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 section of Suncor Energy Inc.'s (Suncor or the company) Management's Discussion and Analysis dated July 24, 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.

"This quarter, we delivered $3.0 billion in funds from operations, a new second quarter record, and $1.3 billion of operating earnings due to our team delivering solid operating performance while taking full advantage of our flexibility to maximize our cash flow, despite the impact of curtailments," said Mark Little, president and chief executive officer. "Strong cash flow generation and our commitment to capital discipline allowed us to return value to our shareholders through $658 million in dividends and $552 million in share repurchases while, at the same time, strengthening our balance sheet."

Suncor's second quarter 2019 operating earnings were $1.253 billion ($0.80 per common share), compared to $1.190 billion ($0.73 per common share) in the prior year quarter. The increase in operating earnings was primarily related to higher overall crude production and refinery crude throughput due to a less intensive, planned maintenance program at both Oil Sands and R&M, as compared to the prior year quarter. In addition, improved reliability at Syncrude and the ramp up of Fort Hills and Hebron production throughout 2018 further increased crude output during the second quarter of 2019, which was only partially offset by a decrease in production associated with the Alberta government's mandatory production curtailments. Other positive factors influencing operating earnings in the second quarter of 2019 were the impact of a weaker Canadian dollar on U.S. dollar denominated sales and improved refining margins.

Second quarter 2019 operating earnings were negatively impacted by lower WTI and Brent benchmark crude prices, an unfavourable first-in, first-out (FIFO) and intercompany inventory change, and an increase in royalties, operating and transportation expenses, consistent with the increase in production. In addition, depreciation, depletion and amortization (DD&A) expenses were higher than the prior year quarter, due primarily to the staged commissioning of Fort Hills in 2018 and the increase in depreciation associated with the transition to International Financial Reporting Standards 16 Leases. Exploration expenses increased due to non-commercial drilling results off the east coast of Canada and in the United Kingdom North Sea.

Net earnings were $2.729 billion ($1.74 per common share) in the second quarter of 2019, compared to net earnings of $972 million ($0.60 per common share) in the prior year quarter. In addition to the factors impacting operating earnings discussed above, net earnings for the second quarter of 2019 included a one-time deferred income tax recovery of $1.116 billion associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022, an after-tax gain of $139 million on the sale of the company's interest in Canbriam Energy Inc. (Canbriam) and a $221 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 $218 million on the revaluation of U.S. dollar denominated debt.

Funds from operations were $3.005 billion ($1.92 per common share) in the second quarter of 2019, compared to $2.862 billion ($1.75 per common share) in the second quarter of 2018, and were influenced by the same factors impacting operating earnings noted above, excluding the impact of DD&A and exploration expenses.

Cash flow provided by operating activities was $3.433 billion ($2.19 per common share) for the second quarter of 2019, compared to $2.446 billion ($1.50 per common share) for the second quarter of 2018. In addition to the items noted in funds from operations, cash flow provided by operating activities was further impacted by a source of cash associated with the company's working capital balances in the second quarter of 2019, as compared to a use of cash in the prior year quarter.

Suncor's total upstream production was 803,900 barrels of oil equivalent per day (boe/d) during the second quarter of 2019, compared to 661,700 boe/d in the prior year quarter, marking a second quarter production record. The increase was primarily due to lower planned Oil Sands maintenance, improved reliability at Syncrude and the ramp up of Fort Hills and Hebron production throughout 2018, partially offset by the impact of mandatory production curtailments in the province of Alberta, which began January 1, 2019.

During the second quarter of 2019, the company was able to leverage its broad asset base and operational flexibility to maximize the value of its allotted barrels under the mandatory curtailment program, focusing on higher value synthetic crude oil (SCO) production and helping to mitigate the impact of planned maintenance activities through the transfer of curtailment allotment among the company's assets. In addition, solid asset reliability and availability allowed the company to purchase 24,000 bbls/d of additional curtailment bitumen volumes from third parties, net of curtailment sales.

"Suncor's upstream assets produced more than 800,000 bbls/d of crude oil during the second quarter of 2019, marking a new second quarter production record, while planned maintenance was completed at many of our Oil Sands assets in the quarter," said Little. "In addition, the team was able to create significant value by opportunistically shifting production among our assets through this period of curtailment – another great example of the benefits that come from having a broad and flexible asset base."

Oil Sands operations production was 414,200 bbls/d in the second quarter of 2019, compared to 358,900 bbls/d in the prior year quarter. The increase in production was primarily SCO and resulted from a decrease in planned upgrader maintenance. Oil Sands operations upgrader reliability improved to 86% in the second quarter of 2019, compared to 69% in the prior year quarter. Production of non-upgraded bitumen from the company's In Situ assets was relatively flat quarter-over-quarter at 118,700 bbls/d during the second quarter of 2019, compared to 121,000 bbls/d in the prior year quarter, and continued to be impacted by mandatory production curtailment as the company favoured the production of higher value SCO barrels, in addition to the completion of major maintenance at Firebag. In addition, overall Oil Sands operations production was reduced by the yield loss associated with upgrading bitumen to SCO.

Oil Sands operations cash operating costs⁽¹⁾ per barrel were $27.80 in the second quarter of 2019, compared to $28.65 in the prior year quarter, with both periods reflecting the impact of planned maintenance. The decrease in Oil Sands operations cash operating costs per barrel was due to the increase in production being partially offset by higher operating, selling and general costs and was further impacted by the yield loss associated with the increase in higher value SCO production. Total Oil Sands operations cash operating costs were $1.051 billion, compared to $940 million in the prior year quarter, due primarily to an increase in commodity consumption costs and higher ore preparation costs, partially offset by a decrease in natural gas prices.

Suncor's share of production from Fort Hills averaged 89,300 bbls/d in the second quarter of 2019 compared to 70,900 bbls/d in the prior year quarter, with the increase in production attributed to the ramp up of operations throughout 2018. The increase in production was partially offset by mandatory production curtailments, which the company limited the effect of through purchasing 6,500 bbls/d of curtailment credits from third-parties. Fort Hills cash operating costs⁽¹⁾ per barrel were $22.50 in the second quarter of 2019, compared to $28.55 in the prior year quarter, with the improvement primarily attributed to the increase in production. Total Fort Hills cash operating costs were consistent at $183 million, compared to $185 million in the prior year quarter, despite the increase in production.

Suncor's share of Syncrude production was 188,700 bbls/d in the second quarter of 2019, compared to 117,800 bbls/d in the prior year quarter. The increase in production was primarily due to improved reliability at Syncrude due to the prior year quarter being impacted by extended planned maintenance and a power disruption. Production increases were partially offset by the impact of mandatory production curtailments, which Suncor and the other Syncrude partners helped to mitigate by allocating a portion of their curtailment allotment to Syncrude, on an opportunistic basis. In addition, Syncrude purchased other third-party curtailment allotments. The total curtailment credits received at Syncrude resulted in an estimated increase in SCO production of 21,000 bbls/d. Upgrader utilization at Syncrude improved to 93% in the second quarter of 2019, compared to 58% in the prior year quarter.

Syncrude cash operating costs⁽¹⁾ per barrel were $34.90 in the second quarter of 2019, a decrease from $56.25 in the prior year quarter, due primarily to the increase in production. Total Syncrude cash operating costs were $599 million in the second quarter of 2019 and were comparable to $603 million in the prior year quarter.

Production volumes at E&P were 111,700 boe/d in the second quarter of 2019, compared to 114,100 boe/d in the prior year quarter. Increased production from Hebron and Oda, which began production in the first quarter of 2019, nearly offset natural declines in the United Kingdom, the continued staged return of White Rose towards full operations and the completion of planned maintenance at Terra Nova.

Refinery crude throughput was 399,100 bbls/d and refinery utilization was 86% in the second quarter of 2019, compared to 344,100 bbls/d and a utilization rate of 74% in the prior year quarter. Both periods were impacted by major planned maintenance, however, the maintenance completed in the current period had a less significant impact on production when compared to the second quarter of 2018, which included the first full turnaround of the Edmonton refinery, as well as additional turnaround activities at the company's other three refineries. Planned maintenance completed in the second quarter of 2019 included turnaround activities at the Sarnia and Montreal refineries, as well as major maintenance at the Edmonton and Commerce City refineries. Refined product sales increased in the second quarter of 2019 to 508,100 bbls/d, compared to 500,000 bbls/d in the prior year quarter, with the increase due to higher refinery crude throughput in the second quarter of 2019 and the associated increase in refined product availability. The prior period quarter included a significant draw of product inventory that was built up in advance of the planned turnaround of the entire Edmonton refinery in the second quarter of 2018.

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 its offshore business in the E&P segment.

Excluding capitalized interest, the company incurred $1.336 billion in capital expenditures in the second quarter of 2019, a decrease from $1.737 billion in the prior year quarter. The decrease was due primarily to lower planned maintenance and turnaround capital due to the completion of a more significant planned maintenance program at both Oil Sands and R&M in the prior year quarter, as well as the decrease in capital associated with the staged completion and commissioning of the Fort Hills extraction plants in the first half of 2018.

Drilling activity at Hebron is ongoing and production continues to ramp up. Other E&P activity in the second quarter included development drilling at Hibernia, White Rose, Buzzard and Terra Nova, and development work on Fenja and the West White Rose Project.

During the second quarter of 2019, the company sanctioned the Terra Nova asset life extension. The project is expected to extend the life of Terra Nova by approximately a decade and is planned for execution in 2020. The company's previously issued 2019 capital guidance included development spending associated with this project.

In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which the company had acquired in the first quarter of 2018. In addition, Suncor sold land and several related natural gas wells held in northeast British Columbia to Canbriam for proceeds of $24 million, with this transaction closing early in the third quarter of 2019.

During the second quarter of 2019, the company issued $750 million of 3.10% senior unsecured medium term notes due in 2029. Also in the quarter, the company reduced its short-term debt balance by $1.281 billion and repaid US$140 million of maturing long-term debt, further improving the company's balance sheet flexibility.

In the second quarter of 2019, the company repurchased $552 million of its own shares for cancellation under the company's normal course issuer bid, and returned $658 million of cash to shareholders through dividends.

"Through our integrated model and focus on operational excellence, capital discipline and sustainability, we are well positioned for the future and continue to deliver increased returns to our shareholders," said Little. "We will continue to optimize and enhance our business through leveraging the talent of our people, a continued focus on innovation and the integration of advanced digital technology. To accelerate these efforts, we have assembled some of our most senior leaders into a dedicated project team to guide Suncor through the next phase of the company's evolution."


	Three months ended June 30			Six months ended June 30
($ millions)	2019		2018	2019		2018

Net earnings	2 729		972	4 199		1 761

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(221	)	218	(482	)	547

Impact of income tax rate adjustment on deferred taxes⁽²⁾	(1 116	)	—	(1 116	)	—

Gain on significant disposal⁽³⁾	(139	)	—	(139	)	(133	)

Operating earnings⁽¹⁾	1 253		1 190	2 462		2 175

(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 the second quarter of 2019, the company recorded a $1.116 billion deferred income tax recovery associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after tax), which had previously been 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. The equity interest in Canbriam was acquired during the first quarter of 2018 in exchange for the company's mineral landholdings in northeast British Columbia, at which time a gain of $133 million after-tax was recorded on the transaction.

Suncor has revised its full year outlook range for capital expenditures to $4.9 – $5.4 billion, down from $4.9 – $5.6 billion to reflect the company's continued focus on capital discipline, and Syncrude cash operating costs per barrel have been increased to $36.50 – $39.50 from $33.50 – $36.50 due to additional costs associated with driving sustained reliability improvements at Syncrude. In addition, the company has updated its key refining benchmark crack spread to New York Harbor 2-1-1 crack, from New York Harbor 3-2-1 crack, which better reflects the approximate composition of Suncor's overall refined product mix. No other changes have been made to Suncor's guidance at this time. For further details and advisories regarding Suncor's 2019 corporate guidance, see www.suncor.com/guidance.

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

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. We are strategically focused on developing one of the world's largest petroleum resource basins – Canada's Athabasca oil sands. In addition, we explore for, acquire, develop, produce and market crude oil and natural gas in Canada and internationally; we transport and refine crude oil, and we market petroleum and petrochemical products primarily in Canada. 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 and six months ended June 30, 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) as issued by the IASB.

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 and six months ended June 30, 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 have been 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 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 and related per share amounts – 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 June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Net earnings (loss)

Oil Sands	1 561		403		1 750		500

Exploration and Production	456		312		948		700

Refining and Marketing	765		671		1 774		1 460

Corporate and Eliminations	(53	)	(414	)	(273	)	(899	)

Total	2 729		972		4 199		1 761

Operating earnings (loss)⁽¹⁾

Oil Sands	651		403		840		500

Exploration and Production	247		312		739		567

Refining and Marketing	677		671		1 686		1 460

Corporate and Eliminations	(322	)	(196	)	(803	)	(352	)

Total	1 253		1 190		2 462		2 175

Funds from (used in) operations⁽¹⁾

Oil Sands	1 866		1 491		3 050		2 473

Exploration and Production	507		539		1 209		1 005

Refining and Marketing	932		892		2 185		1 803

Corporate and Eliminations	(300	)	(60	)	(854	)	(255	)

Total	3 005		2 862		5 590		5 026

Decrease (increase) in non-cash working capital	428		(416	)	(609	)	(1 856	)

Cash flow provided by operating activities	3 433		2 446		4 981		3 170

Capital and exploration expenditures⁽²⁾

Asset sustainment and maintenance	816		1 251		1 235		1 940

Economic investment	520		486		976		1 011

Total	1 336		1 737		2 211		2 951


	Three months ended June 30		Twelve months ended June 30
($ millions)	2019	2018	2019	2018

Discretionary free funds flow⁽¹⁾	1 518	1 009	3 007	1 879

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A. Discretionary free funds flow for the three and six months ended June 30, 2018 have been restated for the impact of the change to the company's classification of asset sustainment and maintenance capital expenditures. Refer to the Capital and Investment Update section of this MD&A for further details.
(2): Excludes capitalized interest of $28 million in the second quarter of 2019 and $25 million in the second quarter of 2018 and reflects the company's revised capital expenditure classification. Refer to the Capital and Investment Update section of this MD&A for further details.

