Management's Discussion and Analysis for the first quarter ended March 31, 2018

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, 2017, dated March 1, 2018 (the 2017 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three months ended March 31, 2018, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2017 and the 2017 annual MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and Suncor's Annual Information Form dated March 1, 2018 (the 2017 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 MD&A by reference.

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

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

Effective January 1, 2018, the company adopted IFRS 15 Revenue from Contracts with Customers (IFRS 15), which sets out new guidelines for the recognition of revenue. As a result, certain comparative figures presented in this MD&A pertaining to Suncor's 2017 results have been restated in accordance with the new standard with no impact to overall net earnings or operating earnings.

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

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

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

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

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

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


	Three months ended March 31
($ millions)	2018		2017

Net earnings (loss)

Oil Sands	82		302

Exploration and Production	395		172

Refining and Marketing	806		829

Corporate, Energy Trading and Eliminations	(494	)	49

Total	789		1 352

Operating earnings (loss)⁽¹⁾

Oil Sands	82		302

Exploration and Production	262		172

Refining and Marketing	806		475

Corporate, Energy Trading and Eliminations	(165	)	(137	)

Total	985		812

Funds from (used in) operations⁽¹⁾

Oil Sands	979		1 109

Exploration and Production	502		481

Refining and Marketing	965		575

Corporate, Energy Trading and Eliminations	(282	)	(141	)

Total	2 164		2 024

Capital and Exploration Expenditures⁽²⁾

Sustaining	807		399

Growth	407		807

Total	1 214		1 206


	Three months ended March 31
	2018	2017

Production volumes by segment

Oil Sands (mbbls/d)	571.7	590.6

Exploration and Production (mboe/d)	117.7	134.5

Total (mboe/d)	689.4	725.1

Production mix

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

Refinery utilization (%)	98	93

Refinery crude oil processed (mbbls/d)	453.5	429.9

Suncor's consolidated net earnings for the first quarter of 2018 were $789 million, compared to net earnings of $1.352 billion for the prior year quarter. Net earnings were primarily affected by the same factors that influenced operating earnings described subsequently in this section of this MD&A.


	Three months ended March 31
($ millions)	2018		2017

Net earnings	789		1 352

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	329		(103	)

Gain on significant disposals⁽²⁾	(133	)	(437	)

Operating earnings⁽¹⁾	985		812

(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): Non-cash after-tax gain of $133 million in the Exploration and Production (E&P) segment related to the asset exchange with Canbriam for the company's mineral landholdings in northeast British Columbia in the first quarter of 2018. The first quarter of 2017 included a $354 million after-tax gain in the R&M segment related to the sale of the company's lubricants business, combined with an after-tax gain of $83 million in the Corporate segment related to the sale of the company's interest in the Cedar Point wind facility.

Suncor's consolidated operating earnings for the first quarter of 2018 were $985 million, compared to $812 million in the prior year quarter. The increase is attributable to improved crude oil pricing and increased refining margins, refinery utilization of 98% and strong In Situ production, partially offset by increased operating costs, which were primarily due to higher maintenance expenses and the addition of full operating costs at Fort Hills while production ramps up. Oil Sands results in the current period were impacted by a weather-related outage at Oil Sands Base, as well as constrained capacity on a bitumen feed line at Syncrude, which resulted in lower overall Oil Sands production.

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


	Average for the three months ended March 31
		2018	2017

WTI crude oil at Cushing	US$/bbl	62.90	51.85

Dated Brent crude	US$/bbl	66.80	53.75

Dated Brent/Maya crude oil FOB price differential	US$/bbl	7.70	9.05

MSW at Edmonton	Cdn$/bbl	72.45	64.25

WCS at Hardisty	US$/bbl	38.60	37.30

Light/heavy differential for WTI at Cushing less WCS at Hardisty	US$/bbl	24.30	14.55

Condensate at Edmonton	US$/bbl	63.15	52.20

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.05	2.70

Alberta Power Pool Price	Cdn$/MWh	34.95	22.40

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	15.50	12.55

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	12.85	11.15

Portland 3-2-1 crack⁽¹⁾	US$/bbl	20.35	18.45

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	15.55	14.00

Exchange rate	US$/Cdn$	0.79	0.76

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

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

Suncor's sweet SCO price realizations are influenced primarily by the price of WTI at Cushing and by the supply and demand for sweet SCO from Western Canada. Price realizations in the first quarter of 2018 for sweet SCO were favourably impacted by a higher WTI price of US$62.90/bbl, compared to US$51.85/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 increased to $72.45/bbl, compared to $64.25/bbl in the prior year quarter, and prices for WCS at Hardisty increased to US$38.60/bbl in the first quarter of 2018, from US$37.30/bbl in the prior year quarter, which was less than the increase in WTI as a result of the impact of widening heavy crude differentials due to takeaway constraints at Hardisty.

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

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude increased to US$66.80/bbl in the first quarter of 2018, compared to US$53.75/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $2.05/mcf in the first quarter of 2018, from $2.70/mcf in the prior year quarter.

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

reflects a declining price environment for crude oil and finished products, whereas FIFO gains reflect an increasing price environment for crude oil and finished products. Specific refining margins are further impacted by actual crude purchase costs, refinery configuration, production mix and realized prices for refined products sales in markets unique to each refinery.

Excess electricity produced in Suncor's Oil Sands operations is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the Oil Sands operations cash operating cost per barrel metric. The Alberta power pool price increased to an average of $34.95/MWh in the first quarter of 2018, compared to $22.40/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In comparison to the prior year quarter, the Canadian dollar strengthened in relation to the U.S. dollar during the first quarter of 2018, as the average exchange rate increased to US$0.79 per one Canadian dollar from US$0.76 per one Canadian dollar in the prior year quarter. This rate increase had a negative impact on price realizations for the company during the first quarter of 2018 when compared to the prior year quarter.

Suncor also has assets and liabilities, including approximately 75% of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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.


