All financial figures are unaudited and presented in Canadian dollars unless noted otherwise. Production volumes are presented on a working-interest basis, before royalties, except for Libya, which is on an entitlement basis. Certain financial measures in this 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 of Suncor's Management Discussion and Analysis dated May 1, 2019 (MD&A). See also the Advisories section of the MD&A. References to Oil Sands operations exclude Suncor's interests in Fort Hills and Syncrude.

"Suncor's integrated model has consistently generated positive results through changing market conditions, including mandatory production curtailments in Alberta, and the first quarter of 2019 was no different," said Mark Little, president and chief operating officer. "Funds from operations increased to $2.6 billion in the first quarter of 2019 as we continue to execute on our long-term strategy."

Suncor's first quarter 2019 operating earnings were $1.209 billion ($0.77 per common share), compared to $985 million ($0.60 per common share) in the prior year quarter, and included the impact of the Government of Alberta's mandatory production curtailments, as well as after-tax insurance proceeds of $264 million related to the company's assets in Libya. Operating earnings were also favourably influenced by an inventory valuation gain associated with improving crude prices, increased overall upstream production and sales volumes, narrower heavy crude oil differentials and strong sales from the company's refining assets. These factors were offset by lower WTI benchmark crude pricing and higher overall operating and transportation costs, predominantly attributed to the production ramp up at Fort Hills, an increase in share-based compensation costs and an additional 5% working interest in Syncrude acquired partway through the first quarter of 2018. Operating earnings were also unfavourably impacted by higher royalties associated with the improvement in both bitumen pricing and production.

The overall impact of crude oil and refined product inventory valuation had a net positive impact on operating earnings of $288 million in the first quarter of 2019, compared to $86 million net positive impact in the prior year quarter. The increase was due to a favourable first-in, first-out (FIFO) inventory valuation adjustment associated with the consumption of less expensive crude feedstock in R&M, partially offset by a deferral of profit on intersegment sales from Oil Sands to R&M remaining in inventory, recorded in the Corporate and Eliminations segment.

Net earnings were $1.470 billion ($0.93 per common share) in the first quarter of 2019, compared to net earnings of $789 million ($0.48 per common share) in the prior year quarter. In addition to the factors explained in operating earnings above, net earnings for the first quarter of 2019 included a $261 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt. Net earnings in the prior year quarter included an unrealized after-tax foreign exchange loss of $329 million on the revaluation of U.S. dollar denominated debt, and a $133 million non-cash after-tax gain in the Exploration and Production (E&P) segment associated with the exchange of the company's mineral landholdings in northeast British Columbia with Canbriam Energy Inc. (Canbriam). The company's investment in Canbriam was subsequently written down to nil in the fourth quarter of 2018 following an assessment of forward natural gas prices and the impact on estimated future cash flows.

Funds from operations were $2.585 billion ($1.64 per common share) in the first quarter of 2019, compared to $2.164 billion ($1.32 per common share) in the first quarter of 2018, and were influenced by the same factors impacting operating earnings noted above.

Cash flow provided by operating activities was $1.548 billion ($0.98 per common share) for the first quarter of 2019, compared to $724 million ($0.44 per common share) for the first quarter of 2018, reflecting the impact of higher commodity prices on accounts receivable and inventory. In addition to the items noted with respect to funds from operations, cash flow provided by operating activities was further impacted by the use of less cash in the company's working capital balances in the current quarter, as compared to the prior year quarter. This was due to a decrease in taxes paid and a smaller increase in the company's inventory value, with the prior year quarter including a substantial build of product inventory in preparation for the full turnaround at the Edmonton refinery in the second quarter of 2018.

Suncor's total upstream production was 764,300 barrels of oil equivalent per day (boe/d) during the first quarter of 2019, compared to 689,400 boe/d in the prior year quarter, with the increase primarily due to the ramp up of Fort Hills production, improved asset reliability at Syncrude and the Hebron ramp up. This was partially offset by the impact of mandatory production curtailments in the province of Alberta, which took effect at the beginning of the year.

"Our upgraders achieved strong reliability throughout the first quarter and our refining business generated record funds from operations, illustrating the resiliency of Suncor's cash flow and operational flexibility when broader industry challenges exist," said Mark Little.

Oil Sands operations production was 396,600 bbls/d in the first quarter of 2019, compared to 404,800 bbls/d in the prior year quarter. The decrease was due to mandatory production curtailments, which primarily affected the company's non-upgraded bitumen sales as the company maximized the production of higher value SCO barrels. Upgrader utilization improved to 98% in the first quarter of 2019, compared to 80% in the prior year quarter, with the prior year quarter being impacted by a weather-related outage. Higher upgrader utilization resulted in a decrease to total Oil Sands operations production due to the approximate 20% yield loss associated with the bitumen upgrading process.

Oil Sands operations cash operating costs per barrel⁽¹⁾ were $29.95 in the first quarter of 2019, an increase from $26.85 in the prior year quarter, reflecting the impact of mandatory production curtailments and the change in production mix associated with a higher proportion of SCO production and lower bitumen volumes, in addition to an increase in operating, selling and general (OS&G) costs. Oil Sands operations OS&G costs in the first quarter of 2019 included an increase in overburden stripping expenses during the optimal time of the year to complete this work. The company expects the increase in this activity in the current period to partially offset Oil Sands operations cash operating costs in subsequent periods, bringing Oil Sands operations cash operating costs per barrel in line with guidance for 2019. Total Oil Sands operations cash operating costs were $1.074 billion, compared to $982 million in the prior year quarter, and were also impacted by higher natural gas pricing.

Suncor's share of production from Fort Hills averaged 78,400 bbls/d in the first quarter of 2019, compared to 24,600 bbls/d in the prior year quarter, with the increase in production attributed to the ramp up of operations throughout the past year, partially offset by mandatory production curtailments. Fort Hills cash operating costs per barrel⁽¹⁾ were $29.60 in the first quarter of 2019, compared to $53.65 in the prior year quarter, with the improvement primarily attributed to the increase in production, despite the mandatory production curtailments.

Suncor's share of Syncrude production was 182,200 bbls/d in the first quarter of 2019, compared to 142,300 bbls/d in the prior year quarter. The increase in production was primarily due to stronger asset reliability, with the prior year quarter impacted by a constrained bitumen feed line and the advancement of upgrader maintenance, partially offset by the impact of mandatory production curtailments. Upgrader utilization at Syncrude improved to 90% in the first quarter of 2019, compared to 71% in the prior year quarter. To help achieve this, Suncor allocated a portion of its mandated production limit by the Alberta government to Syncrude, which reduced lower value bitumen sales at Oil Sands operations.

Syncrude cash operating costs per barrel⁽¹⁾ were $37.05 in the first quarter of 2019, a decrease from $50.75 in the prior year quarter due to the combination of higher production and lower OS&G costs resulting from a decrease in maintenance expenses, partially offset by the increase in natural gas prices.

Production volumes at E&P were 107,100 boe/d in the first quarter of 2019, compared to 117,700 boe/d in the prior year quarter. The decrease in production was primarily due to the continuing staged return of White Rose to full operations, as well as natural declines in the United Kingdom, partially offset by the increase in production from Hebron.

During the first quarter of 2019, the company received $363 million in insurance proceeds for its Libyan assets ($264 million after-tax). The proceeds may be subject to a provisional repayment that may be dependent on the future performance and cash flows from Suncor's Libyan assets.

First oil was achieved ahead of schedule at the Oda project offshore Norway in the first quarter of 2019 and is expected to ramp up to an estimated peak of 10,500 bbls/d, net to Suncor, in 2020. Suncor is a 30% partner in the project.

Refinery crude throughput was 444,900 bbls/d and refinery utilization was 96% in the first quarter of 2019, compared to 453,500 bbls/d and a utilization rate of 98% in the prior year quarter, with solid reliability achieved in both quarters. Refined products sales increased in the first quarter of 2019 to 542,800 bbls/d, compared to 512,900 bbls/d in the prior year quarter, with the increase attributed to record Canadian wholesale sales volumes and higher retail sales volumes.

Suncor's 2019 capital program is focused on the enhancement and optimization of the company's operating asset performance, safety and reliability, including projects focused on delivering increased earnings and funds from operations through further cost savings and structural margin improvements. In addition, the company is developing step-out opportunities and asset extensions within the offshore business in E&P.

Excluding capitalized interest, the company invested $875 million on capital expenditures in the first quarter of 2019, a decrease from $1.214 billion in the prior year quarter. This was due primarily to the decrease in capital associated with the staged completion and commissioning of the Fort Hills extraction plants in the first half of 2018, as well as a decrease in asset sustainment and maintenance capital associated with lower overall planned maintenance preparation expenditures following the execution of a more significant maintenance program in the spring of 2018 at both Oil Sands and R&M. Although capital spending was lower in the first quarter of 2019, the company's capital guidance range of $4.9 billion to $5.6 billion remains unchanged.

Drilling activity at Hebron is ongoing, and production continues to ramp up ahead of schedule. Other E&P activity in the first quarter included development drilling at Hibernia, White Rose and Buzzard, and development work on the West White Rose Project and the Norwegian Oda and Fenja projects.

During the first quarter of 2019, Suncor's Board of Directors approved a 17% dividend increase and up to an additional $2.0 billion in authority for share repurchases. Also in the first quarter, the company continued to return value to shareholders through dividends of $662 million, and a repurchase of $514 million of shares under its normal course issuer bid (NCIB).

Late in 2018, Suncor's chief executive officer, Steve Williams, announced that he will retire on May 2, 2019, the date of Suncor's Annual General Meeting. Mr. Williams will be replaced by Mark Little, the company's current president and chief operating officer.

"I want to thank the dedicated and talented team at Suncor for our many accomplishments over the years, and I have the utmost confidence in Mark as he leads this company into the future." said Steve Williams, chief executive officer. "The strategy we've implemented demonstrates economic, environmental and social leadership, and our value-added investments have created opportunities for thousands of employees and contractors, while also generating significant economic benefit for our shareholders, Albertans, and Canadians."


	Three months ended March 31
($ millions)	2019		2018

Net earnings	1 470		789

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(261	)	329

Non-cash gain on asset exchange⁽²⁾	—		(133	)

Operating earnings⁽¹⁾	1 209		985

(1): Operating 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): In 2018, the company recorded an after-tax gain of $133 million for the disposal of the company's mineral landholdings in northeast British Columbia in exchange for an equity stake in Canbriam. The company's investment in Canbriam was subsequently written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.

Suncor has updated its full year business environment outlook assumptions to reflect average actual year-to-date realized prices plus forward curve pricing. WCS at Hardisty has been updated to US$45.00 from US$33.00 and New York Harbor 3-2-1 crack has been updated to US$17.00 from US$18.50. As a result of the improvement in WCS at Hardisty pricing, Syncrude Crown Royalties has been updated to 9% – 12% from 5% – 8%. In addition, current income tax expense has been updated to $1.4 billion – $1.7 billion from $1.1 billion – $1.4 billion, reflecting the impact of commodity price changes and taxes payable on the insurance proceeds. For further details and advisories regarding Suncor's 2019 corporate guidance, see www.suncor.com/guidance.

The Toronto Stock Exchange (TSX) accepted a notice filed by Suncor of its intention to renew its NCIB to continue to purchase shares under its previously announced buyback program through the facilities of the TSX, New York Stock Exchange and/or alternative trading platforms. The notice provides that, beginning May 6, 2019 and ending May 5, 2020, Suncor may purchase for cancellation up to 50,252,231 common shares, which is equal to approximately 3% of Suncor's issued and outstanding common shares. As at April 30, 2019, Suncor had 1,570,983,561 common shares issued and outstanding.

The actual number of common shares that may be purchased and the timing of any such purchases will be determined by Suncor. Suncor believes that, depending on the trading price of its common shares and other relevant factors, purchasing its own common shares represents an attractive investment opportunity and is in the best interests of the company and its shareholders. The company does not expect the decision to allocate cash to repurchase shares will affect its long-term growth strategy. Pursuant to Suncor's previous NCIB, as amended on November 19, 2018, Suncor agreed that it will not purchase more than 81,695,830 common shares between May 4, 2018 and May 3, 2019. Between May 4, 2018 and April 30, 2019 and pursuant to Suncor's previous NCIB (as amended), Suncor repurchased 69,255,256 shares on the open market for approximately $3.26 billion, at a weighted average price of $47.07 per share.

Subject to the block purchase exemption that is available to Suncor for regular open market purchases under the NCIB, Suncor will limit daily purchases of Suncor common shares on the TSX in connection with the NCIB to no more than 25% (1,025,697) of the average daily trading volume of Suncor's common shares on the TSX during any trading day. Purchases under the NCIB will be made through open market purchases at market price, as well as by other means as may be permitted by the TSX and securities regulatory authorities, including by private agreements. Purchases made by private agreement under an issuer bid exemption order issued by a securities regulatory authority will be at a discount to the prevailing market price as provided in the exemption order. In the future, Suncor expects to enter into an automatic share purchase plan in relation to purchases made in connection with the NCIB.

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. We also conduct energy trading activities focused principally on the marketing and trading of crude oil, natural gas and byproducts. We also operate a renewable energy business as part of our overall portfolio of assets.

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2018, dated February 28, 2019 (the 2018 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three months ended March 31, 2019, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2018 and the 2018 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 28, 2019 (the 2018 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 MD&A, 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).

Effective January 1, 2019, the company adopted IFRS 16 Leases (IFRS 16), which replaced the previous leasing standard IAS 17 Leases (IAS 17), and requires the recognition of all leases on the balance sheet, with optional exemptions for short-term leases where the term is twelve months or less and for leases of low-value items. IFRS 16 effectively removes the classification of leases as either finance or operating leases and treats all leases as finance leases for lessees. The accounting treatment for lessors remains essentially unchanged, with the requirement to classify leases as either finance or operating. Please refer to note 3 in the company's unaudited interim Consolidated Financial Statements for the three months ended March 31, 2019 for further information. The company has selected the modified retrospective transition approach, electing to adjust opening retained earnings with no re-statement of comparative figures. As such, comparative information continues to be reported under IAS 17 and International Financial Reporting Interpretations Committee (IFRIC) 4.

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, except for Libya, which is on an entitlement basis.

Beginning in the first quarter of 2019, results from the company's Energy Trading business will be included within each of the respective operating business segments to which the respective trade relates. The Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change.

Also beginning in the first quarter of 2019, the company has revised the classification of its capital expenditures into "asset sustainment and maintenance" and "economic investment" to better reflect the types of capital investments being made by the company. There is no impact to overall capital expenditures and comparative periods have been restated to reflect this change. Refer to the Capital Investment Update section of this MD&A for further details.

