Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7) :

The Registrant's Management's Discussion and Analysis for the first quarter ended March 31, 2016, included as Exhibit 99.2 of this Form 6-K, and the Unaudited Consolidated Financial Statements for the first quarter ended March 31, 2016, included as Exhibit 99.3 of this Form 6-K, are each incorporated by reference into and as an exhibit to, as applicable, the Registrant's Registration Statements under the Securities Act of 1933: Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form S-8 (File No. 333-161021), Form S-8 (File No. 333-161029) and Form F-10 (File No. 333-196501).

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Exhibit			Description of Exhibit

	99.1		Report to Shareholders for the first quarter ended March 31, 2016
	99.2		Management's Discussion and Analysis for the first quarter ended March 31, 2016
	99.3		Unaudited Consolidated Financial Statements for the first quarter ended March 31, 2016
	99.4		Certification of the President and Chief Executive Officer
	99.5		Certification of the Executive Vice President and Chief Financial Officer

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 referred to 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 27, 2016 (the MD&A). See also the Advisories section of the MD&A. References to Oil Sands operations production and cash operating costs exclude Suncor's interest in Syncrude's operations.

"Suncor's ability to generate cash flow from operations, combined with the strength of our balance sheet, allowed us to maintain our dividend and continue investing in long-term profitable growth projects, even in the poor price environment we saw in the first quarter," said Steve Williams, president and chief executive officer. "We continue to capitalize on opportunities, such as increasing our investment in the Syncrude asset, to generate long-term value for our shareholders."

Suncor Energy Inc. recorded first quarter 2016 operating losses⁽¹⁾ of $500 million ($0.33 per common share) and cash flow from operations of $682 million ($0.45 per common share), compared to operating earnings⁽¹⁾ and cash flow from operations of $175 million ($0.12 per common share) and $1.475 billion ($1.02 per common share), respectively, in the prior year quarter. This reflected the 31% decline in the WTI benchmark price, a 43% decline in the WCS benchmark price, combined with a wider bitumen to WCS differential, as well as a decrease of approximately 40% in benchmark crack spreads, when compared to the first quarter of 2015. Highlights of the first quarter included record Oil Sands operations production, the lowest Oil Sands operations cash operating costs per barrel achieved since 2007 and overall refinery utilization in excess of 90%.

Net earnings were $257 million ($0.17 per common share) for the first quarter of 2016, compared with a net loss of $341 million ($0.24 per common share) for the prior year quarter. Net earnings for the first quarter of 2016 were impacted by the same factors that influenced operating losses described above and also included the impact of a non-cash after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt of $885 million, compared to an after-tax foreign exchange loss of $940 million in the prior year quarter. Net earnings in the first quarter of 2016 also included $38 million (after-tax) for the COS acquisition and integration costs and $90 million (after tax) of non-cash mark to market losses related to interest rate derivatives for future debt issuance. During the first quarter of 2015, the company recognized a tax recovery of $406 million following a decrease in the tax rate in the United Kingdom (U.K.) on oil and gas profits. The net loss in the prior year quarter also included after-tax restructuring costs of $57 million and after-tax insurance proceeds of $75 million.

Suncor's total upstream production was 691,400 barrels of oil equivalent per day (boe/d) in the first quarter of 2016, compared with 602,400 boe/d in the prior year quarter, with the increase due primarily to an additional 36.74% working interest in Syncrude associated with the COS acquisition on February 5, 2016, and increased Oil Sands operations production.

Oil Sands operations production was 453,000 bbls/d in the first quarter of 2016, compared to 440,400 bbls/d in the prior year quarter, primarily due to increased In Situ production in the first quarter of 2016. Production highlights included 322,300 bbls/d of SCO due to strong upgrader reliability, and record production at both Firebag and MacKay River of 199,000 bbls/d and 36,800 bbls/d, respectively. Oil Sands operations production in the second quarter of 2016 is expected to decrease as a result of a planned turnaround of Upgrader 2, which began at the end of the first quarter of 2016.

Cash operating costs per barrel for Oil Sands operations decreased in the first quarter of 2016 to an average of $24.25/bbl, compared to $28.40/bbl in the prior year quarter, due to lower costs as a result of the company's cost reduction initiatives, increased production and lower natural gas prices.

"Our cost reduction initiatives are continuing to drive efficiencies across our operations" said Williams. "Record Oil Sands operations production and our focus on sustainable cost savings have allowed us to achieve the lowest Oil Sands operations cash operating costs per barrel since 2007."

Suncor's share of Syncrude production increased to an average of 112,800 bbls/d in the first quarter of 2016, compared to prior year quarterly production of 35,200 bbls/d. The increase is predominantly due to the COS acquisition. Quarter-over-quarter production at Syncrude also increased due to higher reliability in the first quarter of 2016, with upgrader utilization increasing to 91%, from 84% in the prior year quarter.

Production volumes in Exploration and Production (E&P) were 125,600 boe/d in the first quarter of 2016, compared to 126,800 boe/d in the prior year quarter, primarily due to natural declines, partially offset by higher production from Golden Eagle.

During the first quarter of 2016, Refining and Marketing began planned maintenance at the Commerce City refinery. Average refinery utilization remained strong at 91% in the first quarter, compared to 95% in the prior year quarter, despite weaker demand and the planned turnaround.

Suncor obtained control of COS on February 5, 2016 by acquiring 72.8% of the outstanding common shares. A further 11.3% of the outstanding shares were acquired on February 22, 2016, with the remaining outstanding COS shares

acquired on March 21, 2016. The COS shares were acquired for consideration of 0.28 of a Suncor share for each COS share, valuing the transaction at $6.9 billion at the time of the acquisition, which included COS debt of $2.6 billion.

Subsequent to the quarter end, Suncor entered into a purchase and sale agreement with Murphy Oil Company Ltd. (Murphy Oil), whereby Suncor would acquire Murphy Oil's 5% interest in the Syncrude oil sands mining and upgrading joint arrangement for $937 million. The acquisition will increase Suncor's working interest in Syncrude to 53.74%. The transaction is subject to regulatory approval and is anticipated to close by the end of the second quarter of 2016.

Suncor is also on track to achieve the $750 million reduction to its original 2016 capital budget, while maintaining steady progress on key growth projects already under construction, including Fort Hills and Hebron.

"We continue to progress our major growth projects which are expected to begin producing at the end of 2017," said Williams. "We also continue to look for opportunities to grow our business through acquisitions, by adding assets that fit strategically at competitive valuations."

Suncor continued to deliver cash returns to shareholders in the first quarter of 2016 through $453 million in dividends, increasing the rate per common share to $0.29, compared to $0.28 per common share in the first quarter of 2015. This represents the 14th consecutive year the company has increased the dividend, period over period.

Oil Sands operations continued to focus on projects that enhance safety, reliability and environmental performance. Spending in the first quarter was directed towards preliminary work on the Upgrader 2 turnaround, ongoing well pad development at Firebag and MacKay River to maintain existing production levels, tailings management projects at Oil Sands Base, and logistic and storage assets which will support market access for Fort Hills bitumen.

The Fort Hills mining project continues to be on schedule with construction activities 55% complete. Key activities during the quarter included procurement of equipment for secondary extraction as well as module fabrication and construction for secondary extraction and utilities. The project is expected to deliver approximately 91,000 bbls/d of bitumen to Suncor's operations, with first oil expected in the fourth quarter of 2017 and 90% of its planned capacity being reached within twelve months thereafter. Spending at Fort Hills also included advancement of certain early-works sustaining activities that are expected to optimize the mine plan following the commencement of production. The first quarter of 2016 also included an increased share of Syncrude sustaining capital, which was focused on tailings management and preliminary work on planned coker maintenance that will be executed in the second quarter of 2016.

Construction of the Hebron project continued in the first quarter of 2016 with first oil expected in late 2017. Suncor's working interest in the Hebron project was reset on January 1, 2016, decreasing from 22.7% to 21.0%, reducing the company's share of estimated production to 31,600 bbls/d, at peak production rates.

Exploration drilling at the deepwater Shelburne Basin offshore Nova Scotia continued in the first quarter of 2016. Growth capital also included development drilling activities at Hibernia and Golden Eagle.


	Three months ended March 31
($ millions)	2016		2015

Net earnings (loss)	257		(341	)

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(885	)	940

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

COS acquisition and integration costs⁽³⁾	38		—

Impact of income tax rate adjustments on deferred income taxes⁽⁴⁾	—		(406	)

Restructuring charges⁽⁵⁾	—		57

Insurance proceeds⁽⁶⁾	—		(75	)

Operating (loss) earnings⁽¹⁾	(500	)	175

(1): Operating (loss) earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash loss on the company's interest rate swaps resulting from a decrease in long-term interest rates and unfavourable foreign exchange.
(3): Transaction and related charges associated with the acquisition of COS.
(4): Adjustments to the company's deferred income taxes resulting from a decrease in the U.K. tax rate on oil and gas profits from the North Sea.
(5): Restructuring charges related to the cost reduction initiatives.
(6): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

Suncor has updated production and assumptions provided for in its 2016 corporate guidance, previously issued on February 3, 2016. The full year outlook range for Syncrude production has been updated from 30,000 - 35,000 bbls/d to 125,000 - 135,000 bbls/d, which reflects the additional 36.74% working interest acquired through the COS acquisition on February 5, 2016, and the full year outlook range for Suncor total production has correspondingly been increased from 525,000 - 565,000 bbls/d to 620,000 - 665,000 bbls/d. In addition, Syncrude cash operating costs of $35.00 - $38.00/bbl have been included in the company's 2016 full year outlook. The capital spending outlook of $6.0 - $6.5 billion for 2016 includes approximately $250 million for Suncor's incremental 36.74% ownership of Syncrude.

The following 2016 full year outlook assumptions have also been adjusted: East Coast Canada Royalties to 14% - 18% from 19% - 23%, New York Harbor 3-2-1 crack spread to US$12.50/bbl from US15.00/bbl, AECO - C Spot to $1.75/GJ from $2.50/GJ and the US$/Cdn$ exchange rate to 0.75 from 0.70. For further details and advisories regarding Suncor's 2016 revised corporate guidance, see www.suncor.com/guidance.

Certain natural gas volumes in this report to shareholders have been converted to boe on the basis of one bbl to six mcf. See the Advisories section of 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, 2015, dated, February 25, 2016 (the 2015 annual MD&A). References to Exploration and Production (E&P) Canada include Suncor's offshore operations in East Coast Canada and onshore operations in North America Onshore. References to E&P International include the properties formerly referred to as International.

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, 2016, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2015 and the 2015 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated February 25, 2016 (the 2015 AIF), which is also filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form part of this document, and is not incorporated into this document by reference.

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

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

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

Certain financial measures in this MD&A – namely operating (loss) earnings, cash flow from operations, return on capital employed (ROCE), Oil Sands cash operating costs, free cash flow, and last-in, first-out (LIFO) – are not prescribed by GAAP. Operating (loss) earnings, Oil Sands operations cash operating costs and LIFO are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Cash flow from operations, ROCE and free cash flow are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of this MD&A.

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

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

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


	Three months ended March 31
($ millions)	2016		2015

Net (loss) earnings

Oil Sands	(524	)	(146	)

Exploration and Production	(34	)	462

Refining and Marketing	241		498

Corporate, Energy Trading and Eliminations	574		(1 155	)

Total	257		(341	)

Operating (loss) earnings⁽¹⁾

Oil Sands	(524	)	(146	)

Exploration and Production	(34	)	(19	)

Refining and Marketing	241		498

Corporate, Energy Trading and Eliminations	(183	)	(158	)

Total	(500	)	175

Cash flow from (used in) operations⁽¹⁾

Oil Sands	263		525

Exploration and Production	261		449

Refining and Marketing	404		686

Corporate, Energy Trading and Eliminations	(246	)	(185	)

Total	682		1 475

Capital and Exploration Expenditures⁽²⁾

Sustaining	471		377

Growth	944		856

Total	1 415		1 233


	Three months ended March 31
	2016	2015

Production volumes by segment

Oil Sands (mbbls/d)	565.8	475.6

Exploration and Production (mboe/d)	125.6	126.8

Total	691.4	602.4

Production mix

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

Refinery utilization (%)	91	95

Refinery crude oil processed (mbbls/d)	420.9	437.1

Suncor's consolidated net earnings for the first quarter of 2016 were $257 million, compared with a net loss of $341 million for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating (loss) 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)	2016		2015

Net earnings (loss)	257		(341	)

Unrealized foreign exchange(gain) loss on U.S. dollar denominated debt	(885	)	940

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

COS acquisition and integration costs⁽³⁾	38		—

Impact of income tax rate adjustments on deferred income taxes⁽⁴⁾	—		(406	)

Restructuring charges⁽⁵⁾	—		57

Insurance proceeds⁽⁶⁾	—		(75	)

Operating (loss) earnings⁽¹⁾	(500	)	175

(1): Operating (loss) earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash loss on the company's interest rate swaps resulting from a decrease in long-term interest rates and unfavourable foreign exchange.
(3): Transaction and related charges associated with the acquisition of COS.
(4): Adjustments to the company's deferred income taxes resulting from a decrease in the U.K. tax rate on oil and gas profits from the North Sea.
(5): Restructuring charges related to the cost reduction initiatives.
(6): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

Suncor's consolidated operating loss for the first quarter of 2016 was $500 million, compared to operating earnings of $175 million for the prior year quarter. The quarter-over-quarter decrease is due to declines in upstream price realizations on lower benchmark pricing, a less favourable downstream business environment and the impact of adding $164 million of after-tax operating expenses associated with the increased working interest in Syncrude following the COS acquisition, partially offset by the impacts of weaker exchange rates on price realizations, increased production from Syncrude, $120 million lower companywide operating costs, when removing the impact of the COS acquisition, and lower royalties resulting from the decrease in crude oil prices.