	Three months ended March 31
($ millions)	2018		2017

Gross revenues⁽¹⁾	3 599		3 323

Less: Royalties	(46	)	(61	)

Operating revenues, net of royalties	3 553		3 262

Net earnings	82		302

Operating earnings⁽²⁾	82		302

Funds from operations⁽²⁾	979		1 109

(1): The first quarter of 2017 has been restated in accordance with the new IFRS 15 revenue requirements, with no impact to net earnings or operating earnings. For further information on the restatements associated with IFRS 15, refer to note 3 in Suncor's Consolidated Financial Statements for the three-month period ended March 31, 2018.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

The Oil Sands segment had operating earnings of $82 million in the first quarter of 2018, compared to $302 million in the prior year quarter. The decrease was due to increased maintenance costs at Syncrude and Oil Sands operations and the addition of full operating costs at Fort Hills during its first quarter of operations while production ramps up, and lower overall production than the prior year period, partially offset by higher crude price realizations, lower royalties, and additional production from the increased working interest in Syncrude acquired partway through the quarter.


	Three months ended March 31
(mbbls/d)	2018		2017

Upgraded product (SCO and diesel)	287.6		339.3

Internally consumed diesel⁽²⁾	(8.2	)	(6.5	)

Total Oil Sands operations upgraded product	279.4		332.8

In Situ non-upgraded bitumen	125.4		115.7

Total Oil Sands operations production	404.8		448.5

Fort Hills bitumen	29.8		—

Internally upgraded bitumen from froth	(5.2	)	—

Total Fort Hills bitumen production	24.6		—

Syncrude (sweet SCO and diesel)	144.6		143.9

Internally consumed diesel⁽²⁾	(2.3	)	(1.8	)

Total Syncrude production	142.3		142.1

Total Oil Sands production	571.7		590.6

(1): Bitumen production from Oil Sands Base operations is upgraded, while bitumen production from In Situ operations is either upgraded or sold directly to customers, including Suncor's own refineries, 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 utilizes internally produced diesel from Oil Sands Base within its mining operations. Of the 8,200 bbls/d of internally consumed diesel at Oil Sands operations, 6,500 bbls/d was consumed at Oil Sands Base and 1,700 bbls/d was consumed at Fort Hills. All upgrader utilization rates presented exclude internally produced and consumed diesel.

Oil Sands operations production was 404,800 bbls/d in the first quarter of 2018, compared to 448,500 bbls/d in the prior year quarter, with the decrease due to a weather-related outage at Oil Sands Base plant, partially offset by continued strong In Situ production. As a result of the outage, upgrader utilization in the first quarter of 2018 was 80%, compared to 95% in the prior year quarter. Production rates at Oil Sands Base plant returned to normal by the end of February after the weather-related issue was resolved.

Following the successful commissioning of the secondary extraction assets on January 27, 2018, the Fort Hills project produced an average of 29,800 bbls/d of bitumen, including 5,200 bbls/d of bitumen froth which was further processed by Oil Sands operations into SCO.


	Three months ended March 31
(mbbls/d)	2018	2017

Oil Sands operations sales volumes

Sweet SCO	84.2	124.9

Diesel	20.4	30.3

Sour SCO	178.2	176.4

Upgraded product	282.8	331.6

In Situ non-upgraded bitumen	118.2	104.9

Oil Sands operations	401.0	436.5

Fort Hills bitumen	8.1	—

Syncrude	142.3	142.1

Total	551.4	578.6

Sales volumes for Oil Sands operations decreased to 401,000 bbls/d in the first quarter of 2018, from 436,500 bbls/d in the prior year quarter, consistent with the decrease in production.

The commissioning of the secondary extraction assets at Fort Hills in the first quarter of 2018 resulted in bitumen sales of 8,100 bbls/d and a build of bitumen inventory as initial production continues to make its way to market.

Suncor's share of Syncrude production and sales was 142,300 bbls/d in the first quarter of 2018, comparable to 142,100 bbls/d in the prior year quarter, reflecting unplanned incidents in both periods. In the first quarter of 2018, the additional working interest acquired partway through the quarter was offset by the impact of the bitumen feed line constraint.


	Three months ended March 31
	2018	2017

Oil Sands Base

Bitumen production (mbbls/d)	241.6	311.1

Bitumen ore mined (thousands of tonnes per day)	362.6	469.1

Bitumen ore grade quality (bbls/tonne)	0.67	0.66

In Situ

Bitumen production – Firebag (mbbls/d)	205.8	202.8

Steam-to-oil ratio – Firebag	2.7	2.7

Bitumen production – MacKay River (mbbls/d)	35.1	35.6

Steam-to-oil ratio – MacKay River	3.0	3.0

Total In Situ bitumen production (mbbls/d)	240.9	238.4

Total Oil Sands operations bitumen production (mbbls/d)	482.5	549.5

Fort Hills

Bitumen production (mbbls/d)	29.8	—

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

Bitumen ore grade quality (bbls/tonne)	0.60	—

Syncrude

Bitumen production (mbbls/d)	173.3	170.0

Bitumen ore mined (thousands of tonnes per day)	278.2	277.7

Bitumen ore grade quality (bbls/tonne)	0.62	0.61

Total Oil Sands bitumen production	685.6	719.5

Bitumen production at Oil Sands operations in the first quarter of 2018 decreased to 482,500 bbls/d, compared to 549,500 bbls/d in the prior year quarter. The decrease in production was primarily due to the weather-related outage at Oil Sands Base early in the first quarter, partially offset by increased In Situ production, with Firebag and MacKay River benefiting from reliable operations in the period.

Bitumen production at Fort Hills began in the period following the successful start of operations.

Bitumen production at Syncrude in the first quarter of 2018 was comparable to the prior year quarter due to the previously mentioned unplanned incidents impacting each quarter, with the impact of the first quarter of 2018 incident being offset by the increased 5% ownership interest.


