All financial figures are unaudited and presented in Canadian dollars (Cdn$) unless noted otherwise. Production volumes are presented on a working-interest basis, before royalties, unless noted otherwise. Certain financial measures in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these non-GAAP financial measures, see the Non-GAAP Financial Measures Advisory section of Suncor's Management's Discussion and Analysis, dated April 26, 2017 (the MD&A). See also the Advisories section of the MD&A. References to Oil Sands operations exclude Suncor's interest in Syncrude's operations.

"Our Oil Sands operations and offshore assets posted impressive production results and continued low operating costs, generating industry-leading cash flow per barrel," said Steve Williams, president and chief executive officer. "Our Refining and Marketing segment also delivered another strong quarter, contributing to companywide total funds from operations of over $2.0 billion."

Suncor recorded first quarter 2017 operating earnings⁽¹⁾ of $812 million ($0.49 per common share) compared to a $500 million operating loss ($0.33 per common share) in the prior year quarter. Highlights of the quarter included improved crude price realizations combined with strong upstream production, an R&M first-in, first-out (FIFO) gain and lower companywide operating costs. Additional Syncrude production resulting from working interests acquired during 2016 was partially offset by the impact of decreased production associated with an incident at Syncrude's Mildred Lake facility, which occurred late in the first quarter of 2017.

Funds from operations⁽¹⁾ were $2.024 billion ($1.21 per common share) compared to $682 million ($0.45 per common share) in the first quarter of 2016 and were impacted by the same factors noted in operating earnings above.

Net earnings were $1.352 billion ($0.81 per common share) in the first quarter of 2017, compared with $257 million ($0.17 per common share) in the prior year quarter. Net earnings for the first quarter of 2017 included an unrealized after-tax foreign exchange gain of $103 million on the revaluation of U.S. dollar denominated debt and after-tax gains of $437 million on the sale of the company's lubricants business and its interest in the Cedar Point wind facility. Net earnings in the prior year quarter included an unrealized after-tax foreign exchange gain of $885 million on the revaluation of U.S. dollar denominated debt, an after-tax charge of $38 million for costs associated with the acquisition and integration of Canadian Oil Sands Limited (COS), and a non-cash after-tax loss of $90 million on forward interest rate derivatives.

Suncor's total upstream production was 725,100 boe/d in the first quarter of 2017, compared with 691,400 boe/d in the prior year quarter, with the increase primarily attributed to the additional 41.74% ownership interest in Syncrude acquired during 2016 and increased E&P production, partially offset by the incident at Syncrude's Mildred Lake facility that occurred late in the first quarter. Syncrude has advanced its planned second quarter turnaround to help mitigate the impact of the incident and expects to return to normal operating rates during the second quarter.

Oil Sands operations production was 448,500 bbls/d in the first quarter of 2017, compared to 453,000 bbls/d in the prior year quarter, with strong reliability in both quarters. SCO production improved to 332,800 bbls/d from 322,300 bbls/d in the prior year quarter and was offset by an associated decrease in non-upgraded bitumen. Upgrader utilization at Oil Sands operations improved to 95%, compared to 92% in the prior year quarter, as a result of lower unplanned maintenance.

Oil Sands operations cash operating costs per barrel⁽¹⁾ decreased in the first quarter of 2017 to $22.55, compared to $24.25 in the prior year quarter, due to lower operating expenses resulting from the company's continued focus on cost reductions more than offsetting higher natural gas input costs and lower production volumes.

Suncor's share of Syncrude production was 142,100 bbls/d in the first quarter of 2017, compared to 112,800 bbls/d in the prior year quarter. The increase is attributed to additional working interests acquired partway through the first quarter of 2016 and the second quarter of 2016, partially offset by the facility incident late in the first quarter of 2017. As a result of the incident, upgrader reliability decreased to 75%, from 89% in the prior year quarter. Syncrude cash operating costs per barrel⁽¹⁾ in the first quarter of 2017 were $45.15, an increase from $31.35 in the prior year quarter due to the loss of production combined with higher maintenance and natural gas input costs.

"Our commitment to operational excellence remains a top priority and we will continue to seek ways to become more efficient, including development of regional synergies with Syncrude," said Williams. "We were able to partially mitigate the impact of the Syncrude incident by making use of Suncor's operational flexibility and that's an indication of the future benefits of integration."

Syncrude has developed a detailed repair schedule and return to service plan that includes the completion of a planned turnaround which was advanced in order to minimize the impact of the outage. Restart of pipeline shipments at approximately 50% capacity is expected in early May, with production expected to return to full rates by the end of June. The plant is currently operating at reduced rates and Suncor will continue to assist in inventory management.

Production volumes in E&P increased to 134,500 boe/d in the first quarter of 2017, compared to 125,600 boe/d in the prior year quarter, primarily due to production from new wells at Hibernia and reliability improvements and reservoir optimization at Terra Nova, partially offset by natural declines at Buzzard.

Average refinery crude throughput increased to 429,900 bbls/d, compared to 420,900 bbls/d in the prior year quarter due to lower planned maintenance and improved performance at the Edmonton and Montreal refineries in the first quarter of 2017. Average refinery utilization in the first quarter of 2017 improved to 93% from 91% in the prior year quarter.

The disciplined execution of Suncor's 2017 capital program will focus on bringing Suncor's major growth projects, Fort Hills and Hebron, to first oil by the end of the year, while continuing to invest in the safety, reliability and efficiency of the company's operating assets.

Construction of the Fort Hills project exceeded 80% at the end of the first quarter of 2017, with the mining, ore processing plant and key infrastructure assets being handed over to operations in the period. Activity in the quarter also included the readying of primary extraction for handover to operations and continued development of the secondary extraction facilities. Expenditures in the first quarter of 2017 were also focused on early-works sustaining activities that will support the execution of the Fort Hills mine and tailings plan following the commencement of production.

Significant progress continued on the Hebron project in the first quarter of 2017, with the completed platform ready to be towed out to the final site in the second quarter. First oil remains on track for late 2017. Activity in the first quarter also included continued development drilling at Hibernia and White Rose.

"Significant progress continues to be made on Hebron and Fort Hills, with both projects on track for first oil at the end of 2017," said Williams. "The Hebron platform will be towed out to the production site as planned in the second quarter when weather conditions are optimal. With peak Fort Hills construction activity now behind us, we will continue to progress the phased commissioning of the project throughout the year."

Oil Sands operations continued to focus on ensuring safe, reliable and efficient execution of operations in the first quarter of 2017 and further progress on the East Tank Farm Development. Capital spending also included preparation for planned maintenance at Upgrader 2 and a turnaround at Firebag, both of which are scheduled to be completed in the second quarter of 2017.

Syncrude sustaining capital in the first quarter of 2017 was primarily focused on key reliability, safety and environmental projects, including advancement of an upgrader turnaround in response to the incident that occurred late in the first quarter of 2017.

During the first quarter of 2017, the company aligned with other Syncrude owners on a framework to drive operating efficiencies, improve performance and develop regional synergies through integration. The incident at Syncrude has accelerated the implementation of integration activities, with the flexibility of Suncor's logistics network and processing capabilities being leveraged to handle volumes of intermediate sour Syncrude production to assist in inventory management, allowing certain Syncrude assets to run at partial rates and reduce the impact of restart activities.

Suncor successfully closed the sale of both its Petro-Canada lubricants business and its interest in the Cedar Point wind facility for total proceeds of $1.4 billion and net after-tax gains of $437 million. Subsequent to the end of the first quarter, the proceeds from divestments were used towards the repayment of US$1.25 billion 6.10% notes originally scheduled to mature on June 1, 2018.


	Three months ended March 31
($ millions)	2017		2016

Net earnings	1 352		257

Unrealized foreign exchange gain on U.S. dollar denominated debt	(103	)	(885	)

Gain on significant disposals⁽²⁾	(437	)	—

Non-cash mark to market loss on interest rate swaps and foreign currency derivatives⁽³⁾	—		90

COS acquisition and integration costs⁽⁴⁾	—		38

Operating earnings (loss)⁽¹⁾	812		(500	)

(1): Operating earnings (loss) is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Gain of $354 million related to the sale of the company's lubricants business in the R&M segment, combined with a gain of $83 million related to the sale of the company's interest in the Cedar Point wind facility in the Corporate segment.
(3): Non-cash mark to market loss on forward interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates in the Corporate segment.
(4): Transaction and related charges associated with the acquisition of COS in the Corporate segment.

Suncor has updated production and other information in its 2017 corporate guidance, previously issued on November 17, 2016. The full year outlook range for Syncrude production has been updated from 150,000 – 165,000 bbls/d to 135,000 – 150,000 bbls/d and the full year outlook range for Syncrude cash operating costs has been updated from $32.00 – $35.00/bbl to $36.00 – $39.00/bbl, to reflect the facility incident that occurred late in the first quarter of 2017. In addition, the full year outlook range for E&P production has been updated from 95,000 – 105,000 boe/d to 110,000 – 120,000 boe/d due to improved asset performance, resulting in no change to the full year outlook range for total Suncor production.

The full year outlook range for Syncrude Crown Royalties has been updated from 1% – 3% to 3% – 6%. For further details and advisories regarding Suncor's 2017 revised corporate guidance, see www.suncor.com/guidance.

Subsequent to March 31, 2017, the Toronto Stock Exchange (TSX) accepted a notice filed by Suncor of its intention to commence a new Normal Course Issuer Bid (NCIB) to purchase and cancel up to $2.0 billion of the company's shares beginning on May 2, 2017 and ending on May 1, 2018 through the facilities of the TSX, New York Stock Exchange and/or alternative trading platforms. The actual number of common shares that may be purchased and the timing of any such purchases will be determined by Suncor. Suncor believes that, depending on the trading price of its common shares and other relevant factors, purchasing its own shares represents an attractive investment opportunity and is in the best interests of the company and its shareholders. The company does not expect the decision to allocate cash to repurchase shares will affect its long-term growth strategy.