Suncor's consolidated net earnings for the second quarter of 2019 were $2.729 billion, compared to $972 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 June 30			Six months ended June 30
($ millions)	2019		2018	2019		2018

Net earnings	2 729		972	4 199		1 761

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(221	)	218	(482	)	547

Impact of income tax rate adjustment on deferred taxes⁽²⁾	(1 116	)	—	(1 116	)	—

Gain on significant disposal⁽³⁾	(139	)	—	(139	)	(133	)

Operating earnings⁽¹⁾	1 253		1 190	2 462		2 175

(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 the second quarter of 2019, the company recorded a $1.116 billion deferred income tax recovery associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after- tax), which had previously been 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. The equity interest in Canbriam was acquired during the first quarter of 2018 in exchange for the company's mineral landholdings in northeast British Columbia, at which time a gain of $133 million after-tax was recorded on the transaction.

Suncor's second quarter 2019 operating earnings were $1.253 billion ($0.80 per common share), compared to $1.190 billion ($0.73 per common share) in the prior year quarter. The increase in operating earnings was primarily related to higher overall crude production and refinery crude throughput due to a less intensive planned maintenance program at both Oil Sands and R&M, as compared to the prior year quarter. In addition, improved reliability at Syncrude and the ramp up of Fort Hills and Hebron production throughout 2018 further increased crude output during the second quarter of 2019, which was only partially offset by a decrease in production associated with the Alberta government's mandatory production curtailment. Other positive factors influencing operating earnings in the second quarter of 2019 were the impact of a weaker Canadian dollar on U.S. dollar denominated sales and improved refining margins.

Second quarter 2019 operating earnings were negatively impacted by lower WTI and Brent benchmark crude prices, an unfavourable FIFO and intercompany inventory change, and an increase in royalties, operating and transportation expenses, consistent with the increase in production. In addition, DD&A expense increased over the prior year quarter due primarily to the staged commissioning of Fort Hills in 2018 and additional depreciation associated with the transition to IFRS 16. Exploration expenses increased due to non-commercial drilling results off the east coast of Canada and in the U.K. North Sea.

The after-tax share-based compensation expense decreased to $20 million during the second quarter of 2019, compared to an expense of $117 million during the prior year quarter, as a result of a decline in the company's share price through the period, compared to an increase in the prior year quarter.

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

Average for the three
months ended June 30

Average for the six
months ended June 30

2019

2018

2019

2018

WTI crude oil at Cushing

US$/bbl

59.85

67.90

57.40

65.40

Dated Brent crude

US$/bbl

68.85

74.40

66.05

70.60

Dated Brent/Maya crude oil FOB price differential

US$/bbl

6.90

12.40

5.95

10.05

MSW at Edmonton

Cdn$/bbl

73.40

80.95

69.95

76.70

WCS at Hardisty

US$/bbl

49.20

48.65

45.90

43.65

Light/heavy differential – WTI at Cushing/WCS at Hardisty

US$/bbl

(10.65

)

(19.25

)

(11.50

)

(21.75

)

SYN-WTI Differential

US$/bbl

0.15

(0.65

)

(1.05

)

(1.05

)

Condensate at Edmonton

US$/bbl

55.90

68.50

53.25

65.80

Natural gas (Alberta spot) at AECO

Cdn$/mcf

1.05

1.20

1.70

1.65

Alberta Power Pool Price

Cdn$/MWh

56.35

56.00

63.55

45.65

New York Harbor 2-1-1 crack⁽¹⁾

US$/bbl

22.20

21.10

20.20

18.10

Chicago 2-1-1 crack⁽¹⁾

US$/bbl

21.45

19.05

18.45

15.60

Portland 2-1-1 crack⁽¹⁾

US$/bbl

26.85

28.65

23.10

24.15

Gulf Coast 2-1-1 crack⁽¹⁾

US$/bbl

21.70

20.45

19.80

17.90

Exchange rate

US$/Cdn$

0.75

0.77

0.75

0.78

Exchange rate (end of period)

US$/Cdn$

0.76

0.76

0.76

0.76

(1): 2-1-1 crack spreads are indicators of the refining margin generated by converting two barrels of WTI into one barrel of gasoline and one barrel of diesel. The company previously quoted 3-2-1 crack margin benchmarks based on wider use and familiarity with these benchmarks and, although the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which better reflects the approximate composition of Suncor's overall refined product mix. 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 second quarter of 2019 for sweet SCO were unfavourably impacted by a decrease in WTI at Cushing to US$59.85/bbl in the second quarter of 2019, compared to US$67.90/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 $73.40/bbl compared to $80.95/bbl in the prior year quarter; however, prices for WCS at Hardisty increased to US$49.20/bbl in the second quarter of 2019, from US$48.65/bbl in the prior year quarter, as a result of improved western Canadian heavy crude differentials, in part due to mandatory production curtailments in Alberta. Sweet and sour SCO differentials in the second quarter of 2019 were favourable when compared to the second quarter of 2018.

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 second 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$68.85/bbl in the second quarter of 2019, compared to US$74.40/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 decreased to $1.05/mcf in the second quarter of 2019, from $1.20/mcf in the prior year quarter.

Suncor's refining margins are primarily influenced by industry benchmark crack spreads and although the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which more appropriately reflects the company's refined product mix of gasoline and distillates. Benchmark crack spreads are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates. More complex refineries can earn greater refining margin by processing less expensive, heavier crudes. 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 of $56.35/MWh in the second quarter of 2019 was comparable to $56.00/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 during the second quarter of 2019, as the average exchange rate decreased to US$0.75 per one Canadian dollar from US$0.77 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the second quarter of 2019 when compared to the prior year quarter.

Suncor also has assets and liabilities, including approximately 65% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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 June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Gross revenues	5 140		4 180		9 321		7 779

Less: Royalties	(341	)	(124	)	(539	)	(170	)

Operating revenues, net of royalties	4 799		4 056		8 782		7 609

Net earnings⁽¹⁾	1 561		403		1 750		500

Impact of income tax rate adjustment on deferred taxes⁽²⁾	(910	)	—		(910	)	—

Operating earnings⁽³⁾	651		403		840		500

Funds from operations⁽³⁾	1 866		1 491		3 050		2 473

(1): The three and six months ended June 30, 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): In the second quarter of 2019, the company recorded a $910 million deferred income tax recovery in the Oil Sands segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Oil Sands segment had operating earnings of $651 million in the second quarter of 2019, compared to operating earnings of $403 million in the prior year quarter. The increase was due to higher overall production volumes resulting from a decrease in planned upgrader maintenance at Oil Sands operations and Syncrude, and improved reliability at Syncrude, partially offset by the completion of major maintenance at Firebag. The ramp up of Fort Hills production throughout 2018 also contributed to the increase in production; however, total production was limited by mandatory production curtailments, which primarily impacted the company's bitumen production. Operating earnings were unfavourably impacted by higher operating, selling and general expenses largely tied to the increase in production, an increase in royalties, lower overall crude price realizations and additional DD&A.


	Three months ended June 30				Six months ended June 30
(mbbls/d)	2019		2018		2019		2018

Upgraded product (SCO and diesel)	304.3		246.2		327.1		266.8

Internally consumed diesel⁽²⁾	(8.8	)	(8.3	)	(8.9	)	(8.2	)

Total Oil Sands operations upgraded product	295.5		237.9		318.2		258.6

In Situ non-upgraded bitumen	118.7		121.0		87.2		123.2

Total Oil Sands operations production	414.2		358.9		405.4		381.8

Fort Hills bitumen	89.3		70.9		83.9		50.5

Internally upgraded bitumen from froth	—		—		—		(2.6	)

Total Fort Hills bitumen production	89.3		70.9		83.9		47.9

Syncrude (sweet SCO and diesel)	191.1		120.0		188.1		132.4

Internally consumed diesel⁽²⁾	(2.4	)	(2.2	)	(2.6	)	(2.4	)

Total Syncrude production	188.7		117.8		185.5		130.0

Total Oil Sands production	692.2		547.6		674.8		559.7

(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 and bitumen froth from Fort Hills can be sent to Oil Sands Base for further processing into SCO. 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 8,800 bbls/d of internally consumed diesel at Oil Sands operations in the second quarter of 2019, 7,000 bbls/d was consumed at Oil Sands Base and 1,800 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 increased to 414,200 bbls/d in the second quarter of 2019, from 358,900 bbls/d in the prior year quarter, although the current quarter was partially constrained by mandatory production curtailments in the province of Alberta. The company's second quarter of 2019 planned upgrader maintenance program was less intensive than the prior year quarter, partially offset by the completion of planned maintenance at Firebag. Production curtailments primarily affected the company's In Situ bitumen production as the company favoured the production to higher value SCO barrels in the second quarter of 2019. The decrease in planned upgrader maintenance combined with improved upgrader reliability resulted in SCO production of 295,500 bbls/d in the second quarter of 2019, compared to 237,900 bbls/d in the second quarter of 2018, which represents utilization rates of 86% and 69%, respectively.

Suncor's Base Plant underwent planned maintenance in the second quarter, during which the company was able to optimize overall Oil Sands production by transferring curtailment credits to Syncrude and Fort Hills, while also selling a lesser volume to third-parties. After completing planned maintenance, the company was in a position to take advantage of available third-party curtailment credits and was a net purchaser during the quarter. The impact of net third-party curtailment credit purchases on bitumen production was an estimated increase of 24,000 bbls/d in the second quarter of 2019.

Fort Hills production increased to 89,300 bbls/d of bitumen, net to Suncor, in the second quarter of 2019, compared to 70,900 bbls/d in the prior year quarter. The increase was due to the successful ramp up of operations during 2018 and the purchase of third-party curtailment credits of 6,500 bbls/d during the quarter helped to partially offset the mandatory production curtailment limit set for Fort Hills.


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2019	2018	2019	2018

Oil Sands operations sales volumes

Sweet SCO	118.3	59.6	116.0	71.9

Diesel	25.2	32.4	27.1	26.4

Sour SCO	165.0	159.0	173.7	168.5

Upgraded product	308.5	251.0	316.8	266.8

In Situ non-upgraded bitumen	115.1	113.7	84.3	115.9

Oil Sands operations	423.6	364.7	401.1	382.7

Fort Hills bitumen	82.0	64.0	80.3	36.2

Syncrude	188.7	117.8	185.5	130.0

Total	694.3	546.5	666.9	548.9

Sales volumes for Oil Sands operations were 423,600 bbls/d in the second quarter of 2019, compared to 364,700 bbls/d in the prior year quarter and were influenced by the same factors as production above, in addition to a small draw of crude inventory.

Bitumen sales at Fort Hills averaged 82,000 bbls/d, net to Suncor, in the second quarter of 2019, compared to 64,000 bbls/d in the second quarter of 2018, with both periods reflecting a build of inventory as increasing production made its way to customers.

Suncor's share of Syncrude production was 188,700 bbls/d in the second quarter of 2019, compared to 117,800 bbls/d in the prior year quarter. The increase in production was primarily due to improved reliability at Syncrude due to the prior year quarter being impacted by extended planned maintenance and a power disruption. Production increases were partially offset by the impact of mandatory production curtailments, which Suncor and the other Syncrude partners helped to mitigate by allocating a portion of their curtailment allotment to Syncrude, on an opportunistic basis. In addition, Syncrude purchased other third-party curtailment allotments. The total curtailment credits received resulted in an estimated increase in SCO production of 21,000 bbls/d. Upgrader utilization at Syncrude improved to 93% in the second quarter of 2019, compared to 58% in the prior year quarter.


	Three months ended June 30		Six months ended June 30
	2019	2018	2019	2018

Oil Sands Base

Bitumen production (mbbls/d)	300.5	195.4	284.2	218.4

Bitumen ore mined (thousands of tonnes per day)	433.2	286.5	416.5	324.3

Bitumen ore grade quality (bbls/tonne)	0.69	0.68	0.68	0.67

In Situ

Bitumen production – Firebag (mbbls/d)	168.4	201.9	178.8	203.8

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

Bitumen production – MacKay River (mbbls/d)	36.3	34.4	35.8	34.7

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

Total In Situ bitumen production (mbbls/d)	204.7	236.3	214.6	238.5

Total Oil Sands operations bitumen production (mbbls/d)	505.2	431.7	498.8	456.9

Fort Hills

Bitumen production (mbbls/d)	89.3	70.9	83.9	50.5

Bitumen ore mined (thousands of tonnes per day)	144.5	111.0	138.0	80.5

Bitumen ore grade quality (bbls/tonne)	0.62	0.64	0.61	0.63

Syncrude

Bitumen production (mbbls/d)	228.5	142.7	219.6	157.9

Bitumen ore mined (thousands of tonnes per day)	370.9	233.7	356.4	255.8

Bitumen ore grade quality (bbls/tonne)	0.62	0.61	0.62	0.62

Total Oil Sands bitumen production	823.0	645.3	802.3	665.3

Bitumen production at Oil Sands operations increased in the second quarter of 2019 to 505,200 bbls/d, compared with 431,700 bbls/d in the prior year quarter. The increase was primarily due to a reduction in planned upgrader maintenance at Oil Sands Base in the current quarter and the associated increase in mined bitumen volumes, partially offset by lower In Situ bitumen production due to the completion of planned maintenance at Firebag and mandatory production curtailments.

