All financial figures are unaudited and presented in Canadian dollars (Cdn$) unless noted otherwise. Production volumes are presented on a working-interest basis, before royalties, unless noted otherwise. Certain financial measures in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these non-GAAP financial measures, see the Non-GAAP Financial Measures Advisory section of Suncor's Management's Discussion and Analysis, dated July 27, 2016 (the MD&A). See also the Advisories section of the MD&A. References to Oil Sands operations production and cash operating costs exclude Suncor's interest in Syncrude's operations.

"The forest fires in the Fort McMurray area significantly impacted the region," said Steve Williams, president and chief executive officer. "We shut in our Oil Sands production and focused on the safe evacuation of employees, their families and the community. I'm tremendously proud of the Suncor team. Their resilience and professionalism was readily apparent throughout our response and ensured our assets safely returned to service."

Suncor Energy Inc. recorded a second quarter 2016 operating loss⁽¹⁾ of $565 million ($0.36 per common share) and cash flow from operations⁽¹⁾ of $916 million ($0.58 per common share), compared to operating earnings of $906 million ($0.63 per common share) and cash flow from operations of $2.155 billion ($1.49 per common share) in the prior year quarter. The results reflected the significant decrease in Oil Sands production associated with shutting in operations to address evacuation and safety concerns related to the forest fires in the Fort McMurray region and the subsequent restart and ramp up of production, a turnaround of Upgrader 2 at Oil Sands Base plant, a higher share of Syncrude operating expenses due to the acquisition of additional working interests in 2016 and a lower crude oil price environment. These factors were partially offset by lower operating costs when excluding the impacts of the acquisitions, positive downstream realized margins due to favourable refined product location differentials and a higher FIFO gain, additional production from Syncrude as a result of the increased working interest, and increased production from Exploration & Production (E&P).

A net loss of $735 million ($0.46 per common share) was recorded in the second quarter of 2016, compared with net earnings of $729 million ($0.50 per common share) in the prior year quarter. The net loss for the second quarter of 2016 was impacted by the same factors that influenced the operating loss described above and also included a non-cash after-tax charge of $73 million for early payment of debt, a non-cash after-tax mark to market loss of $70 million on interest rate derivatives for future debt issuance, as well as a non-cash after-tax foreign exchange loss on the revaluation of U.S. dollar denominated debt of $27 million. Net earnings in the prior year quarter included a non-cash $423 million deferred income tax charge related to a 2% increase in the Alberta corporate income tax rate, partially offset by a non-cash after-tax foreign exchange gain of $178 million and an after-tax gain of $68 million on the disposal of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment.

Suncor's total upstream production decreased to 330,700 barrels of oil equivalent per day (boe/d) in the second quarter of 2016, compared with 559,900 boe/d in the prior year quarter, due primarily to shutting in production at Oil Sands operations and Syncrude as a result of the forest fires in the Fort McMurray region, being partially offset by a higher working interest in Syncrude and increased production from E&P.

Oil Sands operations production was 177,500 bbls/d in the second quarter of 2016, compared to 423,800 bbls/d in the prior year quarter, with the decrease primarily due to the forest fires noted above, as well as the completion of a turnaround at the Upgrader 2 facilities, the first completed since the company moved to a five-year turnaround cycle. By mid-July, production at all Oil Sands operations assets had returned to normal rates.

Cash operating costs per barrel⁽¹⁾ for Oil Sands operations increased in the second quarter of 2016 to $46.80 per barrel (bbl), compared to $28.00/bbl in the prior year quarter, due primarily to the loss of production associated with the forest fires and increased turnaround activity, partially offset by lower costs associated with the forest fire outage and the company's cost reduction initiatives. Even with the impacts of the forest fires, Oil Sands operations cash operating costs are expected to be within the full year guidance range of $27.00-$30.00 on a per barrel basis.

Suncor's share of Syncrude production increased to 35,600 bbls/d in the second quarter of 2016, compared to prior year quarterly production of 24,900 bbls/d. The increase is due to the acquisitions of Canadian Oil Sands Limited (COS) in the first quarter of 2016 and Murphy's 5% Syncrude ownership interest in the second quarter of 2016, which was significantly offset by the impact of the forest fires in the Fort McMurray region. Turnaround activity impacted both quarters. Production at Syncrude returned to normal rates by mid-July.

Production volumes in E&P increased to 117,600 boe/d in the second quarter of 2016, compared to 111,200 boe/d in the prior year quarter, primarily due to higher production from new wells at Hibernia, as well as Golden Eagle operating at peak rates compared to being in the ramp-up phase in the second quarter of 2015, partially offset by natural production declines at Terra Nova.

During the second quarter of 2016, Refining and Marketing completed planned maintenance at the Commerce City, Sarnia and Montreal refineries. Average refinery utilization declined to 87% in the second quarter, compared to 90% in the prior year quarter, which included fewer planned maintenance events. In addition, the forest fires in the Fort McMurray region led to reduced throughput at the Edmonton refinery due to constrained crude supply.

"Solid results from our downstream business and reliable production from our E&P assets allowed us to generate positive cash flow in the quarter, helping to offset the impacts of the forest fires, and once again demonstrating the value of our integrated model," said Williams.

During the quarter, Suncor acquired an additional 5% ownership interest in Syncrude from Murphy for $946 million, bringing Suncor's total ownership share of Syncrude to 53.74% and adding an additional 17,500 bbls/d of SCO capacity.

In the second quarter of 2016, the company completed a common share issuance for net proceeds of $2.8 billion and bought back $891 million (US$688 million principal value) of high cost long-term debt and repaid $600 million of bank debt, which were both acquired as part of the acquisition of COS. The early payment of high cost borrowings is expected to reduce long-term financing costs and provide ongoing balance sheet flexibility.

"Our commitment to long-term profitable growth continues to be a priority," said Williams. "The acquisition of an additional 5% of Syncrude is expected to return additional value to shareholders, and the equity issuance completed in the quarter will allow us to pursue further strategic growth opportunities that may arise."

Suncor remains on track to achieve the $750 million reduction to its original 2016 capital budget and continues to progress major growth projects, Fort Hills and Hebron.

The company's strategy includes divesting of non-core assets that are not key components of the integrated model. In the second quarter of 2016, Suncor has commenced a sale process for the lubricants business and anticipates that a sale could occur within the next twelve months.

Suncor continued to deliver cash to shareholders in the second quarter of 2016 through $458 million in dividends ($0.29 per common share).

The main focus in Oil Sands operations was the safe evacuation of employees and Fort McMurray residents and the careful shutdown and return of all Fort McMurray region assets to operating status. The company continued to progress key reliability, safety and environmental performance projects and, following an interruption due to the forest fires, completed a turnaround of Upgrader 2 assets. Second quarter spending in 2016 also included construction of logistic and storage assets to support market access for Fort Hills' bitumen.

The Fort Hills mining project is more than 60% complete at June 30, 2016, with the majority of overseas module construction now complete and the remaining work to be almost entirely based in Canada. Construction activities have resumed after being interrupted in the second quarter of 2016 due to the forest fires in the Fort McMurray area. The company is still targeting first oil at the end of 2017 and is currently assessing and making plans to mitigate the impact of this interruption on the project. Key activities in the period included module fabrication for secondary extraction and utilities as well as procurement of mining and extraction equipment.

Spending at Fort Hills also included advancement of certain early-works sustaining activities that are expected to optimize the mine plan following the commencement of production. The second quarter of 2016 also included an increased share of Syncrude sustaining capital, which was focused on a coker turnaround.

Construction of the Hebron project continued in the second quarter of 2016, with the utility process module being shipped from its construction site in South Korea on schedule, a key milestone for the project. First oil from the project is expected in late 2017.

Growth capital expenditures also included development drilling activities at Hibernia, Golden Eagle and White Rose. Exploration drilling at the deepwater Shelburne Basin offshore Nova Scotia resumed late in the second quarter of 2016 following an operational delay.


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Net (loss) earnings	(735	)	729		(478	)	388

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	27		(178	)	(858	)	762

Non-cash mark to market loss on interest rate swaps⁽²⁾	70		—		160		—

Non-cash loss on early payment of long-term debt⁽³⁾	73		—		73		—

COS acquisition and integration costs⁽⁴⁾	—		—		38		—

Impact of income tax rate adjustments on deferred taxes⁽⁵⁾	—		423		—		17

Gain on significant disposal⁽⁶⁾	—		(68	)	—		(68	)

Restructuring charges⁽⁷⁾	—		—		—		57

Insurance proceeds⁽⁸⁾	—		—		—		(75	)

Operating (loss) earnings⁽¹⁾	(565	)	906		(1 065	)	1 081

(1): Operating (loss) earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash loss on interest rate swaps resulting from a decrease in long-term interest rates and unfavourable foreign exchange.
(3): Charges associated with early repayment of debt in the Corporate segment.
(4): Transaction and related charges associated with the acquisition of COS.
(5): Adjustments to the company's deferred income taxes resulting from a decrease in the United Kingdom tax rate on oil and gas profits from the North Sea in the first quarter of 2015 and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(6): After-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment.
(7): Restructuring charges related to the cost reduction initiatives.
(8): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

There have been no changes to the corporate guidance ranges previously issued on June 6, 2016. Guidance issued on July 27, 2016 now reflects the acquisition of an additional 5% working interest in Syncrude.

