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

"Strong performance in both our upstream and downstream operations combined to generate record quarterly funds from operations of more than $3 billion," said Steve Williams, president and chief executive officer. "This was significantly higher than our capital and dividend commitments, allowing us to reduce long-term debt and return additional value to shareholders through more than $800 million in share repurchases."

Suncor recorded fourth quarter 2017 operating earnings⁽¹⁾ of $1.310 billion ($0.79 per common share) compared to $636 million ($0.38 per common share) in the prior year quarter. Highlights of the quarter include improved crude oil pricing and benchmark crack spreads, lower operating and exploration costs, refinery utilization of 94%, higher sales volumes at Oil Sands and continued strong upstream production. Improved benchmark pricing in the quarter was partially offset by the strengthening of the Canadian dollar.

Funds from operations⁽¹⁾ were $3.016 billion ($1.83 per common share) compared to $2.365 billion ($1.42 per common share) in the fourth quarter of 2016 and were influenced by the same factors impacting operating earnings noted above. Cash flow provided by operating activities, which includes changes in non-cash working capital, was $2.755 billion for the fourth quarter of 2017, compared to $2.791 billion for the fourth quarter of 2016.

Net earnings were $1.382 billion ($0.84 per common share) in the fourth quarter of 2017, compared to $531 million ($0.32 per common share) in the prior year quarter. Net earnings for the fourth quarter of 2017 included a net $124 million deferred income tax recovery related to a decrease in the United States (U.S.) corporate tax rate from 35% to 21%, an unrealized after-tax foreign exchange loss of $91 million on the revaluation of U.S. dollar denominated debt, after-tax insurance proceeds of $55 million, an after-tax loss of $18 million for early payment of debt and a net after-tax gain of $2 million on interest rate swaps associated with debt issued in the fourth quarter. Net earnings in the prior year quarter included an unrealized after-tax foreign exchange loss of $222 million on the revaluation of U.S. dollar denominated debt, $71 million of after-tax derecognition charges and a non-cash after-tax mark to market gain of $188 million on interest rate derivatives.

Suncor's total upstream production was 736,400 boe/d in the fourth quarter of 2017, compared to 738,500 boe/d in the prior year quarter.

Oil Sands operations production was 446,800 barrels per day (bbls/d) in the fourth quarter of 2017, compared to 433,400 bbls/d in the prior year quarter, with the increase as a result of improved mining and extraction reliability and record Firebag production, partially offset by lower production at MacKay River. Upgrader utilization in the fourth quarters of 2017 and 2016 was strong at 93%, with both periods impacted by planned maintenance. Oil Sands operations production in the fourth quarter of 2017 also benefited from bitumen froth received from the Fort Hills primary extraction assets, which was further upgraded into synthetic crude oil (SCO).

Oil Sands operations cash operating costs per barrel⁽¹⁾ decreased to $24.20 in the fourth quarter of 2017, compared to $24.95 in the prior year quarter, and represent the lowest level achieved during a fourth quarter in more than a decade. Improved production and a continued focus on cost discipline in 2017 resulted in Oil Sands operations achieving the lowest annual cash operating costs per barrel in more than a decade, decreasing to $23.80 from $26.50 in 2016.

Suncor's share of Syncrude production was 174,400 bbls/d in the fourth quarter of 2017, compared to 187,000 bbls/d in the prior year quarter. Syncrude upgrader reliability was strong in both quarters, with the fourth quarter of 2017 achieving 94% and the prior year quarter achieving 102%. Syncrude cash operating costs per barrel⁽¹⁾ in the fourth quarter of 2017 were $32.80, and were comparable to $32.55 in the prior year quarter, due to a decrease in operating costs offsetting lower production.

Production volumes in Exploration and Production (E&P) were 115,200 boe/d in the fourth quarter of 2017, compared to 118,100 boe/d in the prior year quarter, with the decrease attributed to lower offshore production, partially offset by increased production from Libya and initial production from the newly commissioned Hebron asset, which began producing in the fourth quarter ahead of schedule.

R&M's refinery crude throughput was 432,400 bbls/d in the fourth quarter of 2017, compared to 427,300 bbls/d in the prior year quarter, with strong reliability at the majority of the company's refineries partially offset by the impact of a third-party power outage at the Montreal refinery. Average refinery utilization was 94% in the fourth quarter of 2017, and was comparable to 93% in the prior year quarter.

"We achieved greater than 90% reliability at all of our Oil Sands upgrading assets and a combined refinery utilization of 94% during the fourth quarter," said Williams. "Our continued focus on disciplined cost management, combined with improved overall reliability, drove annual oil sands cash operating costs below $25 per barrel for the first time in ten years."

The disciplined execution of Suncor's 2017 capital program was focused on bringing Suncor's major growth projects, Fort Hills and Hebron, to first oil, while continuing to invest in the safety, reliability and efficiency of the company's operating assets. The company is proud to report that both Fort Hills and Hebron have been safely brought online and are now producing oil, demonstrating Suncor's continued ability to deliver on its commitments.

The company spent $1.444 billion on capital expenditures during the fourth quarter of 2017, bringing annual spending to $5.822 billion, excluding capitalized interest. 2017 annual spending includes additional expenditures of approximately $150 million related to the facility incident that occurred at Syncrude in the first quarter of 2017. The company expects to receive a total of approximately $140 million in property damage insurance proceeds related to the incident, for net capital expenditures of $5.682 billion for the year. In the fourth quarter of 2017, the company received an interim payment of $76 million of its anticipated property damage insurance proceeds related to the incident, with the remaining payment anticipated to be received in 2018.

The Fort Hills project began producing paraffinic froth-treated bitumen from secondary extraction on January 27, 2018, and the production ramp up to the project's nameplate capacity of 194,000 bbls/d is progressing on schedule. Prior to secondary extraction coming online, the company continued to test the front end of the plant to mitigate the risk associated with the ramp up in 2018, resulting in bitumen froth production. The bitumen froth was further processed by Oil Sands operations and included as SCO production in the period. The total cost of the project to mechanical completion at the end of 2017 was approximately $17.160 billion, excluding the impact of unfavourable foreign exchange. Suncor's estimated capital intensity is approximately $83,000 to mechanical completion and is comparable to the original per flowing barrel cost estimate of $84,000.

During the fourth quarter of 2017, the Fort Hills partners resolved the previously announced commercial dispute and reached an agreement whereby Suncor and Teck Resources Limited (Teck) each acquired an additional working interest in the Fort Hills project from Total E&P Canada Ltd. (Total). Under the terms of the agreement Suncor's share of the project increased to 53.06% and Teck's share increased to 20.89%, for approximate acquisition costs of $300 million and $120 million, respectively, and Total's share decreased to 26.05%. Working interests in the Fort Hills project may be further adjusted in accordance with the terms of the agreement.

In November, Suncor completed the sale of a 49% interest in the East Tank Farm Development to the Fort McKay and Mikisew Cree First Nations for proceeds of $503 million. The mutually beneficial agreement represents the most significant business investment ever made in Canada by First Nations and demonstrates Suncor's commitment to sustainable resource development in partnership with the community.

During the fourth quarter of 2017, first oil at Hebron was achieved ahead of schedule and production continues to ramp up following favourable initial results. At peak, the project is expected to produce more than 30,000 bbls/d, net to Suncor, ramping up over the next several years. The post-sanction cost of the project to first oil was approximately $2.4 billion. Other E&P activity in the fourth quarter included development drilling at White Rose, Hebron, Terra Nova and Hibernia, as well as development work on the West White Rose Project and the Norwegian Oda project.

"With Fort Hills and Hebron both successfully commissioned and now producing oil, the safe and steady ramp up of production is proceeding as planned," said Williams. "We believe the addition of these high-quality assets to our portfolio will return long-term value to shareholders and could not have been achieved without the hard work and dedication of our employees and business partners."

During the fourth quarter of 2017, the company issued US$750 million of 4.00% senior unsecured notes due in 2047. The proceeds were combined with the $503 million received from the sale of a 49% interest in the East Tank Farm Development and were used for the early redemption of US$600 million of 6.05% senior unsecured notes and $700 million of 5.80% Medium Term Notes, both originally due in 2018. The net decrease in long-term debt was executed early to take advantage of favourable market conditions in the fourth quarter of 2017, and is expected to reduce future financing costs and provide ongoing balance sheet flexibility. All debt previously due in 2018 has now been repaid and, apart from US$223 million due in 2019, the company does not have a significant debt repayment due until 2021.

Under the company's normal course issuer bid, which commenced in the second quarter of 2017, the company repurchased $835 million of its own shares for cancellation in the fourth quarter of 2017, bringing the full year total shares purchased and cancelled to $1.413 billion.

Subsequent to the end of the quarter, Suncor's Board of Directors approved a quarterly dividend of $0.36 per common share, which represents an increase of 12.5% over the prior quarter dividend, and also approved a further $2 billion share buyback program currently anticipated to commence after the expiry of the company's current program on May 1, 2018, continuing to demonstrate the company's ability to generate cash flow and commitment to return cash to shareholders.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Net earnings	1 382		531		4 458		445

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	91		222		(702	)	(524	)

(Gain) loss on interest rate swaps⁽²⁾	(2	)	(188	)	20		(6	)

Impact of income tax rate adjustment on deferred taxes⁽³⁾	(124	)	—		(124	)	(180	)

Insurance proceeds⁽⁴⁾	(55	)	—		(55	)	—

Loss on early payment of long-term debt⁽⁵⁾	18		—		28		73

Derecognition⁽⁶⁾	—		71		—		71

Gain on significant disposal⁽⁷⁾	—		—		(437	)	—

COS acquisition and integration costs⁽⁸⁾	—		—		—		38

Operating earnings (loss)⁽¹⁾	1 310		636		3 188		(83	)

(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): (Gain) loss on forward interest rate swaps associated with issued debt, due to changes in long-term interest rates, in the Corporate segment.
(3): In the fourth quarter of 2017, the company recorded a net adjustment to its deferred income taxes of $124 million related to tax reform legislation in the U.S., with the most significant impact resulting from a decrease in the corporate tax rate from 35% to 21%. The net deferred tax recovery of $124 million was comprised of a $140 million recovery in R&M, a $14 million expense in E&P and a $2 million expense in the company's Energy Trading business. The year ended December 31, 2016 was impacted by an adjustment to the company's deferred income taxes resulting from a decrease from 50% to 40% in the United Kingdom tax rate on oil and gas profits from the North Sea.
(4): During the fourth quarter of 2017, the company received after-tax property damage insurance proceeds of $55 million ($76 million before tax) related to a facility incident at Syncrude, which occurred in the first quarter of 2017.
(5): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains, in the Corporate segment.
(6): 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.
(7): Gain of $354 million in the R&M segment related to the sale of the company's lubricants business, combined with a gain of $83 million in the Corporate segment related to the sale of the company's interest in the Cedar Point wind facility.
(8): Transaction and related charges associated with the acquisition of Canadian Oil Sands Limited (COS) in the Corporate segment.

Suncor has updated its full year business environment outlook assumption as a result of the recently announced change in the U.S. corporate tax rate from 35% to 21%. For further details and advisories regarding Suncor's 2018 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 March 1, 2017 (the 2016 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

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

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), specifically International Accounting Standard (IAS) 34 Interim Financial Reporting as issued by the International Accounting Standards Board, which is within the framework of International Financial Reporting Standards (IFRS).

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, except for Libya, which is on an entitlement basis. Certain prior year amounts in the Consolidated Statements of Comprehensive Income (Loss) have been reclassified to conform to the current year's presentation.

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

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense, discretionary free funds flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings (loss) is 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. Oil Sands operations cash operating costs, Syncrude 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 Segment Results and Analysis section of this document. Funds from (used in) operations, ROCE, discretionary free funds flow, refining margin and refining operating expense 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)	2017		2016		2017		2016

Net earnings (loss)

Oil Sands	670		276		1 009		(1 149	)

Exploration and Production	217		54		732		190

Refining and Marketing	886		524		2 658		1 890

Corporate, Energy Trading and Eliminations	(391	)	(323	)	59		(486	)

Total	1 382		531		4 458		445

Operating earnings (loss)⁽¹⁾

Oil Sands	615		316		954		(1 109	)

Exploration and Production	231		54		746		10

Refining and Marketing	746		524		2 164		1 890

Corporate, Energy Trading and Eliminations	(282	)	(258	)	(676	)	(874	)

Total	1 310		636		3 188		(83	)

Funds from (used in) operations⁽¹⁾

Oil Sands	1 780		1 372		4 738		2 669

Exploration and Production	431		385		1 725		1 313

Refining and Marketing	935		722		2 841		2 606

Corporate, Energy Trading and Eliminations	(130	)	(114	)	(165	)	(600	)

Total	3 016		2 365		9 139		5 988

Capital and Exploration Expenditures⁽²⁾

Sustaining	807		497		2 916		2 275

Growth	637		913		2 906		3 711

Total	1 444		1 410		5 822		5 986


	Three months ended December 31		Twelve months ended December 31
	2017	2016	2017	2016

Production volumes by segment

Oil Sands (mbbls/d)	621.2	620.4	563.7	504.9

Exploration and Production (mboe/d)	115.2	118.1	121.6	117.9

Total (mboe/d)	736.4	738.5	685.3	622.8

Production mix

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

Refinery utilization (%)	94	93	96	93

Refinery crude oil processed (mbbls/d)	432.4	427.3	441.2	428.6

Suncor's consolidated net earnings for the fourth quarter of 2017 were $1.382 billion, compared to net earnings of $531 million for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this document. Other items affecting net earnings over these periods included:


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Net earnings	1 382		531		4 458		445

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	91		222		(702	)	(524	)

(Gain) loss on interest rate swaps⁽²⁾	(2	)	(188	)	20		(6	)

Impact of income tax rate adjustment on deferred taxes⁽³⁾	(124	)	—		(124	)	(180	)

Insurance proceeds⁽⁴⁾	(55	)	—		(55	)	—

Loss on early payment of long-term debt⁽⁵⁾	18		—		28		73

Derecognition⁽⁶⁾	—		71		—		71

Gain on significant disposal⁽⁷⁾	—		—		(437	)	—

COS acquisition and integration costs⁽⁸⁾	—		—		—		38

Operating earnings (loss)⁽¹⁾	1 310		636		3 188		(83	)

(1): Operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the document.
(2): (Gain) loss on forward interest rate swaps associated with issued debt, due to changes in long-term interest rates, in the Corporate segment.
(3): In the fourth quarter of 2017, the company recorded a net adjustment to its deferred income taxes of $124 million related to tax reform legislation in the U.S., with the most significant impact resulting from a decrease in the corporate tax rate from 35% to 21%. The net deferred tax recovery of $124 million was comprised of a $140 million recovery in R&M, a $14 million expense in E&P and a $2 million expense in the company's Energy Trading business. The year ended December 31, 2016 was impacted by an adjustment to the company's deferred income taxes resulting from a decrease from 50% to 40% in the U.K. tax rate on oil and gas profits from the North Sea.
(4): During the fourth quarter of 2017, the company received after-tax property damage insurance proceeds of $55 million ($76 million before tax) related to a facility incident at Syncrude, which occurred in the first quarter of 2017, in the Oil Sands segment.
(5): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains, in the Corporate segment.
(6): 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.
(7): Gain of $354 million in the R&M segment related to the sale of the company's lubricants business, combined with a gain of $83 million in the Corporate segment related to the sale of the company's interest in the Cedar Point wind facility.
(8): Transaction and related charges associated with the acquisition of Canadian Oil Sands Limited (COS) in the Corporate segment.