Bitumen production at Syncrude in the second quarter of 2019 increased to 228,500 bbls/d, net to Suncor, from 142,700 bbls/d in the prior year quarter. The increase was primarily due to improved upgrader reliability, partially offset by the impact of mandatory production curtailments.


Net of transportation costs, but before royalties	Three months ended June 30				Six months ended June 30
($/bbl)	2019		2018		2019		2018

Oil Sands operations

SCO and diesel	74.97		80.00		69.83		74.99

Bitumen	48.26		42.84		46.18		35.10

Crude sales basket (all products)	67.72		68.41		64.86		62.91

Crude sales basket, relative to WTI	(12.08	)	(19.77	)	(11.67	)	(20.94	)

Fort Hills bitumen	57.10		51.86		53.62		49.70

Syncrude – sweet SCO	79.32		86.16		73.74		81.09

Syncrude, relative to WTI	(0.48	)	(2.02	)	(2.79	)	(2.76	)

Average price realizations at Oil Sands operations decreased to $67.72/bbl in the second quarter of 2019 from $68.41/bbl in the prior year quarter, due to a decrease in the WTI benchmark, partially offset by narrower heavy crude oil differentials, resulting from mandatory production curtailments in the province of Alberta and continued strong demand for heavy oil at the U.S. Gulf Coast, the impact of a weaker Canadian dollar and narrower SCO differentials.

Average price realizations for Fort Hills bitumen were $57.10/bbl in the second quarter of 2019, compared to $51.86/bbl in the prior year quarter, and were 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 higher 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 second quarter of 2019.

Average price realizations at Syncrude decreased to $79.32/bbl in the second quarter of 2019 from $86.16/bbl in the prior year quarter due to the decrease in the WTI benchmark price, partially offset by the impact of a weaker Canadian dollar and narrower SCO differentials.

Royalties for the Oil Sands segment were higher in the second 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 second 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 expenses were higher when compared to the prior year quarter, due to an increase in commodity consumption costs, higher ore preparation costs and additional expenses associated with emerging technologies intended to optimize future mining and extraction operations, partially offset by lower share-based compensation expense and a decrease in natural gas prices.

At Fort Hills, operating costs in the second quarter of 2019 increased when compared to the prior year quarter primarily due to crude inventory valuation changes, partially offset by a decrease in project start-up expenses.

Suncor's share of Syncrude operating costs were comparable to the prior year quarter.

Oil Sands transportation costs increased primarily as a result of the additional sales volumes from all Oil Sands assets, as compared to the prior year quarter.

DD&A and impairment expenses and exploration expense for the second quarter of 2019 were higher compared to the prior year quarter due to the addition of DD&A related to the staged commissioning of Fort Hills in 2018, additional depreciation associated with the transition to IFRS 16 and an increase in capitalized turnaround costs following the completion of significant maintenance at the end of the second quarter of 2018.


	Three months ended June 30				Six months ended June 30
($ millions, except as noted)	2019		2018		2019		2018

Oil Sands Operating, selling and general expense (OS&G)	2 060		1 849		4 033		3 724

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	1 219		1 057		2 340		2 127

Non-production costs⁽²⁾	(38	)	(47	)	(95	)	(81	)

Excess power capacity and other⁽³⁾	(42	)	(41	)	(117	)	(107	)

Inventory changes	(88	)	(29	)	(3	)	(17	)

Oil Sands operations cash operating costs⁽¹⁾	1 051		940		2 125		1 922

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	27.80		28.65		28.85		27.70

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	216		184		449		328

Non-production costs⁽²⁾	(25	)	(55	)	(72	)	(71	)

Inventory changes	(8	)	56		15		72

Fort Hills cash operating costs⁽¹⁾	183		185		392		329

Fort Hills cash operating costs ($/bbl)⁽¹⁾	22.50		28.55		25.80		35.90

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	625		608		1 244		1 269

Non-production costs⁽²⁾	(26	)	(5	)	(38	)	(15	)

Syncrude cash operating costs⁽¹⁾	599		603		1 206		1 254

Syncrude cash operating costs ($/bbl)⁽¹⁾	34.90		56.25		35.95		53.25

(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⁽¹⁾ per barrel were $27.80 in the second quarter of 2019, compared to $28.65 in the prior year quarter, with the increase in production more than offsetting additional operating, selling and general expenses detailed above. Oil Sands operations cash operating costs per barrel were further impacted by mandatory production curtailment, including the change in product mix and the yield loss associated with the increase in higher value SCO production. Total Oil Sands operations cash operating costs were $1.051 billion, compared to $940 million in the prior year quarter.

In the second quarter of 2019, non-production costs, which are excluded from Oil Sands operations cash operating costs, were lower than the prior year quarter, primarily due to a decrease in share-based compensation expense.

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

Inventory changes at Oil Sands operations in the second quarter of 2019 reflect a draw of crude inventory volumes as well as a decline in crude production costs towards the end of the quarter, as higher cost inventory was expensed and replaced with lower cost inventory. The prior year quarter reflected a draw of inventory.

Fort Hills cash operating costs⁽¹⁾ per barrel averaged $22.50 in the second quarter of 2019, compared to $28.55 in the prior year quarter, reflecting the impact of higher production volumes in the current period coupled with comparable cash operating costs. Non-production costs were lower due primarily to the prior year quarter including project start-up expenses

related to the ramp up of operations in 2018. In the second quarter of 2019, the impact of declining inventory costs more than offset a build of crude inventory, whereas the second quarter of 2018 reflects a build of higher value inventory while operations ramped up.

Syncrude cash operating costs⁽¹⁾ per barrel were $34.90 in the second quarter of 2019, compared to $56.25 in the prior year quarter, with the decrease attributable to the increase in production noted above. Suncor's share of Syncrude cash operating costs were $599 million in the second quarter of 2019, comparable to $603 million in the second quarter of 2018.

Oil Sands net earnings were $1.750 billion for the first six months of 2019, compared to $500 million in the prior year period. In addition to the factors explained in operating earnings below, net earnings for first six months of 2019 included a one-time deferred income tax recovery of $910 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022.

Oil Sands operating earnings for the first six months of 2019 were $840 million, compared to $500 million for the same period in 2018. Operating earnings improved as a result of increased production volumes, higher crude price realizations, and lower natural gas costs, partially offset by an increase in operating, selling and general expenses, primarily attributed to the ramp up of Fort Hills operations, the additional 5% Syncrude ownership interest acquired partway through 2018 and increased costs at Oil Sands operations, as detailed below. Production improved as a result of a decrease in planned overall upgrader maintenance, improved reliability at Syncrude and Oil Sands operations and the production ramp up at Fort Hills throughout 2018, partially offset by the impact of mandatory production curtailments in 2019 and completion of a turnaround at Firebag in the second quarter of 2019.

Funds from operations⁽¹⁾ for the first six months of 2019 were $3.050 billion for the Oil Sands segment, compared to $2.473 billion in the prior year period, with the increase primarily due to the same factors that influenced operating earnings noted above.

Oil Sands operations cash operating costs⁽¹⁾ per barrel averaged $28.85 for the first six months of 2019, an increase from an average of $27.70 for the first six months of 2018 due to an increase in operating, selling and general expense related to additional ore preparation costs, higher commodity consumption costs and additional expenses associated with emerging technologies intended to optimize future mining and extraction operations, partially offset by an increase in production and lower natural gas prices.

Fort Hills cash operating costs⁽¹⁾ per barrel averaged $25.80 for the first six months of 2019, compared to $35.90 for the same period of 2018, with the current period reflecting fully ramped up operations, although production was limited by mandatory production curtailments, and the increase in costs associated with a full six months of production. The prior year period was influenced by the ramp up of production in 2018, which led to lower operating expenses.

Syncrude cash operating costs⁽¹⁾ per barrel averaged $35.95 for the first six months of 2019, a decrease compared to $53.25 in the first six months of 2018, due to a significant increase in production, with the prior year period impacted by a power disruption and extended planned maintenance, as well as a decrease in cash operating costs, which was primarily attributed to lower maintenance costs. Syncrude cash operating costs per barrel were also unfavourably impacted by mandatory production curtailment, partially offset by the transfer and purchase of third-party curtailment credits.

The company completed maintenance events at Firebag and Upgrader 1 during the second quarter of 2019 and plans to commence scheduled maintenance at Upgrader 2 and at Syncrude late in the third quarter of 2019. The impact of this maintenance has been reflected in the company's 2019 guidance.


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Gross revenues⁽¹⁾	904		1 010		1 780		1 948

Less: Royalties⁽¹⁾	(75	)	(65	)	(187	)	(147	)

Operating revenues, net of royalties	829		945		1 593		1 801

Net earnings⁽²⁾	456		312		948		700

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽³⁾	(70	)	—		(70	)	—

Gain on asset disposal⁽⁴⁾	(139	)	—		(139	)	(133	)

Operating earnings⁽⁵⁾	247		312		739		567

Funds from operations⁽⁵⁾	507		539		1 209		1 005

(1): Production, revenues and royalties from the company's Libya operations have been presented in the Exploration and Production (E&P) section of this MD&A on an entitlement basis and exclude an equal and offsetting gross up of revenues and royalties of $90 million in the second quarter of 2019 and $122 million in the second quarter of 2018, which is required for presentation purposes in the company's financial statements under the working-interest basis.
(2): The three and six months ended June 30, 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 the second quarter of 2019, the company recorded a $70 million deferred income tax recovery in the E&P segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(4): In the second quarter of 2019, Suncor sold its 37% interest in Canbriam for total proceeds and an equivalent gain of $151 million ($139 million after-tax), which had previously been 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. The equity interest in Canbriam was acquired during the first quarter of 2018 in exchange for the company's mineral landholdings in northeast British Columbia, at which time a gain of $133 million after-tax was recorded on the transaction.
(5): 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 second quarter of 2019 decreased to $247 million, from $312 million in the prior year quarter, primarily as a result of a decrease in the Brent crude benchmark price and charges for non-commercial drilling results off the east coast of Canada and the U.K. North Sea.


	Three months ended June 30		Six months ended June 30
	2019	2018	2019	2018

E&P Canada

Terra Nova (mbbls/d)	11.3	13.6	12.2	14.5

Hibernia (mbbls/d)	23.8	25.5	24.7	25.8

White Rose (mbbls/d)	3.2	6.0	2.1	7.4

Hebron (mbbls/d)	23.6	13.5	21.0	10.9

North America Onshore (mboe/d)	—	—	—	1.0

	61.9	58.6	60.0	59.6

E&P International

Buzzard (mboe/d)	35.0	39.4	35.8	39.9

Golden Eagle (mboe/d)	8.2	12.6	9.2	13.4

United Kingdom (mboe/d)	43.2	52.0	45.0	53.3

Norway – Oda (mboe/d)	4.0	—	2.1	—

Libya (mbbls/d)	2.6	3.5	2.2	3.0

	49.8	55.5	49.3	56.3

Total Production (mboe/d)	111.7	114.1	109.3	115.9

Total Sales Volumes (mboe/d)	106.1	110.2	108.9	116.0

Production volumes for E&P Canada were 61,900 boe/d in the second quarter of 2019, compared to 58,600 boe/d in the prior year quarter. The increase in production was primarily due to increased production from Hebron, partially offset by the continued impact of White Rose's staged return to full operations, completion of planned maintenance at Terra Nova and natural declines.

E&P International production decreased to 49,800 boe/d, from 55,500 boe/d in the prior year quarter, primarily due to natural declines in the U.K. and a third-party outage impacting Golden Eagle, partially offset by increased production from the Oda project offshore Norway, which began production near the end of the first quarter of 2019 and averaged 4,000 boe/d in the second quarter of 2019.

E&P sales volumes were 106,100 boe/d in the second quarter of 2019, and were comparable to 110,200 boe/d in the prior year quarter.

Price realizations at both E&P Canada and E&P International in the second quarter of 2019 were lower than the prior year quarter due to the decrease in Brent crude benchmark pricing during the second quarter of 2019, partially offset by the impact of a weaker Canadian dollar on U.S. dollar denominated sales.

E&P royalties in the second quarter of 2019 were higher due to an increase in East Coast Canada sales volumes, partially offset by lower price realizations.

Operating and transportation expenses for the second quarter of 2019 were comparable to the prior year quarter.

DD&A and impairment expense in the second quarter of 2019 was lower when compared to the second 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 second quarter of 2019 was higher as compared to the prior year quarter as a result of exploration charges for non-commercial drilling results off the east coast of Canada and the U.K. North Sea.

Net earnings for E&P were $948 million for the first six months of 2019, compared to $700 million in the prior year period. In addition to the factors explained in operating earnings below, net earnings for first six months of 2019 included an after-tax gain of $139 million on the sale of the company's interest in Canbriam and a one-time deferred income tax recovery of $70 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022. The equity interest in Canbriam was acquired during the first quarter of 2018 in exchange for the company's mineral landholdings in northeast British Columbia, at which time a gain of $133 million after-tax was recorded on the transaction.

Operating earnings for E&P for the first six months of 2019 were $739 million, compared to $567 million in the first six months of 2018. The increase was primarily due to the receipt of $264 million, after-tax, for insurance proceeds related to the company's Libyan assets and lower DD&A, partially offset by a decrease in sales volumes, higher exploration expense and lower crude price realizations. The insurance proceeds received may be subject to provisional repayment that may be dependent on future performance and cash flows from Suncor's Libyan assets.

Funds from operations were $1.209 billion for the first six months of 2019, compared to $1.005 billion for the first six months of 2018, due to the same reasons noted in operating earnings above, adjusted for the impact of non-cash DD&A expense.

A planned ten-day maintenance event was completed at Terra Nova during the second quarter of 2019. There are no major maintenance events scheduled at Terra Nova in the third quarter of 2019.