During the first quarter of 2016, annual share-based compensation cash payments were $292 million, compared to $267 million in the prior year quarter.

Consolidated cash flow from operations was $682 million for the first quarter of 2016, compared to $1.475 billion for the prior year quarter. Cash flow from operations was impacted by the same factors that affected operating (loss) earnings discussed above.

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
		2016	2015

WTI crude oil at Cushing	US$/bbl	33.50	48.65

Dated Brent crude oil at Sullom Voe	US$/bbl	33.90	53.85

Dated Brent/Maya crude oil FOB price differential	US$/bbl	8.95	11.05

MSW at Edmonton	Cdn$/bbl	34.50	52.25

WCS at Hardisty	US$/bbl	19.30	33.90

Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.25	14.75

Condensate at Edmonton	US$/bbl	34.45	45.60

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.85	2.75

Alberta Power Pool Price	Cdn$/MWh	18.10	29.15

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	11.75	19.20

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	9.10	16.00

Portland 3-2-1 crack⁽¹⁾	US$/bbl	13.00	21.50

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	11.05	18.00

Exchange rate	US$/Cdn$	0.73	0.81

Exchange rate (end of period)	US$/Cdn$	0.77	0.79

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

Suncor's 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 2016 for sweet SCO were negatively impacted by a lower price for WTI of US$33.50/bbl, compared to US$48.65/bbl in the prior year quarter.

Suncor produces a specific grade of sour SCO, the price realizations for which are 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 and WCS at Hardisty decreased in the first quarter of 2016 to $34.50/bbl and US$19.30/bbl, respectively, compared to $52.25/bbl and US$33.90/bbl, respectively, in the prior year quarter, resulting in lower price realizations for sour SCO.

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

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing decreased to an average of US$33.90/bbl in the first quarter of 2016, compared to US$53.85/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $1.85/mcf in the first quarter of 2016, from $2.75/mcf in the prior year quarter.

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

Excess electricity produced in Suncor's In Situ business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $18.10/MWh in the first quarter of 2016 from $29.15/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities is based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In the first quarter of 2016, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to US$0.73 per one Canadian dollar from US$0.81 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the first quarter of 2016 but only partially offset declining benchmark crude oil prices.

Suncor also has assets and liabilities, notably most of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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)	2016		2015

Gross revenues	2 039		2 284

Less: Royalties	(19	)	(18	)

Operating revenues, net of royalties	2 020		2 266

Net (loss) earnings	(524	)	(146	)

Operating (loss) earnings⁽¹⁾	(524	)	(146	)

Oil Sands operations	*(517*	)	(131	)

Oil Sands ventures	(7	)	(15	)

Cash flow from operations⁽¹⁾	263		525

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

Operating losses for Oil Sands operations were $517 million, compared to operating losses of $131 million in the prior year quarter. Operating losses increased primarily due to lower price realizations, partially offset by lower operating costs and higher production volumes in the first quarter of 2016.

Operating losses for Oil Sands ventures were $7 million, compared to operating losses of $15 million in the prior year quarter, and decreased primarily due to higher production volumes associated with the increased working interest in Syncrude, partially offset by lower price realizations and $164 million in additional after-tax operating expenses associated with the increased production from the acquisition of COS.


	Three months ended March 31
(mbbls/d)	2016	2015

Upgraded product (SCO and diesel)	322.3	346.5

Non-upgraded bitumen	130.7	93.9

Oil Sands operations	453.0	440.4

Oil Sands ventures – Syncrude	112.8	35.2

Total	565.8	475.6

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


	Three months ended March 31
(mbbls/d)	2016	2015

Oil Sands sales volumes

Sweet SCO	132.2	112.5

Diesel	24.8	30.8

Sour SCO	172.7	201.3

Upgraded product	329.7	344.6

Non-upgraded bitumen	134.5	95.8

Oil Sands operations	464.2	440.4

Oil Sands ventures – Syncrude	112.8	35.2

Total	577.0	475.6

Production volumes for Oil Sands operations increased to an average of 453,000 bbls/d in the first quarter of 2016, compared to 440,400 bbls/d in the prior year quarter. The increase was driven primarily by improved production at both Firebag and MacKay River. SCO production in the first quarter of 2016 was down from 346,500 bbls/d in the first quarter of 2015 to 322,300 bbls/d, due to higher planned and unplanned maintenance in the period. The SCO mix in the first quarter of 2016 reflected higher sweet SCO production due to less unplanned maintenance in secondary upgrading when compared to the first quarter of 2015, which included unplanned hydrotreater maintenance.

Sales volumes for Oil Sands operations increased to an average of 464,200 bbls/d in the first quarter of 2016, up from 440,400 bbls/d in the prior year quarter, due to higher production volumes.

Inventory levels in the first quarter of 2016 decreased compared to minimal change to inventory levels in the prior year quarter.

Suncor's share of Syncrude production increased to an average of 112,800 bbls/d in the first quarter of 2016 compared to the prior year quarter production of 35,200 bbls/d. The increase is primarily due to the additional 36.74% working interest obtained through the acquisition of COS on February 5, 2016. Quarter-over-quarter production also increased as a result of improved reliability in the first quarter of 2016, with upgrader utilization improving to 91%, from 84% in the prior year quarter. A planned upgrader turnaround at Syncrude commenced at the start of the second quarter of 2016 and is expected to last approximately seven weeks, with the impact being reflected in the company's revised 2016 guidance.


	Three months ended March 31
	2016	2015

Oil Sands Base

Bitumen production (mbbls/d)	304.0	318.3

Bitumen ore mined (thousands of tonnes per day)	449.4	466.1

Bitumen ore grade quality (bbls/tonne)	0.68	0.68

In Situ

Bitumen production – Firebag (mbbls/d)	199.0	188.7

Bitumen production – MacKay River (mbbls/d)	36.8	29.3

Total In Situ bitumen production	235.8	218.0

Steam-to-oil ratio – Firebag	2.6	2.6

Steam-to-oil ratio – MacKay River	2.8	2.8

Oil Sands Base bitumen production from mining and extraction activities decreased to an average of 304,000 bbls/d in the first quarter of 2016 from 318,300 bbls/d in the prior year quarter. The decrease reflected planned extraction maintenance which began in the period, compared to the first quarter of 2015 which had minimal maintenance.

In Situ bitumen production increased to an average of 235,800 bbls/d in the first quarter of 2016, compared to 218,000 bbls/d in the prior year quarter. The increase was primarily driven by higher Firebag production as a result of debottleneck activities completed in the fourth quarter of 2015 and strong infill well performance. Production at MacKay River increased to 36,800 bbls/d in the first quarter of 2016 from 29,300 bbls/d in the prior year as a result of anticipated production associated with the debottleneck project.

Both Firebag and MacKay River's steam-to-oil ratios were consistent with the prior year quarter, reflecting continued strong reliability and reservoir performance.


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

Oil Sands operations

SCO and diesel	39.44		53.44

Bitumen	6.43		24.01

Crude sales basket (all products)	29.87		47.04

Crude sales basket, relative to WTI	(16.20	)	(13.22	)

Oil Sands ventures

Syncrude – sweet SCO	44.07		55.91

Syncrude, relative to WTI	(2.00	)	(4.35	)

Average price realizations for sales from Oil Sands operations decreased to $29.87/bbl in the first quarter of 2016 from $47.04/bbl in the prior year quarter, primarily due to the lower WTI benchmark price, partially offset by weaker exchange rates. Bitumen realizations of $6.43/bbl in the first quarter of 2016 decreased from $24.01/bbl in the prior year quarter due to wider differentials to the WCS benchmark.

Royalties for the Oil Sands segment were slightly higher in the first quarter of 2016 compared to the prior year quarter, primarily due to higher overall production, partially offset by lower benchmark pricing.

Operating, selling and general and transportation expenses for the first quarter of 2016 increased from the prior year quarter, primarily due to the increased working interest in Syncrude as a result of the acquisition of COS, partially offset by the company's cost reduction initiatives, lower maintenance expense and lower natural gas prices. See the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs for Oil Sands operations. Transportation expense for the first quarter of 2016 was higher than the prior year quarter, primarily due to increased sales volumes.

DD&A expense for the first quarter of 2016 was higher compared to the same period of 2015, mainly due to the increased working interest in Syncrude and a larger asset base primarily as a result of assets commissioned in 2015, including well pads and infill wells. Higher In Situ production in the first quarter of 2016 also contributed to the increase in DD&A expense.


	Three months ended March 31
($ millions)	2016		2015

Oil Sands operations cash operating cost reconciliation

Operating, selling and general expense (OS&G)	1 435		1 372

Syncrude OS&G	(334	)	(114	)

Non-production costs⁽²⁾	(33	)	(39	)

Excess power capacity and other⁽³⁾	(31	)	(68	)

Inventory changes	(38	)	(25	)

Oil Sands operations cash operating costs⁽¹⁾	999		1 126

Oil Sands operations cash operating costs ($/bbl)	24.25		28.40

Syncrude cash operating costs

Syncrude cash operating costs⁽⁴⁾	327		113

Syncrude cash operating costs ($/bbl)	31.35		35.75

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

Cash operating costs per barrel for Oil Sands operations in the first quarter of 2016 decreased to $24.25/bbl compared to $28.40/bbl in the prior year quarter, due to lower total cash operating costs and higher production volumes. Total cash operating costs decreased to $999 million from $1.126 billion in the prior year quarter, primarily due to lower operating and maintenance costs due to the company's cost reduction initiatives, and lower natural gas input costs.

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

Excess power capacity and other costs, which are also excluded from cash operating costs, decreased in the first quarter of 2016 compared to the prior year quarter, primarily due to lower expenses related to a gas swap arrangement with a third-party processor due to lower natural gas prices.

Syncrude cash costs per barrel in the first quarter of 2016 decreased to $31.35 from $35.75 in the previous year quarter due to higher production volumes and lower operating costs. Total cash operating costs increased to $327 million from $113 million in the previous year quarter due to the additional 36.74% working interest obtained through the acquisition of COS, partially offset by reduced operating expenses. Costs associated with the incremental ownership of Syncrude were $224 million in the first quarter of 2016.

As planned every five years, a full turnaround of certain Upgrader 2 assets commenced late in the first quarter of 2016, with the majority of the work to be completed in the second quarter of 2016. The company plans to complete additional major maintenance in upgrading during the third and fourth quarters of 2016.

The impact of these maintenance activities has been reflected in the company's 2016 guidance.

During the first quarter of 2016, the company completed its acquisitions of COS, bringing its ownership interest in Syncrude up to 48.74%.

Subsequent to the quarter end, Suncor also entered into a purchase and sale agreement to acquire Murphy Oil Company Ltd.'s 5% interest in Syncrude for $937 million, subject to closing adjustments. The transaction has an effective date of April 1, 2016 and is expected to close by the end of the second quarter of 2016. Upon closing, Suncor's working interest in Syncrude will increase to 53.74%.


	Three months ended March 31
($ millions)	2016		2015

Gross revenues	531		769

Less: Royalties	(29	)	(126	)

Operating revenues, net of royalties	502		643

Net earnings	(34	)	462

Adjusted for:

Impact of income tax rate adjustments on deferred income taxes⁽¹⁾	—		(406	)

Insurance proceeds	—		(75	)

Operating (loss) earnings⁽²⁾	(34	)	(19	)

E&P Canada	*(19*	)	(33	)

E&P International	*(15*	)	14

Cash flow from operations⁽²⁾	261		449

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

E&P operating loss was $34 million in the first quarter of 2016, compared to an operating loss of $19 million in the prior year quarter.

