due to declines in crude price realizations, lower Oil Sands operations production volumes due to the impact of the forest fires in the Fort McMurray area in the second quarter of 2016 and higher expenses associated with the increased Syncrude working interests. These factors were partially offset by increased production from Syncrude, lower Oil Sands operations operating, selling and general expenses and lower royalty expense.

Cash flow from operations for the first nine months of 2016 was $1.297 billion for the segment, compared to $2.368 billion for the same period in 2015. The decrease in cash flow from operations was due to the same factors that impacted operating earnings above.

Oil Sands operations cash operating costs per barrel averaged $27.15 for the first nine months of 2016, a decrease from an average of $27.80 for the first nine months of 2015, despite significantly lower production volumes. The decrease is attributed to a reduction in absolute cash costs for the first nine months of 2016 when compared to the same period of 2015, which more than offset the impact of lower production volumes caused by the forest fires in the second quarter of 2016. The reduction in cash operating costs was due to the company's cost reduction initiatives and lower natural gas prices, as well as costs avoided during the production outage as a result of the forest fires.

Cash operating costs per barrel for Syncrude operations averaged $37.85/bbl for the first nine months of 2016, a decrease from an average of $43.40/bbl for the first nine months of 2015. The decrease was primarily due to operating cost reductions, partially offset by lower volumes associated with the forest fires.

The company commenced maintenance at Upgrader 1 during the third quarter of 2016, which was completed in the fourth quarter of 2016. The impact of this maintenance has been reflected in the company's 2016 guidance.


	Three months ended September 30				Nine months ended September 30
($ millions)	2016		2015		2016		2015

Gross revenues	547		558		1 702		2 107

Less: Royalties	(44	)	(12	)	(118	)	(234	)

Operating revenues, net of royalties	503		546		1 584		1 873

Net earnings (loss)	144		(1	)	136		505

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	(180	)	—		(180	)	(373	)

Insurance proceeds⁽²⁾	—		—		—		(75	)

Operating (loss) earnings⁽³⁾	(36	)	(1	)	(44	)	57

E&P Canada	*(81*	)	(5	)	*(60*	)	(3	)

E&P International	45		4		16		60

Cash flow from operations⁽³⁾	365		253		928		1 129

(1): Adjustments to the company's deferred income taxes from a 10% and 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea in the third quarter of 2016 and the first quarter of 2015, respectively, and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): Business interruption insurance proceeds for the Terra Nova asset in the E&P segment.
(3): Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

E&P operating loss was $36 million in the third quarter of 2016, compared to an operating loss of $1 million in the prior year quarter.

Operating loss of $81 million for E&P Canada increased from an operating loss of $5 million in the prior year quarter, primarily due to a $102 million after-tax charge related to a non-commercial exploration well at the Shelburne Basin off the east coast of Canada. Excluding this impact, operating earnings increased when compared to the prior year quarter, with improved production and slightly higher realized pricing more than offsetting additional royalties and DD&A expense.

Operating earnings of $45 million for E&P International increased from $4 million in the prior year quarter, primarily due to lower DD&A expense resulting from reduced volumes and a lower depletion rate at Golden Eagle, partially offset by decreased production at Buzzard, due to planned turnaround activities occurring in the third quarter of 2016, and lower price realizations.


	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015

E&P Canada

Terra Nova (mbbls/d)	14.7	10.4	11.0	13.7

Hibernia (mbbls/d)	28.2	16.6	25.6	18.9

White Rose (mbbls/d)	7.5	9.9	11.0	11.3

North America Onshore (mboe/d)	2.7	3.7	2.8	3.2

	53.1	40.6	50.4	47.1

E&P International

Buzzard (mboe/d)	40.8	50.0	48.9	51.2

Golden Eagle (mboe/d)	16.2	17.0	18.5	13.8

United Kingdom (mboe/d)	57.0	67.0	67.4	65.0

Libya (mbbls/d)	0.5	0.1	0.4	3.0

	57.5	67.1	67.8	68.0

Total Production (mboe/d)	110.6	107.7	118.2	115.1

Production mix (liquids/gas) (%)	96/4	95/5	96/4	96/4

E&P Canada production averaged 53,100 boe/d in the third quarter of 2016, compared to 40,600 boe/d in the prior year quarter. The increase was primarily due to higher production at Hibernia with new wells being brought online subsequent to the third quarter of 2015 and higher production at Terra Nova due to reservoir optimization and improved reliability, where production was ramping up after the completion of an extended turnaround in the third quarter of 2015. Both quarters were impacted by planned maintenance.