	Three months ended June 30			Six months ended June 30
($ millions)	2019		2018	2019		2018

Operating revenues	5 626		5 921	10 830		11 359

Net earnings⁽¹⁾	765		671	1 774		1 460

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	(88	)	—	(88	)	—

Operating earnings⁽³⁾	677		671	1 686		1 460

Funds from operations⁽³⁾	932		892	2 185		1 803

(1): The three and six months ended June 30, 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): In the second quarter of 2019 the company recorded a $88 million deferred income tax recovery in the R&M segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings in the second quarter of 2019 were $677 million, compared to $671 million in the prior year quarter. Increased crude throughput, improved refining margins and favourable risk management activities more than offset a smaller FIFO gain, lower retail and marketing margins, and an increase in operating and transportation costs and higher DD&A.


	Three months ended June 30		Six months ended June 30
	2019	2018	2019	2018

Crude oil processed (mbbls/d)

Eastern North America	170.0	182.0	193.0	199.8

Western North America	229.1	162.1	228.9	198.7

Total	399.1	344.1	421.9	398.5

Refinery utilization⁽¹⁾ (%)

Eastern North America	77	82	87	90

Western North America	95	68	95	83

Total	86	74	91	86

Refined product sales (mbbls/d)

Gasoline	235.3	242.0	241.0	237.9

Distillate	206.1	181.7	213.9	192.9

Other	66.7	76.3	70.5	75.7

Total	508.1	500.0	525.4	506.5

Refining margin⁽²⁾ ($/bbl)	33.45	30.25	34.95	30.40

Refining operating expense⁽²⁾ ($/bbl)	5.90	6.25	5.75	5.45

(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 include the impact of the FIFO method of inventory valuation.

Refinery crude throughput was 399,100 bbls/d in the second quarter of 2019, compared to 344,100 bbls/d in the prior year quarter. Both periods were impacted by major planned maintenance, however, the maintenance completed in the current period was less significant when compared to the second quarter of 2018, which included the first full turnaround of the Edmonton refinery, as well as additional turnaround activities at the company's other three refineries. Completed second quarter 2019 maintenance included turnaround activities at the Sarnia and Montreal refineries, and planned maintenance at the Edmonton and Commerce City refineries, resulting in refinery utilization of 86%, compared to 74% in the prior year quarter.

Refined product sales increased in the second quarter of 2019 to 508,100 bbls/d, compared to 500,000 bbls/d in the prior year quarter, with the increase due to higher refinery crude throughput in the second quarter of 2019 and the associated increase in refined product availability. The prior period quarter included a significant draw of product inventory that was built up in advance of the planned turnaround of the entire Edmonton refinery in the second quarter of 2018.

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

Marketing gross margins in the second quarter of 2019 were lower than in the prior year quarter, primarily due to the impact of continued competitive pricing, partially offset by an increase in Canadian retail and wholesale sales volumes, setting a new second quarter and year to date record for those channels.

Operating expenses in the second quarter of 2019 increased compared to the prior year quarter, primarily due to higher refinery maintenance expenses, an increase in variable selling costs associated with the increase in sales and higher commodity input costs, which were tied to the increase in refinery throughput.

DD&A increased in the second quarter of 2019 due to the accounting treatment of capital leases under IFRS 16 in addition to the depreciation associated with the major turnarounds completed in the prior year quarter.

Net earnings for R&M were $1.774 billion for the first six months of 2019, compared to $1.460 billion in the prior year period. In addition to the factors explained in operating earnings below, net earnings for first six months of 2019 included a one-time deferred income tax recovery of $88 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022.

Operating earnings for R&M in the first six months of 2019 were $1.686 billion, compared to $1.460 billion in the first six months of 2018, with the increase attributable to a larger FIFO gain in the current period, an increase in refinery crude throughput, resulting from a decrease in planned maintenance, and higher benchmark cracks spreads, partially offset by narrower crude differentials and unfavourable product location differentials, higher operating, selling and general expense and an increase in DD&A. For the first six months of 2019, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO method, had a positive impact to operating earnings and funds from operations of $505 million after-tax, compared to $204 million after-tax in the first six months of 2018.

Funds from operations were $2.185 billion in the first six months of 2019, compared to $1.803 billion in the first six months of 2018, and increased primarily due to the same factors that influenced operating earnings described above, adjusted for the impact of non-cash DD&A expense.

The company has completed major planned maintenance at the Montreal, Sarnia, Edmonton and Commerce City refineries and does not have any significant maintenance scheduled for the third quarter of 2019.


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Net loss⁽¹⁾	(53	)	(414	)	(273	)	(899	)

Adjusted for:

Impact of income tax rate adjustment on deferred taxes⁽²⁾	(48	)	—		(48	)	—

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(221	)	218		(482	)	547

Operating loss⁽³⁾	(322	)	(196	)	(803	)	(352	)

Corporate	*(261*	)	(231	)	*(563*	)	(420	)

Eliminations	*(61*	)	35		*(240*	)	68

Funds used in operations⁽³⁾	(300	)	(60	)	(854	)	(255	)

(1): 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. The results from the company's Renewable Energy business are included within Corporate results.
(2): In the second quarter of 2019, the company recorded a $48 million deferred income tax recovery in the Corporate and Eliminations segment associated with the Government of Alberta's substantive enactment of legislation for the staged reduction of the corporate income tax rate from 12% to 8% over the next four years.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Corporate operating loss was $261 million for the second quarter of 2019, compared to an operating loss of $231 million for the prior year quarter, with the increased loss attributable to the prior period including the receipt of interest income related to a prior period tax settlement, lower income tax recoveries and an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year quarter, partially offset by a decrease in share-based compensation expense. Suncor capitalized $28 million of its borrowing costs in the second quarter of 2019 as part of the cost of major development assets and construction projects in progress, compared to $25 million in the prior year quarter.

Eliminations reflect the deferral or realization of profit 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 second quarter of 2019, the company deferred $61 million of after-tax intersegment profit, compared to a realization of $35 million of after-tax intersegment profit in the prior year quarter, due to an increase in intersegment inventory volumes.

Corporate and Eliminations funds used in operations in the second quarter of 2019 were unfavourable when compared to the prior year quarter due to the elimination of profit held in intercompany inventory, as compared to a realization of profit in the prior year quarter, the prior period including the receipt of interest income related to a prior period tax settlement, an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year quarter, and lower current tax recoveries.

The net loss for Corporate and Eliminations was $273 million for the first six months of 2019, compared to $899 million in the prior year period. In addition to the factors explained in operating earnings below, net earnings for first six months of 2019 included a $482 million unrealized after-tax foreign exchange gain on the revaluation of U.S. dollar denominated debt and a one-time deferred income tax recovery of $48 million associated with a staged reduction to the Alberta corporate income tax rate of 1% each year from 2019 to 2022. Net earnings in the prior year period included an unrealized after-tax foreign exchange loss of $547 million on the revaluation of U.S. dollar denominated debt.

The operating loss for Corporate and Eliminations for the first six months of 2019 was $803 million, compared to $352 million in the first six months of 2018. The increased loss was attributed to a significant elimination of profit held in intercompany inventory, as compared to a realization of profit in the prior year period, an operational foreign exchange loss, as compared to an operational foreign exchange gain in the prior year period, the prior period including the receipt of interest income related to a prior period tax settlement, lower capitalized interest and an increase in interest costs associated with IFRS 16, partially offset by lower share-based compensation accruals. The company capitalized $56 million of its borrowing costs in the first six months of 2019, compared with $102 million in the first six months of 2018, with the decrease resulting from the staged commissioning of Fort Hills in 2018. The elimination of intercompany profit in inventory was due to an increase in crude margins as well as an increase in intercompany inventory volumes.

Corporate and Eliminations funds used in operations for the first six months of 2019 were $854 million, compared to $255 million in the prior year period. In addition to the cash factors noted above in operating earnings, funds from operations in the first six months of 2019 were favourably impacted by a decrease in share-based compensation payments.

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

Three months ended
June 30, 2019

Six months ended
June 30, 2019

($ millions)

Asset
Sustainment and
Maintenance(2)

Economic
Investment(3)

Total

Asset
Sustainment and
Maintenance(2)

Economic
Investment(3)

Total

Oil Sands

Oil Sands Base

416

440

619

658

In Situ

153

199

336

403

Fort Hills

116

170

216

Syncrude

131

132

Exploration and Production

256

258

470

473

Refining and Marketing

173

218

232

299

Corporate and Eliminations

816

520

1 336

1 235

976

2 211

(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. Comparative periods have been updated to reflect this change.
(2): Asset sustainment 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 $1.336 billion on capital expenditures in the second quarter of 2019, excluding capitalized interest, a decrease from $1.737 billion in the prior year quarter, primarily due to the decrease in capital associated with the completion of a more significant planned maintenance program in the prior year quarter at both Oil Sands and R&M, as well as the decrease in capital associated with the staged completion and commissioning of the Fort Hills extraction plants in the first half of 2018.

Oil Sands Base capital and exploration expenditures were $440 million in the second quarter of 2019, the majority of which was focused on asset sustainment and maintenance activities related to the company's planned major maintenance program, which included the completion 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 $199 million in the second quarter of 2019, and were primarily directed towards economic investment activities, including well pad construction and drilling activities that are expected to maintain existing production levels at Firebag and MacKay River.

Capital expenditures at Fort Hills were $116 million in the second quarter of 2019, with the majority related to tailings infrastructure projects to sustain operations.

Syncrude capital and exploration expenditures were $84 million in the second quarter of 2019, the majority of which was for asset sustainment and maintenance capital expenditures focused on improving asset reliability.

Capital and exploration expenditures at E&P were $258 million in the second quarter of 2019 and were primarily focused on economic investment projects, including development drilling at Hebron, Hibernia, White Rose, Buzzard and Terra Nova, and continued development work on Fenja and the West White Rose Project.

During the second quarter of 2019, the company sanctioned the Terra Nova asset life extension project, which is expected to extend the life of Terra Nova by approximately a decade and is planned for execution in 2020.

R&M capital expenditures were $218 million and were primarily related to the ongoing sustainment of operations, enhancements to retail operations and planned major refinery maintenance.

Corporate capital expenditures were $21 million, primarily directed towards the company's information technology initiatives.


	Twelve months ended
	Previous leasing standard June 30 2019	IFRS 16 impact		IFRS 16 June 30 2019	June 30 2018

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress⁽²⁾	10.7	(0.1	)	10.6	9.5

Including major projects in progress	10.5	(0.1	)	10.4	8.3

Net debt to funds from operations⁽³⁾ (times)	1.3	0.2		1.5	1.5

Interest coverage on long-term debt (times)

Earnings basis⁽⁴⁾	8.0	(0.3	)	7.7	7.4

Funds from operations basis⁽³⁾⁽⁵⁾	14.6	(0.5	)	14.1	13.7

Total debt to total debt plus shareholders' equity (%)	26.5	2.0		28.5	28.3

(1): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): ROCE excluding major projects in progress would have been 8.7% in the second quarter of 2019 if the $1.116 billion deferred tax recovery for the Alberta corporate income tax rate change was excluded.
(3): 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.
(4): Equal to net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest on debt.
(5): 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 lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2019 capital spending program of $4.9 to $5.4 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, if needed, 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.

For the six months ended June 30, 2019, cash and cash equivalents decreased to $2.061 billion, from $2.221 billion at December 31, 2018, with uses of cash in respect of the company's capital and exploration expenditures, dividend requirements, the purchase of $1.066 billion of Suncor's own shares under its NCIB and a net debt reduction of $540 million of debt, inclusive of lease payments, marginally exceeding cash flow provided by operating activities.

For the three months ended June 30, 2019, cash and cash equivalents increased to $2.061 billion, from $1.875 billion at March 31, 2019, due to cash flow provided by operating activities exceeding the company's capital and exploration expenditures, dividend requirements, the purchase of $552 million of Suncor's own shares under its NCIB and a net debt reduction of $796 million, inclusive of lease payments.

As at June 30, 2019, the weighted average term to maturity of the company's short-term investment portfolio was approximately fourteen days.

Available credit facilities for liquidity purposes at June 30, 2019 increased to $4.688 billion, compared to $3.608 billion at December 31, 2018, primarily as a result of a significant reduction in short-term indebtedness noted above, partially offset by the improvement in the Canadian dollar on U.S. dollar short-term debt.

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 June 30, 2019, total debt to total debt plus shareholders' equity was 28.5% (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)	June 30 2019	December 31 2018(1)

Short-term debt	2 198	3 231

Current portion of long-term debt	—	191

Current portion of long-term lease liabilities	307	38

Long-term debt	12 984	12 668

Long-term lease liabilities	2 693	1 222

Total debt	18 182	17 350

Less: Cash and cash equivalents	2 061	2 221

Net debt	16 121	15 129

Shareholders' equity	45 509	44 005

Total debt plus shareholders' equity	63 691	61 355

Total debt to total debt plus shareholders' equity (%)	28.5	28.3

(1): Excludes the impact of IFRS 16, which was prospectively adopted on January 1, 2019 in accordance with the standard.

In May 2019, the company issued $750 million of senior unsecured Series 6 Medium Term Notes maturing on May 24, 2029, with a coupon of 3.10%.


($ millions)	Three months ended June 30, 2019		Six months ended June 30, 2019

Total debt – beginning of period	19 173		17 350

Increase in long-term debt	557		557

Decrease in short-term debt	(1 281	)	(955	)

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

Increase in lease liability	41		92

Lease payments	(72	)	(142	)

Foreign exchange on debt, and other	(236	)	(512	)

Total debt – June 30, 2019	18 182		18 182

Less: Cash and cash equivalents – June 30, 2019	2 061		2 061

Net debt – June 30, 2019	16 121		16 121

The company's total debt decreased in the second quarter of 2019 due to a significant reduction of short-term indebtedness, favourable foreign exchange rates on U.S. dollar denominated debt compared to March 31, 2019, the repayment of US$140 million of maturing higher interest long-term debt and lease principal payments made during the second quarter of 2019, partially offset by a $750 million increase in long-term indebtedness and leases entered into during the period.

