All financial figures are unaudited and presented in Canadian dollars (Cdn$) unless noted otherwise. Production volumes are presented on a working-interest basis, before royalties, unless noted otherwise. Certain financial measures in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these non-GAAP financial measures, see the Non-GAAP Financial Measures Advisory section in this Report to Shareholders (this document). See also the Advisories section of this document. References to Oil Sands operations exclude Suncor's interest in Syncrude's operations.

"Suncor generated $2.4 billion in cash in the fourth quarter thanks to strong contributions from all of our assets and our focus on cost management," said Steve Williams, president and chief executive officer. "Reliable performance throughout the year has helped us overcome challenging crude pricing and the major production outage associated with the Fort McMurray forest fires, resulting in annual cash flow significantly exceeding our annual sustaining capital and dividend commitments."

Suncor recorded fourth quarter 2016 operating earnings⁽¹⁾ of $636 million ($0.38 per common share), compared to an operating loss of $26 million ($0.02 per common share) in the prior year quarter. The increase in operating earnings is primarily attributed to improved benchmark crude pricing, an R&M FIFO gain and higher Syncrude operating earnings, which were a result of the acquisition of additional working interests in 2016 and significantly improved Syncrude upgrader reliability. Lower operating costs at both Oil Sands operations and E&P also contributed to the improvement.

Funds from operations⁽¹⁾ (previously referred to as cash flow from operations) was $2.365 billion ($1.42 per common share) compared to $1.294 billion ($0.90 per common share) in the fourth quarter of 2015, with the improvement being attributed to the same factors noted above in operating earnings.

Net earnings were $531 million ($0.32 per common share) in the fourth quarter of 2016, compared with a net loss of $2.007 billion ($1.38 per common share) in the prior year quarter. In addition to the operating earnings factors noted above, net earnings for the fourth quarter of 2016 included an unrealized after-tax foreign exchange loss of $222 million on the revaluation of U.S. dollar denominated debt, a non-cash after-tax mark to market gain of $188 million on interest rate derivatives for future debt issuance and $71 million of after-tax derecognition charges. The net loss in the prior year quarter included $1.599 billion of non-cash impairment charges and an unrealized after-tax foreign exchange loss of $382 million on the revaluation of U.S. dollar denominated debt.

Suncor's total upstream production achieved a new quarterly record of 738,500 boe/d in the fourth quarter of 2016, compared with 582,900 boe/d in the prior year quarter. The increase was primarily due to the additional 41.74% ownership interest in Syncrude acquired during 2016, combined with significantly improved Syncrude upgrader reliability. Higher E&P production in the fourth quarter of 2016 was offset by slightly lower production at Oil Sands operations, when compared to the prior year period.

Despite continued strong Oil Sands operations production of 433,400 bbls/d in the fourth quarter of 2016, there was a slight decrease from 439,700 bbls/d in the prior year quarter due to increased unplanned maintenance in the fourth quarter of 2016. The production mix in the fourth quarter of 2016 was favourably impacted by an increased proportion of synthetic crude oil (SCO), as a result of a decrease in planned upgrader maintenance compared to the prior year quarter. The increase in SCO production was offset by a decrease in non-upgraded bitumen production.

Oil Sands operations cash operating costs per barrel⁽¹⁾ decreased in the fourth quarter of 2016 to $24.95, compared to $28.00 in the prior year quarter, due to lower operating expenses as a result of the company's ongoing cost reduction initiatives, partially offset by higher natural gas prices.

Suncor's share of Syncrude sweet SCO production was 187,000 bbls/d in the fourth quarter of 2016, compared to 30,900 bbls/d in the prior year quarter. The significant increase is due to additional Syncrude working interests acquired in 2016, combined with continued strong upgrader reliability. Upgrader utilization was 102% of nameplate capacity in the period, compared to 73% in the prior year quarter. Syncrude's cash operating costs per barrel in the fourth quarter of 2016 decreased to $32.55/bbl from $40.15/bbl in the prior year quarter, due primarily to increased production, partially offset by higher operating expenses attributed to higher natural gas prices.

Production volumes in E&P increased to 118,100 boe/d in the fourth quarter of 2016, compared to 112,300 boe/d in the prior year quarter, primarily due to production from new wells at Hibernia and reservoir optimization combined with improved reliability at Terra Nova, partially offset by planned maintenance at Buzzard and natural declines at White Rose.

Average refinery crude throughput was 427,300 bbls/d compared with 430,200 bbls/d in the prior year quarter.

"Our cost reduction efforts have resulted in significant savings in the year, well exceeding the targets we set out in early 2016, and the improvement in Syncrude's reliability in consecutive periods has been impressive," said Williams. "We have achieved a step change in operating efficiency this year, which has resulted in cash operating costs per barrel at our Oil Sands operations being consistently below $25, excluding the impact of the forest fires."

Significant progress on key growth projects, Fort Hills and Hebron, continued in the fourth quarter of 2016, as well as investment in existing assets to ensure continued safe, reliable and efficient operations. The disciplined execution of the company's 2016 capital plan resulted in capital expenditures of $5.986 billion, excluding capitalized interest, which was within the revised guidance range of $5.8 billion to $6.0 billion. The revised capital guidance represented a decrease of over $1.0 billion from the midpoint of the original range.

The Fort Hills project was more than 76% complete at the end of the fourth quarter of 2016, with the remaining work to be based at site. Activity in the period included completion of the secondary extraction module program; construction in secondary extraction and utilities has achieved peak activity and continues to focus on productivity and achieving critical milestones. Early-works sustaining activities that will support the execution of the mine and tailings plan following the commencement of production also continued in the fourth quarter.

The company has assessed the impact of the construction delay due to the forest fires in the second quarter of 2016, and other construction changes associated with the complexity and scale of secondary extraction detailed design development, and now estimates the overall cost of the Fort Hills project to be between $16.5 and $17.0 billion. Suncor's share of Fort Hills' remaining project capital is between $1.6 and $1.8 billion. The majority of the spend will occur in 2017 and will be completed within Suncor's existing capital guidance range. In addition, the company has increased the nameplate capacity to 194,000 bbls/d after optimization and technical review. With these changes, Suncor's total capital intensity is expected to remain consistent with the original sanction estimate of $84,000 per flowing barrel of bitumen. First oil continues to remain on track for late 2017.

Construction of the Hebron project continued in the fourth quarter of 2016, with the integrated topside modules being successfully towed out to the deepwater construction site and mated with the gravity-based structure in the period. First oil from the project continues to be on track for late 2017. Growth capital at E&P also included drilling of a second exploration well at the Shelburne Basin off the east coast of Canada, with the costs subsequently charged to exploration expense within the period, as well as development drilling at Hibernia and White Rose.

"Bringing our key major growth projects, Fort Hills and Hebron, to first oil by the end of this year continues to be a top strategic priority for us," said Williams. "We are encouraged by key milestone achievements at both Fort Hills and Hebron and with the increased capacity of Fort Hills, which means we expect to achieve the capital intensity targets established at the time we sanctioned the Fort Hills project in 2013."

Oil Sands operations' focus in the fourth quarter of 2016 was on ensuring continued safe, reliable and efficient operations and progress was made on key reliability, safety and environmental performance projects. Capital spending in the fourth quarter of 2016 included continued construction of the East Tank Farm Development and completion of planned maintenance at Upgrader 1, which commenced in the third quarter of 2016.

The fourth quarter of 2016 also included an increased share of Syncrude sustaining capital, which was primarily focused on key reliability, safety and environmental projects.

Suncor successfully reached agreements to sell its Petro-Canada lubricants business and its interest in the Cedar Point wind facility. Both transactions closed in the first quarter of 2017, with cash received of $1.4 billion. This brought total anticipated divestment proceeds to $2.0 billion since the start of 2016, significantly exceeding the company's target of $1.0 to $1.5 billion.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Net earnings (loss)	531		(2 007	)	445		(1 995	)

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	222		382		(524	)	1 930

Non-cash mark to market gain on interest rate swaps⁽²⁾	(188	)	—		(6	)	—

Derecognition and impairments⁽³⁾	71		1 599		71		1 599

Impact of income tax rate adjustments on deferred taxes⁽⁴⁾	—		—		(180	)	17

Non-cash loss on early payment of long-term debt⁽⁵⁾	—		—		73		—

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

Gain on significant disposal⁽⁷⁾	—		—		—		(68	)

Restructuring charges⁽⁸⁾	—		—		—		57

Insurance proceeds⁽⁹⁾	—		—		—		(75	)

Operating earnings (loss)⁽¹⁾	636		(26	)	(83	)	1 465

(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 this document.
(2): Non-cash gain on interest rate swaps resulting from an increase in long-term interest rates in the Corporate segment.
(3): During the fourth quarter of 2016, the company recorded after-tax derecognition charges of $40 million on certain upgrading and logistics assets in the Oil Sands segment as a result of the uncertainty of future benefits from these assets, as well as $31 million in the Corporate segment relating to an initial investment in an undeveloped pipeline and on certain renewable energy development assets as a result of the uncertainty of future benefits from these assets. During the fourth quarter of 2015, the company recorded after-tax impairment charges of $798 million on certain offshore E&P assets as a result of declining crude oil pricing, $415 million against the company's Libyan assets, $290 million on the company's interest in the Joslyn mining project and $96 million related to certain assets in the Oil Sands segment following a review of repurpose options due to previously revised growth strategies.
(4): The year ended December 31, 2016 was impacted by an adjustment to the company's deferred income taxes resulting from a 10% decrease in the United Kingdom (U.K.) tax rate on oil and gas profits from the North Sea. The year ended December 31, 2015 was impacted by a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea, which was more than offset by a 2% increase in the Alberta corporate income tax rate.
(5): Charges associated with early repayment of debt in the Corporate segment.
(6): Transaction and related charges associated with the acquisition of Canadian Oil Sands Limited (COS) in the Corporate segment.
(7): 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.
(8): Restructuring charges related to cost reduction initiatives in the Corporate segment.
(9): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

There have been no changes to the corporate guidance ranges previously issued on November 17, 2016. For further details and advisories regarding Suncor's 2017 corporate guidance, see www.suncor.com/guidance.

Certain natural gas volumes in this report to shareholders have been converted to boe on the basis of one bbl to six mcf. See the Advisories section of this document.

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 Income (Loss) have been reclassified to conform to the current year's presentation.

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

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations (previously referred to as 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 document and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this document. Funds from (used in) operations (previously referred to as 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 document.

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 document. This document 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 document 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 document, refer to the Common Abbreviations section of this document.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Net earnings (loss)

Oil Sands	276		(616	)	(1 149	)	(856	)

Exploration and Production	54		(1 263	)	190		(758	)

Refining and Marketing	524		506		1 890		2 306

Corporate, Energy Trading and Eliminations	(323	)	(634	)	(486	)	(2 687	)

Total	531		(2 007	)	445		(1 995	)

Operating earnings (loss)⁽¹⁾

Oil Sands	316		(230	)	(1 109	)	(111	)

Exploration and Production	54		(50	)	10		7

Refining and Marketing	524		506		1 890		2 274

Corporate, Energy Trading and Eliminations	(258	)	(252	)	(874	)	(705	)

Total	636		(26	)	(83	)	1 465

Funds from (used in) operations⁽²⁾

Oil Sands	1 372		467		2 669		2 835

Exploration and Production	385		257		1 313		1 386

Refining and Marketing	722		605		2 606		2 921

Corporate, Energy Trading and Eliminations	(114	)	(35	)	(600	)	(336	)

Total	2 365		1 294		5 988		6 806

Capital and Exploration Expenditures⁽³⁾

Sustaining	497		952		2 275		2 602

Growth	913		949		3 711		3 618

Total	1 410		1 901		5 986		6 220


	Three months ended December 31		Twelve months ended December 31
	2016	2015	2016	2015

Production volumes by segment

Oil Sands (mbbls/d)	620.4	470.6	504.9	463.4

Exploration and Production (mboe/d)	118.1	112.3	117.9	114.4

Total	738.5	582.9	622.8	577.8

Production mix

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

Refinery utilization (%)	93	93	93	94

Refinery crude oil processed (mbbls/d)	427.3	430.2	428.6	432.1

Suncor's consolidated net earnings for the fourth quarter of 2016 were $531 million, compared with a net loss of $2.007 billion in the prior year quarter. Net earnings for the year were $445 million, compared to a net loss of $1.995 billion in the prior year. Net earnings were affected by the same factors that influenced operating earnings described subsequently in this section. Other items affecting net earnings over these periods included:


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Net earnings (loss)	531		(2 007	)	445		(1 995	)

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	222		382		(524	)	1 930

Non-cash mark to market gain on interest rate swaps⁽²⁾	(188	)	—		(6	)	—

Derecognition and impairments⁽³⁾	71		1 599		71		1 599

Impact of income tax rate adjustments on deferred taxes⁽⁴⁾	—		—		(180	)	17

Non-cash loss on early payment of long-term debt⁽⁵⁾	—		—		73		—

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

Gain on significant disposal⁽⁷⁾	—		—		—		(68	)