The operating loss of $19 million for E&P Canada was lower than the operating loss of $33 million in the prior year quarter, primarily due to lower depreciation expense resulting from lower DD&A rates, lower exploration drilling costs and lower royalty expenses, partially offset by lower price realizations and production volumes driven by natural declines at Terra Nova.

The operating loss of $15 million for E&P International compared to operating earnings of $14 million in the prior year quarter, primarily due to lower price realizations and higher depreciation associated with Golden Eagle, partially offset by higher production at Golden Eagle and Buzzard.


	Three months ended March 31
	2016	2015

E&P Canada

Terra Nova (mbbls/d)	12.8	23.3

Hibernia (mbbls/d)	24.1	22.0

White Rose (mbbls/d)	13.7	12.8

North America Onshore (mboe/d)	3.0	3.6

	53.6	61.7

E&P International

Buzzard (mboe/d)	53.4	51.4

Golden Eagle (mboe/d)	18.6	9.8

United Kingdom (mboe/d)	72.0	61.2

Libya (mbbls/d)	—	3.9

	72.0	65.1

Total production (mboe/d)	125.6	126.8

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

E&P Canada production averaged 53,600 boe/d in the first quarter of 2016, compared to 61,700 boe/d in the prior year quarter. The decrease was primarily due to natural declines at Terra Nova, partially offset by higher production at Hibernia and White Rose from field extension projects at the Hibernia Southern Extension Unit and South White Rose Extension in the second half of 2015.

E&P International production averaged 72,000 boe/d in the first quarter of 2016, compared to 65,100 boe/d in the prior year quarter. The increase in production was primarily due to Golden Eagle operating at peak production rates and reliable operations at Buzzard. Production in Libya remains shut-in due to continued political unrest, with the timing of a return to normal operations remaining uncertain.

In the first quarter of 2016, price realizations for crude oil from E&P Canada and E&P International were lower than the prior year quarter, consistent with the decrease in benchmark prices for Brent crude, partially offset by weaker foreign exchange rates.

Royalties for E&P were lower in the first quarter of 2016, compared with the prior year quarter, primarily due to lower price realizations and lower volumes in East Coast Canada.

During the first quarter of 2016, there was an inventory draw compared to minimal change to inventory levels in the prior year quarter.

Operating and transportation expenses decreased in the first quarter of 2016, compared to the prior year quarter, primarily due to cost reduction initiatives.

DD&A and exploration expenses decreased in the first quarter of 2016 compared to the prior year quarter. The first quarter of 2016 had minimal exploration expense compared to the first quarter of 2015, which included a charge for a non-commercial exploration well in East Coast Canada. In addition, DD&A decreased quarter over quarter, with lower depletion rates and production declines in East Coast Canada being partially offset by increased depletion in the U.K. due to increased production.

A planned four-week maintenance event at Terra Nova has been scheduled to commence in the second quarter of 2016. The impact of this maintenance has been reflected in the company's 2016 guidance.


	Three months ended March 31
($ millions)	2016	2015

Operating revenues	3 591	4 830

Net earnings	241	498

Operating earnings⁽¹⁾	241	498

Refining and Supply	*175*	394

Marketing	66	104

Cash flow from operations⁽¹⁾	404	686

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

Refining and Supply had operating earnings of $175 million in the first quarter of 2016, compared to $394 million in the prior year quarter. The decrease in the first quarter of 2016 reflects lower cracking margins, narrower inland crude differentials and lower throughput, partially offset by stronger gasoline location differentials and lower operating expenses. FIFO losses of $192 million in the first quarter of 2016 and $170 million in the first quarter of 2015 were realized on declining crude feedstock pricing.

Marketing activities contributed $66 million to operating earnings in the first quarter of 2016, compared to $104 million in the prior year quarter. The decrease was primarily due to declining lubricant margins and lower distillate volumes and margins in the wholesale channel.


	Three months ended March 31
	2016	2015

Crude oil processed (mbbls/d)

Eastern North America	212.1	212.4

Western North America	208.8	224.7

Total	420.9	437.1

Ethanol production (mbbls/d)	7.3	7.5

Refinery utilization⁽¹⁾ (%)

Eastern North America	96	96

Western North America	87	94

Total	91	95

Refined product sales (mbbls/d)

Gasoline	230.2	237.8

Distillate	172.1	206.2

Other	87.2	75.7

Total	489.5	519.7

Refining gross margin⁽²⁾ ($/bbl)	19.10	28.50

Refining operating expense⁽²⁾ ($/bbl)	5.10	5.40

(1): Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.
(2): Refining gross margin per barrel and Refining operating expense per barrel are presented on the basis of total output from the company's four refineries.

Refinery crude throughput decreased in the first quarter of 2016, resulting in an average refinery utilization of 91%, compared to 95% in the prior year quarter. The average volumes of crude oil processed in Western North America decreased to 208,800 bbls/d in the first quarter of 2016 from 224,700 bbls/d in the prior year quarter, primarily due to lower demand for refined products in Western Canada. Both quarters were impacted by planned maintenance events at Commerce City; however, planned maintenance in the first quarter of 2015 had a smaller impact on throughput volumes. In Eastern North America, the average volume of crude oil processed was 212,100 bbls/d in the first quarter of 2016 and was relatively unchanged from the 212,400 bbls/d processed in the prior year quarter.

Total sales decreased to 489,500 bbls/d in the first quarter of 2016, compared to 519,700 bbls/d in the prior year quarter, primarily due to lower distillate demand, reflecting the weaker economic conditions in Western Canada and warmer weather in Eastern Canada in the first quarter of 2016 compared to the prior year quarter, which impacted heating oil demand.

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

(1) LIFO is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Marketing margins in the first quarter of 2016 were impacted by weaker demand as compared to the first quarter of 2015.

Operating and transportation expenses were lower in the first quarter of 2016 compared to the prior year quarter, primarily due to lower maintenance and marketing expenses, as well as lower energy costs as a result of lower natural gas prices. Refinery operating expenses of $5.10/bbl were 6% below the prior year quarter. DD&A expense increased slightly in the first quarter of 2016 due to asset additions related to planned maintenance events completed since the prior year quarter.

As reflected in the company's 2016 guidance, turnaround maintenance is planned at three of the company's four refineries, including a four-week maintenance event at the Commerce City refinery, a total of 11 weeks of planned maintenance at the Sarnia refinery and a six-week maintenance event at the Montreal refinery.


	Three months ended March 31
($ millions)	2016		2015

Net earnings (loss)	574		(1 155	)

Adjusted for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(885	)	940

Non-cash mark to market loss on interest rate swaps	90		—

COS acquisition and related costs	38		—

Restructuring charges	—		57

Operating loss⁽¹⁾	(183	)	(158	)

Renewable Energy	10		8

Energy Trading	(2	)	57

Corporate	*(226*	)	(257	)

Eliminations	35		34

Cash flow used in operations⁽¹⁾	(246	)	(185	)

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

Renewable Energy had operating earnings of $10 million in the first quarter of 2016, as compared to $8 million in the prior year quarter. The increase was due primarily to the impact of the Cedar Point wind project, which began production in the prior year, partially offset by the disposal of Suncor's interest in the Wintering Hills and Kent Breeze wind projects in the third quarter of 2015.

Energy Trading had an operating loss of $2 million in the quarter, compared to operating earnings of $57 million in the prior year quarter. In the first quarter of 2015, the company experienced higher gains on crude trading strategies as a result of wider crude differentials.

The Corporate operating loss was $226 million for the first quarter of 2016, compared with an operating loss of $257 million for the prior year quarter, primarily as a result of cost reduction initiatives, partially offset by increased interest expense associated with the acquisition of COS debt. The company capitalized $141 million of its borrowing costs in the first quarter of 2016 as part of the cost of major development assets and construction projects in progress, compared to $93 million in the prior year quarter.

Eliminations reflect the inter-company 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 2016, the company realized $35 million of after-tax intersegment profit, compared to $34 million of profit that was recognized in the prior year quarter.


	Three months ended March 31
($ millions)	2016		2015

Oil Sands	1 107		793

Exploration and Production	271		356

Refining and Marketing	172		83

Corporate, Energy Trading and Eliminations	6		94

Total capital and exploration expenditures	1 556		1 326

Less: capitalized interest on debt	(141	)	(93	)

	1 415		1 233


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

Oil Sands

Oil Sands Base	203	110	313

In Situ	55	14	69

Oil Sands Ventures	40	586	*626*

Exploration and Production	2	232	234

Refining and Marketing	166	2	168

Corporate, Energy Trading and Eliminations	5	—	5

	471	944	1 415

(1): Capital expenditures in this table exclude capitalized interest on debt.
(2): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands operations and Refining and Marketing 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 Exploration and Production operations; or v) margin improvement, by increasing revenues or reducing costs.
(3): Sustaining capital expenditures include capital investments that i) ensure compliance or maintain relations with regulators and other stakeholders; ii) improve efficiency and reliability of operations or maintain productive capacity by replacing component assets at the end of their useful lives; iii) deliver existing proved developed reserves for Exploration and Production operations; or iv) maintain current production capacities at existing Oil Sands operations and Refining and Marketing operations.

In the first quarter of 2016, total capital and exploration expenditures were $1.415 billion (excluding capitalized interest). Capital and exploration expenditures in the first quarter of 2016 increased compared to the prior year quarter primarily due to a ramp up in spending at Fort Hills combined with the company's increased working interest obtained in the fourth quarter of 2015. Other factors impacting the increase in capital spending quarter-over-quarter were higher maintenance costs at both Oil Sands and Refining & Marketing, associated with preliminary work on the Upgrader 2 turnaround and planned maintenance at the Commerce City refinery, respectively, partially offset by lower overall development drilling in East Coast Canada and the U.K., and no current exploration drilling activity in Norway. Activity in the first quarter of 2016 included the following:

Oil Sands Base capital and exploration expenditures were $313 million in the first quarter of 2016, of which $203 million and $110 million were directed towards sustaining and growth activities, respectively. Sustaining capital included expenditures related to the planned maintenance program, which commenced at the end of the first quarter of 2016 and is focused on a turnaround of Upgrader 2. In addition, there were a number of reliability and sustainment projects across Oil Sands operations that were executed in the period.

Growth capital was focused on logistical and storage assets designed to support market access for Fort Hills bitumen production.

In Situ capital and exploration expenditures were $69 million, of which $55 million and $14 million were directed towards sustaining and growth activities, respectively. Sustaining capital included ongoing well pad development that is expected to maintain existing production levels at Firebag and MacKay River.

Oil Sands ventures capital and exploration expenditures were $626 million. Growth capital expenditures of $586 million were incurred for development and construction of the Fort Hills project, which was 55% complete at the end of the first quarter of 2016. Spending in the quarter included procurement of material and equipment for secondary extraction as well as module fabrication and construction for secondary extraction and utilities.

Sustaining capital consisted of Suncor's share of capital expenditures for the Syncrude joint venture, which increased in the period as a result of the COS acquisition, and included expenditures on several reliability and sustainment projects, including preliminary work on planned maintenance. Sustaining capital also included accelerated capital associated with projects at Fort Hills that will be required to sustain long-term operations.

E&P capital and exploration expenditures were $234 million, with the majority of spending directed towards growth capital, including the Hebron project. Construction of the gravity-based structure and topsides continued in the first quarter of 2016 at the Hebron project, which remains on schedule with first oil expected in late 2017.

Growth capital in the first quarter of 2016 included exploration drilling activities at the deepwater Shelburne Basin offshore Nova Scotia and ongoing drilling activities at Hibernia and Golden Eagle.

Refining and Marketing capital expenditures of $168 million related primarily to planned maintenance programs at the Commerce City, Sarnia and Montreal refineries, as well as a crude pipeline replacement project which supplies feedstock to the Commerce City refinery.

Corporate capital expenditures were $5 million, with the majority of the spending directed towards the company's information and technology initiatives.


	Twelve months ended March 31
	2016		2015

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	(2.2	)	5.8

Including major projects in progress	(1.9	)	5.0

Net debt to cash flow from operations⁽²⁾ (times)	2.5		1.2

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	(1.0	)	2.7

Cash flow from operations basis⁽²⁾⁽⁴⁾	7.9		12.4

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

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2016 capital spending program of $6.0 to $6.5 billion, which includes the company's increased working interest in the Syncrude project as a result of the acquisition of COS, and to meet current, future and acquired working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities for the remainder of 2016, available committed credit facilities, issuing commercial paper and 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.

Based on Suncor's near-term cash flow projections, which include capital spending on key growth projects, the company anticipates meeting additional cash requirements through a combination of divesting of non-core assets and accessing capital markets, which management believes can be done on competitive terms.

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

Cash and cash equivalents decreased to $3.134 billion during the three months of 2016 from $4.049 billion at December 31, 2015, primarily due to capital and exploration expenditures and changes in non-cash working capital that exceeded cash flow from operations, offset by increases in short-term borrowings.