Net of transportation costs, but before royalties	Three months ended March 31
($/bbl)	2018		2017

Oil Sands operations

SCO and diesel	70.51		62.31

Bitumen	27.57		27.32

Crude sales basket (all products)	57.86		53.90

Crude sales basket, relative to WTI	(21.76	)	(14.32	)

Fort Hills – bitumen	32.48		—

Syncrude – sweet SCO	76.85		65.99

Syncrude, relative to WTI	(2.77	)	(2.23	)

(1): Price realizations for the first quarter of 2017 have been restated in accordance with the new IFRS 15 revenue requirements, with no impact to net earnings or operating earnings, as well as the removal of the impact of risk management activities. For further information on the restatements associated with IFRS 15, refer to note 3 in Suncor's Consolidated Financial Statements for the three-month period ended March 31, 2018.

Average price realizations at Oil Sands operations increased to $57.86/bbl in the first quarter of 2018 from $53.90/bbl in the prior year quarter, due to higher WTI benchmark prices, partially offset by an unfavourable sales mix, wider heavy crude and SCO differentials, resulting from transportation constraints at Edmonton/Hardisty, as well as the impact of a stronger Canadian dollar.

Average price realizations for Fort Hills bitumen were $32.48 in the first quarter of 2018, and were higher than In Situ bitumen realizations primarily due to an increased proportion of shipments to the U.S. Gulf Coast combined with the improved quality differential associated with paraffinic bitumen at Fort Hills, partially offset by higher per barrel transportation costs associated with higher shipments to the U.S. Gulf Coast.

Average price realizations at Syncrude increased to $76.85/bbl in the first quarter of 2018 from $65.99/bbl in the prior year quarter due to the increase in the WTI benchmark price, partially offset by wider SCO differentials and the impact of a stronger Canadian dollar.

Royalties for the Oil Sands segment were lower in the first quarter of 2018 compared to the prior year quarter, primarily due to lower production in the current period.

Oil Sands operating and transportation expenses for the first quarter of 2018 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 non-production costs.

At Fort Hills, operating and transportation costs, including project start-up costs, commenced following the start of operations in the first quarter of 2018.

At Oil Sands operations, operating costs increased as a result of higher planned maintenance costs incurred in preparation for the Upgrader 1 turnaround, which began in the second quarter of 2018, and an increase in unplanned maintenance expenses associated with the weather-related outage, partially offset by lower natural gas prices.

At Syncrude, operating costs were higher than the prior year quarter due to increased unplanned maintenance expenses related to the bitumen feed line constraint, an increase in planned maintenance expenses related to the advancement of the upgrader turnaround and preventive maintenance to improve long-term reliability, as well as an increased share of Syncrude operating costs associated with the acquisition of an additional 5% working interest partway through the quarter, partially offset by lower natural gas prices.

DD&A and exploration expenses for the first quarter of 2018 were higher than the prior year period, due to initial DD&A from Fort Hills and an increased share of Syncrude DD&A with the acquisition of an additional 5% working interest partway through the quarter, offset by lower DD&A at Oil Sands operations.


	Three months ended March 31
($ millions)	2018		2017

Oil Sands Operating, selling and general expense (OS&G)	1 872		1 553

Oil Sands operations cash operating costs⁽¹⁾ reconciliation

Oil Sands operations OS&G	1 067		970

Non-production costs⁽²⁾	(31	)	(21	)

Excess power capacity and other⁽³⁾	(66	)	(49	)

Inventory changes	12		11

Oil Sands operations cash operating costs⁽¹⁾	982		911

Oil Sands operations cash operating costs ($/bbl)⁽¹⁾	26.85		22.55

Fort Hills cash operating costs⁽¹⁾ reconciliation

Fort Hills OS&G	144		—

Non-production costs⁽²⁾	(16	)	—

Inventory changes	16		—

Fort Hills cash operating costs⁽¹⁾	144

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

Syncrude cash operating costs⁽¹⁾ reconciliation

Syncrude OS&G	661		583

Non-production costs⁽²⁾	(10	)	(6	)

Syncrude cash operating costs⁽¹⁾	651		577

Syncrude cash operating costs ($/bbl)⁽¹⁾	50.75		45.15

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

In the first quarter of 2018, Oil Sands operations cash operating costs per barrel were $26.85, compared to $22.55 in the prior year quarter, primarily due to lower production combined with increased operating costs. Total Oil Sands operations cash operating costs increased to $982 million, from $911 million in the prior year quarter, with increased maintenance costs being partially offset by a decrease in natural gas pricing.

In the first quarter of 2018, non-production costs, which are excluded from Oil Sands operations cash operating costs, were higher than the prior year quarter, primarily due to an increase in share-based compensation expense.

Excess power capacity and other at Oil Sands operations for the first quarter of 2018 represents an increase over the prior year quarter due to an increase in power pricing.

Inventory changes at Oil Sands operations in both the first quarter of 2018 and 2017 represent a comparable build of inventory.

In the first quarter of 2018, Fort Hills cash operating costs were $53.65/bbl and were significantly influenced by the addition of full operating costs while production ramps up. Fort Hills cash operating costs per barrel are expected to steadily decline through the production ramp up period in 2018.

In the first quarter of 2018, Syncrude cash operating costs per barrel were $50.75, compared to $45.15 in the prior year period, with the increase due to lower production combined with higher operating expenses. Suncor's share of Syncrude cash operating costs increased to $651 million, from $577 million in the first quarter of 2017, due to an increase in unplanned maintenance costs as well as a higher share of costs of approximately $24 million associated with the increased ownership.

On March 15, Syncrude began an eight-week turnaround, which was originally scheduled to begin in April 2018. Advancing the turnaround will allow Syncrude to address the unrelated bitumen feed line constraint, which occurred early in the first quarter of 2018, and is expected to make more efficient use of resources and minimize the impact to annual production. In April, the company began a six-week turnaround at Upgrader 1. The impact of this maintenance has been reflected in the company's 2018 guidance.