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 the MD&A.

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins – Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. Periodically we market third-party petroleum products. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2016, dated March 1, 2017 (the 2016 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three-month period ended March 31, 2017, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2016 and the 2016 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated March 1, 2017 (the 2016 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

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

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

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

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

Certain financial measures in this MD&A – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense, discretionary free cash flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating earnings (loss), Oil Sands operations cash operating costs, Syncrude cash operating costs and LIFO are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to GAAP measures in the

Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Funds from (used in) operations, ROCE, discretionary free cash flow, refining margin and refining operating expense are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of this MD&A.

The company's financial and operational performance is potentially affected by a number of factors, including, but not limited to, the factors described within the Forward-Looking Information section of this MD&A. This MD&A contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is provided to assist readers in understanding the company's future plans and expectations and may not be appropriate for other purposes. Refer to the Forward-Looking Information section of this MD&A for information on the material risk factors and assumptions underlying our forward-looking information.

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

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


	Three months ended March 31
($ millions)	2017		2016

Net earnings (loss)

Oil Sands	302		(524	)

Exploration and Production	172		(34	)

Refining and Marketing	829		241

Corporate, Energy Trading and Eliminations	49		574

Total	1 352		257

Operating earnings (loss)⁽¹⁾

Oil Sands	302		(524	)

Exploration and Production	172		(34	)

Refining and Marketing	475		241

Corporate, Energy Trading and Eliminations	(137	)	(183	)

Total	812		(500	)

Funds from (used in) operations⁽¹⁾

Oil Sands	1 109		263

Exploration and Production	481		261

Refining and Marketing	575		404

Corporate, Energy Trading and Eliminations	(141	)	(246	)

Total	2 024		682

Capital and Exploration Expenditures⁽²⁾

Sustaining	399		471

Growth	807		944

Total	1 206		1 415


	Three months ended March 31
	2017	2016

Production volumes by segment

Oil Sands (mbbls/d)	590.6	565.8

Exploration and Production (mboe/d)	134.5	125.6

Total (mboe/d)	725.1	691.4

Production mix

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

Refinery utilization (%)	93	91

Refinery crude oil processed (mbbls/d)	429.9	420.9

Suncor's consolidated net earnings for the first quarter of 2017 were $1.352 billion, compared with $257 million for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A. Other items affecting net earnings over these periods included:


	Three months ended March 31
($ millions)	2017		2016

Net earnings	1 352		257

Unrealized foreign exchange gain on U.S. dollar denominated debt	(103	)	(885	)

Gain on significant disposal⁽²⁾	(437	)	—

Non-cash mark to market loss on interest rate swaps and foreign currency derivatives⁽³⁾	—		90

COS acquisition and integration costs⁽⁴⁾	—		38

Operating earnings (loss)⁽¹⁾	812		(500	)

(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 MD&A.
(2): Gain of $354 million related to the sale of the company's lubricants business in the R&M segment, combined with a gain of $83 million on the sale of the company's interest in the Cedar Point wind facility in the Corporate segment.
(3): Non-cash mark to market loss on interest rate swaps and foreign currency derivatives resulting from changes in long-term interest rates and foreign exchange rates in the Corporate segment.
(4): Transaction and related charges associated with the acquisition of COS in the Corporate segment.

Suncor's consolidated operating earnings for the first quarter of 2017 were $812 million, compared to an operating loss of $500 million in the prior year quarter, with the increase attributed to improved crude price realizations combined with strong upstream production, an R&M FIFO gain and lower companywide operating costs. Additional Syncrude production resulting from working interests acquired during 2016 was partially offset by the impact of decreased production associated with the incident at Syncrude's Mildred Lake facility late in the first quarter of 2017.

The after-tax share-based compensation expense decreased to $72 million during the first quarter of 2017, compared to $102 million during the prior year quarter, as a result of a share price decrease in the first quarter of 2017 when compared to the prior year quarter. In the first quarter of 2017, share-based compensation cash payments were $348 million, compared to $292 million 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 three months ended March 31
		2017	2016

WTI crude oil at Cushing	US$/bbl	51.85	33.50

Dated Brent crude	US$/bbl	53.75	33.90

Dated Brent/Maya crude oil FOB price differential	US$/bbl	9.05	8.95

MSW at Edmonton	Cdn$/bbl	64.25	34.50

WCS at Hardisty	US$/bbl	37.30	19.30

Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.55	14.25

Condensate at Edmonton	US$/bbl	52.20	34.45

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.70	1.85

Alberta Power Pool Price	Cdn$/MWh	22.40	18.10

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	12.55	11.75

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	11.15	9.10

Portland 3-2-1 crack⁽¹⁾	US$/bbl	18.45	13.00

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	14.00	11.05

Exchange rate	US$/Cdn$	0.76	0.73

Exchange rate (end of period)	US$/Cdn$	0.75	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 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 first quarter of 2017 for sweet SCO were positively impacted by a higher WTI price of US$51.85/bbl, compared to US$33.50/bbl in the prior year quarter, as well as a favourable differential for SCO relative to WTI. Suncor produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton increased to $64.25/bbl compared to $34.50/bbl in the prior year quarter and prices for WCS at Hardisty increased to US$37.30/bbl from US$19.30 in the first quarter of 2016.

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

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing increased to an average of US$53.75/bbl in the first quarter of 2017, compared to US$33.90/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark increased to $2.70/mcf in the first quarter of 2017, from $1.85/mcf in the prior year quarter.

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

Excess electricity produced in Suncor's Oil Sands business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price increased to an average of $22.40/MWh in the first quarter of 2017, compared with $18.10/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 first quarter of 2017, the Canadian dollar strengthened in relation to the U.S. dollar as the average exchange rate increased to US$0.76 per one Canadian dollar from US$0.73 per one Canadian dollar in the prior year quarter. This rate increase had a negative impact on price realizations for the company during the first quarter of 2017 when compared to the prior year quarter.

Suncor also has assets and liabilities, notably 75% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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 March 31
($ millions)	2017		2016

Gross revenues	3 290		2 039

Less: Royalties	(61	)	(19	)

Operating revenues, net of royalties	3 229		2 020

Net earnings (loss)	302		(524	)

Operating earnings (loss)⁽¹⁾	302		(524	)

Oil Sands operations	*293*		(517	)

Oil Sands ventures	9		(7	)

Funds from operations⁽¹⁾	1 109		263

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

Operating earnings for Oil Sands operations were $293 million, compared to an operating loss of $517 million in the prior year quarter. The improvement is due to higher crude price realizations, consistent with increased benchmark pricing, and lower operating and maintenance expenses associated with the company's continued cost reduction initiatives, partially offset by higher natural gas costs due to an increase in natural gas benchmark pricing.

Operating earnings for Oil Sands ventures were $9 million in the first quarter of 2017, compared to an operating loss of $7 million in the prior year quarter, with higher crude price realizations combined with the acquisition of additional working interests in 2016 being partially offset by the impact of the Syncrude Mildred Lake facility incident occurring near the end of the first quarter of 2017 and an increase in operating expenses associated with additional maintenance and higher natural gas input costs.


	Three months ended March 31
(mbbls/d)	2017	2016

Upgraded product (SCO and diesel)	332.8	322.3

Non-upgraded bitumen	115.7	130.7

Oil Sands operations	448.5	453.0

Oil Sands ventures – Syncrude	142.1	112.8

Total	590.6	565.8

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

Oil Sands operations production was 448,500 bbls/d in the first quarter of 2017, compared to 453,000 bbls/d in the prior year quarter, with both quarters achieving strong reliability. SCO production improved to 332,800 bbls/d from 322,300 bbls/d in the prior year quarter and was offset by an associated decrease in non-upgraded bitumen. Upgrader utilization at Oil Sands operations improved to 95%, compared to 92% in the prior year quarter, as a result of lower unplanned maintenance.


	Three months ended March 31
(mbbls/d)	2017	2016

Oil Sands operations sales volumes

Sweet SCO	124.9	132.2

Diesel	30.3	24.8

Sour SCO	176.4	172.7

Upgraded product	331.6	329.7

Non-upgraded bitumen	104.9	134.5

Oil Sands operations	436.5	464.2

Oil Sands ventures – Syncrude	142.1	112.8

Total	578.6	577.0

Sales volumes for Oil Sands operations decreased to 436,500 bbls/d in the first quarter of 2017 from 464,200 bbls/d in the prior year quarter, due to an increase in shipments to the U.S. Gulf Coast in 2017, which results in additional time to deliver the product to market.

Suncor's share of Syncrude production was 142,100 bbls/d in the first quarter of 2017, compared to 112,800 bbls/d in the prior year quarter. The increase is attributed to additional working interests acquired partway through the first quarter of 2016 and the second quarter of 2016, partially offset by decreased production associated with the facility incident late in the first quarter of 2017. As a result of the incident, Syncrude upgrader reliability decreased to 75%, from 89% in the prior year quarter.


	Three months ended March 31
	2017	2016

Oil Sands Base

Bitumen production (mbbls/d)	311.1	304.0

Bitumen ore mined (thousands of tonnes per day)	469.1	449.4

Bitumen ore grade quality (bbls/tonne)	0.66	0.68

In Situ

Bitumen production – Firebag (mbbls/d)	202.8	199.0

Bitumen production – MacKay River (mbbls/d)	35.6	36.8

Total In Situ bitumen production (mbbls/d)	238.4	235.8

Total Oil Sands Operations Bitumen production (mbbls/d)	549.5	539.8

Steam-to-oil ratio – Firebag	2.7	2.6

Steam-to-oil ratio – MacKay River	3.0	2.8

Bitumen production at Oil Sands operations in the first quarter of 2017 increased to 549,500 bbls/d, compared to 539,800 bbls/d in the prior year quarter, due to higher production at In Situ and Oil Sands Base attributed to strong reliability.