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

Available lines of credit at March 31, 2016 decreased to $6.752 billion, compared to $7.034 billion at December 31, 2015 primarily as a result of increased short-term borrowing, foreign exchange impacts on available credit facilities and increased letters of credit, offset by $940 million of available credit facilities added through the acquisition of COS. In the first quarter of 2016, a $2 billion fully revolving facility has been amended to a three year facility and now expires in 2019; and $1.15 billion of a $1.6 billion fully revolving facility has been extended by an additional year to 2018.

In the first quarter of 2016, Moody's Investors Service (Moody's) downgraded Suncor's long-term debt to Baa1, with a stable outlook, and Dominion Bond Rating Service affirmed Suncor's A (low) rating, but updated its trend to negative.

Subsequent to the end of the first quarter of 2016, Standard & Poor's confirmed the company's A – rating on long-term debt, updating their outlook to negative.

COS, acquired by the company on February 5, 2016, was downgraded by Moody's in the first quarter of 2016 to Ba3 status.

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

The company added $2.6 billion of debt in the first quarter of 2016 through the acquisition of COS, consisting of approximately $2.0 billion in Cdn$ equivalent U.S. notes and $600 million drawn on a Canadian credit facility.

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, 2016, total debt to total debt plus shareholders' equity was 29.6% (December 31, 2015 – 28.2%). The company is also currently in compliance with all operating covenants.


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

Short-term debt	1 639	747

Current portion of long-term debt	71	70

Long-term debt	16 304	14 486

Total debt	18 014	15 303

Less: Cash and cash equivalents	3 134	4 049

Net debt	14 880	11 254

Equity	42 935	39 039

Total debt plus shareholders' equity	60 949	54 342

Total debt to total debt plus equity (%)	29.6	28.2


($ millions)	Three months ended March 31, 2016

Net debt – start of period	11 254

Increase in net debt	3 626

Net debt – March 31, 2015	14 880

Decrease (increase) in net debt

Cash flow from operations	682

Capital and exploration expenditures and other investments	(1 556	)

Cash acquired, COS	109

Proceeds from disposal of assets	159

Change in non-cash working capital	(760	)

Debt acquired, COS	(2 639	)

Dividends less proceeds from exercise of share options	(446	)

Foreign exchange on cash, debt and other balances	825

	(3 626	)

As at April 25, 2016, the total number of common shares outstanding was 1,582,077,670 and the total number of exercisable and non-exercisable common share options outstanding was 35,402,315. Once exercisable, each outstanding common share option is convertible into one common share.

The company issued 135.7 million shares as consideration for the acquisition of COS.

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

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of its 2015 annual MD&A. 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, 2016, the company increased its commitments by approximately $9.4 billion (undiscounted), all of which is attributable to the acquisition of COS, with the details outlined below.

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


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

Long-term debt	120	271	1 437	1 924	3 752

Decommissioning and restoration costs	16	47	69	2 416	2 548

Pipeline commitments	55	110	140	2 423	2 728

Other long-term obligations	107	142	27	49	325

Total	298	570	1 673	6 812	9 353

Trends in Suncor's quarterly earnings and cash flow from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events. Trends in Suncor's quarterly earnings and cash flow from operations are also affected by changes in commodity prices, refining crack spreads and foreign exchange rates.


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

Total production (mboe/d)

Oil Sands	565.8		470.6		458.4		448.7	475.6		419.3		441.1		403.1

Exploration and Production	125.6		112.3		107.7		111.2	126.8		138.3		78.2		115.3

	691.4		582.9		566.1		559.9	602.4		557.6		519.3		518.4

Revenues and other income

Operating revenues, net of royalties	5 644		6 499		7 485		8 095	7 129		8 899		10 175		10 446

Other (loss) income	(67	)	94		72		49	257		192		98		203

	5 577		6 593		7 557		8 144	7 386		9 091		10 273		10 649

Net (loss) earnings	257		(2 007	)	(376	)	729	(341	)	84		919		211

per common share – basic (dollars)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.63		0.14

per common share – diluted (dollars)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.62		0.14

Operating (loss) earnings⁽¹⁾	(500	)	(26	)	410		906	175		386		1 306		1 135

per common share – basic⁽¹⁾ (dollars)	(0.33	)	(0.02	)	0.28		0.63	0.12		0.27		0.89		0.77

Cash flow from operations⁽¹⁾	682		1 294		1 882		2 155	1 475		1 492		2 280		2 406

per common share – basic⁽¹⁾ (dollars)	0.45		0.90		1.30		1.49	1.02		1.03		1.56		1.64

ROCE⁽¹⁾ (%) for the twelve months ended	(2.2	)	0.6		5.1		7.2	5.8		8.6		9.4		10.1

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	885		(382	)	(786	)	178	(940	)	(302	)	(394	)	282

Common share information (dollars)

Dividend per common share	0.29		0.29		0.29		0.28	0.28		0.28		0.28		0.23

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	36.17		35.72		35.69		34.40	37.01		36.90		40.53		45.50

New York Stock Exchange (US$)	27.81		25.80		26.72		27.52	29.25		31.78		36.15		42.63

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


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

WTI crude oil at Cushing	US$/bbl	33.50	42.15	46.45	57.95	48.65	73.15	97.20	103.00

Dated Brent	US$/bbl	33.90	43.70	50.30	61.95	53.85	76.25	101.90	109.65

Dated Brent/Maya FOB price differential	US$/bbl	8.95	10.35	8.50	8.15	11.05	10.05	12.50	13.85

MSW at Edmonton	Cdn$/bbl	34.50	53.55	52.35	68.05	52.25	75.95	97.45	105.90

WCS at Hardisty	US$/bbl	19.30	27.70	33.25	46.35	33.90	58.90	77.00	82.95

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.25	14.50	13.20	11.60	14.75	14.25	20.20	20.05

Condensate at Edmonton	US$/bbl	34.45	41.65	44.20	57.95	45.60	70.55	93.45	105.15

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.85	2.45	2.90	2.55	2.75	3.60	4.00	4.65

Alberta Power Pool Price	Cdn$/MWh	18.10	21.20	26.05	57.25	29.15	30.55	63.90	42.30

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	11.75	13.60	22.25	23.85	19.20	16.15	20.50	21.55

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	9.10	13.90	23.95	20.30	16.00	14.40	17.50	19.40

Portland 3-2-1 crack⁽¹⁾	US$/bbl	13.00	17.90	28.75	32.55	21.50	12.45	24.60	26.10

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	11.05	11.05	21.55	22.90	18.00	10.15	19.10	19.55

Exchange rate	US$/Cdn$	0.73	0.75	0.76	0.81	0.81	0.88	0.92	0.92

Exchange rate (end of period)	US$/Cdn$	0.77	0.72	0.75	0.80	0.79	0.86	0.89	0.94

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

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

Suncor's significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2015 annual MD&A.

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are those that require management to make assumptions about matters that are highly uncertain at the time the estimate is made. Critical accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the company's financial condition, changes in financial condition or financial performance. Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of Suncor's critical accounting estimates is provided in note 4 to the audited Consolidated Financial Statements for the year ended December 31, 2015 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2015 annual MD&A.

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company's position

with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor's financial instruments and the related financial risk factors, see note 26 of the audited Consolidated Financial Statements for the year ended December 31, 2015, note 10 to the unaudited interim Consolidated Financial Statements for the three months ended March 31, 2016, and the Financial Condition and Liquidity section of Suncor's 2015 annual MD&A.

In the first quarter of 2015, the U.K. government enacted a decrease in the supplementary charge rate on oil and gas profits in the North Sea that decreased the statutory tax rate on Suncor's earnings in the U.K. from 62% to 50%. The company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income tax liabilities of $406 million.

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

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

Based on their evaluation as at March 31, 2016, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at March 31, 2016, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three-month period ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

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

Suncor has updated its previously issued 2016 corporate guidance to revise production estimates and certain assumptions. Suncor's press release dated April 27, 2016, which is also available on www.sedar.com, provides the updated assumptions to its corporate guidance.

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

Operating earnings is a non-GAAP financial measure that adjusts net earnings for significant items that are not indicative of operating performance. Management uses operating earnings to evaluate operating performance because management believes it provides better comparability between periods. Operating earnings are reconciled to net earnings 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)		2016		2015

Adjustments to net earnings

Net (loss) earnings		(1 408	)	873

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		104		1 354

Net interest expense		309		260

	A	(995	)	2 487

Capital employed – beginning of twelve-month period

Net debt		9 522		6 962

Equity		41 272		42 258

		50 794		49 220

Capital employed – end of twelve-month period

Net debt		14 880		9 522

Equity		42 935		41 272

		57 815		50 794

Average capital employed	B	52 289		49 297

ROCE – including major projects in progress (%)	A/B	(1.9	)	5.0

Average capitalized costs related to major projects in progress	C	7 871		6 108

ROCE – excluding major projects in progress (%)	A/(B-C)	(2.2	)	5.8

Cash flow from 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 fuel and income taxes, and the timing of cash flows related to accounts receivable and accounts payable, which management believes reduces comparability between periods.

Cash flow from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the cash flow from (used in) operations for the particular quarter ended March 31 and each of the three preceding quarters. Cash flow from (used in) operations for each quarter are separately defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective MD&A for the applicable quarter.


Three months ended March 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net (loss) earnings	(524	)	(146	)	(34	)	462		241		498		574		(1 155	)	257		(341	)

Adjustments for:

Depreciation, depletion, amortization and impairment	917		773		356		365		170		165		29		30		1 472		1 333

Deferred income taxes	(36	)	(45	)	(73	)	(445	)	(9	)	(28	)	53		71		(65	)	(447	)

Accretion of liabilities	45		37		17		12		2		2		—		1		64		52

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(921	)	962		(921	)	962

Change in fair value of derivative contracts	12		27		—		—		34		71		123		50		169		148

(Gain) loss on disposal of assets	(1	)	8		—		1		—		—		—		(7	)	(1	)	2

Share-based compensation	(51	)	(38	)	2		3		(31	)	(24	)	(83	)	(89	)	(163	)	(148	)

Exploration expenses	—		—		—		49		—		—		—		—		—		49

Settlement of decommissioning and restoration liabilities	(119	)	(130	)	—		(1	)	(2	)	(2	)	(1	)	—		(122	)	(133	)

Other	20		39		(7	)	3		(1	)	4		(20	)	(48	)	(8	)	(2	)

Cash flow from (used in) operations	263		525		261		449		404		686		(246	)	(185	)	682		1 475

(Increase) decrease in non-cash working capital	(296	)	(307	)	(196	)	17		(34	)	(288	)	(108	)	(21	)	(634	)	(599	)

Cash flow (used in) provided by operating activities	(33	)	218		65		466		370		398		(354	)	(206	)	48		876

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

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

Oil Sands operations cash operating costs and cash operating costs per barrel are also adjusted for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of

Oil Sands operations, including, but not limited to, share-based compensation adjustments, research, and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenues; and iv) project start-up costs.

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

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

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

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


Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		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; and the receipt, in a timely manner, of regulatory and third-party approvals. In addition, all other statements and other information that address expectations or projections about the future, and other statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements and information may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may", "future" and similar expressions. Forward-looking statements in the document include references to:

actions to resolve this matter. The company has provided security to the CRA and the Provinces in the approximate amount of $642 million, but the company may be required to post cash instead of security.

Forward-looking statements and information are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them. The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, E&P, and Refining and Marketing, 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 Refining and Marketing segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of taxes or changes to fees and royalties, such as the

NORs received by Suncor from the CRA, Ontario, Alberta and Quebec, relating to the settlement of certain derivative contracts, including the risk that: (i) Suncor may not be able to successfully defend its original filing position and ultimately be required to pay increased taxes, interest and penalty as a result; or (ii) Suncor may be required to post cash instead of security in relation to the NORs; changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; outages to third-party infrastructure that could cause disruptions to production; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information systems by computer hackers or cyberterrorists, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; our ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws; risks and uncertainties associated with closing a transaction for the purchase or sale of an oil and gas property, including estimates of the final consideration to be paid or received, the ability of counterparties to comply with their obligations in a timely manner and the receipt of any required regulatory or other third-party approvals outside of Suncor's control that are customary to transactions of this nature; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor's forward-looking statements are discussed in further detail throughout this MD&A, and in the company's 2015 annual MD&A, 2015 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.