Suncor recorded fourth quarter 2017 operating earnings of $1.310 billion compared to $636 million in the prior year quarter, with the increase attributed to improved crude oil pricing and benchmark crack spreads, lower operating and exploration costs, and higher sales volumes at Oil Sands, partially offset by the impact of a stronger Canadian dollar and an increase in royalties.

Suncor's consolidated operating earnings for 2017 were $3.188 billion, compared to an operating loss of $83 million in the prior year. The improvement was due to improved crude oil pricing and benchmark crack spreads, higher upstream production, improved refinery crude throughput and sales and lower exploration expense, partially offset by a stronger Canadian dollar and increased maintenance expenses at Syncrude. Oil Sands production in 2016 was significantly impacted by shut-in production associated with the forest fires in the Fort McMurray region, which more than offset the impact of the facility incident at Syncrude and an overall increase in Oil Sands planned maintenance in 2017.

The after-tax share-based compensation expense decreased to $85 million during the fourth quarter of 2017, compared to $153 million during the prior year quarter, as a result of a smaller increase in the share price during the current period when compared to the share price increase in the prior year quarter.

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

Average for the
Three months ended
December 31

Average for the
Twelve months ended
December 31

2017

2016

2017

2016

WTI crude oil at Cushing

US$/bbl

55.40

49.35

50.95

43.35

Dated Brent crude

US$/bbl

61.40

49.50

54.25

43.75

Dated Brent/Maya crude oil FOB price differential

US$/bbl

9.60

6.70

7.70

7.50

MSW at Edmonton

Cdn$/bbl

69.30

62.00

63.20

51.90

WCS at Hardisty

US$/bbl

43.10

35.00

38.95

29.55

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

US$/bbl

12.30

14.35

11.95

13.85

Condensate at Edmonton

US$/bbl

57.95

48.35

51.55

42.50

Natural gas (Alberta spot) at AECO

Cdn$/mcf

1.70

3.10

2.15

2.15

Alberta Power Pool Price

Cdn$/MWh

22.35

21.95

22.15

18.20

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

19.40

14.35

17.70

14.05

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

20.20

10.55

16.30

12.60

Portland 3-2-1 crack⁽¹⁾

US$/bbl

22.10

14.95

22.15

16.50

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

18.25

13.15

17.65

13.40

Exchange rate

US$/Cdn$

0.79

0.75

0.77

0.75

Exchange rate (end of period)

US$/Cdn$

0.80

0.74

0.80

0.74

(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 2017 for sweet SCO were favourably impacted by a higher WTI price of US$55.40/bbl, compared to US$49.35/bbl in the prior year quarter, as well as a favourable differential for SCO relative to WTI. Suncor also produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $69.30/bbl compared to $62.00/bbl in the prior year quarter and prices for WCS at Hardisty increased to US$43.10/bbl from US$35.00/bbl in the fourth quarter of 2016.

Bitumen production that Suncor does not upgrade is blended with diluent or SCO to facilitate delivery on pipeline systems. Net bitumen price realizations are therefore influenced by both prices for Canadian heavy crude oil (WCS at Hardisty is a common reference), prices for diluent (Condensate at Edmonton) and SCO. Bitumen price realizations can also be affected by bitumen quality and spot sales.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing increased to US$61.40/bbl in the fourth quarter of 2017, compared to US$49.50/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $1.70/mcf in the fourth quarter of 2017, from $3.10/mcf in the prior year quarter.

Suncor's refining margins are influenced primarily by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour crude differentials. More complex refineries can earn greater refining margins by processing less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins of a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual refining margins are based on first-in, first-out (FIFO) inventory accounting, where a delay exists between the time that feedstock is purchased and when it is processed and sold to a third party. A FIFO loss normally reflects a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. Specific refinery margins are further impacted by actual crude purchase costs, refinery configuration, production mix and realized prices for refined products sales in markets unique to each refinery.

Excess electricity produced in Suncor's Oil Sands operations is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the Oil Sands operations cash operating cost per barrel metric. The Alberta power pool price increased to an average of $22.35/MWh in the fourth quarter of 2017, compared to $21.95/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In the fourth quarter of 2017, the Canadian dollar strengthened in relation to the U.S. dollar as the average exchange rate increased to US$0.79 per one Canadian dollar from US$0.75 per one Canadian dollar in the prior year quarter. This rate increase had a negative impact on price realizations for the company during the fourth quarter of 2017 when compared to the prior year quarter.

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


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Gross revenues	4 116		3 356		13 137		9 522

Less: Royalties	(175	)	(4	)	(355	)	(52	)

Operating revenues, net of royalties	3 941		3 352		12 782		9 470

Net earnings (loss)	670		276		1 009		(1 149	)

Adjusted for:

Insurance proceeds⁽¹⁾	(55	)	—		(55	)	—

Derecognition⁽²⁾	—		40		—		40

Operating earnings (loss)⁽³⁾	615		316		954		(1 109	)

Oil Sands operations	*445*		192		*1 040*		(1 135	)

Oil Sands ventures	*170*		124		*(86*	)	26

Funds from operations⁽³⁾	1 780		1 372		4 738		2 669

(1): During the fourth quarter of 2017, the company received after-tax property damage insurance proceeds of $55 million ($76 million before tax) related to the facility incident at Syncrude that occurred in the first quarter of 2017.
(2): 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 those assets.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Operating earnings for Oil Sands operations were $445 million in the fourth quarter of 2017, compared to $192 million in the prior year quarter. The improvement was due to higher crude price realizations, increased crude oil production and sales, and lower DD&A, partially offset by the impact of a stronger Canadian dollar and an increase in royalties, resulting from the impact of favourable royalty audit assessments in the prior year quarter and higher bitumen pricing.

Operating earnings for Oil Sands ventures were $170 million in the fourth quarter of 2017, compared to operating earnings of $124 million in the prior year quarter. The increase was a result of higher crude price realizations and lower operating costs, partially offset by decreased crude oil production, the impact of a stronger Canadian dollar and higher royalties.


	Three months ended December 31		Twelve months ended December 31
(mbbls/d)	2017	2016	2017	2016

Upgraded product (SCO and diesel)	324.9	324.5	317.7	258.9

Non-upgraded bitumen	121.9	108.9	111.7	115.9

Oil Sands operations	446.8	433.4	429.4	374.8

Oil Sands ventures – Syncrude	174.4	187.0	134.3	130.1

Total	621.2	620.4	563.7	504.9

(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. Essentially all of the bitumen produced at Syncrude is upgraded to sweet SCO.

Oil Sands operations production was 446,800 bbls/d in the fourth quarter of 2017, compared to 433,400 bbls/d in the prior year quarter, with the increase driven primarily by improved mining and extraction reliability, bitumen froth production received from Fort Hills, which was further processed at Oil Sands Base into SCO, and record Firebag production. Upgrader utilization in both the fourth quarters of 2017 and 2016 was 93%, with both periods being impacted by planned maintenance. All planned maintenance in the fourth quarter of 2017 was completed by the end of the year.


	Three months ended December 31		Twelve months ended December 31
(mbbls/d)	2017	2016	2017	2016

Oil Sands operations sales volumes

Sweet SCO	95.5	87.2	107.9	87.3

Diesel	21.1	28.4	27.5	21.2

Sour SCO	214.4	201.5	183.6	153.4

Upgraded product	331.0	317.1	319.0	261.9

Non-upgraded bitumen	130.7	103.5	110.6	117.4

Oil Sands operations	461.7	420.6	429.6	379.3

Oil Sands ventures – Syncrude	174.4	187.0	134.3	130.1

Total	636.1	607.6	563.9	509.4

Sales volumes for Oil Sands operations increased to 461,700 bbls/d in the fourth quarter of 2017, from 420,600 bbls/d in the prior year quarter, as a result of the increase in production combined with a draw of inventory.

Suncor's share of Syncrude sales was 174,400 bbls/d in the fourth quarter of 2017, compared to 187,000 bbls/d in the prior year quarter. Both quarters had strong upgrader reliability at 94% and 102%, respectively.


	Three months ended December 31		Twelve months ended December 31
	2017	2016	2017	2016

Oil Sands Base

Bitumen production (mbbls/d)	296.7	284.8	305.4	238.0

Bitumen ore mined (thousands of tonnes per day)	450.0	420.3	464.4	351.1

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

In Situ

Bitumen production – Firebag (mbbls/d)	208.5	204.5	181.5	180.8

Bitumen production – MacKay River (mbbls/d)	28.3	33.9	31.1	27.6

Total In Situ bitumen production (mbbls/d)	236.8	238.4	212.6	208.4

Total Oil Sands operations bitumen production (mbbls/d)	533.5	523.2	518.0	446.4

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

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

Bitumen production at Oil Sands operations in the fourth quarter of 2017 increased to 533,500 bbls/d, compared to 523,200 bbls/d in the prior year quarter, attributed to increased production from Oil Sands Base as a result of improved mining and extraction reliability, bitumen froth from the Fort Hills primary extraction assets and an increase in Firebag production, partially offset by a decrease at MacKay River, which was due to a third-party cogeneration facility outage early in the quarter. Firebag continued to perform over nameplate capacity in the fourth quarter of 2017, benefiting from the completion of a full turnaround of the expanded central facility earlier in the year.


Net of transportation costs, but before royalties	Three months ended December 31				Twelve months ended December 31
($/bbl)	2017		2016		2017		2016

Oil Sands operations

SCO and diesel	66.40		58.30		61.40		49.77

Bitumen	38.94		26.16		33.60		18.12

Crude sales basket (all products)	58.63		50.39		54.24		39.97

Crude sales basket, relative to WTI	(11.50	)	(15.41	)	(11.93	)	(17.83	)

Oil Sands ventures

Syncrude – sweet SCO	73.28		63.93		66.05		56.38

Syncrude, relative to WTI	3.15		(1.87	)	(0.12	)	(1.42	)

Average price realizations at Oil Sands operations increased to $58.63/bbl in the fourth quarter of 2017 from $50.39/bbl in the prior year quarter, due to higher WTI benchmark prices, as well as improved heavy crude and SCO differentials, partially offset by the impact of a stronger Canadian dollar.

Average price realizations at Syncrude increased to $73.28/bbl in the fourth quarter of 2017 from $63.93/bbl in the prior year quarter due to the increase in the WTI benchmark price and improved SCO differentials, partially offset by the impact of a stronger Canadian dollar.

Royalties for the Oil Sands segment were higher in the fourth quarter of 2017 compared to the prior year quarter, primarily due to favourable audit assessments realized in the prior period, improved bitumen pricing and higher production in the current quarter.

Operating and transportation expenses for the fourth quarter of 2017 decreased when compared to the prior year quarter, due to a decline in natural gas prices and lower operating and maintenance expenses at Syncrude, as a result of continued efforts to sustainably reduce costs. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs.

DD&A and exploration expenses for the fourth quarter of 2017 were lower in comparison to the same period of 2016, due to a reduction in asset net book value.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Operating, selling and general expense (OS&G)	1 616		1 634		6 257		5 777

Syncrude OS&G	(536	)	(577	)	(2 195	)	(1 749	)

Non-production costs⁽²⁾	(34	)	(54	)	(102	)	(136	)

Excess power capacity and other⁽³⁾	(52	)	(51	)	(232	)	(197	)

Inventory changes	—		42		1		(63	)

Oil Sands operations cash operating costs⁽¹⁾	994		994		3 729		3 632

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	24.20		24.95		23.80		26.50

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	536		577		2 195		1 749

Non-production costs⁽²⁾	(10	)	(17	)	(37	)	(31	)

Syncrude cash operating costs⁽¹⁾	526		560		2 158		1 718

Syncrude cash operating costs ($/bbl)⁽¹⁾	32.80		32.55		44.05		35.95

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.
(2): Significant non-production costs include, but are not limited to, share-based compensation expense and research expenses.
(3): Excess power capacity and other includes, but is not limited to, the operational revenue impacts of excess power from a cogeneration unit and the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.

In the fourth quarter of 2017, Oil Sands operations cash operating costs per barrel were $24.20, compared to $24.95 in the prior year quarter, a result of higher production. Total Oil Sands operations cash operating costs were the same as the prior year quarter at $994 million, with increased operating and maintenance costs being offset by a decrease in natural gas pricing.