Restructuring charges⁽⁸⁾	—		—		—		57

Insurance proceeds⁽⁹⁾	—		—		—		(75	)

Operating earnings (loss)⁽¹⁾	636		(26	)	(83	)	1 465

(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 this document.
(2): Non-cash gain on interest rate swaps resulting from an increase in long-term interest rates in the Corporate segment.
(3): During the fourth quarter of 2016, the company recorded after-tax derecognition charges of $40 million on certain upgrading and logistics assets in the Oil Sands segment as a result of the uncertainty of future benefits from these assets, as well as $31 million in the Corporate segment relating to an initial investment in an undeveloped pipeline and on certain renewable energy development assets as a result of the uncertainty of future benefits from these assets. During the fourth quarter of 2015, the company recorded after-tax impairment charges of $798 million on certain offshore E&P assets as a result of declining crude oil pricing, $415 million against the company's Libyan assets, $290 million on the company's interest in the Joslyn mining project and $96 million related to certain assets in the Oil Sands segment following a review of repurpose options due to previously revised growth strategies.
(4): The year ended December 31, 2016 was 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 year ended December 31, 2015 was impacted by a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea, which was more than offset by a 2% increase in the Alberta corporate income tax rate.
(5): Charges associated with early repayment of debt in the Corporate segment.
(6): Transaction and related charges associated with the acquisition of COS in the Corporate segment.
(7): 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.
(8): Restructuring charges related to cost reduction initiatives in the Corporate segment.
(9): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

Suncor's consolidated operating earnings for the fourth quarter of 2016 were $636 million compared to an operating loss of $26 million in the prior year quarter, with the increase attributed to improved benchmark crude pricing, an R&M FIFO gain, a higher share of Syncrude operating earnings and lower operating costs at Oil Sands operations and E&P. The increased share of Syncrude operating earnings was a result of the acquisition of additional working interests in 2016 combined with significantly improved Syncrude upgrader reliability.

Suncor's consolidated operating loss in 2016 was $83 million, compared to operating earnings of $1.465 billion in the prior year. The decrease was primarily due to lower upstream price realizations in the first nine months of 2016, consistent with the decline in benchmark crude prices, the impact of shut-in production associated with the forest fires in the Fort McMurray area in the second quarter of 2016, and weaker benchmark crack spreads. These factors were partially offset by an R&M FIFO gain, when compared to a FIFO loss in the prior year, a higher share of Syncrude production, which was a result of the acquisition of additional working interests in 2016, combined with significantly improved upgrader reliability in the second half of the year, lower operating costs across the company's operated assets, and higher refined product location differentials.

The after-tax share-based compensation expense increased to $153 million during the fourth quarter of 2016 compared to $59 million during the prior year quarter as a result of a larger increase in the company's share price in the fourth 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
December 31

Average for twelve months ended
December 31

2016

2015

2016

2015

WTI crude oil at Cushing

US$/bbl

49.35

42.15

43.35

48.75

Dated Brent crude

US$/bbl

49.50

43.70

43.75

52.40

Dated Brent/Maya crude oil FOB price differential

US$/bbl

6.70

10.35

7.50

9.50

MSW at Edmonton

Cdn$/bbl

62.00

53.55

51.90

57.60

WCS at Hardisty

US$/bbl

35.00

27.70

29.55

35.25

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

US$/bbl

14.35

14.50

13.85

13.50

Condensate at Edmonton

US$/bbl

48.35

41.65

42.50

47.35

Natural gas (Alberta spot) at AECO

Cdn$/mcf

3.10

2.45

2.15

2.65

Alberta Power Pool Price

Cdn$/MWh

21.95

21.20

18.20

33.40

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

14.35

13.60

14.05

19.70

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

10.55

13.90

12.60

18.50

Portland 3-2-1 crack⁽¹⁾

US$/bbl

14.95

17.90

16.50

25.15

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

13.15

11.05

13.40

18.35

Exchange rate

US$/Cdn$

0.75

0.75

0.75

0.78

Exchange rate (end of period)

US$/Cdn$

0.74

0.72

0.74

0.72

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

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 fourth quarter of 2016 for sweet SCO were positively affected by a higher WTI price of US$49.35/bbl, compared to US$42.15/bbl in the prior year quarter, partially offset by an unfavourable differential for sweet SCO relative to WTI. Suncor also produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $62.00/bbl compared to $53.55/bbl in the prior year quarter and prices for WCS at Hardisty increased to US$35.00/bbl from US$27.70 in the fourth 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 which increased to an average of US$49.50/bbl in the fourth quarter of 2016, compared to US$43.70/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 increased to $3.10/mcf in the fourth quarter of 2016, from $2.45/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 sweet/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 affected 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 increased to an average of $21.95/MWh in the fourth quarter of 2016 from $21.20/MWh in the prior year quarter.

The majority of Suncor's revenue from the sale of oil and natural gas commodities is 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 fourth quarter of 2016, the Canadian dollar remained unchanged in relation to the U.S. dollar as the average exchange rate for both of the fourth quarters of 2016 and 2015 was US$0.75 per one Canadian dollar.

Suncor also has assets and liabilities, notably 75% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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 December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Gross revenues	3 356		2 017		9 522		9 332

Less: Royalties	(4	)	(10	)	(52	)	(114	)

Operating revenues, net of royalties	3 352		2 007		9 470		9 218

Net earnings (loss)	276		(616	)	(1 149	)	(856	)

Adjusted for:

Derecognition and impairments⁽¹⁾	40		386		40		386

Impact of income tax rate adjustments on deferred taxes⁽²⁾	—		—		—		359

Operating earnings (loss)⁽³⁾	316		(230	)	(1 109	)	(111	)

Oil Sands operations	*192*		(231	)	*(1 135*	)	(33	)

Oil Sands ventures	*124*		1		26		(78	)

Funds from operations⁽⁴⁾	1 372		467		2 669		2 835

(1): During the fourth quarter of 2016, the company recorded after-tax derecognition charges of $40 million on certain upgrading and logistics assets in Oil Sands operations as a result of the uncertainty of future benefits from those assets. In the fourth quarter of 2015, the company recorded after-tax impairment charges of $290 million on its interest in the Joslyn mining project and $96 million related to certain assets in Oil Sands operations.
(2): 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.
(3): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.
(4): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

Operating earnings for Oil Sands operations were $192 million, compared to an operating loss of $231 million in the prior year quarter. The improvement is due to higher crude price realizations, consistent with increased benchmark pricing, combined with lower operating and maintenance expenses attributable to the company's cost reduction initiatives, and favourable royalty audit settlements, partially offset by higher natural gas prices.

Operating earnings for Oil Sands ventures were $124 million in the fourth quarter of 2016, compared to operating earnings of $1 million in the prior year quarter, with the increase primarily due to a higher share of Syncrude operating earnings as a result of additional working interests acquired in 2016. The improvement in Syncrude operating earnings is attributed to improved upgrader utilization combined with higher price realizations, partially offset by increased royalty expense and higher natural gas prices.


	Three months ended December 31		Twelve months ended December 31
(mbbls/d)	2016	2015	2016	2015

Upgraded product (SCO and diesel)	324.5	292.2	258.9	320.1

Non-upgraded bitumen	108.9	147.5	115.9	113.5

Oil Sands operations	433.4	439.7	374.8	433.6

Oil Sands ventures – Syncrude sweet SCO	187.0	30.9	130.1	29.8

Total	620.4	470.6	504.9	463.4

(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 December 31		Twelve months ended December 31
(mbbls/d)	2016	2015	2016	2015

Oil Sands operations sales volumes

Sweet SCO	87.2	100.2	87.3	107.0

Diesel	28.4	29.4	21.2	31.3

Sour SCO	201.5	154.2	153.4	182.5

Upgraded product	317.1	283.8	261.9	320.8

Non-upgraded bitumen	103.5	136.3	117.4	107.7

Oil Sands operations	420.6	420.1	379.3	428.5

Oil Sands ventures – Syncrude sweet SCO	187.0	30.9	130.1	29.8

Total	607.6	451.0	509.4	458.3

Production volumes for Oil Sands operations were 433,400 bbls/d in the fourth quarter of 2016, compared to 439,700 bbls/d in the prior year quarter, with the decrease attributed to an increase in unplanned maintenance in the current period. The fourth quarter of 2016 benefited from a favourable production mix, with an increase in higher value SCO production resulting in lower bitumen exports. Upgrader utilization at Oil Sands operations improved to 93%, compared to 83% in the prior year quarter, due to a decrease in planned upgrader maintenance in the fourth quarter of 2016.

Sales volumes for Oil Sands operations of 420,600 bbls/d in the fourth quarter of 2016 were comparable to 420,100 bbls/d in the prior year quarter, with a smaller build in inventory during the fourth quarter of 2016.

Syncrude sweet SCO production increased to 187,000 bbls/d in the fourth quarter of 2016, compared to 30,900 bbls/d in the prior year quarter. The increase is due to additional working interests acquired in 2016 combined with significantly improved upgrader reliability. Syncrude upgrader utilization was 102% of nameplate capacity in the quarter, compared to 73% in the prior year quarter.


	Three months ended December 31		Twelve months ended December 31
	2016	2015	2016	2015

Oil Sands Base

Bitumen production (mbbls/d)	284.8	292.4	238.0	307.3

Bitumen ore mined (thousands of tonnes per day)	420.3	433.7	351.1	461.3

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

In Situ

Bitumen production – Firebag (mbbls/d)	204.5	198.8	180.8	186.9

Bitumen production – MacKay River (mbbls/d)	33.9	34.5	27.6	30.7

Total In Situ bitumen production	238.4	233.3	208.4	217.6

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

Steam-to-oil ratio – MacKay River	3.1	3.0	3.2	2.9

Oil Sands Base bitumen production from mining and extraction activities averaged 284,800 bbls/d in the fourth quarter of 2016, compared to 292,400 bbls/d in the prior year quarter, due to an increase in unplanned maintenance in the current period.

In Situ bitumen production increased to 238,400 bbls/d in the fourth quarter of 2016, compared to 233,300 bbls/d in the prior year quarter. The increase was primarily driven by increased production at Firebag due to continued strong reliability.

Both Firebag and MacKay River's steam-to-oil ratios were comparable with the prior year quarter.


Net of transportation costs, but before royalties	Three months ended December 31				Twelve months ended December 31
($/bbl)	2016		2015		2016		2015

Oil Sands operations

SCO and diesel	58.30		51.33		49.77		56.45

Bitumen	26.16		18.58		18.12		25.92

Crude sales basket (all products)	50.39		40.69		39.97		48.78

Crude sales basket, relative to WTI	(15.41	)	(15.51	)	(17.83	)	(13.72	)

Oil Sands ventures

Syncrude – sweet SCO	63.93		59.83		56.38		59.74

Syncrude, relative to WTI	(1.87	)	3.63		(1.42	)	(2.76	)

Average price realizations from Oil Sands operations increased to $50.39/bbl in the fourth quarter of 2016 from $40.69/bbl in the prior year quarter, primarily due to higher WTI benchmark prices and a favourable sales mix that included a greater proportion of higher value SCO, partially offset by unfavourable changes in SCO differentials.

Average price realizations at Syncrude increased to $63.93/bbl in the fourth quarter of 2016 from $59.83/bbl in the prior year quarter due to an increase in the WTI benchmark price, partially offset by unfavourable changes in SCO differentials.

Royalties for the Oil Sands segment decreased in the fourth quarter of 2016 compared to the prior year quarter, as a result of favourable royalty audit settlements at Oil Sands operations more than offsetting higher Syncrude royalties.

Operating expenses for the fourth quarter of 2016 decreased on a per unit basis at Oil Sands operations due to the impact of Suncor's cost reduction initiatives. At Syncrude, per unit costs decreased primarily as a result of increased production. Absolute operating and transportation costs have increased from the prior year quarter, primarily due to the company's increased working interest in Syncrude and higher 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 fourth quarter of 2016 was higher in comparison to the same period of 2015 as a result of the increased working interest in Syncrude.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Oil Sands operations cash operating cost reconciliation

Operating, selling and general expense (OS&G)	1 634		1 317		5 777		5 220

Syncrude OS&G	(577	)	(118	)	(1 749	)	(471	)

Non-production costs⁽¹⁾	(54	)	(28	)	(136	)	(97	)

Excess power capacity and other⁽²⁾	(51	)	(60	)	(197	)	(245	)

Inventory changes	42		21		(63	)	—

Oil Sands operations cash operating costs⁽³⁾	994		1 132		3 632		4 407

Oil Sands operations cash operating costs ($/bbl)⁽³⁾	24.95		28.00		26.50		27.85

Syncrude cash operating costs

Syncrude cash operating costs⁽⁴⁾	560		116		1 718		464

Syncrude cash operating costs ($/bbl)	32.55		40.15		35.95		42.00

(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 cogeneration units 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 document.
(4): Syncrude cash operating costs are presented on a sales basis, after deducting non-production costs, primarily relating to research and development.