	Three months ended March 31
($ millions)	2016		2015

Revenues and Other Income

Operating revenues, net of royalties (note 3)	5 644		7 129

Other (loss) income (note 5)	(67	)	257

	5 577		7 386

Expenses

Purchases of crude oil and products	2 069		2 772

Operating, selling and general	2 349		2 295

Transportation	289		267

Depreciation, depletion, amortization and impairment	1 472		1 333

Exploration	41		183

(Gain) loss on disposal of assets	(1	)	2

Financing (income) expenses (note 7)	(718	)	1 138

	5 501		7 990

Earnings (Loss) before Income Taxes	76		(604	)

Income Taxes (note 8)

Current	(116	)	184

Deferred	(65	)	(447	)

	(181	)	(263	)

Net Earnings (Loss)	257		(341	)

Net Earnings (Loss) Attributable to:

Common shareholders	246		(341	)

Non-controlling interest (note 4)	11		—

	257		(341	)

Other Comprehensive Income

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	(262	)	386

Items that will not be reclassified to earnings

Actuarial loss on employee retirement benefit plans, net of income taxes	—		(30	)

Other Comprehensive Income	(262	)	356

Total Comprehensive (Loss) Income	(5	)	15

Per Common Share (dollars) (note 9)

Net earnings (loss) – basic and diluted	0.17		(0.24	)

Net earnings (loss) attributable to common shareholders – basic and diluted	0.16		(0.24	)

Cash dividends	0.29		0.28

See accompanying notes to the interim consolidated financial statements.


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

Assets

Current assets

Cash and cash equivalents	3 134	4 049

Accounts receivable	3 061	2 751

Inventories	3 108	3 090

Income taxes receivable	817	538

Total current assets	10 120	10 428

Property, plant and equipment, net	70 050	61 151

Exploration and evaluation	2 081	1 681

Other assets	1 209	1 153

Goodwill and other intangible assets	3 077	3 079

Deferred income taxes	35	35

Total assets	86 572	77 527

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	1 639	747

Current portion of long-term debt	71	70

Accounts payable and accrued liabilities	5 075	5 306

Current portion of provisions	805	769

Income taxes payable	194	244

Total current liabilities	7 784	7 136

Long-term debt	16 304	14 486

Other long-term liabilities	1 900	1 573

Provisions (note 13)	6 040	5 339

Deferred income taxes	11 609	9 954

Shareholders' equity	42 935	39 039

Total liabilities and shareholders' equity	86 572	77 527

See accompanying notes to the interim consolidated financial statements.


	Three months ended March 31
($ millions)	2016		2015

Operating Activities

Net earnings (loss)	257		(341	)

Adjustments for:

Depreciation, depletion, amortization and impairment	1 472		1 333

Deferred income taxes	(65	)	(447	)

Accretion	64		52

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(921	)	962

Change in fair value of derivative contracts	169		148

(Gain) loss on disposal of assets	(1	)	2

Share-based compensation	(163	)	(148	)

Exploration	—		49

Settlement of decommissioning and restoration liabilities	(122	)	(133	)

Other	(8	)	(2	)

Increase in non-cash working capital	(634	)	(599	)

Cash flow provided by operating activities	48		876

Investing Activities

Capital and exploration expenditures	(1 556	)	(1 326	)

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

Proceeds from disposal of assets	159		40

Other investments	(2	)	(4	)

Increase in non-cash working capital	(126	)	(47	)

Cash flow used in investing activities	(1 416	)	(1 337	)

Financing Activities

Net change in short-term debt	964		58

Net change in long-term debt	36		—

Issuance of common shares under share option plans	7		34

Dividends paid on common shares	(453	)	(405	)

Cash flow provided by (used in) financing activities	554		(313	)

Decrease in Cash and Cash Equivalents	(814	)	(774	)

Effect of foreign exchange on cash and cash equivalents	(101	)	104

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

Cash and Cash Equivalents at End of Period	3 134		4 825

Supplementary Cash Flow Information

Interest paid	86		76

Income taxes paid	131		792

See accompanying notes to the interim consolidated financial statements.


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

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

Net loss	—	—		—		—		(341	)	(341	)	—

Foreign currency translation adjustment	—	—		386		—		—		386		—

Actuarial loss on employee retirement benefit plans, net of income taxes of $10	—	—		—		—		(30	)	(30	)	—

Total comprehensive income	—	—		386		—		(371	)	15		—

Issued under share option plans	44	(5	)	—		—		—		39		1 150

Issued under dividend reinvestment plan	10	—		—		—		(10	)	—		—

Share-based compensation	—	20		—		—		—		20		—

Dividends paid on common shares	—	—		—		—		(405	)	(405	)	—

At March 31, 2015	19 365	624		890		—		20 393		41 272		1 445 269



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 income (loss)	—	—		(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

See accompanying notes to the interim consolidated financial statements.

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

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

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

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

Comparative figures have been reclassified to conform to the current year financial statement presentation for the revenues and expenses for the company's ethanol business that is presented in the Refining and Marketing segment, and was previously presented in the Corporate, Energy Trading and Eliminations segment. The reclassification resulted in an increase in net earnings for the Refining and Marketing segment of $6 million for the three months ended March 31, 2015 and $40 million for the twelve months ended December 31, 2015. Net earnings for the Corporate, Energy Trading and Eliminations segment decreased by $6 million for the three months ended March 31, 2015 and $40 million for the twelve months ended December 31, 2015 as a result of the reclassification.

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

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

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

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

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)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	1 585		1 777		531		732		3 579		4 808		(3	)	(44	)	5 692		7 273

Intersegment revenues	454		507		—		37		12		22		(466	)	(566	)	—		—

Less: Royalties	(19	)	(18	)	(29	)	(126	)	—		—		—		—		(48	)	(144	)

Operating revenues, net of royalties	2 020		2 266		502		643		3 591		4 830		(469	)	(610	)	5 644		7 129

Other income (loss)	33		58		2		116		11		21		(113	)	62		(67	)	257

	2 053		2 324		504		759		3 602		4 851		(582	)	(548	)	5 577		7 386

Expenses

Purchases of crude oil and products	140		70		—		1		2 456		3 347		(527	)	(646	)	2 069		2 772

Operating, selling and general	1 435		1 372		145		131		542		570		227		222		2 349		2 295

Transportation	184		152		23		27		92		99		(10	)	(11	)	289		267

Depreciation, depletion, amortization and impairment	917		773		356		365		170		165		29		30		1 472		1 333

Exploration	30		105		11		78		—		—		—		—		41		183

(Gain) loss on disposal of assets	(1	)	8		—		1		—		—		—		(7	)	(1	)	2

Financing (income) expenses	55		39		15		38		11		(7	)	(799	)	1 068		(718	)	1 138

	2 760		2 519		550		641		3 271		4 174		(1 080	)	656		5 501		7 990

(Loss) earnings before Income Taxes	(707	)	(195	)	(46	)	118		331		677		498		(1 204	)	76		(604	)

Income Taxes

Current	(147	)	(4	)	61		101		99		207		(129	)	(120	)	(116	)	184

Deferred	(36	)	(45	)	(73	)	(445	)	(9	)	(28	)	53		71		(65	)	(447	)

	(183	)	(49	)	(12	)	(344	)	90		179		(76	)	(49	)	(181	)	(263	)

Net (Loss) Earnings	(524	)	(146	)	(34	)	462		241		498		574		(1 155	)	257		(341	)

Capital and Exploration Expenditures	1 107		793		271		356		172		83		6		94		1 556		1 326

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 on the acquisition date.

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 preliminary purchase price allocation is based on management's best estimates of fair values of COS' assets and liabilities as at February 5, 2016. Adjustments to estimates may be required.


($ 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

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 are 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 commencing in the first quarter of 2016.

Acquisition costs of $28.7 million have been charged to Operating, Selling and General expense in the consolidated statements of comprehensive income for the period ended March 31, 2016.

COS contributed $326.4 million to gross revenues and $77.0 million to consolidated net earnings from the acquisition date to March 31, 2016.

Had the acquisition occurred on January 1, 2016, COS would have contributed $508.0 million to gross revenues and $40.1 million to consolidated net earnings, which would have resulted in gross revenues of $6.2 billion and consolidated net earnings of $297 million for the period ended March 31, 2016.


	Three months ended March 31
($ millions)	2016		2015

Energy trading activities

Change in fair value of contracts	(24	)	7

Gains on inventory valuation	30		75

Risk management activities⁽¹⁾	(99	)	8

Investment and interest income	18		18

Renewable energy grants	—		5

Risk mitigation and insurance proceeds⁽²⁾	—		104

Change in value of transportation commitments and other	8		40

	(67	)	257

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

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


	Three months ended March 31
($ millions)	2016		2015

Interest on debt	254		210

Capitalized interest	(141	)	(93	)

Interest expense	113		117

Interest on pension and other post-retirement benefits	12		15

Accretion	64		52

Foreign exchange (gain) loss on U.S. dollar denominated debt	(921	)	962

Foreign exchange and other	14		(8	)

	(718	)	1 138

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


	Three months ended March 31
($ millions)	2016	2015

Net earnings (loss)	257	(341	)

Net earnings (loss) attributable to common shareholders	246	(341	)

(millions of common shares)

Weighted average number of common shares	1 516	1 445

Dilutive securities:

Effect of share options	1	—

Weighted average number of diluted common shares	1 517	1 445

(dollars per common share)

Basic and diluted earnings (loss) per share	0.17	(0.24	)

Basic and diluted earnings (loss) per share attributable to common shareholders	0.16	(0.24	)

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

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

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

The company uses forward starting interest rate swaps to mitigate its exposure to the effect of future interest rate movements on future debt issuances. As at March 31, 2016, the company had executed $1.3 billion in forward swaps. A decrease in interest rates of 0.53% during the quarter resulted in a decrease in value of $123 million associated with the swaps.

At March 31, 2016, the carrying value of fixed-term debt accounted for under amortized cost was $15.2 billion (December 31, 2015 – $13.3 billion) and the fair value was $16.0 billion (December 31, 2015 – $14.5 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

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

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

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

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

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

An increase in the credit-adjusted risk-free interest rate to 4.73% (December 31, 2015 – 4.37%) resulted in a decrease in provisions of $440 million for the three months ended March 31, 2016.

On April 27, 2016 Suncor announced that it had entered into a purchase and sale agreement with Murphy Oil Company Ltd. (Murphy Oil) to acquire Murphy Oil's 5% interest in the Syncrude oil sands mining and upgrading joint arrangement for $937 million, subject to closing adjustments. The transaction is subject to regulatory approval and has an effective date of April 1, 2016. Upon completion of the transaction, which is expected to close by the end of the second quarter of 2016, Suncor's working interest in Syncrude will increase to 53.74%.


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

Revenues and other income	5,577		6 593		7 557		8 144		7 386		29 680

Net (loss) earnings

Oil Sands	(524	)	(616	)	(50	)	(44	)	(146	)	(856	)

Exploration and Production	(34	)	(1 263	)	(1	)	44		462		(758	)

Refining and Marketing	241		506		625		677		498		2 306

Corporate, Energy Trading and Eliminations	574		(634	)	(950	)	52		(1 155	)	(2 687	)

	257		(2 007	)	(376	)	729		(341	)	(1 995	)

Operating (loss) earnings^(A)

Oil Sands	(524	)	(230	)	(50	)	315		(146	)	(111	)

Exploration and Production	(34	)	(50	)	(1	)	77		(19	)	7

Refining and Marketing	241		506		625		645		498		2 274

Corporate, Energy Trading and Eliminations	(183	)	(252	)	(164	)	(131	)	(158	)	(705	)

	(500	)	(26	)	410		906		175		1 465

Cash flow from (used in) operations^(A)

Oil Sands	263		467		785		1 058		525		2 835

Exploration and Production	261		257		253		427		449		1 386

Refining and Marketing	404		605		814		816		686		2 921

Corporate, Energy Trading and Eliminations	(246	)	(35	)	30		(146	)	(185	)	(336	)

	682		1 294		1 882		2 155		1 475		6 806

Per common share

Net earnings (loss) – basic and diluted	0.17		(1.38	)	(0.26	)	0.50		(0.24	)	(1.38	)

Net earnings (loss) attributable to common shareholders – basic and diluted	0.16		(1.38	)	(0.26	)	0.50		(0.24	)	(1.38	)

Operating (loss) earnings – basic	(0.33	)	(0.02	)	0.28		0.63		0.12		1.01

Cash dividends – basic	0.29		0.29		0.29		0.28		0.28		1.14

Cash flow from operations – basic	0.45		0.90		1.30		1.49		1.02		4.71


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

Total Production (mbbls/d)	565.8	470.6	458.4	448.7	475.6	463.4

Oil Sands operations

Production volumes (mbbls/d)

Upgraded product (sweet SCO, sour SCO & diesel)	322.3	292.2	314.9	327.4	346.5	320.1

Non-upgraded bitumen	130.7	147.5	115.4	96.4	93.9	113.5

Oil Sands operations production	453.0	439.7	430.3	423.8	440.4	433.6

Bitumen production (mbbls/d)