In the fourth quarter of 2017, non-production costs, which are excluded from Oil Sands operations cash operating costs, were lower than the prior year quarter, primarily due to a decrease in share-based compensation expense, which was attributed to a smaller increase in the company's share price during the quarter when compared to the prior year period.

Excess power capacity and other for the fourth quarter of 2017 was consistent with the fourth quarter of 2016.

Inventory changes in the fourth quarter of 2017 represent a draw of inventory, compared to a build of inventory in the prior year quarter, due to high refinery demand in the U.S. The draw of product inventory in the current quarter was offset by an increase in inventory costs, primarily attributed to the increase in royalty costs.

In the fourth quarter of 2017, Syncrude cash operating costs per barrel were $32.80, compared to $32.55 in the prior year period, with the increase attributed to lower production, partially offset by lower operating expenses. Suncor's share of Syncrude cash operating costs decreased to $526 million, from $560 million in the previous year quarter.

The company completed planned upgrader maintenance in the fourth quarter of 2017 as well as planned maintenance at MacKay River. There are no major maintenance events planned at Oil Sands operations during the first quarter of 2018.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Gross revenues⁽¹⁾	802		730		3 177		2 432

Less: Royalties⁽¹⁾	(53	)	(83	)	(266	)	(201	)

Operating revenues, net of royalties	749		647		2 911		2 231

Net earnings	217		54		732		190

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	14		—		14		(180	)

Operating earnings (loss)⁽³⁾	231		54		746		10

E&P Canada	77		2		*159*		(58	)

E&P International	*154*		52		*587*		68

Funds from operations⁽³⁾	431		385		1 725		1 313

(1): Production, revenues and royalties from the company's Libya operations have been presented in the E&P section of this document on an entitlement basis and exclude an equal and offsetting gross up of revenues and royalties, which is required for presentation purposes in the company's financial statements under the working-interest basis.
(2): Adjustments to the company's deferred income taxes relating to tax reform legislation in the U.S. for North America Onshore assets in the fourth quarter of 2017 and a decrease in the U.K. tax rate on oil and gas profits in the North Sea from 50% to 40% during the third quarter of 2016.
(3): Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this document.

Operating earnings for E&P Canada in the fourth quarter of 2017 increased to $77 million, from $2 million in the prior year quarter, as a result of higher crude price realizations, lower exploration expense and lower royalties, partially offset by lower production and a build in East Coast inventory in the current year quarter compared to a draw in the prior year quarter.

Operating earnings for E&P International in the fourth quarter of 2017 increased to $154 million, from $52 million in the prior year quarter, due to higher crude price realizations, increased production from Libya and lower DD&A at Buzzard resulting from an increase in reserves, partially offset by lower U.K. production.


	Three months ended December 31		Twelve months ended December 31
	2017	2016	2017	2016

E&P Canada

Terra Nova (mbbls/d)	14.6	16.7	11.5	12.4

Hibernia (mbbls/d)	27.1	30.1	28.5	26.8

White Rose (mbbls/d)	10.6	10.9	11.4	10.9

Hebron (mbbls/d)	1.8	—	0.4	—

North America Onshore (mboe/d)	1.4	2.8	1.9	2.8

	55.5	60.5	53.7	52.9

E&P International

Buzzard (mboe/d)	36.6	37.5	43.8	46.0

Golden Eagle (mboe/d)	17.9	19.0	19.6	18.6

United Kingdom (mboe/d)	54.5	56.5	63.4	64.6

Libya (mbbls/d)	5.2	1.1	4.5	0.4

	59.7	57.6	67.9	65.0

Total Production (mboe/d)	115.2	118.1	121.6	117.9

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

Total Sales Volumes (mboe/d)	104.8	120.5	120.8	119.3

E&P Canada production averaged 55,500 boe/d in the fourth quarter of 2017, compared to 60,500 boe/d in the prior year quarter. The decrease was primarily due to natural declines, partially offset by production from development drilling at existing East Coast assets and initial production from Hebron.

E&P International production increased to 59,700 boe/d in the fourth quarter of 2017, compared to 57,600 boe/d in the prior year quarter. The increase was primarily due to planned maintenance at Buzzard in the prior year quarter and higher production from Libya, partially offset by a third-party pipeline outage late in the quarter that impacted Buzzard. The third-party pipeline has since returned to operations and Buzzard is operating at normal rates.

E&P sales volumes decreased to 104,800 boe/d in the fourth quarter of 2017, compared to 120,500 boe/d in the prior year quarter, for the same reasons noted in production above combined with a build of inventory in East Coast Canada as a result of tanker shipment timing.

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

E&P royalties decreased in the fourth quarter of 2017, compared to the prior year quarter, due to decreased sales volumes and higher eligible capital expenditures at E&P Canada, partially offset by improved crude prices.

Operating and transportation expenses decreased when compared to the prior year quarter, primarily due to the decrease in sales volumes in East Coast Canada, partially offset by the addition of operating expenses from Hebron following the start of operations, and increased activity in Libya.

DD&A expense decreased in the fourth quarter of 2017, compared to the prior year quarter, due primarily to lower depletion rates at Buzzard, attributed to an increased reserve base, and the build of inventory in East Coast Canada.

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


	Three months ended December 31			Twelve months ended December 31
($ millions)	2017		2016	2017		2016

Operating revenues	5 426		4 675	19 963		17 567

Net earnings	886		524	2 658		1 890

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽¹⁾	(140	)	—	(140	)	—

Gain on significant disposal⁽²⁾	—		—	(354	)	—

Operating earnings⁽³⁾	746		524	2 164		1 890

Refining and Supply	*719*		439	*1 902*		1 527

Marketing	27		85	*262*		363

Funds from operations⁽³⁾	935		722	2 841		2 606

(1): The company recorded an adjustment to its deferred income taxes related to tax reform legislation in the U.S., with the most significant impact resulting from a decrease in the corporate tax rate from 35% to 21%.
(2): After-tax gain related to the sale of the company's lubricants business.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

R&M operating earnings on a FIFO basis were $746 million in the fourth quarter of 2017, compared to $524 million in the prior year quarter, with the increase described below. Using a LIFO⁽¹⁾ method of inventory valuation, which management uses to assess performance, earnings were $566 million compared to $384 million in the prior year quarter, after removing the impact of the sale of the company's lubricants business in the first quarter of 2017.

Refining and Supply operating earnings were $719 million in the fourth quarter of 2017, compared to $439 million in the prior year quarter. The increase was attributed to higher benchmark crack spreads and a larger FIFO gain, partially offset by the impact of the stronger Canadian dollar.

Marketing activities contributed $27 million to operating earnings in the fourth quarter of 2017, compared to $85 million in the prior year quarter. After removing the impact of the sale of the lubricants business, Marketing operating earnings decreased quarter-over-quarter due to a write-off of certain information technology assets and additional selling costs associated with higher sales volumes, partially offset by increased sales volumes, including record quarterly wholesale sales volumes in Canada and improved unit margins.

During the first quarter of 2017, Suncor completed the sale of its Petro-Canada lubricants business, which contributed $30 million in net earnings and $40 million in funds from operations in the fourth quarter of 2016. The impact of the lubricants sale has been reflected in Financing Expense and Other Income in the bridge analysis above.


	Three months ended December 31		Twelve months ended December 31
	2017	2016	2017	2016

Crude oil processed (mbbls/d)

Eastern North America	188.7	204.8	206.4	203.1

Western North America	243.7	222.5	234.8	225.5

Total	432.4	427.3	441.2	428.6

Refinery utilization⁽¹⁾ (%)

Eastern North America	85	92	93	92

Western North America	102	93	98	94

Total	94	93	96	93

Refined product sales (mbbls/d)

Gasoline	246.8	241.3	242.9	244.3

Distillate	200.9	186.7	199.3	186.1

Other	79.1	86.8	88.3	91.0

Total	526.8	514.8	530.5	521.4

Refining margin⁽²⁾ ($/bbl)	31.75	23.00	24.20	20.30

Refining operating expense⁽²⁾ ($/bbl)	5.25	5.45	5.05	5.10

(1): Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Refinery crude throughput in the fourth quarter of 2017 increased to 432,400 bbls/d, compared to 427,300 bbls/d in the prior year quarter, with strong reliability at the company's refineries being partially offset by the impact of a third-party power outage at the Montreal refinery.

Total refined product sales increased to 526,800 bbls/d in the fourth quarter of 2017, compared to 514,800 bbls/d in the prior year quarter. The increase is attributed to improved crude throughput combined with record wholesale volumes in Canada and higher retail volumes.

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

Marketing margins in the fourth quarter of 2017, excluding the impact of the sale of the lubricants business in the first quarter of 2017, were higher than margins in the prior year quarter, primarily due to improved retail pricing and non-petroleum contributions, partially offset by weaker wholesale margins due to continued competitive pricing.

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

The Edmonton refinery has a planned seven-week maintenance event, which includes a one-month full refinery turnaround, and the Commerce City refinery has a four-week turnaround event, both of which are scheduled to begin late in the first quarter of 2018 and extend into the second quarter of 2018. The anticipated impact of this maintenance has been reflected in the company's 2018 guidance.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Net (loss) earnings	(391	)	(323	)	59		(486	)

Adjusted for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	91		222		(702	)	(524	)

Loss on early payment of long term debt⁽¹⁾	18		—		28		73

(Gain) loss on interest rate swaps⁽²⁾	(2	)	(188	)	20		(6	)

Impact of income tax rate adjustment on deferred taxes⁽³⁾	2		—		2		—

Gain on significant disposal⁽⁴⁾	—		—		(83	)	—

Derecognition and impairments⁽⁵⁾	—		31		—		31

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

Operating (loss) earnings⁽⁷⁾	(282	)	(258	)	(676	)	(874	)

Renewable Energy	(1	)	23		(4	)	38

Energy Trading	*(15*	)	19		*(62*	)	4

Corporate	*(184*	)	(261	)	*(528*	)	(864	)

Eliminations	*(82*	)	(39	)	*(82*	)	(52	)

Funds (used in) from operations⁽⁷⁾	(130	)	(114	)	(165	)	(600	)

(1): Charges associated with the early repayment of debt, net of associated realized foreign currency hedge gains.
(2): (Gain) loss on interest rate swaps associated with issued debt due to changes in long-term interest rates.
(3): In the fourth quarter of 2017, the company recorded an adjustment to its deferred income taxes related to the tax reform legislation in the U.S., with the most significant impact resulting from a decrease in the corporate tax rate from 35% to 21%.
(4): After-tax gain related to the sale of the company's interest in the Cedar Point wind facility.
(5): 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.
(6): After-tax transaction and related charges associated with the acquisition of COS.
(7): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.

Renewable Energy had an operating loss of $1 million in the fourth quarter of 2017, compared to operating earnings of $23 million in the prior year quarter. The decrease was due in part to lower production associated with the sale of the company's interest in the Cedar Point wind facility, effective January 1, 2017, and the sale of the Ripley wind facility, effective July 10, 2017, as well as increased development costs.

The operating loss for Energy Trading was $15 million in the quarter, compared to operating earnings of $19 million in the prior year quarter, with the decrease due to weaker crude location spreads.

The Corporate operating loss was $184 million for the fourth quarter of 2017, compared to an operating loss of $261 million for the prior year quarter. The favourable change was primarily due to a decrease in share-based compensation expense, operational foreign exchange gains, lower interest expense as a result of an overall decrease in the company's long-term debt and an increase in capitalized interest. The company capitalized $177 million of its borrowing costs in the fourth quarter of 2017 as part of the cost of major development assets and construction projects in progress, compared to $162 million in the prior year quarter.

Eliminations reflect the deferral of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Supply. Consolidated profits are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the fourth quarter of 2017, the company deferred $82 million of after-tax intersegment profit, compared to $39 million of after-tax intersegment profit in the prior year quarter. The increase in profit deferred was due to a build in intercompany refined product inventory in preparation for turnaround activity in the first and second quarters of 2018, as well as an increase in profit margins related to higher crude price realizations.

Corporate, Energy Trading and Eliminations funds used in operations for the fourth quarter of 2017 was $130 million, compared to funds used in operations of $114 million in the prior year period. After removing the impact of lower non-cash share-based compensation expense, the unfavourable change in funds used in operations is due to the same factors affecting operating earnings described above, partially offset by the positive impact of current tax recoveries related to foreign exchange losses on the early payment of long-term debt.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Oil Sands	1 160		1 057		5 059		4 724

Exploration and Production	193		310		824		1 139

Refining and Marketing	249		183		634		685

Corporate, Energy Trading and Eliminations	19		22		34		34

Total capital and exploration expenditures	1 621		1 572		6 551		6 582

Less: capitalized interest on debt	(177	)	(162	)	(729	)	(596	)

	1 444		1 410		5 822		5 986

Three months ended December 31, 2017

Twelve months ended December 31, 2017

($ millions)

Sustaining(2)

Growth(3)

Total

Sustaining(2)

Growth(3)

Total

Oil Sands

Oil Sands Base

350

355

1 374

172

1 546

In Situ

305

313

Oil Sands ventures

130

473

603

556

2 096

2 652

Exploration and Production

157

158

630

645

Refining and Marketing

248

—

248

632

—

632

Corporate, Energy Trading and Eliminations

—

807

637

1 444

2 916

2 906

5 822

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

In the fourth quarter of 2017, total capital and exploration expenditures were $1.444 billion (excluding capitalized interest). Capital and exploration expenditures in the fourth quarter of 2017 were higher than the prior year quarter, due to increased sustaining capital more than offsetting the decrease in growth expenditures associated with major construction activities winding down on Fort Hills and Hebron.

2017 annual spending was $5.822 billion, excluding capitalized interest, and includes additional expenditure of approximately $150 million related to the facility incident that occurred at Syncrude in the first quarter of 2017. The company received an interim payment of $76 million of its anticipated $140 million property damage insurance proceeds, for net capital expenditures of $5.682 billion for the year.