For further details and advisories regarding Suncor's 2016 revised corporate guidance, see www.suncor.com/guidance.

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

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

For a description of Suncor's segments, refer to Suncor's Management's Discussion and Analysis for the year ended December 31, 2015, dated February 25, 2016 (the 2015 annual MD&A).

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's unaudited interim Consolidated Financial Statements for the three-month and six-month periods ended June 30, 2016, Suncor's audited Consolidated Financial Statements for the year ended December 31, 2015 and the 2015 annual MD&A.

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

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

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

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

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

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

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

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


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Net (loss) earnings

Oil Sands	(1 063	)	(44	)	(1 587	)	(190	)

Exploration and Production	26		44		(8	)	506

Refining and Marketing	689		677		930		1 175

Corporate, Energy Trading and Eliminations	(387	)	52		187		(1 103	)

Total	(735	)	729		(478	)	388

Operating (loss) earnings⁽¹⁾

Oil Sands	(1 063	)	315		(1 587	)	169

Exploration and Production	26		77		(8	)	58

Refining and Marketing	689		645		930		1 143

Corporate, Energy Trading and Eliminations	(217	)	(131	)	(400	)	(289	)

Total	(565	)	906		(1 065	)	1 081

Cash flow from (used in) operations⁽¹⁾

Oil Sands	(202	)	1 058		61		1 583

Exploration and Production	302		427		563		876

Refining and Marketing	885		816		1 289		1 502

Corporate, Energy Trading and Eliminations	(69	)	(146	)	(315	)	(331	)

Total	916		2 155		1 598		3 630

Capital and Exploration Expenditures⁽²⁾

Sustaining	752		575		1 223		952

Growth	869		890		1 813		1 746

Total	1 621		1 465		3 036		2 698


	Three months ended June 30		Six months ended June 30
	2016	2015	2016	2015

Production volumes by segment

Oil Sands (mbbls/d)	213.1	448.7	389.4	462.1

Exploration and Production (mboe/d)	117.6	111.2	121.6	118.9

Total	330.7	559.9	511.0	581.0

Production mix

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

Refinery utilization (%)	87	90	89	92

Refinery crude oil processed (mbbls/d)	400.2	416.8	410.5	426.6

Suncor's consolidated net loss for the second quarter of 2016 was $735 million, compared with net earnings of $729 million for the prior year quarter. Net loss for the first six months of 2016 was $478 million, compared to net earnings of $388 million in the prior year period. Net loss was primarily affected by the same factors that influenced operating loss described subsequently in this section of this MD&A. Other items affecting net earnings over these periods included:


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Net (loss) earnings	(735	)	729		(478	)	388

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	27		(178	)	(858	)	762

Non-cash mark to market loss on interest rate swaps⁽²⁾	70		—		160		—

Non-cash loss on extinguishment of long-term debt⁽³⁾	73		—		73		—

COS acquisition and integration costs⁽⁴⁾	—		—		38		—

Impact of income tax rate adjustments on deferred taxes⁽⁵⁾	—		423		—		17

Gain on significant disposal⁽⁶⁾	—		(68	)	—		(68	)

Restructuring charges⁽⁷⁾			—		—		57

Insurance proceeds⁽⁸⁾	—		—		—		(75	)

Operating (loss) earnings⁽¹⁾	(565	)	906		(1 065	)	1 081

(1): Operating (loss) earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of the MD&A.
(2): Non-cash loss on interest rate swaps resulting from a decrease in long-term interest rates and foreign exchange impacts.
(3): Charges associated with early repayment of debt in the Corporate segment.
(4): Transaction and related charges associated with the acquisition of COS.
(5): Adjustments to the company's deferred income taxes resulting from a decrease in the U.K. tax rate on oil and gas profits from the North Sea in the first quarter of 2015 and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(6): After-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment.
(7): Restructuring charges related to the cost reduction initiatives.
(8): Business interruption insurance proceeds on the Terra Nova asset in the E&P segment.

Suncor's consolidated operating loss for the second quarter of 2016 was $565 million and compares to operating earnings of $906 million in the prior year quarter. The decline is due to the significant decrease in Oil Sands production associated with the forest fires in the Fort McMurray region and subsequent restart of operations, a turnaround of Upgrader 2 at Oil Sands Base plant, a higher share of Syncrude operating expenses due to the acquisition of additional working interests in 2016, and a lower crude oil price environment. These factors were partially offset by lower operating costs after removing the impacts of the Syncrude acquisitions, favourable downstream refining margins, additional production from Syncrude as a result of the acquisitions, and increased production from E&P.

Suncor's consolidated operating loss was $1.065 billion for the first six months of 2016, compared to $1.081 billion of operating earnings in the prior year period. The decrease was primarily due to the forest fires noted above, a lower upstream pricing environment consistent with the decline in benchmark crude oil prices, a higher share of Syncrude operating expenses due to the acquisition of additional working interests in 2016 and a less favourable downstream business environment, partially offset by additional production from Syncrude as a result of the acquisitions, lower royalties and higher E&P production.

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

Average for three months ended
June 30

Average for six months ended
June 30

2016

2015

2016

2015

WTI crude oil at Cushing

US$/bbl

45.60

57.95

39.55

53.30

Dated Brent crude oil at Sullom Voe

US$/bbl

45.60

61.95

39.75

57.90

Dated Brent/Maya crude oil FOB price differential

US$/bbl

7.65

8.15

8.30

9.60

MSW at Edmonton

Cdn$/bbl

55.80

68.05

45.15

60.15

WCS at Hardisty

US$/bbl

32.30

46.35

25.80

40.10

Light/heavy differential for WTI at Cushing less WCS at Hardisty

US$/bbl

13.30

11.60

13.75

13.15

Condensate at Edmonton

US$/bbl

44.10

57.95

39.30

51.80

Natural gas (Alberta spot) at AECO

Cdn$/mcf

1.40

2.55

1.60

2.65

Alberta Power Pool Price

Cdn$/MWh

14.90

57.25

16.50

43.20

New York Harbor 3-2-1 crack⁽¹⁾

US$/bbl

16.10

23.85

13.95

21.50

Chicago 3-2-1 crack⁽¹⁾

US$/bbl

16.65

20.30

12.90

18.15

Portland 3-2-1 crack⁽¹⁾

US$/bbl

19.30

32.55

16.15

27.05

Gulf Coast 3-2-1 crack⁽¹⁾

US$/bbl

14.85

22.90

12.95

20.45

Exchange rate

US$/Cdn$

0.78

0.81

0.75

0.81

Exchange rate (end of period)

US$/Cdn$

0.77

0.80

0.77

0.80

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

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 second quarter of 2016 for sweet SCO were negatively affected by a lower WTI price of US$45.60/bbl, compared to US$57.95/bbl in the prior year quarter, as well as an unfavourable differential for SCO relative to WTI. Suncor produces a specific grade of sour SCO, the price realizations for which are influenced by various crude benchmarks, including, but not limited to, MSW at Edmonton and WCS at Hardisty, and which can also be affected by prices negotiated for spot sales. Prices for MSW at Edmonton and WCS at Hardisty decreased in the second quarter of 2016 to $55.80/bbl and US$32.30/bbl, respectively, compared to $68.05/bbl and US$46.35/bbl, respectively, in the prior year quarter, resulting in lower price realizations for sour SCO.

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

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude pricing decreased to an average of US$45.60/bbl in the second quarter of 2016, compared to US$61.95/bbl in the prior year quarter.

Natural gas used in Suncor's Oil Sands and Refining operations is primarily referenced to Alberta spot prices at AECO. The average AECO benchmark decreased to $1.40/mcf in the second quarter of 2016, from $2.55/mcf in the prior year quarter.

Suncor's refining margins are influenced primarily by 3-2-1 crack spreads, which are industry indicators approximating the gross margin on a barrel of crude oil that is refined to produce gasoline and distillates, and by light/heavy and light/sour

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

Excess electricity produced in Suncor's In Situ business is sold to the Alberta Electric System Operator (AESO), with the proceeds netted against the cash operating cost per barrel metric. The Alberta power pool price decreased to an average of $14.90/MWh in the second quarter of 2016 from $57.25/MWh in the prior year quarter.

The majority of Suncor's revenues from the sale of oil and natural gas commodities are based on prices that are determined by or referenced to U.S. dollar benchmark prices. The majority of Suncor's expenditures are realized in Canadian dollars. In the second quarter of 2016, the Canadian dollar weakened in relation to the U.S. dollar as the average exchange rate decreased to US$0.78 per one Canadian dollar from US$0.81 per one Canadian dollar in the prior year quarter. This rate decrease had a positive impact on price realizations for the company during the second quarter of 2016 and partially offsets reduced benchmark crude oil prices.