Firebag's steam-to-oil ratio of 2.7 was comparable with the prior year quarter. The steam-to-oil ratio at MacKay River increased to 3.0 from 2.8 in the prior year quarter due to additional steam requirements for a new well pad.


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

Oil Sands operations

SCO and diesel	62.40		39.44

Bitumen	28.46		6.43

Crude sales basket (all products)	54.24		29.87

Crude sales basket, relative to WTI	(13.98	)	(16.20	)

Oil Sands ventures

Syncrude – sweet SCO	65.99		44.07

Syncrude, relative to WTI	(2.23	)	(2.00	)

Average price realizations from Oil Sands operations increased to $54.24/bbl in the first quarter of 2017 from $29.87/bbl in the prior year quarter, due to higher WTI benchmark prices, improved SCO differentials and a higher proportion of SCO production in the first quarter of 2017.

Average price realizations at Syncrude increased to $65.99/bbl in the first quarter of 2017 from $44.07/bbl in the prior year quarter due to the increase in the WTI benchmark price. Improved SCO differentials were partly due to the incident at Syncrude that occurred late in the first quarter of 2017 and were not a significant factor for Syncrude price realizations.

Royalties for the Oil Sands segment were higher in the first quarter of 2017 compared to the prior year quarter, primarily due to improved bitumen prices and additional production associated with the increased working interest in Syncrude.

Operating and transportation expenses for the first quarter of 2017 increased from the prior year quarter, primarily due to additional Syncrude working interests acquired in 2016 combined with an increase in Syncrude maintenance costs and natural gas input costs across Oil Sands, partially offset by the impact of Suncor's cost reduction initiatives at Oil Sands operations. Absolute operating costs at Oil Sands operations in the first quarter of 2017 decreased more than 10% when compared to the prior year quarter. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs for Oil Sands operations.

DD&A and exploration expenses for the first quarter of 2017 were lower in comparison to the same period of 2016, due to a lower asset base at Oil Sands operations and a decrease in exploration expense more than offsetting the increased working interest in Syncrude.


	Three months ended March 31
($ millions)	2017		2016

Oil Sands operations cash operating cost⁽¹⁾ reconciliation

Operating, selling and general expense (OS&G)	1 553		1 435

Syncrude OS&G	(583	)	(334	)

Non-production costs⁽²⁾	(21	)	(33	)

Excess power capacity and other⁽³⁾	(49	)	(31	)

Inventory changes	11		(38	)

Oil Sands operations cash operating costs⁽¹⁾	911		999

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	22.55		24.25

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	583		334

Non-production costs⁽²⁾	(6	)	(12	)

Syncrude cash operating costs⁽¹⁾	577		322

Syncrude cash operating costs ($/bbl)⁽¹⁾	45.15		31.35

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

In the first quarter of 2017, Oil Sands operations cash operating costs per barrel decreased to $22.55, compared to $24.25 in the prior year quarter, due to lower operating and maintenance costs associated with the company's cost reduction initiatives partially offset by higher natural gas input costs. Total Oil Sands operations cash operating costs decreased to $911 million from $999 million in the prior year quarter.

In the first 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 as a result of a share price decrease in the first quarter of 2017 when compared to the prior year quarter.

Excess power capacity and other for the first quarter of 2017 represents a larger reduction to Oil Sands operations cash operating costs than the first quarter of 2016, primarily due to improved cogeneration power sales pricing.

Inventory changes in the first quarter of 2017 represent a build of inventory as compared to a significant draw in the prior year quarter, due to increased shipments to the U.S. Gulf Coast in the first quarter of 2017 and the resulting additional time required for product delivery.

In the first quarter of 2017, Syncrude cash operating costs per barrel increased to $45.15 from $31.35 in the previous year quarter due to lower production associated with the Mildred Lake facility incident, which occurred near the end of the first quarter of 2017, as well as higher cash operating expenses due to an increase in maintenance activities and natural gas input costs. Suncor's share of Syncrude cash operating costs increased to $577 million from $322 million in the previous year quarter due to the additional Syncrude working interests acquired in 2016, as well as the increase in operating expenses.

The company plans to complete maintenance at Upgrader 2 and a turnaround at Firebag in the second quarter of 2017. The impact of this maintenance has been reflected in the company's 2017 guidance.


	Three months ended March 31
($ millions)	2017		2016

Gross revenues	920		531

Less: Royalties	(123	)	(29	)

Operating revenues, net of royalties	797		502

Net earnings (loss)	172		(34	)

Operating earnings (loss)⁽¹⁾	172		(34	)

E&P Canada	17		(19	)

E&P International	*155*		(15	)

Funds from operations⁽¹⁾	481		261

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

Operating earnings of $17 million for E&P Canada improved from an operating loss of $19 million in the prior year quarter, primarily due to increased crude price realizations and lower operating costs, partially offset by increased exploration expense, as well as higher royalties associated with the increase in both crude pricing and production.

Operating earnings of $155 million for E&P International improved from an operating loss of $15 million in the prior year quarter, primarily due to increased crude price realizations, lower DD&A, decreased operating costs and increased production from Libya, partially offset by lower production at Buzzard.


	Three months ended March 31
	2017	2016

E&P Canada

Terra Nova (mbbls/d)	14.7	12.8

Hibernia (mbbls/d)	30.3	24.1

White Rose (mbbls/d)	13.1	13.7

North America Onshore (mboe/d)	2.8	3.0

	60.9	53.6

E&P International

Buzzard (mboe/d)	49.0	53.4

Golden Eagle (mboe/d)	20.2	18.6

United Kingdom (mboe/d)	69.2	72.0

Libya (mbbls/d)	4.4	—

	73.6	72.0

Total Production (mboe/d)	134.5	125.6

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

E&P Canada production averaged 60,900 boe/d in the first quarter of 2017, compared to 53,600 boe/d in the prior year quarter. The increase was primarily due to higher production at Hibernia with new wells being brought online in 2016 and at Terra Nova due to reservoir optimization and increased reliability.

E&P International production averaged 73,600 boe/d in the first quarter of 2017, compared to 72,000 boe/d in the prior year quarter, with increased production from Golden Eagle and Libya offsetting natural declines at Buzzard.

Price realizations for crude oil from E&P Canada and E&P International were higher in the first quarter of 2017 compared to the prior year quarter primarily due to an increase in benchmark crude pricing, partially offset by weaker foreign exchange rates.

Royalties were higher in the first quarter of 2017, compared with the prior year quarter, primarily due to improved crude prices combined with increased production from E&P Canada.

Operating and transportation expenses decreased in the first quarter of 2017, compared to the prior year quarter, primarily driven by a continued focus on cost reduction, lower planned maintenance costs and favourable foreign exchange on U.K. expenses, with the Canadian dollar improving approximately 20% quarter-over-quarter compared to the pound sterling.

Exploration expense in the first quarter of 2017 increased due to additional charges associated with drilling at the Shelburne Basin off the east coast of Canada, which predominantly took place late in 2016.

DD&A expense decreased in the first quarter of 2017, compared to the prior year quarter, primarily due to lower depletion rates at Buzzard, partially offset by higher East Coast Canada production.


	Three months ended March 31
($ millions)	2017		2016

Operating revenues	4 653		3 591

Net earnings	829		241

Adjusted for:

Gain on significant disposal⁽¹⁾	(354	)	—

Operating earnings⁽²⁾	475		241

Refining and Supply	*394*		175

Marketing	81		66

Funds from operations⁽²⁾	575		404

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

Refining and Supply operating earnings were $394 million in the first quarter of 2017, compared to $175 million in the prior year quarter. The increase was primarily due to realizing a FIFO gain, as compared to a FIFO loss in the prior year period, improved benchmark refining crack spreads and an increase in refinery crude throughput and sales, partially offset by decreased product location differentials and narrower crude differentials.

Marketing activities contributed $81 million to operating earnings in the first quarter of 2017, compared to $66 million in the prior year quarter, with the improvement attributed to stronger wholesale margins and volumes in Western North America and improved retail margins.

During the quarter, Suncor completed the sale of its Petro-Canada lubricants business, which contributed $8 million in net earnings and $11 million in funds from operations in the first quarter of 2017, compared to $13 million in net earnings and $28 million in funds from operations in the prior year quarter.


	Three months ended March 31
	2017	2016

Crude oil processed (mbbls/d)

Eastern North America	214.6	212.1

Western North America	215.3	208.8

Total	429.9	420.9

Refinery utilization⁽¹⁾ (%)

Eastern North America	97	96

Western North America	90	87

Total	93	91

Refined product sales (mbbls/d)

Gasoline	229.9	230.2

Distillate	192.3	172.1

Other	85.8	87.2

Total	508.0	489.5

Refining margin⁽²⁾ ($/bbl)	22.30	19.10

Refining operating expense⁽²⁾ ($/bbl)	5.50	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 MD&A.

Refinery crude throughput in the first quarter of 2017 was 429,900 bbls/d, compared to 420,900 bbls/d in the prior year quarter. In Eastern North America, the volume of crude oil processed in the first quarter of 2017 was similar to the prior year quarter due to solid reliability in both periods. The average volume of crude oil processed in Western North America increased to 215,300 bbls/d in the first quarter of 2017 from 208,800 bbls/d in the prior year quarter, primarily due to higher throughput at Edmonton attributed to improved asset performance, partially offset by decreased production at Commerce City associated with a third-party power outage. The first quarter of 2016 was impacted by planned maintenance at Commerce City.

Total refined product sales of 508,000 bbls/d in the first quarter of 2017 increased from 489,500 bbls/d in the prior year quarter due to increased wholesale volumes associated with improvements in the Western North America market.

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

Marketing margins in the first quarter of 2017, excluding the impact of the sale of the lubricants business partway through the first quarter of 2017, were higher than margins in the prior year quarter, primarily due to improved wholesale and retail margins.