Oil Sands operations cash operating costs per barrel decreased to $24.95 in the fourth quarter of 2016, compared to $28.00 in the prior year quarter, due to lower operating and maintenance costs as a result of the company's cost reduction initiatives, partially offset by higher natural gas input costs. Total Oil Sands operations cash operating costs decreased to $994 million from $1.132 billion in the prior year quarter, despite a $45 million increase in natural gas costs.

In the fourth quarter of 2016, non-production costs, which are excluded from Oil Sands operations cash operating costs, were higher than the prior year quarter, primarily due to an increase in stock-based compensation which was attributed to an increase in the company's share price.

Inventory changes in the fourth quarter of 2016 represent a smaller build than the prior year quarter; however, the fourth quarter of 2015 was impacted by a write-down of inventory to fair market value.

Syncrude cash operating costs per barrel decreased to $32.55 in the fourth quarter of 2016, compared to $40.15 in the previous year quarter, due to higher production, which was attributable to improved reliability. Suncor's share of Syncrude cash operating costs increased to $560 million from $116 million in the previous year quarter due to the additional Syncrude working interests acquired in 2016.

Planned coker maintenance at Oil Sands Base has been scheduled to commence at the end of the first quarter of 2017, with completion anticipated in the second quarter of 2017. The impact of this maintenance has been reflected in the company's 2017 guidance.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Gross revenues	742		505		2 444		2 612

Less: Royalties	(95	)	(33	)	(213	)	(267	)

Operating revenues, net of royalties	647		472		2 231		2 345

Net earnings (loss)	54		(1 263	)	190		(758	)

Adjusted for:

Impairments⁽¹⁾	—		1 213		—		1 213

Impact of income tax rate adjustments on deferred taxes⁽²⁾	—		—		(180	)	(373	)

Insurance proceeds⁽³⁾	—		—		—		(75	)

Operating earnings (loss)⁽⁴⁾	54		(50	)	10		7

E&P Canada	2		(9	)	*(58*	)	(14	)

E&P International	52		(41	)	68		21

Funds from operations⁽⁵⁾	385		257		1 313		1 386

(1): After-tax impairment charges of $798 million on certain offshore E&P assets as a result of declining crude oil pricing and $415 million against the company's Libyan assets.
(2): 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.
(3): Business interruption insurance proceeds for the Terra Nova asset in the E&P segment.
(4): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.
(5): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

Operating earnings of $2 million for E&P Canada compared with an operating loss of $9 million in the prior year quarter, with the improvement due to higher crude price realizations, consistent with increased benchmark pricing, higher production and lower operating costs, partially offset by increased exploration expenses and higher royalties.

Operating earnings of $52 million for E&P International improved from an operating loss of $41 million in the prior year quarter, primarily due to decreased DD&A expense, higher crude price realizations, a reduced tax rate in the U.K. and lower operating expenses, partially offset by decreased production at Buzzard due to planned turnaround activities in the fourth quarter of 2016.


	Three months ended December 31		Twelve months ended December 31
	2016	2015	2016	2015

E&P Canada

Terra Nova (mbbls/d)	16.7	13.1	12.4	13.5

Hibernia (mbbls/d)	30.1	15.6	26.8	18.1

White Rose (mbbls/d)	10.9	14.8	10.9	12.2

North America Onshore (mboe/d)	2.8	3.1	2.8	3.2

	60.5	46.6	52.9	47.0

E&P International

Buzzard (mboe/d)	37.5	45.5	46.0	49.8

Golden Eagle (mboe/d)	19.0	17.7	18.6	14.8

United Kingdom (mboe/d)	56.5	63.2	64.6	64.6

Libya (mbbls/d)⁽¹⁾	1.1	2.5	0.4	2.8

	57.6	65.7	65.0	67.4

Total Production (mboe/d)	118.1	112.3	117.9	114.4

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

(1): Effective in the fourth quarter of 2016, production volumes for Libya are presented on an entitlement basis, whereas 2015 production is on a working-interest basis.

E&P Canada production was 60,500 boe/d in the fourth quarter of 2016, compared to 46,600 boe/d in the prior year quarter. The improvement was a result of higher production at Hibernia, with new wells being brought online in 2016, and higher production at Terra Nova due to reservoir optimization and improved reliability, combined with a decrease in maintenance. The fourth quarter of 2015 was impacted by a planned turnaround at Hibernia, as well as unplanned maintenance at Terra Nova.

E&P International production averaged 57,600 boe/d in the fourth quarter of 2016, compared to 65,700 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 and was completed in the fourth quarter of 2016. This was partially offset by higher production at Golden Eagle, which returned to peak production rates in the period following the completion of planned maintenance in the third quarter of 2016. Production in Libya remained substantially shut in during the fourth quarter of 2016 and the timing of a return to normal operations remains uncertain.

Price realizations for E&P Canada and E&P International were both higher in the fourth quarter of 2016, compared to the prior year quarter, due to increases in benchmark crude prices.

Royalties were higher in the fourth quarter of 2016, compared with the prior year quarter, primarily due to higher crude price realizations and higher production in East Coast Canada.

Operating and transportation expenses decreased in the fourth 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 fourth quarter of 2016, compared to the prior year quarter, primarily due to a charge for a second deepwater exploration well at the Shelburne Basin off the east coast of Canada.

DD&A expense decreased in the fourth quarter of 2016, compared to the prior year quarter, primarily due to lower depletion rates at Golden Eagle as a result of the impairment charge in the fourth quarter of 2015 and decreased production at Buzzard associated with planned maintenance, partially offset by higher production at East Coast Canada.


	Three months ended December 31		Twelve months ended December 31
($ millions)	2016	2015	2016	2015

Operating revenues	4 675	4 456	17 567	19 882

Net earnings	524	506	1 890	2 306

Adjusted for:

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

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

Operating earnings⁽³⁾	524	506	1 890	2 274

Refining and Supply	*439*	432	*1 527*	1 904

Marketing	85	74	*363*	370

Funds from operations⁽⁴⁾	722	605	2 606	2 921

(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 measure. See the Non-GAAP Financial Measures Advisory section of this document.
(4): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

Refining and Supply operating earnings were $439 million in the fourth quarter of 2016, compared to $432 million in the prior year quarter. The increase in the fourth quarter of 2016 was primarily due to a FIFO inventory gain of $114 million compared to a FIFO loss of $77 million in the prior period quarter. Lower benchmark refining crack spreads and refined product location differentials in the fourth quarter of 2016 were also partially offset by a higher value product mix and favourable crude price differentials.

Marketing activities contributed $85 million to operating earnings in the fourth quarter of 2016 compared with $74 million in the prior year quarter. The increase was due to a gain on the sale of certain retail assets and higher retail volumes and margins in Eastern North America, partially offset by weaker wholesale volumes and margins in Western North America.

During the quarter, Suncor reached an agreement for the sale of its Petro-Canada lubricants business, with the transaction closing on February 1, 2017 for gross proceeds of $1.125 billion, subject to customary post-closing adjustments. The lubricants business contributed $30 million in net earnings and $40 million in funds from operations (previously referred to as cash flow from operations) in the fourth quarter of 2016 and $133 million in net earnings and $183 million in funds from operations in 2016.


	Three months ended December 31		Twelve months ended December 31
	2016	2015	2016	2015

Crude oil processed (mbbls/d)

Eastern North America	204.8	208.0	203.1	208.1

Western North America	222.5	222.2	225.5	224.0

Total	427.3	430.2	428.6	432.1

Refinery utilization⁽¹⁾ (%)

Eastern North America	92	94	92	94

Western North America	93	93	94	93

Total	93	93	93	94

Refined product sales (mbbls/d)

Gasoline	241.3	243.8	244.3	246.2

Distillate	186.7	187.0	186.1	198.0

Other	86.8	70.4	91.0	79.1

Total	514.8	501.2	521.4	523.3

Refining gross margin⁽²⁾ ($/bbl)	23.00	23.20	20.30	24.90

Refining operating expense⁽³⁾ ($/bbl)	5.45	5.25	5.10	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 nameplate capacity of these units.
(2): Refinery margin per barrel is presented on the basis of total output from the company's four refineries and is derived from the R&M segmented statement of net earnings (loss) and is adjusted for the gross margin associated with the company's Supply and Marketing businesses, both of which are included in the R&M segment, as well as the impact of applicable hedging activity, which is included in other income in the R&M segmented statement of net earnings (loss).
(3): Refinery operating expense per barrel is presented on the basis of total output from the company's four refineries and is derived from the OS&G line in the R&M segmented statement of net earnings (loss) and is adjusted for operating expenses associated with the company's Supply and Marketing businesses, both of which are included in the R&M segment.

Total refined product sales were 514,800 bbls/d in the fourth quarter of 2016, compared to 501,200 bbls/d in the prior year quarter, primarily due to increased retail sales volumes.

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

Marketing margins in the fourth 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.

OS&G expense in the fourth quarter of 2016 was higher than the prior year quarter due to higher stock-based compensation expense and higher natural gas prices, partially offset by a decrease in controllable operating cost associated with the company's cost reduction initiatives.

DD&A expense in the fourth quarter of 2016 was higher than the prior year quarter due to the derecognition of certain refinery assets.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Net loss	(323	)	(634	)	(486	)	(2 687	)

Adjusted for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	222		382		(524	)	1 930

Non-cash mark to market gain on interest rate swaps⁽¹⁾	(188	)	—		(6	)	—

Derecognition and impairments⁽²⁾	31		—		31		—

Non-cash loss on early payment of long-term debt⁽³⁾	—		—		73		—

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

Restructuring charges⁽⁵⁾	—		—		—		57

Impact of income tax rate adjustments on deferred taxes⁽⁶⁾	—		—		—		(5	)

Operating (loss) earnings⁽⁷⁾	(258	)	(252	)	(874	)	(705	)

Renewable Energy	23		5		38		16

Energy Trading	19		(13	)	4		36

Corporate	*(261*	)	(249	)	*(864*	)	(799	)

Eliminations	*(39*	)	5		*(52*	)	42

Funds used in operations⁽⁸⁾	(114	)	(35	)	(600	)	(336	)

(1): Non-cash gain on interest rate swaps resulting from an increase in long-term interest rates.
(2): After-tax derecognition charge related to an initial investment in an undeveloped pipeline and certain renewable energy development assets as a result of the uncertainty of future benefits from these assets.
(3): Charges associated with early repayment of debt.
(4): Transaction and related charges associated with the acquisition of COS.
(5): Restructuring charges related to cost reduction initiatives.
(6): 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.
(7): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.
(8): Funds used in operations was previously referred to as cash flow used in operations, with the calculation being unchanged from prior quarters. Funds used in operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

In the third quarter of 2016, Suncor commenced a sales process for certain assets and associated liabilities related to its Renewable Energy business, with an agreement reached for the sale of its interest in the Cedar Point wind facility in the fourth quarter of 2016. The transaction closed on January 24, 2017.

Renewable Energy had operating earnings of $23 million in the fourth quarter of 2016, compared to $5 million in the prior year quarter, with the increase attributed to a recovery of deferred income tax and higher wind production.

Energy Trading had operating earnings of $19 million in the quarter, compared to an operating loss of $13 million in the prior year quarter. Wider crude location differentials and improved market conditions resulted in gains from crude trading in the fourth quarter of 2016 combined with favourable natural gas trading.

The operating loss for Corporate increased to $261 million in the fourth quarter of 2016, compared with $249 million in the prior year quarter. The increase was due to higher share-based compensation expense, unfavourable operational foreign exchange and additional interest expense associated with the debt acquired as part of the COS acquisition in the first quarter of 2016. These factors were partially offset by a decrease in operating costs as a result of the company's cost reduction initiatives, and a loss on foreign exchange currency swaps which occurred in the prior year quarter.

The company capitalized $162 million of its borrowing costs in the fourth quarter of 2016 as part of the cost of major development assets and construction projects in progress, compared to $129 million in the prior year quarter, with the increase being a result of higher accumulated capital project balances for Fort Hills and Hebron.