Suncor also has assets and liabilities, notably most of the company's debt, which are denominated in U.S. dollars and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. 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 June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Gross revenues	1 160		2 759		3 199		5 043

Less: Royalties	(9	)	(38	)	(28	)	(56	)

Operating revenues, net of royalties	1 151		2 721		3 171		4 987

Net (loss) earnings	(1 063	)	(44	)	(1 587	)	(190	)

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	—		359		—		359

Operating (loss) earnings⁽²⁾	(1 063	)	315		(1 587	)	169

Oil Sands operations	*(797*	)	350		*(1 314*	)	219

Oil Sands ventures	*(266*	)	(35	)	*(273*	)	(50	)

Cash flow (used in) from operations⁽²⁾	(202	)	1 058		61		1 583

(1): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating loss for Oil Sands operations was $797 million, compared to operating earnings of $350 million in the prior year quarter. The decrease is primarily due to the forced shut in of Oil Sands operations assets in response to the forest fires in the Fort McMurray region and subsequent ramp up of production, increased planned turnaround activity and a lower crude oil price environment. These decreases were partially offset by lower operating, selling and general and transportation expenses associated with the production outage, the company's cost reduction initiatives, lower commodity input costs and lower royalties.

Operating loss for Oil Sands ventures was $266 million, compared to an operating loss of $35 million in the prior year quarter. The decrease was primarily due to the forest fires noted above, a higher share of Syncrude operating expenses due to the acquisition of additional working interests in 2016 and lower price realizations, partially offset by additional production from Syncrude as a result of the increased working interest and the reduction in operating, selling and general expenses associated with the production outage resulting from the forest fires.

In the second quarter of 2016, Suncor acquired an additional 5% working interest in Syncrude from Murphy, adding 17,500 bbls/d of SCO capacity and increasing the company's ownership interest to 53.74%.


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2016	2015	2016	2015

Upgraded product (SCO and diesel)	86.4	327.4	204.3	336.9

Non-upgraded bitumen	91.1	96.4	110.9	95.1

Oil Sands operations	177.5	423.8	315.2	432.0

Oil Sands ventures – Syncrude	35.6	24.9	74.2	30.1

Total	213.1	448.7	389.4	462.1

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


	Three months ended June 30		Six months ended June 30
(mbbls/d)	2016	2015	2016	2015

Oil Sands sales volumes

Sweet SCO	29.0	102.4	80.6	107.5

Diesel	3.4	35.1	14.1	33.0

Sour SCO	76.3	194.4	124.5	197.8

Upgraded product	108.7	331.9	219.2	338.3

Non-upgraded bitumen	108.1	91.8	121.3	93.8

Oil Sands operations	216.8	423.7	340.5	432.1

Oil Sands ventures – Syncrude	35.6	24.9	74.2	30.1

Total	252.4	448.6	414.7	462.2

Production volumes for Oil Sands operations decreased to 177,500 bbls/d in the second quarter of 2016, compared to 423,800 bbls/d in the prior year quarter. The decrease was driven primarily by the loss of production associated with the forest fires in the Fort McMurray area and was also impacted by a turnaround of Upgrader 2.

Sales volumes for Oil Sands operations decreased to an average of 216,800 bbls/d in the second quarter of 2016, from 423,700 bbls/d in the prior year quarter, due to the same factors noted above, partially offset by a draw of inventory in response to the loss of production associated with the forest fires.

Suncor's share of Syncrude production increased to 35,600 bbls/d in the second quarter of 2016, compared to production of 24,900 bbls/d in the prior year quarter. The increase is due to the acquisition of COS in the first quarter of 2016 and Murphy's 5% Syncrude ownership interest in the second quarter of 2016, partially offset by the loss of production associated with the forest fires.


	Three months ended June 30		Six months ended June 30
	2016	2015	2016	2015

Oil Sands Base

Bitumen production (mbbls/d)	66.8	315.5	185.4	316.9

Bitumen ore mined (thousands of tonnes per day)	106.1	474.7	277.7	470.4

Bitumen ore grade quality (bbls/tonne)	0.63	0.66	0.67	0.67

In Situ

Bitumen production – Firebag (mbbls/d)	121.8	168.1	160.4	178.3

Bitumen production – MacKay River (mbbls/d)	13.1	31.5	25.0	30.4

Total In Situ bitumen production	134.9	199.6	185.4	208.7

Steam-to-oil ratio – Firebag	2.6	2.6	2.6	2.6

Steam-to-oil ratio – MacKay River	3.2	3.0	3.0	2.9

Oil Sands Base bitumen production from mining and extraction activities decreased to an average of 66,800 bbls/d in the second quarter of 2016 from 315,500 bbls/d in the prior year quarter. The decrease was primarily due to the forest fires and the Upgrader 2 turnaround that occurred in the second quarter of 2016.

In Situ bitumen production decreased to 134,900 bbls/d in the second quarter of 2016, compared to 199,600 bbls/d in the prior year quarter. Production from both Firebag and MacKay River were shut in due to the forest fires. MacKay River production was further impacted by unavailability of a third-party pipeline due to issues incurred by the pipeline operator upon the restart of operations.

Firebag's steam-to-oil ratio was comparable to the prior year quarter, with an effective restart mitigating loss of reservoir performance after being shut in due to forest fires. The steam-to-oil ratio at MacKay River increased to 3.2 from 3.0 in the prior year quarter and was impacted by operations being shut in, as well as a restart delay due to the pipeline issues noted above. Reservoir performance at MacKay River is expected to return to pre-fire levels in the third quarter.


Net of transportation costs, but before royalties	Three months ended June 30				Six months ended June 30
($/bbl)	2016		2015		2016		2015

Oil Sands operations

SCO and diesel	47.51		66.89		41.44		60.07

Bitumen	18.21		37.63		11.67		30.74

Crude sales basket (all products)	32.90		60.55		30.83		53.70

Crude sales basket, relative to WTI	(25.56	)	(10.99	)	(21.90	)	(12.10	)

Oil Sands ventures

Syncrude – sweet SCO	57.64		73.34		51.02		62.18

Syncrude, relative to WTI	(0.82	)	1.80		(1.71	)	(3.62	)

Average price realizations at Oil Sands operations decreased to $32.90/bbl in the second quarter of 2016 from $60.55/bbl in the prior year quarter, primarily due to the lower WTI benchmark price, partially offset by favourable foreign exchange rates and the narrowing of crude differentials.

Average price realizations at Syncrude decreased to $57.64/bbl in the second quarter of 2016 from $73.34/bbl in the prior year quarter for the same reasons that impacted Oil Sands operations above.

Royalties for the Oil Sands segment were lower in the second quarter of 2016 compared to the prior year quarter, due to lower volumes associated with the loss of production resulting from the forest fires, as well as lower price realizations.

Operating and transportation expenses for the second quarter of 2016 decreased from the prior year quarter, primarily due to costs avoided while operations were shut in, lower natural gas costs and the company's cost reduction initiatives, partially offset by the company's increased working interest in Syncrude. See the Cash Operating Costs section below for further details regarding cash operating costs and non-production costs for Oil Sands operations. Transportation expense for the second quarter of 2016 was lower than the prior year quarter, primarily due to reduced sales volumes.

DD&A expense for the second quarter of 2016 was higher than the same period of 2015 due to the increased working interest in Syncrude and a larger asset base at Oil Sands operations, partially offset by lower depletion associated with the decrease in volumes in the period.


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Oil Sands operations cash operating cost reconciliation

Operating, selling and general expense (OS&G)	1 288		1 285		2 723		2 657

Syncrude OS&G	(364	)	(129	)	(698	)	(243	)

Non-production costs⁽¹⁾	(32	)	(7	)	(65	)	(46	)

Excess power capacity and other⁽²⁾	(50	)	(68	)	(81	)	(136	)

Inventory changes	(87	)	(1	)	(125	)	(26	)

Oil Sands operations cash operating costs⁽³⁾	755		1 080		1 754		2 206

Oil Sands operations cash operating costs ($/bbl)⁽³⁾	46.80		28.00		30.60		28.20

Syncrude cash operating costs

Syncrude cash operating costs⁽⁴⁾	360		127		691		240

Syncrude cash operating costs ($/bbl)	113.55		56.10		51.20		44.20

(1): Significant non-production costs include, but are not limited to, share-based compensation expense and research and development expenses.
(2): Excess power capacity and other includes the operational revenue impacts of excess power from a cogeneration unit and the natural gas expense recorded as part of a non-monetary arrangement involving a third-party processor.
(3): Oil Sands operations cash operating costs and cash operating costs per barrel are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(4): Syncrude cash operating costs are presented on a sales basis, after deducting non-production costs, primarily relating to research and development.

Cash operating costs per barrel⁽¹⁾ for Oil Sands operations increased to $46.80/bbl in the second quarter of 2016, compared to $28.00/bbl in the prior year quarter, due to the impact of lower production volumes as a result of the forest fires, partially offset by lower total cash operating costs. Total Oil Sands operations cash operating costs⁽¹⁾ decreased to $755 million, compared to $1.080 billion in the second quarter of 2015, predominantly due to costs avoided during the production outage caused by the forest fires.

In the second quarter of 2016, non-production costs, which are excluded from Oil Sands operations cash operating costs, were higher than the prior year quarter, primarily due to higher stock-based compensation expense and a charge associated with early termination of a third-party operating arrangement.

Excess power capacity and other costs for the second quarter of 2016 were lower than the second quarter of 2015 due to the loss of cogeneration power production associated with shut-in operations and lower power prices in the second quarter of 2016.