The company's total debt has increased in 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, a net increase in long-term debt and leases entered into during the first six months of 2019, partially offset by the repayment of $955 million of short-term debt, favourable foreign exchange rates on U.S. dollar denominated debt, as compared to December 31, 2018, and lease principal payments made during the first half of 2019.

As at July 22, 2019, the total number of common shares outstanding was 1,557,613,662 and the total number of exercisable and non-exercisable common share options outstanding was 35,381,135. 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 Toronto Stock Exchange (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 it was entitled to purchase for cancellation between May 4, 2018 and May 3, 2019 to 81,695,830 common shares.

During the second 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 second quarter of 2019, Suncor repurchased and cancelled 13,001,087 common shares at an average price of $42.46 per share, for a total of $552 million, compared to the prior year quarter when the company repurchased and cancelled 11,860,356 common shares at an average price of $51.33 per share, for a total of $609 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 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 to note during the first six months 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 Government of Alberta's mandatory production curtailments implemented in the first six months of 2019.


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

Total production (mboe/d)

Oil Sands	692.2	657.2	740.8		651.7	547.6		571.7		621.2		628.4

Exploration and Production	111.7	107.1	90.2		92.1	114.1		117.7		115.2		111.5

	803.9	764.3	831.0		743.8	661.7		689.4		736.4		739.9

Revenues and other income

Operating revenues, net of royalties	10 071	8 983	8 561		10 847	10 327		8 807		9 000		7 963

Other income (loss)	27	414	384		16	101		(57	)	41		43

	10 098	9 397	8 945		10 863	10 428		8 750		9 041		8 006

Net earnings (loss)	2 729	1 470	(280	)	1 812	972		789		1 382		1 289

per common share – basic (dollars)	1.74	0.93	(0.18	)	1.12	0.60		0.48		0.84		0.78

per common share – diluted (dollars)	1.74	0.93	(0.18	)	1.11	0.59		0.48		0.84		0.78

Operating Earnings⁽¹⁾	1 253	1 209	580		1 557	1 190		985		1 310		867

per common share – basic⁽¹⁾ (dollars)	0.80	0.77	0.36		0.96	0.73		0.60		0.79		0.52

Funds from operations⁽¹⁾	3 005	2 585	2 007		3 139	2 862		2 164		3 016		2 472

per common share – basic⁽¹⁾ (dollars)	1.92	1.64	1.26		1.94	1.75		1.32		1.83		1.49

Cash flow provided by operating activities	3 433	1 548	3 040		4 370	2 446		724		2 755		2 912

per common share – basic (dollars)	2.19	0.98	1.90		2.70	1.50		0.44		1.67		1.75

ROCE⁽¹⁾ (%) for the twelve months ended	10.4	8.2	8.0		9.7	8.3		6.5		6.7		5.5

ROCE⁽¹⁾, excluding major projects in progress (%) for twelve months ended	10.6	8.3	8.2		10.4	9.5		7.8		8.6		7.0

After-tax unrealized foreign exchange gain (loss) on U.S. dollar denominated debt	221	261	(637	)	195	(218	)	(329	)	(91	)	412

Common share information (dollars)

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

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	40.85	43.31	38.13		49.98	53.50		44.49		46.15		43.73

New York Stock Exchange (US$)	31.16	32.43	27.97		38.69	40.68		34.54		36.72		35.05

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


(average for the three months ended)		June 30 2019		Mar 31 2019		Dec 31 2018		Sept 30 2018		June 30 2018		Mar 31 2018		Dec 31 2017		Sept 30 2017

WTI crude oil at Cushing	US$/bbl	59.85		54.90		58.85		69.50		67.90		62.90		55.40		48.20

Dated Brent crude	US$/bbl	68.85		63.20		67.80		75.25		74.40		66.80		61.40		52.50

Dated Brent/Maya FOB price differential	US$/bbl	6.90		5.00		4.35		10.20		12.40		7.70		9.60		6.30

MSW at Edmonton	Cdn$/bbl	73.40		66.45		42.70		82.10		80.95		72.45		69.30		57.05

WCS at Hardisty	US$/bbl	49.20		42.50		19.50		47.35		48.65		38.60		43.10		38.25

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	(10.65	)	(12.40	)	(39.35	)	(22.15	)	(19.25	)	(24.30	)	(12.30	)	(9.95	)

SYN-WTI (differential) premium	US$/bbl	0.15		(2.30	)	(21.60	)	(0.90	)	(0.65	)	(1.45	)	3.25		0.65

Condensate at Edmonton	US$/bbl	55.90		50.55		45.30		66.80		68.50		63.15		57.95		47.60

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.05		2.55		1.60		1.20		1.20		1.75		1.70		1.45

Alberta Power Pool Price	Cdn$/MWh	56.35		70.75		55.55		54.45		56.00		34.95		22.35		24.55

New York Harbor 2-1-1 crack⁽¹⁾	US$/bbl	22.20		18.25		19.15		20.25		21.10		16.70		20.50		22.00

Chicago 2-1-1 crack⁽¹⁾	US$/bbl	21.45		15.35		16.35		20.00		19.05		14.25		21.40		19.80

Portland 2-1-1 crack⁽¹⁾	US$/bbl	26.85		19.35		22.25		22.05		28.65		21.00		23.55		26.95

Gulf Coast 2-1-1 crack⁽¹⁾	US$/bbl	21.70		17.85		17.65		19.35		20.45		16.30		19.10		21.20

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

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

(1): 2-1-1 crack spreads are indicators of the refining margin generated by converting two barrels of WTI into one barrel of gasoline and one barrel of diesel. The company previously quoted 3-2-1 crack margin benchmarks based on wider use and familiarity with these benchmarks and though the 3-2-1 crack spread is more commonly quoted, the company's refinery production is better aligned with a 2-1-1 crack spread, which better reflects the approximate composition of Suncor's overall refined product mix. 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 and six months ended June 30, 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 and six months ended June 30, 2019, and the Financial Condition and Liquidity section of the 2018 annual MD&A.

Based on their evaluation as at June 30, 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 June 30, 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 June 30, 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 July 24, 2019, which is 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, LIFO inventory valuation methodology and related per share amounts – 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 June 30 ($ millions, except as noted)		2019		2018

Adjustments to net earnings

Net earnings		5 731		4 432

(Deduct) add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(40	)	226

Net interest expense		616		321

	A	6 307		4 979

Capital employed – beginning of twelve-month period

Net debt		16 163		13 780

Shareholders' equity		45 543		44 887

		61 706		58 667

Capital employed – end of twelve-month period

Net debt		16 121		16 163

Shareholders' equity		45 509		45 543

		61 630		61 706

Average capital employed	B	60 702		59 793

ROCE – including major projects in progress (%)	A/B	10.4		8.3

Average capitalized costs related to major projects in progress	C	1 135		7 202

ROCE – excluding major projects in progress (%)	A/(B-C)	10.6		9.5

Funds from (used in) operations is a non-GAAP financial measure that adjusts a GAAP measure – cash flow provided by (used in) operating activities – for changes in non-cash working capital, which management uses to analyze operating performance and liquidity. Changes to non-cash working capital can 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.

Funds from (used in) operations for each quarter are separately defined and reconciled to the cash flow provided by operating activities measure in the Non-GAAP Financial Measures Advisory section of each respective management's discussion and analysis or quarterly report to shareholders, as applicable, for the related quarter.


Three months ended June 30	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)	1 561		403		456		312		765		671		(53	)	(414	)	2 729		972

Adjustments for:

Depreciation, depletion, amortization and impairment	1 060		954		235		249		200		174		18		14		1 513		1 391

Deferred income taxes	(797	)	84		(89	)	(30	)	(66	)	26		(48	)	11		(1 000	)	91

Accretion	55		53		11		12		2		2		—		—		68		67

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(231	)	245		(231	)	245

Change in fair value of financial instruments and trading inventory	38		19		11		(7	)	27		1		—		—		76		13

Gain on disposal of assets	(6	)	—		(151	)	—		(1	)	(4	)	—		—		(158	)	(4	)

Share-based compensation	9		52		1		6		5		23		9		76		24		157

Exploration	—		—		37		—		—		—		—		—		37		—

Settlement of decommissioning and restoration liabilities	(68	)	(84	)	(4	)	(3	)	(4	)	(3	)	—		—		(76	)	(90	)

Other	14		10		—		—		4		2		5		8		23		20

Funds from (used in) operations	1 866		1 491		507		539		932		892		(300	)	(60	)	3 005		2 862

Decrease (increase) in non-cash working capital																	428		(416	)

Cash flow provided by operating activities																	3 433		2 446


Six months ended June 30	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)	1 750		500		948		700		1 774		1 460		(273	)	(899	)	4 199		1 761

Adjustments for:

Depreciation, depletion, amortization and impairment	2 052		1 928		482		528		403		328		38		31		2 975		2 815

Deferred income taxes	(737	)	141		(122	)	(85	)	(61	)	49		(77	)	15		(997	)	120

Accretion	113		104		22		24		4		4		—		—		139		132

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(511	)	618		(511	)	618

Change in fair value of financial instruments and trading inventory	44		15		7		(36	)	97		(18	)	—		1		148		(38	)

Gain on disposal of assets	(10	)	(1	)	(151	)	(162	)	(2	)	(4	)	—		—		(163	)	(167	)

Share-based compensation	(25	)	(12	)	(4	)	(4	)	(19	)	(16	)	(37	)	(35	)	(85	)	(67	)

Exploration	—		—		39		—		—		—		—		—		39		—

Settlement of decommissioning and restoration liabilities	(180	)	(238	)	(5	)	(16	)	(5	)	(5	)	—		—		(190	)	(259	)

Other	43		36		(7	)	56		(6	)	5		6		14		36		111

Funds from (used in) operations	3 050		2 473		1 209		1 005		2 185		1 803		(854	)	(255	)	5 590		5 026

Increase in non-cash working capital																	(609	)	(1 856	)

Cash flow provided by operating activities																	4 981		3 170

Discretionary free funds flow is a non-GAAP financial measure that is calculated by taking funds from operations and subtracting asset sustainment and maintenance 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, and the company's former lubricants business, 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 the company's former lubricants business; and ii) non-refining costs that management believes do not relate to the production of refined products, including, but not limited to, share-based compensation and enterprise shared service allocations. Management uses refining margin and refining operating expense to measure operating performance on a production barrel basis.


	Three months ended June 30				Six months ended June 30
($ millions, except as noted)	2019		2018		2019		2018

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 647		1 639		3 787		3 424

Other income (loss)	14		(15	)	29		(32	)

Non-refining margin	(326	)	(620	)	(913	)	(1 035	)

Refining margin	1 335		1 004		2 903		2 357

Refinery production⁽¹⁾ (mbbls)	39 901		33 165		83 044		77 528

Refining margin ($/bbl)	33.45		30.25		34.95		30.40

Refining operating expense reconciliation

Operating, selling and general expense	530		494		1 066		986

Non-refining costs	(295	)	(288	)	(589	)	(562	)

Refining operating expense	235		206		477		424

Refinery production⁽¹⁾ (mbbls)	39 901		33 165		83 044		77 528

Refining operating expense ($/bbl)	5.90		6.25		5.75		5.45

(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
		Q2	Three months ended June 30
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

The MD&A 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 the MD&A 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 major 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, the 2018 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other MD&As that Suncor files from time to time with securities regulatory authorities. Copies of these MD&As are available without charge from the company.

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


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Revenues and Other Income

Operating revenues, net of royalties (note 4)	10 071		10 327		19 054		19 134

Other income (note 5)	27		101		441		44

	10 098		10 428		19 495		19 178

Expenses

Purchases of crude oil and products	3 286		4 056		5 907		6 903

Operating, selling and general	2 799		2 612		5 631		5 232

Transportation	361		335		697		609

Depreciation, depletion, amortization and impairment	1 513		1 391		2 975		2 815

Exploration	76		19		189		51

Gain on asset exchange and disposals (note 16)	(158	)	(4	)	(163	)	(167	)

Financing expenses (note 7)	97		543		129		1 105

	7 974		8 952		15 365		16 548

Earnings before Income Taxes	2 124		1 476		4 130		2 630

Income Tax Expense (Recovery)

Current	395		413		928		749

Deferred (note 15)	(1 000	)	91		(997	)	120

	(605	)	504		(69	)	869

Net Earnings	2 729		972		4 199		1 761

Other Comprehensive (Loss) Income

Items That May be Subsequently Reclassified to Earnings:

Foreign currency translation adjustment	(80	)	36		(148	)	165

Items That Will Not be Reclassified to Earnings:

Actuarial (loss) gain on employee retirement benefit plans, net of income taxes	(177	)	129		(313	)	119

Other Comprehensive (Loss) Income	(257	)	165		(461	)	284

Total Comprehensive Income	2 472		1 137		3 738		2 045

Per Common Share (dollars) (note 8)

Net earnings – basic	1.74		0.60		2.67		1.08

Net earnings – diluted	1.74		0.59		2.66		1.07

Cash dividends	0.42		0.36		0.84		0.72

See accompanying notes to the condensed interim consolidated financial statements.