Eliminations reflect the elimination of profit on crude oil sales from the Oil Sands segment 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 fourth quarter of 2016, the company eliminated $39 million of after-tax intersegment profit, compared to a $5 million realization of intersegment profit in the prior year quarter. The elimination of profit in the period is due to an increased volume of intercompany crude held at the refineries combined with improvements in crude profit margins related to the increase in crude benchmark pricing.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Oil Sands	1 057		1 267		4 724		4 181

Exploration and Production	310		375		1 139		1 459

Refining and Marketing	183		356		685		821

Corporate, Energy Trading and Eliminations	22		32		34		206

Total capital and exploration expenditures	1 572		2 030		6 582		6 667

Less: capitalized interest on debt	(162	)	(129	)	(596	)	(447	)

	1 410		1 901		5 986		6 220


	Three months ended December 31, 2016			Twelve months ended December 31, 2016
($ millions)	Sustaining	Growth	Total	Sustaining	Growth	Total

Oil Sands

Oil Sands Base	204	93	*297*	1 128	418	*1 546*

In Situ	19	1	20	110	21	*131*

Oil Sands ventures	63	558	*621*	314	2 300	*2 614*

Exploration and Production	6	261	267	12	969	981

Refining and Marketing	183	—	183	680	3	683

Corporate, Energy Trading and Eliminations	22	—	22	31	—	31

	497	913	1 410	2 275	3 711	5 986

(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 fourth quarter of 2016, capital and exploration expenditures were $1.410 billion (excluding capitalized interest). Capital and exploration expenditures in the fourth quarter of 2016 decreased relative to the prior year quarter due to the company's cost reduction initiatives, fewer planned maintenance activities and decreased purchases of haul trucks at Oil Sands Base, partially offset by increased Fort Hills activity, as well as expenditures associated with the increased ownership in Syncrude. Activity in the fourth quarter of 2016 is summarized by business unit below.

Oil Sands Base capital and exploration expenditures were $297 million in the fourth quarter of 2016, of which $204 million and $93 million were directed towards sustaining and growth activities, respectively. Sustaining capital included expenditures related to planned major maintenance, including completion of coker maintenance at Upgrader 1, which began in the third 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 $20 million, of which $19 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 $621 million, including $558 million in growth capital expenditures and $63 million in sustaining capital expenditures. Growth capital was primarily for the Fort Hills mining project, which is more than 76% complete, with the remaining work to be based in Alberta. Activity in the period included completion of the secondary extraction module program; construction in secondary extraction and utilities has achieved peak activity and continues to focus on productivity and achieving critical milestones.

and now estimates the overall cost of the Fort Hills project to be between $16.5 and $17.0 billion. Suncor's share of Fort Hills' remaining project capital is between $1.6 and $1.8 billion. The majority of the spend will occur in 2017 and will be completed within Suncor's existing capital guidance range. In addition, the company has increased the nameplate capacity to 194,000 bbls/d after optimization and technical review. With these changes, Suncor's total capital intensity is expected to remain consistent with the original sanction estimate of $84,000 per flowing barrel of bitumen. First oil continues to remain on track for late 2017.

Sustaining capital expenditure at Fort Hills included development of early-works sustaining activities that will support the execution of the mine and tailings plan following the commencement of production.

The fourth quarter of 2016 also included an increased share of Syncrude sustaining capital, which was primarily focused on key reliability, safety and environmental projects.

Growth capital of $261 million was primarily focused on the construction of the Hebron project, which continued in the fourth quarter of 2016, with the integrated topside modules being successfully towed out to the deepwater construction site and mated with the gravity-based structure. First oil from the project continues to be expected in late 2017. Growth capital also included drilling of a second exploration well at the Shelburne Basin off the east coast of Canada, with the costs subsequently charged to exploration expense within the period, and development drilling at Hibernia and White Rose.

The Oda field offshore Norway, previously referred to as Butch, was sanctioned during the fourth quarter of 2016. Suncor is a 30% non-operating partner in Oda. First oil is expected in 2019, with the company's share of peak oil production estimated to be 10,500 boe/d.

R&M capital expenditures were $183 million and were primarily related to the completion of planned maintenance activities at the Sarnia and Montreal refineries, as well as improvements to retail locations.

Corporate capital expenditures were $22 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended December 31
	2016	2015

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	0.5	0.6

Including major projects in progress	0.4	0.5

Net debt to funds from operations⁽²⁾ (times)	2.4	1.7

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	0.5	(1.8	)

Funds from operations basis⁽²⁾⁽⁴⁾	6.5	9.3

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this document.
(2): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.
(3): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(4): Funds from operations (previously referred to as 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 realized proceeds from the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2017 capital spending program of $4.8 to $5.2 billion and to meet current and future working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities, 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 $3.016 billion during 2016 from $4.049 billion at December 31, 2015. The decrease was primarily due to the acquisition of an additional 5% interest in Syncrude from Murphy Oil Company Ltd. (Murphy) for $946 million, capital and exploration expenditures exceeding cash flow provided by operating activities after dividends, early payment of $891 million of bonds and repayment of $600 million of bank debt, both of which were 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, the issuance of $1.0 billion of debt in the third quarter of 2016 and increased short-term borrowings.

As at December 31, 2016, the weighted average term to maturity of the short-term investment portfolio was approximately 10 days.

Available lines of credit at December 31, 2016 increased to $7.467 billion, compared to $7.034 billion at December 31, 2015, primarily as a result of credit facilities added through the acquisition of COS and reduced letters of credit, partially offset by increased short-term borrowings and foreign exchange impacts on available credit facilities.

Subsequent to the end of the fourth quarter of 2016, the company cancelled a $950 million credit facility that was acquired through the acquisition of COS, reducing available lines of credit to $6.5 billion. The credit facility is no longer required for liquidity purposes and the cancelation will reduce future financing expense.

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans and the current pricing environment. Suncor believes a phased and flexible approach to existing and future growth projects will assist the company in managing debt levels.

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an "event of default" as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders' equity. At December 31, 2016, total debt to total debt plus shareholders' equity was 28.1% (December 31, 2015 – 28.2%). The company is currently in compliance with all operating covenants.


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

Short-term debt	1 273	747

Current portion of long-term debt	54	70

Long-term debt	16 103	14 486

Total debt	17 430	15 303

Less: Cash and cash equivalents	3 016	4 049

Net debt	14 414	11 254

Shareholders' equity	44 630	39 039

Total debt plus shareholders' equity	62 060	54 342

Total debt to total debt plus shareholders' equity (%)	28.1	28.2


	Three and twelve months ended December 31, 2016
($ millions)	Q4		YTD

Net debt – start of period	14 729		11 254

(Decrease) increase in net debt	(315	)	3 160

Net debt – December 31, 2016	14 414		14 414

Decrease (increase) in net debt

Funds from operations⁽¹⁾	2 365		5 988

Capital and exploration expenditures	(1 572	)	(6 582	)

Acquisitions	(68	)	(1 014	)

Cash acquired, COS	—		109

Debt acquired, COS	—		(2 639	)

Proceeds from disposal of assets	33		229

Dividends less proceeds from exercise of share options	(367	)	(1 744	)

Change in non-cash working capital and other investments	233		(557	)

Issuance of common shares	—		2 782

Foreign exchange on cash, debt and other balances	(309	)	268

	315		(3 160	)

(1): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.

As at February 3, 2017, the total number of common shares outstanding was 1,668,518,630 and the total number of exercisable and non-exercisable common share options outstanding was 29,982,051. 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 Management's Discussion and Analysis for the year ended December 31, 2015, dated February 25, 2016 (the 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 twelve months ended December 31, 2016, the company increased its commitments by approximately $7.0 billion (undiscounted), which is primarily due 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 a reduction in decommissioning and restoration costs as a result of revised estimates of the cash required to settle existing liabilities and the early payment of a portion of long-term debt acquired as part of the COS acquisition.

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


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

Total production (mboe/d)

Oil Sands	620.4		617.5		213.1		565.8		470.6		458.4		448.7	475.6

Exploration and Production	118.1		110.6		117.6		125.6		112.3		107.7		111.2	126.8

	738.5		728.1		330.7		691.4		582.9		566.1		559.9	602.4

Revenues and other income

Operating revenues, net of royalties	7 840		7 409		5 914		5 644		6 499		7 485		8 095	7 129

Other income (loss)	301		(15	)	(58	)	(67	)	94		72		49	257

	8 141		7 394		5 856		5 577		6 593		7 557		8 144	7 386

Net earnings (loss)	531		392		(735	)	257		(2 007	)	(376	)	729	(341	)

per common share – basic (dollars)	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)

per common share – diluted (dollars)	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)

Operating earnings (loss)⁽²⁾	636		346		(565	)	(500	)	(26	)	410		906	175

per common share – basic⁽²⁾ (dollars)	0.38		0.21		(0.36	)	(0.33	)	(0.02	)	0.28		0.63	0.12

Funds from operations⁽¹⁾	2 365		2 025		916		682		1 294		1 882		2 155	1 475

per common share – basic⁽¹⁾ (dollars)	1.42		1.22		0.58		0.45		0.90		1.30		1.49	1.02

ROCE⁽²⁾ (%) for the twelve months ended	0.5		(4.6	)	(4.9	)	(2.2	)	0.6		5.1		7.2	5.8

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(222	)	(112	)	(27	)	885		(382	)	(786	)	178	(940	)

Common share information (dollars)

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

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	43.90		36.42		35.84		36.17		35.72		35.69		34.40	37.01

New York Stock Exchange (US$)	32.69		27.78		27.73		27.81		25.80		26.72		27.52	29.25

(1): Funds from operations was previously referred to as cash flow from operations, with the calculation being unchanged from prior quarters. Funds from operations is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this document.
(2): 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)		Dec 31 2016	Sept 30 2016	June 30 2016	Mar 31 2016	Dec 31 2015	Sept 30 2015	June 30 2015	Mar 31 2015

WTI crude oil at Cushing	US$/bbl	49.35	44.95	45.60	33.50	42.15	46.45	57.95	48.65

Dated Brent crude	US$/bbl	49.50	45.85	45.60	33.90	43.70	50.30	61.95	53.85

Dated Brent/Maya FOB price differential	US$/bbl	6.70	6.80	7.65	8.95	10.35	8.50	8.15	11.05

MSW at Edmonton	Cdn$/bbl	62.00	55.10	55.80	34.50	53.55	56.55	68.05	52.25

WCS at Hardisty	US$/bbl	35.00	31.45	32.30	19.30	27.70	33.25	46.35	33.90

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.35	13.50	13.30	14.25	14.50	13.20	11.60	14.75

Condensate at Edmonton	US$/bbl	48.35	43.05	44.10	34.45	41.65	44.20	57.95	45.60

Natural gas (Alberta spot) at AECO	Cdn$/mcf	3.10	2.30	1.40	1.85	2.45	2.90	2.55	2.75

Alberta Power Pool Price	Cdn$/MWh	21.95	17.90	14.90	18.10	21.20	26.05	57.25	29.15

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	14.35	14.00	16.10	11.75	13.60	22.25	23.85	19.20

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	10.55	14.15	16.65	9.10	13.90	23.95	20.30	16.00

Portland 3-2-1 crack⁽¹⁾	US$/bbl	14.95	18.75	19.30	13.00	17.90	28.75	32.55	21.50

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	13.15	14.50	14.85	11.05	11.05	21.55	22.90	18.00

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

Exchange rate (end of period)	US$/Cdn$	0.74	0.76	0.77	0.77	0.72	0.75	0.80	0.79

(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 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 15 to the unaudited interim Consolidated Financial Statements for the three and twelve months ended December 31, 2016, and the Financial Condition and Liquidity section of Suncor's 2015 annual MD&A.

In the fourth quarter of 2016, the Tax Court of Canada issued a favourable Order resolving a previously disclosed $1.3 billion tax dispute with the Canada Revenue Agency (CRA). The dispute was regarding the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. The Tax Court of Canada Order has confirmed the successful resolution of the matter between Suncor and the CRA, resulting in no additional taxes, interest or penalties. All of the security which Suncor had posted with respect to this item has now been returned to the company.

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

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

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 deferred income tax recovery of $406 million.

Certain financial measures in this document – namely operating earnings (loss), ROCE, funds from (used in) operations (previously referred to as 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 document.

Throughout this document, 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 document. 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 December 31 ($ millions, except as noted)		2016		2015

Adjustments to net earnings

Net (loss) earnings attributed to common shareholders		434		(1 995	)

Add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(524	)	1 930

Net interest expense		304		312

	A	214		247

Capital employed – beginning of twelve-month period

Net debt		11 254		7 834

Shareholders' equity		39 039		41 603

		50 293		49 437

Capital employed – end of twelve-month period

Net debt		14 414		11 254

Shareholders' equity		44 630		39 039

		59 044		50 293

Average capital employed	B	57 999		50 565

ROCE – including major projects in progress (%)	A/B	0.4		0.5

Average capitalized costs related to major projects in progress	C	10 147		7 195

ROCE – excluding major projects in progress (%)	A/(B–C)	0.5		0.6

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

Funds from (used in) operations in this document for the twelve-month ended periods are the sum of the funds from (used in) operations for the particular quarter ended December 31 and each of the three preceding quarters. Funds 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 document for the applicable quarter.