References to Oil Sands operations exclude Suncor's interests in Fort Hills and Syncrude.

Certain financial measures in this MD&A – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs, refining margin, refining operating expense, discretionary free funds flow, and last-in, first-out (LIFO) inventory valuation methodology – are not prescribed by GAAP. Operating earnings (loss) is defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to the most directly comparable GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Oil Sands operations cash operating costs, Fort Hills cash operating costs, Syncrude cash operating costs and LIFO are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to the most directly comparable GAAP measures in the Segment Results and Analysis section of this MD&A. Funds from (used in) operations, ROCE, discretionary free funds flow, refining margin and refining operating expense are defined and reconciled to the most directly comparable 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 contained in this MD&A.

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)	2019		2018

Net earnings (loss)⁽¹⁾

Oil Sands	189		97

Exploration and Production	492		388

Refining and Marketing	1 009		789

Corporate and Eliminations	(220	)	(485	)

Total	1 470		789

Operating earnings (loss)⁽¹⁾⁽²⁾

Oil Sands	189		97

Exploration and Production	492		255

Refining and Marketing	1 009		789

Corporate and Eliminations	(481	)	(156	)

Total	1 209		985

Funds from (used in) operations⁽¹⁾⁽²⁾

Oil Sands	1 184		982

Exploration and Production	702		466

Refining and Marketing	1 253		911

Corporate and Eliminations	(554	)	(195	)

Total	2 585		2 164

Increase in non-cash working capital	(1 037	)	(1 440	)

Cash flow provided by operating activities	1 548		724

Capital and exploration expenditures⁽³⁾

Asset sustainment and maintenance	419		689

Economic investment	456		525

Total	875		1 214

(1): The three months ended March 31, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3): Excludes capitalized interest of $28 million in the first quarter of 2019 and $77 million in the first quarter of 2018, and now reflects the company's revised capital expenditure classification, with prior periods having been restated for this change. Refer to the Capital Investment Update section of this MD&A for further details.

Suncor's consolidated net earnings for the first quarter of 2019 were $1.470 billion, compared to $789 million for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A.


	Three months ended March 31
($ millions)	2019		2018

Net earnings	1 470		789

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(261	)	329

Non-cash gain on asset exchange⁽²⁾	—		(133	)

Operating earnings⁽¹⁾	1 209		985

(1): Operating 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 this MD&A.
(2): In 2018, the company recorded an after-tax gain of $133 million for the disposal of the company's mineral landholdings in northeast British Columbia in exchange for an equity stake in Canbriam. The company's investment in Canbriam was subsequently written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.

Suncor's first quarter 2019 operating earnings were $1.209 billion, compared to $985 million in the prior year quarter, and included the impact of the Government of Alberta's mandatory production curtailments, as well as after-tax insurance proceeds of $264 million related to the company's assets in Libya. Operating earnings were also favourably influenced by an inventory valuation gain associated with improving crude prices, increased overall upstream production and sales volumes, narrower heavy crude oil differentials and strong sales from the company's refining assets. These factors were offset by lower WTI benchmark crude pricing and higher overall operating and transportation costs, predominantly attributed to the production ramp up at Fort Hills, an increase in share-based compensation costs and the additional ownership at Syncrude. Operating earnings were also unfavourably impacted by higher royalties associated with the improvement in both bitumen pricing and production.

The overall impact of crude oil and refined product inventory valuation had a net positive impact on operating earnings of $288 million in the first quarter of 2019, compared to $86 million net positive impact in the prior year quarter. The increase was due to a favourable FIFO inventory valuation adjustment associated with the consumption of less expensive crude feedstock in R&M, partially offset by a deferral of profit on intersegment sales from Oil Sands to R&M remaining in inventory, recorded in the Corporate and Eliminations segment.

The after-tax share-based compensation expense increased to $124 million during the first quarter of 2019, compared to an expense of $82 million during the prior year quarter, as a result of a greater increase in the company's share price through the period.

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


	Average for the three months ended March 31
		2019		2018

WTI crude oil at Cushing	US$/bbl	54.90		62.90

Dated Brent crude	US$/bbl	63.20		66.80

Dated Brent/Maya crude oil FOB price differential	US$/bbl	5.00		7.70

MSW at Edmonton	Cdn$/bbl	66.45		72.45

WCS at Hardisty	US$/bbl	42.50		38.60

Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(12.40	)	(24.30	)

SYN-WTI Differential	US$/bbl	(2.30	)	(1.45	)

Condensate at Edmonton	US$/bbl	50.55		63.15

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.55		2.05

Alberta Power Pool Price	Cdn$/MWh	70.75		34.95

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	15.55		15.50

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	13.10		12.85

Portland 3-2-1 crack⁽¹⁾	US$/bbl	17.35		20.35

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	15.70		15.55

Exchange rate	US$/Cdn$	0.75		0.79

Exchange rate (end of period)	US$/Cdn$	0.75		0.78

(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, which influences SCO differentials. Price realizations in the first quarter of 2019 for sweet SCO were unfavourably impacted by a decrease in WTI at Cushing to US$54.90/bbl in the first quarter of 2019, compared to US$62.90/bbl in the prior year quarter. Suncor also produces sour SCO, the price of which is influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton decreased to $66.45/bbl compared to $72.45/bbl in the prior year quarter; however, prices for WCS at Hardisty increased to US$42.50/bbl in the first quarter of 2019, from US$38.60/bbl in the prior year quarter, as a result of improved western Canadian heavy crude differentials. Sweet and sour SCO differentials in the first quarter of 2019 were unfavourable when compared to the first quarter of 2018, although they improved significantly over the previous quarter.

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. Bitumen prices in the first quarter of 2019 were favourably impacted by improved heavy crude oil differentials.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude, which decreased to US$63.20/bbl in the first quarter of 2019, compared to US$66.80/bbl in the prior year quarter.

The cost of natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark increased to $2.55/mcf in the first quarter of 2019, from $2.05/mcf in the prior year quarter.

Suncor's refining margins are primarily influenced by 3-2-1 benchmark 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 crude

differentials. More complex refineries can earn greater refining margin by processing less expensive, heavier crudes, or lighter crudes discounted relative to the WTI benchmark. Crack spreads do not necessarily reflect the margins at a specific refinery. Crack spreads are based on current crude feedstock prices whereas actual earnings are based on FIFO inventory accounting, where a delay exists between the time that feedstock is purchased and when it is processed and sold to a third party. A FIFO loss normally reflects a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. Specific refinery margins are determined by actual crude purchase costs, refinery configuration, production mix and realized prices for refined products sales in markets unique to each refinery.

Excess electricity produced in Suncor's Oil Sands operations is sold to the Alberta Electric System Operator, with the proceeds netted against the Oil Sands operations cash operating cost per barrel metric. The Alberta power pool price increased to an average of $70.75/MWh in the first quarter of 2019, compared to $34.95/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices, while the majority of Suncor's expenditures are realized in Canadian dollars. The Canadian dollar weakened in relation to the U.S. dollar in the first quarter of 2019, as the average exchange rate decreased to US$0.75 per one Canadian dollar from US$0.79 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 2019 when compared to the prior year quarter.

Suncor also has assets and liabilities, including approximately 70% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. A decrease in the value of the Canadian dollar, relative to the U.S. dollar, from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations, while an increase in the value of the Canadian dollar, relative to the U.S. dollar, decreases the amount of Canadian dollars required to settle U.S. dollar denominated obligations.


	Three months ended March 31
($ millions)	2019		2018

Gross and intersegment revenues	4 181		3 599

Less: Royalties	(198	)	(46	)

Operating revenues, net of royalties	3 983		3 553

Net earnings⁽¹⁾	189		97

Operating Earnings⁽¹⁾⁽²⁾	189		97

Funds from operations⁽¹⁾⁽²⁾	1 184		982

(1): The three months ended March 31, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Oil Sands segment had net earnings and operating earnings of $189 million in the first quarter of 2019, compared to net and operating earnings of $97 million in the prior year quarter. The increase was due to higher overall production volumes due to increased SCO production associated with improved upgrader utilization at Oil Sands operations and Syncrude, and a full quarter of operations at Fort Hills following the ramp up through 2018, partially offset by the impact of mandatory production curtailments, which primarily impacted the company's non-upgraded bitumen production. Operating earnings were also favourably impacted by overall improved crude price realizations, partially offset by an increase in operating costs primarily relating to the ramp up at Fort Hills, a rise in overburden stripping costs at Oil Sands Base plant to advance mining operations, an increase in share-based compensation costs and an increase in natural gas prices.


	Three months ended March 31
(mbbls/d)	2019		2018

Oil Sands operations upgraded product (SCO and diesel)	350.2		287.6

Internally consumed diesel⁽²⁾	(9.0	)	(8.2	)

Total Oil Sands operations upgraded product	341.2		279.4

In Situ non-upgraded bitumen	55.4		125.4

Total Oil Sands operations production	396.6		404.8

Fort Hills bitumen	78.4		29.8

Internally upgraded bitumen from froth	—		(5.2	)

Total Fort Hills bitumen production	78.4		24.6

Syncrude (sweet SCO and diesel)	184.9		144.6

Internally consumed diesel⁽²⁾	(2.7	)	(2.3	)

Total Syncrude production	182.2		142.3

Total Oil Sands production	657.2		571.7

(1): Bitumen production from Oil Sands Base is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries, with SCO and diesel yields of approximately 79% of bitumen feedstock input. Fort Hills finished bitumen is sold directly to customers. All of the bitumen produced at Syncrude is upgraded to sweet SCO and a small amount of diesel, at an approximate yield of 85%.
(2): Both Oil Sands operations and Syncrude produce diesel, which is internally consumed in mining operations, and Fort Hills uses internally produced diesel from Oil Sands Base within its mining operations. Of the 9,000 bbls/d of internally consumed diesel at Oil Sands operations in the first quarter of 2019, 7,400 bbls/d was consumed at Oil Sands Base and 1,600 bbls/d, net, was consumed at Fort Hills. Oil Sands operations utilization rates are calculated net of Oil Sands Base internally consumed diesel, but inclusive of diesel consumed internally at Fort Hills. Syncrude utilization rates are calculated using intermediate sour production.

Oil Sands operations production was 396,600 bbls/d in the first quarter of 2019, which was comparable to 404,800 bbls/d in the prior year quarter, with the current quarter impacted by mandatory production curtailments in the province of Alberta, and the prior year quarter reflecting the impact of a weather-related outage at Oil Sands Base plant. Mandatory production curtailments primarily affected the company's non-upgraded bitumen production as the company shifted production to higher value SCO barrels. As a result of improved reliability, SCO production increased to 341,200 bbls/d in the first quarter of 2019, compared to 279,400 bbls/d in the first quarter of 2018, which represents utilization rates of 98% and 80%, respectively. Higher upgrader utilization resulted in a decrease to total Oil Sands operations production due to the approximate 20% yield loss associated with the bitumen upgrading process.

Fort Hills production increased to 78,400 bbls/d of bitumen, net to Suncor, in the first quarter of 2019, compared to 24,600 bbls/d in the prior year quarter, as a result of the successful ramp up of operations over the past year, partially offset by the impact of mandatory production curtailments.


	Three months ended March 31
(mbbls/d)	2019	2018

Oil Sands operations sales volumes

Sweet SCO	113.7	84.2

Diesel	29.0	20.4

Sour SCO	182.4	178.2

Upgraded product	325.1	282.8

In Situ non-upgraded bitumen	53.2	118.2

Oil Sands operations	378.3	401.0

Fort Hills bitumen	78.7	8.1

Syncrude	182.2	142.3

Total	639.2	551.4

Sales volumes for Oil Sands operations were 378,300 bbls/d in the first quarter of 2019, compared to 401,000 bbls/d in the prior year quarter and were influenced by the same factors as production volumes above, in addition to a build of inventory associated with timing of sales.

Bitumen sales at Fort Hills averaged 78,700 bbls/d, net to Suncor, in the first quarter of 2019, compared to 8,100 bbls/d in the first quarter of 2018, with the first quarter of 2018 reflecting a significant build of inventory as initial production made its way to customers.

Suncor's share of Syncrude production and sales was 182,200 bbls/d in the first quarter of 2019, compared to 142,300 bbls/d in the prior year quarter. The increase was primarily due to stronger reliability, with the prior year quarter impacted by a constrained bitumen feed line and the advancement of major maintenance, and the additional 5% interest in Syncrude acquired by Suncor partway through the first quarter of 2018, partially offset by the impact of mandatory production curtailments in the current quarter. Upgrader utilization at Syncrude improved to 90% in the first quarter of 2019, compared to 71% in the prior year quarter. To help achieve this, Suncor allocated a portion of its mandated production limit from the Alberta government to Syncrude.


	Three months ended March 31
	2019	2018

Oil Sands Base

Bitumen production (mbbls/d)	267.8	241.6

Bitumen ore mined (thousands of tonnes per day)	399.7	362.6

Bitumen ore grade quality (bbls/tonne)	0.67	0.67

In Situ

Bitumen production – Firebag (mbbls/d)	189.4	205.8

Steam-to-oil ratio – Firebag	2.8	2.7

Bitumen production – MacKay River (mbbls/d)	35.2	35.1

Steam-to-oil ratio – MacKay River	3.1	3.0

Total In Situ bitumen production (mbbls/d)	224.6	240.9

Total Oil Sands operations bitumen production (mbbls/d)	492.4	482.5

Fort Hills

Bitumen production (mbbls/d)	78.4	29.8

Bitumen ore mined (thousands of tonnes per day)	131.4	49.7

Bitumen ore grade quality (bbls/tonne)	0.60	0.60

Syncrude

Bitumen production (mbbls/d)	210.6	173.3

Bitumen ore mined (thousands of tonnes per day)	341.7	278.2

Bitumen ore grade quality (bbls/tonne)	0.62	0.62

Total Oil Sands bitumen production	781.4	685.6

Bitumen production at Oil Sands operations increased in the first quarter of 2019 to 492,400 bbls/d, compared with 482,500 bbls/d in the prior year quarter. The increase was primarily due to stronger upgrader reliability and the associated increase in mined bitumen volumes, partially offset by lower non-upgraded In Situ bitumen production due to mandatory production curtailments, after maximizing the volume of Firebag bitumen upgraded into SCO.

Bitumen production at Syncrude in the first quarter of 2019 increased to 210,600 bbls/d, net to Suncor, from 173,300 bbls/d in the prior year quarter. The increase was primarily due to stronger asset reliability, partially offset by the impact of mandatory production curtailments.