E&P International production averaged 57,500 boe/d in the third quarter of 2016, compared to 67,100 boe/d in the prior year quarter. The decrease was primarily due to planned maintenance at Buzzard that began late in the third quarter of 2016. Production at Golden Eagle was comparable to the prior year quarter, with peak production rates being offset by a planned turnaround in the current period. Production in Libya remains substantially shut in, and the timing of a return to normal operations remains uncertain.


	Three months ended September 30		Nine months ended September 30
Net of transportation costs, but before royalties	2016	2015	2016	2015

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	59.26	56.02	53.69	66.30

E&P Canada – Natural gas ($/mcfe)	1.94	1.82	1.47	2.04

E&P International ($/boe)	55.27	60.43	49.56	64.31

Price realizations for crude oil from E&P Canada were higher in the third quarter of 2016 compared to the prior year quarter, as a higher amount of cargo sales occurred later in the current period quarter when benchmark prices were higher, whereas cargo sales in the prior year quarter occurred during periods of lower benchmark pricing.

Price realizations for E&P International were lower in the third quarter of 2016 than the prior year quarter due to the overall decrease in benchmark prices for Brent crude and unfavourable foreign exchange rates.

Royalties were higher in the third quarter of 2016, compared with the prior year quarter, primarily due to turnaround activity in 2015 triggering minimal royalty rates in the comparative period, as well as the impacts of higher production and price realizations in the current period.

Operating and transportation expenses decreased in the third quarter of 2016, compared to the prior year quarter, primarily driven by cost reduction initiatives and lower transportation expense in the U.K. due to lower volumes and decreased tariffs.

Exploration expenses increased in the third quarter of 2016, compared to the prior year quarter, primarily due to a charge for a non-commercial deepwater exploration well at the Shelburne Basin off the east coast of Canada.

DD&A expense decreased in the third quarter of 2016, compared to the prior year quarter, primarily due to lower depletion rates at Golden Eagle as a result of the impairment charges in the fourth quarter of 2015, as well as decreased production at Buzzard due to the turnaround, partially offset by higher production at East Coast Canada.

Financing expense and other was positively impacted by the 10% U.K. tax rate reduction enacted in the third quarter of 2016.

Operating loss for E&P for the first nine months of 2016 was $44 million, compared to $57 million of operating earnings for the first nine months of 2015. The decrease was due to lower overall price realizations related to declines in benchmark crude pricing, partially offset by higher production, lower royalties and lower operating expenses.

Cash flow from operations was $928 million for the first nine months of 2016, compared to $1.129 billion for the first nine months of 2015, and decreased primarily due to the same factors that impacted operating earnings.


	Three months ended September 30		Nine months ended September 30
($ millions)	2016	2015	2016	2015

Operating revenues	4 711	5 254	12 892	15 426

Net earnings	436	625	1 366	1 800

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	—	—	—	36

Gain on significant disposal⁽²⁾	—	—	—	(68	)

Operating earnings⁽³⁾	436	625	1 366	1 768

Refining and Supply	*332*	518	*1 088*	1 472

Marketing	*104*	107	*278*	296

Cash flow from operations⁽³⁾	595	814	1 884	2 316

(1): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): After-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the second quarter of 2015.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Refining and Supply operating earnings were $332 million in the third quarter of 2016, compared to $518 million in the prior year quarter. The decrease in the third quarter of 2016 was primarily due to lower benchmark refining crack spreads and secondary product margins, as well as narrower crude price differentials, partially offset by a lower FIFO loss. The impact of record refinery crude throughput was more than offset by unfavourable refinery product mix.

Marketing activities contributed $104 million to operating earnings in the third quarter of 2016 and were comparable to $107 million in the prior year quarter, with higher retail volumes and margins in Eastern North America more than offset by weaker wholesale volumes and margins in Western North America.

Suncor advanced the sales process for its lubricants business during the quarter.


	Three months ended September 30		Nine months ended September 30
	2016	2015	2016	2015

Crude oil processed (mbbls/d)

Eastern North America	213.5	200.5	202.4	208.1

Western North America	252.1	244.3	226.6	224.6

Total	465.6	444.8	429.0	432.7

Refinery utilization⁽¹⁾ (%)

Eastern North America	96	90	91	94

Western North America	105	102	94	94

Total	101	96	93	94

Refined product sales (mbbls/d)

Gasoline	254.4	254.4	245.3	247.1

Distillate	195.2	206.3	185.9	201.6

Other	99.1	85.7	92.5	82.0

Total	548.7	546.4	523.7	530.7

Refining gross margin⁽²⁾ ($/bbl)	17.75	26.60	19.40	25.50

Refining operating expense⁽²⁾ ($/bbl)	4.55	4.70	5.00	5.10

(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): Refining gross margin per barrel and Refining operating expense per barrel are presented on the basis of total output from the company's four refineries.