Mining	302.0	292.4	303.3	315.5	318.3	307.3

In Situ – Firebag	199.0	198.8	191.7	168.1	188.7	186.9

In Situ – MacKay River	36.8	34.5	27.4	31.5	29.3	30.7

Total bitumen production	537.8	525.7	522.4	515.1	536.3	524.9

Sales (mbbls/d)

Light sweet crude oil	132.2	100.2	112.9	102.4	112.5	107.0

Diesel	24.8	29.4	30.0	35.1	30.8	31.3

Light sour crude oil	172.7	154.2	180.7	194.4	201.3	182.5

Upgraded product (SCO and diesel)	329.7	283.8	323.6	331.9	344.6	320.8

Non-upgraded bitumen	134.5	136.3	106.3	91.8	95.8	107.7

Total sales	464.2	420.1	429.9	423.7	440.4	428.5

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

Cash costs	22.55	25.70	24.95	26.15	25.70	25.65

Natural gas	1.70	2.30	2.05	1.85	2.70	2.20

	24.25	28.00	27.00	28.00	28.40	27.85

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

Cash costs	21.70	25.10	22.65	22.50	22.65	23.20

Natural gas	0.50	0.70	0.45	0.45	0.55	0.55

	22.20	25.80	23.10	22.95	23.20	23.75

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

Cash costs	7.60	8.10	8.80	9.25	9.90	9.00

Natural gas	2.80	3.55	3.75	3.80	4.10	3.80

	10.40	11.65	12.55	13.05	14.00	12.80

Syncrude

Production (mbbls/d)	112.8	30.9	28.1	24.9	35.2	29.8

Cash operating costs⁽¹⁾ ($/bbl)

Cash costs	30.25	38.55	39.70	54.45	34.20	40.35

Natural gas	1.10	1.60	1.95	1.65	1.50	1.65

	31.35	40.15	41.65	56.10	35.70	42.00

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Bitumen ($/bbl)

Average price realized	12.00		25.63		33.39		43.11		29.76		32.18

Royalties	—		(0.32	)	(0.71	)	(1.17	)	0.52		(0.41	)

Transportation costs	(5.57	)	(7.05	)	(6.40	)	(5.48	)	(5.75	)	(6.26	)

Net operating expenses⁽²⁾	(9.81	)	(11.32	)	(10.32	)	(12.22	)	(13.61	)	(11.76	)

Operating netback	(3.38	)	6.94		15.96		24.24		10.92		13.75

SCO ($/bbl)

Average price realized	43.27		54.39		57.45		70.01		56.71		59.81

Royalties	(0.57	)	(0.48	)	(0.91	)	(0.67	)	(0.55	)	(0.65	)

Transportation costs	(3.83	)	(3.06	)	(3.95	)	(3.12	)	(3.27	)	(3.36	)

Net operating expenses⁽²⁾ – bitumen	(21.98	)	(26.81	)	(24.85	)	(24.48	)	(23.85	)	(24.91	)

Net operating expenses⁽²⁾ – upgrading	(5.51	)	(7.02	)	(5.18	)	(5.46	)	(6.24	)	(5.96	)

Operating netback	11.38		17.02		22.56		36.28		22.80		24.93

Average Oil Sands operations ($/bbl)

Average price realized	34.21		45.05		51.50		64.18		50.85		52.87

Royalties	(0.41	)	(0.43	)	(0.86	)	(0.77	)	(0.32	)	(0.59	)

Transportation costs	(4.34	)	(4.36	)	(4.55	)	(3.63	)	(3.81	)	(4.09	)

Net operating expenses⁽²⁾ – bitumen and upgrading	(22.36	)	(26.53	)	(25.16	)	(26.10	)	(26.52	)	(26.07	)

Operating netback	7.10		13.73		20.93		33.68		20.20		22.12

Syncrude ($/bbl)

Average price realized	44.93		60.43		61.23		74.03		56.21		60.28

Royalties	(0.18	)	2.78		(5.36	)	(3.68	)	(1.75	)	(1.89	)

Transportation costs	(0.86	)	(0.60	)	(0.70	)	(0.69	)	(0.30	)	(0.54	)

Net operating expenses⁽²⁾ – bitumen and upgrading	(27.75	)	(36.11	)	(35.36	)	(47.29	)	(30.24	)	(35.69	)

Operating netback	16.14		26.50		19.81		22.37		23.92		22.16

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Total Production (mboe/d)	125.6		112.3		107.7		111.2		126.8		114.4

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)	12.8		13.1		10.4		7.3		23.3		13.5

Hibernia (mbbls/d)	24.1		15.6		16.6		18.3		22.0		18.1

White Rose (mbbls/d)	13.7		14.8		9.9		11.4		12.8		12.2

North America Onshore (mboe/d)	3.0		3.1		3.7		2.4		3.6		3.2

	53.6		46.6		40.6		39.4		61.7		47.0

Exploration and Production International

Buzzard (mboe/d)	53.4		45.5		50.0		52.4		51.4		49.8

Golden Eagle (mboe/d)	18.6		17.7		17.0		14.5		9.8		14.8

United Kingdom (mboe/d)	72.0		63.2		67.0		66.9		61.2		64.6

Libya (mbbls/d)	—		2.5		0.1		4.9		3.9		2.8

	72.0		65.7		67.1		71.8		65.1		67.4

Netbacks

East Coast Canada ($/bbl)

Average price realized	46.17		52.51		59.09		78.23		66.38		65.12

Royalties	(5.51	)	(5.79	)	(4.39	)	(16.38	)	(17.58	)	(12.49	)

Transportation costs	(1.68	)	(2.81	)	(2.97	)	(1.73	)	(1.76	)	(2.18	)

Operating costs	(13.72	)	(16.86	)	(17.66	)	(16.63	)	(9.57	)	(14.15	)

Operating netback	25.26		27.05		34.07		43.49		37.47		36.30

United Kingdom ($/boe)

Average price realized	43.02		54.91		62.86		72.84		64.48		63.85

Transportation costs	(1.97	)	(2.22	)	(2.43	)	(2.66	)	(2.32	)	(2.41	)

Operating costs	(5.75	)	(6.20	)	(5.99	)	(5.86	)	(7.33	)	(6.29	)

Operating netback	35.30		46.49		54.44		64.32		54.83		55.15

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Refined product sales (mbbls/d)	489.5	501.2	546.4	525.5	519.7	523.3

Crude oil processed (mbbls/d)	420.9	430.2	444.8	416.8	437.1	432.1

Utilization of refining capacity (%)	91	93	96	90	95	94

Refining margin ($/bbl)	19.10	23.20	26.60	21.10	28.50	24.90

Refining operating expense ($/bbl)	5.10	4.70	4.70	5.20	5.40	5.10

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	107.8	116.1	119.1	121.8	118.6	118.9

Distillate	75.5	86.2	90.5	91.8	96.0	91.1

Total transportation fuel sales	183.3	202.3	209.6	213.6	214.6	210.0

Petrochemicals	12.0	8.9	10.4	10.6	13.3	10.8

Asphalt	11.9	14.1	18.4	12.0	7.6	13.1

Other	35.4	28.2	24.8	31.8	31.0	28.9

Total refined product sales	242.6	253.5	263.2	268.0	266.5	262.8

Crude oil supply and refining

Processed at refineries (mbbls/d)	212.1	208.0	200.5	211.6	212.4	208.1

Utilization of refining capacity (%)	96	94	90	95	96	94

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	122.4	127.7	135.3	126.7	119.2	127.3

Distillate	96.6	100.8	115.8	100.7	110.2	106.9

Total transportation fuel sales	219.0	228.5	251.1	227.4	229.4	234.2

Asphalt	8.7	10.8	13.9	13.9	9.7	11.9

Other	19.2	8.4	18.2	16.2	14.1	14.4

Total refined product sales	246.9	247.7	283.2	257.5	253.2	260.5

Crude oil supply and refining

Processed at refineries (mbbls/d)	208.8	222.2	244.3	205.2	224.7	224.0

Utilization of refining capacity (%)	87	93	102	86	94	93

See accompanying footnotes and definitions to the quarterly operating summaries.

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

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

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

Management's Discussion and Analysis for the first quarter ended March 31, 2016

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)	2016		2015

Net (loss) earnings

Oil Sands	(524	)	(146	)

Exploration and Production	(34	)	462

Refining and Marketing	241		498

Corporate, Energy Trading and Eliminations	574		(1 155	)

Total	257		(341	)

Operating (loss) earnings⁽¹⁾

Oil Sands	(524	)	(146	)

Exploration and Production	(34	)	(19	)

Refining and Marketing	241		498

Corporate, Energy Trading and Eliminations	(183	)	(158	)

Total	(500	)	175

Cash flow from (used in) operations⁽¹⁾

Oil Sands	263		525

Exploration and Production	261		449

Refining and Marketing	404		686

Corporate, Energy Trading and Eliminations	(246	)	(185	)

Total	682		1 475

Capital and Exploration Expenditures⁽²⁾

Sustaining	471		377

Growth	944		856

Total	1 415		1 233


	Three months ended March 31
	2016	2015

Production volumes by segment

Oil Sands (mbbls/d)	565.8	475.6

Exploration and Production (mboe/d)	125.6	126.8

Total	691.4	602.4

Production mix

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

Refinery utilization (%)	91	95

Refinery crude oil processed (mbbls/d)	420.9	437.1


	Three months ended March 31
($ millions)	2016		2015

Net earnings (loss)	257		(341	)

Unrealized foreign exchange(gain) loss on U.S. dollar denominated debt	(885	)	940

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

COS acquisition and integration costs⁽³⁾	38		—

Impact of income tax rate adjustments on deferred income taxes⁽⁴⁾	—		(406	)

Restructuring charges⁽⁵⁾	—		57

Insurance proceeds⁽⁶⁾	—		(75	)

Operating (loss) earnings⁽¹⁾	(500	)	175

(1): Operating (loss) earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash loss on the company's interest rate swaps resulting from a decrease in long-term interest rates and unfavourable foreign exchange.
(3): Transaction and related charges associated with the acquisition of COS.
(4): Adjustments to the company's deferred income taxes resulting from a decrease in the U.K. tax rate on oil and gas profits from the North Sea.
(5): Restructuring charges related to the cost reduction initiatives.
(6): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

During the first quarter of 2016, annual share-based compensation cash payments were $292 million, compared to $267 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
		2016	2015

WTI crude oil at Cushing	US$/bbl	33.50	48.65

Dated Brent crude oil at Sullom Voe	US$/bbl	33.90	53.85

Dated Brent/Maya crude oil FOB price differential	US$/bbl	8.95	11.05

MSW at Edmonton	Cdn$/bbl	34.50	52.25

WCS at Hardisty	US$/bbl	19.30	33.90

Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.25	14.75

Condensate at Edmonton	US$/bbl	34.45	45.60

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.85	2.75

Alberta Power Pool Price	Cdn$/MWh	18.10	29.15

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	11.75	19.20

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	9.10	16.00

Portland 3-2-1 crack⁽¹⁾	US$/bbl	13.00	21.50

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	11.05	18.00

Exchange rate	US$/Cdn$	0.73	0.81

Exchange rate (end of period)	US$/Cdn$	0.77	0.79

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


	Three months ended March 31
($ millions)	2016		2015

Gross revenues	2 039		2 284

Less: Royalties	(19	)	(18	)

Operating revenues, net of royalties	2 020		2 266

Net (loss) earnings	(524	)	(146	)

Operating (loss) earnings⁽¹⁾	(524	)	(146	)

Oil Sands operations	*(517*	)	(131	)

Oil Sands ventures	(7	)	(15	)

Cash flow from operations⁽¹⁾	263		525

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


	Three months ended March 31
(mbbls/d)	2016	2015

Upgraded product (SCO and diesel)	322.3	346.5

Non-upgraded bitumen	130.7	93.9

Oil Sands operations	453.0	440.4

Oil Sands ventures – Syncrude	112.8	35.2

Total	565.8	475.6

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


	Three months ended March 31
(mbbls/d)	2016	2015

Oil Sands sales volumes

Sweet SCO	132.2	112.5

Diesel	24.8	30.8

Sour SCO	172.7	201.3

Upgraded product	329.7	344.6

Non-upgraded bitumen	134.5	95.8

Oil Sands operations	464.2	440.4

Oil Sands ventures – Syncrude	112.8	35.2

Total	577.0	475.6

Sales volumes for Oil Sands operations increased to an average of 464,200 bbls/d in the first quarter of 2016, up from 440,400 bbls/d in the prior year quarter, due to higher production volumes.

Inventory levels in the first quarter of 2016 decreased compared to minimal change to inventory levels in the prior year quarter.