Operating expenses in the first quarter of 2017 were higher than the prior year quarter, after removing the impact of the lubricants sale, due to higher commodity prices and volumes and an increase in refinery maintenance, as reflected in the increase to refinery operating costs per barrel over the prior quarter.

The Montreal refinery has a planned maintenance event scheduled to commence in the second quarter of 2017. The impact of this maintenance has been reflected in the company's 2017 guidance.


	Three months ended March 31
($ millions)	2017		2016

Net earnings	49		574

Adjusted for:

Unrealized foreign exchange gain on U.S. dollar denominated debt	(103	)	(885	)

Gain on significant disposal⁽¹⁾	(83	)	—

Non-cash mark to market loss on interest rate swaps and foreign currency derivatives⁽²⁾	—		90

COS acquisition and related costs⁽³⁾	—		38

Operating (loss) earnings⁽⁴⁾	(137	)	(183	)

Renewable Energy	(2	)	10

Energy Trading	*(11*	)	(2	)

Corporate	*(140*	)	(226	)

Eliminations	16		35

Funds used in operations⁽⁴⁾	(141	)	(246	)

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

Renewable Energy had an operating loss of $2 million in the first quarter of 2017, compared to operating earnings of $10 million in the prior year quarter. The decrease is due to an impairment charge associated with one of the company's wind facilities, as well as the decrease in production associated with the sale of the company's interest in the Cedar Point wind facility, which was effective January 1, 2017.

Energy Trading's operating loss was $11 million in the quarter, compared to an operating loss of $2 million in the prior year quarter, due to narrow crude differentials and volatile crude pricing in the period. Natural gas trading continued to positively impact earnings in the first quarter of 2017, with prices increasing throughout the quarter.

The Corporate operating loss was $140 million for the first quarter of 2017, compared to an operating loss of $226 million for the prior year quarter, primarily due to a decrease in functional costs attributed to the company's continued cost reduction efforts, a realized gain on forward interest rate swaps, higher capitalized interest and lower share-based compensation expense. The company capitalized $174 million of its borrowing costs in the first quarter of 2017 as part of the cost of major development assets and construction projects in progress, compared to $141 million in the prior year quarter.

Eliminations reflect the elimination of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Supply. Consolidated profits are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the first quarter of 2017, the company realized $16 million of after-tax intersegment profit, compared to $35 million of after-tax intersegment profit that was realized in the prior year quarter, with the decrease attributed to improved profit margins, partially offset by a decline in intersegment inventory levels.


	Three months ended March 31
($ millions)	2017		2016

Oil Sands	1 059		1 107

Exploration and Production	227		271

Refining and Marketing	92		172

Corporate, Energy Trading and Eliminations	2		6

Total capital and exploration expenditures	1 380		1 556

Less: capitalized interest on debt	(174	)	(141	)

	1 206		1 415


	Three months ended March 31, 2017
($ millions)	Sustaining(2)	Growth(3)	Total

Oil Sands

Oil Sands Base	183	69	*252*

In Situ	54	6	60

Oil Sands ventures	65	555	*620*

Exploration and Production	3	177	180

Refining and Marketing	92	—	92

Corporate, Energy Trading and Eliminations	2	—	2

	399	807	1 206

(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 operations and R&M operations.
(3): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands operations and R&M operations; ii) new facilities or operations that increase overall production; iii) new infrastructure that is required to support higher production levels; iv) new reserves or a positive change in the company's reserves profile in E&P operations; or v) margin improvement, by increasing revenues or reducing costs.

In the first quarter of 2017, total capital and exploration expenditures were $1.206 billion (excluding capitalized interest). Capital and exploration expenditures in the first quarter of 2017 decreased relative to the prior year quarter due to the company's disciplined execution of its capital program, lower planned maintenance activities at R&M and decreased expenditures at Fort Hills following peak construction activity in 2016 and the start of the staged handover to operations. Suncor's share of capital expenditures at Syncrude increased as a result of additional working interests acquired in 2016. Activity in the first quarter of 2017 is summarized by business unit below.

Oil Sands Base capital and exploration expenditures were $252 million in the first quarter of 2017, the majority of which was directed towards sustaining activities. Sustaining capital included preliminary planning activities associated with Upgrader 2 maintenance, scheduled for completion in the second quarter of 2017. Capital expenditures also included various reliability and sustainment projects across the operations. Growth capital at Oil Sands Base was focused on the East Tank Farm Development, which will support market access for Fort Hills' bitumen production.

In Situ capital and exploration expenditures were $60 million, of which $54 million was directed towards sustaining activities, including ongoing well pad construction that is expected to maintain existing production levels at Firebag and MacKay River, as well as preliminary planning activities related to a turnaround at Firebag scheduled for completion in the second quarter of 2017.

Oil Sands ventures capital and exploration expenditures were $620 million, of which growth capital expenditures were $555 million and sustaining capital expenditures were $65 million. Growth capital was primarily for the Fort Hills mining project, with the project now more than 80% complete. Significant milestones were achieved in the period, including the handover of the mining, ore processing plant and key infrastructure assets to operations. Activity in the quarter also included readying primary extraction for handover to operations and continued development of the secondary extraction facilities.

Sustaining capital expenditures at Fort Hills included continued development of assets that will support the mine plan following the commencement of production.

The first quarter of 2017 included an increased share of Syncrude sustaining capital, which was primarily focused on maintaining assets and executing the mine-tailings plan, including advancement of the upgrader turnaround originally scheduled for the second quarter of 2017.

Significant progress continued on the Hebron project in the first quarter of 2017, with the completed platform ready to be towed out to the final site in the second quarter. First oil from the project continues to be on track for late 2017. Growth capital at E&P also included development drilling at Hibernia and White Rose.

R&M capital expenditures were $92 million and were primarily related to ongoing sustainment of operations and enhancements to retail operations, including information technology upgrades.

Corporate capital expenditures were $2 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended March 31
	2017	2016

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	4.4	(2.2	)

Including major projects in progress	3.5	(1.9	)

Net debt to funds from operations⁽²⁾ (times)	1.8	2.5

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	2.2	(1.0	)

Funds from operations basis⁽²⁾⁽⁴⁾	8.4	7.9

(1): Non-GAAP financial measure. ROCE is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Funds from operations and metrics that use funds from operations are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(4): Funds from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, available lines of credit and the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2017 capital spending program of $4.8 to $5.2 billion and to meet current and future working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, divesting of non-core assets and accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

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

Cash and cash equivalents increased to $3.577 billion during the first three months of 2017 from $3.016 billion at December 31, 2016, primarily due to proceeds from the sale of the company's lubricants business and its interest in the Cedar Point wind facility, and funds from operations exceeding capital and exploration expenditures and dividend requirements, partially offset by the repayment of $511 million in short-term indebtedness and changes in non-cash working capital.

As at March 31, 2017, the weighted average term to maturity of the short-term investment portfolio was approximately 14 days.

Available lines of credit at March 31, 2017 decreased to $7.014 billion, compared to $7.467 billion at December 31, 2016, as a result of the cancellation of a $950 million credit facility that was acquired through the acquisition of COS, partially offset by the $511 million in repayment of short-term indebtedness. As capital spending on major growth projects starts to ramp down, the company has determined that the cancelled credit facility will no longer be required for liquidity purposes and the termination will reduce future financing expense.

Management of debt levels continues to be a priority for Suncor given the company's long-term growth plans and the current pricing environment. Suncor believes a phased and flexible approach to existing and future growth projects should assist the company in maintaining its ability to manage project costs and debt levels.

Subsequent to the first quarter of 2017, Suncor repaid US$1.25 billion 6.10% of notes originally scheduled to mature June 1, 2018. 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 March 31, 2017, total debt to total debt plus shareholders' equity was 27.0% (December 31, 2016 – 28.1%). The company is currently in compliance with all operating covenants.


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


Short-term debt	748	1 273

Current portion of long-term debt	54	54

Long-term debt	15 991	16 103

Total debt	16 793	17 430

Less: Cash and cash equivalents	3 577	3 016

Net debt	13 216	14 414

Shareholders' equity	45 516	44 630

Total debt plus shareholders' equity	62 309	62 060

Total debt to total debt plus shareholders' equity (%)	27.0	28.1

The company's debt position improved in the first quarter due to repayment of $511 million in short-term debt combined with the impact of favourable foreign exchange rates on U.S. dollar denominated debt. The increase in cash and cash equivalents noted above further improved the company's net debt position in the first quarter of 2017.

As at April 21, 2017, the total number of common shares outstanding was 1,669,326,509 and the total number of exercisable and non-exercisable common share options outstanding was 36,179,293. Once exercisable, each outstanding common share option is convertible into one common share.

Subsequent to March 31, 2017, the Toronto Stock Exchange (TSX) accepted a notice filed by Suncor of its intention to commence a normal course issuer bid (the NCIB) to purchase shares through the facilities of the TSX, New York Stock Exchange and/or alternative trading platforms. The notice provides that Suncor may purchase for cancellation up to $2.0 billion worth of its common shares beginning May 2, 2017 and ending May 1, 2018. Pursuant to the NCIB, Suncor has agreed that it will not purchase more than 50,079,795 common shares, which is equal to approximately 3% of Suncor's issued and outstanding common shares.

Suncor has not purchased any of its shares pursuant to a normal course issuer bid within the past twelve months. Suncor security holders may obtain a copy of the notice, without charge, by contacting the company.

Contractual Obligations, Commitments, Guarantees, and Off-Balance Sheet Arrangements

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of its 2016 annual MD&A and has provided an update below. The company does not believe that it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial performance or financial condition, results of operations, liquidity or capital expenditures.

During the three months ended March 31, 2017, the company decreased its commitments by approximately $600 million (undiscounted), which is related to the repayment of short-term indebtedness in the first quarter of 2017 and the reduction in commitments associated with the disposal of Suncor's lubricants business and its interest in the Cedar Point wind facility.

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 in the first quarter of 2017.