Net of transportation costs, but before royalties	Three months ended March 31
($/bbl)	2019		2018

Oil Sands operations

SCO and diesel	64.90		70.51

Bitumen	41.59		27.57

Crude sales basket (all products)	61.62		57.86

Crude sales basket, relative to WTI	(11.58	)	(21.76	)

Fort Hills bitumen	49.95		32.48

Syncrude – sweet SCO	67.90		76.85

Syncrude, relative to WTI	(5.30	)	(2.77	)

Average price realizations at Oil Sands operations increased to $61.62/bbl in the first quarter of 2019 from $57.86/bbl in the prior year quarter, due to narrower heavy crude oil differentials resulting from mandatory production curtailments, strong demand for heavy oil at the U.S. Gulf Coast and the impact of a weaker Canadian dollar, partially offset by a decrease in the WTI benchmark and wider SCO crude differentials.

The average price realization for Fort Hills bitumen was $49.95/bbl in the first quarter of 2019, higher than In Situ bitumen realizations due to a higher proportion of sales being made in the U.S. mid-continent and the U.S. Gulf Coast, where Suncor is able to utilize its logistics network to access favourable pricing in the U.S. market, combined with the improved quality associated with paraffinic froth-treated bitumen produced at Fort Hills. Both Fort Hills and In Situ bitumen benefited from improved heavy crude oil differentials in the first quarter of 2019.

The average price realization at Syncrude decreased to $67.90/bbl in the first quarter of 2019, from $76.85/bbl in the prior year quarter, due to the decrease in the WTI benchmark price, wider SCO differentials and the timing of sales relative to the average SYN benchmark differentials in the current period, partially offset by the impact of a weaker Canadian dollar.

Royalties for the Oil Sands segment were higher in the first quarter of 2019 compared to the prior year quarter, primarily due to improved bitumen pricing and higher overall production.

Oil Sands operating and transportation expenses for the first quarter of 2019 increased when compared to the prior year quarter, as described in detail below. See the reconciliation in the Cash Operating Costs section below for further details regarding cash operating costs and a breakdown of non-production costs by asset.

At Oil Sands operations, operating, selling and general (OS&G) costs increased when compared to the prior year quarter, due to an increase in overburden stripping expenses during the optimal time of the year to complete this work. Higher share-based compensation expense and an increase in natural gas input prices also contributed to unfavourable OS&G costs.

At Fort Hills, operating costs in the first quarter of 2019 were higher due to increased mining and plant activity following the ramp up to full operations and also included increased overburden stripping expenses to advance mining operations.

Suncor's share of Syncrude operating costs were lower than the prior year quarter, primarily attributable to a decrease in maintenance costs due to the prior year quarter including additional costs to address a constrained bitumen feed line, partially offset by the additional 5% working interest in Syncrude acquired partway through the first quarter of 2018 and an increase in natural gas prices.

Oil Sands transportation costs increased primarily as a result of the addition of sales volumes from Fort Hills, as well as higher overall production and sales volumes.

DD&A and impairment expenses and exploration expense for the first quarter of 2019 were higher compared to the prior year quarter due to an increase in In Situ exploration drilling activity at development opportunities, Meadow Creek and Lewis, which are expected to support future production.


	Three months ended March 31
($ millions, except as noted)	2019		2018

Oil Sands OS&G expense	1 973		1 875

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	1 121		1 070

Non-production costs⁽²⁾	(57	)	(34	)

Excess power capacity and other⁽³⁾	(75	)	(66	)

Inventory changes	85		12

Oil Sands operations cash operating costs⁽¹⁾	1 074		982

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	29.95		26.85

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	233		144

Non-production costs⁽²⁾	(47	)	(16	)

Inventory changes	23		16

Fort Hills cash operating costs⁽¹⁾	209		144

Fort Hills cash operating costs ($/bbl)⁽¹⁾	29.60		53.65

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	619		661

Non-production costs⁽²⁾	(12	)	(10	)

Syncrude cash operating costs⁽¹⁾	607		651

Syncrude cash operating costs ($/bbl)⁽¹⁾	37.05		50.75

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Significant non-production costs include, but are not limited to, share-based compensation expense and research expenses. Non-production costs at Fort Hills also include, but are not limited to, project start-up costs, excess power revenue from cogeneration units and an adjustment to reflect internally produced diesel from Oil Sands operations at the cost of production.
(3): Oil Sands operations excess power capacity and other includes, but is not limited to, the operational revenue impacts of excess power from a cogeneration unit and the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.

Oil Sands operations cash operating costs per barrel⁽¹⁾ were $29.95 in the first quarter of 2019, an increase from $26.85 in the prior year quarter, reflecting the change in production mix associated with a higher proportion of SCO production and lower bitumen volumes, in addition to the increase in OS&G expenses detailed above. Oil Sands operations cash operating costs in the first quarter of 2019 included costs for the advancement of overburden stripping, which the company expects will partially offset Oil Sands operations cash operating costs in subsequent periods bringing Oil Sands operations cash operating costs per barrel in line with guidance for 2019. Total Oil Sands operations cash operating costs were $1.074 billion, compared to $982 million in the prior year quarter.

In the first quarter of 2019, non-production costs, which are excluded from Oil Sands operations cash operating costs, were higher than the prior year quarter, primarily due to increased share-based compensation expense.

Excess power capacity and other costs at Oil Sands operations for the first quarter of 2019 were comparable to the prior year quarter.

Inventory changes at Oil Sands operations reflect a larger build of inventory in the first quarter of 2019, as compared to the prior year quarter, due to the timing of sales in addition to the increase in inventory value associated with a higher proportion of SCO production.

Fort Hills cash operating costs per barrel⁽¹⁾ averaged $29.60 in the first quarter of 2019, compared to $53.65 in the prior year quarter, reflecting the impact of higher production volumes in the current period, partially offset by an increase in operating

costs, as described in detail above. Non-production costs were higher than the prior year quarter due to an increase in non-cash expenses in the period, as well as higher consumption of internally sourced diesel. Inventory changes represented a larger adjustment to Fort Hills cash operating costs in the first quarter of 2019, despite a smaller draw of inventory in the current period, due to an increase in inventory value from the fourth quarter of 2018.

Syncrude cash operating costs⁽¹⁾ per barrel were $37.05 in the first quarter of 2019, compared to $50.75 in the prior year quarter, with the decrease attributable to higher production and lower operating costs. Suncor's share of Syncrude cash operating costs decreased to $607 million, from $651 million in the first quarter of 2018, as a result of the same factors that impacted Syncrude cash operating costs described above.

The company plans to complete maintenance events at Firebag, Oil Sands operations Upgrader 1 and Fort Hills during the second quarter of 2019. The anticipated impact of this maintenance, as well as additional events scheduled in the third and fourth quarter of 2019, have been reflected in the company's 2019 guidance.


	Three months ended March 31
($ millions)	2019		2018

Gross revenues⁽¹⁾	876		938

Less: Royalties⁽¹⁾	(112	)	(82	)

Operating revenues, net of royalties	764		856

Net earnings⁽²⁾	492		388

Adjusted for:

Non-cash gain on asset exchange⁽³⁾	—		(133	)

Operating Earnings⁽²⁾⁽⁴⁾	492		255

Funds from operations⁽²⁾⁽⁴⁾	702		466

(1): Production, revenues and royalties from the company's Libya operations have been presented in the E&P section of this MD&A on an entitlement basis and exclude an equal and offsetting gross up of revenues and royalties of $61 million in the first quarter of 2019 and $79 million in the first quarter of 2018, which is required for presentation purposes in the company's financial statements under the working-interest basis.
(2): The three months ended March 31, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(3): In 2018, the company recorded an after-tax gain of $133 million for the disposal of the company's mineral landholdings in northeast British Columbia in exchange for an equity stake in Canbriam. The company's investment in Canbriam was subsequently written down to nil in the fourth quarter of 2018 following the company's assessment of forward natural gas prices and the impact on estimated future cash flows.
(4): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings for the E&P segment in the first quarter of 2019 increased to $492 million, from $255 million in the prior year quarter, largely due to the receipt of $264 million, after-tax, for insurance proceeds related to the company's assets in Libya. Other factors influencing net and operating earnings were lower overall production, increased East Coast Canada operating expenses and increased royalties, partially offset by increased production at Hebron, improved crude price realizations and lower DD&A expense. The insurance proceeds received may be subject to a provisional repayment that may be dependent on the future performance and cash flows from Suncor's Libyan assets.


	Three months ended March 31
	2019	2018

E&P Canada

Terra Nova (mbbls/d)	13.2	15.4

Hibernia (mbbls/d)	25.7	26.1

White Rose (mbbls/d)	1.1	8.8

Hebron (mbbls/d)	18.3	8.2

North America Onshore (mboe/d)	—	2.0

	58.3	60.5

E&P International

Buzzard (mboe/d)	36.7	40.4

Golden Eagle (mboe/d)	10.2	14.3

United Kingdom (mboe/d)	46.9	54.7

Norway – Oda (mboe/d)	0.2	—

Libya (mbbls/d)	1.7	2.5

	48.8	57.2

Total Production (mboe/d)	107.1	117.7

Total Sales Volumes (mboe/d)	111.8	121.9

Production volumes for E&P Canada were 58,300 bbls/d in the first quarter of 2019, compared to 60,500 boe/d in the prior year quarter. The decrease in production was primarily due to an extended outage at the non-operated White Rose asset and the continuing staged return of the asset to standard operations, partially offset by the addition of production volumes from Hebron, which averaged 18,300 bbls/d in the quarter, compared to 8,200 bbls/d in the prior year quarter.

E&P International production decreased to 48,800 boe/d, from 57,200 boe/d in the prior year quarter, primarily due to natural declines in the U.K.

First oil was achieved ahead of schedule at the Oda project offshore Norway in the first quarter of 2019, where Suncor is a 30% partner in the project. The project is expected to ramp up to an estimated peak of 10,500 bbls/d, net to Suncor, in 2020.

Price realizations at both E&P Canada and E&P International in the first quarter of 2019 were higher than the prior year quarter, with the impact of a weaker Canadian dollar more than offsetting the decrease in Brent crude benchmark pricing.

E&P royalties in the first quarter of 2019 were higher than the prior year quarter due to an increase in royalty rates associated with production mix and higher pricing.

Operating and transportation expenses for the first quarter of 2019 were higher compared to the prior year quarter, primarily resulting from additional operating costs at Terra Nova related to well workovers deferred from the fourth quarter of 2018 due to severe winter weather, as well as an increase in operating costs at Hebron associated with the production ramp up.

DD&A expense in the first quarter of 2019 was lower compared to the first quarter of 2018, primarily due to lower overall production, partially offset by an increase in DD&A at Hebron associated with higher production.

Exploration expense in the first quarter of 2019 was comparable to the prior year quarter.

A planned two-week maintenance event has been scheduled to commence at Terra Nova in the second quarter of 2019. The anticipated impact of this maintenance has been reflected in the company's 2019 guidance.


	Three months ended March 31
($ millions)	2019	2018

Operating revenues	5 204	5 438

Net earnings⁽¹⁾	1 009	789

Operating Earnings⁽¹⁾⁽²⁾	1 009	789

Funds from operations⁽¹⁾⁽²⁾	1 253	911

(1): The three months ended March 31, 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M net earnings and operating earnings in the first quarter of 2019 were $1.009 billion, compared to $789 million in the prior year quarter, and represent a new quarterly record. The improvement was primarily due to a FIFO gain associated with the consumption of less expensive refinery feedstock held in inventory at the beginning of the quarter and an increase in distillate crack spreads, partially offset by lower product location differentials, narrower crude oil differentials, lower gasoline crack spreads and an increase in refinery operating expenses.

At the company level, the FIFO gain was partially offset by a deferral of intersegment profit associated with internal crude feedstock sourced from the company's Oil Sands assets, for a favourable net inventory valuation change of $288 million in the quarter.


	Three months ended March 31
	2019	2018

Crude oil processed (mbbls/d)

Eastern North America	216.2	217.8

Western North America	228.7	235.7

Total	444.9	453.5

Refinery utilization⁽¹⁾ (%)

Eastern North America	97	98

Western North America	95	98

Total	96	98

Refined product sales (mbbls/d)

Gasoline	246.7	233.7

Distillate	221.8	191.7

Other	74.3	87.5

Total	542.8	512.9

Refining margin⁽²⁾ ($/bbl)	36.35	30.50

Refining operating expense⁽²⁾ ($/bbl)	5.60	4.90

(1): Refinery utilization is the amount of crude oil and natural gas plant liquids run through crude distillation units, expressed as a percentage of the capacity of these units.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A. Refining margins per barrel include the impact of the FIFO method of inventory valuation.

Refinery crude throughput was 444,900 bbls/d in the first quarter of 2019, compared to 453,500 bbls/d in the prior year quarter. Reliability at all of the company's refineries was solid in the first quarter of 2019, despite the impact of maintenance at the Commerce City refinery in the quarter, resulting in utilization of 96%, compared to 98% in the prior year quarter.

Total refined products sales increased to 542,800 bbls/d in the first quarter of 2019, from 512,900 bbls/d in the prior year quarter, which reflects record wholesale and higher retail sales volumes in Canada.

Realized refined product gross margins were higher in the first quarter of 2019, compared to the prior year quarter, and were influenced by the following:

Marketing gross margins in the first quarter of 2019 were lower than in the prior year quarter, primarily due to competitive pricing, partially offset by the increase in wholesale and retail sales volumes.

Operating expenses in the first quarter of 2019 were higher when compared to the prior year quarter, largely due to an increase in commodity input costs, a rise in share-based compensation and additional refinery maintenance expenses.

DD&A increased in the first quarter of 2019 due to the additional depreciation associated with the right-of-use assets recorded within property, plant and equipment as part of the transition to IFRS 16, in addition to the increased depreciation associated with the significant turnarounds completed in the second quarter of 2018.

The Montreal and Sarnia refineries both have planned seven-week turnaround events scheduled to be completed in the second quarter of 2019 and planned maintenance at the Commerce City refinery, which commenced in the first quarter of 2019, is expected to be completed early in the second quarter of 2019. In addition, the Edmonton refinery has a one week maintenance event scheduled for the second quarter of 2019. The anticipated impact of these maintenance events has been reflected in the company's 2019 guidance.