	Three months ended March 31
($ millions)	2018		2017

Gross revenues⁽¹⁾	938		884

Less: Royalties⁽¹⁾	(82	)	(87	)

Operating revenues, net of royalties	856		797

Net earnings	395		172

Adjusted for:

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

Operating earnings⁽³⁾	262		172

Funds from operations⁽³⁾	502		481

(1): Production, revenues and royalties from the company's Libya operations have been presented in the E&P section of this MD&A on an entitlement basis and exclude an equal and offsetting gross up of revenues and royalties, which is required for presentation purposes in the company's financial statements under the working-interest basis.
(2): After-tax gain of $133 million related to the asset exchange with Canbriam for the company's mineral landholdings in northeast British Columbia in the first quarter of 2018.
(3): Non-GAAP financial measures. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings for the E&P segment in the first quarter of 2018 increased to $262 million, from $172 million in the prior year quarter, as a result of higher crude price realizations and the addition of production from the Hebron project, partially offset by lower overall production volumes.


	Three months ended March 31
	2018	2017

E&P Canada

Terra Nova (mbbls/d)	15.4	14.7

Hibernia (mbbls/d)	26.1	30.3

White Rose (mbbls/d)	8.8	13.1

Hebron (mbbls/d)	8.2	—

North America Onshore (mboe/d)	2.0	2.8

	60.5	60.9

E&P International

Buzzard (mboe/d)	40.4	49.0

Golden Eagle (mboe/d)	14.3	20.2

United Kingdom (mboe/d)	54.7	69.2

Libya (mbbls/d)	2.5	4.4

	57.2	73.6

Total Production (mboe/d)	117.7	134.5

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

Total Sales Volumes (mboe/d)	121.9	136.8

E&P Canada production averaged 60,500 boe/d in the first quarter of 2018, comparable to 60,900 boe/d in the prior year period. The additional production from the ramp up of the Hebron growth project, with the second production well coming online in the first quarter, was offset by natural declines at Hibernia and White Rose.

E&P International production decreased to 57,200 boe/d in the first quarter of 2018, compared to 73,600 boe/d in the prior year quarter, reflecting natural declines in the U.K. and lower production from Libya.

E&P sales volumes decreased to 121,900 boe/d in the first quarter of 2018, compared to 136,800 boe/d in the prior year quarter, due to the decrease in production.

Price realizations for E&P Canada and E&P International were higher in the first quarter of 2018, compared to the prior year quarter, primarily due to an increase in benchmark Brent crude pricing, partially offset by the impact of a stronger Canadian dollar.

E&P royalties in the first quarter of 2018 were comparable to the prior year quarter.

Operating and transportation expenses for the first quarter of 2018 increased compared to the prior year quarter, primarily due to additional operating costs at Hebron, which began producing in the fourth quarter of 2017.

DD&A expense in the first quarter of 2018 was comparable to the first quarter of 2017.

Exploration expense decreased when compared to the first quarter of 2017 due to the prior year period including exploration charges for drilling at the Shelburne Basin off the east coast of Canada.


	Three months ended March 31
($ millions)	2018	2017

Operating revenues⁽¹⁾	5 426	4 580

Net earnings	806	829

Adjusted for:

Gain on significant disposal⁽²⁾	—	(354	)

Operating earnings⁽³⁾	806	475

Funds from operations⁽³⁾	965	575

(1): The first quarter of 2017 has been restated in accordance with the new IFRS 15 revenue requirements, with no impact to net earnings or operating earnings. For further information on the restatements associated with IFRS 15, refer to note 3 in Suncor's Consolidated Financial Statements for the three-month period ended March 31, 2018.
(2): After-tax gain related to the sale of the company's lubricants business.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

R&M operating earnings were $806 million in the first quarter of 2018, compared to $475 million in the prior year quarter, with the increase due to higher refining margins, higher sales volumes, including record wholesale volumes in Canada, partially offset by the impact of a stronger Canadian dollar. The improved refining margins were primarily due to improved benchmark crack spreads, product location differentials and light/heavy crude differentials, combined with a higher value product mix.

The company sold its Petro-Canada lubricants business in the first quarter of 2017, which contributed $8 million in net earnings and $11 million in funds from operations during that period. The impact of the lubricants business sale has been reflected in Financing Expense and Other Income in the bridge analysis above.


	Three months ended March 31
	2018	2017

Crude oil processed (mbbls/d)

Eastern North America	217.8	214.6

Western North America	235.7	215.3

Total	453.5	429.9

Refinery utilization⁽¹⁾ (%)

Eastern North America	98	97

Western North America	98	90

Total	98	93

Refined product sales (mbbls/d)

Gasoline	233.7	229.9

Distillate	191.7	192.3

Other	87.5	85.8

Total	512.9	508.0

Refining margin⁽²⁾ ($/bbl)	30.25	21.90

Refining operating expense⁽²⁾ ($/bbl)	4.90	5.50

(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 have been presented on a LIFO basis and exclude the impact of risk management activities as management uses this basis to assess performance, with the prior period restated to reflect this change.

Refinery crude throughput in the first quarter of 2018 increased to 453,500 bbls/d, compared to 429,900 bbls/d in the prior year quarter, reflecting strong reliability at all refineries during the quarter and a planned buildup of inventory in advance of major maintenance events in the second quarter of 2018 that will support sales during the planned turnaround. Throughput in the prior year quarter was lower as a result of a third-party power outage at the company's Commerce City refinery.

Total refined product sales increased to 512,900 bbls/d in the first quarter of 2018, compared to 508,000 bbls/d in the prior year period. The increase is attributed to improved crude throughput combined with record wholesale volumes in Canada and stronger retail volumes. Retail sales volumes in Canada established a new record for a first quarter.

Realized refined product gross margins were higher in the first quarter of 2018, compared to the prior year quarter, and were impacted primarily by the following factors:

Marketing gross margins in the first quarter of 2018 were higher than in the prior year quarter, primarily due to improved wholesale and retail unit margins, as well as increased contributions from non-petroleum revenues.

After removing the impact of the lubricants business, which was sold in the first quarter of 2017, operating expenses in the first quarter of 2018 were higher than the prior year quarter due to an increase in share-based compensation, partially offset by lower natural gas pricing.

The Edmonton refinery has a planned seven-week maintenance event, which includes a one-month full refinery turnaround, the Sarnia refinery has a six-week turnaround event and the Commerce City refinery has a four-week turnaround event, all of which began late in the first quarter of 2018 and will extend into the second quarter of 2018. The anticipated impact of these maintenance events has been reflected in the company's 2018 guidance.