Refinery crude throughput in the third quarter of 2016 is a new quarterly record at 465,600 bbls/d, compared to 444,800 bbls/d in the prior year quarter. In Eastern North America, the volume of crude oil processed increased to 213,500 bbls/d in the third quarter of 2016 from 200,500 bbls/d in the prior year quarter due to lower planned maintenance and strong reliability. The average volume of crude oil processed in Western North America increased to 252,100 bbls/d in the third quarter of 2016 from 244,300 bbls/d in the prior year quarter, primarily due to planned maintenance in the prior year quarter.

Total refined product sales of 548,700 bbls/d in the third quarter of 2016 were comparable to 546,400 bbls/d in the prior year quarter.

Refined product margins in Refining and Supply were lower in the third quarter of 2016 than in the prior year quarter, and were impacted primarily by the following factors:

Marketing margins in the third quarter of 2016 were higher than margins in the prior year quarter, primarily due to higher retail and lubricant margins, partially offset by lower wholesale margins.

Operating expenses in the third quarter of 2016 were comparable to the prior year quarter.

For the first nine months of 2016, R&M operating earnings were $1.366 billion, compared to operating earnings of $1.768 billion for the first nine months of 2015. The decrease in earnings was due primarily to lower benchmark refining crack spreads and narrower inland crude differentials, partially offset by higher refined product location differentials, higher refinery crude throughput and the positive impact of the weaker Canadian dollar. For the first nine months of the year, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO⁽¹⁾ method, had a negative impact to net earnings and cash flow from operations of approximately $3 million after-tax, compared to a negative impact of approximately $209 million after-tax in the first nine months of 2015.

Cash flow from operations was $1.884 billion for the first nine months of 2016, compared to $2.316 billion for the first nine months of 2015, and decreased primarily due to the same factors that influenced operating earnings described above.

The Montreal refinery has a seven-week planned maintenance event that began in the third quarter of 2016 and the Sarnia refinery has a five-week planned maintenance event that began in the third quarter of 2016. The anticipated impact of this maintenance has been reflected in the company's 2016 guidance.


	Three months ended September 30				Nine months ended September 30
($ millions)	2016		2015		2016		2015

Net loss	(350	)	(950	)	(163	)	(2 053	)

Adjusted for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	112		786		(746	)	1 548

Non-cash mark to market loss on interest rate swaps⁽¹⁾	22		—		182		—

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

COS acquisition and related costs⁽³⁾	—		—		38		—

Restructuring charges⁽⁴⁾	—		—		—		57

Impact of income tax rate adjustments on deferred taxes⁽⁵⁾	—		—		—		(5	)

Operating loss⁽⁶⁾	(216	)	(164	)	(616	)	(453	)

Renewable Energy	2		2		15		11

Energy Trading	(7	)	12		*(15*	)	49

Corporate	*(195*	)	(215	)	*(603*	)	(550	)

Eliminations	*(16*	)	37		*(13*	)	37

Cash flow (used in) from operations⁽⁶⁾	(171	)	30		(486	)	(301	)

(1): Non-cash loss on interest rate swaps resulting from a decrease in long-term interest rates.
(2): Charges associated with early repayment of debt.
(3): Transaction and related charges associated with the acquisition of COS.
(4): Restructuring charges related to cost reduction initiatives.
(5): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(6): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Renewable Energy had operating earnings of $2 million in the third quarter of 2016, which was comparable to the prior year quarter. Increased production from the addition of Cedar Point in the third quarter of 2016 was offset by lower operating earnings associated with the disposal of Kent Breeze and the company's share of the Wintering Hills wind power facilities in the third quarter of 2015.

In the third quarter of 2016, Suncor commenced a sale process for certain assets and associated liabilities related to its Renewable Energy business and anticipates that a sale could occur within the next twelve months.

Energy Trading had an operating loss of $7 million in the quarter, compared to operating earnings of $12 million in the prior year quarter. Narrow crude location differentials and weaker market conditions resulted in losses from crude trading in the third quarter of 2016, while natural gas trading contributed positively in the third quarter of both years.