Three months ended December 31	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)	276		(616	)	54		(1 263	)	524		506		(323	)	(634	)	531		(2 007	)

Adjustments for:

Depreciation, depletion, amortization and impairment	1 038		1 260		294		2 063		196		176		73		30		1 601		3 529

Deferred income taxes	(14	)	(174	)	(44	)	(579	)	(3	)	(36	)	(9	)	54		(70	)	(735	)

Accretion of liabilities	53		38		10		13		2		2		—		(2	)	65		51

Unrealized foreign exchange loss on U.S. dollar denominated debt	—		—		—		—		—		—		313		386		313		386

Change in fair value of financial instruments and trading inventory	—		(14	)	—		—		(1	)	(32	)	(271	)	83		(272	)	37

(Gain) on disposal of assets	—		—		—		—		(21	)	(4	)	—		(1	)	(21	)	(5	)

Share-based compensation	57		21		7		3		32		11		105		35		201		70

Exploration expenses	—		—		65		41		—		—		—		—		65		41

Settlement of decommissioning and restoration liabilities	(55	)	(37	)	(1	)	(3	)	(7	)	(7	)	—		—		(63	)	(47	)

Other	17		(11	)	—		(18	)	—		(11	)	(2	)	14		15		(26	)

Funds from (used in) operations	1 372		467		385		257		722		605		(114	)	(35	)	2 365		1 294

Increase (decrease) in non-cash working capital	217		(2	)	156		45		982		424		(929	)	(318	)	426		149

Cash flow provided by (used in) operating activities	1 589		465		541		302		1 704		1 029		(1 043	)	(353	)	2 791		1 443


Twelve months ended December 31	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	(1 149	)	(856	)	190		(758	)	1 890		2 306		(486	)	(2 687	)	445		(1 995	)

Adjustments for:

Depreciation, depletion, amortization and impairment	3 864		3 583		1 381		3 106		702		685		170		126		6 117		7 500

Deferred income taxes	(78	)	172		(506	)	(1 235	)	12		(21	)	60		160		(512	)	(924	)

Accretion of liabilities	208		144		53		50		7		7		1		(4	)	269		197

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(458	)	1 967		(458	)	1 967

Change in fair value of financial instruments and trading inventory	19		20		—		—		27		60		(53	)	7		(7	)	87

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

(Gain) loss on disposal of assets	(33	)	8		—		(5	)	(35	)	(109	)	—		(4	)	(68	)	(110	)

Share-based compensation	41		13		12		9		21		2		68		(6	)	142		18

Exploration expenses	—		—		204		255		—		—		—		—		204		255

Settlement of decommissioning and restoration liabilities	(248	)	(277	)	(1	)	(5	)	(20	)	(20	)	—		—		(269	)	(302	)

Other	45		28		(20	)	(31	)	2		11		(1	)	105		26		113

Funds from (used in) operations	2 669		2 835		1 313		1 386		2 606		2 921		(600	)	(336	)	5 988		6 806

(Increase) decrease in non-cash working capital	(383	)	(27	)	60		322		787		306		(772	)	(523	)	(308	)	78

Cash flow provided by (used in) operating activities	2 286		2 808		1 373		1 708		3 393		3 227		(1 372	)	(859	)	5 680		6 884

Free cash flow is a non-GAAP financial measure that is calculated by deducting capital and exploration expenditures for the twelve-month period from funds from operations⁽¹⁾ 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 document. 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
		Q4	Three months ended December 31
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; 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, including

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


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Revenues and Other Income

Operating revenues, net of royalties (note 3)	7 840		6 499		26 807		29 208

Other income (note 7)	301		94		161		472

	8 141		6 593		26 968		29 680

Expenses

Purchases of crude oil and products	2 402		2 673		9 877		11 590

Operating, selling and general	2 536		2 223		9 150		8 607

Transportation	279		278		1 072		1 085

Depreciation, depletion, amortization and impairment	1 601		3 529		6 117		7 500

Exploration	86		67		289		478

Gain on disposal of assets	(21	)	(5	)	(68	)	(110	)

Financing expenses (note 11)	532		496		445		2 557

	7 415		9 261		26 882		31 707

Earnings (loss) before Income Taxes	726		(2 668	)	86		(2 027	)

Income Taxes (note 12)

Current	265		74		153		892

Deferred	(70	)	(735	)	(512	)	(924	)

	195		(661	)	(359	)	(32	)

Net Earnings (Loss)	531		(2 007	)	445		(1 995	)

Net Earnings (Loss) Attributable to:

Common shareholders	531		(2 007	)	434		(1 995	)

Non-controlling interest (note 4)	—		—		11		—

	531		(2 007	)	445		(1 995	)

Other Comprehensive Income (Loss)

Items reclassified to earnings

Realized gain on disposal of assets available for sale, net of income taxes of $13 (note 20)	—		—		—		(85	)

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	36		131		(258	)	846

Items that will not be reclassified to earnings

Actuarial gain (loss) on employee retirement benefit plans, net of income taxes	450		157		(24	)	212

Other Comprehensive Income (Loss)	486		288		(282	)	973

Total Comprehensive Income (Loss)	1,017		(1 719	)	163		(1 022	)

Per Common Share (dollars) (note 13)

Net earnings (loss) – basic and diluted	0.32		(1.38	)	0.28		(1.38	)

Net earnings (loss) – attributable to common shareholders – basic and diluted	0.32		(1.38	)	0.27		(1.38	)

Cash dividends	0.29		0.29		1.16		1.14

See accompanying notes to the interim consolidated financial statements.


($ millions)	December 31 2016 (see note 4)	December 31 2015

Assets

Current assets

Cash and cash equivalents	3 016	4 049

Accounts receivable	3 182	2 751

Inventories	3 240	3 090

Income taxes receivable	376	538

Assets held for sale (note 6)	1 205	—

Total current assets	11 019	10 428

Property, plant and equipment, net	71 259	61 151

Exploration and evaluation	2 038	1 681

Other assets	1 248	1 153

Goodwill and other intangible assets	3 075	3 079

Deferred income taxes	63	35

Total assets	88 702	77 527

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	1 273	747

Current portion of long-term debt	54	70

Accounts payable and accrued liabilities	5 588	5 306

Current portion of provisions	781	769

Income taxes payable	224	244

Liabilities associated with assets held for sale (note 6)	197	—

Total current liabilities	8 117	7 136

Long-term debt	16 103	14 486

Other long-term liabilities	2 067	1 573

Provisions (note 19)	6 542	5 339

Deferred income taxes	11 243	9 954

Equity	44 630	39 039

Total liabilities and equity	88 702	77 527

See accompanying notes to the interim consolidated financial statements.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Operating Activities

Net earnings (loss)	531		(2 007	)	445		(1 995	)

Adjustments for:

Depreciation, depletion, amortization and impairment	1 601		3 529		6 117		7 500

Deferred income taxes	(70	)	(735	)	(512	)	(924	)

Accretion	65		51		269		197

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	313		386		(458	)	1 967

Change in fair value of financial instruments and trading inventory	(272	)	37		(7	)	87

Gain on disposal of assets	(21	)	(5	)	(68	)	(110	)

Loss on extinguishment of long-term debt (note 11)	—		—		99		—

Share-based compensation	201		70		142		18

Exploration	65		41		204		255

Settlement of decommissioning and restoration liabilities	(63	)	(47	)	(269	)	(302	)

Other	15		(26	)	26		113

Decrease (increase) in non-cash working capital	426		149		(308	)	78

Cash flow provided by operating activities	2 791		1 443		5 680		6 884

Investing Activities

Capital and exploration expenditures	(1 572	)	(2 030	)	(6 582	)	(6 667	)

Cash acquired from Canadian Oil Sands Limited (note 4)	—		—		109		—

Acquisitions (notes 4, 5 and 16)	(68	)	(360	)	(1 014	)	(360	)

Proceeds from disposal of assets	33		6		229		277

Other investments	(14	)	(7	)	(25	)	(18	)

Increase in non-cash working capital	(179	)	(26	)	(224	)	(3	)

Cash flow used in investing activities	(1 800	)	(2 417	)	(7 507	)	(6 771	)

Financing Activities

Net change in short-term debt	(719	)	(25	)	531		(203	)

Repayment of long-term debt	(14	)	(16	)	(1 693	)	(55	)

Issuance of long-term debt (note 11)	—		—		993		—

Issuance of common shares under share option plans	116		19		133		95

(Purchase) issuance of common shares (notes 10 and 14)	—		(3	)	2 782		(43	)

Dividends paid on common shares	(483	)	(419	)	(1 877	)	(1 648	)

Cash flow (used in) provided by financing activities	(1 100	)	(444	)	869		(1 854	)

Decrease in Cash and Cash Equivalents	(109	)	(1 418	)	(958	)	(1 741	)

Effect of foreign exchange on cash and cash equivalents	23		58		(75	)	295

Cash and cash equivalents at beginning of period	3 102		5 409		4 049		5 495

Cash and Cash Equivalents at End of Period	3 016		4 049		3 016		4 049

Supplementary Cash Flow Information

Interest paid	395		374		992		881

Income taxes (received) paid	(105	)	112		(161	)	1 424

See accompanying notes to the interim consolidated financial statements.


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

At December 31, 2014	19 311		609		504		—		21 179		41 603		1 444 119

Net loss	—		—		—		—		(1 995	)	(1 995	)	—

Foreign currency translation adjustment	—		—		846		—		—		846		—

Realized gain on disposal of assets available for sale, net of income taxes of $13 (note 20)	—		—		(85	)	—		—		(85	)	—

Actuarial gain on employee retirement benefit plans, net of income taxes of $75	—		—		—		—		212		212		—

Total comprehensive income (loss)	—		—		761		—		(1 783	)	(1 022	)	—

Issued under share option plans	125		(20	)	—		—		—		105		3 124

Issued under dividend reinvestment plan	47		—		—		—		(47	)	—		—

Purchase of common shares for cancellation (see note 10)	(17	)	—		—		—		(26	)	(43	)	(1 230	)

Share-based compensation	—		44		—		—		—		44		—

Dividends paid on common shares	—		—		—		—		(1 648	)	(1 648	)	—

At December 31, 2015	19 466		633		1 265		—		17 675		39 039		1 446 013

Net earnings	—		—		—		11		434		445		—

Foreign currency translation adjustment	—		—		(258	)	—		—		(258	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $5	—		—		—		—		(24	)	(24	)	—

Total comprehensive (loss) income	—		—		(258	)	11		410		163		—

Issued under share option plans	216		(84	)	—		—		—		132		3 983

Issued for cash, net of income taxes of $26 (note 14)	2 808		—		—		—		—		2 808		82 225

Issued for the acquisition of Canadian Oil Sands Ltd. (note 4)	3 154		—		—		1 172		—		4 326		98 814

Equity transactions to eliminate non-controlling interest in Canadian Oil Sands Ltd. (note 4)	1 298		—		—		(1 183	)	(115	)	—		36 879

Share-based compensation	—		39		—		—		—		39		—

Dividends paid on common shares	—		—		—		—		(1 877	)	(1 877	)	—

At December 31, 2016	26 942		588		1 007		—		16 093		44 630		1 667 914

See accompanying notes to the interim consolidated financial statements.

Suncor Energy Inc. (Suncor or the company) is an integrated energy company headquartered in Canada. Suncor's operations include oil sands development and upgrading, onshore and offshore oil and gas production, petroleum refining, and product marketing primarily under the Petro-Canada brand. The consolidated financial statements of the company comprise the company and its subsidiaries and the company's interests in associates and joint arrangements.

The address of the company's registered office is 150 – 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3E3.

These condensed interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board. They are condensed as they do not include all of the information required for full annual financial statements, and they should be read in conjunction with the consolidated financial statements for the year ended December 31, 2015.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as at December 31, 2015.

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 segment, and was previously presented in Corporate, Energy Trading and Eliminations. The reclassification resulted in an increase in net earnings for the Refining and Marketing segment and an increase in net loss for Corporate, Energy Trading and Eliminations of $7 million for the three months ended December 31, 2015 and $40 million for twelve months ended December 31, 2015.

The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in the company's consolidated financial statements for the year ended December 31, 2015.

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

The timely preparation of financial statements requires that management make estimates and assumptions and use judgment. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates and judgment used in the preparation of the financial statements are described in the company's consolidated financial statements for the year ended December 31, 2015.

The company recognizes the impacts of income tax rate changes in earnings in the period the rate change is substantively enacted.

Assets and liabilities are classified as held for sale if their carrying amounts are expected to be recovered through a disposition rather than through continuing use. The assets or disposal groups are measured at the lower of their carrying amount and estimated fair value less costs of disposal. Impairment losses on initial classification as well as subsequent gains or losses on remeasurement are recognized in Depreciation, Depletion, Amortization and Impairment. When the assets or disposal groups are sold, the gains or losses on the sale are recognized in (Gain) Loss on Disposal of Assets. Assets classified as held for sale are not depreciated, depleted or amortized.

The company's operating segments are reported based on the nature of their products and services and management responsibility.

Intersegment sales of crude oil and natural gas are accounted for at market values and are included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer. Intersegment amounts are eliminated on consolidation.