	Three months ended March 31
($ millions)	2018		2017

Net (loss) earnings	(494	)	49

Adjusted for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	329		(103	)

Gain on significant disposal⁽¹⁾	—		(83	)

Operating (loss) earnings⁽²⁾	(165	)	(137	)

Renewable Energy	1		(2	)

Energy Trading	(9	)	(11	)

Corporate	*(190*	)	(140	)

Eliminations	33		16

Funds (used in) from operations⁽²⁾	(282	)	(141	)

(1): After-tax gain related to the sale of the company's interest in the Cedar Point wind facility.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Renewable Energy had operating earnings of $1 million in the first quarter of 2018, compared to an operating loss of $2 million in the prior year quarter, primarily due to the prior year period recording an impairment charge associated with one of the company's wind facilities, partially offset by lower volumes associated with the sale of the company's interests in the Cedar Point and Ripley wind facilities in 2017.

The operating loss for Energy Trading was $9 million in the first quarter of 2018, and was comparable to $11 million in the first quarter of 2017, with improved crude location spreads offsetting increased rail costs in the first quarter of 2018.

The Corporate operating loss was $190 million for the first quarter of 2018, compared to an operating loss of $140 million for the prior year quarter, with the increased loss attributed to a significant decrease in capitalized interest, a realized gain on forward interest rate swaps in the prior year quarter and an increase in operating costs in the current quarter. These factors were partially offset by lower interest expense as a result of an overall decrease in the company's long-term debt and a higher operational foreign exchange gain than in the prior year period. The company capitalized $77 million of its borrowing costs in the first quarter of 2018 as part of the cost of major development assets and construction projects in progress, compared to $174 million in the prior year quarter, with the decrease resulting from the commissioning of the significant growth projects, Fort Hills and Hebron.

Eliminations reflect the deferral of profit on crude oil sales from Oil Sands and East Coast Canada to the company's refineries. Consolidated profits are only realized when the refined products produced from internal purchases of crude feedstock have been sold to third parties. During the first quarter of 2018, the company realized $33 million of after-tax intersegment profit, compared to $16 million of after-tax intersegment profit realized in the prior year quarter. The increase was due to the timing of recognition of profit in intercompany inventory.

Corporate, Energy Trading and Eliminations funds used in operations for the first quarter of 2018 were $282 million, compared to funds used in operations of $141 million in the prior year period. In addition to the factors noted in operating earnings above, apart from the increase in non-cash share based compensation expense, funds from operations were impacted by the timing of realized losses on derivative financial instruments in the company's Energy Trading business, which were predominately offset by realized gains in prior periods.


	Three months ended March 31
($ millions)	2018		2017

Oil Sands	992		1 059

Exploration and Production	165		227

Refining and Marketing	117		92

Corporate, Energy Trading and Eliminations	17		2

Total capital and exploration expenditures	1 291		1 380

Less: capitalized interest on debt	(77	)	(174	)

	1 214		1 206


	Three months ended March 31, 2018
($ millions)	Sustaining(2)	Growth(3)	Total

Oil Sands

Oil Sands Base	384	7	*391*

In Situ	96	15	*111*

Fort Hills	68	228	*296*

Syncrude	121	1	*122*

Exploration and Production	4	156	160

Refining and Marketing	117	—	117

Corporate, Energy Trading and Eliminations	17	—	17

	807	407	1 214

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

In the first quarter of 2018, total capital and exploration expenditures were $1.214 billion (excluding capitalized interest), compared to $1.206 billion in the prior year period, with increased sustaining capital expenditures offsetting the decrease in growth capital associated with the commissioning of the company's major growth projects, Fort Hills and Hebron. Higher sustaining capital in the first quarter of 2018 was primarily driven by an increase in planned maintenance activity in 2018.

This included preliminary planning work on the first full turnaround in five years of Oil Sands operations Upgrader 1 and the advancement of the upgrader turnaround at Syncrude, as well as an increase in spending associated with the company's recently approved tailings management plan. The company anticipates the majority of the turnaround costs to be incurred in the first half of 2018, and expects to remain within the capital guidance range of $4.5 to $5.0 billion for the year. Activity in the first quarter of 2018 is summarized by business unit below.

Oil Sands Base capital and exploration expenditures were $391 million in the first quarter of 2018, the majority of which focused on sustaining activities related to the company's planned maintenance program, ongoing tailings management, including development of new tailings infrastructure, and various reliability and sustainment projects across the operations.

In Situ capital and exploration expenditures were $111 million, of which $96 million was directed towards sustaining activities, including an increase in well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Capital expenditures at Fort Hills were $296 million in the first quarter of 2018, of which $228 million was related to growth spending which focused primarily on ramping up the project to full rates, and continued development of the remaining secondary extraction facilities. Sustaining capital expenditures in the first quarter of 2018 continued to focus on early work associated with sustaining activities that will support the execution of the mine and tailings plan.

Fort Hills began producing paraffinic froth-treated bitumen from secondary extraction on January 27, 2018, and the production ramp up to the project's nameplate capacity of 194,000 bbls/d (105,000 bbls/d net to Suncor) is progressing ahead of schedule. The second of three secondary extraction trains was commissioned at the end of the first quarter of 2018 and the third secondary extraction train is expected to come online in the second quarter of 2018.

During the fourth quarter of 2017, the Fort Hills partners resolved the previously announced commercial dispute and reached an agreement whereby Suncor and Teck Resources Limited (Teck) each acquired an additional working interest in the Fort Hills project from Total E&P Canada Ltd. (Total). In the first quarter of 2018, under the terms of the agreement, Suncor's share of the project increased to 54.11%, Teck's share increased to 21.31%, and Total's share decreased to 24.58%. Working interests in the Fort Hills project may be further adjusted in accordance with the terms of the agreement.

Syncrude capital and exploration expenditures were $122 million in the first quarter of 2018, of which sustaining capital expenditures were $121 million and were primarily focused on maintaining assets, including the advancement of maintenance originally scheduled for the second quarter of 2018, and execution of the mine tailings plan.