	Three months ended March 31
	2016	2015

Oil Sands Base

Bitumen production (mbbls/d)	304.0	318.3

Bitumen ore mined (thousands of tonnes per day)	449.4	466.1

Bitumen ore grade quality (bbls/tonne)	0.68	0.68

In Situ

Bitumen production – Firebag (mbbls/d)	199.0	188.7

Bitumen production – MacKay River (mbbls/d)	36.8	29.3

Total In Situ bitumen production	235.8	218.0

Steam-to-oil ratio – Firebag	2.6	2.6

Steam-to-oil ratio – MacKay River	2.8	2.8

Both Firebag and MacKay River's steam-to-oil ratios were consistent with the prior year quarter, reflecting continued strong reliability and reservoir performance.


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

Oil Sands operations

SCO and diesel	39.44		53.44

Bitumen	6.43		24.01

Crude sales basket (all products)	29.87		47.04

Crude sales basket, relative to WTI	(16.20	)	(13.22	)

Oil Sands ventures

Syncrude – sweet SCO	44.07		55.91

Syncrude, relative to WTI	(2.00	)	(4.35	)


	Three months ended March 31
($ millions)	2016		2015

Oil Sands operations cash operating cost reconciliation

Operating, selling and general expense (OS&G)	1 435		1 372

Syncrude OS&G	(334	)	(114	)

Non-production costs⁽²⁾	(33	)	(39	)

Excess power capacity and other⁽³⁾	(31	)	(68	)

Inventory changes	(38	)	(25	)

Oil Sands operations cash operating costs⁽¹⁾	999		1 126

Oil Sands operations cash operating costs ($/bbl)	24.25		28.40

Syncrude cash operating costs

Syncrude cash operating costs⁽⁴⁾	327		113

Syncrude cash operating costs ($/bbl)	31.35		35.75

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

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

The impact of these maintenance activities has been reflected in the company's 2016 guidance.

During the first quarter of 2016, the company completed its acquisitions of COS, bringing its ownership interest in Syncrude up to 48.74%.


	Three months ended March 31
($ millions)	2016		2015

Gross revenues	531		769

Less: Royalties	(29	)	(126	)

Operating revenues, net of royalties	502		643

Net earnings	(34	)	462

Adjusted for:

Impact of income tax rate adjustments on deferred income taxes⁽¹⁾	—		(406	)

Insurance proceeds	—		(75	)

Operating (loss) earnings⁽²⁾	(34	)	(19	)

E&P Canada	*(19*	)	(33	)

E&P International	*(15*	)	14

Cash flow from operations⁽²⁾	261		449

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

E&P operating loss was $34 million in the first quarter of 2016, compared to an operating loss of $19 million in the prior year quarter.


	Three months ended March 31
	2016	2015

E&P Canada

Terra Nova (mbbls/d)	12.8	23.3

Hibernia (mbbls/d)	24.1	22.0

White Rose (mbbls/d)	13.7	12.8

North America Onshore (mboe/d)	3.0	3.6

	53.6	61.7

E&P International

Buzzard (mboe/d)	53.4	51.4

Golden Eagle (mboe/d)	18.6	9.8

United Kingdom (mboe/d)	72.0	61.2

Libya (mbbls/d)	—	3.9

	72.0	65.1

Total production (mboe/d)	125.6	126.8

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

Royalties for E&P were lower in the first quarter of 2016, compared with the prior year quarter, primarily due to lower price realizations and lower volumes in East Coast Canada.

During the first quarter of 2016, there was an inventory draw compared to minimal change to inventory levels in the prior year quarter.

Operating and transportation expenses decreased in the first quarter of 2016, compared to the prior year quarter, primarily due to cost reduction initiatives.

A planned four-week maintenance event at Terra Nova has been scheduled to commence in the second quarter of 2016. The impact of this maintenance has been reflected in the company's 2016 guidance.


	Three months ended March 31
($ millions)	2016	2015

Operating revenues	3 591	4 830

Net earnings	241	498

Operating earnings⁽¹⁾	241	498

Refining and Supply	*175*	394

Marketing	66	104

Cash flow from operations⁽¹⁾	404	686

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


	Three months ended March 31
	2016	2015

Crude oil processed (mbbls/d)

Eastern North America	212.1	212.4

Western North America	208.8	224.7

Total	420.9	437.1

Ethanol production (mbbls/d)	7.3	7.5

Refinery utilization⁽¹⁾ (%)

Eastern North America	96	96

Western North America	87	94

Total	91	95

Refined product sales (mbbls/d)

Gasoline	230.2	237.8

Distillate	172.1	206.2

Other	87.2	75.7

Total	489.5	519.7

Refining gross margin⁽²⁾ ($/bbl)	19.10	28.50

Refining operating expense⁽²⁾ ($/bbl)	5.10	5.40

(1): Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.
(2): Refining gross margin per barrel and Refining operating expense per barrel are presented on the basis of total output from the company's four refineries.

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

(1) LIFO is a non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Marketing margins in the first quarter of 2016 were impacted by weaker demand as compared to the first quarter of 2015.


	Three months ended March 31
($ millions)	2016		2015

Net earnings (loss)	574		(1 155	)

Adjusted for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(885	)	940

Non-cash mark to market loss on interest rate swaps	90		—

COS acquisition and related costs	38		—

Restructuring charges	—		57

Operating loss⁽¹⁾	(183	)	(158	)

Renewable Energy	10		8

Energy Trading	(2	)	57

Corporate	*(226*	)	(257	)

Eliminations	35		34

Cash flow used in operations⁽¹⁾	(246	)	(185	)

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


	Three months ended March 31
($ millions)	2016		2015

Oil Sands	1 107		793

Exploration and Production	271		356

Refining and Marketing	172		83

Corporate, Energy Trading and Eliminations	6		94

Total capital and exploration expenditures	1 556		1 326

Less: capitalized interest on debt	(141	)	(93	)

	1 415		1 233


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

Oil Sands

Oil Sands Base	203	110	313

In Situ	55	14	69

Oil Sands Ventures	40	586	*626*

Exploration and Production	2	232	234

Refining and Marketing	166	2	168

Corporate, Energy Trading and Eliminations	5	—	5

	471	944	1 415

(1): Capital expenditures in this table exclude capitalized interest on debt.
(2): Growth capital expenditures include capital investments that result in i) an increase in production levels at existing Oil Sands operations and Refining and Marketing 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 Exploration and Production operations; or v) margin improvement, by increasing revenues or reducing costs.
(3): Sustaining capital expenditures include capital investments that i) ensure compliance or maintain relations with regulators and other stakeholders; ii) improve efficiency and reliability of operations or maintain productive capacity by replacing component assets at the end of their useful lives; iii) deliver existing proved developed reserves for Exploration and Production operations; or iv) maintain current production capacities at existing Oil Sands operations and Refining and Marketing operations.

Growth capital was focused on logistical and storage assets designed to support market access for Fort Hills bitumen production.

Corporate capital expenditures were $5 million, with the majority of the spending directed towards the company's information and technology initiatives.


	Twelve months ended March 31
	2016		2015

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	(2.2	)	5.8

Including major projects in progress	(1.9	)	5.0

Net debt to cash flow from operations⁽²⁾ (times)	2.5		1.2

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	(1.0	)	2.7

Cash flow from operations basis⁽²⁾⁽⁴⁾	7.9		12.4

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

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

Subsequent to the end of the first quarter of 2016, Standard & Poor's confirmed the company's A – rating on long-term debt, updating their outlook to negative.

COS, acquired by the company on February 5, 2016, was downgraded by Moody's in the first quarter of 2016 to Ba3 status.


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

Short-term debt	1 639	747

Current portion of long-term debt	71	70

Long-term debt	16 304	14 486

Total debt	18 014	15 303

Less: Cash and cash equivalents	3 134	4 049

Net debt	14 880	11 254

Equity	42 935	39 039

Total debt plus shareholders' equity	60 949	54 342

Total debt to total debt plus equity (%)	29.6	28.2


($ millions)	Three months ended March 31, 2016

Net debt – start of period	11 254

Increase in net debt	3 626

Net debt – March 31, 2015	14 880

Decrease (increase) in net debt

Cash flow from operations	682

Capital and exploration expenditures and other investments	(1 556	)

Cash acquired, COS	109

Proceeds from disposal of assets	159

Change in non-cash working capital	(760	)

Debt acquired, COS	(2 639	)

Dividends less proceeds from exercise of share options	(446	)

Foreign exchange on cash, debt and other balances	825

	(3 626	)

The company issued 135.7 million shares as consideration for the acquisition of COS.

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

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


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

Long-term debt	120	271	1 437	1 924	3 752

Decommissioning and restoration costs	16	47	69	2 416	2 548

Pipeline commitments	55	110	140	2 423	2 728

Other long-term obligations	107	142	27	49	325

Total	298	570	1 673	6 812	9 353


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

Total production (mboe/d)

Oil Sands	565.8		470.6		458.4		448.7	475.6		419.3		441.1		403.1

Exploration and Production	125.6		112.3		107.7		111.2	126.8		138.3		78.2		115.3

	691.4		582.9		566.1		559.9	602.4		557.6		519.3		518.4

Revenues and other income

Operating revenues, net of royalties	5 644		6 499		7 485		8 095	7 129		8 899		10 175		10 446

Other (loss) income	(67	)	94		72		49	257		192		98		203

	5 577		6 593		7 557		8 144	7 386		9 091		10 273		10 649

Net (loss) earnings	257		(2 007	)	(376	)	729	(341	)	84		919		211

per common share – basic (dollars)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.63		0.14

per common share – diluted (dollars)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.62		0.14

Operating (loss) earnings⁽¹⁾	(500	)	(26	)	410		906	175		386		1 306		1 135

per common share – basic⁽¹⁾ (dollars)	(0.33	)	(0.02	)	0.28		0.63	0.12		0.27		0.89		0.77

Cash flow from operations⁽¹⁾	682		1 294		1 882		2 155	1 475		1 492		2 280		2 406

per common share – basic⁽¹⁾ (dollars)	0.45		0.90		1.30		1.49	1.02		1.03		1.56		1.64

ROCE⁽¹⁾ (%) for the twelve months ended	(2.2	)	0.6		5.1		7.2	5.8		8.6		9.4		10.1

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	885		(382	)	(786	)	178	(940	)	(302	)	(394	)	282

Common share information (dollars)

Dividend per common share	0.29		0.29		0.29		0.28	0.28		0.28		0.28		0.23

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	36.17		35.72		35.69		34.40	37.01		36.90		40.53		45.50

New York Stock Exchange (US$)	27.81		25.80		26.72		27.52	29.25		31.78		36.15		42.63

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


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

WTI crude oil at Cushing	US$/bbl	33.50	42.15	46.45	57.95	48.65	73.15	97.20	103.00

Dated Brent	US$/bbl	33.90	43.70	50.30	61.95	53.85	76.25	101.90	109.65

Dated Brent/Maya FOB price differential	US$/bbl	8.95	10.35	8.50	8.15	11.05	10.05	12.50	13.85

MSW at Edmonton	Cdn$/bbl	34.50	53.55	52.35	68.05	52.25	75.95	97.45	105.90

WCS at Hardisty	US$/bbl	19.30	27.70	33.25	46.35	33.90	58.90	77.00	82.95

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	14.25	14.50	13.20	11.60	14.75	14.25	20.20	20.05

Condensate at Edmonton	US$/bbl	34.45	41.65	44.20	57.95	45.60	70.55	93.45	105.15

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.85	2.45	2.90	2.55	2.75	3.60	4.00	4.65

Alberta Power Pool Price	Cdn$/MWh	18.10	21.20	26.05	57.25	29.15	30.55	63.90	42.30

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	11.75	13.60	22.25	23.85	19.20	16.15	20.50	21.55

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	9.10	13.90	23.95	20.30	16.00	14.40	17.50	19.40

Portland 3-2-1 crack⁽¹⁾	US$/bbl	13.00	17.90	28.75	32.55	21.50	12.45	24.60	26.10

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	11.05	11.05	21.55	22.90	18.00	10.15	19.10	19.55

Exchange rate	US$/Cdn$	0.73	0.75	0.76	0.81	0.81	0.88	0.92	0.92

Exchange rate (end of period)	US$/Cdn$	0.77	0.72	0.75	0.80	0.79	0.86	0.89	0.94

(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:

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


For the twelve months ended March 31 ($ millions, except as noted)		2016		2015

Adjustments to net earnings

Net (loss) earnings		(1 408	)	873

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		104		1 354

Net interest expense		309		260

	A	(995	)	2 487

Capital employed – beginning of twelve-month period

Net debt		9 522		6 962

Equity		41 272		42 258

		50 794		49 220

Capital employed – end of twelve-month period

Net debt		14 880		9 522

Equity		42 935		41 272

		57 815		50 794

Average capital employed	B	52 289		49 297

ROCE – including major projects in progress (%)	A/B	(1.9	)	5.0

Average capitalized costs related to major projects in progress	C	7 871		6 108

ROCE – excluding major projects in progress (%)	A/(B-C)	(2.2	)	5.8


Three months ended March 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net (loss) earnings	(524	)	(146	)	(34	)	462		241		498		574		(1 155	)	257		(341	)