Syncrude cash operating costs per barrel in the second quarter of 2016 increased to $113.55/bbl from $56.10/bbl in the previous year quarter due primarily to lower production attributed to the forest fires. Total Syncrude cash operating costs increased to $360 million from $127 million in the previous year quarter due to the additional Syncrude working interests obtained in 2016, partially offset by reduced operating expenses due to costs avoided while Syncrude was shut-in as a result of the forest fires.

Oil Sands segment operating loss for the first six months of 2016 was $1.587 billion, compared to operating earnings of $169 million for the same period in 2015. Operating earnings decreased due to the loss of production associated with the forest fires in the Fort McMurray area in the second quarter of 2016, the Upgrader 2 turnaround, declines in crude price realizations and higher overall expenses associated with the increased working interest in Syncrude, partially offset by lower operating expenses as a result of costs avoided during the outage, the company's cost reduction initiatives, lower royalty expense and lower natural gas costs.

Cash flow from operations for the first six months of 2016 was $61 million for the segment, compared to $1.583 billion for the same period in 2015. The decrease in cash flow from operations was due to the same factors that influenced the operating loss above.

Cash operating costs per barrel for Oil Sands operations averaged $30.60/bbl for the first six months of 2016, an increase from an average of $28.20/bbl for the first six months of 2015. The increase was primarily due to significantly lower production volumes as a result of the forest fires, offset by lower cash operating costs due to avoiding certain expenditures while operations were shut in, the company's cost reduction initiatives and lower natural gas costs.

Cash operating costs per barrel for Syncrude operations averaged $51.20/bbl for the first six months of 2016, an increase from an average of $44.20/bbl for the first six months of 2015. The increase was primarily due to shut in production at Syncrude as a result of the forest fires, partially offset by lower total cash operating costs resulting from costs avoided during the production outage.

The company plans to commence maintenance at Upgrader 1 in the third quarter of 2016. The impact of this maintenance has been reflected in the company's 2016 guidance.


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Gross revenues	624		780		1 155		1 549

Less: Royalties	(45	)	(96	)	(74	)	(222	)

Operating revenues, net of royalties	579		684		1 081		1 327

Net earnings (loss)	26		44		(8	)	506

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	—		33		—		(373	)

Insurance proceeds	—		—		—		(75	)

Operating earnings (loss)⁽²⁾	26		77		(8	)	58

E&P Canada	40		35		21		2

E&P International	(14	)	42		(29	)	56

Cash flow from operations⁽²⁾	302		427		563		876

(1): Adjustments to the company's deferred income taxes from a 12% decrease in the U.K. tax rate on oil and gas profits from the North Sea in the first quarter of 2015, and a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating earnings of $40 million for E&P Canada increased from $35 million in the prior year quarter, primarily due to an increase in production at Hibernia, insurance proceeds related to Terra Nova property damage and lower royalties, partially offset by lower price realizations.

Operating loss of $14 million for E&P International decreased in the second quarter of 2016, compared to operating earnings of $42 million in the prior year quarter. The decrease is due to lower price realizations and the impairment of the Beta development in Norway, partially offset by higher production from Golden Eagle, and lower exploration and operating costs.


	Three months ended June 30		Six months ended June 30
	2016	2015	2016	2015

E&P Canada

Terra Nova (mbbls/d)	5.4	7.3	9.0	15.3

Hibernia (mbbls/d)	24.6	18.3	24.4	20.1

White Rose (mbbls/d)	11.7	11.4	12.7	12.0

North America Onshore (mboe/d)	2.7	2.4	2.9	3.0

	44.4	39.4	49.0	50.4

E&P International

Buzzard (mboe/d)	52.7	52.4	53.0	51.9

Golden Eagle (mboe/d)	20.5	14.5	19.6	12.2

United Kingdom (mboe/d)	73.2	66.9	72.6	64.1

Libya (mbbls/d)	—	4.9	—	4.4

	73.2	71.8	72.6	68.5

Total Production (mboe/d)	117.6	111.2	121.6	118.9

Production mix (liquids/gas) (%)	98/2	97/3	98/2	96/4

E&P Canada production averaged 44,400 boe/d in the second quarter of 2016, compared to 39,400 boe/d in the prior year quarter. The increase was primarily due to higher production at Hibernia with new wells being brought online

subsequent to the second quarter of 2015, partially offset by natural production declines at Terra Nova. Both quarters were impacted by planned maintenance.

E&P International production averaged 73,200 boe/d in the second quarter of 2016, compared to 71,800 boe/d in the prior year quarter. The increase in production was primarily due to Golden Eagle consistently operating at peak production rates, compared to the second quarter of 2015 when production was still ramping up. Production in Libya remains shut in due to political unrest, with the timing of a return to normal operations remaining uncertain.

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

Royalties for E&P Canada were lower in the second quarter of 2016, compared with the prior year quarter, primarily due to lower price realizations, partially offset by increased production volumes.

Operating and transportation expenses decreased in the second quarter of 2016, compared to the prior year quarter, primarily driven by cost reduction initiatives and lower costs in Libya due to operations being shut in.

Exploration expenses decreased in the second quarter of 2016, compared to the prior year quarter, primarily due to a charge for three non-commercial wells in the North Sea recorded in the second quarter of 2015.

DD&A expense increased in the second quarter of 2016 primarily due to an impairment charge associated with the Beta development in Norway.

The planned maintenance event at Terra Nova was completed within the second quarter of 2016.

Operating loss for E&P in the first six months of 2016 was $8 million, compared to $58 million of operating earnings for the first six months of 2015. Operating earnings were impacted by lower price realizations, partially offset by lower DD&A and exploration expenses, lower royalties, higher production and lower operating expenses.

Cash flow from operations was $563 million for the first six months of 2016, compared to $876 million for the first six months of 2015, and decreased due to lower price realizations, partially offset by lower royalties, higher production and lower operating expenses.


	Three months ended June 30			Six months ended June 30
($ millions)	2016	2015		2016	2015

Operating revenues	4 590	5 230		8 181	10 060

Net earnings	689	677		930	1 175

Adjusted for:

Impact of income tax rate adjustments on deferred taxes⁽¹⁾	—	36		—	36

Gain on significant disposal⁽²⁾	—	(68	)	—	(68	)

Operating earnings⁽³⁾	689	645		930	1 143

Refining and Supply	*581*	560		*756*	954

Marketing	*108*	85		*174*	189

Cash flow from operations⁽³⁾	885	816		1 289	1 502

(1): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(2): After-tax gain related to the sale of the company's share of certain assets and liabilities of Pioneer Energy in the Refining and Marketing segment.
(3): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Refining and Supply reported operating earnings of $581 million in the second quarter of 2016, compared to $560 million in the prior year quarter. The increase in the second quarter of 2016 is due to stronger refined product location differentials and a larger FIFO gain, reflecting rising prices for crude oil and finished products, partially offset by lower benchmark crack spreads, the impact of narrower inland crude differentials and lower refinery production.

Marketing activities contributed $108 million to operating earnings in the second quarter of 2016, compared to $85 million in the prior year quarter, primarily due to higher retail sales volumes in Eastern North America and improved lubricant margins on the rising price environment for crude oil and finished products, partially offset by lower retail volumes in Western Canada and lower overall wholesale volumes and margins.

Suncor has commenced a sale process for its lubricants business and anticipates that a sale could occur within the next twelve months.


	Three months ended June 30		Six months ended June 30
	2016	2015	2016	2015

Crude oil processed (mbbls/d)

Eastern North America	181.7	211.6	196.9	212.0

Western North America	218.5	205.2	213.6	214.6

Total	400.2	416.8	410.5	426.6

Refinery utilization⁽¹⁾ (%)

Eastern North America	82	95	89	96

Western North America	91	86	89	89

Total	87	90	89	92

Refined product sales (mbbls/d)

Gasoline	251.3	248.5	240.6	243.2

Distillate	190.0	192.5	181.1	199.3

Other	91.2	84.5	89.3	80.2

Total	532.5	525.5	511.0	522.7

Refining gross margin⁽²⁾ ($/bbl)	21.65	21.10	20.35	24.85

Refining operating expense⁽²⁾ ($/bbl)	5.40	5.20	5.25	5.30

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

Refinery crude throughput decreased in the second quarter of 2016, resulting in an average refinery utilization of 87%, compared to 90% in the prior year quarter. In Eastern North America, the average volume of crude oil processed decreased to 181,700 bbls/d in the second quarter of 2016 from 211,600 bbls/d in the prior year quarter, reflecting planned maintenance at the Sarnia and Montreal refineries in the second quarter of 2016. The average volume of crude oil processed in Western North America increased to 218,500 bbls/d in the second quarter of 2016 from 205,200 bbls/d in the prior year quarter due to fewer planned maintenance activities. Significant maintenance performed at the Edmonton refinery in the second quarter of 2015 had a greater impact on crude throughput than the planned maintenance at the Commerce City refinery in the second quarter of 2016. Throughput at the Edmonton refinery was impacted by constrained crude supply due to the forest fires in the Fort McMurray region and an unplanned outage in the period, causing temporary fuel shortages at some Petro-Canada stations in Western Canada.

Total sales increased to 532,500 bbls/d in the second quarter of 2016, compared to 525,500 bbls/d in the prior year quarter, primarily due to solid demand in Eastern Canada and higher exports, partially offset by the impact of the forest fires and weaker demand in Western Canada.