Capital expenditures at E&P were $160 million in the first quarter of 2018 and were primarily focused on growth opportunities, including continued development drilling at Hebron as part of the ramp up phase. Other E&P activity in the first quarter included development drilling at White Rose, Terra Nova and Hibernia, as well as development work on the West White Rose Project and the Norwegian Oda project.

R&M capital expenditures were $117 million and were primarily related to the ongoing sustainment of operations, including planned refinery maintenance, enhancements to retail operations and information technology upgrades.

Corporate capital expenditures were $17 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended March 31
	2018	2017

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	7.8	4.4

Including major projects in progress	6.5	3.5

Net debt to funds from operations⁽²⁾ (times)	1.7	1.8

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	6.1	2.2

Funds from operations basis⁽²⁾⁽⁴⁾	11.8	8.4

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

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, available lines of credit and proceeds received from the divestiture of non-core assets. Suncor's management believes the company will have the capital resources to fund its planned 2018 capital spending program of $4.5 to $5.0 billion and to meet current and future working capital requirements through cash balances and cash equivalents, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and, if needed, divesting of non-core assets and accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

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

Cash and cash equivalents decreased to $2.083 billion during the first three months of 2018, from $2.672 billion at December 31, 2017, which is due, in part, to the company decision to hold less cash following the commissioning of Fort Hills and Hebron. In addition, the decrease is a result of a use of cash associated with an increase in the company's non-cash working capital balances, the company's capital and exploration expenditures and dividend requirements, the acquisition of an additional 5% interest in Syncrude and the purchase of the company's own shares under its normal course issuer bid, partially offset by funds from operations and an increase in short-term indebtedness.

As at March 31, 2018, the weighted average term to maturity of the short-term investment portfolio was approximately 15 days.

Available credit facilities for liquidity purposes at March 31, 2018 decreased to $2.719 billion, compared to $4.489 billion at December 31, 2017, which was primarily a result of an increase in short-term indebtedness which was, in part, associated with the acquisition of an additional 5% working interest in Syncrude.

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

Suncor is subject to financial and operating covenants related to its bank debt and public market debt. Failure to meet the terms of one or more of these covenants may constitute an "event of default" as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its financial covenant that requires total debt to not exceed 65% of its total debt plus shareholders' equity. At March 31, 2018, total debt to total debt plus shareholders' equity was 28.0% (December 31, 2017 – 25.6%). The company continues to be in compliance with all operating covenants.


($ millions, except as noted)	March 31 2018	December 31 2017

Short-term debt	3 973	2 136

Current portion of long-term debt	63	71

Long-term debt	13 650	13 372

Total debt	17 686	15 579

Less: Cash and cash equivalents	2 083	2 672

Net debt	15 603	12 907

Shareholders' equity	45 483	45 383

Total debt plus shareholders' equity	63 169	60 962

Total debt to total debt plus shareholders' equity (%)	28.0	25.6


($ millions)	Three months ended March 31, 2018

Total debt – beginning of period	15 579

Net decrease in long-term debt	(17	)

Increase in short-term debt	1 745

Foreign exchange on debt, and other	379

Total debt – March 31, 2018	17 686

Less: Cash and cash equivalents – March 31, 2018	2 083

Net debt – March 31, 2018	15 603

The company's total debt increased in the first quarter of 2018 due to an increase in short-term indebtedness, which was primarily used to fund the acquisition of an additional 5% working interest in Syncrude, as well as the impact of unfavourable foreign exchange rates on U.S. dollar denominated debt compared to December 31, 2017.

As at April 27, 2018, the total number of common shares outstanding was 1,633,879,598 and the total number of exercisable and non-exercisable common share options outstanding was 33,834,741. Once exercisable, each outstanding common share option is convertible into one common share.

Under the company's normal course issuer bid that commenced in the second quarter of 2017 (2017 NCIB), the company was permitted to purchase for cancellation up to approximately $2.0 billion worth of its common shares from May 2, 2017 to May 1, 2018 and had agreed that it would not purchase more than 50,079,795 common shares, which was equal to approximately 3% of Suncor's issued and outstanding common shares.

Pursuant to the 2017 NCIB, Suncor repurchased 8,999,091 common shares at an average price of $43.28 per share, for a total of $389 million in the first quarter of 2018, compared to the prior year quarter where no purchases were made.

The Toronto Stock Exchange (TSX) accepted a notice filed by Suncor of its intention to renew its normal course issuer bid (the 2018 NCIB) to continue to purchase shares under its previously announced buyback program through the facilities of the TSX, New York Stock Exchange and/or alternative trading platforms. The notice provides that Suncor may purchase for cancellation up to approximately $2.15 billion worth of its common shares beginning May 4, 2018 and ending May 3, 2019.

Pursuant to the 2018 NCIB, Suncor has agreed that it will not repurchase more than 52,285,330 common shares, which is equal to approximately 3% of Suncor's issued and outstanding common shares.

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

During the three months ended March 31, 2018, the company increased its commitments by approximately $100 million (undiscounted), which is primarily related to a diluent storage service arrangement and additional mining equipment at Fort Hills.

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


Three months ended ($ millions, unless otherwise noted)	Mar 31 2018		Dec 31 2017		Sept 30 2017	June 30 2017	Mar 31 2017	Dec 31 2016		Sept 30 2016		June 30 2016

Total production (mboe/d)

Oil Sands	571.7		621.2		628.4	413.6	590.6	620.4		617.5		213.1

Exploration and Production	117.7		115.2		111.5	125.5	134.5	118.1		110.6		117.6

	689.4		736.4		739.9	539.1	725.1	738.5		728.1		330.7

Revenues and other income

Operating revenues, net of royalties⁽²⁾	8 807		8 973		7 963	7 231	7 787	7 805		7 352		5 855

Other (loss) income	(57	)	41		43	16	25	301		(15	)	(58	)

	8 750		9 014		8 006	7 247	7 812	8 106		7 337		5 797

Net earnings (loss)	789		1 382		1 289	435	1 352	531		392		(735	)

per common share – basic (dollars)	0.48		0.84		0.78	0.26	0.81	0.32		0.24		(0.46	)

per common share – diluted (dollars)	0.48		0.84		0.78	0.26	0.81	0.32		0.24		(0.46	)