Three months ended December 31	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

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	2 514		1 575		741		505		4 663		4 443		21		19		7 939		6 542

Intersegment revenues	842		442		1		—		12		13		(855	)	(455	)	—		—

Less: Royalties	(4	)	(10	)	(95	)	(33	)	—		—		—		—		(99	)	(43	)

Operating revenues, net of royalties	3 352		2 007		647		472		4 675		4 456		(834	)	(436	)	7 840		6 499

Other income (loss)	8		68		—		14		(10	)	47		303		(35	)	301		94

	3 360		2 075		647		486		4 665		4 503		(531	)	(471	)	8 141		6 593

Expenses

Purchases of crude oil and products	101		136		—		—		3 095		2 988		(794	)	(451	)	2 402		2 673

Operating, selling and general	1 634		1 317		115		126		586		573		201		207		2 536		2 223

Transportation	177		170		21		22		95		100		(14	)	(14	)	279		278

Depreciation, depletion, amortization and impairment	1 038		1 260		294		2 063		196		176		73		30		1 601		3 529

Exploration	—		8		86		59		—		—		—		—		86		67

Gain on disposal of assets	—		—		—		—		(21	)	(4	)	—		(1	)	(21	)	(5	)

Financing expenses (income)	58		36		20		22		(2	)	(2	)	456		440		532		496

	3 008		2 927		536		2 292		3 949		3 831		(78	)	211		7 415		9 261

Earnings (loss) before Income Taxes	352		(852	)	111		(1 806	)	716		672		(453	)	(682	)	726		(2 668	)

Income Taxes

Current	90		(62	)	101		36		195		202		(121	)	(102	)	265		74

Deferred	(14	)	(174	)	(44	)	(579	)	(3	)	(36	)	(9	)	54		(70	)	(735	)

	76		(236	)	57		(543	)	192		166		(130	)	(48	)	195		(661	)

Net Earnings (Loss)	276		(616	)	54		(1 263	)	524		506		(323	)	(634	)	531		(2 007	)

Capital and Exploration Expenditures	1 057		1 267		310		375		183		356		22		32		1 572		2 030


Twelve months ended December 31	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

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	7 229		7 174		2 329		2 524		17 459		19 839		55		52		27 072		29 589

Intersegment revenues	2 293		2 158		115		88		108		43		(2 516	)	(2 289	)	—		—

Less: Royalties	(52	)	(114	)	(213	)	(267	)	—		—		—		—		(265	)	(381	)

Operating revenues, net of royalties	9 470		9 218		2 231		2 345		17 567		19 882		(2 461	)	(2 237	)	26 807		29 208

Other income	26		146		45		150		16		86		74		90		161		472

	9 496		9 364		2 276		2 495		17 583		19 968		(2 387	)	(2 147	)	26 968		29 680

Expenses

Purchases of crude oil and products	548		319		—		3		11 754		13 571		(2 425	)	(2 303	)	9 877		11 590

Operating, selling and general	5 777		5 220		483		502		2 203		2 219		687		666		9 150		8 607

Transportation	666		645		86		98		366		388		(46	)	(46	)	1 072		1 085

Depreciation, depletion, amortization and impairment	3 864		3 583		1 381		3 106		702		685		170		126		6 117		7 500

Exploration	30		120		259		358		—		—		—		—		289		478

(Gain) loss on disposal of assets	(33	)	8		—		(5	)	(35	)	(109	)	—		(4	)	(68	)	(110	)

Financing expenses (income)	234		150		82		82		10		(14	)	119		2 339		445		2 557

	11 086		10 045		2 291		4 144		15 000		16 740		(1 495	)	778		26 882		31 707

(Loss) earnings before Income Taxes	(1 590	)	(681	)	(15	)	(1 649	)	2 583		3 228		(892	)	(2 925	)	86		(2 027	)

Income Taxes

Current	(363	)	3		301		344		681		943		(466	)	(398	)	153		892

Deferred	(78	)	172		(506	)	(1 235	)	12		(21	)	60		160		(512	)	(924	)

	(441	)	175		(205	)	(891	)	693		922		(406	)	(238	)	(359	)	(32	)

Net (Loss) Earnings	(1 149	)	(856	)	190		(758	)	1 890		2 306		(486	)	(2 687	)	445		(1 995	)

Capital and Exploration Expenditures	4 724		4 181		1 139		1 459		685		821		34		206		6 582		6 667

On February 5, 2016 Suncor obtained control of Canadian Oil Sands Limited (COS) by acquiring 73% of COS' outstanding common shares in exchange for 0.28 of a Suncor share per COS share tendered. The acquisition resulted in the issuance of 98.9 million Suncor common shares, which had a fair value of $31.88 per share based on the closing price on the TSX on the acquisition date.

COS owned a 36.74% interest in the Syncrude joint arrangement. Suncor acquired COS to benefit from operating synergies and economies of scale expected from combining the two companies' ownership interests in Syncrude.

On February 22, 2016 and March 21, 2016, Suncor acquired the remaining outstanding 131.3 million COS shares on the same terms as the initial acquisition resulting in the issuance of an additional 36.7 million Suncor common shares which resulted in a total acquisition price of $4.452 billion. The estimated fair values of the net assets acquired were not adjusted to reflect the changes in Suncor's share price on the subsequent transaction dates.

The acquisition has been accounted for as a business combination using the acquisition method whereby the net assets acquired and the liabilities assumed are recorded at fair value, except for the employee future benefit liability which is measured as the present value of the net obligation. The purchase price allocation is based on management's best estimates of fair values of COS' assets and liabilities as at February 5, 2016.


($ millions)

Cash	109

Accounts receivable	231

Inventory	135

Other assets	105

Property, plant and equipment	9 476

Exploration and evaluation	602

Total assets acquired	10 658

Accounts payable and other liabilities	(375	)

Long-term debt	(2 639	)

Employee future benefits	(323	)

Decommissioning provision	(1 169	)

Deferred income taxes	(1 826	)

Total liabilities assumed	(6 332	)

Net assets of COS	4 326

Non-controlling interest	(1 172	)

Net assets acquired	3 154

The fair values of cash, accounts receivable and other current assets, and accounts payable and other liabilities approximate their carrying values due to the short-term maturity of the instruments. The fair values of crude inventory and long-term debt were determined using quoted prices and rates from available pricing sources. The fair value of materials and supplies inventory approximates book value due to short-term turnover rates. The fair values of property, plant and equipment, and the decommissioning provision were determined using an expected future cash flow approach. Key assumptions used in the calculations were discount rates, future commodity prices and costs, timing of development activities, projections of oil reserves, and cost estimates to abandon and reclaim the mine and facilities.

During the second quarter of 2016 the company repurchased US$688 million of debt acquired through the acquisition of COS. The company also repaid approximately $600 million of the credit facility acquired in the COS transaction (note 11).

The non-controlling interest (NCI) was initially measured at the NCI's proportionate share of the net identifiable assets acquired. The subsequent transactions on February 22, 2016, and March 21, 2016, were accounted for as equity transactions with shareholders and eliminated the NCI balance. Suncor recognized the difference between the fair value of the common shares issued and the NCI recorded at February 5, 2016 directly in equity. During the period from February 5, 2016 to March 21, 2016, when Suncor did not own 100% of the equity, net earnings of $11 million were earned that were attributable to the NCI owners.

As part of the acquisition the company also assumed various pipeline and storage commitments of $3.0 billion undiscounted. The contract terms of these commitments range between one and 24 years, with payments that commenced in the first quarter of 2016.

Acquisition costs of $29 million have been charged to Operating, Selling and General expense in the consolidated statement of comprehensive income (loss) for the twelve month period ended December 31, 2016.

The acquisition of COS contributed $1.9 billion to gross revenues and a loss of $69 million to consolidated net income from the acquisition date to December 31, 2016.

Had the acquisition occurred on January 1, 2016, COS would have contributed $2.1 billion to gross revenues and a loss of $105 million to consolidated net income, which would have resulted in gross revenues of $27 billion and a consolidated net income of $408 million for the twelve month period ended December 31, 2016.

On June 23, 2016 Suncor completed the purchase of an additional 5% working interest in the Syncrude project from Murphy Oil Corporation's Canadian subsidiary for $946 million after purchase price adjustments. The purchase increased Suncor's share in the Syncrude project to 53.74%.

The acquisition has been accounted for as a business combination using the acquisition method. The purchase price allocation is based on management's best estimates of fair values of Syncrude's assets and liabilities as at June 23, 2016.


($ millions)

Accounts receivable	8

Inventory	19

Property, plant and equipment	1 330

Exploration and evaluation	82

Total assets acquired	1 439

Accounts payable and other liabilities	(29	)

Employee future benefits	(49	)

Decommissioning provision	(187	)

Deferred income taxes	(228	)

Total liabilities assumed	(493	)

Net assets acquired	946

The fair values of accounts receivable and accounts payable approximate their carrying values due to the short-term maturity of the instruments. The fair value of crude inventory was determined using quoted prices and rates from available pricing sources. The fair value of materials and supplies inventory approximates book value due to short-term turnover rates. The fair values of property, plant and equipment, and the decommissioning provision were determined using an expected future cash flow approach. Key assumptions used in the calculations were discount rates, future commodity prices and costs, timing of development activities, projections of oil reserves, and cost estimates to abandon and reclaim the mine and facilities. All of the key assumptions were applied on a consistent basis as the COS acquisition (note 4).

The additional interest in Syncrude contributed $191 million to gross revenues and $7 million to consolidated net income from the acquisition date to December 31, 2016.

Had the acquisition occurred on January 1, 2016, the additional interest would have contributed $275 million to gross revenues and a loss of $26 million to consolidated net income, which would have resulted in gross revenues of $27 billion and consolidated net income of $412 million for the twelve months ended December 31, 2016.

As at June 30, 2016, the company had reclassified the assets and liabilities related to its lubricants plant and associated infrastructure as assets held for sale. The lubricants business is reported within the Refining and Marketing segment. See note 21 for closing of sale.

The table below details the assets and liabilities of the lubricants business that were held for sale as at December 31, 2016:


($ millions)

Assets

Accounts receivable		209

Prepaids		3

Inventories		258

Property, plant & equipment, net		428

Total assets		898

Liabilities

Accounts payable and accrued liabilities		72

Income taxes payable		3

Pension liability		20

Deferred income taxes		71

Total liabilities		166

As at September 30, 2016 the company has also reclassified certain assets and liabilities related to its renewable energy business as assets held for sale. Suncor has commenced a sale process for these assets and anticipates that a sale could occur within the next nine months. The renewable energy business is reported within the Corporate segment. See note 21 for the sale of the Cedar Point wind facility, included in the assets and liabilities held for sale below.

The table below details the assets and liabilities of the renewable energy business that were held for sale as at December 31, 2016:


	Three months ended December 31			Twelve months ended December 31
($ millions)	2016	2015		2016		2015

Energy trading activities

Unrealized gains (losses) recognized in earnings during the period	16	22		(47	)	28

Gains (losses) on inventory valuation	14	(27	)	62		43

Risk management activities⁽¹⁾	228	41		(25	)	93

Investment and interest income	21	11		77		62

Renewable energy grants	5	5		24		30

Risk mitigation and insurance proceeds⁽²⁾	15	—		41		121

Change in value of pipeline commitments and other	2	42		29		95

	301	94		161		472

(1): Includes fair value changes related to short-term derivative contracts in the Oil Sands and Refining and Marketing segments and long-term forward starting interest rate swaps in the Corporate segment.
(2): Includes property damage insurance proceeds recorded in the fourth quarter of 2016 for Syncrude in the Oil Sands segment, and property damage insurance proceeds recorded in the second quarter of 2016 and business interruption insurance proceeds recorded in the first quarter of 2015 for the Terra Nova asset in the Exploration and Production segment.

During the fourth quarter of 2016, the company recorded after-tax derecognition charges of $40 million on certain upgrading and logistics assets in the Oil Sands segment as a result of the uncertainty of future benefits from these assets. In addition, the company also recorded after-tax derecognition charges of $31 million in the Corporate segment relating to an initial investment in an undeveloped pipeline and on certain renewable energy development assets as a result of the uncertainty of future benefits from these assets.

The following asset impairments were recorded during the fourth quarter of 2015.

As a result of the decline in crude oil prices, the company reassessed the remaining carrying value of its interest in the Joslyn mining project for impairment as at December 31, 2015. As a result, the company recognized an after-tax impairment charge of $290 million against the Exploration and Evaluation assets. The remaining carrying value of the company's share of the Joslyn mining project at December 31, 2015 was $nil.

During the fourth quarter of 2015, the company recorded an after-tax impairment charge of $96 million in the Oil Sands segment following a review of certain assets, including engineering costs related to In Situ expansion, that no longer fit with Suncor's growth strategies and are not expected to be repurposed or otherwise deployed.

As a result of shut-in production due to the continued closure of certain Libyan export terminals, ongoing political unrest, asset damages confirmed during the quarter, and the increasing uncertainty with respect to the company's return to normal operations in the country, the company performed an impairment assessment as at December 31, 2015, using a fair value less cost to sell methodology. The company used an expected cash flow approach, with a risk-adjusted discount rate of 17% to perform the calculation. As a result of the assessment, the company impaired the remaining carrying value

of its Libyan Property, Plant and Equipment, Exploration and Evaluation, and inventory, resulting in a $415 million after-tax impairment.