Oil Sands Base capital and exploration expenditures were $355 million in the fourth quarter of 2017, the majority of which were directed towards sustaining activities primarily focused on planned upgrader maintenance and tailings management. Capital expenditures also included various reliability and sustainment projects across the operations.

In Situ capital and exploration expenditures were $61 million and were directed towards sustaining activities, including planned maintenance at MacKay River completed in the fourth quarter, and ongoing well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Oil Sands ventures capital and exploration expenditures were $603 million, of which growth capital expenditures were $473 million and sustaining capital expenditures were $130 million.

Fort Hills began producing paraffinic froth-treated bitumen from secondary extraction on January 27, 2018, and the production ramp up to the project's nameplate capacity of 194,000 bbls/d is progressing on schedule. During the fourth quarter, the company continued to test the front end of the plant to mitigate the risk associated with the ramp up in 2018, resulting in bitumen froth production. The froth production was further processed by Oil Sands operations and included as SCO production and sales. The total cost of the project to mechanical completion at the end of 2017 was approximately $17.160 billion, excluding the impact of unfavourable foreign exchange. Suncor's estimated capital intensity is approximately $83,000 per flowing barrel to mechanical completion at the end of 2017 and is comparable to the original per flowing barrel cost estimate of $84,000.

Sustaining capital expenditures in the fourth quarter of 2017 at Fort Hills continued to focus on early work associated with sustaining activities that will support the execution of the Fort Hills mine and tailings plan.

Syncrude sustaining capital in the fourth quarter of 2017 was primarily focused on permanent repairs associated with the facility incident from the first quarter of 2017 and also included various reliability and sustainment projects across the operations to support the execution of the mine and tailings plan.

Capital expenditures at E&P were $158 million in the fourth quarter of 2017 and were primarily focused on growth opportunities. First oil at Hebron was achieved ahead of schedule and continues to ramp up following favourable initial production results. At peak, the project is expected to produce more than 30,000 bbls/d, net to Suncor, ramping up over the next several years. Other E&P activity in the fourth quarter included development drilling at White Rose, Hebron, Terra Nova and Hibernia, as well as development work on the West White Rose Project and the Norwegian Oda project.

Subsequent to the end of the quarter, Suncor reached an agreement with Canbriam Energy Inc. (Canbriam) to exchange all of Suncor's northeast British Columbia mineral land holdings and consideration of $52 million for a 37% equity interest in Canbriam, a private natural gas company. The transaction is subject to regulatory approval and is expected to close in the first quarter of 2018.

R&M capital expenditures were $248 million and were primarily related to ongoing sustainment of operations, including planned refinery maintenance, enhancements to retail operations and information technology upgrades.

Corporate capital expenditures were $19 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended December 31
	2017	2016

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	8.6	0.5

Including major projects in progress	6.7	0.4

Net debt to funds from operations⁽²⁾ (times)	1.4	2.4

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	6.5	0.5

Funds from operations basis⁽²⁾⁽⁴⁾	11.2	6.5

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this document.
(2): Funds from operations and metrics that use funds from operations are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this 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 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 proceeds received from the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2018 capital spending program of $4.5 to $5.0 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, divesting of non-core assets and accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

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

Cash and cash equivalents decreased to $2.672 billion during 2017, from $3.016 billion at December 31, 2016. The decrease is primarily due to the early repayment of notes having aggregate principal amounts of US$1.250 billion, US$600 million and $700 million, as well as the purchase of the company's own shares under its normal course issuer bid (NCIB), partially offset by the proceeds from the sales of the company's lubricants business and its interest in the Cedar Point and Ripley wind facilities, issuance of US$750 million of 4.00% senior unsecured notes issued during the fourth quarter, an increase in short-term indebtedness, proceeds from the sale of the 49% interest in ETFD and cash flow provided by operating activities exceeding capital and exploration expenditures and dividend requirements.

As the company's current significant growth projects, Fort Hills and Hebron, have substantially been completed, it is anticipated that less cash will be required for growth funding purposes in the near future. This supports the repayment of long-term debt and returning additional cash to shareholders, subject to prevailing economic conditions and other relevant factors.

As at December 31, 2017, the weighted average term to maturity of the short-term investment portfolio was approximately 16 days.

Available credit facilities for liquidity purposes at December 31, 2017 decreased to $4.489 billion, compared to $7.467 billion at December 31, 2016, as a result of a planned $1.0 billion reduction in the company's credit facility, the company's cancellation of a $950 million credit facility that was acquired through the acquisition of COS and an increase in short-term indebtedness. The decrease in the company's credit facility and the cancelation of the credit facility were executed in 2017 as the excess liquidity is no longer anticipated to be required and the reduction 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 future expected volatility in the pricing environment. Suncor believes a phased and flexible approach to existing and future growth projects should assist the company in maintaining its ability to manage project costs and debt levels.

During the fourth quarter of 2017, the company issued US$750 million of 4.00% senior unsecured notes due on November 15, 2047. In addition, the Fort McKay First Nation and Mikisew Cree First Nation completed their purchase of a 49% interest in Suncor's ETFD for total proceeds of $503 million. The proceeds of these transactions were used towards the early redemption of outstanding US$600 million of 6.05% senior unsecured notes and $700 million of 5.80% Medium Term Notes, both originally due in 2018. The early redemption included a premium that was paid in conjunction with the debt, which will be more than offset by the reduction in future interest charges.

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

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, 2017, total debt to total debt plus shareholders' equity was 25.6% (December 31, 2016 – 28.1%). The company continues to be in compliance with all operating covenants.


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

Short-term debt	2 136	1 273

Current portion of long-term debt	71	54

Long-term debt	13 372	16 103

Total debt	15 579	17 430

Less: Cash and cash equivalents	2 672	3 016

Net debt	12 907	14 414

Shareholders' equity	45 383	44 630

Total debt plus shareholders' equity	60 962	62 060

Total debt to total debt plus shareholders' equity (%)	25.6	28.1


	Three and twelve months ended December 31, 2017
($ millions)	Q4		YTD

Total debt – beginning of period	15 847		17 430

Net decrease in long-term debt	(610	)	(2 378	)

Increase in short-term debt	56		981

Foreign exchange on debt	74		(771	)

Change in capital leases, and other	212		317

Total debt – December 31, 2017	15 579		15 579

Less: Cash and cash equivalents – December 31, 2017	2 672		2 672

Net debt – December 31, 2017	12 907		12 907

The company's total debt decreased in the fourth quarter of 2017 due to the early redemption of outstanding US$600 million 6.05% senior unsecured notes and $700 million 5.80% Medium Term Notes both scheduled to mature in 2018, partially offset by the issuance of US$750 million 4.00% senior unsecured notes, a net increase in financing leases primarily associated with Fort Hills, the impact of unfavourable foreign exchange rates on U.S. dollar denominated debt and an increase in short-term borrowings.

On a year-to-date basis, in addition to the net decrease in long-term debt during the fourth quarter noted above, the company's total debt position improved due to the early repayment of US$1.250 billion of 6.10% notes originally scheduled to mature on June 1, 2018 and the impact of favourable foreign exchange rates on U.S. dollar denominated debt in 2017, partially offset by an increase in short-term borrowings.

As at February 5, 2018, the total number of common shares outstanding was 1,640,706,184 and the total number of exercisable and non-exercisable common share options outstanding was 28,905,918. Once exercisable, each outstanding common share option is convertible into one common share.

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

During the fourth quarter of 2017, the company repurchased 18,712,919 common shares at an average price of $44.57 per share, for $835 million, compared to the prior year quarter where no purchases were made.

Subsequent to the end of the fourth quarter, Suncor's Board approved a further $2.0 billion share buyback program, currently anticipated to commence after the expiry of the company's current program on May 1, 2018.

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, 2016, dated March 1, 2017 (the 2016 annual MD&A) and has provided an update below. The company does not believe that it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial performance or financial condition, results of operations, liquidity or capital expenditures.

During the twelve months ended December 31, 2017, the company decreased its commitments by approximately $2.6 billion (undiscounted), which is primarily related to early debt repayments in 2017 totalling over $3.0 billion, net of US$750 million of debt issued in the fourth quarter of 2017, and the reduction in commitments associated with the sale of Suncor's lubricants business, partially offset by increases to the company's decommissioning and restoration costs, an increase in commitments associated with capital leases that support Fort Hills and various other service commitments entered into during the year.

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


Three months ended ($ millions, unless otherwise noted)	Dec 31 2017		Sept 30 2017	June 30 2017	Mar 31 2017	Dec 31 2016		Sept 30 2016		June 30 2016		Mar 31 2016

Total production (mboe/d)

Oil Sands	621.2		628.4	413.6	590.6	620.4		617.5		213.1		565.8

Exploration and Production	115.2		111.5	125.5	134.5	118.1		110.6		117.6		125.6

	736.4		739.9	539.1	725.1	738.5		728.1		330.7		691.4

Revenues and other income

Operating revenues, net of royalties	9 000		7 986	7 247	7 818	7 840		7 409		5 914		5 644

Other income (loss)	41		43	16	25	301		(15	)	(58	)	(67	)

	9 041		8 029	7 263	7 843	8 141		7 394		5 856		5 577

Net earnings (loss)	1 382		1 289	435	1 352	531		392		(735	)	257

per common share – basic (dollars)	0.84		0.78	0.26	0.81	0.32		0.24		(0.46	)	0.17

per common share – diluted (dollars)	0.84		0.78	0.26	0.81	0.32		0.24		(0.46	)	0.17

Operating earnings (loss)⁽¹⁾	1 310		867	199	812	636		346		(565	)	(500	)

per common share – basic⁽¹⁾ (dollars)	0.79		0.52	0.12	0.49	0.38		0.21		(0.36	)	(0.33	)

Funds from operations⁽¹⁾	3 016		2 472	1 627	2 024	2 365		2 025		916		682

per common share – basic⁽¹⁾ (dollars)	1.83		1.49	0.98	1.21	1.42		1.22		0.58		0.45

Cash flow provided by operating activities	2 755		2 912	1 671	1 628	2 791		1 979		862		48

per common share – basic (dollars)	1.67		1.75	1.00	0.98	1.68		1.19		0.54		0.03

ROCE⁽¹⁾ (%) for the twelve months ended	6.7		5.5	4.9	3.5	0.4		(3.9	)	(4.1	)	(1.9	)

ROCE⁽¹⁾, excluding major projects in progress (%) for the twelve months ended	8.6		7.0	6.2	4.4	0.5		(4.6	)	(4.9	)	(2.2	)

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(91	)	412	278	103	(222	)	(112	)	(27	)	885

Common share information (dollars)

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

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	46.15		43.73	37.89	40.83	43.90		36.42		35.84		36.17

New York Stock Exchange (US$)	36.72		35.05	29.20	30.75	32.69		27.78		27.73		27.81

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


Three months ended (average for the period ended, except as noted)		Dec 31 2017	Sept 30 2017	June 30 2017	Mar 31 2017	Dec 31 2016	Sept 30 2016	June 30 2016	Mar 31 2016

WTI crude oil at Cushing	US$/bbl	55.40	48.20	48.30	51.85	49.35	44.95	45.60	33.50

Dated Brent crude	US$/bbl	61.40	52.05	49.85	53.75	49.50	45.85	45.60	33.90

Dated Brent/Maya FOB price differential	US$/bbl	9.60	6.30	5.80	9.05	6.70	6.80	7.65	8.95

MSW at Edmonton	Cdn$/bbl	69.30	57.05	62.30	64.25	62.00	55.10	55.80	34.50

WCS at Hardisty	US$/bbl	43.10	38.25	37.20	37.30	35.00	31.45	32.30	19.30

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	12.30	9.95	11.10	14.55	14.35	13.50	13.30	14.25

Condensate at Edmonton	US$/bbl	57.95	47.60	48.45	52.20	48.35	43.05	44.10	34.45

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.70	1.45	2.80	2.70	3.10	2.30	1.40	1.85

Alberta Power Pool Price	Cdn$/MWh	22.35	24.55	19.30	22.40	21.95	17.90	14.90	18.10

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	19.40	22.35	16.35	12.55	14.35	14.00	16.10	11.75

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	20.20	19.25	14.40	11.15	10.55	14.15	16.65	9.10

Portland 3-2-1 crack⁽¹⁾	US$/bbl	22.10	26.80	21.25	18.45	14.95	18.75	19.30	13.00

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	18.25	21.45	16.80	14.00	13.15	14.50	14.85	11.05

Exchange rate	US$/Cdn$	0.79	0.80	0.74	0.76	0.75	0.77	0.78	0.73

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

(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 2016 annual MD&A.

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are those that require management to make assumptions about matters that are highly uncertain at the time the estimate is made. Critical accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the company's financial condition, changes in financial condition or financial performance. Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of Suncor's critical accounting estimates is provided in note 4 to the audited Consolidated Financial Statements for the year ended December 31, 2016 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2016 annual MD&A.

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company's position with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor's financial instruments and the related financial risk factors, see note 28 of the audited Consolidated Financial Statements for the year ended December 31, 2016, note 11 to the unaudited interim Consolidated

Financial Statements for the three months ended December 31, 2017, and the Financial Condition and Liquidity section of Suncor's 2016 annual MD&A.

In the fourth quarter of 2017, the U.S. government enacted a decrease in the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. As a result, the company revalued its deferred income tax balances, resulting in a net deferred income tax recovery of $124 million.

In the fourth quarter of 2017, the Government of British Columbia enacted an increase to the provincial corporate income tax rate from 11% to 12%. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax expense of $18 million.

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.

Certain financial measures in this document – namely operating earnings (loss), ROCE, funds from (used in) operations, discretionary free funds flow, Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense and LIFO – are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze business performance, leverage and liquidity, and it may be useful to investors on the same basis. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. Therefore, these non-GAAP financial measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Except as otherwise indicated, these non-GAAP financial measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

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

changes in statutory income tax rates, other income tax adjustments and the net impact of the sale of the lubricants business in the first quarter of 2017.