	Three months ended March 31
($ millions)	2019		2018

Net (loss) earnings	(220	)	(485	)

Adjusted for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(261	)	329

Operating (loss) earnings⁽²⁾	(481	)	(156	)

Corporate	*(302*	)	(189	)

Intersegment (Elimination) Profit Realization	*(179*	)	33

Funds (used in) from operations⁽²⁾	(554	)	(195	)

(1): Beginning in the first quarter of 2019, results from the company's Energy Trading business is included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change. The results from the company's Renewable Energy business are included within Corporate results.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Corporate operating loss was $302 million for the first quarter of 2019, compared to an operating loss of $189 million for the prior year quarter, with the increased loss primarily attributable to a decrease in capitalized interest following the staged commissioning of Fort Hills in the first half of 2018, higher share-based compensation expense, an increase in interest costs and an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year quarter. The increase in interest costs was due to the additional interest expense associated with a higher balance of lease liabilities following the transition to IFRS 16 in the period, as well as the impact of the weaker Canadian dollar on U.S. dollar interest payments. Suncor capitalized $28 million of its borrowing costs in the first quarter of 2019 as part of the cost of major development assets and construction projects in progress, compared to $77 million in the prior year quarter.

Eliminations reflect the deferral or realization of profit or loss on crude oil sales from Oil Sands to Suncor's refineries. 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 2019, the company deferred $179 million of after-tax intersegment profit, compared to a realization of $33 million of after-tax intersegment profit in the prior year quarter, which was driven by the increase in Oil Sands price realizations over the previous quarter, as lower margin crude refinery feedstock inventory sourced internally from Oil Sands was sold and replaced by higher margin crude. This combined with the FIFO gain in the R&M segment resulted in a net $288 million after-tax inventory valuation gain.


	Three months ended March 31
($ millions)	2019		2018

Oil Sands	584		992

Exploration and Production	228		165

Refining and Marketing	82		117

Corporate and Eliminations	9		17

Total capital and exploration expenditures	903		1 291

Less: capitalized interest on debt	(28	)	(77	)

Capital and Exploration Expenditures, excluding capitalized interest	875		1 214

Capital and Exploration Expenditures by Type, excluding capitalized interest⁽¹⁾


	Three months ended March 31, 2019
($ millions)	Asset Sustainment and Maintenance(2)	Economic Investment(3)	Total

Oil Sands

Oil Sands Base	203	15	*218*

In Situ	21	183	*204*

Fort Hills	83	17	*100*

Syncrude	48	—	48

Exploration and Production	1	214	215

Refining and Marketing	59	22	81

Corporate and Eliminations	4	5	9

	419	456	875

(1): Capital expenditures in this table exclude capitalized interest on debt and the classification of the company's capital expenditures has been updated to "asset sustainment and maintenance" and "economic investment" to better reflect the types of capital investments being made by the company.
(2): Asset sustaining and maintenance capital expenditures include capital investments that deliver on existing value by ensuring compliance or maintaining relations with regulators and other stakeholders; maintaining current processing capacity; and delivering existing developed reserves.
(3): Economic investment capital expenditures include capital investments that result in an increase in value through adding reserves, improving processing capacity, utilization, cost or margin, including associated infrastructure.

The company spent $875 million on capital expenditures in the first quarter of 2019, excluding capitalized interest, a decrease from $1.214 billion in the prior year quarter, primarily due to the decrease in capital associated with the staged commissioning of the Fort Hills extraction plants in the first half of 2018, in addition to a decrease in asset sustainment and maintenance capital associated with lower overall planned maintenance expenditures following the completion of a more significant maintenance program in the spring of 2018 at both Oil Sands and R&M.

Oil Sands Base capital and exploration expenditures were $218 million in the first quarter of 2019, the majority of which was focused on asset sustaining and maintenance activities related to the company's planned major maintenance program, which included preparation of the spring turnaround at Upgrader 1, the continued development of tailings infrastructure, and other reliability and sustainment projects across the operations.

In Situ capital and exploration expenditures were $204 million in the first quarter of 2019 and were primarily directed towards economic investment activities, including well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Capital expenditures at Fort Hills were $100 million in the first quarter of 2019, with the majority related to asset sustaining and maintenance capital expenditures focused on mine and tailings development to support ongoing operations.

Syncrude capital and exploration expenditures were $48 million in the first quarter of 2019, all of which was for asset sustaining and maintenance capital expenditures focused on existing asset reliability.

Capital and exploration expenditures at E&P were $215 million in the first quarter of 2019 and were primarily focused on economic investment projects, including development drilling at Hebron, Hibernia, White Rose and Buzzard, and continued development work on the West White Rose Project and the Norwegian Oda and Fenja projects.

R&M capital expenditures were $81 million and were primarily related to the ongoing sustainment of operations, enhancements to retail operations and planned major refinery maintenance.

Corporate capital expenditures were $9 million, primarily directed towards the company's information technology initiatives.


	Twelve months ended
	Previous leasing standard March 31 2019	IFRS 16 impact		IFRS 16 March 31 2019	March 31 2018

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	8.3	—		8.3	7.8

Including major projects in progress	8.3	(0.1	)	8.2	6.5

Net debt to funds from operations⁽²⁾ (times)	1.5	0.1		1.6	1.7

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	7.3	(0.2	)	7.1	6.1

Funds from operations basis⁽²⁾⁽⁴⁾	14.6	(0.5	)	14.1	11.8

Total debt to total debt plus shareholders' equity (%)	28.1	2.1		30.2	28.3

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

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents and available credit facilities, including commercial paper. Suncor's management believes the company will have the capital resources to fund its planned 2019 capital spending program of $4.9 – $5.6 billion and to meet current and future working capital requirements through cash and cash equivalents balances, cash flow provided by operating activities, 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.

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

Cash and cash equivalents decreased to $1.875 billion at March 31, 2019, from $2.221 billion at December 31, 2018, with cash flow provided by operating activities and an increase in short-term indebtedness being more than offset by the planned use of cash related to the company's capital and exploration expenditures, dividend requirements and the purchase of Suncor's own shares under its NCIB program in the first quarter of 2019. The company's cash and cash equivalents balance at March 31, 2019 were impacted by a use of cash in the current period associated with the company's working capital balances, which generally occurs in the first quarter as the company settles significant payments related to income taxes and employee benefits accrued throughout the preceding year. In addition, the company's accounts receivables and inventory balances were higher as commodity prices increased in the quarter.

As at March 31, 2019, the weighted average term to maturity of the company's short-term investment portfolio was approximately ten days.

Available credit facilities for liquidity purposes at March 31, 2019 decreased to $3.442 billion, compared to $3.608 billion at December 31, 2018, which was primarily a result of the increase in short-term indebtedness noted above, partially offset by the improvement in the Canadian dollar on U.S. dollar short-term debt. In March 2019, the company extended the maturity of its syndicated credit facilities to April 2022 and April 2023.

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

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, 2019, total debt to total debt plus shareholders' equity was 30.2% (December 31, 2018 – 28.3%) and now reflects the impact of additional capital lease liabilities of $1.792 billion recorded on January 1, 2019 as part of the adoption of IFRS 16. The company continues to be in compliance with all operating covenants.


($ millions, except as noted)	March 31 2019	December 31 2018

Short-term debt	3 506	3 231

Current portion of long-term debt	187	191

Current portion of long-term lease liabilities	297	38

Long-term debt	12 446	12 668

Long-term lease liabilities	2 737	1 222

Total debt	19 173	17 350

Less: Cash and cash equivalents	1 875	2 221

Net debt	17 298	15 129

Shareholders' equity	44 262	44 005

Total debt plus shareholders' equity	63 435	61 355

Total debt to total debt plus shareholders' equity (%)	30.2	28.3


($ millions)	Three months ended March 31, 2019

Total debt – beginning of period	17 350

Net change in long-term debt	—

Increase in short-term debt	326

January 1, 2019 increase in lease liabilities associated with IFRS 16	1 792

Increase in lease liability	51

Lease payments	(70	)

Foreign exchange on debt, and other	(276	)

Total debt – March 31, 2019	19 173

Less: Cash and cash equivalents – March 31, 2019	1 875

Net debt – March 31, 2019	17 298

The company's total debt increased in the first quarter of 2019 due primarily to the impact of the adoption of IFRS 16, which added $1.792 billion in lease liability to the company's balance sheet, an increase in short-term indebtedness and new leases entered into during the period, partially offset by favourable foreign exchange rates on U.S. dollar denominated debt compared to December 31, 2018 and lease principal payments made during the first quarter of 2019.

As at April 30, 2019, the total number of common shares outstanding was 1,570,983,561 and the total number of exercisable and non-exercisable common share options outstanding was 35,370,135. Once exercisable, each outstanding common share option is convertible into one common share.

In May 2018, Suncor renewed its NCIB to continue to repurchase its common shares through the facilities of the TSX, New York Stock Exchange (NYSE) and/or alternative trading platforms between May 4, 2018 and May 3, 2019. The TSX subsequently accepted a notice filed by Suncor of its intention to amend the NCIB effective as of November 19, 2018 pursuant to which Suncor was permitted to increase the maximum number of common shares that may be purchased for cancellation between May 4, 2018 and May 3, 2019 to 81,695,830 common shares.

Subsequent to the first quarter of 2019, the TSX accepted a notice filed by Suncor of its intention to renew its NCIB to continue to repurchase shares under its share buyback program through the facilities of the TSX, NYSE and/or alternative trading platforms. The notice provides that, between May 6, 2019 and May 5, 2020, Suncor may purchase for cancellation up to 50,252,231 common shares, or approximately 3% of Suncor's issued and outstanding common shares as at April 30, 2019. Suncor security holders may obtain a copy of the notice, without charge, by contacting the company.

During the first quarter of 2019, Suncor repurchased and cancelled 11,951,027 common shares at an average price of $42.99 per share, for a total of $514 million, compared to the prior year quarter when the company repurchased and cancelled 8,999,091 common shares at an average price of $43.28 per share, for $389 million.

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

In the normal course of business, the company is obligated to make future payments, including pursuant to contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of the 2018 annual MD&A, with no significant updates during the first quarter of 2019. Suncor 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.

Trends in Suncor's quarterly revenue, earnings and funds from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events, changes in commodity prices, including widening of crude differentials, refining crack spreads, foreign exchange rates and other significant events impacting operations, such as the impact of mandatory production curtailments in Alberta during the first quarter of 2019.


Three months ended ($ millions, unless otherwise noted)	Mar 31 2019	Dec 31 2018		Sept 30 2018	June 30 2018		Mar 31 2018		Dec 31 2017		Sept 30 2017	June 30 2017

Total production (mboe/d)

Oil Sands	657.2	740.8		651.7	547.6		571.7		621.2		628.4	413.6

Exploration and Production	107.1	90.2		92.1	114.1		117.7		115.2		111.5	125.5

	764.3	831.0		743.8	661.7		689.4		736.4		739.9	539.1

Revenues and other income

Operating revenues, net of royalties	8 983	8 561		10 847	10 327		8 807		8 973		7 963	7 231

Other income (loss)	414	384		16	101		(57	)	41		43	16

	9 397	8 945		10 863	10 428		8 750		9 014		8 006	7 247

Net earnings (loss)	1 470	(280	)	1 812	972		789		1 382		1 289	435

per common share – basic (dollars)	0.93	(0.18	)	1.12	0.60		0.48		0.84		0.78	0.26

per common share – diluted (dollars)	0.93	(0.18	)	1.11	0.59		0.48		0.84		0.78	0.26

Operating Earnings⁽¹⁾	1 209	580		1 557	1 190		985		1 310		867	199

per common share – basic⁽¹⁾ (dollars)	0.77	0.36		0.96	0.73		0.60		0.79		0.52	0.12

Funds from operations⁽¹⁾	2 585	2 007		3 139	2 862		2 164		3 016		2 472	1 627

per common share – basic⁽¹⁾ (dollars)	1.64	1.26		1.94	1.75		1.32		1.83		1.49	0.98

Cash flow provided by operating activities	1 548	3 040		4 370	2 446		724		2 755		2 912	1 671

per common share – basic (dollars)	0.98	1.90		2.70	1.50		0.44		1.67		1.75	1.00

ROCE⁽¹⁾ (%) for the twelve months ended	8.3	8.0		9.7	8.3		6.5		6.7		5.5	4.9

ROCE⁽¹⁾, excluding major projects in progress (%) for twelve months ended	8.2	8.2		10.4	9.5		7.8		8.6		7.0	6.2

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	261	(637	)	195	(218	)	(329	)	(91	)	412	278

Common share information (dollars)

Dividend per common share	0.42	0.36		0.36	0.36		0.36		0.32		0.32	0.32

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	43.31	38.13		49.98	53.50		44.49		46.15		43.73	37.89

New York Stock Exchange (US$)	32.43	27.97		38.69	40.68		34.54		36.72		35.05	29.20

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


Three months ended (average for the period ended, except as noted)		Mar 31 2019		Dec 31 2018		Sept 30 2018		June 30 2018		Mar 31 2018		Dec 31 2017		Sept 30 2017		June 30 2017

WTI crude oil at Cushing	US$/bbl	54.90		58.85		69.50		67.90		62.90		55.40		48.20		48.30

Dated Brent crude	US$/bbl	63.20		67.80		75.25		74.40		66.80		61.40		52.50		49.85

Dated Brent/Maya FOB price differential	US$/bbl	5.00		4.35		10.20		12.40		7.70		9.60		6.30		5.80

MSW at Edmonton	Cdn$/bbl	66.45		42.70		82.10		80.95		72.45		69.30		57.05		62.30

WCS at Hardisty	US$/bbl	42.50		19.50		47.35		48.65		38.60		43.10		38.25		37.20

Light/heavy crude oil (differential) for WTI at Cushing less WCS at Hardisty	US$/bbl	(12.40	)	(39.35	)	(22.15	)	(19.25	)	(24.30	)	(12.30	)	(9.95	)	(11.10	)

SYN-WTI (differential) premium	US$/bbl	(2.30	)	(21.60	)	(0.90	)	(0.65	)	(1.45	)	3.25		0.65		1.55

Condensate at Edmonton	US$/bbl	50.55		45.30		66.82		68.50		63.15		57.95		47.60		48.45

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.55		1.60		1.19		1.20		1.77		1.70		1.45		2.80

Alberta Power Pool Price	Cdn$/MWh	70.75		55.55		54.45		56.00		34.95		22.35		24.55		19.30

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	15.55		16.20		19.65		20.65		15.50		19.40		22.35		16.35

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	13.10		13.35		19.05		18.30		12.85		20.20		19.25		14.40

Portland 3-2-1 crack⁽¹⁾	US$/bbl	17.35		21.60		21.40		27.90		20.35		22.10		26.80		21.25

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	15.68		15.10		18.85		20.25		15.55		18.25		21.45		16.80

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

Exchange rate (end of period)	US$/Cdn$	0.75		0.73		0.77		0.76		0.78		0.80		0.80		0.77

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

Suncor's significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2018 annual MD&A and in note 3 of Suncor's unaudited interim Consolidated Financial Statements for the three months ended March 31, 2019.