As a result of the decline in the crude oil price environment, the company performed impairment tests on its assets in the Exploration and Production segment as at December 31, 2015. The tests were performed using a fair value less cost of disposal methodology. An expected cash flow approach was used based on 2015 year-end reserves data with the following assumptions:

As a result of the impairment tests, the company recorded after-tax impairments of $359 million on the company's share of the White Rose assets, $331 million on the company's share of the Golden Eagle assets, and $54 million on the company's share of the Terra Nova assets. At December 31, 2015, the remaining carrying values of the White Rose, Golden Eagle and Terra Nova assets were $520 million, $1.0 billion and $910 million, respectively.

During the fourth quarter of 2015, the company recognized an after-tax impairment charge of $54 million related to certain East Coast Canada exploration and evaluation assets as a result of future development uncertainty.

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

Until August 4, 2016, the company was authorized to repurchase shares pursuant to a normal course issuer bid (NCIB) through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative trading platforms. Under the NCIB, the company was authorized to purchase for cancellation up to approximately $500 million worth of its common shares beginning August 5, 2015 and ending August 4, 2016.

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

In accordance with applicable securities law, repurchases under the program were suspended on October 5, 2015, as a result of the offer to the shareholders of COS. The company did not resume repurchases after the offer was completed and did not renew its NCIB in response to the lower crude price environment.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Interest on debt	259		226		1 012		870

Capitalized interest	(163	)	(129	)	(597	)	(447	)

Interest expense	96		97		415		423

Interest on pension and other post-retirement benefits	14		13		59		52

Accretion	65		51		269		197

Foreign exchange loss (gain) on U.S. dollar denominated debt	313		386		(458	)	1 967

Foreign exchange and other	44		(51	)	61		(82	)

Loss on extinguishment of long-term debt	—		—		99		—

	532		496		445		2 557

During the second quarter of 2016 the company purchased US$688 million ($891 million) principal value (book value of $864 million) of subsidiary debt acquired through the acquisition of COS (note 4) for US$751 million ($973 million) including US$8 million ($10 million) of accrued interest, resulting in a debt extinguishment loss of $99 million. The company also repaid approximately $600 million of the credit facility acquired in the COS transaction.

During the third quarter of 2016 the company issued $700 million of senior unsecured Series 5 Medium Term Notes maturing on September 14, 2026. The notes have a coupon of 3.00% and were priced at $99.751 per note for an effective yield of 3.029%. The company also issued $300 million of senior unsecured Series 5 Medium Term Notes maturing on September 13, 2046. The notes have a coupon of 4.34% and were priced at $99.900 per note for an effective yield of 4.346%.

In the fourth quarter of 2016, the Tax Court of Canada issued a favourable Order resolving the previously disclosed $1.3 billion tax dispute with the Canada Revenue Agency (CRA). The dispute was in regards to the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts. The Tax Court of Canada Order has confirmed the successful resolution of this matter between Suncor and the CRA, resulting in no additional taxes, interest or penalties. All of the security which Suncor had posted with respect to this item has now been returned to the company.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2016		2015		2016		2015

Net earnings (loss)	531		(2 007	)	445		(1 995	)

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	(1	)	—		(1	)	—

Net earnings (loss) – diluted	530		(2 007	)	444		(1 995	)

Net earnings (loss) attributable to common shareholders	531		(2 007	)	434		(1 995	)

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	(1	)	—		(1	)	—

Net earnings (loss) – diluted attributable to common shareholders	530		(2 007	)	433		(1 995	)

(millions of common shares)

Weighted average number of common shares	1 666		1 446		1 610		1 446

Dilutive securities:

Effect of share options	4		1		2		1

Weighted average number of diluted common shares	1 670		1 447		1 612		1 447

(dollars per common share)

Basic and diluted earnings (loss) per share	0.32		(1.38	)	0.28		(1.38	)

Basic and diluted earnings (loss) per share attributable to common shareholders	0.32		(1.38	)	0.27		(1.38	)

(1): Cash payment alternatives are accounted for as cash-settled plans. As these awards can be exchanged for common shares of the company, they are considered potentially dilutive and are included in the calculation of the company's diluted net earnings (loss) per share if they have a dilutive impact in the period. Accounting for these awards as equity-settled was determined to have a dilutive impact for the three and twelve months ended December 31, 2016.

On June 22, 2016, the company issued 82.2 million common shares for $35.00 per common share. Gross proceeds were approximately $2.878 billion ($2.782 billion net of fees).

The following table presents the company's non-designated Energy Trading and Risk Management derivatives measured at fair value as at December 31, 2016.

The following table presents the company's financial instruments measured at fair value for each hierarchy level as at December 31, 2016.

During the fourth quarter of 2016, there were no transfers between Level 1 and Level 2 fair value measurements and no transfers into and out of Level 3 fair value measurements.

The company uses forward starting interest rate swaps to mitigate its exposure to the effect of future interest rate movements on future debt issuances. As at December 31, 2016, the company had executed $1.9 billion in forward swaps. An increase in interest rates of 0.80% during the quarter resulted in an increase in value of $258 million associated with the swaps. A decrease in interest rates of 0.21% during the twelve months ended December 31, 2016 resulted in a decrease in value of $38 million offset by new swaps acquired during the year with a value of $48 million.

At December 31, 2016, the carrying value of fixed-term debt accounted for under amortized cost was $15.1 billion (December 31, 2015 – $13.3 billion) and the fair value was $17.5 billion (December 31, 2015 – $14.5 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

On October 6, 2016, Suncor completed the purchase of a 30% interest in the U.K. North Sea Rosebank project from OMV (U.K.) Limited (OMV) for an initial payment of US$50 million to OMV. In the event the co-venturers approve the Rosebank project final investment decision and Suncor elects to participate, Suncor could pay additional consideration to OMV of up to US$165 million. As the additional consideration is dependent on Suncor approval of the final investment decision, no amount has been recognized at December 31, 2016.

On August 31, 2015 Suncor completed an exchange of assets with TransAlta Corporation. Suncor exchanged Kent Breeze and its share of the Wintering Hills wind power facilities for TransAlta's Poplar Creek cogeneration facilities, which provide steam and power for Suncor's Oil Sands operations. The acquisition of the Poplar Creek cogeneration facilities is expected to enhance the reliability and efficiency of Suncor's base operations.

As part of the agreement, Suncor entered into a 15-year lease with TransAlta to finance the difference between the fair value of the cogeneration facilities and the fair value of the wind farms. The leased assets consist of two gas turbine generators and heat recovery steam generators. Ownership of these assets will automatically transfer to Suncor at the end of the term for a nominal amount. Although the legal form of this arrangement is a lease, in substance it is a deferred financing arrangement because it was entered into to finance the remaining balance of this acquisition and ownership of the assets will automatically transfer to Suncor at the end of the term. The lease is accounted for as a deferred financing arrangement that is part of the business combination because it is a component of the consideration provided to TransAlta.

The transaction was determined to have commercial substance since Suncor acquired operational control of Poplar Creek and will be entitled to all of the electrical output. The acquisition of the Poplar Creek assets was treated as a business combination, whereby the assets and liabilities acquired were recorded at their fair value. The fair values were calculated using an expected future cash flow approach with risk-adjusted discount rates between 6% and 8%. Key assumptions used in the calculation were discount rate, power price and natural gas price.

The preliminary purchase price allocation is based on management's best estimates of the fair values of the acquired assets and assumed liabilities. Upon finalization, adjustments to the initial estimates may be required.

On November 6, 2015 Suncor completed the purchase an additional 10% working interest in the Fort Hills oil sands project from Total E&P Canada Ltd. for total aggregate consideration of $360 million. Suncor's share in the project has increased to 50.8%.

A decrease in the credit-adjusted risk-free interest rate to 3.90% (December 31, 2015 – 4.37%) resulted in an increase in the decommissioning and restoration provision of $532 million offset by a decrease of $832 million due to changes in estimates for the twelve months ended December 31, 2016.

During the third quarter of 2014, the company announced that, along with The Pioneer Group Inc., it had reached an agreement to sell the assets of Pioneer Energy, including retail gas stations in Ontario and Manitoba. The company's investment in Pioneer Energy was recorded at fair value and classified as an available for sale financial instrument. The transaction closed in the second quarter of 2015 and the company received $183 million for its 50% share of Pioneer Energy and realized an after-tax gain of $68 million in the Refining and Marketing segment.

On February 1, 2017, the company completed the sale of its Petro-Canada Lubricants Inc. (PCLI) business to a subsidiary of HollyFrontier Corporation (HollyFrontier) for gross proceeds of $1.125 billion, subject to customary post-closing adjustments. The sale includes PCLI's production and manufacturing centre in Mississauga, Ontario and the global marketing and distribution assets held by PCLI including its global offices. Under the terms of the agreement, HollyFrontier will continue to operate the lubricants business under the Petro-Canada trademark. On January 24, 2017, the company completed the sale of its interest in Cedar Point wind facility for gross proceeds of $291 million.


	Three months ended										Twelve months ended
($ millions, except per share amounts)	Dec 31 2016		Sept 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015		Dec 31 2016		Dec 31 2015

Revenues and other income	8 141		7 394		5 856		5 577		6 593		26 968		29 680

Net earnings (loss)

Oil Sands	276		162		(1 063	)	(524	)	(616	)	(1 149	)	(856	)

Exploration and Production	54		144		26		(34	)	(1 263	)	190		(758	)

Refining and Marketing	524		436		689		241		506		1 890		2 306

Corporate, Energy Trading and Eliminations	(323	)	(350	)	(387	)	574		(634	)	(486	)	(2 687	)

	531		392		(735	)	257		(2 007	)	445		(1 995	)

Operating earnings (loss)^(A)

Oil Sands	316		162		(1 063	)	(524	)	(230	)	(1 109	)	(111	)

Exploration and Production	54		(36	)	26		(34	)	(50	)	10		7

Refining and Marketing	524		436		689		241		506		1 890		2 274

Corporate, Energy Trading and Eliminations	(258	)	(216	)	(217	)	(183	)	(252	)	(874	)	(705	)

	636		346		(565	)	(500	)	(26	)	(83	)	1 465

Funds from (used in) operations^(A)

Oil Sands	1 372		1 236		(202	)	263		467		2 669		2 835

Exploration and Production	385		365		302		261		257		1 313		1 386

Refining and Marketing	722		595		885		404		605		2 606		2 921

Corporate, Energy Trading and Eliminations	(114	)	(171	)	(69	)	(246	)	(35	)	(600	)	(336	)

	2 365		2 025		916		682		1 294		5 988		6 806

Per common share

Net earnings (loss) basic and diluted	0.32		0.24		(0.46	)	0.17		(1.38	)	0.28		(1.38	)

Net earnings (loss) attributable to common shareholders – basic and diluted	0.32		0.24		(0.46	)	0.16		(1.38	)	0.27		(1.38	)

Operating earnings (loss) – basic^(A)	0.38		0.21		(0.36	)	(0.33	)	(0.02	)	(0.05	)	1.01

Cash dividends – basic	0.29		0.29		0.29		0.29		0.29		1.16		1.14

Funds from operations – basic^(A)	1.42		1.22		0.58		0.45		0.90		3.72		4.71


	Three months ended					Twelve months ended
Oil Sands	Dec 31 2016	Sept 30 2016	Jun 30 2016	Mar 31 2016	Dec 31 2015	Dec 31 2016	Dec 31 2015

Total Production (mbbls/d)	620.4	617.5	213.1	565.8	470.6	504.9	463.4

Oil Sands operations

Production volumes (mbbls/d)

Upgraded product (sweet SCO, sour SCO & diesel)	324.5	301.1	86.4	322.3	292.2	258.9	320.1

Non-upgraded bitumen	108.9	132.6	91.1	130.7	147.5	115.9	113.5

Oil Sands operations production	433.4	433.7	177.5	453.0	439.7	374.8	433.6

Bitumen production (mbbls/d)

Mining	284.8	295.1	66.8	302.0	292.4	238.0	307.3

In Situ – Firebag	204.5	197.6	121.8	199.0	198.8	180.8	186.9

In Situ – MacKay River	33.9	26.6	13.1	36.8	34.5	27.6	30.7

Total bitumen production	523.2	519.3	201.7	537.8	525.7	446.4	524.9

Sales (mbbls/d)

Light sweet crude oil	87.2	100.8	29.0	132.2	100.2	87.3	107.0

Diesel	28.4	27.9	3.4	24.8	29.4	21.2	31.3

Light sour crude oil	201.5	162.5	76.3	172.7	154.2	153.4	182.5

Upgraded product (SCO and diesel)	317.1	291.2	108.7	329.7	283.8	261.9	320.8

Non-upgraded bitumen	103.5	123.5	108.1	134.5	136.3	117.4	107.7

Sales	420.6	414.7	216.8	464.2	420.1	379.3	428.5

Cash operating costs – Average⁽¹⁾ ($/bbl)