Operating earnings (loss)⁽¹⁾	985		1 310		867	199	812	636		346		(565	)

per common share – basic⁽¹⁾ (dollars)	0.60		0.79		0.52	0.12	0.49	0.38		0.21		(0.36	)

Funds from operations⁽¹⁾	2 164		3 016		2 472	1 627	2 024	2 365		2 025		916

per common share – basic⁽¹⁾ (dollars)	1.32		1.83		1.49	0.98	1.21	1.42		1.22		0.58

Cash flow provided by operating activities	724		2 755		2 912	1 671	1 628	2 791		1 979		862

per common share – basic (dollars)	0.44		1.67		1.75	1.00	0.98	1.68		1.19		0.54

ROCE⁽¹⁾ (%) for the twelve months ended	6.5		6.7		5.5	4.9	3.5	0.4		(3.9	)	(4.1	)

ROCE⁽¹⁾, excluding major projects in progress (%) for twelve months ended	7.8		8.6		7.0	6.2	4.4	0.5		(4.6	)	(4.9	)

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(329	)	(91	)	412	278	103	(222	)	(112	)	(27	)

Common share information (dollars)

Dividend per common share	0.36		0.32		0.32	0.32	0.32	0.29		0.29		0.29

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	44.49		46.15		43.73	37.89	40.83	43.90		36.42		35.84

New York Stock Exchange (US$)	34.54		36.72		35.05	29.20	30.75	32.69		27.78		27.73

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Restated in accordance with the new IFRS 15 revenue requirements, with no impact to net earnings or operating earnings. For further information on the restatements associated with IFRS 15, refer to note 3 in Suncor's Consolidated Financial Statements for the three-month period ended March 31, 2018.


Three months ended (average for the period ended, except as noted)		Mar 31 2018	Dec 31 2017	Sept 30 2017	June 30 2017	Mar 31 2017	Dec 31 2016	Sept 30 2016	June 30 2016

WTI crude oil at Cushing	US$/bbl	62.90	55.40	48.20	48.30	51.85	49.35	44.95	45.60

Dated Brent crude	US$/bbl	66.80	61.40	52.50	49.85	53.75	49.50	45.85	45.60

Dated Brent/Maya FOB price differential	US$/bbl	7.70	9.60	6.30	5.80	9.05	6.70	6.80	7.65

MSW at Edmonton	Cdn$/bbl	72.45	69.30	57.05	62.30	64.25	62.00	55.10	55.80

WCS at Hardisty	US$/bbl	38.60	43.10	38.25	37.20	37.30	35.00	31.45	32.30

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	24.30	12.30	9.95	11.10	14.55	14.35	13.50	13.30

Condensate at Edmonton	US$/bbl	63.15	57.95	47.60	48.45	52.20	48.35	43.05	44.10

Natural gas (Alberta spot) at AECO	Cdn$/mcf	2.05	1.70	1.45	2.80	2.70	3.10	2.30	1.40

Alberta Power Pool Price	Cdn$/MWh	34.95	22.35	24.55	19.30	22.40	21.95	17.90	14.90

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	15.50	19.40	22.35	16.35	12.55	14.35	14.00	16.10

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	12.85	20.20	19.25	14.40	11.15	10.55	14.15	16.65

Portland 3-2-1 crack⁽¹⁾	US$/bbl	20.35	22.10	26.80	21.25	18.45	14.95	18.75	19.30

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	15.55	18.25	21.45	16.80	14.00	13.15	14.50	14.85

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

Exchange rate (end of period)	US$/Cdn$	0.78	0.80	0.80	0.77	0.75	0.74	0.76	0.77

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

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

Suncor's significant accounting policies and a summary of recently announced accounting standards are described in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2017 annual MD&A.

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are those that require management to make assumptions about matters that are highly uncertain at the time the estimate is made. Critical accounting estimates are also those estimates which, where a different estimate could have been used or where changes in the estimate that are reasonably likely to occur, would have a material impact on the company's financial condition, changes in financial condition or financial performance. Critical accounting estimates and judgments are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of Suncor's critical accounting estimates is provided in note 4 to the audited Consolidated Financial Statements for the year ended December 31, 2017 and in the Accounting Policies and Critical Accounting Estimates section of Suncor's 2017 annual MD&A.

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company's position with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor's financial instruments and the related financial risk factors, see note 28 of the audited Consolidated Financial Statements for the year ended December 31, 2017, note 11 to the unaudited interim Consolidated Financial Statements for the three months ended March 31, 2018, and the Financial Condition and Liquidity section of Suncor's 2017 annual MD&A.

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

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

Based on their evaluation as at March 31, 2018, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at March 31, 2018, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three-month period ended March 31, 2018 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 2018 corporate guidance, as set forth in Suncor's press release dated May 1, 2018, which is also available on www.sedar.com.

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

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

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

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

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


For the twelve months ended March 31 ($ millions, except as noted)		2018		2017

Adjustments to net earnings

Net earnings		3 895		1 540

(Deduct) add after-tax amounts for:

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt		(270	)	258

Net interest expense		197		278

	A	3 822		2 076

Capital employed – beginning of twelve-month period

Net debt		13 216		14 880

Shareholders' equity		45 516		42 935

		58 732		57 815

Capital employed – end of twelve-month period

Net debt		15 603		13 216

Shareholders' equity		45 483		45 516

		61 086		58 732

Average capital employed	B	59 097		58 789

ROCE – including major projects in progress (%)	A/B	6.5		3.5

Average capitalized costs related to major projects in progress	C	10 192		11 018

ROCE – excluding major projects in progress (%)	A/(B–C)	7.8		4.4

Funds from (used in) operations is a non-GAAP financial measure that adjusts a GAAP measure – cash flow provided by (used in) operating activities – for changes in non-cash working capital, which management uses to analyze operating performance and liquidity. Changes to non-cash working capital can include, among other factors, the timing of offshore feedstock purchases and payments for commodity and income taxes, 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 consolidated GAAP measure in the Non-GAAP Financial Measures Advisory section of each respective MD&A or quarterly report to shareholders, as applicable, for the related quarter.