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, 2018 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2018 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 25 of the audited Consolidated Financial Statements for the year ended December 31, 2018, note 10 to the unaudited interim Consolidated Financial Statements for the three months ended March 31, 2019, and the Financial Condition and Liquidity section of Suncor's 2018 annual MD&A.

Based on their evaluation as at March 31, 2019, 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, 2019, 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, 2019 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 2019 corporate guidance, as set forth in Suncor's press release dated May 1, 2019, which is also available on www.sedar.com.

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

Operating earnings (loss) is a non-GAAP financial measure that adjusts net earnings (loss) for significant items that are not indicative of operating performance. Management uses operating earnings (loss) to evaluate operating performance because management believes it provides better comparability between periods. Operating earnings (loss) are reconciled to net earnings (loss) in the Consolidated Financial Information and Segment Results and Analysis sections of this 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 for 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)		2019	2018

Adjustments to net earnings

Net earnings		3 974	3 895

(Deduct) add after-tax amounts for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt		399	(270	)

Net interest expense		610	197

	A	4 983	3 822

Capital employed – beginning of twelve-month period

Net debt		15 603	13 216

Shareholders' equity		45 483	45 516

		61 086	58 732

Capital employed – end of twelve-month period

Net debt		17 298	15 603

Shareholders' equity		44 262	45 483

		61 560	61 086

Average capital employed	B	60 671	59 097

ROCE – including major projects in progress (%)	A/B	8.2	6.5

Average capitalized costs related to major projects in progress	C	534	10 192

ROCE – excluding major projects in progress (%)	A/(B-C)	8.3	7.8

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


Three months ended March 31(1)	Oil Sands				Exploration and Production				Refining and Marketing				Corporate and Eliminations				Total
($ millions)	2019		2018		2019		2018		2019		2018		2019		2018		2019		2018

Net earnings (loss)	189		97		492		388		1 009		789		(220	)	(485	)	1 470		789

Adjustments for:

Depreciation, depletion, amortization and impairment	992		974		247		279		203		154		20		17		1 462		1 424

Deferred income taxes	60		57		(33	)	(55	)	5		23		(29	)	4		3		29

Accretion	58		51		11		12		2		2		—		—		71		65

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		(280	)	373		(280	)	373

Change in fair value of financial instruments and trading inventory	6		(4	)	(4	)	(29	)	70		(25	)	—		7		72		(51	)

Gain on disposal of assets	(4	)	(1	)	—		(162	)	(1	)	—		—		—		(5	)	(163	)

Share-based compensation	(34	)	(64	)	(5	)	(10	)	(24	)	(35	)	(46	)	(115	)	(109	)	(224	)

Exploration	—		—		2		—		—		—		—		—		2		—

Settlement of decommissioning and restoration liabilities	(112	)	(154	)	(1	)	(13	)	(1	)	(2	)	—		—		(114	)	(169	)

Other	29		26		(7	)	56		(10	)	5		1		4		13		91

Funds from (used in) operations	1 184		982		702		466		1 253		911		(554	)	(195	)	2 585		2 164

Increase in non-cash working capital																	(1 037	)	(1 440	)

Cash flow provided by operating activities																	1 548		724

(1): Beginning in the first quarter of 2019, results from the company's Energy Trading business is included within each of the respective operating business segments to which the respective trade relates. Suncor's Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change.

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

Oil Sands operations, Syncrude and Fort Hills cash operating costs are non-GAAP financial measures. Oil Sands operations cash operating costs are calculated by adjusting Oil Sands segment OS&G expense (a GAAP measure based on sales volumes) for i) costs pertaining to Fort Hills and Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, research and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenue; iv) project start-up costs; and v) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes. Syncrude and Fort Hills cash operating costs are calculated by adjusting Syncrude OS&G expense and Fort Hills OS&G expense, respectively, for non-production costs that management believes do not relate to the production performance of Syncrude operations or Fort Hills operations, respectively, including, but not limited to, share-based compensation, research and project start-up costs, if applicable. Oil Sands operations, Fort Hills and Syncrude 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 operating performance.

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


	Three months ended March 31
($ millions, except as noted)	2019		2018

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	2 140		1 785

Other income (loss)	15		(17	)

Non-refining margin	(587	)	(415	)

Refining margin	1 568		1 353

Refinery production⁽¹⁾ (mbbls)	43 143		44 363

Refining margin ($/bbl)	36.35		30.50

Refining operating expense reconciliation

OS&G expense	536		492

Non-refining costs	(294	)	(274	)

Refining operating expense	242		218

Refinery production⁽¹⁾ (mbbls)	43 143		44 363

Refining operating expense ($/bbl)	5.60		4.90

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

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

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

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

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


Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		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	SYN	Synthetic crude oil benchmark
mmcf/d	millions of cubic feet of natural gas per day	MSW	Mixed Sweet Blend
mmcfe	millions of cubic feet of natural gas equivalent	NYMEX	New York Mercantile Exchange
mmcfe/d	millions of cubic feet of natural gas equivalent	YTD	Year to date
	per day
MW	Megawatts
MWh	megawatts per hour

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

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

Factors that affect Suncor's 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 the company's proprietary production will be closed, experience equipment failure or other accidents; Suncor's ability to operate its 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; Suncor's dependence on pipeline capacity and other logistical constraints, which may affect the company's ability to distribute products to market and which may cause the company to delay or cancel planned growth projects in the event of insufficient takeaway capacity; Suncor's ability to finance Oil Sands economic investment and asset sustainment and maintenance 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; changes in operating costs, including the cost of labour, natural gas and other energy sources used in oil sands processes; and the company's 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).

Factors that affect Suncor's 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; 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 market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect our R&M segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; the company's ability to reliably operate refining and marketing facilities in order to meet production or sales targets; and 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.

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; risks associated with the development and execution of Suncor's projects and the commissioning and integration of new facilities; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; the risk that projects and initiatives intended to achieve cash flow growth and/or reductions in operating costs may not achieve the expected results in the time anticipated or at all; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties and other government-imposed compliance costs; changes to laws and government policies that could impact the company's business, including environmental (including climate change), royalty and tax laws and policies; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to the company; the unavailability of, or outages to, third-party infrastructure that could cause disruptions to production or prevent the company from being able to transport its products; the occurrence of a protracted operational outage, a major safety or environmental incident, or unexpected events such as fires (including forest fires), equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information technology and infrastructure by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; security threats and terrorist or activist activities; the risk that competing business objectives may exceed Suncor's capacity to adopt and implement change; risks and uncertainties associated with obtaining regulatory, third-party and stakeholder approvals outside of Suncor's control for the company's operations, projects, initiatives, and exploration and development activities and the satisfaction of any conditions to approvals; the potential for disruptions to operations and construction projects as a result of Suncor's relationships with labour unions that represent employees at the company's facilities; the company's 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 or to issue other securities at acceptable prices; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset or oil and gas property, including estimates of the final consideration to be paid or received; the ability of counterparties to comply with their obligations in a timely manner; risks associated with joint arrangements in which the company has an interest; risks associated with land claims and Aboriginal consultation requirements; the risk that the company may be subject to litigation; the impact of technology and risks associated with developing and implementing new technologies; 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 2018 annual MD&A, 2018 AIF and most recent Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

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


	Three months ended March 31
($ millions)	2019		2018

Revenues and Other Income

Operating revenues, net of royalties (note 4)	8 983		8 807

Other income (loss) (note 5)	414		(57	)

	9 397		8 750

Expenses

Purchases of crude oil and products	2 621		2 847

Operating, selling and general	2 832		2 620

Transportation	336		274

Depreciation, depletion, amortization and impairment	1 462		1 424

Exploration	113		32

Gain on asset exchange and disposals (note 15)	(5	)	(163	)

Financing expenses (note 7)	32		562

	7 391		7 596

Earnings before Income Taxes	2 006		1 154

Income Tax Expense

Current	533		336

Deferred	3		29

	536		365

Net Earnings	1 470		789

Other Comprehensive (Loss) Income

Items That May be Subsequently Reclassified to Earnings:

Foreign currency translation adjustment	(68	)	129

Items That Will Not be Reclassified to Earnings:

Actuarial loss on employee retirement benefit plans, net of income taxes	(136	)	(10	)

Other Comprehensive (Loss) Income	(204	)	119

Total Comprehensive Income	1 266		908

Per Common Share (dollars) (note 8)

Net earnings – basic and diluted	0.93		0.48

Cash dividends	0.42		0.36

See accompanying notes to the condensed interim consolidated financial statements.


($ millions)	March 31 2019	December 31 2018

Assets

Current assets

Cash and cash equivalents	1 875	2 221

Accounts receivable	4 271	3 206

Inventories	3 650	3 159

Income taxes receivable	149	114

Total current assets	9 945	8 700

Property, plant and equipment, net (note 12)	76 347	74 245

Exploration and evaluation	2 372	2 319

Other assets	1 260	1 126

Goodwill and other intangible assets	3 060	3 061

Deferred income taxes	183	128

Total assets	93 167	89 579

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	3 506	3 231

Current portion of long-term debt	187	229

Current portion of long-term lease liabilities (note 3)	297	—

Accounts payable and accrued liabilities	5 912	5 647

Current portion of provisions	719	667

Income taxes payable	680	535

Total current liabilities	11 301	10 309

Long-term debt	12 446	13 890

Long-term lease liabilities (note 3)	2 737	—

Other long-term liabilities (note 10)	2 481	2 346

Provisions (note 11)	7 887	6 984

Deferred income taxes	12 053	12 045

Equity	44 262	44 005

Total liabilities and shareholders' equity	93 167	89 579

See accompanying notes to the condensed interim consolidated financial statements.


	Three months ended March 31
($ millions)	2019		2018

Operating Activities

Net Earnings	1 470		789

Adjustments for:

Depreciation, depletion, amortization and impairment	1 462		1 424

Deferred income tax expense	3		29

Accretion	71		65

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(280	)	373

Change in fair value of financial instruments and trading inventory	72		(51	)

Gain on asset exchange and disposals (note 15)	(5	)	(163	)

Share-based compensation	(109	)	(224	)

Exploration	2		—

Settlement of decommissioning and restoration liabilities	(114	)	(169	)

Other	13		91

Increase in non-cash working capital	(1 037	)	(1 440	)

Cash flow provided by operating activities	1 548		724

Investing Activities

Capital and exploration expenditures	(903	)	(1 291	)

Acquisitions (notes 13 and 14)	—		(1 068	)

Proceeds from disposal of assets	7		—

Other investments (note 15)	(57	)	(57	)

(Increase) decrease in non-cash working capital	(34	)	243

Cash flow used in investing activities	(987	)	(2 173	)

Financing Activities

Net increase in short-term debt	326		1 745

Net decrease in long-term debt	—		(17	)

Change in long-term lease liability	(70	)	—

Issuance of common shares under share option plans	35		69

Purchase of common shares (note 9)	(514	)	(389	)

Distributions relating to non-controlling interest	(2	)	—

Dividends paid on common shares	(662	)	(590	)

Cash flow (used in) provided by financing activities	(887	)	818

Decrease in Cash and Cash Equivalents	(326	)	(631	)

Effect of foreign exchange on cash and cash equivalents	(20	)	42

Cash and cash equivalents at beginning of period	2 221		2 672

Cash and Cash Equivalents at End of Period	1 875		2 083

Supplementary Cash Flow Information

Interest paid	154		107

Income taxes paid	116		617

See accompanying notes to the condensed interim consolidated financial statements.


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

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

Net earnings	—		—		—		789		789		—

Foreign currency translation adjustment	—		—		129		—		129		—

Actuarial loss on employee retirement benefit plans, net of income taxes of $4	—		—		—		(10	)	(10	)	—

Total comprehensive income	—		—		129		779		908		—

Issued under share option plans	91		(21	)	—		—		70		1 832

Purchase of common shares for cancellation (note 9)	(145	)	—		—		(244	)	(389	)	(8 999	)

Change in liability for share purchase commitment	25		—		—		54		79		—

Share-based compensation	—		22		—		—		22		—

Dividends paid on common shares	—		—		—		(590	)	(590	)	—

At March 31, 2018	26 577		568		938		17 400		45 483		1 633 816

At December 31, 2018	25 910		540		1 076		16 479		44 005		1 584 484

At January 1, 2019	25 910		540		1 076		16 479		44 005		1 584 484

Adoption of IFRS 16 impact (note 3)	—		—		—		14		14		—

At January 1, 2019, adjusted	25 910		540		1 076		16 493		44 019		1 584 484

Net earnings	—		—		—		1 470		1 470		—

Foreign currency translation adjustment	—		—		(68	)	—		(68	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $50	—		—		—		(136	)	(136	)	—

Total comprehensive (loss) income	—		—		(68	)	1 334		1 266		—

Issued under share option plans	46		(10	)	—		—		36		1 025

Purchase of common shares for cancellation (note 9)	(193	)	—		—		(321	)	(514	)	(11 951	)

Change in liability for share purchase commitment (note 9)	48		—		—		45		93		—

Share-based compensation	—		24		—		—		24		—

Dividends paid on common shares	—		—		—		(662	)	(662	)	—

At March 31, 2019	25 811		554		1 008		16 889		44 262		1 573 558

See accompanying notes to the condensed 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, offshore oil and gas production, petroleum refining, and product marketing, primarily under the Petro-Canada brand.

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 (IASB). 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 of the company for the year ended December 31, 2018.

The consolidated financial statements are prepared on a historical cost basis except as detailed in the accounting policies disclosed in the company's consolidated financial statements for the year ended December 31, 2018. Adoption of the new accounting pronouncements are described in note 3.

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, 2018.

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

Effective January 1, 2019, the company adopted IFRS 16 Leases (IFRS 16) which replaces IAS 17 Leases (IAS 17) and requires the recognition of most leases on the balance sheet. IFRS 16 effectively removes the classification of leases as either finance or operating leases and treats all leases as finance leases for lessees with optional exemptions for short-term leases where the term is twelve months or less. The accounting treatment for lessors remains essentially unchanged, with the requirement to classify leases as either finance or operating.

The company has selected the modified retrospective transition approach, electing to adjust opening retained earnings with no restatement of comparative figures. As such, comparative information continues to be reported under IAS 17 and International Financial Reporting Interpretations Committee (IFRIC) 4. The details of accounting policies under IAS 17 and IFRIC 4 are disclosed separately if they are different from those under IFRS 16 and the impact of the change is disclosed below.