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

Total production (mboe/d)

Oil Sands	590.6	620.4		617.5		213.1		565.8		470.6		458.4		448.7

Exploration and Production	134.5	118.1		110.6		117.6		125.6		112.3		107.7		111.2

	725.1	738.5		728.1		330.7		691.4		582.9		566.1		559.9

Revenues and other income

Operating revenues, net of royalties	7 818	7 840		7 409		5 914		5 644		6 499		7 485		8 095

Other income (loss)	25	301		(15	)	(58	)	(67	)	94		72		49

	7 843	8 141		7 394		5 856		5 577		6 593		7 557		8 144

Net earnings (loss)	1 352	531		392		(735	)	257		(2 007	)	(376	)	729

per common share – basic (dollars)	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50

per common share – diluted (dollars)	0.81	0.32		0.24		(0.46	)	0.17		(1.38	)	(0.26	)	0.50

Operating earnings (loss)⁽¹⁾	812	636		346		(565	)	(500	)	(26	)	410		906

per common share – basic⁽¹⁾ (dollars)	0.49	0.38		0.21		(0.36	)	(0.33	)	(0.02	)	0.28		0.63

Funds from operations⁽¹⁾	2 024	2 365		2 025		916		682		1 294		1 882		2 155

per common share – basic⁽¹⁾ (dollars)	1.21	1.42		1.22		0.58		0.45		0.90		1.30		1.49

Cash flow provided by operating activities	1 628	2 791		1 979		862		48		1 443		2 771		1 794

per common share – basic (dollars)	0.98	1.68		1.19		0.54		0.03		1.00		1.92		1.24

ROCE⁽¹⁾ (%) for the twelve months ended	4.4	0.5		(4.6	)	(4.9	)	(2.2	)	0.6		5.1		7.2

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	103	(222	)	(112	)	(27	)	885		(382	)	(786	)	178

Common share information (dollars)

Dividend per common share	0.32	0.29		0.29		0.29		0.29		0.29		0.29		0.28

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	40.83	43.90		36.42		35.84		36.17		35.72		35.69		34.40

New York Stock Exchange (US$)	30.75	32.69		27.78		27.73		27.81		25.80		26.72		27.52

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


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

WTI crude oil at Cushing	US$/bbl	51.85	49.35	44.95	45.60	33.50	42.15	46.45	57.95

Dated Brent crude	US$/bbl	53.75	49.50	45.85	45.60	33.90	43.70	50.30	61.95

Dated Brent/Maya FOB price differential	US$/bbl	9.05	6.70	6.80	7.65	8.95	10.35	8.50	8.15

MSW at Edmonton	Cdn$/bbl	64.25	62.00	55.10	55.80	34.50	53.55	56.55	68.05

WCS at Hardisty	US$/bbl	37.30	35.00	31.45	32.30	19.30	27.70	33.25	46.35

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.55	14.35	13.50	13.30	14.25	14.50	13.20	11.60

Condensate at Edmonton	US$/bbl	52.20	48.35	43.05	44.10	34.45	41.65	44.20	57.95

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.70	3.10	2.30	1.40	1.85	2.45	2.90	2.55

Alberta Power Pool Price	Cdn$/MWh	22.40	21.95	17.90	14.90	18.10	21.20	26.05	57.25

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	12.55	14.35	14.00	16.10	11.75	13.60	22.25	23.85

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	11.15	10.55	14.15	16.65	9.10	13.90	23.95	20.30

Portland 3-2-1 crack⁽¹⁾	US$/bbl	18.45	14.95	18.75	19.30	13.00	17.90	28.75	32.55

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	14.00	13.15	14.50	14.85	11.05	11.05	21.55	22.90

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

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

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

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

charges of $290 million were recorded on the company's interest in the Joslyn mining project and $54 million on the Ballicatters well, due to uncertainty in the timing and likelihood of development plans, and $96 million in Oil Sands following a review of certain assets that no longer fit with Suncor's growth strategies and which could not be repurposed or otherwise deployed.

Suncor's significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor's 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 12 to the unaudited interim Consolidated Financial Statements for the three months ended March 31, 2017, and the Financial Condition and Liquidity section of Suncor's 2016 annual MD&A.

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

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

Based on their evaluation as at March 31, 2017, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at March 31, 2017, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three-month period ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

Based on their inherent limitations, disclosure controls and procedures and internal control over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Suncor has updated its previously issued 2017 corporate guidance, as set forth in Suncor's press release dated April 26, 2017, which is also available on www.sedar.com.

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

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

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

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

The company presents two ROCE calculations – one including and one excluding the impacts on capital employed of major projects in progress. Major projects in progress includes accumulated capital expenditures and capitalized interest for significant projects still under construction or in the process of being commissioned, and acquired assets that are still being evaluated. Management uses ROCE excluding the impacts of major projects in progress on capital employed to assess performance of operating assets.


For the twelve months ended March 31 ($ millions, except as noted)		2017	2016

Adjustments to net earnings

Net earnings (loss)		1 540	(1 408	)

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		258	104

Net interest expense		278	309

	A	2 076	(995	)

Capital employed – beginning of twelve-month period

Net debt		14 880	9 522

Shareholders' equity		42 935	41 272

		57 815	50 794

Capital employed – end of twelve-month period

Net debt		13 216	14 880

Shareholders' equity		45 516	42 935

		58 732	57 815

Average capital employed	B	58 789	52 289

ROCE – including major projects in progress (%)	A/B	3.5	(1.9	)

Average capitalized costs related to major projects in progress	C	11 018	7 871

ROCE – excluding major projects in progress (%)	A/(B–C)	4.4	(2.2	)

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

Funds from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the funds from (used in) operations for the particular quarter ended March 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 for the applicable 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)	302		(524	)	172		(34	)	829		241		49		574		1 352		257

Adjustments for:

Depreciation, depletion, amortization and impairment	941		917		284		356		160		170		37		29		1 422		1 472

Deferred income taxes	9		(36	)	(59	)	(73	)	(9	)	(9	)	47		53		(12	)	(65	)

Accretion of liabilities	49		45		10		17		2		2		—		—		61		64

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(109	)	(921	)	(109	)	(921	)

Change in fair value of financial instruments and trading inventory	(7	)	12		—		—		(10	)	34		27		93		10		139

Gain on disposal of assets	(1	)	(1	)	—		—		(349	)	—		(70	)	—		(420	)	(1	)

Share-based compensation	(86	)	(51	)	(3	)	2		(38	)	(31	)	(123	)	(83	)	(250	)	(163	)

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

Settlement of decommissioning and restoration liabilities	(118	)	(119	)	(1	)	—		(1	)	(2	)	—		(1	)	(120	)	(122	)

Other	20		20		37		(7	)	(9	)	(1	)	1		10		49		22

Funds from (used in) operations	1 109		263		481		261		575		404		(141	)	(246	)	2 024		682

Decrease (increase) in non-cash working capital	449		(296	)	(112	)	(196	)	(101	)	(34	)	(632	)	(108	)	(396	)	(634	)

Cash flow provided by (used in) operating activities	1 558		(33	)	369		65		474		370		(773	)	(354	)	1 628		48

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

Oil Sands operations and Syncrude cash operating costs are non-GAAP financial measures. Oil Sands operations cash operating costs are calculated by adjusting Oil Sands segment OS&G expense (a GAAP measure based on sales volumes) for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the

production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, research, and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenues; iv) project start-up costs; and v) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes. Syncrude cash operating costs are calculated by adjusting Syncrude OS&G for non-production costs that management believes do not relate to the production performance of Syncrude operations, including, but not limited to, share-based compensation, research and project start-up costs. Oil Sands operations and Syncrude cash operating costs are reconciled in the Segment Results and Analysis – Oil Sands section of this MD&A. Management uses Oil Sands operations and Syncrude cash operating costs to measure Oil Sands operating performance.

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


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

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 401		1 135

Other income	19		11

Non-refining margin	(495	)	(355	)

Refining margin	925		791

Refinery production⁽¹⁾ (mbbls)	41 540		41 415

Refining margin ($/bbl)	22.30		19.10

Refining operating expense reconciliation

Operating, selling and general expense	517		542

Non-refining costs	(288	)	(332	)

Refining operating expense	229		210

Refinery production⁽¹⁾ (mbbls)	41 540		41 415

Refining operating expense ($/bbl)	5.50		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 Inventory Valuation on Refining and Marketing Net Earnings

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

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

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


Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		Q1	Three months ended March 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; capital efficiencies and cost-savings; applicable royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; 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 and information may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may", "future", "potential", "opportunity", "would" and similar expressions. Forward-looking statements in the document include references to:

cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, divesting of non-core assets and accessing capital markets;

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

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

Factors that affect our E&P segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya due to ongoing political unrest and that operations in Syria continue to be impacted by sanctions and political unrest; risks and uncertainties associated with obtaining regulatory and stakeholder approval for exploration and development activities; the potential for disruptions to operations and construction projects as a result of our relationships with labour unions that represent employees at our facilities; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect our R&M segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other

impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of taxes or changes to fees and royalties; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires (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 an oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control; risks associated with land claims and Aboriginal consultation requirements; risks relating to litigation; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

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

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


	Three months ended March 31
($ millions)	2017		2016

Revenues and Other Income

Operating revenues, net of royalties (note 3)	7 818		5 644

Other income (loss) (note 6)	25		(67	)

	7 843		5 577

Expenses

Purchases of crude oil and products	2 478		2 069

Operating, selling and general	2 306		2 349

Transportation	286		289

Depreciation, depletion, amortization and impairment	1 422		1 472

Exploration	52		41

Gain on disposal of assets (notes 14 and 15)	(548	)	(1	)

Financing expenses (income) (note 8)	36		(718	)

	6 032		5 501

Earnings before Income Taxes	1 811		76

Income Taxes (note 9)

Current	471		(116	)

Deferred	(12	)	(65	)

	459		(181	)

Net Earnings	1 352		257

Net Earnings Attributable to:

Common shareholders	1 352		246

Non-controlling interest (note 4)	—		11

	1 352		257

Other Comprehensive Income (Loss)

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	(28	)	(262	)

Items that will not be reclassified to earnings

Actuarial gain on employee retirement benefit plans, net of income taxes	29		—

Other Comprehensive Income (Loss)	1		(262	)

Total Comprehensive Income (Loss)	1 353		(5	)

Per Common Share (dollars) (note 10)

Net earnings – basic and diluted	0.81		0.17

Net earnings – attributable to common shareholders – basic and diluted	0.81		0.16

Cash dividends	0.32		0.29

See accompanying notes to the interim consolidated financial statements.