Corporate operating loss decreased to $195 million for the third quarter of 2016, compared with $215 million for the prior year quarter, primarily due to a loss on interest rate swaps recorded in the third quarter of 2015. The third quarter of 2016 was also impacted by higher capitalized interest and lower stock-based compensation expense, partially offset by higher interest expense associated with the acquisition of COS debt in the first quarter of 2016. The company capitalized $153 million of its borrowing costs in the third quarter of 2016 as part of the cost of major development assets and construction projects in progress, compared to $115 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 2016, the company eliminated $16 million of after-tax intersegment profit, compared to $37 million of intersegment profit that was realized in the prior year quarter.

The operating loss for Corporate, Energy Trading and Eliminations for the first nine months of 2016 was $616 million, compared to an operating loss of $453 million for the first nine months of 2015. The increase was primarily due to higher interest expense associated with the acquisition of COS debt in the first quarter of 2016 and the elimination of $13 million of after-tax intersegment profit in 2016, compared to $37 million of profit that was realized in the prior year period, partially offset by higher capitalized interest in the current year. The operating loss was also impacted by gains on interest rate swaps, and crude trading strategies as a result of wider crude differentials that were recorded in the prior year period. The company capitalized $434 million of its borrowing costs in the first nine months of 2016 as part of the cost of major development assets and construction projects, compared to the $318 million capitalized in the first nine months of 2015, as a result of the progress made on the Fort Hills and Hebron projects.


	Three months ended September 30				Nine months ended September 30
($ millions)	2016		2015		2016		2015

Oil Sands	1 306		1 136		3 667		2 914

Exploration and Production	283		332		829		1 084

Refining and Marketing	101		209		502		465

Corporate, Energy Trading and Eliminations	3		59		12		174

Total capital and exploration expenditures	1 693		1 736		5 010		4 637

Less: capitalized interest on debt	(153	)	(115	)	(434	)	(318	)

	1 540		1 621		4 576		4 319


	Three months ended September 30, 2016			Nine months ended September 30, 2016
($ millions)	Sustaining	Growth	Total	Sustaining	Growth	Total

Oil Sands

Oil Sands Base	349	112	*461*	924	325	*1 249*

In Situ	12	2	14	91	20	*111*

Oil Sands ventures	89	631	*720*	251	1 742	*1 993*

Exploration and Production	1	240	241	6	708	714

Refining and Marketing	101	—	101	497	3	500

Corporate, Energy Trading and Eliminations	3	—	3	9	—	9

	555	985	1 540	1 778	2 798	4 576

(1): Capital expenditures in this table exclude capitalized interest on debt.
(2): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands operations 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.
(3): 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 operations and R&M operations.

In the third quarter of 2016, total capital and exploration expenditures were $1.540 billion (excluding capitalized interest). Capital and exploration expenditures in the third quarter of 2016 decreased relative to the prior year quarter due to cost reduction initiatives and lower planned maintenance activities, partially offset by increased ownership interests in both Fort Hills and Syncrude. Activity in the third quarter of 2016 is summarized by business unit below.

Oil Sands Base capital and exploration expenditures were $461 million in the third quarter of 2016, of which $349 million and $112 million were directed towards sustaining and growth activities, respectively. Sustaining capital included expenditures related to the planned major maintenance program, including coker maintenance at Upgrader 1, which began in the third quarter of 2016 and was completed in the fourth quarter of 2016, as well as a number of reliability and sustainment projects across the operations.

Growth capital was focused on the East Tank Farm Development, which will support market access for Fort Hills' bitumen production.

In Situ capital and exploration expenditures were $14 million, of which $12 million was directed towards sustaining activities, including 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 $720 million, of which growth capital expenditures were $631 million and sustaining capital expenditures were $89 million, respectively. Growth capital was primarily for the Fort Hills mining project, with the project now more than 70% complete and the majority of the remaining work based in Alberta. Key activities in the period included completion of the utilities modules, significant progress on modules and construction in secondary extraction, as well as procurement of mining and secondary extraction equipment. First oil remains on track for late 2017. The company is working on opportunities to mitigate the impact on overall project costs of both unfavourable foreign exchange rates and the forest fires in the second quarter of 2016 and believes Suncor's total capital intensity will be consistent with the original sanction estimate of $84,000 per flowing barrel of bitumen.

Sustaining capital expenditure at Fort Hills included development of activities that will support the mine plan following the commencement of production.

The third quarter of 2016 also included an increased share of Syncrude sustaining capital, which was primarily focused on maintaining assets and implementing the mine-tailings plan.