At inception of a contract, the company assesses whether a contract is, or contains, a lease based on whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

The company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured based on the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received. The assets are depreciated to the earlier of the end of the useful life of the right-of-use asset or the lease term using the straight-line method as this most closely reflects the expected pattern of consumption of the future economic benefits. In addition, the right-of-use assets may be periodically reduced by impairment losses, if any, and adjusted for certain re-measurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the company's incremental borrowing rate. The company uses its incremental borrowing rate as the discount rate. Lease payments include fixed payments, and variable payments that are based on an index or a rate.

Cash payments for the principal portion of the lease liability are presented within the financing activities and the interest portion of the lease liability is presented within the operating activities of the statement of cash flows. Short-term lease payments and variable lease payments not included in the measurement of the lease liability are presented within the operating activities of the statement of cash flows.

The lease liability is measured at amortized cost using the effective interest method. It is re-measured when there is a change in future lease payments arising from a change in an index or rate, if there is a change in the company's estimate of the amount expected to be payable under a residual value guarantee, or if the company changes its assessment of whether it will exercise a purchase, extension or termination option.

When the lease liability is re-measured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

In the comparative period, the company classified leases that transfer substantially all of the risks and rewards of ownership as finance leases. When this was the case, the leased assets were measured initially at an amount equal to the lower of their fair value and the present value of minimum lease payments. Minimum lease payments were the payments over the lease term that the lessee was required to make, excluding any contingent rent.

Subsequently, the assets were accounted for in accordance with the accounting policy applicable to that asset.

Assets held under other leases were classified as operating leases and were not recognized in the company's statement of financial position. Payments made under operating leases were recognized in profit or loss on a straight-line basis over the term of the lease. Lease incentives received were recognized as an integral part of the total lease expense over the term of the lease.

As part of the initial application of IFRS 16, the company also chose to apply the following transitional provisions:

The company applied the following practical expedients when applying IFRS 16 to leases previously classified as operating leases under IAS 17:

The following table reconciles the company's operating lease obligations at December 31, 2018, as previously disclosed in the company's consolidated financial statements, to the lease obligations recognized on initial application of IFRS 16 at January 1, 2019.

The following table summarizes the impact of adopting IFRS 16 on the company's consolidated balance sheets at January 1, 2019. Prior period amounts have not been restated. The effects of the transition have been recognized through retained earnings in equity.


($ millions) increase (decrease)	December 31 2018	Adjustments due to IFRS 16	January 1 2019

Assets

Current assets

Accounts receivable	3 206	(2)	3 204

Property, plant and equipment, net	74 245	(1 267)	72 978

Right-of-use assets, net	—	3 059	3 059

Liabilities and Shareholders' Equity

Current liabilities

Current portion of long-term debt	229	(38)	191

Current portion of lease liabilities	—	276	276

Current portion of provisions	667	(1)	666

Long-term debt	13 890	(1 222)	12 668

Long-term lease liabilities	—	2 777	2 777

Other long-term liabilities	2 346	(1)	2 345

Provisions	6 984	(20)	6 964

Deferred income taxes	12 045	5	12 050

Equity	44 005	14	44 019

For leases that were classified as finance leases under IAS 17, the carrying amount of the right-of-use asset and the lease liability at January 1, 2019 were determined as the carrying amount of the lease asset and lease liability under IAS 17 immediately before that date.

The lease liabilities recognized in accordance with IFRS 16 were discounted using the company's incremental borrowing rate upon adoption. The weighted average rate of additional leases recognized in accordance with IFRS 16 was 3.85% as at January 1, 2019.

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 and Eliminations				Total
($ millions)	2019		2018		2019		2018		2019		2018		2019		2018		2019		2018

Revenues and Other Income

Gross revenues	3 219		2 571		937		1 017		5 190		5 417		8		9		9 354		9 014

Intersegment revenues	962		1 028		—		—		14		21		(976	)	(1 049	)	—		—

Less: Royalties	(198	)	(46	)	(173	)	(161	)	—		—		—		—		(371	)	(207	)

Operating revenues, net of royalties	3 983		3 553		764		856		5 204		5 438		(968	)	(1 040	)	8 983		8 807

Other income (loss)	10		15		386		(58	)	15		(17	)	3		3		414		(57	)

	3 993		3 568		1 150		798		5 219		5 421		(965	)	(1 037	)	9 397		8 750

Expenses

Purchases of crude oil and products	273		270		—		—		3 064		3 653		(716	)	(1 076	)	2 621		2 847

Operating, selling and general	1 973		1 875		148		111		536		492		175		142		2 832		2 620

Transportation	298		226		19		24		29		38		(10	)	(14	)	336		274

Depreciation, depletion, amortization and impairment	992		974		247		279		203		154		20		17		1 462		1 424

Exploration	102		23		11		9		—		—		—		—		113		32

Gain on asset exchange and disposals	(4	)	(1	)	—		(162	)	(1	)	—		—		—		(5	)	(163	)

Financing expenses (income)	69		77		14		1		13		3		(64	)	481		32		562

	3 703		3 444		439		262		3 844		4 340		(595	)	(450	)	7 391		7 596

Earnings (Loss) before Income Taxes	290		124		711		536		1 375		1 081		(370	)	(587	)	2 006		1 154

Income Tax Expense (Recovery)

Current	41		(30	)	252		203		361		269		(121	)	(106	)	533		336

Deferred	60		57		(33	)	(55	)	5		23		(29	)	4		3		29

	101		27		219		148		366		292		(150	)	(102	)	536		365

Net Earnings (Loss)	189		97		492		388		1 009		789		(220	)	(485	)	1 470		789

Capital and Exploration Expenditures	584		992		228		165		82		117		9		17		903		1 291

(1): The company adopted IFRS 16 on January 1, 2019 using the modified retrospective transition approach and, therefore, prior periods have not been restated. Refer to note 3 for further information.
(2): Beginning in the first quarter of 2019, results from the company's Energy Trading business are included within each of the respective operating business segments to which the respective trade relates. The Energy Trading business was previously reported within the the Corporate, Energy Trading and Eliminations segment. Prior periods have been restated to reflect this change. The results from the company's Renewable Energy business are included within Corporate and Eliminations segment.

Disaggregation of Revenue from Contracts with Customers and Intersegment Revenue

The company derives revenue from the transfer of goods mainly at a point in time in the following major commodities, revenue streams and geographical regions:


For the three months ended March 31	2019					2018
($ millions)	North America		International	Total		North America		International	Total

Oil Sands

SCO and diesel	3 278		—	3 278		2 950		—	2 950

Bitumen	903		—	903		649		—	649

	4 181		—	4 181		3 599		—	3 599

Exploration and Production

Crude oil and natural gas liquids	491		444	935		481		529	1 010

Natural gas	—		2	2		3		4	7

	491		446	937		484		533	1 017

Refining and Marketing

Gasoline	2 106		—	2 106		2 388		—	2 388

Distillate	2 383		—	2 383		2 290		—	2 290

Other	715		—	715		760		—	760

	5 204		—	5 204		5 438		—	5 438

Corporate and Eliminations

	(968	)	—	(968	)	(1 040	)	—	(1 040	)

Total Revenue from Contracts with Customers	8 908		446	9 354		8 481		533	9 014


	Three months ended March 31
($ millions)	2019		2018

Energy trading activities

Unrealized gains (losses) recognized in earnings	95		(14	)

(Losses) gains on inventory valuation	(23	)	16

Risk management activities⁽¹⁾	(57	)	(25	)

Investment and interest income	50		9

Insurance proceeds⁽²⁾	363		—

Other	(14	)	(43	)

	414		(57	)

(1): Includes fair value changes related to short-term derivative contracts in the Oil Sands and Refining and Marketing segments.
(2): Insurance proceeds for Libyan assets within Exploration and Production segment (note 15).

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)	2019		2018

Interest on debt	210		209

Interest on lease liabilities (note 3)	45		—

Capitalized interest	(28	)	(77	)

Interest expense	227		132

Interest on partnership liability	14		14

Interest on pension and other post-retirement benefits	15		14

Accretion	71		65

Foreign exchange (gain) loss on U.S. dollar denominated debt	(280	)	373

Foreign exchange and other	(15	)	(36	)

	32		562


	Three months ended March 31
($ millions)	2019	2018

Net earnings	1 470	789

(millions of common shares)

Weighted average number of common shares	1 579	1 639

Dilutive securities:

Effect of share options	3	5

Weighted average number of diluted common shares	1 582	1 644

(dollars per common share)

Basic and diluted earnings per share	0.93	0.48

On May 1, 2018, the company announced its intention to renew its existing normal course issuer bid (the 2018 NCIB) to continue to repurchase shares through the facilities of the Toronto Stock Exchange (TSX), New York Stock Exchange (NYSE) and/or alternative trading platforms. Pursuant to the 2018 NCIB, the company was permitted to purchase for cancellation up to 52,285,330 of its common shares between May 4, 2018 and May 3, 2019. On November 14, 2018, Suncor announced an amendment to the 2018 NCIB, effective as of November 19, 2018, which allowed the company to increase the maximum number of aggregate common shares that may be repurchased between May 4, 2018 and May 3, 2019 to 81,695,830.

During the first quarter of 2019, the company repurchased 12.0 million common shares under the 2018 NCIB at an average price of $42.99 per share, for a total repurchase cost of $514 million.

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

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

On May 1, 2019, the TSX accepted a notice filed by Suncor of its intention to renew its normal course issuer bid to continue to purchase shares under its previously announced buyback program through the facilities of the TSX, NYSE and/or alternative trading platforms. The notice provides that, beginning May 6, 2019 and ending May 5, 2020, Suncor may purchase for cancellation up to 50,252,231 common shares, which is equal to approximately 3% of Suncor's issued and outstanding common shares as at April 30, 2019.

The changes in the fair value of non-designated Energy Trading and Risk Management derivatives are as follows:

To estimate the fair value of derivatives, the company uses quoted market prices when available, or third-party models and valuation methodologies that utilize observable market data. In addition to market information, the company incorporates transaction-specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

In forming estimates, the company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement.

The following table presents the company's financial instruments measured at fair value for each hierarchy level as at March 31, 2019:

During the first quarter of 2019, there were no transfers between Level 1 and Level 2 fair value measurements.

At March 31, 2019, the carrying value of fixed-term debt accounted for under amortized cost was $12.6 billion (December 31, 2018 – $12.9 billion) and the fair value was $14.8 billion (December 31, 2018 – $14.2 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

Suncor's decommissioning and restoration provision increased by $921 million for the three months ended March 31, 2019. The increase was primarily due to a decrease in the credit-adjusted risk-free interest rate to 3.50% (December 31, 2018 – 4.20%). This increase was partially offset by the liabilities settled during the period.

The company has lease contracts which include storage tanks, railway cars, vessels, buildings, land and mobile equipment for the purpose of production, storage and transportation of crude oil and related products.


($ millions)	Plant and Equipment

Cost

At January 1, 2019	3 326

Additions and adjustments	51

Foreign exchange	(2	)

At March 31, 2019	3 375

Accumulated provision

At January 1, 2019	267

Depreciation	84

At March 31, 2019	351

Net ROU assets

At January 1, 2019	3 059

At March 31, 2019	3 024

During the first quarter of 2018, Suncor acquired an additional 1.05% interest in the Fort Hills project for consideration of $145 million. The additional interest was an outcome of the commercial dispute settlement agreement reached among the Fort Hills partners in December 2017. Teck Resources Limited (Teck) also acquired an additional 0.42% in the project. Suncor's share in the project has increased to 54.11% and Teck's has increased to 21.31%, with Total E&P Canada Ltd.'s share decreasing to 24.58%.

On February 23, 2018, Suncor completed the purchase of an additional 5% working interest in the Syncrude project from Mocal Energy Limited for $923 million cash. Suncor's share in the Syncrude project has increased to 58.74%.

The acquisition has been accounted for as a business combination using the acquisition method. The purchase price allocation is based on management's best estimates of fair values of Syncrude's assets and liabilities as at February 23, 2018.


($ millions)

Accounts receivable	2

Inventory	15

Property, plant and equipment	998

Exploration and evaluation	163

Total assets acquired	1 178

Accounts payable and accrued liabilities	(51	)

Employee future benefits	(33	)

Decommissioning provision	(169	)

Deferred income taxes	(2	)

Total liabilities assumed	(255	)

Net assets acquired	923

The fair values of accounts receivable and accounts payable approximate their carrying values due to the short-term maturity of the instruments. The fair value of 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.

The additional working interest in Syncrude contributed $29 million to gross revenues and a $4 million net loss to consolidated net earnings (loss) from the acquisition date to March 31, 2018.

Had the acquisition occurred on January 1, 2018, the additional working interest would have contributed an additional $64 million to gross revenues and $4 million to consolidated net earnings, which would have resulted in gross revenues of $9.1 billion and consolidated net earnings of $793 million for the three months ended March 31, 2018.

During the first quarter of 2019, the company received $363 million in insurance proceeds for its Libyan assets ($264 million after-tax). The proceeds may be subject to a provisional repayment, which may be dependent on the future performance and cash flows from Suncor's Libyan assets.

On September 29, 2018, Suncor along with the other working interest partners in the Joslyn Oil Sands Mining Project, agreed to sell 100% of their respective working interests to Canadian Natural Resources Limited for gross proceeds of $225 million, $82.7 million net to Suncor. Suncor held a 36.75% working interest in Joslyn prior to the transaction. The working-interest partners received cash proceeds of $100 million ($36.8 million net to Suncor) upon closing with the remaining $125 million ($45.9 million net to Suncor) to be received in equal instalments over the next five years. As a result, Suncor has recorded a long-term receivable of $36.7 million within the Other Assets line item and the first instalment of $9.2 million is recorded within the Accounts Receivable line item. The transaction resulted in a gain of $83 million in the Oil Sands segment.

On May 31, 2018, the company completed the previously announced transaction to acquire a 17.5% interest in the Fenja development project in Norway from Faroe Petroleum Norge AS for acquisition costs of US$55 million (approximately $70 million), plus interim settlement costs of $22 million under the acquisition method. This project was sanctioned by its owners in December 2017.

On March 23, 2018, Suncor completed an exchange of its northeast British Columbia mineral landholdings, including associated production, and consideration of $52 million for a 37% equity interest in Canbriam Energy Inc. (Canbriam) (a private natural gas company). The investment was initially recorded at $277 million and was accounted for using the equity method of accounting. As a result of the asset transfer at that time, Suncor originally recognized a gain of $162 million in the Exploration and Production segment after eliminating a portion of the gain against the investment value. In the fourth quarter of 2018, the company wrote down its interest in Canbriam as a result of the company's assessment of expected future commodity prices and net cash flows relative to its investment, for a net loss for the year of $90 million after-tax. The remaining carrying value of the company's interest in Canbriam is nil.