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)		2017		2016

Adjustments to net earnings

Net earnings		4 458		434

(Deduct) add after-tax amounts for:

Unrealized foreign exchange (gain) on U.S. dollar denominated debt		(702	)	(524	)

Net interest expense		158		304

	A	3 914		214

Capital employed – beginning of twelve-month period

Net debt		14 414		11 254

Shareholders' equity		44 630		39 039

		59 044		50 293

Capital employed – end of twelve-month period

Net debt		12 907		14 414

Shareholders' equity		45 383		44 630

		58 290		59 044

Average capital employed	B	58 667		57 999

ROCE – including major projects in progress (%)	A/B	6.7		0.4

Average capitalized costs related to major projects in progress	C	12 901		10 147

ROCE – excluding major projects in progress (%)	A/(B–C)	8.6		0.5

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

Funds from (used in) operations in this 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 the consolidated GAAP measure in the Non-GAAP Financial Measures Advisory section of each respective MD&A or quarterly report to shareholders, as applicable, for the related quarter.


Three months ended December 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net earnings (loss)	670		276		217		54		886		524		(391	)	(323	)	1 382		531

Adjustments for:

Depreciation, depletion, amortization and impairment	1 055		1 038		219		294		196		196		18		73		1 488		1 601

Deferred income taxes	181		(14	)	5		(44	)	(161	)	(3	)	78		(9	)	103		(70	)

Accretion	49		53		12		10		2		2		—		—		63		65

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		74		313		74		313

Change in fair value of financial instruments and trading inventory	2		—		—		—		9		(1	)	5		(271	)	16		(272	)

Gain on disposal of assets	(46	)	—		—		—		(2	)	(21	)	—		—		(48	)	(21	)

Loss on debt extinguishment	—		—		—		—		—		—		26		—		26		—

Share-based compensation	34		57		4		7		17		32		61		105		116		201

Exploration	—		—		—		65		—		—		—		—		—		65

Settlement of decommissioning and restoration liabilities	(76	)	(55	)	(15	)	(1	)	(7	)	(7	)	—		—		(98	)	(63	)

Other	(89	)	17		(11	)	—		(5	)	—		(1	)	(2	)	(106	)	15

Funds from (used in) operations	1 780		1 372		431		385		935		722		(130	)	(114	)	3 016		2 365

(Increase) decrease in non- cash working capital	(509	)	217		101		156		496		982		(349	)	(929	)	(261	)	426

Cash flow provided by (used in) operating activities	1 271		1 589		532		541		1 431		1 704		(479	)	(1 043	)	2 755		2 791


Twelve months ended December 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Net earnings (loss)	1 009		(1 149	)	732		190		2 658		1 890		59		(486	)	4 458		445

Adjustments for:

Depreciation, depletion, amortization and impairment	3 782		3 864		1 028		1 381		685		702		106		170		5 601		6 117

Deferred income taxes	170		(78	)	(113	)	(506	)	(138	)	12		330		60		249		(512	)

Accretion	195		208		45		53		7		7		—		1		247		269

Unrealized foreign exchange (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		(771	)	(458	)	(771	)	(458	)

Change in fair value of financial instruments and trading inventory	2		19		—		—		9		27		117		(53	)	128		(7	)

Gain on disposal of assets	(50	)	(33	)	—		—		(354	)	(35	)	(70	)	—		(474	)	(68	)

Loss on debt extinguishment	—		—		—		—		—		—		51		99		51		99

Share-based compensation	(3	)	41		6		12		4		21		24		68		31		142

Exploration	—		—		41		204		—		—		—		—		41		204

Settlement of decommissioning and restoration liabilities	(305	)	(248	)	(31	)	(1	)	(17	)	(20	)	—		—		(353	)	(269	)

Other	(62	)	45		17		(20	)	(13	)	2		(11	)	(1	)	(69	)	26

Funds from (used in) operations	4 738		2 669		1 725		1 313		2 841		2 606		(165	)	(600	)	9 139		5 988

(Increase) decrease in non- cash working capital	(451	)	(383	)	(13	)	60		1 563		787		(1 272	)	(772	)	(173	)	(308	)

Cash flow provided by (used in) operating activities	4 287		2 286		1 712		1 373		4 404		3 393		(1 437	)	(1 372	)	8 966		5 680

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

Oil Sands operations and Syncrude cash operating costs are non-GAAP financial measures. Oil Sands operations cash operating costs are calculated by adjusting Oil Sands segment OS&G expense (a GAAP measure based on sales volumes) for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, research and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue;

iv) project start-up costs; and v) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes. Syncrude cash operating costs are calculated by adjusting Syncrude OS&G for non-production costs that management believes do not relate to the production performance of Syncrude operations, including, but not limited to, share-based compensation, research and project start-up costs. Oil Sands operations and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this document. Management uses Oil Sands operations and Syncrude cash operating costs to measure Oil Sands operating performance.

Refining margin and refining operating expense are non-GAAP financial measures. Refining margin is calculated by adjusting R&M segment operating revenue, other income, and purchases of crude oil and products (GAAP measures) for non-refining margin pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business. Refinery operating expense is calculated by adjusting R&M segment OS&G for i) non-refining costs pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business; and ii) non-refining costs that management believes do not relate to the production of refined products, including, but not limited to, share-based compensation and enterprise shared service allocations. Management uses refining margin and refining operating expense to measure operating performance on a production barrel basis.


	Three months ended December 31				Twelve months ended December 31
($ millions, except as noted)	2017		2016		2017		2016

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 871		1 580		5 952		5 813

Other (loss) income	(13	)	(10	)	73		16

Non-refining margin	(467	)	(592	)	(1 800	)	(2 403	)

Refining margin	1 391		978		4 225		3 426

Refinery production⁽¹⁾ (mbbls)	43 801		42 510		174 461		168 798

Refining margin ($/bbl)	31.75		23.00		24.20		20.30

Refining operating expense reconciliation

Operating, selling and general expense	545		586		2 007		2 203

Non-refining costs	(316	)	(355	)	(1 125	)	(1 343	)

Refining operating expense	229		231		882		860

Refinery production⁽¹⁾ (mbbls)	43 801		42 510		174 461		168 798

Refining operating expense ($/bbl)	5.25		5.45		5.05		5.10

(1): Refinery production is the output of the refining process, and differs from crude oil processed as a result of volumetric adjustments for non-crude feedstock, volumetric gain associated with the refining process, and changes in unfinished product inventories.

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

GAAP requires the use of a FIFO inventory valuation methodology. For Suncor, this results in a disconnect between the sales prices for refined products, which reflect current market conditions, and the amount recorded as the cost of sale for the related refinery feedstock, which reflects market conditions at the time the feedstock was purchased. This lag between purchase and sale can be anywhere from several weeks to several months, and is influenced by the time to receive crude after purchase (which can be several weeks for foreign offshore crude purchases), regional crude inventory levels, the completion of refining processes, transportation time to distribution channels, and regional refined product inventory levels.

Suncor prepares and presents an estimate of the impact of using a FIFO inventory valuation methodology compared to a LIFO methodology, because management uses the information to analyze operating performance and compare itself against refining peers that are permitted to use LIFO inventory valuation under United States GAAP (U.S. GAAP).

The company's estimate is not derived from a standardized calculation and, therefore, may not be directly comparable to similar measures presented by other companies, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP or U.S. GAAP.


Measurement		Places and Currencies
bbl	Barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		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
	per day
MW	megawatts
MWh	megawatts per hour

The document contains certain forward-looking information and forward-looking statements (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information are based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; the performance of assets and equipment; capital efficiencies and cost-savings; applicable laws and government policies, including royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; the satisfaction by third parties of their obligations to Suncor; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other information that address expectations or projections about the future, and other statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may", "future", "potential", "opportunity", "would" and similar expressions. Forward-looking statements in the document include references to:

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them. The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, E&P, and R&M, may be affected by a number of factors.

Factors that affect our Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process our proprietary production will be closed, experience equipment failure or other accidents; our ability to operate our Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance of which may be difficult to predict during initial operations; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; our dependence on pipeline capacity and other logistical constraints, which may affect our ability to distribute our products to market; our ability to finance Oil Sands growth and sustaining capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; inflationary pressures on operating costs, including labour, natural gas and other energy sources used in oil sands processes; our ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools); risks and uncertainties associated with obtaining regulatory and stakeholder approval for the company's operations and 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 the company's operations and 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; risks and uncertainties associated with obtaining regulatory and stakeholder approval; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties and other government-imposed compliance costs; changes in environmental and other regulations and policies; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires (including forest fires), equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information technology and infrastructure by computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset, or oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control and the satisfaction of any conditions to such approvals; risks associated with land claims and Aboriginal consultation requirements; risks relating to litigation; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor's forward-looking statements are discussed in further detail throughout this document, and in the company's 2016 annual MD&A, 2016 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

The forward-looking statements contained in this 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)	2017		2016		2017		2016

Revenues and Other Income

Operating revenues, net of royalties (note 3)	9 000		7 840		32 051		26 807

Other income (note 4)	41		301		125		161

	9 041		8 141		32 176		26 968

Expenses

Purchases of crude oil and products	2 773		2 402		11 121		9 877

Operating, selling and general	2 435		2 536		9 245		9 150

Transportation	256		279		1 037		1 072

Depreciation, depletion, amortization and impairment	1 488		1 601		5 601		6 117

Exploration	26		86		104		289

Gain on disposal of assets (notes 13 and 14)	(47	)	(21	)	(602	)	(68	)

Financing expenses (income) (note 6)	225		532		(246	)	445

	7 156		7 415		26 260		26 882

Earnings before Income Taxes	1 885		726		5 916		86

Income Taxes – Expense (Recovery) (note 7)

Current	400		265		1 209		153

Deferred	103		(70	)	249		(512	)

	503		195		1 458		(359	)

Net Earnings	1 382		531		4 458		445

Net Earnings Attributable to:

Common shareholders	1 382		531		4 458		434

Non-controlling interest	—		—		—		11

	1 382		531		4 458		445

Other Comprehensive (Loss) Income

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	8		36		(198	)	(258	)

Items that will not be reclassified to earnings

Actuarial (loss) gain on employee retirement benefit plans, net of income taxes	(22	)	450		31		(24	)

Other Comprehensive (Loss) Income	(14	)	486		(167	)	(282	)

Total Comprehensive Income	1 368		1 017		4 291		163

Per Common Share (dollars) (note 8)

Net earnings – basic and diluted	0.84		0.32		2.68		0.28

Net earnings – attributable to common shareholders – basic and diluted	0.84		0.32		2.68		0.27

Cash dividends	0.32		0.29		1.28		1.16

See accompanying notes to the interim consolidated financial statements.


($ millions)	December 31 2017	December 31 2016

Assets

Current assets

Cash and cash equivalents	2 672	3 016

Accounts receivable	3 281	3 182

Inventories	3 468	3 240

Income taxes receivable	156	376

Assets held for sale (notes 13 and 14)	—	1 205

Total current assets	9 577	11 019

Property, plant and equipment, net	73 493	71 259

Exploration and evaluation	2 052	2 038

Other assets	1 211	1 248

Goodwill and other intangible assets	3 061	3 075

Deferred income taxes	100	63

Total assets	89 494	88 702

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	2 136	1 273

Current portion of long-term debt	71	54

Accounts payable and accrued liabilities	6 203	5 588

Current portion of provisions	722	781

Income taxes payable	425	224

Liabilities associated with assets held for sale (notes 13 and 14)	—	197

Total current liabilities	9 557	8 117

Long-term debt	13 372	16 103

Other long-term liabilities (notes 11 and 15)	2 412	2 067

Provisions (note 12)	7 237	6 542

Deferred income taxes	11 533	11 243

Equity	45 383	44 630

Total liabilities and equity	89 494	88 702

See accompanying notes to the interim consolidated financial statements.


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Operating Activities

Net earnings	1 382		531		4 458		445

Adjustments for:

Depreciation, depletion, amortization and impairment	1 488		1 601		5 601		6 117

Deferred income taxes	103		(70	)	249		(512	)

Accretion	63		65		247		269

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	74		313		(771	)	(458	)

Change in fair value of financial instruments and trading inventory	16		(272	)	128		(7	)

Gain on disposal of assets (notes 13 and 14)	(48	)	(21	)	(474	)	(68	)

Loss on extinguishment of long-term debt (note 6)	26		—		51		99

Share-based compensation	116		201		31		142

Exploration	—		65		41		204

Settlement of decommissioning and restoration liabilities	(98	)	(63	)	(353	)	(269	)

Other	(106	)	15		(69	)	26

(Increase) decrease in non-cash working capital	(261	)	426		(173	)	(308	)

Cash flow provided by operating activities	2 755		2 791		8 966		5 680

Investing Activities

Capital and exploration expenditures	(1 621	)	(1 572	)	(6 551	)	(6 582	)

Cash acquired from Canadian Oil Sands Limited	—		—		—		109

Acquisitions (note 16)	(308	)	(68	)	(308	)	(1 014	)

Proceeds from disposal of assets⁽¹⁾	80		33		1 611		229

Other investments	(24	)	(14	)	(38	)	(25	)

Decrease (increase) in non-cash working capital	339		(179	)	267		(224	)

Cash flow used in investing activities	(1 534	)	(1 800	)	(5 019	)	(7 507	)

Financing Activities

Net change in short-term debt	56		(719	)	981		531

Repayment of long-term debt	(1 515	)	(14	)	(3 283	)	(1 693	)

Issuance of long-term debt (note 6)	905		—		905		993

Issuance of common shares under share option plans	123		116		228		133

(Purchase) issuance of common shares (notes 9 and 10)	(835	)	—		(1 413	)	2 782

Proceeds from sale of non-controlling interest (note 15)	483		—		483		—

Dividends paid on common shares	(526	)	(483	)	(2 124	)	(1 877	)

Cash flow (used in) provided by financing activities	(1 309	)	(1 100	)	(4 223	)	869

Decrease in Cash and Cash Equivalents	(88	)	(109	)	(276	)	(958	)

Effect of foreign exchange on cash and cash equivalents	3		23		(68	)	(75	)

Cash and cash equivalents at beginning of period	2 757		3 102		3 016		4 049

Cash and Cash Equivalents at End of Period	2 672		3 016		2 672		3 016

Supplementary Cash Flow Information

Interest paid	332		395		941		992

Income taxes paid (received)	283		(105	)	557		(161	)

(1): Includes property damage insurance proceeds of $76 million for Syncrude.