Refined product margins in Refining and Supply were higher in the second quarter of 2016 than in the prior year quarter, and were impacted primarily by the following factors:

Marketing margins in the second quarter of 2016 were higher than margins in the prior year quarter, primarily due to higher retail and lubricant margins on increasing crude oil and product prices.

Operating expenses were lower in the second quarter of 2016 compared to the prior year quarter, primarily due to lower energy costs in Western Canada, reflecting lower natural gas and electricity prices and lower transportation expense.

For the first six months of 2016, Refining and Marketing segment operating earnings were $930 million, compared to operating earnings of $1.143 billion for the first six months of 2015. The decrease in earnings was due primarily to lower benchmark crack spreads and lower refinery throughput resulting from greater planned maintenance activity and weaker demand in Western Canada. These factors were partially offset by higher refined product location differentials, decreased operating expenses, including lower energy costs, and the positive impact of the weaker Canadian dollar. For the first six months of 2016, the impact of the FIFO method of inventory valuation, as used by the company, relative to an estimated LIFO⁽¹⁾ method, had a positive impact to operating earnings and cash flow from operations of approximately $83 million after-tax, compared to approximately $65 million after-tax in the first six months of 2015.

Cash flow from operations was $1.289 billion for the first six months of 2016, compared to $1.502 billion for the first six months of 2015, and decreased primarily due to the same factors that influenced operating earnings.

The Montreal refinery has a seven-week planned maintenance event scheduled to begin in the third quarter of 2016, and the Sarnia refinery has a six-week planned maintenance event scheduled to begin in the third quarter of 2016. The impact of this maintenance has been reflected in the company's 2016 guidance.

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


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Net (loss) earnings	(387	)	52		187		(1 103	)

Adjusted for:

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	27		(178	)	(858	)	762

Non-cash mark to market loss on interest rate swaps⁽¹⁾	70		—		160		—

Non-cash loss on early payment of long-term debt⁽²⁾	73		—		73		—

COS acquisition and related costs⁽³⁾	—		—		38		—

Restructuring charges⁽⁴⁾	—		—		—		57

Impact of income tax rate adjustments on deferred taxes⁽⁵⁾	—		(5	)	—		(5	)

Operating (loss) earnings⁽⁶⁾	(217	)	(131	)	(400	)	(289	)

Renewable Energy	3		1		13		9

Energy Trading	(6	)	(20	)	(8	)	37

Corporate	*(183*	)	(78	)	*(409*	)	(335	)

Eliminations	*(31*	)	(34	)	4		—

Cash flow used in operations⁽⁶⁾	(69	)	(146	)	(315	)	(331	)

(1): Non-cash loss on interest rate swaps resulting from a decrease in long-term interest rates and unfavourable foreign exchange.
(2): Charges associated with early repayment of debt.
(3): Transaction and related charges associated with the acquisition of COS.
(4): Restructuring charges related to the cost reduction initiatives.
(5): Adjustment to the company's deferred income taxes resulting from a 2% increase in the Alberta corporate income tax rate in the second quarter of 2015.
(6): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Renewable Energy had operating earnings of $3 million in the second quarter of 2016, as compared to $1 million in the prior year quarter. The increase was due to the impact of the Cedar Point wind project, which began production subsequent to the second quarter of 2015, partially offset by the disposal of Suncor's interest in the Wintering Hills and Kent Breeze wind projects in the third quarter of 2015.

Energy Trading had an operating loss of $6 million in the quarter, compared to an operating loss of $20 million in the prior year quarter. Narrow crude location differentials resulted in a trading loss in the second quarters of both 2016 and 2015, with 2016 receiving some benefit from inventory strategies and natural gas price movements.

The Corporate operating loss increased to $183 million for the second quarter of 2016, compared with $78 million for the prior year quarter, primarily as a result of a gain on interest rate swaps recorded in the second quarter of 2015. The increased loss in the current period quarter was also due to higher interest expense associated with the acquisition of COS debt in the first quarter of 2016, fire evacuation costs and higher stock-based compensation expense in 2016, partially offset by higher capitalized interest. The company capitalized $140 million of its borrowing costs in the second quarter of 2016 as part of the cost of major development assets and construction projects in progress, compared to $110 million in the prior year quarter.

Eliminations reflect the elimination of profit on crude oil sales from Oil Sands and East Coast Canada to Refining and Marketing. 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 2016, the company eliminated $31 million of after-tax intersegment profit, compared to $34 million of profit that was eliminated in the prior year quarter.

The operating loss for Corporate, Energy Trading and Eliminations for the first six months of 2016 was $400 million, compared to an operating loss of $289 million for the first six months of 2015. The operating loss was impacted by the same factors described above and also includes the impact of gains on crude trading strategies as a result of wider crude differentials in the first quarter of 2015. The company capitalized $281 million of its borrowing costs in the first six months of 2016 as part of the cost of major development assets and construction projects, compared with $203 million of capitalized borrowing costs in the first six months of 2015, with the increase due to higher accumulated expenditures on major growth projects.


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Oil Sands	1 254		985		2 361		1 778

Exploration and Production	275		396		546		752

Refining and Marketing	231		172		403		256

Corporate, Energy Trading and Eliminations	1		22		7		115

Total capital and exploration expenditures	1 761		1 575		3 317		2 901

Less: capitalized interest on debt	(140	)	(110	)	(281	)	(203	)

	1 621		1 465		3 036		2 698


	Three months ended June 30, 2016			Six months ended June 30, 2016
($ millions)	Sustaining	Growth	Total	Sustaining	Growth	Total

Oil Sands

Oil Sands Base	372	103	*475*	575	213	*788*

In Situ	24	4	28	79	18	97

Oil Sands ventures	122	525	*647*	162	1 111	*1 273*

Exploration and Production	3	236	239	5	468	473

Refining and Marketing	230	1	231	396	3	399

Corporate, Energy Trading and Eliminations	1	—	1	6	—	6

	752	869	1 621	1 223	1 813	3 036

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

In the second quarter of 2016, total capital and exploration expenditures were $1.621 billion (excluding capitalized interest). Capital and exploration expenditures in the second quarter of 2016 increased relative to the prior year quarter due to an increased ownership interest in both Fort Hills and Syncrude being partially offset by cost reduction initiatives and lower spending in E&P due to a decrease in development drilling. Activity in the second quarter of 2016 is summarized by business unit below.

Oil Sands Base capital and exploration expenditures were $475 million in the second quarter of 2016, of which $372 million and $103 million were directed towards sustaining and growth activities, respectively. Sustaining capital included expenditures related to the planned maintenance programs, including a turnaround of certain Upgrader 2 assets that was completed during the second quarter of 2016, and a number of reliability and sustainment projects across the operations.

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

In Situ capital and exploration expenditures were $28 million, of which $24 million was primarily directed towards sustaining capital, which included ongoing well pad construction that is expected to maintain existing production levels at Firebag and MacKay River.

Oil Sands ventures capital and exploration expenditures were $647 million, of which growth capital expenditures were $525 million and sustaining capital expenditures were $122 million. Growth capital expenditures were incurred primarily for the Fort Hills mining project, which resumed construction activities in the second quarter of 2016 after delays experienced due to the forest fires in the Fort McMurray area. The company is still targeting first oil at the end of 2017 and is currently assessing and making plans to mitigate the impact of this interruption on the project. The Fort Hills mining project is more than 60% complete at June 30, 2016, with the majority of the remaining work to be completed

in Canada. Spending in the quarter included module fabrication for secondary extraction and utilities as well as procurement of equipment for mining and secondary extraction.

Sustaining capital consisted of Suncor's share of capital expenditures for the Syncrude joint venture, which increased in the period as a result of the acquisitions of COS and Murphy's 5% interest in Syncrude, and included expenditures on several reliability and sustainment projects, including a planned coker turnaround. Sustaining capital also included advancement of certain early-works sustaining activities at Fort Hills that are expected to optimize the mine plan following the commencement of production.

E&P capital and exploration expenditures were $239 million, with the majority of spending directed towards growth capital, including the advancement of the Hebron project, with the utility process module shipped from its construction site in South Korea on schedule, a major milestone. The project remains on schedule with first oil expected in late 2017. Growth capital also included development drilling at Hibernia, White Rose and Golden Eagle. Exploration drilling at the deepwater Shelburne Basin offshore Nova Scotia resumed late in the second quarter of 2016 following an operational delay.

Refining and Marketing capital expenditures were $231 million and are primarily related to planned maintenance activities at the Sarnia, Montreal and Commerce City refineries and a crude pipeline replacement project which supplies feedstock to the Commerce City refinery.

Corporate capital expenditures were $1 million, with the majority of the spending directed towards the company's information technology initiatives.


	Twelve months ended June 30
	2016		2015

Return on Capital Employed⁽¹⁾ (%)

Excluding major projects in progress	(4.9	)	7.2

Including major projects in progress	(4.1	)	6.3

Net debt to cash flow from operations⁽²⁾ (times)	3.0		1.2

Interest coverage on long-term debt (times)

Earnings basis⁽³⁾	(3.6	)	3.7

Cash flow from operations basis⁽²⁾⁽⁴⁾	5.6		11.3

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

Suncor's capital resources consist primarily of cash flow provided by operating activities, cash and cash equivalents, and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2016 capital spending program of $6.0 to $6.5 billion, which includes the company's increased working interest in Syncrude as a result of the acquisitions of COS and Murphy's 5% interest in Syncrude, and to meet current, future and acquired working capital requirements through cash balances and cash equivalents, cash flow provided by operating

activities for the remainder of 2016, available committed credit facilities, issuing commercial paper and accessing capital markets. The company's cash flow provided by operating activities depends on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates.