Construction of the Hebron project continued in the third quarter of 2016. Following the arrival of the utilities and process module from South Korea, all topside modules are now on location in Bull Arm, Newfoundland and Labrador, and integration of these modules is underway. First oil is expected in late 2017. Growth capital also included drilling at the Shelburne Basin off the east coast of Canada, including commencement of a second exploration well, as well as development drilling at Hibernia, White Rose and Golden Eagle.

Subsequent to the quarter end, Suncor acquired a 30% participating interest in the U.K. North Sea Rosebank project at an initial cost of US$50 million. If the Rosebank project final investment is approved with Suncor's participation, the company could pay additional consideration of up to US$165 million.

R&M capital expenditures were $101 million and were primarily related to planned maintenance activities at the Sarnia and Montreal refineries and the completion of a crude pipeline replacement project which supplies feedstock to the Commerce City refinery.

Corporate capital expenditures were $3 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended September 30
	2016		2015

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	(4.6	)	5.1

Including major projects in progress	(3.9	)	4.5

Net debt to cash flow from operations⁽²⁾ (times)	3.0		1.4

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	(3.0	)	1.6

Cash flow from operations basis⁽²⁾⁽⁴⁾	5.4		10.0

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this document.
(2): Cash flow from operations and metrics that use cash flow 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): Cash flow 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 2016 capital spending program of $5.8 to $6.0 billion and to meet current and future working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities for the remainder of 2016, available committed credit facilities, issuing commercial paper and, if needed, 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 $3.102 billion during the first nine months of 2016 from $4.049 billion at December 31, 2015, primarily due to capital and exploration expenditures exceeding cash flow provided by operating activities, the acquisition of an additional 5% interest in Syncrude from Murphy Oil Company Ltd. (Murphy) for $946 million, and early payment of $891 million of bonds and repayment of $600 million of bank debt acquired as part of the COS acquisition, partially offset by the $2.8 billion (net) common share equity offering completed in the second quarter of 2016.

As at September 30, 2016, the weighted average term to maturity of the short-term investment portfolio was approximately 12 days.

Available lines of credit at September 30, 2016 decreased to $6.695 billion, compared to $7.034 billion at December 31, 2015, primarily as a result of increased short-term borrowings and foreign exchange impacts on available credit facilities, partially offset by net available credit facilities added through the acquisition of COS.

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 third quarter of 2016, Suncor issued $700 million of 3.00% senior unsecured Medium Term Notes maturing on September 14, 2026 and $300 million of 4.34% senior unsecured Medium Term Notes maturing on September 13, 2046. The proceeds of the debt offering were used to pay down short-term indebtedness.

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, 2016, total debt to total debt plus shareholders' equity was 28.8% (December 31, 2015 – 28.2%). The company is currently in compliance with all operating covenants.


($ millions, except as noted)	September 30 2016	December 31 2015

Short-term debt	1 956	747

Current portion of long-term debt	55	70

Long-term debt	15 820	14 486

Total debt	17 831	15 303

Less: Cash and cash equivalents	3 102	4 049

Net debt	14 729	11 254

Shareholders' equity	43 976	39 039

Total debt plus shareholders' equity	61 807	54 342

Total debt to total debt plus shareholders' equity (%)	28.8	28.2


	Three and nine months ended September 30, 2016
($ millions)	Q3		YTD

Net debt – start of period	14 545		11 254

Increase in net debt	184		3 475

Net debt – September 30, 2016	14 729		14 729

Decrease (increase) in net debt

Cash flow from operations⁽¹⁾	2 025		3 623

Capital and exploration expenditures and other investments	(1 693	)	(5 010	)

Acquisitions	—		(946	)

Cash acquired, COS	—		109

Debt acquired, COS	—		(2 639	)

Proceeds from disposal of assets	4		196

Dividends less proceeds from exercise of share options	(478	)	(1 377	)

Change in non-cash working capital and other investments	76		(779	)

Issuance of common shares	—		2 782

Foreign exchange on cash, debt and other balances	(118	)	566

	(184	)	(3 475	)

(1): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

As at October 24, 2016, the total number of common shares outstanding was 1,664,953,005 and the total number of exercisable and non-exercisable common share options outstanding was 34,442,900. Once exercisable, each outstanding common share option is convertible into one common share.

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 2015 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, 2016, the company increased its commitments by $9.3 billion (undiscounted), which is primarily attributable to the acquisition of COS and Murphy's 5% Syncrude ownership and $1.0 billion of long-term debt issued in the third quarter of 2016, partially offset by the early payment of a portion of long-term debt acquired as part of the COS acquisition. The details of these increased commitments are outlined below.