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

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 9)	2 808		—		—		—		—		2 808		82 225

Issued for the acquisition of Canadian Oil Sands Limited	3 154		—		—		1 172		—		4 326		98 814

Equity transactions to eliminate non-controlling interest in Canadian Oil Sands Limited	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

Net earnings	—		—		—		—		4 458		4 458		—

Foreign currency translation adjustment	—		—		(198	)	—		—		(198	)	—

Actuarial gain on employee retirement benefit plans, net of income taxes of $19	—		—		—		—		31		31		—

Total comprehensive (loss) income	—		—		(198	)	—		4 489		4 291		—

Issued under share option plans	297		(69	)	—		—				228		6 223

Purchase of common shares for cancellation (note 10)	(536	)	—		—		—		(877	)	(1 413	)	(33 154	)

Change in liability for share purchase commitment (note 10)	(97	)	—		—		—		(180	)	(277	)	—

Share-based compensation	—		48		—		—		—		48		—

Dividends paid on common shares	—		—		—		—		(2 124	)	(2 124	)	—

At December 31, 2017	26 606		567		809		—		17 401		45 383		1 640 983

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, 2016.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as at February 7, 2018.

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, 2016.

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, 2016.

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

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)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Revenues and Other Income

Gross revenues	3 027		2 514		949		741		5 389		4 663		10		21		9 375		7 939

Intersegment revenues	1 089		842		—		1		37		12		(1 126	)	(855	)	—		—

Less: Royalties	(175	)	(4	)	(200	)	(95	)	—		—		—		—		(375	)	(99	)

Operating revenues, net of royalties	3 941		3 352		749		647		5 426		4 675		(1 116	)	(834	)	9 000		7 840

Other income (loss)	61		8		8		—		(13	)	(10	)	(15	)	303		41		301

	4 002		3 360		757		647		5 413		4 665		(1 131	)	(531	)	9 041		8 141

Expenses

Purchases of crude oil and products	233		101		—		—		3 555		3 095		(1 015	)	(794	)	2 773		2 402

Operating, selling and general	1 616		1 634		101		115		545		586		173		201		2 435		2 536

Transportation	169		177		20		21		80		95		(13	)	(14	)	256		279

Depreciation, depletion, amortization and impairment	1 055		1 038		219		294		196		196		18		73		1 488		1 601

Exploration	6		—		20		86		—		—		—		—		26		86

Gain on disposal of assets	(46	)	—		—		—		(1	)	(21	)	—		—		(47	)	(21	)

Financing expenses (income)	55		58		14		20		3		(2	)	153		456		225		532

	3 088		3 008		374		536		4 378		3 949		(684	)	(78	)	7 156		7 415

Earnings (Loss) before Income Taxes	914		352		383		111		1 035		716		(447	)	(453	)	1 885		726

Income Taxes – Expense (Recovery)

Current	63		90		161		101		310		195		(134	)	(121	)	400		265

Deferred	181		(14	)	5		(44	)	(161	)	(3	)	78		(9	)	103		(70	)

	244		76		166		57		149		192		(56	)	(130	)	503		195

Net Earnings (Loss)	670		276		217		54		886		524		(391	)	(323	)	1 382		531

Capital and Exploration Expenditures	1 160		1 057		193		310		249		183		19		22		1 621		1 572


Twelve months ended December 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2017		2016		2017		2016		2017		2016		2017		2016		2017		2016

Revenues and Other Income

Gross revenues	9 586		7 229		3 487		2 329		19 871		17 459		38		55		32 982		27 072

Intersegment revenues	3 551		2 293		—		115		92		108		(3 643	)	(2 516	)	—		—

Less: Royalties	(355	)	(52	)	(576	)	(213	)	—		—		—		—		(931	)	(265	)

Operating revenues, net of royalties	12 782		9 470		2 911		2 231		19 963		17 567		(3 605	)	(2 461	)	32 051		26 807

Other income (loss)	86		26		(14	)	45		73		16		(20	)	74		125		161

	12 868		9 496		2 897		2 276		20 036		17 583		(3 625	)	(2 387	)	32 176		26 968

Expenses

Purchases of crude oil and products	623		548		—		—		14 011		11 754		(3 513	)	(2 425	)	11 121		9 877

Operating, selling and general	6 257		5 777		422		483		2 007		2 203		559		687		9 245		9 150

Transportation	690		666		86		86		312		366		(51	)	(46	)	1 037		1 072

Depreciation, depletion, amortization and impairment	3 782		3 864		1 028		1 381		685		702		106		170		5 601		6 117

Exploration	15		30		89		259		—		—		—		—		104		289

Gain on disposal of assets	(50	)	(33	)	—		—		(455	)	(35	)	(97	)	—		(602	)	(68	)

Financing expenses (income)	180		234		36		82		15		10		(477	)	119		(246	)	445

	11 497		11 086		1 661		2 291		16 575		15 000		(3 473	)	(1 495	)	26 260		26 882

Earnings (Loss) before Income Taxes	1 371		(1 590	)	1 236		(15	)	3 461		2 583		(152	)	(892	)	5 916		86

Income Taxes – Expense (Recovery)

Current	192		(363	)	617		301		941		681		(541	)	(466	)	1 209		153

Deferred	170		(78	)	(113	)	(506	)	(138	)	12		330		60		249		(512	)

	362		(441	)	504		(205	)	803		693		(211	)	(406	)	1 458		(359	)

Net Earnings (Loss)	1 009		(1 149	)	732		190		2 658		1 890		59		(486	)	4 458		445

Capital and Exploration Expenditures	5 059		4 724		824		1 139		634		685		34		34		6 551		6 582


	Three months ended December 31			Twelve months ended December 31
($ millions)	2017		2016	2017		2016

Energy trading activities

(Losses) gains recognized in earnings during the period	(19	)	16	(37	)	(47	)

Gains (losses) on inventory valuation	7		14	(39	)	62

Risk management activities⁽¹⁾	(51	)	228	(19	)	(25	)

Investment and interest income	22		21	162		77

Risk mitigation and insurance proceeds⁽²⁾	76		15	76		41

Change in value of pipeline commitments and other	6		7	(18	)	53

	41		301	125		161

(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 2017 for Syncrude and property damage proceeds recorded in the second quarter of 2016 for the Terra Nova asset in the Exploration and Production segment.

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


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Interest on debt	241		259		945		1 012

Capitalized interest	(177	)	(163	)	(729	)	(597	)

Interest expense	64		96		216		415

Interest on partnership liability (note 15)	5		—		5		—

Interest on pension and other post-retirement benefits	14		14		58		59

Accretion	63		65		247		269

Foreign exchange loss (gain) on U.S. dollar denominated debt	74		313		(771	)	(458	)

Foreign exchange and other	(21	)	44		(52	)	61

Loss on extinguishment of long-term debt	26		—		113		99

Realized gains on foreign currency hedges	—		—		(62	)	—

	225		532		(246	)	445

During the fourth quarter of 2017, the company completed an early retirement of its US$600 million (book value of $771 million) senior unsecured notes with a coupon of 6.05% originally scheduled to mature on May 15, 2018 for US$614 million ($788 million), including US$3 million ($4 million) of accrued interest. The company also completed an early retirement of its $700 million senior unsecured Series 4 Medium Term notes with a coupon of 5.80% originally scheduled to mature on May 22, 2018 for $715 million, including $3 million of accrued interest. The company realized an overall debt extinguishment loss of $26 million ($18 million after-tax).

During the fourth quarter of 2017, the company issued US$750 million of senior unsecured notes maturing on November 15, 2047. The notes have a coupon of 4.00% and were priced at $99.498 per note for an effective yield of 4.029%.

During the second quarter of 2017, the company completed an early retirement of its US$1.250 billion (book value of $1.700 billion) senior unsecured notes originally scheduled to mature on June 1, 2018 for US$1.344 billion ($1.830 billion), including US$31 million ($42 million) of accrued interest. In conjunction with the early retirement of the notes, the company also realized gains of $62 million on foreign currency hedges, resulting in an overall debt extinguishment loss of $25 million ($10 million after-tax).

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%.

During the second quarter of 2016, the company purchased US$688 million (book value of $864 million) of subsidiary debt acquired through the acquisition of Canadian Oil Sands Limited (COS) for US$751 million ($973 million) including US$8 million ($10 million) of accrued interest, resulting in a debt extinguishment loss of $99 million ($73 million after-tax). The company also repaid approximately $600 million of the credit facility acquired in the COS transaction.

In the fourth quarter of 2017, the U.S. government enacted a decrease in the federal corporate income tax rate from 35% to 21% effective January 1, 2018. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax recovery of $124 million.

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 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)	2017	2016		2017		2016

Net earnings	1 382	531		4 458		445

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

Net earnings – diluted	1 382	530		4 457		444

Net earnings attributable to common shareholders	1 382	531		4 458		434

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

Net earnings – diluted attributable to common shareholders	1 382	530		4 457		433

(millions of common shares)

Weighted average number of common shares	1 650	1 666		1 661		1 610

Dilutive securities:

Effect of share options	5	4		4		2

Weighted average number of diluted common shares	1 655	1 670		1 665		1 612

(dollars per common share)

Basic and diluted earnings per share	0.84	0.32		2.68		0.28

Basic and diluted earnings per share attributable to common shareholders	0.84	0.32		2.68		0.27

(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 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, 2017 and 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).

On April 26, 2017, the company announced its intention to commence a new Normal Course Issuer Bid (the 2017 NCIB) to repurchase shares through the facilities of the Toronto Stock Exchange, New York Stock Exchange and/or alternative trading platforms. Pursuant to the 2017 NCIB, the company may purchase for cancellation up to approximately $2.0 billion worth of its common shares between May 2, 2017 and May 1, 2018. During the fourth quarter of 2017, the company repurchased 18.7 million common shares under the 2017 NCIB at an average price of $44.57 per share, for a total repurchase cost of $835 million.

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

Under an automatic repurchase plan agreement with an independent broker, the company has recorded the following liability for share repurchases that may take place during its internal blackout period:

The following table presents the company's non-designated Energy Trading, and Risk Management derivatives measured at fair value as at December 31, 2017:

The following table presents the company's financial instruments measured at fair value for each hierarchy level as at December 31, 2017:

During the fourth quarter of 2017, 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, 2017, the company had no outstanding forward starting swaps as all the positions were settled during the year.

At December 31, 2017, the carrying value of fixed-term debt accounted for under amortized cost was $12.1 billion (December 31, 2016 – $15.1 billion) and the fair value was $14.7 billion (December 31, 2016 – $17.5 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

Suncor entered into a partnership with Fort McKay First Nation (FMFN) and Mikisew Cree First Nation (MCFN) where FMFN and MCFN acquired a combined 49% partnership in the East Tank Farm Development (ETFD). The partnership liability is recorded at amortized cost using the effective interest method. At December 31, 2017, the carrying value of the Partnership liability accounted for under amortized cost was $483 million.

A decrease in the credit-adjusted risk-free interest rate to 3.70% (December 31, 2016 – 3.90%) and recognition of additional disturbances offset by liabilities settled resulted in an increase in the decommissioning and restoration provision of $719 million for the twelve months ended December 31, 2017.

On February 1, 2017, the company completed the previously announced sale of its lubricants business for proceeds of $1.1 billion before closing adjustments and other closing costs. The sale of this business resulted in an after-tax gain of $354 million, including a current tax expense of $101 million and a deferred tax recovery of $11 million, in the Refining and Marketing segment.

The company sold its interest in the Cedar Point wind facility in southwestern Ontario for proceeds of $291 million before closing adjustments and other closing costs, with an effective date of January 1, 2017. The disposition resulted in an after-tax gain of $83 million, including a current tax expense of $29 million and a deferred tax recovery of $15 million, in the Corporate, Energy Trading and Eliminations segment.

On November 22, 2017, the company completed the previously announced disposition of a 49% ownership interest in the ETFD to the FMFN and the MCFN for gross proceeds of $503 million. Suncor will retain a 51% ownership interest and will remain as operator of the assets. Since the partnership has a non-discretionary obligation to distribute the variable monthly residual cash in ETFD to the partners, the company recorded a corresponding liability within Other Long-Term

Liabilities to reflect the 49% non-controlling interest of the third parties. As a result, the company will continue to consolidate 100% of the full results of the partnership. During the year ended December 31, 2017 the company paid $25 million in distributions to the partners, of which $5M was allocated to interest expense and $20M to the principal.

On December 21, 2017, the Fort Hills partners resolved their commercial dispute and reached an agreement in which Suncor acquired an additional 2.26% interest in the project for consideration of $308 million. Teck Resources Limited (Teck) also acquired an additional 0.89% interest in the project as a result of the agreement. Suncor's share in the project has increased to 53.06% and Teck's share has increased to 20.89% with Total E&P Canada Ltd. (Total) share decreasing to 26.05%. Working interests in the Fort Hills project may continue to be adjusted in accordance with the terms of the agreement.