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
QUARTERLY FINANCIAL SUMMARY
(unaudited)


	Three months ended															Twelve months ended
($ millions, except per share amounts)	Mar 31 2019			Dec 31 2018			Sep 30 2018			Jun 30 2018			Mar 31 2018			Dec 31 2018

Revenues, net of royalties, and other income		9 397			8 945			10 863			10 428			8 750			38 986

Net earnings (loss)^(A)

Oil Sands		189			(377	)		822			403			97			945

Exploration and Production		492			(115	)		222			312			388			807

Refining and Marketing		1 009			762			932			671			789			3 154

Corporate and Eliminations		(220	)		(550	)		(164	)		(414	)		(485	)		(1 613	)

		1 470			(280	)		1 812			972			789			3 293

Operating earnings (loss)^(A)(B)

Oil Sands		189			(377	)		762			403			97			885

Exploration and Production		492			108			222			312			255			897

Refining and Marketing		1 009			762			932			671			789			3 154

Corporate and Eliminations		(481	)		87			(359	)		(196	)		(156	)		(624	)

		1 209			580			1 557			1 190			985			4 312

Funds from (used in) operations^(A)(B)

Oil Sands		1 184			607			1 884			1 491			982			4 964

Exploration and Production		702			331			443			539			466			1 779

Refining and Marketing		1 253			873			1 122			892			911			3 798

Corporate and Eliminations		(554	)		196			(310	)		(60	)		(195	)		(369	)

Total Funds from operations		2 585			2 007			3 139			2 862			2 164			10 172

Change in non-cash working capital		(1 037	)		1 033			1 231			(416	)		(1 440	)		408

Cash flow provided by operating activities		1 548			3 040			4 370			2 446			724			10 580

Per common share

Net earnings (loss) – basic		0.93			(0.18	)		1.12			0.60			0.48			2.03

Net earnings (loss) – diluted		0.93			(0.18	)		1.11			0.59			0.48			2.02

Operating earnings – basic^(B)		0.77			0.36			0.96			0.73			0.60			2.65

Cash dividends – basic		0.42			0.36			0.36			0.36			0.36			1.44

Funds from operations – basic^(B)		1.64			1.26			1.94			1.75			1.32			6.27

Cash flow provided by operating activities – basic		0.98			1.90			2.70			1.50			0.44			6.54


	For the twelve months ended
	Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Mar 31 2018

Return on capital employed^(B)

– excluding major projects in progress (%)		8.3		8.2		10.4		9.5		7.8

– including major projects in progress (%)		8.2		8.0		9.7		8.3		6.5

(A): Comparative figures from 2018 have been restated to reflect the change to the company's segmented presentation of its Energy Trading business, with no impact to overall consolidated results. The Energy Trading business is now included within each of the respective operating business segments to which the respective trade relates, where previously Suncor's Energy Trading business results were reported within the Corporate, Energy Trading and Eliminations segment.
(B): Non-GAAP financial measures. See the Operating Summary Information – Non-GAAP Financial Measures section of this Quarterly Report.


	Three months ended										Twelve months ended
Oil Sands	Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Mar 31 2018		Dec 31 2018

Total Production (mbbls/d)		657.2		740.8		651.7		547.6		571.7		628.6

Oil Sands operations

Upgraded product (sweet SCO, sour SCO and diesel)		341.2		273.4		330.1		237.9		279.4		280.3

Non-upgraded bitumen		55.4		159.3		146.0		121.0		125.4		138.0

Oil Sands operations production		396.6		432.7		476.1		358.9		404.8		418.3

Bitumen production (mbbls/d)

Mining		267.8		278.3		323.4		195.4		241.6		258.8

In Situ – Firebag		189.4		197.2		211.0		201.9		205.8		204.0

In Situ – MacKay River		35.2		37.0		37.1		34.4		35.1		36.0

Total bitumen production		492.4		512.5		571.5		431.7		482.5		498.8

Sales (mbbls/d)

Light sweet crude oil		113.7		110.2		129.5		59.6		84.2		96.1

Diesel		29.0		27.6		34.7		32.4		20.4		28.8

Light sour crude oil		182.4		150.7		162.8		159.0		178.2		162.6

Upgraded product (SCO and diesel)		325.1		288.5		327.0		251.0		282.8		287.5

Non-upgraded bitumen		53.2		172.0		131.4		113.7		118.2		134.0

Sales		378.3		460.5		458.4		364.7		401.0		421.5

Oil Sands operations cash operating costs – Average^(1)(B) ($/bbl)*

Cash costs		27.15		22.80		21.05		27.45		25.05		23.85

Natural gas		2.80		1.70		0.95		1.20		1.80		1.40

		29.95		24.50		22.00		28.65		26.85		25.25

Mining cash operating costs^(1)(B) ($/bbl)

Cash costs		27.80		23.65		20.35		32.15		26.50		25.20

Natural gas		1.00		0.35		0.15		0.30		0.65		0.35

		28.80		24.00		20.50		32.45		27.15		25.55

In Situ cash operating costs^(1)(B) ($/bbl)

Cash costs		6.10		5.75		6.20		6.10		6.55		6.15

Natural gas		3.80		2.55		1.85		1.80		3.00		2.30

		9.90		8.30		8.05		7.90		9.55		8.45

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

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended											Twelve months ended
Oil Sands	Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Mar 31 2018			Dec 31 2018

Fort Hills

Bitumen production (mbbls/d)		78.4		98.5		69.4		70.9		29.8			67.4

Internally upgraded bitumen from froth (mbbls/d)		—		—		—		—		(5.2	)		(1.3	)

Total Fort Hills Bitumen Production		78.4		98.5		69.4		70.9		24.6			66.1

Bitumen sales (mbbls/d)		78.7		94.6		61.6		64.0		8.1			57.3

Fort Hills cash operating costs^(1)(B) ($/bbl)

Cash costs		27.70		23.85		32.55		27.60		50.45			30.00

Natural gas		1.90		1.00		0.90		0.95		3.20			1.20

		29.60		24.85		33.45		28.55		53.65			31.20

Syncrude

Sweet SCO production (mbbls/d)		182.2		209.6		106.2		117.8		142.3			144.2

Bitumen production (mbbls/d)		210.6		240.7		130.9		142.7		173.3			172.0

Intermediate sour SCO (mbbls/d)⁽²⁾		186.0		206.3		107.2		119.9		138.2			143.0

Syncrude cash operating costs^(1)(B) ($/bbl)

Cash costs		35.55		30.85		62.80		53.80		49.25			46.15

Natural gas		1.50		0.90		1.05		2.45		1.50			1.10

		37.05		31.75		63.85		56.25		50.75			47.25

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

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended															Twelve months ended
Oil Sands Operating Netbacks ^(B)(C)	Mar 31 2019			Dec 31 2018			Sep 30 2018			Jun 30 2018			Mar 31 2018			Dec 31 2018

Bitumen ($/bbl)

Average price realized		48.37			7.96			42.03			47.08			33.55			30.22

Royalties		(1.37	)		(0.06	)		(3.20	)		(3.27	)		(0.90	)		(1.70	)

Transportation costs		(6.78	)		(5.53	)		(5.41	)		(4.24	)		(5.98	)		(5.52	)

Net operating expenses		(8.56	)		(7.61	)		(7.01	)		(7.37	)		(8.75	)		(7.68	)

Operating netback^(B)		31.66			(5.24	)		26.41			32.20			17.92			15.32

SCO and diesel ($/bbl)

Average price realized		69.34			46.07			86.71			85.06			74.65			73.07

Royalties		(1.38	)		(0.91	)		(2.70	)		(2.60	)		(0.56	)		(1.63	)

Transportation costs		(4.44	)		(3.63	)		(3.76	)		(5.06	)		(4.14	)		(4.10	)

Net operating expenses – bitumen		(23.87	)		(23.72	)		(20.49	)		(27.52	)		(25.33	)		(24.04	)

Net operating expenses – upgrading		(5.11	)		(6.49	)		(5.03	)		(8.13	)		(6.05	)		(6.32	)

Operating netback^(B)		34.54			11.32			54.73			41.75			38.57			36.98

Average Oil Sands operations ($/bbl)

Average price realized		66.39			31.84			73.90			73.21			62.54			59.46

Royalties		(1.38	)		(0.59	)		(2.84	)		(2.81	)		(0.66	)		(1.70	)

Transportation costs		(4.77	)		(4.34	)		(4.23	)		(4.80	)		(4.68	)		(4.55	)

Net operating expenses – bitumen and upgrading		(26.11	)		(21.78	)		(20.21	)		(26.83	)		(24.71	)		(23.15	)

Operating netback^(B)		34.13			5.13			46.62			38.77			32.49			30.06

Fort Hills ($/bbl)

Average price realized		62.92			30.57			64.33			60.81			40.58			48.48

Royalties		(1.43	)		(1.41	)		(3.07	)		(0.73	)		(1.54	)		(1.67	)

Transportation costs		(12.97	)		(10.31	)		(10.90	)		(8.95	)		(8.10	)		(10.01	)

Net operating expenses – bitumen		(25.17	)		(28.79	)		(30.69	)		(22.73	)		(106.07	)		(30.32	)

Operating netback^(B)		23.35			(9.94	)		19.67			28.40			(75.13	)		6.48

Syncrude ($/bbl)

Average price realized		68.36			48.07			89.50			86.73			77.33			70.68

Royalties		(8.09	)		(1.53	)		(2.49	)		(2.41	)		(1.57	)		(1.90	)

Transportation costs		(0.46	)		(0.36	)		(0.70	)		(0.57	)		(0.48	)		(0.49	)

Net operating expenses – bitumen and upgrading		(31.53	)		(28.33	)		(62.61	)		(52.27	)		(45.30	)		(43.81	)

Operating netback^(B)		28.28			17.85			23.70			31.48			29.98			24.48

(B): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.
(C): Netbacks are based on sales volumes.


	Three months ended															Twelve months ended
Exploration and Production	Mar 31 2019			Dec 31 2018			Sep 30 2018			Jun 30 2018			Mar 31 2018			Dec 31 2018

Total Sales Volumes (mboe/d)		111.8			83.1			96.5			110.2			121.9			102.8

Total Production (mboe/d)		107.1			90.2			92.1			114.1			117.7			103.4

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)		13.2			9.5			8.6			13.6			15.4			11.7

Hibernia (mbbls/d)		25.7			19.0			17.9			25.5			26.1			22.1

White Rose (mbbls/d)		1.1			3.7			8.0			6.0			8.8			6.6

Hebron (mbbls/d)		18.3			15.7			14.4			13.5			8.2			13.0

North America Onshore (mboe/d)		—			—			—			—			2.0			0.5

		58.3			47.9			48.9			58.6			60.5			53.9

Exploration and Production International

Buzzard (mboe/d)		36.7			27.7			29.6			39.4			40.4			34.2

Golden Eagle (mboe/d)		10.2			10.7			12.0			12.6			14.3			12.4

United Kingdom (mboe/d)		46.9			38.4			41.6			52.0			54.7			46.6

Norway – Oda (mboe/d)		0.2			—			—			—			—			—

Libya (mbbls/d)⁽³⁾		1.7			3.9			1.6			3.5			2.5			2.9

		48.8			42.3			43.2			55.5			57.2			49.5

Netbacks^(B)(C)

East Coast Canada ($/bbl)

Average price realized		86.16			76.19			99.50			97.30			84.63			90.04

Royalties		(19.75	)		(5.04	)		(18.75	)		(13.02	)		(14.34	)		(13.31	)

Transportation costs		(1.56	)		(2.71	)		(2.28	)		(2.24	)		(1.84	)		(2.22	)

Operating costs		(15.63	)		(23.71	)		(16.06	)		(11.21	)		(9.70	)		(14.43	)

Operating netback^(B)		49.22			44.73			62.41			70.83			58.75			60.08

United Kingdom ($/boe)

Average price realized		85.40			85.31			94.28			93.88			83.22			89.10

Transportation costs		(2.22	)		(2.14	)		(2.22	)		(2.20	)		(2.14	)		(2.18	)

Operating costs		(5.09	)		(8.94	)		(6.04	)		(5.39	)		(5.36	)		(6.27	)

Operating netback^(B)		78.09			74.23			86.02			86.29			75.72			80.65

(B): Non-GAAP financial measures. See the Quarterly Operating Metrics Reconciliation and the Operating Summary Information – Non-GAAP Financial Measures sections of this Quarterly Report.
(C): Netbacks are based on sales volumes.