Contractual Obligations, Commitments and Off-Balance Sheet Arrangements added in the period


	Payments due by period
($ millions, undiscounted)	2016	2017-2018	2019-2020	2020 and beyond	Total

Long-term debt	72	225	478	2 577	3 352

Decommissioning and restoration costs	18	53	78	2 746	2 895

Pipeline commitments	55	110	140	2 423	2 728

Other long-term obligations	107	142	27	49	325

Total	252	530	723	7 795	9 300

Trends in Suncor's quarterly earnings and cash flow from operations 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 forest fires in the Fort McMurray area in the second quarter of 2016.


Three months ended ($ millions, unless otherwise noted)	Sept 30 2016		June 30 2016		Mar 31 2016		Dec 31 2015		Sept 30 2015		June 30 2015	Mar 31 2015		Dec 31 2014

Total production (mboe/d)

Oil Sands	617.5		213.1		565.8		470.6		458.4		448.7	475.6		419.3

Exploration and Production	110.6		117.6		125.6		112.3		107.7		111.2	126.8		138.3

	728.1		330.7		691.4		582.9		566.1		559.9	602.4		557.6

Revenues and other income

Operating revenues, net of royalties	7 409		5 914		5 644		6 499		7 485		8 095	7 129		8 899

Other (loss) income	(15	)	(58	)	(67	)	94		72		49	257		192

	7 394		5 856		5 577		6 593		7 557		8 144	7 386		9 091

Net earnings (loss)	392		(735	)	257		(2 007	)	(376	)	729	(341	)	84

per common share – basic (dollars)	0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06

per common share – diluted (dollars)	0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06

Operating earnings (loss)⁽¹⁾	346		(565	)	(500	)	(26	)	410		906	175		386

per common share – basic⁽¹⁾ (dollars)	0.21		(0.36	)	(0.33	)	(0.02	)	0.28		0.63	0.12		0.27

Cash flow from operations⁽¹⁾	2 025		916		682		1 294		1 882		2 155	1 475		1 492

per common share – basic⁽¹⁾ (dollars)	1.22		0.58		0.45		0.90		1.30		1.49	1.02		1.03

ROCE⁽¹⁾ (%) for the twelve months ended	(4.6	)	(4.9	)	(2.2	)	0.6		5.1		7.2	5.8		8.6

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(112	)	(27	)	885		(382	)	(786	)	178	(940	)	(302	)

Common share information (dollars)

Dividend per common share	0.29		0.29		0.29		0.29		0.29		0.28	0.28		0.28

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	36.42		35.84		36.17		35.72		35.69		34.40	37.01		36.90

New York Stock Exchange (US$)	27.78		27.73		27.81		25.80		26.72		27.52	29.25		31.78

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


Three months ended (average for the period ended, except as noted)		Sept 30 2016	June 30 2016	Mar 31 2016	Dec 31 2015	Sept 30 2015	June 30 2015	Mar 31 2015	Dec 31 2014

WTI crude oil at Cushing	US$/bbl	44.95	45.60	33.50	42.15	46.45	57.95	48.65	73.15

Dated Brent crude	US$/bbl	45.85	45.60	33.90	43.70	50.30	61.95	53.85	76.25

Dated Brent/Maya FOB price differential	US$/bbl	6.80	7.65	8.95	10.35	8.50	8.15	11.05	10.05

MSW at Edmonton	Cdn$/bbl	55.10	55.80	34.50	53.55	56.55	68.05	52.25	75.95

WCS at Hardisty	US$/bbl	31.45	32.30	19.30	27.70	33.25	46.35	33.90	58.90

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	13.50	13.30	14.25	14.50	13.20	11.60	14.75	14.25

Condensate at Edmonton	US$/bbl	43.05	44.10	34.45	41.65	44.20	57.95	45.60	70.55

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.30	1.40	1.85	2.45	2.90	2.55	2.75	3.60

Alberta Power Pool Price	Cdn$/MWh	17.90	14.90	18.10	21.20	26.05	57.25	29.15	30.55

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	14.00	16.10	11.75	13.60	22.25	23.85	19.20	16.15

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	14.15	16.65	9.10	13.90	23.95	20.30	16.00	14.40

Portland 3-2-1 crack⁽¹⁾	US$/bbl	18.75	19.30	13.00	17.90	28.75	32.55	21.50	12.45

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	14.50	14.85	11.05	11.05	21.55	22.90	18.00	10.15

Exchange rate	US$/Cdn$	0.77	0.78	0.73	0.75	0.76	0.81	0.81	0.88

Exchange rate (end of period)	US$/Cdn$	0.76	0.77	0.77	0.72	0.75	0.80	0.79	0.86

(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:

plans, and $96 million in Oil Sands following a review of certain assets that no longer fit with Suncor's growth strategies and which could not be repurposed or otherwise deployed.