Three months ended March 31	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2018		2017		2018		2017		2018		2017		2018		2017		2018		2017

Net earnings	82		302		395		172		806		829		(494	)	49		789		1 352

Adjustments for:

Depreciation, depletion, amortization and impairment	974		941		279		284		154		160		17		37		1 424		1 422

Deferred income taxes	57		9		(55	)	(59	)	23		(9	)	4		47		29		(12	)

Accretion	51		49		12		10		2		2		—		—		65		61

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	—		—		—		—		—		—		373		(109	)	373		(109	)

Change in fair value of financial instruments and trading inventory	8		(7	)	—		—		12		(10	)	(71	)	27		(51	)	10

Gain on disposal of assets	(1	)	(1	)	(162	)	—		—		(349	)	—		(70	)	(163	)	(420	)

Share-based compensation	(64	)	(86	)	(10	)	(3	)	(35	)	(38	)	(115	)	(123	)	(224	)	(250	)

Exploration	—		—		—		41		—		—		—		—		—		41

Settlement of decommissioning and restoration liabilities	(154	)	(118	)	(13	)	(1	)	(2	)	(1	)	—		—		(169	)	(120	)

Other	26		20		56		37		5		(9	)	4		1		91		49

Funds from (used in) operations⁽¹⁾	979		1 109		502		481		965		575		(282	)	(141	)	2 164		2 024

(Increase) in non-cash working capital																	(1 440	)	(396	)

Cash flow provided by operating activities																	724		1 628

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

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

Oil Sands operations, In Situ, 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. To determine In Situ cash operating costs, Oil Sands operations cash operating costs are further adjusted to remove costs pertaining to Oil Sands operations mining and upgrading. 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, 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 Oil Sands operating performance. Oil Sands operations cash operating costs in the first quarter of 2018 were $982 million and included $207 million related to In Situ production for In Situ cash operating costs per barrel of $9.55, based on total In Situ production of 240,900 bbls/d.

Refining margin and refining operating expense are non-GAAP financial measures and are presented on a LIFO basis. Refining margin is calculated by adjusting R&M segment operating revenue, other income and purchases of crude oil and products (GAAP measures) for non-refining margin pertaining to the company's supply, marketing and ethanol businesses, and the company's former lubricants business, as well as removing the impact of FIFO inventory gains and losses and risk management hedging 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 March 31
($ millions, except as noted)	2018		2017

Refining margin reconciliation

Gross margin, operating revenue less purchases of crude oil and products	1 773		1 328

Other (loss) income	(7	)	19

Last-in, First-out (LIFO) adjustment	(11	)	(6	)

Non-refining margin	(413	)	(431	)

Refining margin	1 342		910

Refinery production⁽¹⁾ (mbbls)	44 363		41 540

Refining margin ($/bbl)	30.25		21.95

Refining operating expense reconciliation

Operating, selling and general expense	480		503

Non-refining costs	(262	)	(274	)

Refining operating expense	218		229

Refinery production⁽¹⁾ (mbbls)	44 363		41 540

Refining operating expense ($/bbl)	4.90		5.50

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

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

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

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

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


Measurement		Places and Currencies
bbl	barrel	U.S.	United States
bbls/d	barrels per day	U.K.	United Kingdom
mbbls/d	thousands of barrels per day
		$ or Cdn$	Canadian dollars
boe	barrels of oil equivalent	US$	United States dollars
boe/d	barrels of oil equivalent per day
mboe	thousands of barrels of oil equivalent
mboe/d	thousands of barrels of oil equivalent per day	Financial and Business Environment
		Q1	Three months ended March 31
GJ	Gigajoule	DD&A	Depreciation, depletion and amortization
		WTI	West Texas Intermediate
mcf	thousands of cubic feet of natural gas	WCS	Western Canadian Select
mcfe	thousands of cubic feet of natural gas equivalent	SCO	Synthetic crude oil
mmcf	millions of cubic feet of natural gas	MSW	Mixed Sweet Blend
mmcf/d	millions of cubic feet of natural gas per day	NYMEX	New York Mercantile Exchange
mmcfe	millions of cubic feet of natural gas equivalent	YTD	Year to date
mmcfe/d	millions of cubic feet of natural gas equivalent
	per day
MW	megawatts
MWh	megawatts per hour

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

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

Factors that affect 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; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; Suncor's dependence on pipeline capacity and other logistical constraints, which may affect the company's ability to distribute products to market; Suncor's ability to finance Oil Sands growth and sustaining capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; 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 our E&P segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya due to ongoing political unrest; and 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; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; 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 execution of Suncor's major projects and the commissioning and integration of new facilities; 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; the risk that competing business objectives may exceed Suncor's capacity to adopt and implement change; risks and uncertainties associated with obtaining regulatory and stakeholder approval for the company's operations and exploration and development activities; the potential for disruptions to operations and construction projects as a result of 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; the receipt of any required regulatory or other third-party approvals outside of Suncor's control and the satisfaction of any conditions to such approvals; risks associated with land claims and Aboriginal consultation requirements; risks relating to litigation; 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 2017 annual MD&A, 2017 AIF and Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

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


	Three months ended March 31
Net of transportation costs, but before royalties	2018	2017

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	82.78	68.03

E&P Canada – Natural gas ($/mcfe)	1.94	2.48

E&P International ($/boe)	81.01	65.74


(thousands)		March 31 2018

Common shares		1 633 816

Common share options – exercisable		20 877

Common share options – non-exercisable		14 083


1.	Advisories	6
2.	First Quarter Highlights	8
3.	Consolidated Financial Information	9
4.	Segment Results and Analysis	14
5.	Capital Investment Update	26
6.	Financial Condition and Liquidity	28
7.	Quarterly Financial Data	31
8.	Other Items	33
9.	Non-GAAP Financial Measures Advisory	34
10.	Common Abbreviations	38
11.	Forward-Looking Information	39