($ millions)	June 30 2019	December 31 2018

Assets

Current assets

Cash and cash equivalents	2 061	2 221

Accounts receivable	4 345	3 206

Inventories	3 734	3 159

Income taxes receivable	153	114

Total current assets	10 293	8 700

Property, plant and equipment, net (note 12)	76 398	74 245

Exploration and evaluation	2 374	2 319

Other assets	1 275	1 126

Goodwill and other intangible assets	3 059	3 061

Deferred income taxes	200	128

Total assets	93 599	89 579

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	2 198	3 231

Current portion of long-term debt	—	229

Current portion of long-term lease liabilities (note 3)	307	—

Accounts payable and accrued liabilities	6 214	5 647

Current portion of provisions	711	667

Income taxes payable	1 059	535

Total current liabilities	10 489	10 309

Long-term debt	12 984	13 890

Long-term lease liabilities (note 3)	2 693	—

Other long-term liabilities (note 10)	2 751	2 346

Provisions (note 11)	8 174	6 984

Deferred income taxes (note 15)	10 999	12 045

Equity	45 509	44 005

Total liabilities and shareholders' equity	93 599	89 579

See accompanying notes to the condensed interim consolidated financial statements.


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Operating Activities

Net Earnings	2 729		972		4 199		1 761

Adjustments for:

Depreciation, depletion, amortization and impairment	1 513		1 391		2 975		2 815

Deferred income tax (recovery) expense	(1 000	)	91		(997	)	120

Accretion	68		67		139		132

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	(231	)	245		(511	)	618

Change in fair value of financial instruments and trading inventory	76		13		148		(38	)

Gain on asset exchange and disposals (note 16)	(158	)	(4	)	(163	)	(167	)

Share-based compensation	24		157		(85	)	(67	)

Exploration	37		—		39		—

Settlement of decommissioning and restoration liabilities	(76	)	(90	)	(190	)	(259	)

Other	23		20		36		111

Decrease (increase) in non-cash working capital	428		(416	)	(609	)	(1 856	)

Cash flow provided by operating activities	3 433		2 446		4 981		3 170

Investing Activities

Capital and exploration expenditures	(1 364	)	(1 762	)	(2 267	)	(3 053	)

Acquisitions (notes 13 and 14)	—		(123	)	—		(1 191	)

Proceeds from disposal of assets (note 16)	159		4		166		4

Other investments (note 16)	(42	)	(27	)	(99	)	(84	)

Decrease (increase) in non-cash working capital	28		145		(6	)	388

Cash flow used in investing activities	(1 219	)	(1 763	)	(2 206	)	(3 936	)

Financing Activities

Net (decrease) increase in short-term debt	(1 281	)	234		(955	)	1 979

Net increase (decrease) in long-term debt	557		(18	)	557		(35	)

Lease liability payments	(72	)	—		(142	)	—

Issuance of common shares under share option plans	6		187		41		256

Purchase of common shares (note 9)	(552	)	(609	)	(1 066	)	(998	)

Distributions relating to non-controlling interest	(2	)	(2	)	(4	)	(2	)

Dividends paid on common shares	(658	)	(587	)	(1 320	)	(1 177	)

Cash flow (used in) provided by financing activities	(2 002	)	(795	)	(2 889	)	23

Increase (Decrease) in Cash and Cash Equivalents	212		(112	)	(114	)	(743	)

Effect of foreign exchange on cash and cash equivalents	(26	)	12		(46	)	54

Cash and cash equivalents at beginning of period	1 875		2 083		2 221		2 672

Cash and Cash Equivalents at End of Period	2 061		1 983		2 061		1 983

Supplementary Cash Flow Information

Interest paid	352		306		506		413

Income taxes paid	282		47		398		664

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	—		—		—		1 761		1 761		—

Foreign currency translation adjustment	—		—		165		—		165		—

Actuarial gain on employee retirement benefit plans, net of income taxes of $44	—		—		—		119		119		—

Total comprehensive income	—		—		165		1 880		2 045		—

Issued under share option plans	321		(66	)	—		—		255		7 098

Purchase of common shares for cancellation (note 9)	(337	)	—		—		(661	)	(998	)	(20 859	)

Change in liability for share purchase commitment (note 9)	15		—		—		(10	)	5		—

Share-based compensation	—		30		—		—		30		—

Dividends paid on common shares	—		—		—		(1 177	)	(1 177	)	—

At June 30, 2018	26 605		531		974		17 433		45 543		1 627 222

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	—		—		—		4 199		4 199		—

Foreign currency translation adjustment	—		—		(148	)	—		(148	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $107	—		—		—		(313	)	(313	)	—

Total comprehensive (loss) income	—		—		(148	)	3 886		3 738		—

Issued under share option plans	53		(11	)	—		—		42		1 197

Purchase of common shares for cancellation (note 9)	(406	)	—		—		(660	)	(1 066	)	(24 952	)

Change in liability for share purchase commitment (note 9)	30		—		—		33		63		—

Share-based compensation	—		33		—		—		33		—

Dividends paid on common shares	—		—		—		(1 320	)	(1 320	)	—

At June 30, 2019	25 587		562		928		18 432		45 509		1 560 729

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 enacted or 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 June 30	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	3 985		3 602		994		1 132		5 592		5 898		6		6		10 577		10 638

Intersegment revenues	1 155		578		—		—		34		23		(1 189	)	(601	)	—		—

Less: Royalties	(341	)	(124	)	(165	)	(187	)	—		—		—		—		(506	)	(311	)

Operating revenues, net of royalties	4 799		4 056		829		945		5 626		5 921		(1 183	)	(595	)	10 071		10 327

Other income (loss)	1		53		9		—		14		(15	)	3		63		27		101

	4 800		4 109		838		945		5 640		5 906		(1 180	)	(532	)	10 098		10 428

Expenses

Purchases of crude oil and products	404		400		—		—		3 979		4 282		(1 097	)	(626	)	3 286		4 056

Operating, selling and general	2 060		1 849		114		114		530		494		95		155		2 799		2 612

Transportation	326		291		21		22		27		32		(13	)	(10	)	361		335

Depreciation, depletion, amortization and impairment	1 060		954		235		249		200		174		18		14		1 513		1 391

Exploration	10		4		66		15		—		—		—		—		76		19

Gain on asset exchange and disposals	(6	)	—		(151	)	—		(1	)	(4	)	—		—		(158	)	(4	)

Financing expenses (income)	74		79		14		11		14		8		(5	)	445		97		543

	3 928		3 577		299		411		4 749		4 986		(1 002	)	(22	)	7 974		8 952

Earnings (Loss) before Income Taxes	872		532		539		534		891		920		(178	)	(510	)	2 124		1 476

Income Tax (Recovery) Expense

Current	108		45		172		252		192		223		(77	)	(107	)	395		413

Deferred	(797	)	84		(89	)	(30	)	(66	)	26		(48	)	11		(1 000	)	91

	(689	)	129		83		222		126		249		(125	)	(96	)	(605	)	504

Net Earnings (Loss)	1 561		403		456		312		765		671		(53	)	(414	)	2 729		972

Capital and Exploration Expenditures	856		1 121		268		251		220		370		20		20		1 364		1 762

(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 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 the Corporate and Eliminations segment.


Six months ended June 30	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	7 204		6 173		1 931		2 149		10 782		11 315		14		15		19 931		19 652

Intersegment revenues	2 117		1 606		—		—		48		44		(2 165	)	(1 650	)	—		—

Less: Royalties	(539	)	(170	)	(338	)	(348	)	—		—		—		—		(877	)	(518	)

Operating revenues, net of royalties	8 782		7 609		1 593		1 801		10 830		11 359		(2 151	)	(1 635	)	19 054		19 134

Other income (loss)	11		68		395		(58	)	29		(32	)	6		66		441		44

	8 793		7 677		1 988		1 743		10 859		11 327		(2 145	)	(1 569	)	19 495		19 178

Expenses

Purchases of crude oil and products	677		670		—		—		7 043		7 935		(1 813	)	(1 702	)	5 907		6 903

Operating, selling and general	4 033		3 724		262		225		1 066		986		270		297		5 631		5 232

Transportation	624		517		40		46		56		70		(23	)	(24	)	697		609

Depreciation, depletion, amortization and impairment	2 052		1 928		482		528		403		328		38		31		2 975		2 815

Exploration	112		27		77		24		—		—		—		—		189		51

Gain on asset exchange and disposals	(10	)	(1	)	(151	)	(162	)	(2	)	(4	)	—		—		(163	)	(167	)

Financing expenses (income)	143		156		28		12		27		11		(69	)	926		129		1 105

	7 631		7 021		738		673		8 593		9 326		(1 597	)	(472	)	15 365		16 548

Earnings (Loss) before Income Taxes	1 162		656		1 250		1 070		2 266		2 001		(548	)	(1 097	)	4 130		2 630

Income Tax (Recovery) Expense

Current	149		15		424		455		553		492		(198	)	(213	)	928		749

Deferred	(737	)	141		(122	)	(85	)	(61	)	49		(77	)	15		(997	)	120

	(588	)	156		302		370		492		541		(275	)	(198	)	(69	)	869

Net Earnings (Loss)	1 750		500		948		700		1 774		1 460		(273	)	(899	)	4 199		1 761

Capital and Exploration Expenditures	1 440		2 113		496		416		302		487		29		37		2 267		3 053

(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 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 the 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:


Three months ended June 30	2019					2018
($ millions)	North America		International	Total		North America		International	Total

Oil Sands

SCO and diesel	3 660		—	3 660		2 919		—	2 919

Bitumen	1 480		—	1 480		1 261		—	1 261

	5 140		—	5 140		4 180		—	4 180

Exploration and Production

Crude oil and natural gas liquids	507		486	993		485		644	1 129

Natural gas	—		1	1		—		3	3

	507		487	994		485		647	1 132

Refining and Marketing

Gasoline	2 660		—	2 660		2 920		—	2 920

Distillate	2 255		—	2 255		2 234		—	2 234

Other	711		—	711		767		—	767

	5 626		—	5 626		5 921		—	5 921

Corporate and Eliminations

	(1 183	)	—	(1 183	)	(595	)	—	(595	)

Total Revenue from Contracts with Customers	10 090		487	10 577		9 991		647	10 638


Six months ended June 30	2019					2018
($ millions)	North America		International	Total		North America		International	Total

Oil Sands

SCO and diesel	6 938		—	6 938		5 869		—	5 869

Bitumen	2 383		—	2 383		1 910		—	1 910

	9 321		—	9 321		7 779		—	7 779

Exploration and Production

Crude oil and natural gas liquids	998		930	1 928		966		1 173	2 139

Natural gas	—		3	3		3		7	10

	998		933	1 931		969		1 180	2 149

Refining and Marketing

Gasoline	4 766		—	4 766		5 308		—	5 308

Distillate	4 638		—	4 638		4 524		—	4 524

Other	1 426		—	1 426		1 527		—	1 527

	10 830		—	10 830		11 359		—	11 359

Corporate, Energy Trading and Eliminations

	(2 151	)	—	(2 151	)	(1 635	)	—	(1 635	)

Total Revenue from Contracts with Customers	18 998		933	19 931		18 472		1 180	19 652

(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.


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Energy trading activities

Unrealized gains recognized in earnings	15		35		110		21

(Losses) gains on inventory valuation	(12	)	3		(35	)	19

Risk management activities⁽¹⁾	11		(44	)	(46	)	(69	)

Investment and interest income	—		(3	)	50		6

Insurance proceeds⁽²⁾	34		33		397		33

Other⁽³⁾	(21	)	77		(35	)	34

	27		101		441		44

(1): Includes fair value changes related to short-term derivative contracts in the Oil Sands and Refining and Marketing segments.
(2): 2019 and 2018 includes insurance proceeds for Syncrude within Oil Sands segment, and six months ended June 30, 2019 includes insurance proceeds for Libyan assets within Exploration and Production segment (note 16).
(3): Includes $60 million of interest income related to prior period tax settlement recorded in the second quarter of 2018.

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


	Three months ended June 30				Six months ended June 30
($ millions)	2019		2018		2019		2018

Interest on debt	202		234		412		443

Interest on lease liabilities (note 3)	43		—		88		—

Capitalized interest	(28	)	(25	)	(56	)	(102	)

Interest expense	217		209		444		341

Interest on partnership liability	14		14		28		28

Interest on pension and other post-retirement benefits	15		15		30		29

Accretion	68		67		139		132

Foreign exchange (gain) loss on U.S. dollar denominated debt	(231	)	245		(511	)	618

Foreign exchange and other	14		(7	)	(1	)	(43	)

	97		543		129		1 105

During the second quarter of 2019, the company re-paid its US$140 million (book value of $188 million) senior unsecured notes at maturity, with a coupon of 7.75%, for US$145 million ($195 million), including US$5 million ($7 million) of accrued interest.

In May 2019, the company issued $750 million of senior unsecured Series 6 Medium Term Notes maturing on May 24, 2029. The Series 6 Medium Term Notes have a coupon of 3.10% and were priced at $99.761 per $100 principal amount for an effective yield of 3.128%. Interest is paid semi-annually.


	Three months ended June 30		Six months ended June 30
($ millions)	2019	2018	2019	2018

Net earnings	2 729	972	4 199	1 761

(millions of common shares)

Weighted average number of common shares	1 569	1 633	1 574	1 636

Dilutive securities:

Effect of share options	3	8	3	7

Weighted average number of diluted common shares	1 572	1 641	1 577	1 643

(dollars per common share)

Basic earnings per share	1.74	0.60	2.67	1.08

Diluted earnings per share	1.74	0.59	2.66	1.07

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 it was permitted to repurchase for cancellation between May 4, 2018 and May 3, 2019 to 81,695,830.

On May 1, 2019, the company announced its intention to renew its existing normal course issuer bid (the 2019 NCIB) to continue to repurchase shares under its previously announced buyback program through the facilities of the TSX, NYSE and/or alternative trading platforms. Pursuant to the 2019 NCIB, the company is permitted to purchase for cancellation up to 50,252,231 of its common shares between May 6, 2019 and May 5, 2020.

During the second quarter of 2019, the company repurchased 13.0 million common shares under the 2019 NCIB at an average price of $42.46 per share, for a total repurchase cost of $552 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:

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 June 30, 2019:

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

The company uses foreign exchange forwards to mitigate its exposure to the effect of future foreign exchange movements on future debt issuance or settlements. As at June 30, 2019, the fair value of foreign exchange forward contracts was $95 million.