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

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 $3.008 billion during the six months of 2016 from $4.049 billion at December 31, 2015, primarily due to capital and exploration expenditures exceeding cash flow provided by operating activities, the acquisition of Murphy's 5% interest in Syncrude for $946 million and an early payment of $891 million (US$688 million principal value) of bonds and repayment of $600 million of bank debt acquired as part of the COS acquisition, partially offset by the $2.8 billion (net) common share equity offering completed in the second quarter of 2016 and increases to short-term borrowings.

The early payment of high cost borrowings is expected to provide ongoing balance sheet flexibility and reduce long-term financing costs.

As at June 30, 2016, the weighted average term to maturity of the short-term investment portfolio was approximately eight days.

Available lines of credit at June 30, 2016 decreased to $5.762 billion, compared to $7.034 billion at December 31, 2015, primarily as a result of increased short-term borrowings, foreign exchange impacts on available credit facilities and increased letters of credit, partially offset by net available credit facilities added through the acquisition of COS.

Balance sheet management continues to be a priority for Suncor given the company's long-term growth plans and 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, 2016, total debt to total debt plus shareholders' equity was 28.3% (December 31, 2015 – 28.2%). The company is currently in compliance with all operating covenants.


($ millions, except as noted)	June 30 2016	December 31 2015

Short-term debt	2 638	747

Current portion of long-term debt	72	70

Long-term debt	14 843	14 486

Total debt	17 553	15 303

Less: Cash and cash equivalents	3 008	4 049

Net debt	14 545	11 254

Shareholders' equity	44 453	39 039

Total debt plus shareholders' equity	62 006	54 342

Total debt to total debt plus shareholders' equity (%)	28.3	28.2


	Three and six months ended June 30, 2016
($ millions)	Q2		YTD

Net debt – start of period	14 880		11 254

(Decrease) increase in net debt	(335	)	3 291

Net debt – June 30, 2016	14 545		14 545

Decrease (increase) in net debt

Cash flow from operations	916		1 598

Capital and exploration expenditures and other investments	(1 761	)	(3 317	)

Acquisitions	(946	)	(946	)

Cash acquired, COS	—		109

Debt acquired, COS	—		(2 639	)

Proceeds from disposal of assets	33		192

Change in non-cash working capital	(95	)	(855	)

Dividends less proceeds from exercise of share options	(453	)	(899	)

Issuance of common shares	2 782		2 782

Foreign exchange on cash, debt and other balances	(141	)	684

	335		(3 291	)

As at July 25, 2016, the total number of common shares outstanding was 1,664,457,972 and the total number of exercisable and non-exercisable common share options outstanding was 35,042,512. Once exercisable, each outstanding common share option is convertible into one common share.

During the second quarter of 2016, the company issued 82.2 million common shares for $35.00 per common share as part of a common share offering for net proceeds of $2.8 billion.

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

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments. Suncor has included these items in the Financial Condition and Liquidity section of its 2015 annual MD&A. The company does not believe that it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company's financial performance or financial condition, results of operations, liquidity or capital expenditures.

During the six months ended June 30, 2016, the company increased its commitments by approximately $7.7 billion (undiscounted), which is primarily attributable to the acquisition of COS and Murphy's 5% Syncrude ownership, partially offset by the early payment of long-term debt. The details are outlined below.

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

Trends in Suncor's quarterly earnings and cash flow from operations are driven primarily by production volumes, which can be significantly impacted by major maintenance events. Trends in Suncor's quarterly earnings and cash flow from operations are also affected by changes in commodity prices, refining crack spreads, foreign exchange rates and other significant events impacting operations, such as the forest fires in the Fort McMurray area in the second quarter of 2016.


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

Total production (mboe/d)

Oil Sands	213.1		565.8		470.6		458.4		448.7	475.6		419.3		441.1

Exploration and Production	117.6		125.6		112.3		107.7		111.2	126.8		138.3		78.2

	330.7		691.4		582.9		566.1		559.9	602.4		557.6		519.3

Revenues and other income

Operating revenues, net of royalties	5 914		5 644		6 499		7 485		8 095	7 129		8 899		10 175

Other (loss) income	(58	)	(67	)	94		72		49	257		192		98

	5 856		5 577		6 593		7 557		8 144	7 386		9 091		10 273

Net (loss) earnings	(735	)	257		(2 007	)	(376	)	729	(341	)	84		919

per common share – basic (dollars)	(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.63

per common share – diluted (dollars)	(0.46	)	0.17		(1.38	)	(0.26	)	0.50	(0.24	)	0.06		0.62

Operating (loss) earnings⁽¹⁾	(565	)	(500	)	(26	)	410		906	175		386		1 306

per common share – basic⁽¹⁾ (dollars)	(0.36	)	(0.33	)	(0.02	)	0.28		0.63	0.12		0.27		0.89

Cash flow from operations⁽¹⁾	916		682		1 294		1 882		2 155	1 475		1 492		2 280

per common share – basic⁽¹⁾ (dollars)	0.58		0.45		0.90		1.30		1.49	1.02		1.03		1.56

ROCE⁽¹⁾ (%) for the twelve months ended	(4.9	)	(2.2	)	0.6		5.1		7.2	5.8		8.6		9.4

After-tax unrealized foreign exchange (loss) gain on U.S. dollar denominated debt	(27	)	885		(382	)	(786	)	178	(940	)	(302	)	(394	)

Common share information (dollars)

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

Share price at the end of trading

Toronto Stock Exchange (Cdn$)	35.84		36.17		35.72		35.69		34.40	37.01		36.90		40.53

New York Stock Exchange (US$)	27.73		27.81		25.80		26.72		27.52	29.25		31.78		36.15

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


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

WTI crude oil at Cushing	US$/bbl	45.60	33.50	42.15	46.45	57.95	48.65	73.15	97.20

Dated Brent crude oil at Sullom Voe	US$/bbl	45.60	33.90	43.70	50.30	61.95	53.85	76.25	101.90

Dated Brent/Maya FOB price differential	US$/bbl	7.65	8.95	10.35	8.50	8.15	11.05	10.05	12.50

MSW at Edmonton	Cdn$/bbl	55.80	34.50	53.55	52.35	68.05	52.25	75.95	97.45

WCS at Hardisty	US$/bbl	32.30	19.30	27.70	33.25	46.35	33.90	58.90	77.00

Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	13.30	14.25	14.50	13.20	11.60	14.75	14.25	20.20

Condensate at Edmonton	US$/bbl	44.10	34.45	41.65	44.20	57.95	45.60	70.55	93.45

Natural gas (Alberta spot) at AECO	Cdn$/mcf	1.40	1.85	2.45	2.90	2.55	2.75	3.60	4.00

Alberta Power Pool Price	Cdn$/MWh	14.90	18.10	21.20	26.05	57.25	29.15	30.55	63.90

New York Harbor 3-2-1 crack⁽¹⁾	US$/bbl	16.10	11.75	13.60	22.25	23.85	19.20	16.15	20.50

Chicago 3-2-1 crack⁽¹⁾	US$/bbl	16.65	9.10	13.90	23.95	20.30	16.00	14.40	17.50

Portland 3-2-1 crack⁽¹⁾	US$/bbl	19.30	13.00	17.90	28.75	32.55	21.50	12.45	24.60

Gulf Coast 3-2-1 crack⁽¹⁾	US$/bbl	14.85	11.05	11.05	21.55	22.90	18.00	10.15	19.10

Exchange rate	US$/Cdn$	0.78	0.73	0.75	0.76	0.81	0.81	0.88	0.92

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

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

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

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

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

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates, and to optimize the company's position with respect to interest payments. The company also uses physical and financial energy derivatives to earn trading profits. For more information on Suncor's financial instruments and the related financial risk factors, see note 26 of the audited Consolidated Financial Statements for the year ended December 31, 2015, note 13 to the unaudited interim Consolidated Financial Statements for the three and six months ended June 30, 2016, and the Financial Condition and Liquidity section of Suncor's 2015 annual MD&A.

In the second quarter of 2015, the Government of Alberta enacted an increase in the corporate income tax rate from 10% to 12% effective July 1, 2015. As a result, the company revalued its deferred income tax balances, resulting in a deferred income tax expense of $423 million.

In the first quarter of 2015, the U.K. government enacted a decrease in the supplementary charge rate on oil and gas profits in the North Sea that reduced the statutory tax rate on Suncor's earnings in the U.K. from 62% to 50%. The

company revalued its deferred income tax balances, resulting in a one-time decrease to deferred income taxes of $406 million.

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

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

Based on their evaluation as at June 30, 2016, Suncor's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934, as amended (the Exchange Act)), are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as at June 30, 2016, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the three – and six-month periods ended June 30, 2016 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

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

Suncor has updated its previously issued 2016 corporate guidance, as set forth in Suncor's press releases dated June 6, 2016 and July 27, 2016, which are also available on www.sedar.com.