The company has updated its commodity price, capital cost and operating cost assumptions for its Fort Hills' project. As a result, the company performed an impairment test on its share of the project as at December 31, 2017. The impairment test was performed using a fair value less cost of disposal methodology, and no impairment was noted. An expected cash flow approach was used based on 2017 year end reserves data and long-range planning assumptions reviewed and approved by management, with the following assumptions (Level 3 fair value inputs):

Based on the above assumptions, the estimated recoverable amount in respect of the company's interest in Fort Hills exceeds the carrying value. The recoverable amount is sensitive to changes in the key assumptions. Future changes in these assumptions, individually or in combination, could result in the recoverable amount being less than the carrying value and an impairment adjustment. A 5% decrease in the assumed realized prices would decrease the recoverable amount by approximately $1.1 billion. A 1% increase in the discount rate would decrease the recoverable amount by approximately $1.6 billion and a 5% increase in the estimated future operating costs would decrease the recoverable amount by $0.5 billion (sensitivities are after-tax).

The carrying value of the company's share of the Fort Hills project at December 31, 2017 was $11.8 billion which includes capitalized interest, capital leases and amounts allocated to the project at the time of the company's merger with Petro-Canada in 2009.

On February 7, 2018, Suncor reached an agreement with Canbriam Energy Inc. (Canbriam) to acquire a 37% equity interest in Canbriam, a private natural gas company, in exchange for substantially all of Suncor's northeast British Columbia land holdings and consideration of $52 million. The transaction is subject to regulatory approval and is expected to close in the first quarter of 2018.


	Three months ended										Twelve months ended
($ millions, except per share amounts)	Dec 31 2017		Sept 30 2017		Jun 30 2017		Mar 31 2017		Dec 31 2016		Dec 31 2017		Dec 31 2016

Revenues and other income	9 041		8 029		7 263		7 843		8 141		32 176		26 968

Net earnings (loss)

Oil Sands	670		314		(277	)	302		276		1 009		(1 149	)

Exploration and Production	217		161		182		172		54		732		190

Refining and Marketing	886		597		346		829		524		2 658		1 890

Corporate, Energy Trading and Eliminations	(391	)	217		184		49		(323	)	59		(486	)

	1 382		1 289		435		1 352		531		4 458		445

Operating earnings (loss)^(A)

Oil Sands	615		314		(277	)	302		316		954		(1 109	)

Exploration and Production	231		161		182		172		54		746		10

Refining and Marketing	746		597		346		475		524		2 164		1 890

Corporate, Energy Trading and Eliminations	(282	)	(205	)	(52	)	(137	)	(258	)	(676	)	(874	)

	1 310		867		199		812		636		3 188		(83	)

Funds from (used in) operations^(A)

Oil Sands	1 780		1 276		573		1 109		1 372		4 738		2 669

Exploration and Production	431		375		438		481		385		1 725		1 313

Refining and Marketing	935		827		504		575		722		2 841		2 606

Corporate, Energy Trading and Eliminations	(130	)	(6	)	112		(141	)	(114	)	(165	)	(600	)

	3 016		2 472		1 627		2 024		2 365		9 139		5 988

Per common share

Net earnings – basic and diluted	0.84		0.78		0.26		0.81		0.32		2.68		0.28

Net earnings attributable to common shareholders – basic and diluted	0.84		0.78		0.26		0.81		0.32		2.68		0.27

Operating earnings (loss) – basic^(A)	0.79		0.52		0.10		0.49		0.38		1.92		(0.05	)

Cash dividends – basic	0.32		0.32		0.32		0.32		0.29		1.28		1.16

Funds from operations – basic^(A)	1.83		1.49		0.98		1.21		1.42		5.50		3.72

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended					Twelve months ended
Oil Sands	Dec 31 2017	Sept 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016	Dec 31 2017	Dec 31 2016

Total Production (mbbls/d)	621.2	628.4	413.6	590.6	620.4	563.7	504.9

Oil Sands operations

Production volumes (mbbls/d)

Upgraded product (sweet SCO, sour SCO and diesel)	324.9	324.4	288.6	332.8	324.5	317.7	258.9

Non-upgraded bitumen	121.9	144.9	64.0	115.7	108.9	111.7	115.9

Oil Sands operations production	446.8	469.3	352.6	448.5	433.4	429.4	374.8

Bitumen production (mbbls/d)

Mining	296.7	328.1	293.1	311.1	284.8	305.4	238.0

In Situ – Firebag	208.5	203.6	110.9	202.8	204.5	181.5	180.8

In Situ – MacKay River	28.3	30.8	30.0	35.6	33.9	31.1	27.6

Total bitumen production	533.5	562.5	434.0	549.5	523.2	518.0	446.4

Sales (mbbls/d)

Light sweet crude oil	95.5	105.9	104.4	124.9	87.2	107.9	87.3

Diesel	21.1	30.4	29.6	30.3	28.4	27.5	21.2

Light sour crude oil	214.4	183.2	160.1	176.4	201.5	183.6	153.4

Upgraded product (SCO and diesel)	331.0	319.5	294.1	331.6	317.1	319.0	261.9

Non-upgraded bitumen	130.7	120.3	86.0	104.9	103.5	110.6	117.4

Sales	461.7	439.8	380.1	436.5	420.6	429.6	379.3

Cash operating costs – Average^(1)(A) ($/bbl)*

Cash costs	22.55	20.40	25.70	20.15	22.10	21.95	24.35

Natural gas	1.65	1.20	2.10	2.40	2.85	1.85	2.15

	24.20	21.60	27.80	22.55	24.95	23.80	26.50

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

Cash costs	24.55	20.60	21.25	19.95	22.55	21.55	25.00

Natural gas	0.45	0.25	0.60	0.60	0.80	0.45	0.60

	25.00	20.85	21.85	20.55	23.35	22.00	25.60

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

Cash costs	6.20	6.75	10.95	7.00	6.35	7.35	7.60

Natural gas	2.65	2.20	4.00	4.00	4.40	3.15	3.30

	8.85	8.95	14.95	11.00	10.75	10.50	10.90

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.
(B): Cash operating costs – Mining bitumen production only for the twelve months ended December 31, 2016 has been restated.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended					Twelve months ended
Oil Sands	Dec 31 2017	Sept 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016	Dec 31 2017	Dec 31 2016

Syncrude

Sweet SCO production (mbbls/d)	174.4	159.1	61.0	142.1	187.0	134.3	130.1

Bitumen production (mbbls/d)	207.5	193.7	82.4	170.0	219.6	163.6	151.1

Intermediate sour SCO (mbbls/d)⁽²⁾	177.1	157.1	61.3	140.9	192.6	132.9	131.2

Cash operating costs^(1)(A) ($/bbl)

Cash costs	31.75	34.00	89.90	43.25	31.05	42.50	34.60

Natural gas	1.05	1.00	7.90	1.90	1.50	1.55	1.35

	32.80	35.00	97.80	45.15	32.55	44.05	35.95

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Twelve months ended
Oil Sands Operating Netbacks(A)	Dec 31 2017		Sept 30 2017		Jun 30 2017		Mar 31 2017		Dec 31 2016		Dec 31 2017		Dec 31 2016

Bitumen ($/bbl)

Average price realized	42.00		38.10		37.61		35.03		31.68		38.45		23.50

Royalties	(1.02	)	(0.50	)	(0.69	)	(0.54	)	(0.33	)	(0.71	)	(0.23	)

Transportation costs	(3.06	)	(3.78	)	(7.06	)	(6.57	)	(5.52	)	(4.85	)	(5.38	)

Net operating expenses	(7.61	)	(8.26	)	(14.05	)	(9.98	)	(9.99	)	(9.59	)	(11.25	)

Operating netback	30.31		25.56		15.81		17.94		15.84		23.30		6.64

SCO and diesel ($/bbl)

Average price realized	70.27		59.69		64.20		66.38		62.28		65.21		53.53

Royalties	(1.14	)	(1.03	)	(1.19	)	(0.59	)	2.74		(0.98	)	0.50

Transportation costs	(3.87	)	(3.65	)	(3.72	)	(3.98	)	(3.98	)	(3.81	)	(3.76	)

Net operating expenses – bitumen	(23.21	)	(21.66	)	(24.14	)	(21.01	)	(22.56	)	(22.47	)	(24.87	)

Net operating expenses – upgrading	(3.40	)	(3.28	)	(4.15	)	(3.58	)	(4.31	)	(3.59	)	(5.38	)

Operating netback	38.65		30.07		31.00		37.22		34.17		34.36		20.02

Average Oil Sands operations ($/bbl)

Average price realized	62.27		53.78		58.18		58.84		54.75		58.32		44.23

Royalties	(1.11	)	(0.89	)	(1.07	)	(0.58	)	1.99		(0.91	)	0.28

Transportation costs	(3.64	)	(3.68	)	(4.47	)	(4.60	)	(4.36	)	(4.08	)	(4.26	)

Net operating expenses – bitumen and upgrading	(21.23	)	(20.38	)	(25.08	)	(21.07	)	(22.72	)	(21.82	)	(24.37	)

Operating netback	36.29		28.83		27.56		32.59		29.66		31.51		15.88

Syncrude ($/bbl)

Average price realized	73.64		60.68		62.27		66.37		64.28		66.59		56.91

Royalties	(7.94	)	(3.18	)	—		(2.96	)	(4.70	)	(4.32	)	(1.90	)

Transportation costs	(0.36	)	(0.38	)	(1.83	)	(0.38	)	(0.35	)	(0.54	)	(0.53	)

Net operating expenses – bitumen and upgrading	(28.81	)	(31.48	)	(90.72	)	(39.70	)	(29.18	)	(39.46	)	(32.05	)

Operating netback	36.53		25.64		(30.28	)	23.33		30.05		22.27		22.43

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Twelve months ended
Exploration and Production	Dec 31 2017		Sept 30 2017		Jun 30 2017		Mar 31 2017		Dec 31 2016		Dec 31 2017		Dec 31 2016

Total Sales Volumes (mboe/d)	104.8		112.6		130.3		136.8		120.5		120.8		119.3

Total Production (mboe/d)	115.2		111.5		125.5		134.5		118.1		121.6		117.9

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)	14.6		5.8		11.0		14.7		16.7		11.5		12.4

Hibernia (mbbls/d)	27.1		26.6		30.0		30.3		30.1		28.5		26.8

White Rose (mbbls/d)	10.6		9.0		12.9		13.1		10.9		11.4		10.9

Hebron (mbbls/d)	1.8		—		—		—		—		0.4		—

North America Onshore (mboe/d)	1.4		1.5		1.8		2.8		2.8		1.9		2.8

	55.5		42.9		55.7		60.9		60.5		53.7		52.9

Exploration and Production International

Buzzard (mboe/d)	36.6		44.3		45.3		49.0		37.5		43.8		46.0

Golden Eagle (mboe/d)	17.9		20.5		20.1		20.2		19.0		19.6		18.6

United Kingdom (mboe/d)	54.5		64.8		65.4		69.2		56.5		63.4		64.6

Libya (mbbls/d)⁽³⁾	5.2		3.8		4.4		4.4		1.1		4.5		0.4

	59.7		68.6		69.8		73.6		57.6		67.9		65.0

Netbacks^(A)

East Coast Canada ($/bbl)

Average price realized	81.49		67.23		66.26		69.75		68.06		71.06		59.31

Royalties	(13.21	)	(13.01	)	(14.05	)	(15.94	)	(15.07	)	(14.26	)	(10.64	)

Transportation costs	(2.27	)	(2.13	)	(1.60	)	(1.72	)	(1.72	)	(1.90	)	(1.91	)

Operating costs	(11.16	)	(14.72	)	(10.58	)	(9.28	)	(9.52	)	(11.24	)	(12.67	)

Operating netback	54.85		37.37		40.03		42.81		41.75		43.66		34.09

United Kingdom ($/boe)

Average price realized	76.46		62.99		63.46		67.55		62.63		67.25		53.91

Transportation costs	(1.80	)	(1.77	)	(1.88	)	(1.81	)	(1.62	)	(1.81	)	(1.84	)

Operating costs	(5.89	)	(4.51	)	(4.57	)	(3.75	)	(7.00	)	(4.62	)	(5.62	)

Operating netback	68.77		56.71		57.01		61.99		54.01		60.82		46.45

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended					Twelve months ended
Refining and Marketing	Dec 31 2017	Sept 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016	Dec 31 2017	Dec 31 2016

Refined product sales (mbbls/d)	526.8	564.5	521.9	508.0	514.8	530.5	521.4

Crude oil processed (mbbls/d)	432.4	466.8	435.5	429.9	427.3	441.2	428.6

Utilization of refining capacity (%)	94	101	94	93	93	96	93

Refining margin ($/bbl)^(A)	31.75	23.80	18.85	22.30	23.00	24.20	20.30

Refining operating expense ($/bbl)^(A)	5.25	4.50	5.05	5.50	5.45	5.05	5.10

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	121.1	121.2	114.8	112.8	115.5	117.5	115.2

Distillate	89.2	92.6	82.9	82.2	79.9	86.8	76.3

Total transportation fuel sales	210.3	213.8	197.7	195.0	195.4	204.3	191.5

Petrochemicals	10.5	10.6	12.2	15.5	10.1	12.2	9.2

Asphalt	15.8	20.6	18.0	12.6	16.8	16.8	16.7

Other	31.4	32.4	35.5	34.5	34.4	33.4	35.9

Total refined product sales	268	277.4	263.4	257.6	256.7	266.7	253.3

Crude oil supply and refining

Processed at refineries (mbbls/d)	188.7	213.9	208.6	214.6	204.8	206.4	203.1

Utilization of refining capacity (%)	85	96	94	97	92	93	92

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	125.7	136.4	122.0	117.1	125.8	125.4	129.1

Distillate	111.7	119.9	108.3	110.1	106.8	112.5	109.8

Total transportation fuel sales	237.4	256.3	230.3	227.2	232.6	237.9	238.9

Asphalt	9.3	16.0	14.6	9.2	9.7	12.3	11.8

Other	12.1	14.8	13.6	14.0	15.8	13.6	17.4

Total refined product sales	258.8	287.1	258.5	250.4	258.1	263.8	268.1

Crude oil supply and refining

Processed at refineries (mbbls/d)	243.7	252.9	226.9	215.3	222.5	234.8	225.5

Utilization of refining capacity (%)	102	105	95	90	93	98	94

(A): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended December 31, 2017	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	710		2 209		2 919		1 196		1		4 116