At June 30, 2019, the carrying value of fixed-term debt accounted for under amortized cost was $13.0 billion (December 31, 2018 – $12.9 billion) and the fair value was $15.8 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 $1.2 billion for the six months ended June 30, 2019. The increase was primarily due to a decrease in the credit-adjusted risk-free interest rate to 3.30% (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	88

Foreign exchange	(6	)

At June 30, 2019	3 408

Accumulated provision

At January 1, 2019	267

Depreciation	163

At June 30, 2019	430

Net ROU assets

At January 1, 2019	3 059

At June 30, 2019	2 978

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 $109 million to gross revenues and a $2 million net loss to consolidated net earnings (loss) from the acquisition date to June 30, 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 $19.72 billion and consolidated net earnings of $1.77 billion for the six months ended June 30, 2018.

In the second quarter of 2019, Suncor recognized a deferred income tax recovery of $1.116 billion related to a decrease in the Alberta corporate tax rate from 12% to 8%. The tax rate decrease will be phased in as follows: 11% effective July 1, 2019, 10% effective January 1, 2020, 9% effective January 1, 2021, and 8% effective January 1, 2022. The deferred income tax recovery of $1.116 billion was comprised of $910 million recovery in the Oil Sands segment, $88 million recovery in the Refining and Marketing segment, $70 million recovery in the Exploration and Production segment and $48 million recovery in the Corporate and Eliminations segment.

On June 28, 2019, the company completed a transaction to sell its 37% equity interest in Canbriam Energy Inc. (Canbriam) and recognized a gain on sale for the full proceeds of $151 million ($139 million after-tax) in the Exploration and Production segment. The investment in Canbriam was acquired early in 2018 through the exchange of Suncor's northeast British Columbia mineral landholdings, including associated production, and consideration of $52 million. Subsequently, the company

wrote down its investment in Canbriam to nil in the fourth quarter of 2018, following an assessment of expected future commodity prices and net cash flows relative to the value of its investment.

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.

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION
QUARTERLY FINANCIAL SUMMARY
(unaudited)


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

Revenues, net of royalties, and other income		10 098			9 397			8 945			10 863			10 428			19 495			19 178			38 986

Net earnings (loss)^(A)

Oil Sands		1 561			189			(377	)		822			403			1 750			500			945

Exploration and Production		456			492			(115	)		222			312			948			700			807

Refining and Marketing		765			1009			762			932			671			1 774			1 460			3 154

Corporate and Eliminations		(53	)		(220	)		(550	)		(164	)		(414	)		(273	)		(899	)		(1 613	)

		2 729			1 470			(280	)		1 812			972			4 199			1 761			3 293

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

Oil Sands		651			189			(377	)		762			403			840			500			885

Exploration and Production		247			492			108			222			312			739			567			897

Refining and Marketing		677			1009			762			932			671			1 686			1 460			3 154

Corporate and Eliminations		(322	)		(481	)		87			(359	)		(196	)		(803	)		(352	)		(624	)

		1 253			1209			580			1 557			1 190			2 462			2 175			4 312

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

Oil Sands		1 866			1 184			607			1 884			1 491			3 050			2 473			4 964

Exploration and Production		507			702			331			443			539			1 209			1 005			1 779

Refining and Marketing		932			1 253			873			1 122			892			2 185			1 803			3 798

Corporate and Eliminations		(300	)		(554	)		196			(310	)		(60	)		(854	)		(255	)		(369	)

Total Funds from operations		3 005			2 585			2 007			3 139			2 862			5 590			5 026			10 172

Change in non-cash working capital		428			(1 037	)		1 033			1 231			(416	)		(609	)		(1 856	)		408

Cash flow provided by operating activities		3 433			1 548			3 040			4 370			2 446			4 981			3 170			10 580

Per common share

Net earnings (loss) – basic		1.74			0.93			(0.18	)		1.12			0.60			2.67			1.08			2.03

Net earnings (loss) – diluted		1.74			0.93			(0.18	)		1.11			0.59			2.66			1.07			2.02

Operating earnings – basic^(B)		0.80			0.77			0.36			0.96			0.73			1.56			1.33			2.65

Cash dividends – basic		0.42			0.42			0.36			0.36			0.36			0.84			0.72			1.44

Funds from operations – basic^(B)		1.92			1.64			1.26			1.94			1.75			3.55			3.07			6.27

Cash flow provided by operating activities – basic		2.19			0.98			1.90			2.70			1.50			3.16			1.94			6.54


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

Return on capital employed^(B)

– excluding major projects in progress (%)		10.6		8.3		8.2		10.4		9.5

– including major projects in progress (%)		10.4		8.2		8.0		9.7		8.3

(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.

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Total Production (mbbls/d)		692.2		657.2		740.8		651.7		547.6		674.8		559.7		628.6

Oil Sands operations

Upgraded product (sweet SCO, sour SCO and diesel)		295.5		341.2		273.4		330.1		237.9		318.2		258.6		280.3

Non-upgraded bitumen		118.7		55.4		159.3		146.0		121.0		87.2		123.2		138.0

Oil Sands operations production		414.2		396.6		432.7		476.1		358.9		405.4		381.8		418.3

Bitumen production (mbbls/d)

Mining		300.5		267.8		278.3		323.4		195.4		284.2		218.4		258.8

In Situ – Firebag		168.4		189.4		197.2		211.0		201.9		178.8		203.8		204.0

In Situ – MacKay River		36.3		35.2		37.0		37.1		34.4		35.8		34.7		36.0

Total bitumen production		505.2		492.4		512.5		571.5		431.7		498.8		456.9		498.8

Sales (mbbls/d)

Light sweet crude oil		118.3		113.7		110.2		129.5		59.6		116.0		71.9		96.1

Diesel		25.2		29.0		27.6		34.7		32.4		27.1		26.4		28.8

Light sour crude oil		165.0		182.4		150.7		162.8		159.0		173.7		168.5		162.6

Upgraded product (SCO and diesel)		308.5		325.1		288.5		327.0		251.0		316.8		266.8		287.5

Non-upgraded bitumen		115.1		53.2		172.0		131.4		113.7		84.3		115.9		134.0

Sales		423.6		378.3		460.5		458.4		364.7		401.1		382.7		421.5

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

Cash costs		26.80		27.15		22.80		21.05		27.45		27.15		26.20		23.85

Natural gas		1.00		2.80		1.70		0.95		1.20		1.70		1.50		1.40

		27.80		29.95		24.50		22.00		28.65		28.85		27.70		25.25

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

Cash costs		25.55		27.80		23.65		20.35		32.15		26.65		29.10		25.20

Natural gas		0.30		1.00		0.35		0.15		0.30		0.60		0.50		0.35

		25.85		28.80		24.00		20.50		32.45		27.25		29.60		25.55

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

Cash costs		7.15		6.10		5.75		6.20		6.10		6.60		6.35		6.15

Natural gas		1.60		3.80		2.55		1.85		1.80		2.75		2.40		2.30

		8.75		9.90		8.30		8.05		7.90		9.35		8.75		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										Six months ended					Twelve months ended
Oil Sands	Jun 30 2019		Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Jun 30 2019		Jun 30 2018			Dec 31 2018

Fort Hills

Bitumen production (mbbls/d)		89.3		78.4		98.5		69.4		70.9		83.9		50.5			67.4

Internally upgraded bitumen from froth (mbbls/d)		—		—		—		—		—		—		(2.6	)		(1.3	)

Total Fort Hills Bitumen Production		89.3		78.4		98.5		69.4		70.9		83.9		47.9			66.1

Bitumen sales (mbbls/d)		82.0		78.7		94.6		61.6		64.0		80.3		36.20			57.3

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

Cash costs		21.80		27.70		23.85		32.55		27.60		24.55		34.30			30.00

Natural gas		0.70		1.90		1.00		0.90		0.95		1.25		1.60			1.20

		22.50		29.60		24.85		33.45		28.55		25.80		35.90			31.20

Syncrude

Sweet SCO production (mbbls/d)		188.7		182.2		209.6		106.2		117.8		185.5		130.0			144.2

Bitumen production (mbbls/d)		228.5		210.6		240.7		130.9		142.7		219.6		157.9			172.0

Intermediate sour SCO (mbbls/d)⁽²⁾		191.4		186.0		206.3		107.2		119.9		188.7		129.0			143.0

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

Cash costs		34.40		35.55		30.85		62.80		53.80		34.95		52.00			46.15

Natural gas		0.50		1.50		0.90		1.05		2.45		1.00		1.25			1.10

		34.90		37.05		31.75		63.85		56.25		35.95		53.25			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															Six months ended						Twelve months ended
Oil Sands Operating Netbacks ^(B)(C)	Jun 30 2019			Mar 31 2019			Dec 31 2018			Sep 30 2018			Jun 30 2018			Jun 30 2019			Jun 30 2018			Dec 31 2018

Bitumen ($/bbl)

Average price realized		54.03			48.37			7.96			42.03			47.08			52.26			40.22			30.22

Royalties		(2.96	)		(1.37	)		(0.06	)		(3.20	)		(3.27	)		(2.46	)		(2.07	)		(1.70	)

Transportation costs		(5.77	)		(6.78	)		(5.53	)		(5.41	)		(4.24	)		(6.08	)		(5.12	)		(5.52	)

Net operating expenses		(8.86	)		(8.56	)		(7.61	)		(7.01	)		(7.37	)		(8.77	)		(8.07	)		(7.68	)

Operating netback^(B)		36.44			31.66			(5.24	)		26.41			32.20			34.95			24.96			15.32

SCO and diesel ($/bbl)

Average price realized		78.67			69.34			46.07			86.71			85.06			73.91			79.57			73.07

Royalties		(2.98	)		(1.38	)		(0.91	)		(2.70	)		(2.60	)		(2.16	)		(1.53	)		(1.63	)

Transportation costs		(3.70	)		(4.44	)		(3.63	)		(3.76	)		(5.06	)		(4.08	)		(4.58	)		(4.10	)

Net operating expenses – bitumen		(26.94	)		(23.87	)		(23.72	)		(20.49	)		(27.52	)		(25.38	)		(26.39	)		(24.04	)

Net operating expenses – upgrading		(6.39	)		(5.11	)		(6.49	)		(5.03	)		(8.13	)		(5.73	)		(7.01	)		(6.32	)

Operating netback^(B)		38.66			34.54			11.32			54.73			41.75			36.56			40.06			36.98

Average Oil Sands operations ($/bbl)

Average price realized		71.98			66.39			31.84			73.90			73.21			69.36			67.65			59.46

Royalties		(2.98	)		(1.38	)		(0.59	)		(2.84	)		(2.81	)		(2.23	)		(1.69	)		(1.70	)

Transportation costs		(4.26	)		(4.77	)		(4.34	)		(4.23	)		(4.80	)		(4.50	)		(4.74	)		(4.55	)

Net operating expenses – bitumen and upgrading		(26.68	)		(26.11	)		(21.78	)		(20.21	)		(26.83	)		(26.41	)		(25.73	)		(23.15	)

Operating netback^(B)		38.06			34.13			5.13			46.62			38.77			36.22			35.49			30.06

Fort Hills ($/bbl)

Average price realized		70.71			62.92			30.57			64.33			60.81			66.92			58.56			48.48

Royalties		(1.27	)		(1.43	)		(1.41	)		(3.07	)		(0.73	)		(1.35	)		(0.82	)		(1.67	)

Transportation costs		(13.61	)		(12.97	)		(10.31	)		(10.90	)		(8.95	)		(13.30	)		(8.86	)		(10.01	)

Net operating expenses – bitumen		(24.43	)		(25.17	)		(28.79	)		(30.69	)		(22.73	)		(24.79	)		(32.03	)		(30.32	)

Operating netback^(B)		31.40			23.35			(9.94	)		19.67			28.40			27.48			16.85			6.48

Syncrude ($/bbl)

Average price realized		79.74			68.36			48.07			89.50			86.73			74.18			81.61			70.68

Royalties		(12.59	)		(8.09	)		(1.53	)		(2.49	)		(2.41	)		(10.39	)		(1.95	)		(1.90	)

Transportation costs		(0.42	)		(0.46	)		(0.36	)		(0.70	)		(0.57	)		(0.44	)		(0.52	)		(0.49	)

Net operating expenses – bitumen and upgrading		(28.73	)		(31.53	)		(28.33	)		(62.61	)		(52.27	)		(30.10	)		(48.45	)		(43.81	)

Operating netback^(B)		38.00			28.28			17.85			23.70			31.48			33.25			30.69			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.