($ millions)	March 31 2017	December 31 2016

Assets

Current assets

Cash and cash equivalents	3 577	3 016

Accounts receivable	3 274	3 182

Inventories	3 427	3 240

Income taxes receivable	169	376

Assets held for sale (notes 14 and 15)	—	1 205

Total current assets	10 447	11 019

Property, plant and equipment, net	71 500	71 259

Exploration and evaluation	2 043	2 038

Other assets	1 217	1 248

Goodwill and other intangible assets	3 062	3 075

Deferred income taxes	91	63

Total assets	88 360	88 702

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	748	1 273

Current portion of long-term debt	54	54

Accounts payable and accrued liabilities	5 043	5 588

Current portion of provisions	766	781

Income taxes payable	316	224

Liabilities associated with assets held for sale (notes 14 and 15)	—	197

Total current liabilities	6 927	8 117

Long-term debt	15 991	16 103

Other long-term liabilities	1 887	2 067

Provisions (note 13)	6 774	6 542

Deferred income taxes	11 265	11 243

Equity	45 516	44 630

Total liabilities and equity	88 360	88 702

See accompanying notes to the interim consolidated financial statements.


	Three months ended March 31
($ millions)	2017		2016

Operating Activities

Net earnings	1 352		257

Adjustments for:

Depreciation, depletion, amortization and impairment	1 422		1 472

Deferred income taxes	(12	)	(65	)

Accretion	61		64

Unrealized foreign exchange gain on U.S. dollar denominated debt	(109	)	(921	)

Change in fair value of financial instruments and trading inventory	10		139

Gain on disposal of assets (notes 14 and 15)	(420	)	(1	)

Share-based compensation	(250	)	(163	)

Exploration	41		—

Settlement of decommissioning and restoration liabilities	(120	)	(122	)

Other	49		22

Increase in non-cash working capital	(396	)	(634	)

Cash flow provided by operating activities	1 628		48

Investing Activities

Capital and exploration expenditures	(1 380	)	(1 556	)

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

Proceeds from disposal of assets	1 396		159

Other investments	—		(2	)

Increase in non-cash working capital	(61	)	(126	)

Cash flow used in investing activities	(45	)	(1 416	)

Financing Activities

Net change in short-term debt	(511	)	964

Net change in long-term debt	(14	)	36

Issuance of common shares under share option plans	44		7

Dividends paid on common shares	(534	)	(453	)

Cash flow (used in) provided by financing activities	(1 015	)	554

Increase (decrease) in Cash and Cash Equivalents	568		(814	)

Effect of foreign exchange on cash and cash equivalents	(7	)	(101	)

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

Cash and Cash Equivalents at End of Period	3 577		3 134

Supplementary Cash Flow Information

Interest paid	115		86

Income taxes paid	121		131

See accompanying notes to the interim consolidated financial statements.


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

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

Net earnings	—	—		—		11		246		257		—

Foreign currency translation adjustment	—	—		(262	)	—		—		(262	)	—

Total comprehensive (loss) income	—	—		(262	)	11		246		(5	)	—

Issued under share option plans	12	(1	)	—		—		—		11		305

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

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

Share-based compensation	—	17		—		—		—		17		—

Dividends paid on common shares	—	—		—		—		(453	)	(453	)	—

At March 31, 2016	23 930	649		1 003		—		17 353		42 935		1 582 011

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

Net earnings	—	—		—		—		1 352		1 352		—

Foreign currency translation adjustment	—	—		(28	)	—		—		(28	)	—

Actuarial gain on employee retirement benefit plans, net of income taxes of $11	—	—		—		—		29		29		—

Total comprehensive (loss) income	—	—		(28	)	—		1 381		1 353		—

Issued under share option plans	55	(8	)	—		—		—		47		1 301

Share-based compensation	—	20		—		—		—		20		—

Dividends paid on common shares	—	—		—		—		(534	)	(534	)	—

At March 31, 2017	26 997	600		979		—		16 940		45 516		1 669 215

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 April 26, 2017.

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 March 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	2 422		1 585		920		531		4 647		3 579		13		(3	)	8 002		5 692

Intersegment revenues	868		454		—		—		6		12		(874	)	(466	)	—		—

Less: Royalties	(61	)	(19	)	(123	)	(29	)	—		—		—		—		(184	)	(48	)

Operating revenues, net of royalties	3 229		2 020		797		502		4 653		3 591		(861	)	(469	)	7 818		5 644

Other income (loss)	14		33		(33	)	2		19		11		25		(113	)	25		(67	)

	3 243		2 053		764		504		4 672		3 602		(836	)	(582	)	7 843		5 577

Expenses

Purchases of crude oil and products	116		140		—		—		3 252		2 456		(890	)	(527	)	2 478		2 069

Operating, selling and general	1 553		1 435		101		145		517		542		135		227		2 306		2 349

Transportation	189		184		23		23		87		92		(13	)	(10	)	286		289

Depreciation, depletion, amortization and impairment	941		917		284		356		160		170		37		29		1 422		1 472

Exploration	2		30		50		11		—		—		—		—		52		41

Gain on disposal of assets	(1	)	(1	)	—		—		(450	)	—		(97	)	—		(548	)	(1	)

Financing expenses (income)	33		55		17		15		9		11		(23	)	(799	)	36		(718	)

	2 833		2 760		475		550		3 575		3 271		(851	)	(1 080	)	6 032		5 501

Earnings (loss) before Income Taxes	410		(707	)	289		(46	)	1 097		331		15		498		1 811		76

Income Taxes

Current	99		(147	)	176		61		277		99		(81	)	(129	)	471		(116	)

Deferred	9		(36	)	(59	)	(73	)	(9	)	(9	)	47		53		(12	)	(65	)

	108		(183	)	117		(12	)	268		90		(34	)	(76	)	459		(181	)

Net Earnings (Loss)	302		(524	)	172		(34	)	829		241		49		574		1 352		257

Capital and Exploration Expenditures	1 059		1 107		227		271		92		172		2		6		1 380		1 556

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

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

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

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


($ millions)

Cash	109

Accounts receivable	231

Inventory	135

Other assets	105

Property, plant and equipment	9 476

Exploration and evaluation	602

Total assets acquired	10 658

Accounts payable and other liabilities	(375	)

Long-term debt	(2 639	)

Employee future benefits	(323	)

Decommissioning provision	(1 169	)

Deferred income taxes	(1 826	)

Total liabilities assumed	(6 332	)

Net assets of COS	4 326

Non-controlling interest	(1 172	)

Net assets acquired	3 154

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


($ millions)		February 5, 2016

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

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

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

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

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

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

Total Notes		2 089

Credit facility		550

Total long-term debt		2 639

During the second quarter of 2016, the company purchased US$688 million of subsidiary debt acquired through the acquisition of COS. The company also repaid approximately $600 million of the credit facility acquired in the COS transaction.

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

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

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

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

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

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

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


($ millions)

Accounts receivable	8

Inventory	19

Property, plant and equipment	1 330

Exploration and evaluation	82

Total assets acquired	1 439

Accounts payable and other liabilities	(29	)

Employee future benefits	(49	)

Decommissioning provision	(187	)

Deferred income taxes	(228	)

Total liabilities assumed	(493	)

Net assets acquired	946

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

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

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


	Three months ended March 31
($ millions)	2017		2016

Energy trading activities

Gains (losses) recognized in earnings during the period	19		(24	)

(Losses) gains on inventory valuation	(37	)	30

Risk management activities⁽¹⁾	56		(99	)

Investment and interest income	21		18

Change in value of pipeline commitments and other	(34	)	8

	25		(67	)

(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.

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


	Three months ended March 31
($ millions)	2017		2016

Interest on debt	252		254

Capitalized interest	(174	)	(141	)

Interest expense	78		113

Interest on pension and other post-retirement benefits	15		12

Accretion	61		64

Foreign exchange gain on U.S. dollar denominated debt	(109	)	(921	)

Foreign exchange and other	(9	)	14

	36		(718	)


	Three months ended March 31
($ millions)	2017		2016

Net earnings	1 352		257

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	(4	)	—

Net earnings – diluted	1 348		257

Net earnings attributable to common shareholders	1 352		246

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	(4	)	—

Net earnings – diluted attributable to common shareholders	1 348		246

(millions of common shares)

Weighted average number of common shares	1 669		1 516

Dilutive securities:

Effect of share options	4		1

Weighted average number of diluted common shares	1 673		1 517

(dollars per common share)

Basic and diluted earnings per share	0.81		0.17

Basic and diluted earnings per share attributable to common shareholders	0.81		0.16

(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 months ended March 31, 2017.

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

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

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

During the first 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 March 31, 2017, the company had $966 million in outstanding forward swaps. During the first quarter of 2017, swaps with a notional value of $955 million were settled resulting in a realized gain of $35 million. An increase in interest rates of 0.04% during the quarter resulted in an increase in value of $8 million associated with the remaining swaps.

The company also uses foreign exchange forwards to mitigate its exposure to the effect of future foreign exchange movements on future debt issuances or settlements. As at March 31, 2017, the company had $400 million in outstanding foreign exchange forwards.