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended										Twelve months ended
Refining and Marketing	Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Mar 31 2018		Dec 31 2018

Refined product sales (mbbls/d)		542.8		530.6		565.5		500.0		512.9		527.4

Crude oil processed (mbbls/d)		444.9		467.9		457.2		344.1		453.5		430.8

Utilization of refining capacity (%)		96		101		99		74		98		93

Refining margin ($/bbl)^(B)		36.35		41.50		34.45		30.25		30.50		34.50

Refining operating expense ($/bbl)^(B)		5.60		5.45		5.00		6.25		4.90		5.35

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		120.6		117.8		122.0		117.8		113.6		117.8

Distillate		103.1		100.2		96.7		93.4		81.8		95.8

Total transportation fuel sales		223.7		218.0		218.7		211.2		195.4		213.6

Petrochemicals		12.8		10.3		9.0		11.8		14.1		11.3

Asphalt		12.6		15.2		20.5		13.3		13.1		15.5

Other		27.5		25.7		26.5		25.9		36.6		26.0

Total refined product sales		276.6		269.2		274.7		262.2		259.2		266.4

Crude oil supply and refining

Processed at refineries (mbbls/d)		216.2		221.0		211.6		182.0		217.8		208.1

Utilization of refining capacity (%)		97		100		95		82		98		94

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		126.1		127.8		139.0		124.2		120.1		127.8

Distillate		118.7		109.5		121.0		88.3		109.9		107.6

Total transportation fuel sales		244.8		237.3		260.0		212.5		230.0		235.4

Asphalt		7.5		11.3		16.1		14.3		11.3		13.3

Other		13.9		12.8		14.7		11.0		12.4		12.3

Total refined product sales		266.2		261.4		290.8		237.8		253.7		261.0

Crude oil supply and refining

Processed at refineries (mbbls/d)		228.7		246.9		245.6		162.1		235.7		222.7

Utilization of refining capacity (%)		95		103		102		68		98		93

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


For the quarter ended March 31, 2019	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	277		2 158		2 435		627		1 143		(24	)	4 181

Other income (loss)	—		24		24		(41	)	(10	)	37		10

Purchases of crude oil and products	(58	)	(36	)	(94	)	(155	)	(22	)	(2	)	(273	)

Gross realization adjustment⁽⁵⁾	12		(17	)	(5	)	15		(8	)

Gross realizations	231		2 129		2 360		446		1 103

Royalties	(7	)	(40	)	(47	)	(18	)	(133	)	—		(198	)

Transportation	(32	)	(156	)	(188	)	(102	)	(8	)	—		(298	)

Transportation adjustment⁽⁶⁾	—		26		26		10		(1	)

Net transportation expenses	(32	)	(130	)	(162	)	(92	)	(9	)

Operating, selling and general (OS&G)	(68	)	(1 073	)	(1 141	)	(234	)	(619	)	21		(1 973	)

OS&G adjustment⁽⁷⁾	17		226		243		55		103

Net operating expenses	(51	)	(847	)	(898	)	(179	)	(516	)

Gross profit	141		1 112		1 253		157		445

Sales volumes (mbbls)	4 784		29 260		34 044		7 080		16 380

Operating netback per barrel	31.66		34.54		34.13		23.35		28.28


For the quarter ended December 31, 2018	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	405		1 326		1 731		508		940		(30	)	3 149

Other income	—		76		76		111		93		18		298

Purchases of crude oil and products	(267	)	(16	)	(283	)	(218	)	(14	)	—		(515	)

Gross realization adjustment⁽⁵⁾	(12	)	(164	)	(176	)	(136	)	(93	)

Gross realizations	126		1 222		1 348		265		926

Royalties	(1	)	(24	)	(25	)	(12	)	(30	)	—		(67	)

Transportation	(88	)	(116	)	(204	)	(106	)	(9	)	—		(319	)

Transportation adjustment⁽⁶⁾	—		20		20		16		2

Net transportation expenses	(88	)	(96	)	(184	)	(90	)	(7	)

OS&G	(167	)	(949	)	(1 116	)	(291	)	(619	)	28		(1 998	)

OS&G adjustment⁽⁷⁾	47		147		194		41		73

Net operating expenses	(120	)	(802	)	(922	)	(250	)	(546	)

Gross profit (loss)	(83	)	300		217		(87	)	343

Sales volumes (mbbls)	15 825		26 545		42 370		8 706		19 286

Operating netback per barrel	(5.24	)	11.32		5.13		(9.94	)	17.85

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

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended September 30, 2018	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	729		2 696		3 425		532		884		(26	)	4 815

Other (loss) income	—		(8	)	(8	)	(2	)	4		27		21

Purchases of crude oil and products	(211	)	(15	)	(226	)	(143	)	(10	)	1		(378	)

Gross realization adjustment⁽⁵⁾	(10	)	(63	)	(73	)	(23	)	(4	)

Gross realizations	508		2 610		3 118		364		874

Royalties	(39	)	(81	)	(120	)	(17	)	(24	)	—		(161	)

Transportation	(65	)	(152	)	(217	)	(78	)	(13	)	—		(308	)

Transportation adjustment⁽⁶⁾	—		39		39		17		6

Net transportation expenses	(65	)	(113	)	(178	)	(61	)	(7	)

OS&G	(119	)	(915	)	(1 034	)	(214	)	(635	)	28		(1 855	)

OS&G adjustment⁽⁷⁾	35		145		180		40		24

Net operating expenses	(84	)	(770	)	(854	)	(174	)	(611	)

Gross profit	320		1 646		1 966		112		232

Sales volumes (mbbls)	12 092		30 080		42 172		5 664		9 769

Operating netback per barrel	26.41		54.73		46.62		19.67		23.70


For the quarter ended June 30, 2018	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	703		2 020		2 723		558		938		(39	)	4 180

Other income (loss)	2		(11	)	(9	)	(10	)	36		36		53

Purchases of crude oil and products	(204	)	(13	)	(217	)	(177	)	(8	)	2		(400	)

Gross realization adjustment⁽⁵⁾	(14	)	(54	)	(68	)	(16	)	(36	)

Gross realizations	487		1 942		2 429		355		930

Royalties	(34	)	(60	)	(94	)	(4	)	(26	)	—		(124	)

Transportation	(44	)	(148	)	(192	)	(87	)	(12	)	—		(291	)

Transportation adjustment⁽⁶⁾	—		33		33		34		6

Net transportation expenses	(44	)	(115	)	(159	)	(53	)	(6	)

OS&G	(113	)	(981	)	(1 094	)	(184	)	(608	)	37		(1 849	)

OS&G adjustment⁽⁷⁾	37		166		203		51		48

Net operating expenses	(76	)	(815	)	(891	)	(133	)	(560	)

Gross profit	333		952		1 285		165		338

Sales volumes (mbbls)	10 351		22 838		33 189		5 828		10 718

Operating netback per barrel	32.20		41.75		38.77		28.40		31.48

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

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended March 31, 2018	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	572		1 960		2 532		77		1 003		(13	)	3 599

Other (loss) income	(4	)	—		(4	)	(2	)	3		18		15

Purchases of crude oil and products	(211	)	(35	)	(246	)	(17	)	(16	)	9		(270	)

Gross realization adjustment⁽⁵⁾	—		(25	)	(25	)	(28	)	—

Gross realizations	357		1 900		2 257		30		990

Royalties	(10	)	(14	)	(24	)	(2	)	(20	)	—		(46	)

Transportation	(64	)	(126	)	(190	)	(26	)	(10	)	—		(226	)

Transportation adjustment⁽⁶⁾	—		21		21		20		4

Net transportation expenses	(64	)	(105	)	(169	)	(6	)	(6	)

OS&G	(127	)	(945	)	(1 072	)	(143	)	(661	)	1		(1 875	)

OS&G adjustment⁽⁷⁾	34		146		180		66		81

Net operating expenses	(93	)	(799	)	(892	)	(77	)	(580	)

Gross profit (loss)	190		982		1 172		(55	)	384

Sales volumes (mbbls)	10 635		25 453		36 088		729		12 810

Operating netback per barrel	17.92		38.57		32.49		(75.13	)	29.98


For the year ended December 31, 2018	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	2 409		8 002		10 411		1 675		3 765		(108	)	15 743

Other (loss) income	(2	)	57		55		97		136		99		387

Purchases of crude oil and products	(893	)	(79	)	(972	)	(555	)	(48	)	12		(1 563	)

Gross realization adjustment⁽⁵⁾	(36	)	(306	)	(342	)	(203	)	(133	)

Gross realizations	1 478		7 674		9 152		1 014		3 720

Royalties	(84	)	(179	)	(263	)	(35	)	(100	)	—		(398	)

Transportation	(261	)	(542	)	(803	)	(297	)	(44	)	—		(1 144	)

Transportation adjustment⁽⁶⁾	—		113		113		87		18

Net transportation expenses	(261	)	(429	)	(690	)	(210	)	(26	)

OS&G	(526	)	(3 790	)	(4 316	)	(832	)	(2 523	)	94		(7 577	)

OS&G adjustment⁽⁷⁾	153		604		757		198		226

Net operating expenses	(373	)	(3,186	)	(3,559	)	(634	)	(2,297	)

Gross profit	760		3 880		4 640		135		1 297

Sales volumes (mbbls)	48 903		104 916		153 819		20 927		52 583

Operating netback per barrel	15.32		36.98		30.06		6.48		24.48

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

See accompanying footnotes and definitions to the quarterly operating summaries.

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


For the quarter ended March 31, 2019	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	360		491		86		937

Royalties	—		(112	)	(61	)	(173	)

Transportation	(9	)	(9	)	(1	)	(19	)

OS&G	(26	)	(106	)	(16	)	(148	)

Non-production costs⁽¹⁰⁾	4		16

Gross realizations	329		280

Sales volumes (mboe)	4 217		5 693

Operating netback per barrel	78.09		49.22


For the quarter ended December 31, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	301		286		184		771

Royalties	—		(19	)	(120	)	(139	)

Transportation	(8	)	(10	)	(1	)	(19	)

OS&G	(39	)	(101	)	(15	)	(155	)

Non-production costs⁽¹⁰⁾	8		12

Gross realizations	262		168

Sales volumes (mboe)	3 531		3 758

Operating netback per barrel	74.23		44.73


For the quarter ended September 30, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	361		488		100		949

Royalties	—		(91	)	(74	)	(165	)

Transportation	(8	)	(12	)	—		(20	)

OS&G	(27	)	(90	)	(10	)	(127	)

Non-production costs⁽¹⁰⁾	3		11

Gross realizations	329		306

Sales volumes (mboe)	3 827		4 905

Operating netback per barrel	86.02		62.41

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

See accompanying footnotes and definitions to the quarterly operating summaries.

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


For the quarter ended June 30, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	444		484		204		1 132

Royalties	—		(65	)	(122	)	(187	)

Transportation	(10	)	(11	)	(1	)	(22	)

OS&G	(30	)	(69	)	(15	)	(114	)

Non-production costs⁽¹⁰⁾	4		13

Gross realizations	408		352

Sales volumes (mboe)	4 728		4 973

Operating netback per barrel	86.29		70.83


For the quarter ended March 31, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	409		478		130		1 017

Royalties	—		(82	)	(79	)	(161	)

Transportation	(11	)	(10	)	(3	)	(24	)

OS&G	(32	)	(68	)	(11	)	(111	)

Non-production costs⁽¹⁰⁾	7		14

Gross realizations	373		332

Sales volumes (mboe)	4 920		5 647

Operating netback per barrel	75.72		58.75


For the year ended December 31, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	1 515		1 736		618		3 869

Royalties	—		(257	)	(395	)	(652	)

Transportation	(37	)	(43	)	(5	)	(85	)

OS&G	(129	)	(328	)	(50	)	(507	)

Non-production costs⁽¹⁰⁾	23		50

Gross realizations	1 372		1 158

Sales volumes (mboe)	17 006		19 283

Operating netback per barrel	80.65		60.08

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

See accompanying footnotes and definitions to the quarterly operating summaries.


	Three months ended											Twelve months ended
	Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018			Mar 31 2018		Dec 31 2018

Gross margin⁽¹¹⁾	2 140		1 711		1 987			1 639		1 785		7 122

Other income (loss)	15		90		10			(15	)	(17	)	68

Non-refining margin⁽¹²⁾	(587	)	115		(431	)		(620	)	(415	)	(1 351	)

Refining margin^(B)	1 568		1 916		1 566			1 004		1 353		5 839

Refinery production (mbbls)⁽¹³⁾	43 143		46 145		45 465			33 165		44 363		169 138

Refining margin ($/bbl)^(B)	36.35		41.50		34.45			30.25		30.50		34.50

Last-in, first out (LIFO) adjustment	(333	)	444		—			(96	)	(11	)	337

Adjusted LIFO Refining Margin^(B)	1 235		2 360		1 566			908		1 342		6 176

Adjusted LIFO refining margin ($/bbl)^(B)	28.65		51.15		34.45			27.40		30.25		36.50

OS&G	536		538		519			494		492		2 043

Non-refining costs⁽¹⁴⁾	(294	)	(288	)	(292	)		(288	)	(274	)	(1 142	)

Refining operating expense	242		250		227			206		218		901

Refinery production (mbbls)⁽¹³⁾	43 143		46 145		45 465			33 165		44 363		169 138

Refining operating expense ($/bbl)^(B)	5.60		5.45		5.00			6.25		4.90		5.35

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

See accompanying footnotes and definitions to the quarterly operating summaries.

Certain financial measures in this document – namely operating earnings (loss), funds from (used in) operations, return on capital employed (ROCE), Oil Sands operations cash operating costs, Syncrude cash operating costs, Fort Hills cash operating costs, In Situ cash operating costs, mining cash operating costs, refining margin, refining operating expense and netbacks – are not prescribed by generally accepted accounting principles (GAAP). Suncor uses this information to analyze business performance, leverage and liquidity and includes these financial measures because investors may find such measures useful on the same basis. These non-GAAP financial measures do not have any standardized meaning and, therefore, are unlikely to be comparable to similar measures presented by other companies. 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), Oil Sands operations cash operating costs, and Fort Hills cash operating costs are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Consolidated Financial Information and Segment Results and Analysis sections of each respective quarterly Report to Shareholders issued by Suncor in respect of the relevant quarter (Quarterly Reports). Funds from (used in) operations and ROCE are defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective Quarterly Report. Refining margin, refining operating expense and Syncrude cash operating costs are defined in the Non-GAAP Financial Measures Advisory section and reconciled to GAAP measures in the Operating Metrics Reconciliation section of each respective Quarterly Report. Netbacks are defined below and are reconciled to GAAP measures in the Operating Metrics Reconciliation 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 this Quarterly Report.

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

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


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


(thousands)		March 31 2019

Common shares		1 573 558

Common share options – exercisable		21 251

Common share options – non-exercisable		14 222


($ millions)	January 1 2019

Operating leases as at December 31, 2018⁽¹⁾	2 457

Exemption for short-term leases	(42	)

Discounting	(623	)

Additional lease liabilities recognized due to adoption of IFRS 16 as at January 1, 2019	1 792


	Three months ended March 31
($ millions, except as noted)	2019	2018

Share repurchase activities (thousands of common shares)

Shares repurchased	11 951	8 999

Amounts charged to

Share capital	193	145

Retained earnings	321	244

Share repurchase cost	514	389


1.	Advisories	6
2.	First Quarter Highlights	8
3.	Consolidated Financial Information	9
4.	Segment Results and Analysis	14
5.	Capital Investment Update	25
6.	Financial Condition and Liquidity	27
7.	Quarterly Financial Data	30
8.	Other Items	32
9.	Non-GAAP Financial Measures Advisory	33
10.	Common Abbreviations	37
11.	Forward-Looking Information	38


($ millions)	Energy Trading		Risk Management		Total

Fair value outstanding at December 31, 2018	1		59		60

Cash Settlements – (received) paid during the year	(102	)	17		(85	)

Unrealized gains (losses) recognized in earnings during the year (note 5)	95		(57	)	38

Fair value outstanding at March 31, 2019	(6	)	19		13


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

Accounts receivable	23		36		—	59

Accounts payable	(16	)	(30	)	—	(46	)

	7		6		—	13


($ millions)		March 31 2019

Property, plant and equipment, net – excluding ROU assets		73 323

ROU assets		3 024

		76 347

Three months ended
March 31

($ millions)

Discretionary free funds flow⁽²⁾