Adjustments for:

Depreciation, depletion, amortization and impairment	917		773		356		365		170		165		29		30		1 472		1 333

Deferred income taxes	(36	)	(45	)	(73	)	(445	)	(9	)	(28	)	53		71		(65	)	(447	)

Accretion of liabilities	45		37		17		12		2		2		—		1		64		52

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(921	)	962		(921	)	962

Change in fair value of derivative contracts	12		27		—		—		34		71		123		50		169		148

(Gain) loss on disposal of assets	(1	)	8		—		1		—		—		—		(7	)	(1	)	2

Share-based compensation	(51	)	(38	)	2		3		(31	)	(24	)	(83	)	(89	)	(163	)	(148	)

Exploration expenses	—		—		—		49		—		—		—		—		—		49

Settlement of decommissioning and restoration liabilities	(119	)	(130	)	—		(1	)	(2	)	(2	)	(1	)	—		(122	)	(133	)

Other	20		39		(7	)	3		(1	)	4		(20	)	(48	)	(8	)	(2	)

Cash flow from (used in) operations	263		525		261		449		404		686		(246	)	(185	)	682		1 475

(Increase) decrease in non-cash working capital	(296	)	(307	)	(196	)	17		(34	)	(288	)	(108	)	(21	)	(634	)	(599	)

Cash flow (used in) provided by operating activities	(33	)	218		65		466		370		398		(354	)	(206	)	48		876

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


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

Unaudited Consolidated Financial Statements for the first quarter ended March 31, 2016


	Three months ended March 31
($ millions)	2016		2015

Revenues and Other Income

Operating revenues, net of royalties (note 3)	5 644		7 129

Other (loss) income (note 5)	(67	)	257

	5 577		7 386

Expenses

Purchases of crude oil and products	2 069		2 772

Operating, selling and general	2 349		2 295

Transportation	289		267

Depreciation, depletion, amortization and impairment	1 472		1 333

Exploration	41		183

(Gain) loss on disposal of assets	(1	)	2

Financing (income) expenses (note 7)	(718	)	1 138

	5 501		7 990

Earnings (Loss) before Income Taxes	76		(604	)

Income Taxes (note 8)

Current	(116	)	184

Deferred	(65	)	(447	)

	(181	)	(263	)

Net Earnings (Loss)	257		(341	)

Net Earnings (Loss) Attributable to:

Common shareholders	246		(341	)

Non-controlling interest (note 4)	11		—

	257		(341	)

Other Comprehensive Income

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	(262	)	386

Items that will not be reclassified to earnings

Actuarial loss on employee retirement benefit plans, net of income taxes	—		(30	)

Other Comprehensive Income	(262	)	356

Total Comprehensive (Loss) Income	(5	)	15

Per Common Share (dollars) (note 9)

Net earnings (loss) – basic and diluted	0.17		(0.24	)

Net earnings (loss) attributable to common shareholders – basic and diluted	0.16		(0.24	)

Cash dividends	0.29		0.28

See accompanying notes to the interim consolidated financial statements.


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

Assets

Current assets

Cash and cash equivalents	3 134	4 049

Accounts receivable	3 061	2 751

Inventories	3 108	3 090

Income taxes receivable	817	538

Total current assets	10 120	10 428

Property, plant and equipment, net	70 050	61 151

Exploration and evaluation	2 081	1 681

Other assets	1 209	1 153

Goodwill and other intangible assets	3 077	3 079

Deferred income taxes	35	35

Total assets	86 572	77 527

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	1 639	747

Current portion of long-term debt	71	70

Accounts payable and accrued liabilities	5 075	5 306

Current portion of provisions	805	769

Income taxes payable	194	244

Total current liabilities	7 784	7 136

Long-term debt	16 304	14 486

Other long-term liabilities	1 900	1 573

Provisions (note 13)	6 040	5 339

Deferred income taxes	11 609	9 954

Shareholders' equity	42 935	39 039

Total liabilities and shareholders' equity	86 572	77 527

See accompanying notes to the interim consolidated financial statements.


	Three months ended March 31
($ millions)	2016		2015

Operating Activities

Net earnings (loss)	257		(341	)

Adjustments for:

Depreciation, depletion, amortization and impairment	1 472		1 333

Deferred income taxes	(65	)	(447	)

Accretion	64		52

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(921	)	962

Change in fair value of derivative contracts	169		148

(Gain) loss on disposal of assets	(1	)	2

Share-based compensation	(163	)	(148	)

Exploration	—		49

Settlement of decommissioning and restoration liabilities	(122	)	(133	)

Other	(8	)	(2	)

Increase in non-cash working capital	(634	)	(599	)

Cash flow provided by operating activities	48		876

Investing Activities

Capital and exploration expenditures	(1 556	)	(1 326	)

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

Proceeds from disposal of assets	159		40

Other investments	(2	)	(4	)

Increase in non-cash working capital	(126	)	(47	)

Cash flow used in investing activities	(1 416	)	(1 337	)

Financing Activities

Net change in short-term debt	964		58

Net change in long-term debt	36		—

Issuance of common shares under share option plans	7		34

Dividends paid on common shares	(453	)	(405	)

Cash flow provided by (used in) financing activities	554		(313	)

Decrease in Cash and Cash Equivalents	(814	)	(774	)

Effect of foreign exchange on cash and cash equivalents	(101	)	104

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

Cash and Cash Equivalents at End of Period	3 134		4 825

Supplementary Cash Flow Information

Interest paid	86		76

Income taxes paid	131		792

See accompanying notes to the interim consolidated financial statements.


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

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

Net loss	—	—		—		—		(341	)	(341	)	—

Foreign currency translation adjustment	—	—		386		—		—		386		—

Actuarial loss on employee retirement benefit plans, net of income taxes of $10	—	—		—		—		(30	)	(30	)	—

Total comprehensive income	—	—		386		—		(371	)	15		—

Issued under share option plans	44	(5	)	—		—		—		39		1 150

Issued under dividend reinvestment plan	10	—		—		—		(10	)	—		—

Share-based compensation	—	20		—		—		—		20		—

Dividends paid on common shares	—	—		—		—		(405	)	(405	)	—

At March 31, 2015	19 365	624		890		—		20 393		41 272		1 445 269



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 income (loss)	—	—		(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

See accompanying notes to the interim consolidated financial statements.

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

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

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

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.


Three months ended March 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	1 585		1 777		531		732		3 579		4 808		(3	)	(44	)	5 692		7 273

Intersegment revenues	454		507		—		37		12		22		(466	)	(566	)	—		—

Less: Royalties	(19	)	(18	)	(29	)	(126	)	—		—		—		—		(48	)	(144	)

Operating revenues, net of royalties	2 020		2 266		502		643		3 591		4 830		(469	)	(610	)	5 644		7 129

Other income (loss)	33		58		2		116		11		21		(113	)	62		(67	)	257

	2 053		2 324		504		759		3 602		4 851		(582	)	(548	)	5 577		7 386

Expenses

Purchases of crude oil and products	140		70		—		1		2 456		3 347		(527	)	(646	)	2 069		2 772

Operating, selling and general	1 435		1 372		145		131		542		570		227		222		2 349		2 295

Transportation	184		152		23		27		92		99		(10	)	(11	)	289		267

Depreciation, depletion, amortization and impairment	917		773		356		365		170		165		29		30		1 472		1 333

Exploration	30		105		11		78		—		—		—		—		41		183

(Gain) loss on disposal of assets	(1	)	8		—		1		—		—		—		(7	)	(1	)	2

Financing (income) expenses	55		39		15		38		11		(7	)	(799	)	1 068		(718	)	1 138

	2 760		2 519		550		641		3 271		4 174		(1 080	)	656		5 501		7 990

(Loss) earnings before Income Taxes	(707	)	(195	)	(46	)	118		331		677		498		(1 204	)	76		(604	)

Income Taxes

Current	(147	)	(4	)	61		101		99		207		(129	)	(120	)	(116	)	184

Deferred	(36	)	(45	)	(73	)	(445	)	(9	)	(28	)	53		71		(65	)	(447	)

	(183	)	(49	)	(12	)	(344	)	90		179		(76	)	(49	)	(181	)	(263	)

Net (Loss) Earnings	(524	)	(146	)	(34	)	462		241		498		574		(1 155	)	257		(341	)

Capital and Exploration Expenditures	1 107		793		271		356		172		83		6		94		1 556		1 326

Suncor acquired COS to benefit from operating synergies and economies of scale expected from combining the two companies' ownership interests in Syncrude.


($ 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


($ 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

Acquisition costs of $28.7 million have been charged to Operating, Selling and General expense in the consolidated statements of comprehensive income for the period ended March 31, 2016.

COS contributed $326.4 million to gross revenues and $77.0 million to consolidated net earnings from the acquisition date to March 31, 2016.


	Three months ended March 31
($ millions)	2016		2015

Energy trading activities

Change in fair value of contracts	(24	)	7

Gains on inventory valuation	30		75

Risk management activities⁽¹⁾	(99	)	8

Investment and interest income	18		18

Renewable energy grants	—		5

Risk mitigation and insurance proceeds⁽²⁾	—		104

Change in value of transportation commitments and other	8		40

	(67	)	257

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

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


	Three months ended March 31
($ millions)	2016		2015

Interest on debt	254		210

Capitalized interest	(141	)	(93	)

Interest expense	113		117

Interest on pension and other post-retirement benefits	12		15

Accretion	64		52

Foreign exchange (gain) loss on U.S. dollar denominated debt	(921	)	962

Foreign exchange and other	14		(8	)

	(718	)	1 138

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


	Three months ended March 31
($ millions)	2016	2015

Net earnings (loss)	257	(341	)

Net earnings (loss) attributable to common shareholders	246	(341	)

(millions of common shares)

Weighted average number of common shares	1 516	1 445

Dilutive securities:

Effect of share options	1	—

Weighted average number of diluted common shares	1 517	1 445

(dollars per common share)

Basic and diluted earnings (loss) per share	0.17	(0.24	)

Basic and diluted earnings (loss) per share attributable to common shareholders	0.16	(0.24	)

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

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

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

An increase in the credit-adjusted risk-free interest rate to 4.73% (December 31, 2015 – 4.37%) resulted in a decrease in provisions of $440 million for the three months ended March 31, 2016.


	SUNCOR ENERGY INC.
Date: April 27, 2016	By:	/s/ SHAWN POIRIER Shawn Poirier Assistant Corporate Secretary


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

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	44.49	66.62

E&P Canada – Natural gas ($/mcfe)	1.36	2.23

E&P International ($/boe)	41.05	62.16


(thousands)		March 31, 2016

Common shares		1 582 011

Common share options – exercisable		21 149

Common share options – non-exercisable		14 392


	Twelve months ended March 31
($ millions)	2016		2015

Cash flow from operations	6 013		7 653

Less: Capital and exploration expenditures	6 897		6 797

Free Cash Flow	(884	)	856




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


For the month of: April, 2016		Commission File Number: 1-12384


1.	Advisories	5
2.	First Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	23
6.	Financial Condition and Liquidity	25
7.	Quarterly Financial Data	28
8.	Other Items	30
9.	Non-GAAP Financial Measures Advisory	32
10.	Common Abbreviations	35
11.	Forward-Looking Information	36


($ millions)	Energy Trading		Risk Management		Total

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

Value of contracts settled during the quarter	24		(70	)	(46	)

Changes in fair value during the quarter (note 5)	(24	)	(99	)	(123	)

Fair value outstanding at March 31, 2016	(18	)	(149	)	(167	)


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

Accounts receivable	2		29		—	31

Accounts payable	(45	)	(153	)	—	(198	)

	(43	)	(124	)	—	(167	)


($ millions)

Fair value of Kent Breeze wind farm		47

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

Fair value of deferred financing arrangement		303

Total purchase consideration		427


($ millions)

Working capital	36

Property, plant and equipment	393

Decommissioning provision	(2	)

Net assets acquired	427


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

Return on capital employed^(A)

– excluding major projects in progress (%)	(2.2	)	0.6	5.1	7.2	5.8

– including major projects in progress (%)	(1.9	)	0.5	4.5	6.3	5.0


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


DATE:		April 27, 2016		/s/ STEVEN W. WILLIAMS Steven W. Williams President and Chief Executive Officer


DATE:		April 27, 2016		/s/ ALISTER COWAN Alister Cowan Executive Vice President and Chief Financial Officer