At March 31, 2017, the carrying value of fixed-term debt accounted for under amortized cost was $15.0 billion (December 31, 2016 – $15.1 billion) and the fair value was $17.3 billion (December 31, 2016 – $17.5 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

A decrease in the credit-adjusted risk-free interest rate to 3.70% (December 31, 2016 – 3.90%) resulted in an increase in the decommissioning and restoration provision of $250 million for the three months ended March 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.

Subsequent to March 31, 2017, the TSX accepted a notice filed by Suncor of its intention to commence a new Normal Course Issuer Bid to purchase and cancel up to $2 billion of the company's shares beginning on May 2, 2017 and ending on May 1, 2018 through the facilities of the TSX, New York Stock Exchange and/or alternative trading platforms.

Subsequent to March 31, 2017, the company also repaid the US$1.25 billion 6.10% notes originally scheduled to mature June 1, 2018.


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

Revenues and other income	7 843		8 141		7 394		5 856		5 577		26 968

Net earnings (loss)

Oil Sands	302		276		162		(1 063	)	(524	)	(1 149	)

Exploration and Production	172		54		144		26		(34	)	190

Refining and Marketing	829		524		436		689		241		1 890

Corporate, Energy Trading and Eliminations	49		(323	)	(350	)	(387	)	574		(486	)

	1 352		531		392		(735	)	257		445

Operating earnings (loss)^(A)

Oil Sands	302		316		162		(1 063	)	(524	)	(1 109	)

Exploration and Production	172		54		(36	)	26		(34	)	10

Refining and Marketing	475		524		436		689		241		1 890

Corporate, Energy Trading and Eliminations	(137	)	(258	)	(216	)	(217	)	(183	)	(874	)

	812		636		346		(565	)	(500	)	(83	)

Funds from (used in) operations^(A)

Oil Sands	1 109		1 372		1 236		(202	)	263		2 669

Exploration and Production	481		385		365		302		261		1 313

Refining and Marketing	575		722		595		885		404		2 606

Corporate, Energy Trading and Eliminations	(141	)	(114	)	(171	)	(69	)	(246	)	(600	)

	2 024		2 365		2 025		916		682		5 988

Per common share

Net earnings (loss) – basic and diluted	0.81		0.32		0.24		(0.46	)	0.17		0.28

Net earnings (loss) attributable to common shareholders – basic and diluted	0.81		0.32		0.24		(0.46	)	0.16		0.27

Operating earnings (loss) – basic^(A)	0.49		0.38		0.21		(0.36	)	(0.33	)	(0.05	)

Cash dividends – basic	0.32		0.29		0.29		0.29		0.29		1.16

Funds from operations – basic^(A)	1.21		1.42		1.22		0.58		0.45		3.72


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

Total Production (mbbls/d)	590.6	620.4	617.5	213.1	565.8	504.9

Oil Sands operations

Production volumes (mbbls/d)

Upgraded product (sweet SCO, sour SCO & diesel)	332.8	324.5	301.1	86.4	322.3	258.9

Non-upgraded bitumen	115.7	108.9	132.6	91.1	130.7	115.9

Oil Sands operations production	448.5	433.4	433.7	177.5	453.0	374.8

Bitumen production (mbbls/d)

Mining	311.1	284.8	295.1	66.8	304.0	238.0

In Situ – Firebag	202.8	204.5	197.6	121.8	199.0	180.8

In Situ – MacKay River	35.6	33.9	26.6	13.1	36.8	27.6

Total bitumen production	549.5	523.2	519.3	201.7	539.8	446.4

Sales (mbbls/d)

Light sweet crude oil	124.9	87.2	100.8	29.0	132.2	87.3

Diesel	30.3	28.4	27.9	3.4	24.8	21.2

Light sour crude oil	176.4	201.5	162.5	76.3	172.7	153.4

Upgraded product (SCO and diesel)	331.6	317.1	291.2	108.7	329.7	261.9

Non-upgraded bitumen	104.9	103.5	123.5	108.1	134.5	117.4

Sales	436.5	420.6	414.7	216.8	464.2	379.3

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

Cash costs	20.15	22.10	20.30	44.55	22.55	24.35

Natural gas	2.40	2.85	1.85	2.25	1.70	2.15

	22.55	24.95	22.15	46.80	24.25	26.50

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

Cash costs	19.95	22.55	19.30	76.65	21.70	25.00

Natural gas	0.60	0.80	0.50	1.15	0.50	0.60

	20.55	23.35	19.80	77.80	22.20	25.60

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

Cash costs	7.00	6.35	7.15	10.75	7.60	7.60

Natural gas	4.00	4.40	3.30	2.20	2.80	3.30

	11.00	10.75	10.45	12.95	10.40	10.90

Syncrude

Sweet SCO production (mbbls/d)	142.1	187.0	183.8	35.6	112.8	130.1

Bitumen production (mbbls/d)	170.0	219.6	210.1	52.5	120.6	151.1

Intermediate sour SCO (mbbls/d)⁽²⁾	140.9	192.6	179.2	42.8	109.0	131.2

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

Cash costs	43.25	31.05	26.50	111.40	30.25	34.60

Natural gas	1.90	1.50	1.15	2.15	1.10	1.35

	45.15	32.55	27.65	113.55	31.35	35.95

(A): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section 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 Operating Netbacks^(A)	Mar 31 2017		Dec 31 2016		Sept 30 2016		Jun 30 2016		Mar 31 2016		Dec 31 2016

Bitumen ($/bbl)

Average price realized	35.03		31.68		26.67		23.90		12.00		23.50

Royalties	(0.54	)	(0.33	)	(0.39	)	(0.24	)	—		(0.23	)

Transportation costs	(6.57	)	(5.52	)	(4.80	)	(5.69	)	(5.57	)	(5.38	)

Net operating expenses	(9.98	)	(9.99	)	(10.73	)	(14.65	)	(9.81	)	(11.25	)

Operating netback	17.94		15.84		10.75		3.32		(3.38	)	6.64

SCO and diesel ($/bbl)

Average price realized	66.38		62.28		56.69		52.58		43.27		53.53

Royalties	(0.59	)	2.74		(0.42	)	(0.33	)	(0.57	)	0.50

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

Net operating expenses – bitumen	(21.01	)	(22.56	)	(20.69	)	(50.90	)	(21.98	)	(24.87	)

Net operating expenses – upgrading	(3.58	)	(4.31	)	(4.34	)	(12.02	)	(5.51	)	(5.38	)

Operating netback	37.22		34.17		28.28		(15.74	)	11.38		20.02

Average Oil Sands operations ($/bbl)

Average price realized	58.84		54.75		47.75		38.28		34.21		44.23

Royalties	(0.58	)	1.99		(0.41	)	(0.29	)	(0.41	)	0.28

Transportation costs	(4.60	)	(4.36	)	(3.51	)	(5.38	)	(4.34	)	(4.26	)

Net operating expenses – bitumen and upgrading	(21.07	)	(22.72	)	(20.77	)	(38.85	)	(22.36	)	(24.37	)

Operating netback	32.59		29.66		23.06		(6.24	)	7.10		15.88

Syncrude ($/bbl)

Average price realized	66.37		64.28		58.62		59.34		44.93		56.91

Royalties	(2.96	)	(4.70	)	(0.26	)	(0.98	)	(0.18	)	(1.90	)

Transportation costs	(0.38	)	(0.35	)	(0.29	)	(1.70	)	(0.86	)	(0.53	)

Net operating expenses – bitumen and upgrading	(39.70	)	(29.18	)	(25.05	)	(102.35	)	(27.75	)	(32.05	)

Operating netback	23.33		30.05		33.02		(45.69	)	16.14		22.43

(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.


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

Total Sales Volumes (mboe/d)	136.8		120.5		103.1		120.4		133.4		119.3

Total Production (mboe/d)	134.5		118.1		110.6		117.6		125.6		117.9

Production Volumes

Exploration and Production Canada

East Coast Canada

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

Hibernia (mbbls/d)	30.3		30.1		28.2		24.6		24.1		26.8

White Rose (mbbls/d)	13.1		10.9		7.5		11.7		13.7		10.9

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

	60.9		60.5		53.1		44.4		53.6		52.9

Exploration and Production International

Buzzard (mboe/d)	49.0		37.5		40.8		52.7		53.4		46.0

Golden Eagle (mboe/d)	20.2		19.0		16.2		20.5		18.6		18.6

United Kingdom (mboe/d)	69.2		56.5		57.0		73.2		72.0		64.6

Libya (mbbls/d)⁽³⁾	4.4		1.1		0.5		—		—		0.4

	73.6		57.6		57.5		73.2		72.0		65.0

Netbacks^(A)

East Coast Canada ($/bbl)

Average price realized	69.75		68.06		61.63		62.39		46.17		59.31

Royalties	(15.94	)	(15.07	)	(10.93	)	(11.06	)	(5.51	)	(10.64	)

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

Operating costs	(9.28	)	(9.52	)	(13.57	)	(14.76	)	(13.72	)	(12.67	)

Operating netback	42.81		41.75		34.80		34.52		25.26		34.09

United Kingdom ($/boe)

Average price realized	67.55		62.63		56.96		55.43		43.02		53.91

Transportation costs	(1.81	)	(1.62	)	(1.69	)	(2.00	)	(1.97	)	(1.84	)

Operating costs	(3.75	)	(7.00	)	(5.29	)	(4.68	)	(5.75	)	(5.62	)

Operating netback	61.99		54.01		49.98		48.75		35.30		46.45

(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.