Cash costs	22.10	20.30	44.55	22.55	25.70	24.35	25.65

Natural gas	2.85	1.85	2.25	1.70	2.30	2.15	2.20

	24.95	22.15	46.80	24.25	28.00	26.50	27.85

Cash operating costs – Mining bitumen production only⁽¹⁾ ($/bbl)

Cash costs	22.55	19.30	76.65	21.70	25.10	34.75	23.20

Natural gas	0.80	0.50	1.15	0.50	0.70	0.85	0.55

	23.35	19.80	77.80	22.20	25.80	35.60	23.75

Cash operating costs – In Situ bitumen production only⁽¹⁾ ($/bbl)

Cash costs	6.35	7.15	10.75	7.60	8.10	7.60	9.00

Natural gas	4.40	3.30	2.20	2.80	3.55	3.30	3.80

	10.75	10.45	12.95	10.40	11.65	10.90	12.80

Syncrude

Sweet SCO production (mbbls/d)	187.0	183.8	35.6	112.8	30.9	130.1	29.8

Bitumen production (mbbls/d)	219.6	210.1	52.5	120.6	36.0	151.1	35.1

Intermediate sour SCO (mbbls/d)⁽²⁾	192.6	179.2	42.8	109.0	30.6	131.2	30.0

Cash operating costs⁽¹⁾ ($/bbl)

Cash costs	31.05	26.50	111.40	30.25	38.55	34.60	40.35

Natural gas	1.50	1.15	2.15	1.10	1.60	1.35	1.65

	32.55	27.65	113.55	31.35	40.15	35.95	42.00

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Twelve months ended
Oil Sands Operating Netbacks⁽³⁾	Dec 31 2016		Sept 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015		Dec 31 2016		Dec 31 2015

Bitumen ($/bbl)

Average price realized	31.68		26.67		23.90		12.00		25.63		23.50		32.18

Royalties	(0.33	)	(0.39	)	(0.24	)	—		(0.32	)	(0.23	)	(0.41	)

Transportation costs	(5.52	)	(4.80	)	(5.69	)	(5.57	)	(7.05	)	(5.38	)	(6.26	)

Net operating expenses	(9.99	)	(10.73	)	(14.65	)	(9.81	)	(11.32	)	(11.25	)	(11.76	)

Operating netback	15.84		10.75		3.32		(3.38	)	6.94		6.64		13.75

SCO and diesel ($/bbl)

Average price realized	62.28		56.69		52.58		43.27		54.39		53.53		59.81

Royalties	2.74		(0.42	)	(0.33	)	(0.57	)	(0.48	)	0.50		(0.65	)

Transportation costs	(3.98	)	(2.96	)	(5.07	)	(3.83	)	(3.06	)	(3.76	)	(3.36	)

Net operating expenses – bitumen	(22.56	)	(20.69	)	(50.90	)	(21.98	)	(26.81	)	(24.87	)	(24.91	)

Net operating expenses – upgrading	(4.31	)	(4.34	)	(12.02	)	(5.51	)	(7.02	)	(5.38	)	(5.96	)

Operating netback	34.17		28.28		(15.74	)	11.38		17.02		20.02		24.93

Average Oil Sands operations ($/bbl)

Average price realized	54.75		47.75		38.28		34.21		45.05		44.23		52.87

Royalties	1.99		(0.41	)	(0.29	)	(0.41	)	(0.43	)	0.28		(0.59	)

Transportation costs	(4.36	)	(3.51	)	(5.38	)	(4.34	)	(4.36	)	(4.26	)	(4.09	)

Net operating expenses – bitumen and upgrading	(22.72	)	(20.77	)	(38.85	)	(22.36	)	(26.53	)	(24.37	)	(26.07	)

Operating netback	29.66		23.06		(6.24	)	7.10		13.73		15.88		22.12

Syncrude ($/bbl)

Average price realized	64.28		58.62		59.34		44.93		60.43		56.91		60.28

Royalties	(4.70	)	(0.26	)	(0.98	)	(0.18	)	2.78		(1.90	)	(1.89	)

Transportation costs	(0.35	)	(0.29	)	(1.70	)	(0.86	)	(0.60	)	(0.53	)	(0.54	)

Net operating expenses – bitumen and upgrading	(29.18	)	(25.05	)	(102.35	)	(27.75	)	(36.11	)	(32.05	)	(35.69	)

Operating netback	30.05		33.02		(45.69	)	16.14		26.50		22.43		22.16

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Twelve months ended
Exploration and Production	Dec 31 2016		Sept 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015		Dec 31 2016		Dec 31 2015

Total Sales Volume (mboe/d)	120.5		103.1		120.4		133.4		101.4		119.3		110.6

Total Production (mboe/d)	118.1		110.6		117.6		125.6		112.3		117.9		114.4

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)	16.7		14.7		5.4		12.8		13.1		12.4		13.5

Hibernia (mbbls/d)	30.1		28.2		24.6		24.1		15.6		26.8		18.1

White Rose (mbbls/d)	10.9		7.5		11.7		13.7		14.8		10.9		12.2

North America Onshore (mboe/d)	2.8		2.7		2.7		3.0		3.1		2.8		3.2

	60.5		53.1		44.4		53.6		46.6		52.9		47.0

Exploration and Production International

Buzzard (mboe/d)	37.5		40.8		52.7		53.4		45.5		46.0		49.8

Golden Eagle (mboe/d)	19.0		16.2		20.5		18.6		17.7		18.6		14.8

United Kingdom (mboe/d)	56.5		57.0		73.2		72.0		63.2		64.6		64.6

Libya (mbbls/d)⁽⁴⁾	1.1		0.5		—		—		2.5		0.4		2.8

	57.6		57.5		73.2		72.0		65.7		65.0		67.4

Netbacks⁽⁵⁾

East Coast Canada ($/bbl)

Average price realized	68.06		61.63		62.39		46.17		52.51		59.31		65.12

Royalties	(15.07	)	(10.93	)	(11.06	)	(5.51	)	(5.79	)	(10.64	)	(12.49	)

Transportation costs	(1.72	)	(2.33	)	(2.05	)	(1.68	)	(2.81	)	(1.91	)	(2.18	)

Operating costs	(9.52	)	(13.57	)	(14.76	)	(13.72	)	(16.86	)	(12.67	)	(14.15	)

Operating netback	41.75		34.80		34.52		25.26		27.05		34.09		36.30

United Kingdom ($/boe)

Average price realized	62.63		56.96		55.43		43.02		54.91		53.91		63.85

Transportation costs	(1.62	)	(1.69	)	(2.00	)	(1.97	)	(2.22	)	(1.84	)	(2.41	)

Operating costs	(7.00	)	(5.29	)	(4.68	)	(5.75	)	(6.20	)	(5.62	)	(6.29	)

Operating netback	54.01		49.98		48.75		35.30		46.49		46.45		55.15

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended					Twelve months ended
Refining and Marketing	Dec 31 2016	Sept 30 2016	Jun 30 2016	Mar 31 2016	Dec 31 2015	Dec 31 2016	Dec 31 2015

Refined product sales (mbbls/d)	514.8	548.7	532.5	489.5	501.2	521.4	523.3

Crude oil processed (mbbls/d)	427.3	465.6	400.2	420.9	430.2	428.6	432.1

Utilization of refining capacity (%)	93	101	87	91	93	93	94

Refining margin ($/bbl)⁽⁶⁾	23.00	17.75	21.65	19.10	23.20	20.30	24.90

Refining operating expense ($/bbl)⁽⁷⁾	5.45	4.55	5.40	5.10	5.25	5.10	5.10

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	115.5	119.8	117.8	107.8	116.1	115.2	118.9

Distillate	79.9	77.8	71.8	75.5	86.2	76.3	91.1

Total transportation fuel sales	195.4	197.6	189.6	183.3	202.3	191.5	210.0

Petrochemicals	10.1	7.2	7.7	12.0	8.9	9.2	10.8

Asphalt	16.8	22.9	15.3	11.9	14.1	16.7	13.1

Other	34.4	34.6	39.4	35.4	28.2	35.9	28.9

Total refined product sales	256.7	262.3	252.0	242.6	253.5	253.3	262.8

Crude oil supply and refining

Processed at refineries (mbbls/d)	204.8	213.5	181.7	212.1	208.0	203.1	208.1

Utilization of refining capacity (%)	92	96	82	96	94	92	94

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	125.8	134.6	133.5	122.4	127.7	129.1	127.3

Distillate	106.8	117.4	118.2	96.6	100.8	109.8	106.9

Total transportation fuel sales	232.6	252.0	251.7	219.0	228.5	238.9	234.2

Asphalt	9.7	16.9	11.7	8.7	10.8	11.8	11.9

Other	15.8	17.5	17.1	19.2	8.4	17.4	14.4

Total refined product sales	258.1	286.4	280.5	246.9	247.7	268.1	260.5

Crude oil supply and refining

Processed at refineries (mbbls/d)	222.5	252.1	218.5	208.8	222.2	225.5	224.0

Utilization of refining capacity (%)	93	105	91	87	93	94	93

See accompanying footnotes and definitions to the quarterly operating summaries.

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations (previously referred to as cash flow from (used in) operations), return on capital employed, Oil Sands cash operating costs and netbacks – are not prescribed by GAAP. Suncor includes these financial measures because management and readers may use this information to analyze business performance, leverage and liquidity. These non-GAAP financial measures do not have any standardized meaning and, therefore, may not be comparable to similar measures presented by other companies. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

Operating earnings (loss) and Oil Sands cash operating costs for each quarter in 2016 and 2015 are each defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in each respective Quarterly Report to Shareholders. Funds flow from (used in) operations and return on capital employed for each quarter in 2016 and 2015 are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective Quarterly Report. The remainder of the non-GAAP financial measures not otherwise mentioned in this paragraph are defined and reconciled in Suncor's Management's Discussion and Analysis contained in the 2015 Annual Report.

Suncor Energy Inc.
150 - 6 Avenue S.W., Calgary, Alberta, Canada T2P 3E3
T: 403-296-8000


	Three months ended December 31		Twelve months ended December 31
Net of transportation costs, but before royalties	2016	2015	2016	2015

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	66.33	49.69	57.37	62.87

E&P Canada – Natural gas ($/mcfe)	2.43	1.03	1.71	1.78

E&P International ($/boe)	61.01	52.68	52.07	61.44


(thousands)		December 31, 2016

Common shares		1 667 914

Common share options – exercisable		17 821

Common share options – non-exercisable		13 621




Number of COS common shares tendered (millions)		353.3

Multiplied by share exchange ratio		0.28

Number of Suncor common shares issued (millions)		98.9

Share price on acquisition date		$31.88

Fair value of consideration ($ millions)		3 154


($ millions)		February 5, 2016

Fixed-term debt, redeemable at the option of the company

7.75% Notes, due 2019 (US$500)		755

7.90% Notes, due 2021 (US$250)		389

4.50% Notes, due 2022 (US$400)		515

8.20% Notes, due 2027 (US$74)		114

6.00% Notes, due 2042 (US$300)		316

Total Notes		2 089

Credit facility		550

Total long-term debt		2 639


1.	Advisories	5
2.	Fourth Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	24
6.	Financial Condition and Liquidity	26
7.	Quarterly Financial Data	30
8.	Other Items	31
9.	Non-GAAP Financial Measures Advisory	32
10.	Common Abbreviations	37
11.	Forward-Looking Information	38


($ millions)	Energy Trading		Risk Management		Total

Fair value outstanding at December 31, 2015	(18	)	20		2

Cash Settlements – paid (received) during the period	29		(13	)	16

Unrealized (losses) recognized in earnings during the period (note 7)	(47	)	(25	)	(72	)

Fair value outstanding at December 31, 2016	(36	)	(18	)	(54	)


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

Accounts receivable	46		109		—	155

Accounts payable	(100	)	(109	)	—	(209	)

	(54	)	—		—	(54	)


($ millions)

Fair value of Kent Breeze wind farm		47

Fair value of Suncor's share of Wintering Hills wind farm		77

Fair value of deferred financing arrangement		303

Total purchase consideration		427


($ millions)

Working capital	36

Property, plant and equipment	393

Decommissioning provision	(2	)

Net assets acquired	427


	For the Twelve Months Ended
	Dec 31 2016	Sept 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2015

Return on capital employed^(A)

– excluding major projects in progress (%)	0.5	(4.6	)	(4.9	)	(2.2	)	0.6

– including major projects in progress (%)	0.4	(3.9	)	(4.1	)	(1.9	)	0.5


bbl		– barrel
mbbls/d		– thousands of barrels per day
boe		– barrels of oil equivalent
boe/d		– barrels of oil equivalent per day
mboe/d		– thousands of barrels of oil equivalent per day
m3/d		– cubic metres per day
SCO		– synthetic crude oil