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 2015 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, 2015 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2015 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 26 of the audited Consolidated Financial Statements for the year ended December 31, 2015, note 14 to the unaudited interim Consolidated Financial Statements for the three and nine months ended September 30, 2016, and the Financial Condition and Liquidity section of Suncor's 2015 annual MD&A.

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.

In the second quarter of 2015, the Government of Alberta enacted an increase in the corporate income tax rate from 10% to 12% effective July 1, 2015. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax expense of $423 million.

In the first quarter of 2015, 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 62% to 50%. The company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income taxes of $406 million.

Pursuant to the previously disclosed 2013 proposal letter from the Canada Revenue Agency (CRA), the company received a Notice of Reassessment (NOR) from the CRA during the second quarter of 2014, regarding the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. The total amount of the NOR, including tax, penalty and interest, was approximately $920 million. The company strongly disagrees with the CRA's position and continues to firmly believe it will be able to successfully defend its original filing position and will take the appropriate actions to resolve this matter. In addition to the above, the company has:

If the company is unsuccessful in defending its tax filing position, it could be subject to an earnings and cash impact of up to $1.3 billion.

Based on their evaluation as at September 30, 2016, 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, 2016, 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, 2016 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 2016 corporate guidance. Suncor's press release dated October 26, 2016, which is also available on www.sedar.com, provides this update to the corporate guidance.

Certain financial measures in this MD&A – namely operating earnings (loss), ROCE, cash flow from (used in) operations, free cash flow, Oil Sands operations cash operating costs, 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. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP financial measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Except as otherwise indicated, these non-GAAP financial measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Operating earnings (loss) is a non-GAAP financial measure that adjusts net earnings (loss) for significant items that are not indicative of operating performance. Management uses operating earnings (loss) to evaluate operating performance because management believes it provides better comparability between periods. Operating earnings (loss) are reconciled to net earnings (loss) in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A.

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

ROCE is a non-GAAP financial measure that management uses to analyze operating performance and the efficiency of Suncor's capital allocation process. Average capital employed is calculated as a twelve-month average of the capital employed balance at the beginning of the twelve-month period and the month-end capital employed balances throughout the remainder of the twelve-month period. Figures for capital employed at the beginning and end of the twelve-month period are presented to show the changes in the components of the calculation over the twelve-month period.

The company presents two ROCE calculations – one including and one excluding the impacts on capital employed 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)		2016		2015

Adjustments to net earnings

Net (loss) earnings		(2 103	)	96

Add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(362	)	1 851

Net interest expense		306		306

	A	(2 159	)	2 253

Capital employed – beginning of twelve-month period

Net debt		9 551		6 573

Shareholders' equity		41 148		41 983

		50 699		48 556

Capital employed – end of twelve-month period

Net debt		14 729		9 551

Shareholders' equity		43 976		41 148

		58 705		50 699

Average capital employed	B	56 010		50 299

ROCE – including major projects in progress (%)	A/B	(3.9	)	4.5

Average capitalized costs related to major projects in progress	C	9 351		6 569

ROCE – excluding major projects in progress (%)	A/(B–C)	(4.6	)	5.1

Cash flow 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.

Cash flow from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the cash flow from (used in) operations for the particular quarter ended September 30 and each of the three preceding quarters. Cash flow from (used in) operations for each quarter are separately defined and reconciled to GAAP measures 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)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net earnings (loss)	162		(50	)	144		(1	)	436		625		(350	)	(950	)	392		(376	)

Adjustments for:

Depreciation, depletion, amortization and impairment	971		790		270		340		164		172		34		31		1 439		1 333

Deferred income taxes	62		30		(198	)	(106	)	(8	)	(20	)	7		33		(137	)	(63	)

Accretion of liabilities	54		34		11		13		1		2		1		—		67		49

Unrealized foreign exchange loss on U.S. dollar denominated debt	—		—		—		—		—		—		121		800		121		800

Change in fair value of financial instruments and trading inventory	6		2		—		—		5		14		(16	)	25		(5	)	41

Loss (gain) on disposal of assets	—		1		—		—		(13	)	(4	)	—		—		(13	)	(3	)

Share-based compensation	20		26		3		3		11		14		33		52		67		95

Exploration expenses	—		—		139		16		—		—		—		—		139		16

Settlement of decommissioning and restoration liabilities	(43	)	(46	)	—		(1	)	(5	)	(6	)	—		—		(48	)	(53	)