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

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

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

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

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


For the twelve months ended June 30 ($ millions, except as noted)		2016		2015

Adjustments to net (loss) earnings

Net (loss) earnings		(2 861	)	1 391

Add after-tax amounts for:

Unrealized foreign exchange loss on U.S. dollar denominated debt		311		1 457

Net interest expense		317		286

	A	(2 233	)	3 134

Capital employed – beginning of twelve-month period

Net debt		9 234		6 542

Shareholders' equity		41 615		41 886

		50 849		48 428

Capital employed – end of twelve-month period

Net debt		14 545		9 234

Shareholders' equity		44 453		41 615

		58 998		50 849

Average capital employed	B	54 174		49 795

ROCE – including major projects in progress (%)	A/B	(4.1	)	6.3

Average capitalized costs related to major projects in progress	C	8 611		6 271

ROCE – excluding major projects in progress (%)	A/(B–C)	(4.9	)	7.2

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

Cash flow from (used in) operations in this MD&A for the twelve-month ended periods are the sum of the cash flow from (used in) operations for the particular quarter ended June 30 and each of the three preceding quarters. Cash flow from (used in) operations for each quarter are separately defined and reconciled to GAAP measures in the Non-GAAP Financial Measures Advisory section of each respective MD&A for the applicable quarter.


Three months ended June 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net (loss) earnings	(1 063	)	(44	)	26		44		689		677		(387	)	52		(735	)	729

Adjustments for:

Depreciation, depletion, amortization and impairment	938		760		461		338		172		172		34		35		1 605		1 305

Deferred income taxes	(90	)	361		(191	)	(105	)	32		63		9		2		(240	)	321

Accretion of liabilities	56		35		15		12		2		1		—		(3	)	73		45

Unrealized foreign exchange loss on U.S. dollar denominated debt	—		—		—		—		—		—		29		(181	)	29		(181	)

Change in fair value of financial instruments and trading inventory	1		5		—		—		(11	)	7		140		(76	)	130		(64	)

(Gain) loss on disposal of assets	(32	)	(1	)	—		(6	)	(1	)	(101	)	—		4		(33	)	(104	)

Loss on debt extinguishment	—		—		—		—		—		—		99		—		99		—

Share-based compensation	15		4		—		—		9		1		13		(4	)	37		1

Exploration expenses	—		—		—		149		—		—		—		—		—		149

Settlement of decommissioning and restoration liabilities	(31	)	(64	)	—		—		(6	)	(5	)	1		—		(36	)	(69	)

Other	4		2		(9	)	(5	)	(1	)	1		(7	)	25		(13	)	23

Cash flow from (used in) operations	(202	)	1 058		302		427		885		816		(69	)	(146	)	916		2 155

Decrease (increase) in non-cash working capital	198		(117	)	156		247		234		13		(642	)	(504	)	(54	)	(361	)

Cash flow provided by (used in) operating activities	(4	)	941		458		674		1 119		829		(711	)	(650	)	862		1 794


Six months ended June 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

Net (loss) earnings	(1 587	)	(190	)	(8	)	506		930		1 175		187		(1 103	)	(478	)	388

Adjustments for:

Depreciation, depletion, amortization and impairment	1 855		1 533		817		703		342		337		63		65		3 077		2 638

Deferred income taxes	(126	)	316		(264	)	(550	)	23		35		62		73		(305	)	(126	)

Accretion of liabilities	101		72		32		24		4		3		—		(2	)	137		97

Unrealized foreign exchange (gain) loss on U.S. dollar denominated debt	—		—		—		—		—		—		(892	)	781		(892	)	781

Change in fair value of financial instruments and trading inventory	13		32		—		—		23		78		234		(101	)	270		9

(Gain) loss on disposal of assets	(33	)	7		—		(5	)	(1	)	(101	)	—		(3	)	(34	)	(102	)

Loss on debt extinguishment	—		—		—		—		—		—		99		—		99

Share-based compensation	(36	)	(34	)	2		3		(22	)	(23	)	(70	)	(93	)	(126	)	(147	)

Exploration expenses	—		—		—		198		—		—		—		—		—		198

Settlement of decommissioning and restoration liabilities	(150	)	(194	)	—		(1	)	(8	)	(7	)	—		—		(158	)	(202	)

Other	24		41		(16	)	(2	)	(2	)	5		2		52		8		96

Cash flow from (used in) operations	61		1 583		563		876		1 289		1 502		(315	)	(331	)	1 598		3 630

(Increase) decrease in non-cash working capital	(98	)	(424	)	(40	)	264		200		(275	)	(750	)	(525	)	(688	)	(960	)

Cash flow provided by (used in) operating activities	(37	)	1 159		523		1 140		1 489		1 227		(1 065	)	(856	)	910		2 670

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

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

Oil Sands operations cash operating costs and cash operating costs per barrel are also adjusted for i) costs pertaining to Syncrude operations; ii) non-production costs that management believes do not relate to the production performance of Oil Sands operations, including, but not limited to, share-based compensation adjustments, research, and the expense recorded as part of a non-monetary arrangement involving a third-party processor; iii) revenues associated with excess capacity, including excess power generated and sold that is recorded in operating revenues; and iv) project start-up costs.

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

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

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

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


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

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

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

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

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

Factors that affect our Refining and Marketing segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; our ability to reliably operate refining and marketing facilities in order to meet production or sales targets; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period; and the potential for disruptions to operations and construction projects as a result of our relationships with labour unions or employee associations that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and

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

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

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)	2016		2015		2016		2015

Revenues and Other Income

Operating revenues, net of royalties (note 3)	5 914		8 095		11 558		15 224

Other (loss) income (note 7)	(58	)	49		(125	)	306

	5 856		8 144		11 433		15 530

Expenses

Purchases of crude oil and products	2 672		3 061		4 741		5 833

Operating, selling and general	2 053		2 036		4 402		4 331

Transportation	242		245		531		512

Depreciation, depletion, amortization and impairment	1 605		1 305		3 077		2 638

Exploration	16		173		57		356

Gain on disposal of assets	(33	)	(104	)	(34	)	(102	)

Financing expenses (income) (note 9)	343		(30	)	(375	)	1 108

	6 898		6 686		12 399		14 676

(Loss) Earnings before Income Taxes	(1 042	)	1 458		(966	)	854

Income Taxes (note 10)

Current	(67	)	408		(183	)	592

Deferred	(240	)	321		(305	)	(126	)

	(307	)	729		(488	)	466

Net (Loss) Earnings	(735	)	729		(478	)	388

Net (Loss) Earnings Attributable to:

Common shareholders	(735	)	729		(489	)	388

Non-controlling interest (note 4)	—		—		11		—

	(735	)	729		(478	)	388

Other Comprehensive (Loss) Income

Items reclassified to earnings

Realized gain on disposal of assets available for sale, net of income taxes of $13 (note 17)	—		(85	)	—		(85	)

Items that may be subsequently reclassified to earnings

Foreign currency translation adjustment	(68	)	(6	)	(330	)	380

Items that will not be reclassified to earnings

Actuarial (loss) gain on employee retirement benefit plans, net of income taxes	(40	)	85		(40	)	55

Other Comprehensive (Loss) Income	(108	)	(6	)	(370	)	350

Total Comprehensive (Loss) Income	(843	)	723		(848	)	738

Per Common Share (dollars) (note 11)

Net (loss) earnings – basic and diluted	(0.46	)	0.50		(0.31	)	0.26

Net (loss) earnings – attributable to common shareholders – basic and diluted	(0.46	)	0.50		(0.31	)	0.26

Cash dividends	0.29		0.28		0.58		0.56

See accompanying notes to the interim consolidated financial statements.


($ millions)	June 30 2016 (see note 4)	December 31 2015

Assets

Current assets

Cash and cash equivalents	3 008	4 049

Accounts receivable	2 719	2 751

Inventories	2 930	3 090

Income taxes receivable	797	538

Assets held for sale (note 6)	845	—

Total current assets	10 299	10 428

Property, plant and equipment, net	72 037	61 151

Exploration and evaluation	2 131	1 681

Other assets	1 206	1 153

Goodwill and other intangible assets	3 077	3 079

Deferred income taxes	36	35

Total assets	88 786	77 527

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt	2 638	747

Current portion of long-term debt	72	70

Accounts payable and accrued liabilities	4 850	5 306

Current portion of provisions	812	769

Income taxes payable	225	244

Liabilities associated with assets held for sales (note 6)	188	—

Total current liabilities	8 785	7 136

Long-term debt	14 843	14 486

Other long-term liabilities	2 089	1 573

Provisions (note 16)	7 174	5 339

Deferred income taxes	11 442	9 954

Shareholders' equity	44 453	39 039

Total liabilities and shareholders' equity	88 786	77 527

See accompanying notes to the interim consolidated financial statements.