Other (loss) income	(10	)	(8	)	(18	)	79		—		61

Purchases of crude oil and products	(179	)	(38	)	(217	)	(14	)	(2	)	(233	)

Gross realization adjustment⁽⁵⁾	(17	)	(22	)	(39	)	(79	)

Gross realizations	504		2 141		2 645		1 182

Royalties	(12	)	(35	)	(47	)	(128	)	—		(175	)

Transportation	(39	)	(118	)	(157	)	(12	)	—		(169	)

Transportation adjustment⁽⁶⁾	3		—		3		6

Net transportation expenses	(36	)	(118	)	(154	)	(6	)

Operating, selling and general (OS&G)	(119	)	(958	)	(1 077	)	(536	)	(3	)	(1 616	)

OS&G adjustment⁽⁷⁾	27		148		175		74

Net operating expenses	(92	)	(810	)	(902	)	(462	)

Gross profit	364		1 178		1 542		586

Sales volumes (mbbls)	12 019		30 454		42 473		16 049

Operating netback per barrel	30.31		38.65		36.29		36.53


For the quarter ended September 30, 2017	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	543		1 787		2 330		901		2		3 233

Other (loss) income	(5	)	(2	)	(7	)	1		—		(6	)

Purchases of crude oil and products	(103	)	(18	)	(121	)	(12	)	(2	)	(135	)

Gross realization adjustment⁽⁵⁾	(14	)	(13	)	(27	)	(1	)

Gross realizations	421		1 754		2 175		889

Royalties	(5	)	(30	)	(35	)	(47	)	—		(82	)

Transportation	(46	)	(107	)	(153	)	(11	)	—		(164	)

Transportation adjustment⁽⁶⁾	4		—		4		6

Net transportation expenses	(42	)	(107	)	(149	)	(5	)

OS&G	(115	)	(870	)	(985	)	(525	)	(3	)	(1 513	)

OS&G adjustment⁽⁷⁾	24		137		161		63

Net operating expenses	(91	)	(733	)	(824	)	(462	)

Gross profit	283		884		1 167		375

Sales volumes (mbbls)	11 075		29 390		40 465		14 636

Operating netback per barrel	25.56		30.07		28.83		25.64

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended June 30, 2017	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	377		1 758		2 135		361		2		2 498

Other income (loss)	12		(1	)	11		—		6		17

Purchases of crude oil and products	(101	)	(21	)	(122	)	(15	)	(2	)	(139	)

Gross realization adjustment⁽⁵⁾	6		(18	)	(12	)	—

Gross realizations	294		1 718		2 012		346

Royalties	(5	)	(32	)	(37	)	—		—		(37	)

Transportation	(55	)	(100	)	(155	)	(13	)	—		(168	)

Transportation adjustment⁽⁶⁾	—		—		—		3

Net transportation expenses	(55	)	(100	)	(155	)	(10	)

OS&G	(126	)	(900	)	(1 026	)	(551	)	2		(1 575	)

OS&G adjustment⁽⁷⁾	16		143		159		47

Net operating expenses	(110	)	(757	)	(867	)	(504	)

Gross profit (loss)	124		829		953		(168	)

Sales volumes (mbbls)	7 827		26 764		34 590		5 549

Operating netback per barrel	15.81		31.00		27.56		(30.28	)


For the quarter ended March 31, 2017	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)	Oil Sands Segment

Operating revenues	400		2 022		2 422		868		—	3 290

Other income	9		3		12		2		—	14

Purchases of crude oil and products	(75	)	(22	)	(97	)	(19	)	—	(116	)

Gross realization adjustment⁽⁵⁾	(4	)	(22	)	(26	)	(2	)

Gross realizations	330		1 981		2 311		849

Royalties	(5	)	(18	)	(23	)	(38	)	—	(61	)

Transportation	(62	)	(118	)	(180	)	(9	)	—	(189	)

Transportation adjustment⁽⁶⁾	—		—		—		4

Net transportation expenses	(62	)	(118	)	(180	)	(5	)

OS&G	(123	)	(875	)	(998	)	(583	)	28	(1 553	)

OS&G adjustment⁽⁷⁾	29		141		170		76

Net operating expenses	(94	)	(734	)	(828	)	(507	)

Gross profit	169		1 111		1 280		299

Sales volumes (mbbls)	9 444		29 844		39 288		12 788

Operating netback per barrel	17.94		37.22		32.59		23.33

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended December 31, 2016	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	375		1 865		2 240		1 116		—		3 356

Other (loss) income	(4	)	(5	)	(9	)	17		—		8

Purchases of crude oil and products	(62	)	(20	)	(82	)	(19	)	—		(101	)

Gross realization adjustment⁽⁵⁾	(7	)	(25	)	(32	)	(8	)

Gross realizations	302		1 815		2 117		1 106

Royalties	(3	)	80		77		(81	)	—		(4	)

Transportation	(52	)	(116	)	(168	)	(9	)	—		(177	)

Transportation adjustment⁽⁶⁾	—		—		—		3

Net transportation expenses	(52	)	(116	)	(168	)	(6	)

OS&G	(121	)	(935	)	(1 056	)	(577	)	(1	)	(1 634	)

OS&G adjustment⁽⁷⁾	25		152		177		75

Net operating expenses	(96	)	(783	)	(879	)	(502	)

Gross profit	151		996		1 147		517

Sales volumes (mbbls)	9 525		29 176		38 701		17 205

Operating netback per barrel	15.84		34.17		29.66		30.05


For the twelve months ended December 31, 2017	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	2 031		7 777		9 808		3 325		4		13 137

Other income (loss)	9		(9	)	—		82		4		86

Purchases of crude oil and products	(458	)	(99	)	(557	)	(61	)	(5	)	(623	)

Gross realization adjustment⁽⁵⁾	(31	)	(76	)	(107	)	(82	)

Gross realizations	1 551		7 593		9 144		3 264

Royalties	(28	)	(115	)	(143	)	(212	)	—		(355	)

Transportation	(202	)	(443	)	(645	)	(45	)	—		(690	)

Transportation adjustment⁽⁶⁾	7		—		7		18

Net transportation expenses	(195	)	(443	)	(638	)	(27	)

OS&G	(484	)	(3 604	)	(4 088	)	(2 196	)	27		(6 257	)

OS&G adjustment⁽⁷⁾	96		569		665		262

Net operating expenses	(388	)	(3 035	)	(3 423	)	(1 934	)

Gross profit	940		4 000		4 940		1 091

Sales volumes (mbbls)	40 365		116 451		156 816		49 022

Operating netback per barrel	23.30		34.36		31.51		22.27

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.


For the twelve months ended December 31, 2016	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)	Oil Sands Segment

Operating revenues	1 434		5 281		6 715		2 807		—	9 522

Other income	6		2		8		17		1	26

Purchases of crude oil and products	(408	)	(83	)	(491	)	(57	)	—	(548	)

Gross realization adjustment⁽⁵⁾	(22	)	(70	)	(92	)	(57	)

Gross realizations	1 010		5 130		6 140		2 710

Royalties	(10	)	48		38		(90	)	—	(52	)

Transportation	(231	)	(385	)	(616	)	(50	)	—	(666	)

Transportation adjustment⁽⁶⁾	—		25		25		25

Net transportation expenses	(231	)	(360	)	(591	)	(25	)

OS&G	(595	)	(3 468	)	(4 063	)	(1 749	)	35	(5 777	)

OS&G adjustment⁽⁷⁾	112		568		680		223

Net operating expenses	(483	)	(2 900	)	(3 383	)	(1 526	)

Gross profit	286		1 918		2 204		1 069

Sales volumes (mbbls)	42 973		95 852		138 825		47 614

Operating netback per barrel	6.64		20.02		15.88		22.43

See accompanying footnotes and definitions to the quarterly operating summaries.

Exploration and Production Netbacks(A)
($ millions except per barrel amounts)


For the quarter ended September 30, 2017	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	375		263		128		766

Royalties	—		(51	)	(81	)	(132	)

Transportation	(11	)	(8	)	(2	)	(21	)

OS&G	(31	)	(68	)	(10	)	(109	)

Non-production costs⁽¹⁰⁾	5		10

Gross realizations	338		146

Sales volumes (mboe)	5 963		3 906

Operating netback per barrel	56.71		37.37

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

Exploration and Production Netbacks(A)
($ millions except per barrel amounts)


For the quarter ended December 31, 2016	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	325		374		43		742

Royalties	—		(83	)	(12	)	(95	)

Transportation	(9	)	(10	)	(2	)	(21	)

OS&G	(38	)	(63	)	(14	)	(115	)

Non-production costs⁽¹⁰⁾	3		11

Gross realizations	281		229

Sales volumes (mboe)	5 193		5 495

Operating netback per barrel	54.01		41.75

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

Exploration and Production Netbacks(A)
($ millions except per barrel amounts)


	Three months ended										Twelve months ended
	Dec 31 2017		Sept 30 2017		June 30 2017		Mar 31 2017		Dec 31 2016		Dec 31 2017		Dec 31 2016

Gross margin⁽¹¹⁾	1 871		1 520		1 160		1 401		1 580		5 952		5 813

Other (loss) income	(13	)	48		19		19		(10	)	73		16

Non-refining margin⁽¹²⁾	(467	)	(463	)	(375	)	(495	)	(592	)	(1 800	)	(2 403	)

Refining margin	1 391		1 105		804		925		978		4 225		3 426

Refinery production (mbbls)⁽¹³⁾	43 801		46 491		42 629		41 540		42 510		174 461		168 798

Refining margin ($/bbl)^(A)	31.75		23.80		18.85		22.30		23.00		24.20		20.30

OS&G	545		481		464		517		586		2 007		2 203

Non-refining costs⁽¹⁴⁾	(316	)	(272	)	(249	)	(288	)	(355	)	(1 125	)	(1 343	)

Refining operating expense	229		209		215		229		231		882		860

Refinery production (mbbls)⁽¹³⁾	43 801		46 491		42 629		41 540		42 510		174 461		168 798

Refining operating expense ($/bbl)^(A)	5.25		4.50		5.05		5.50		5.45		5.05		5.10

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.

See accompanying footnotes and definitions to the quarterly operating summaries.

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense and netbacks – are not prescribed by GAAP. Suncor includes these financial measures because investors may use this 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. 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 operations cash operating costs for each quarter in 2017 and 2016 are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in each respective quarterly Report to Shareholders issued by Suncor in respect of the relevant quarter (Quarterly Reports). Funds from (used in) operations and ROCE for each quarter in 2017 and 2016 are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective Quarterly Report. Refining margin, refining operating expense and Syncrude cash operating costs for each relevant quarter in 2017 and 2016 and for the year ended December 31, 2016 are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Operating Metrics Reconciliation section of this Quarterly Report. Netbacks for each relevant quarter in 2017 and 2016 and for the year ended December 31, 2016 are defined below and are reconciled to GAAP measures in the Operating Metrics Reconciliation section of this Quarterly Report.

Oil Sands operating netbacks are a non-GAAP measure, presented on a crude product and sales barrel basis, and are derived from the Oil Sands segmented statement of net earnings (loss), after adjusting for items not directly attributable to the revenues and costs associated with production and delivery. Management uses Oil Sands operating netbacks to measure crude product profitability on a sales barrel basis.

Exploration and Production netbacks are a non-GAAP measure, presented on an asset location and sales barrel basis, and are derived from the E&P segmented statement of net earnings (loss), after adjusting for items not directly attributable to the costs associated with production and delivery. Management uses Exploration and Production operating netbacks to measure asset profitability by location on a sales barrel basis.

(10) Reflects adjustments for general and administrative costs not directly attributed to production.

(12) Reflects the gross margin associated with the company's supply, marketing, lubricants and ethanol businesses.

(13) Refinery production is the output of the refining process, and differs from crude oil processed as a result of volumetric adjustments for non-crude feedstock, volumetric gain associated with the refining process, and changes in unfinished product inventories.

(14) Reflects operating, selling and general costs associated with the company's supply, marketing, lubricants and ethanol businesses, as well as certain general and administrative costs not directly attributable to refinery production.

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	2017	2016	2017	2016

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	79.19	66.33	69.14	57.37

E&P Canada – Natural gas ($/mcfe)	0.44	2.43	1.77	1.71

E&P International ($/boe)	74.49	61.01	65.46	52.07


(thousands)		December 31, 2017

Common shares		1 640 983

Common share options – exercisable		17 363

Common share options – non-exercisable		13 747


	Three months ended December 31				Twelve months ended December 31
($ millions)	2017		2016		2017		2016

Funds from operations	3 016		2 365		9 139		5 988

Sustaining capital and dividends	(1 344	)	(990	)	(5 083	)	(4 191	)

Discretionary Free Funds Flow	1 672		1 375		4 056		1 797


1.	Advisories	5
2.	Fourth Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	23
6.	Financial Condition and Liquidity	25
7.	Quarterly Financial Data	29
8.	Other Items	30
9.	Non-GAAP Financial Measures Advisory	31
10.	Common Abbreviations	36
11.	Forward-Looking Information	37


($ millions)	Energy Trading		Risk Management		Total

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

Cash Settlements – received during the period	(12	)	17		5

Losses recognized in earnings during the period (note 4)	(37	)	(19	)	(56	)

Fair value outstanding at December 31, 2017	(85	)	(20	)	(105	)


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

Accounts receivable	21		53		—	74

Accounts payable	(74	)	(105	)	—	(179	)

	(53	)	(52	)	—	(105	)


	For the twelve months ended
	Dec 31 2017	Sep 30 2017	Jun 30 2017	Mar 31 2017	Dec 31 2016

Return on capital employed^(A)

– excluding major projects in progress (%)	8.6	7.0	6.2	4.4	0.5

– including major projects in progress (%)	6.7	5.5	4.9	3.5	0.4


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