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

Refined product sales (mbbls/d)	508.0	514.8	548.7	532.5	489.5	521.4

Crude oil processed (mbbls/d)	429.9	427.3	465.6	400.2	420.9	428.6

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

Refining margin ($/bbl)^(A)	22.30	23.00	17.75	21.65	19.10	20.30

Refining operating expense ($/bbl)^(A)	5.50	5.45	4.55	5.40	5.10	5.10

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	112.8	115.5	119.8	117.8	107.8	115.2

Distillate	82.2	79.9	77.8	71.8	75.5	76.3

Total transportation fuel sales	195.0	195.4	197.6	189.6	183.3	191.5

Petrochemicals	15.5	10.1	7.2	7.7	12.0	9.2

Asphalt	12.6	16.8	22.9	15.3	11.9	16.7

Other	34.5	34.4	34.6	39.4	35.4	35.9

Total refined product sales	257.6	256.7	262.3	252.0	242.6	253.3

Crude oil supply and refining

Processed at refineries (mbbls/d)	214.6	204.8	213.5	181.7	212.1	203.1

Utilization of refining capacity (%)	97	92	96	82	96	92

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	117.1	125.8	134.6	133.5	122.4	129.1

Distillate	110.1	106.8	117.4	118.2	96.6	109.8

Total transportation fuel sales	227.2	232.6	252.0	251.7	219.0	238.9

Asphalt	9.2	9.7	16.9	11.7	8.7	11.8

Other	14.0	15.8	17.5	17.1	19.2	17.4

Total refined product sales	250.4	258.1	286.4	280.5	246.9	268.1

Crude oil supply and refining

Processed at refineries (mbbls/d)	215.3	222.5	252.1	218.5	208.8	225.5

Utilization of refining capacity (%)	90	93	105	91	87	94

(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 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	)

Operating, selling and general (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


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

(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 September 30, 2016	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)	Oil Sands Segment


Operating revenues	406		1 562		1 968		999		—	2 967

Other income	3		—		3		—		—	3

Purchases of crude oil and products	(95	)	(24	)	(119	)	(16	)	—	(135	)

Gross realization adjustment⁽⁵⁾	(11	)	(19	)	(30	)	8

Gross realizations	303		1 519		1 822		991

Royalties	(5	)	(11	)	(16	)	(4	)	—	(20	)

Transportation	(55	)	(90	)	(145	)	(14	)	—	(159	)

Transportation adjustment⁽⁶⁾	—		11		11		9

Net transportation expenses	(55	)	(79	)	(134	)	(5	)

OS&G	(145	)	(803	)	(948	)	(474	)	2	(1 420	)

OS&G adjustment⁽⁷⁾	24		132		156		50

Net operating expenses	(121	)	(671	)	(792	)	(424	)

Gross profit	122		758		880		558

Sales volumes (mbbls)	11 368		26 786		38 154		16 906

Operating netback per barrel	10.75		28.28		23.06		33.02


For the quarter ended June 30, 2016	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)	Oil Sands Segment


Operating revenues	427		523		950		210		—	1 160

Other (loss) income	(19	)	1		(18	)	—		—	(18	)

Purchases of crude oil and products	(164	)	(2	)	(166	)	(6	)	—	(172	)

Gross realization adjustment⁽⁵⁾	(8	)	(2	)	(10	)	(12	)

Gross realizations	236		520		756		192

Royalties	(2	)	(4	)	(6	)	(3	)	—	(9	)

Transportation	(56	)	(64	)	(120	)	(26	)	—	(146	)

Transportation adjustment⁽⁶⁾	—		14		14		21

Net transportation expenses	(56	)	(50	)	(106	)	(5	)

OS&G	(175	)	(753	)	(928	)	(364	)	4	(1 288	)

OS&G adjustment⁽⁷⁾	30		131		161		32

Net operating expenses	(145	)	(622	)	(767	)	(332	)

Gross profit	33		(156	)	(123	)	(148	)

Sales volumes (mbbls)	9 839		9 891		19 730		3 235

Operating netback per barrel	3.32		(15.74	)	(6.24	)	(45.69	)

(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 March 31, 2016	Bitumen		SCO and Diesel		Oil Sands Operations		Syncrude		Other(4)	Oil Sands Segment


Operating revenues	226		1 331		1 557		482		—	2 039

Other income	26		6		32		—		1	33

Purchases of crude oil and products	(110	)	(14	)	(124	)	(16	)	—	(140	)

Gross realization adjustment⁽⁵⁾	4		(24	)	(20	)	(5	)

Gross realizations	146		1 299		1 445		461

Royalties	—		(17	)	(17	)	(2	)	—	(19	)

Transportation	(68	)	(115	)	(183	)	(1	)	—	(184	)

Transportation adjustment⁽⁶⁾	—		—		—		(8	)

Net transportation expenses	(68	)	(115	)	(183	)	(9	)

OS&G	(153	)	(978	)	(1 131	)	(334	)	30	(1 435	)

OS&G adjustment⁽⁷⁾	33		153		186		50

Net operating expenses	(120	)	(825	)	(945	)	(284	)

Gross profit	(42	)	342		300		166

Sales volumes (mbbls)	12 241		29 999		42 240		10 268

Operating netback per barrel	(3.38	)	11.38		7.10		16.14


For the year 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

(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 March 31, 2017	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	421		379		120		920

Royalties	—		(87	)	(36	)	(123	)

Transportation	(11	)	(9	)	(3	)	(23	)

OS&G	(28	)	(60	)	(13	)	(101	)

Non-production costs⁽¹⁰⁾	4		10

Gross realizations	386		233

Sales volumes (mboe)	6 228		5 432

Operating netback per barrel	61.99		42.81


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


For the quarter ended September 30, 2016	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	300		246		1		547

Royalties	—		(44	)	—		(44	)

Transportation	(9	)	(9	)	(2	)	(20	)

OS&G	(33	)	(62	)	(12	)	(107	)

Non-production costs⁽¹⁰⁾	4		8

Gross realizations	262		139

Sales volumes (mboe)	5 247		3 987

Operating netback per barrel	49.98		34.80

(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 June 30, 2016	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	370		253		1		624

Royalties	—		(45	)	—		(45	)

Transportation	(13	)	(8	)	(1	)	(22	)

OS&G	(37	)	(68	)	(11	)	(116	)

Non-production costs⁽¹⁰⁾	5		8

Gross realizations	325		140

Sales volumes (mboe)	6 661		4 052

Operating netback per barrel	48.75		34.52


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

Operating revenues	281		246		4		531

Royalties	—		(29	)	—		(29	)

Transportation	(13	)	(9	)	(1	)	(23	)

OS&G	(43	)	(85	)	(17	)	(145	)

Non-production costs⁽¹⁰⁾	6		12

Gross realizations	231		135

Sales volumes (mboe)	6 552		5 315

Operating netback per barrel	35.30		25.26


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

Operating revenues	1 276		1 119		49		2 444

Royalties	—		(201	)	(12	)	(213	)

Transportation	(44	)	(36	)	(6	)	(86	)

OS&G	(151	)	(278	)	(54	)	(483	)

Non-production costs⁽¹⁰⁾	18		39

Gross realizations	1 099		643

Sales volumes (mboe)	23 653		18 849

Operating netback per barrel	46.45		34.09

(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.


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

Gross margin⁽¹¹⁾	1 401		1 580		1 377		1 721		1 135		5 813

Other income	19		(10	)	13		2		11		16

Non-refining margin⁽¹²⁾	(495	)	(592	)	(572	)	(884	)	(355	)	(2 403	)

Refining margin^(A)	925		978		818		839		791		3 426

Refinery production (mbbls)⁽¹³⁾	41 540		42 510		46 119		38 754		41 415		168 798

Refining margin ($/bbl)^(A)	22.30		23.00		17.75		21.65		19.10		20.30

OS&G	517		586		549		526		542		2 203

Non-refining costs⁽¹⁴⁾	(288	)	(355	)	(339	)	(317	)	(332	)	(1 343	)

Refining operating expense^(A)	229		231		210		209		210		860

Refinery production (mbbls)⁽¹³⁾	41 540		42 510		46 119		38 754		41 415		168 798

Refining operating expense ($/bbl)^(A)	5.50		5.45		4.55		5.40		5.10		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. Funds from (used in) operations was previously referred to as cash flow from (used in) operations, with the calculation being unchanged from prior periods. Refining margin, refining operating expense and Syncrude cash operating costs for each 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 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. The remainder of the non-GAAP financial measures not otherwise mentioned in this paragraph are defined and reconciled in Suncor's Management's Discussion and Analysis contained in the 2016 Annual 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.

E&P 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.

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


	Three months ended March 31
Net of transportation costs, but before royalties	2017	2016

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	68.03	44.49

E&P Canada – Natural gas ($/mcfe)	2.48	1.36

E&P International ($/boe)	65.74	41.05


($ millions)	Three months ended March 31, 2017

Total debt – December 31, 2016	17 430

Decrease in short-term debt	(511	)

Foreign exchange on debt, and other	(126	)

Total debt – March 31, 2017	16 793

Less: Cash and cash equivalents – March 31, 2017	3 577

Net debt – March 31, 2017	13 216


(thousands)		March 31, 2017

Common shares		1 669 215

Common share options – exercisable		21 729

Common share options – non-exercisable		14 470




Number of COS common shares tendered (millions)		353.3

Multiplied by share exchange ratio		0.28

Number of Suncor common shares issued (millions)		98.9

Share price on acquisition date		$31.88

Fair value of consideration ($ millions)		3 154


1.	Advisories	5
2.	First Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	24
6.	Financial Condition and Liquidity	26
7.	Quarterly Financial Data	29
8.	Other Items	31
9.	Non-GAAP Financial Measures Advisory	32
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) paid during the period	(9	)	(39	)	(48	)

Gains recognized in earnings during the period (note 6)	19		56		75

Fair value outstanding at March 31, 2017	(26	)	(1	)	(27	)


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

Accounts receivable	23		64		—	87

Accounts payable	(44	)	(70	)	—	(114	)

	(21	)	(6	)	—	(27	)


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

Return on capital employed^(A)

– excluding major projects in progress (%)	4.4	0.5	(4.6	)	(4.9	)	(2.2	)

– including major projects in progress (%)	3.5	0.4	(3.9	)	(4.1	)	(1.9	)


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