Other	4		(2	)	(4	)	(11	)	4		17		(1	)	39		3		43

Cash flow from (used in) operations	1 236		785		365		253		595		814		(171	)	30		2 025		1 882

(Increase) decrease in non-cash working capital	(502	)	399		(56	)	13		(395	)	157		907		320		(46	)	889

Cash flow provided by operating activities	734		1 184		309		266		200		971		736		350		1 979		2 771


Nine months ended September 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net (loss) earnings	(1 425	)	(240	)	136		505		1 366		1 800		(163	)	(2 053	)	(86	)	12

Adjustments for:

Depreciation, depletion, amortization and impairment	2 826		2 323		1 087		1 043		506		509		97		96		4 516		3 971

Deferred income taxes	(64	)	346		(462	)	(656	)	15		15		69		106		(442	)	(189	)

Accretion of liabilities	155		106		43		37		5		5		1		(2	)	204		146

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(771	)	1 581		(771	)	1 581

Change in fair value of financial instruments and trading inventory	19		34		—		—		28		92		218		(76	)	265		50

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

(Gain) loss on disposal of assets	(33	)	8		—		(5	)	(14	)	(105	)	—		(3	)	(47	)	(105	)

Share-based compensation	(16	)	(8	)	5		6		(11	)	(9	)	(37	)	(41	)	(59	)	(52	)

Exploration expenses	—		—		139		214		—		—		—		—		139		214

Settlement of decommissioning and restoration liabilities	(193	)	(240	)	—		(2	)	(13	)	(13	)	—		—		(206	)	(255	)

Other	28		39		(20	)	(13	)	2		22		1		91		11		139

Cash flow from (used in) operations	1 297		2 368		928		1 129		1 884		2 316		(486	)	(301	)	3 623		5 512

(Increase) decrease in non-cash working capital	(600	)	(25	)	(96	)	277		(195	)	(118	)	157		(205	)	(734	)	(71	)

Cash flow provided by (used in) operating activities	697		2 343		832		1 406		1 689		2 198		(329	)	(506	)	2 889		5 441

Free cash flow is a non-GAAP financial measure that is calculated by deducting capital and exploration expenditures for the twelve-month period from cash flow from operations for the same period. Free cash flow reflects cash available for distribution to shareholders and to fund financing activities. Management uses free cash flow to measure financial performance and liquidity.

Oil Sands operations cash operating costs and cash operating costs per barrel are non-GAAP financial measures, which are calculated by adjusting Oil Sands operations OS&G expense (a GAAP measure based on sales volumes) to a production basis (a non-GAAP measure based on production volumes) by adjusting for the impacts of changes in inventory levels. Oil Sands operations cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this MD&A. Management uses Oil Sands operations cash operating costs to measure Oil Sands operating performance on a production barrel basis.

Oil Sands operations cash operating costs and cash operating costs per barrel are also adjusted 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 revenues; and iv) project start-up costs.

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

GAAP requires the use of a FIFO inventory valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflects market conditions at the time when 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	ICE	Intercontinental Exchange
	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; capital efficiencies and cost-savings; applicable 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; 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 and information 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" and similar expressions. Forward-looking statements in the document include references to:

Forward-looking statements and information 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 taxes or changes to fees and royalties, such as the NORs received by Suncor from the CRA, Ontario, Alberta and Quebec, relating to the settlement of certain derivative contracts, including the risk that: (i) Suncor may not be able to successfully defend its original filing position and ultimately be required to pay increased taxes, interest and penalty as a result; or (ii) Suncor may be required to post cash instead of security in relation to the NORs; changes in environmental and other regulations; 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, 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 systems 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; risks and uncertainties associated with closing a transaction for the purchase or sale of an 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 that are customary to transactions of this nature; 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 2015 annual MD&A, 2015 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, 2016

Common shares		1 664 528

Common share options – exercisable		20 952

Common share options – non-exercisable		13 944


	Twelve months ended September 30
($ millions)	2016		2015

Cash flow from operations	4 917		7 004

Less: Capital and exploration expenditures	7 040		6 537

Free Cash Flow	(2 123	)	467


1.	Advisories	6
2.	Third Quarter Highlights	8
3.	Consolidated Financial Information	9
4.	Segment Results and Analysis	14
5.	Capital Investment Update	26
6.	Financial Condition and Liquidity	28
7.	Quarterly Financial Data	32
8.	Other Items	34
9.	Non-GAAP Financial Measures Advisory	36
10.	Common Abbreviations	41
11.	Forward-Looking Information	42