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Total Sales Volumes (mboe/d)		106.1			111.8			83.1			96.5			110.2			108.9			116.0			102.8

Total Production (mboe/d)		111.7			107.1			90.2			92.1			114.1			109.3			115.9			103.4

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)		11.3			13.2			9.5			8.6			13.6			12.2			14.5			11.7

Hibernia (mbbls/d)		23.8			25.7			19.0			17.9			25.5			24.7			25.8			22.1

White Rose (mbbls/d)		3.2			1.1			3.7			8.0			6.0			2.1			7.4			6.6

Hebron (mbbls/d)		23.6			18.3			15.7			14.4			13.5			21.0			10.9			13.0

North America Onshore (mboe/d)		—			—			—			—			—			—			1.0			0.5

		61.9			58.3			47.9			48.9			58.6			60.0			59.6			53.9

Exploration and Production International

Buzzard (mboe/d)		35.0			36.7			27.7			29.6			39.4			35.8			39.9			34.2

Golden Eagle (mboe/d)		8.2			10.2			10.7			12.0			12.6			9.2			13.4			12.4

United Kingdom (mboe/d)		43.2			46.9			38.4			41.6			52.0			45.0			53.3			46.6

Norway – Oda (mboe/d)		4.0			0.2			—			—			—			2.1			—			—

Libya (mbbls/d)⁽³⁾		2.6			1.7			3.9			1.6			3.5			2.2			3.0			2.9

		49.8			48.8			42.3			43.2			55.5			49.3			56.3			49.5

Netbacks^(B)(C)

East Coast Canada ($/bbl)

Average price realized		92.42			86.16			76.19			99.50			97.30			89.23			90.56			90.04

Royalties		(13.65	)		(19.75	)		(5.04	)		(18.75	)		(13.02	)		(16.76	)		(13.72	)		(13.31	)

Transportation costs		(1.94	)		(1.56	)		(2.71	)		(2.28	)		(2.24	)		(1.75	)		(2.03	)		(2.22	)

Operating costs		(10.96	)		(15.63	)		(23.71	)		(16.06	)		(11.21	)		(13.34	)		(10.40	)		(14.43	)

Operating netback^(B)		65.87			49.22			44.73			62.41			70.83			57.38			64.41			60.08

United Kingdom ($/boe)

Average price realized		90.13			85.40			85.31			94.28			93.88			87.68			88.44			89.10

Transportation costs		(2.24	)		(2.22	)		(2.14	)		(2.22	)		(2.20	)		(2.23	)		(2.17	)		(2.18	)

Operating costs		(7.08	)		(5.09	)		(8.94	)		(6.04	)		(5.39	)		(6.05	)		(5.38	)		(6.27	)

Operating netback^(B)		80.81			78.09			74.23			86.02			86.29			79.40			80.89			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										Six months ended				Twelve months ended
Refining and Marketing	Jun 30 2019		Mar 31 2019		Dec 31 2018		Sep 30 2018		Jun 30 2018		Jun 30 2019		Jun 30 2018		Dec 31 2018

Refined product sales (mbbls/d)		508.1		542.8		530.6		565.5		500.0		525.4		506.5		527.4

Crude oil processed (mbbls/d)		399.1		444.9		467.9		457.2		344.1		421.9		398.5		430.8

Utilization of refining capacity (%)		86		96		101		99		74		91		86		93

Refining margin ($/bbl)^(B)		33.45		36.35		41.50		34.45		30.25		34.95		30.40		34.50

Refining operating expense ($/bbl)^(B)		5.90		5.60		5.45		5.00		6.25		5.75		5.45		5.35

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		114.1		120.6		117.8		122		117.8		117.4		115.7		117.8

Distillate		98.2		103.1		100.2		96.7		93.4		100.6		93.1		95.8

Total transportation fuel sales		212.3		223.7		218.0		218.7		211.2		218.0		208.8		213.6

Petrochemicals		12.5		12.8		10.3		9.0		11.8		12.7		12.9		11.3

Asphalt		12.7		12.6		15.2		20.5		13.3		12.6		13.3		15.5

Other		14.6		27.5		25.7		26.5		25.9		21.0		25.8		26.0

Total refined product sales		252.1		276.6		269.2		274.7		262.2		264.3		260.8		266.4

Crude oil supply and refining

Processed at refineries (mbbls/d)		170.0		216.2		221.0		211.6		182.0		193.0		199.8		208.1

Utilization of refining capacity (%)		77		97		100		95		82		87		90		94

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline		121.2		126.1		127.8		139.0		124.2		123.6		122.2		127.8

Distillate		107.9		118.7		109.5		121.0		88.3		113.3		99.8		107.6

Total transportation fuel sales		229.1		244.8		237.3		260.0		212.5		236.9		222.0		235.4

Asphalt		11.4		7.5		11.3		16.1		14.3		9.5		12.8		13.3

Other		15.5		13.9		12.8		14.7		11.0		14.7		10.9		12.3

Total refined product sales		256.0		266.2		261.4		290.8		237.8		261.1		245.7		261.0

Crude oil supply and refining

Processed at refineries (mbbls/d)		229.1		228.7		246.9		245.6		162.1		228.9		198.7		222.7

Utilization of refining capacity (%)		95		95		103		102		68		95		83		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.

See accompanying footnotes and definitions to the quarterly operating summaries.


For the quarter ended June 30, 2019	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	720		2 301		3 021		760		1 380		(21	)	5 140

Other income (loss)	—		—		—		(4	)	18		(13	)	1

Purchases of crude oil and products	(144	)	(41	)	(185	)	(208	)	(11	)	—		(404	)

Gross realization adjustment⁽⁵⁾	(10	)	(52	)	(62	)	(21	)	(18	)

Gross realizations	566		2 208		2 774		527		1 369

Royalties	(31	)	(84	)	(115	)	(10	)	(216	)	—		(341	)

Transportation	(60	)	(143	)	(203	)	(105	)	(18	)	—		(326	)

Transportation adjustment⁽⁶⁾	—		38		38		4		11

Net transportation expenses	(60	)	(105	)	(165	)	(101	)	(7	)

Operating, selling and general (OS&G)	(122	)	(1 118	)	(1 240	)	(216	)	(625	)	21		(2 060	)

OS&G adjustment⁽⁷⁾	29		182		211		34		132

Net operating expenses	(93	)	(936	)	(1 029	)	(182	)	(493	)

Gross profit	382		1 083		1 465		234		653

Sales volumes (mbbls)	10 474		28 078		38 552		7 458		17 169

Operating netback per barrel	36.44		38.66		38.06		31.40		38.00


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		(117	)	(105	)	15		10

Gross realizations	231		2 029		2 260		446		1 121

Royalties	(7	)	(40	)	(47	)	(10	)	(133	)	(8	)	(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)	(58	)	(1 083	)	(1 141	)	(233	)	(619	)	20		(1 973	)

OS&G adjustment⁽⁷⁾	17		236		253		55		103

Net operating expenses	(41	)	(847	)	(888	)	(178	)	(516	)

Gross profit	151		1 012		1 163		166		463

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

(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 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


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

(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 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


For the six months ended June 30, 2019	Bitumen		SCO and Diesel		Oil Sands Operations		Fort Hills		Syncrude		Other(4)		Oil Sands Segment

Operating revenues	997		4 459		5 456		1 387		2 523		(45	)	9 321

Other income (loss)	—		24		24		(45	)	8		24		11

Purchases of crude oil and products	(202	)	(77	)	(279	)	(363	)	(33	)	(2	)	(677	)

Gross realization adjustment⁽⁵⁾	2		(169	)	(167	)	(6	)	(8	)

Gross realizations	797		4 237		5 034		973		2 490

Royalties	(38	)	(124	)	(162	)	(20	)	(349	)	(8	)	(539	)

Transportation	(92	)	(299	)	(391	)	(207	)	(26	)	—		(624	)

Transportation adjustment⁽⁶⁾	—		64		64		14		10

Net transportation expenses	(92	)	(235	)	(327	)	(193	)	(16	)

OS&G	(180	)	(2 201	)	(2 381	)	(449	)	(1 244	)	41		(4 033	)

OS&G adjustment⁽⁷⁾	46		418		464		89		235

Net operating expenses	(134	)	(1 783	)	(1 917	)	(360	)	(1 009	)

Gross profit	533		2 095		2 628		400		1 116

Sales volumes (mbbls)	15 258		57 338		72 596		14 538		33 549

Operating netback per barrel	34.94		36.56		36.22		27.48		33.25

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

Operating revenues	1 275		3 980		5 255		635		1 941		(52	)	7 779

Other (loss) income	(2	)	(11	)	(13	)	(12	)	39		54		68

Purchases of crude oil and products	(415	)	(48	)	(463	)	(194	)	(24	)	11		(670	)

Gross realization adjustment⁽⁵⁾	(14	)	(79	)	(93	)	(44	)	(36	)

Gross realizations	844		3 842		4 686		385		1 920

Royalties	(44	)	(74	)	(118	)	(6	)	(46	)	—		(170	)

Transportation	(108	)	(274	)	(382	)	(113	)	(22	)	—		(517	)

Transportation adjustment⁽⁶⁾	—		54		54		54		10

Net transportation expenses	(108	)	(220	)	(328	)	(59	)	(12	)

OS&G	(240	)	(1 926	)	(2 166	)	(327	)	(1 269	)	38		(3 724	)

OS&G adjustment⁽⁷⁾	71		312		383		117		129

Net operating expenses	(169	)	(1 614	)	(1 783	)	(210	)	(1 140	)

Gross profit	523		1 934		2 457		110		722

Sales volumes (mbbls)	20 986		48 291		69 277		6 557		23 528

Operating netback per barrel	24.96		40.06		35.49		16.85		30.69


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 June 30, 2019	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	354		507		133		994

Royalties	—		(75	)	(90	)	(165	)

Transportation	(9	)	(11	)	(1	)	(21	)

OS&G	(32	)	(69	)	(13	)	(114	)

Non-production costs⁽¹⁰⁾	5		9

Gross realizations	318		361

Sales volumes (mboe)	3 923		5 489

Operating netback per barrel	80.81		65.87


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

(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 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


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 six months ended June 30, 2019	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	714		998		219		1 931

Royalties	—		(187	)	(151	)	(338	)

Transportation	(18	)	(20	)	(2	)	(40	)

OS&G	(58	)	(175	)	(29	)	(262	)

Non-production costs⁽¹⁰⁾	9		25

Gross realizations	647		641

Sales volumes (mboe)	8 140		11 182

Operating netback per barrel	79.40		57.38

(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 six months ended June 30, 2018	United Kingdom		East Coast Canada		Other(9)		E&P Segment

Operating revenues	853		962		334		2 149

Royalties	—		(147	)	(201	)	(348	)

Transportation	(21	)	(21	)	(4	)	(46	)

OS&G	(62	)	(137	)	(24	)	(223	)

Non-production costs⁽¹⁰⁾	11		27		—

Gross realizations	781		684

Sales volumes (mboe)	9 648		10 620

Operating netback per barrel	80.89		64.41


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

Gross margin⁽¹¹⁾		1 647			2 140			1 711			1 987			1 639			3 787			3 401		7 122

Other income (loss)		14			15			90			10			(15	)		29			(21	)	68

Non-refining margin⁽¹²⁾		(326	)		(587	)		115			(431	)		(620	)		(913	)		(1 023	)	(1 351	)

Refining margin^(B)		1 335			1 568			1 916			1 566			1 004			2 903			2 357		5 839

Refinery production (mbbls)⁽¹³⁾		39 901			43 143			46 145			45 465			33 165			83 044			77 528		169 138

Refining margin ($/bbl)^(B)		33.45			36.35			41.50			34.45			30.25			34.95			30.40		34.50

Last-in, first out (LIFO) adjustment		7			(333	)		444			—			(96	)		(326	)		(107	)	337

Adjusted LIFO Refining Margin^(B)		1 342			1 235			2 360			1 566			908			2 577			2 250		6 176

Adjusted LIFO refining margin ($/bbl)^(B)		33.65			28.65			51.15			34.45			27.40			31.05			29.05		36.50

OS&G		530			536			538			519			494			1 066			958		2 043

Non-refining costs⁽¹⁴⁾		(295	)		(294	)		(288	)		(292	)		(288	)		(589	)		(534	)	(1 142	)

Refining operating expense		235			242			250			227			206			477			424		901

Refinery production (mbbls)⁽¹³⁾		39 901			43 143			46 145			45 465			33 165			83 044			77 528		169 138

Refining operating expense ($/bbl)^(B)		5.90			5.60			5.45			5.00			6.25			5.75			5.45		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.


(thousands)		June 30, 2019

Common shares		1 560 729

Common share options – exercisable		21 236

Common share options – non-exercisable		14 156


($ 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 June 30		Six months ended June 30
($ millions, except as noted)	2019	2018	2019	2018

Share repurchase activities (thousands of common shares)

Shares repurchased	13 001	11 860	24 952	20 859

Amounts charged to

Share capital	213	192	406	337

Retained earnings	339	417	660	661

Share repurchase cost	552	609	1 066	998


1.	Advisories	6
2.	Second Quarter Highlights	8
3.	Consolidated Financial Information	9
4.	Segment Results and Analysis	14
5.	Capital Investment Update	30
6.	Financial Condition and Liquidity	32
7.	Quarterly Financial Data	36
8.	Other Items	38
9.	Non-GAAP Financial Measures Advisory	39
10.	Common Abbreviations	44
11.	Forward-Looking Information	45


($ millions)	Energy Trading		Risk Management		Total

Fair value outstanding at December 31, 2018	1		59		60

Cash Settlements – received during the year	(153	)	(23	)	(176	)

Unrealized gains (losses) recognized in earnings during the year (note 5)	110		(46	)	64

Fair value outstanding at June 30, 2019	(42	)	(10	)	(52	)


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

Accounts receivable	9		118		—	127

Accounts payable	(97	)	(82	)	—	(179	)

	(88	)	36		—	(52	)


($ millions)		June 30 2019

Property, plant and equipment, net – excluding ROU assets		73 420

ROU assets		2 978

		76 398


	Three months ended															Six months ended						Twelve months ended
	June 30 2019			Mar 31 2019			Dec 31 2018			Sept 30 2018			June 30 2018			June 30 2019			June 30 2018			Dec 31 2018

Syncrude OS&G		625			619			619			635			608			1 244			1 269			2 523

Non-production costs⁽⁸⁾		(26	)		(12	)		(7	)		(11	)		(5	)		(38	)		(15	)		(33	)

Syncrude cash operating costs		599			607			612			624			603			1 206			1 254			2 490

Syncrude sales volumes (mbbls)		17 169			16 380			19 286			9 769			10 718			33 549			23 528			52 583

Syncrude cash operating costs ($/bbl)		34.90			37.05			31.75			63.85			56.25			35.95			53.25			47.25


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 meters per day
SCO		– synthetic crude oil