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Operating Activities

Net (loss) earnings	(735	)	729		(478	)	388

Adjustments for:

Depreciation, depletion, amortization and impairment	1 605		1 305		3 077		2 638

Deferred income taxes	(240	)	321		(305	)	(126	)

Accretion	73		45		137		97

Unrealized foreign exchange loss (gain) on U.S. dollar denominated debt	29		(181	)	(892	)	781

Change in fair value of financial instruments and trading inventory	130		(64	)	270		9

Gain on disposal of assets	(33	)	(104	)	(34	)	(102	)

Loss on extinguishment of long-term debt (note 9)	99		—		99		—

Share-based compensation	37		1		(126	)	(147	)

Exploration	—		149		—		198

Settlement of decommissioning and restoration liabilities	(36	)	(69	)	(158	)	(202	)

Other	(13	)	23		8		96

Increase in non-cash working capital	(54	)	(361	)	(688	)	(960	)

Cash flow provided by operating activities	862		1 794		910		2 670

Investing Activities

Capital and exploration expenditures	(1 761	)	(1 575	)	(3 317	)	(2 901	)

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

Acquisitions (note 5)	(946	)	—		(946	)	—

Proceeds from disposal of assets	33		229		192		269

Other investments	(5	)	(4	)	(7	)	(8	)

(Decrease) Increase in non-cash working capital	(41	)	7		(167	)	(40	)

Cash flow used in investing activities	(2 720	)	(1 343	)	(4 136	)	(2 680	)

Financing Activities

Net change in short-term debt	991		(8	)	1 955		56

Net change in long-term debt	(1 578	)	2		(1 542	)	(4	)

Issuance of common shares under share option plans	5		15		12		49

Issuance of common shares (note 12)	2 782		—		2 782		—

Dividends paid on common shares	(458	)	(405	)	(911	)	(810	)

Cash flow provided by (used in) financing activities	1 742		(396	)	2 296		(709	)

(Decrease) Increase in Cash and Cash Equivalents	(116	)	55		(930	)	(719	)

Effect of foreign exchange on cash and cash equivalents	(10	)	12		(111	)	116

Cash and cash equivalents at beginning of period	3 134		4 825		4 049		5 495

Cash and Cash Equivalents at End of Period	3 008		4 892		3 008		4 892

Supplementary Cash Flow Information

Interest paid	428		348		514		424

Income taxes (received) paid	(141	)	210		(10	)	1 002

See accompanying notes to the interim consolidated financial statements.


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

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

Net earnings	—	—		—		—		388		388		—

Foreign currency translation adjustment	—	—		380		—		—		380		—

Realized gain on disposal of assets available for sale, net of income taxes of $13 (note 17)	—	—		(85	)	—		—		(85	)	—

Actuarial gain on employee retirement benefit plans, net of income taxes of $21	—	—		—		—		55		55		—

Total comprehensive income	—	—		295		—		443		738		—

Issued under share option plans	63	(7	)	—		—		—		56		1 646

Issued under dividend reinvestment plan	19	—		—		—		(19	)	—		—

Share-based compensation		28		—		—		—		28		—

Dividends paid on common shares	—	—		—		—		(810	)	(810	)	—

At June 30, 2015	19 393	630		799		—		20 793		41 615		1 445 765



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

Net earnings (loss)	—	—				11		(489	)	(478	)	—

Foreign currency translation adjustment	—	—		(330	)	—		—		(330	)	—

Actuarial loss on employee retirement benefit plans, net of income taxes of $13	—	—		—		—		(40	)	(40	)	—

Total comprehensive (loss) income	—	—		(330	)	11		(529	)	(848	)	—

Issued under share option plans	17	(2	)	—		—		—		15		450

Issued for cash, net of income taxes of $26 (note 12)	2 808	—		—		—		—		2 808		82 225

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

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

Share-based compensation	—	24		—		—		—		24		—

Dividends paid on common shares	—	—		—		—		(911	)	(911	)	—

At June 30, 2016	26 743	655		935		—		16 120		44 453		1 664 381

See accompanying notes to the interim consolidated financial statements.

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

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

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

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

Comparative figures have been reclassified to conform to the current year financial statement presentation for the revenues and expenses for the company's ethanol business that is presented in the Refining and Marketing segment, and was previously presented in Corporate, Energy Trading and Eliminations. The reclassification resulted in an increase in net earnings for the Refining and Marketing segment and a decrease for Corporate, Energy Trading and Eliminations of $14 million for the three months ended June 30, 2015, $20 million for the six months ended June 30, 2015 and $40 million for the year ended December 31, 2015.

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

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

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

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

Assets and liabilities are classified as held for sale if their carrying amounts are expected to be recovered through a disposition rather than through continuing use. The assets or disposal groups are measured at the lower of their carrying amount and estimated fair value less costs of disposal. Impairment losses on initial classification as well as subsequent gains or losses on remeasurement are recognized in Depreciation, Depletion, Amortization and Impairment. When the assets or disposal groups are sold, the gains or losses on the sale are recognized in Gain (loss) on disposal of assets. Assets classified as held for sale are not depreciated, depleted or amortized.

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, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	810		2 204		595		729		4 538		5 229		25		67		5 968		8 229

Intersegment revenues	350		555		29		51		52		1		(431	)	(607	)	—		—

Less: Royalties	(9	)	(38	)	(45	)	(96	)	—		—		—		—		(54	)	(134	)

Operating revenues, net of royalties	1 151		2 721		579		684		4 590		5 230		(406	)	(540	)	5 914		8 095

Other (loss) income	(18	)	(13	)	36		(4	)	2		(17	)	(78	)	83		(58	)	49

	1 133		2 708		615		680		4 592		5 213		(484	)	(457	)	5 856		8 144

Expenses

Purchases of crude oil and products	172		53		—		1		2 869		3 513		(369	)	(506	)	2 672		3 061

Operating, selling and general	1 288		1 285		116		129		526		527		123		95		2 053		2 036

Transportation	146		141		22		24		84		90		(10	)	(10	)	242		245

Depreciation, depletion, amortization and impairment	938		760		461		338		172		172		34		35		1 605		1 305

Exploration	—		4		16		169		—		—		—		—		16		173

(Gain) loss on disposal of assets	(32	)	(1	)	—		(6	)	(1	)	(101	)	—		4		(33	)	(104	)

Financing expenses (income)	64		39		35		(4	)	1		—		243		(65	)	343		(30	)

	2 576		2 281		650		651		3 651		4 201		21		(447	)	6 898		6 686

(Loss) Earnings before Income Taxes	(1 443	)	427		(35	)	29		941		1 012		(505	)	(10	)	(1 042	)	1 458

Income Taxes

Current	(290	)	110		130		90		220		272		(127	)	(64	)	(67	)	408

Deferred	(90	)	361		(191	)	(105	)	32		63		9		2		(240	)	321

	(380	)	471		(61	)	(15	)	252		335		(118	)	(62	)	(307	)	729

Net (Loss) Earnings	(1 063	)	(44	)	26		44		689		677		(387	)	52		(735	)	729

Capital and Exploration Expenditures	1 254		985		275		396		229		172		3		22		1 761		1 575


Six months ended June 30	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2016		2015		2016		2015		2016		2015		2016		2015		2016		2015

											(Restated)				(Restated)

Revenues and Other Income

Gross revenues	2 395		3 981		1 126		1 461		8 117		10 037		22		23		11 660		15 502

Intersegment revenues	804		1 062		29		88		64		23		(897	)	(1 173	)	—		—

Less: Royalties	(28	)	(56	)	(74	)	(222	)	—		—		—		—		(102	)	(278	)

Operating revenues, net of royalties	3 171		4 987		1 081		1 327		8 181		10 060		(875	)	(1 150	)	11 558		15 224

Other income (loss)	15		45		38		112		13		4		(191	)	145		(125	)	306

	3 186		5 032		1 119		1 439		8 194		10 064		(1 066	)	(1 005	)	11 433		15 530

Expenses

Purchases of crude oil and products	312		123		—		2		5 325		6 860		(896	)	(1 152	)	4 741		5 833

Operating, selling and general	2 723		2 657		261		260		1 068		1 097		350		317		4 402		4 331

Transportation	330		293		45		51		176		189		(20	)	(21	)	531		512

Depreciation, depletion, amortization and impairment	1 855		1 533		817		703		342		337		63		65		3 077		2 638

Exploration	30		109		27		247		—		—		—		—		57		356

(Gain) loss on disposal of assets	(33	)	7		—		(5	)	(1	)	(101	)	—		(3	)	(34	)	(102	)

Financing expenses (income)	119		78		50		34		12		(7	)	(556	)	1 003		(375	)	1 108

	5 336		4 800		1 200		1 292		6 922		8 375		(1 059	)	209		12 399		14 676

(Loss) Earnings before Income Taxes	(2 150	)	232		(81	)	147		1 272		1 689		(7	)	(1 214	)	(966	)	854

Income Taxes

Current	(437	)	106		191		191		319		479		(256	)	(184	)	(183	)	592

Deferred	(126	)	316		(264	)	(550	)	23		35		62		73		(305	)	(126	)

	(563	)	422		(73	)	(359	)	342		514		(194	)	(111	)	(488	)	466

Net (Loss) Earnings	(1 587	)	(190	)	(8	)	506		930		1 175		187		(1 103	)	(478	)	388

Capital and Exploration Expenditures	2 361		1 778		546		752		401		256		9		115		3 317		2 901

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

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

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

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


($ millions)

Cash	109

Accounts receivable	231

Inventory	135

Other assets	105

Property, plant and equipment	9 476

Exploration and evaluation	602

Total assets acquired	10 658

Accounts payable and other liabilities	(375	)

Long-term debt	(2 639	)

Employee future benefits	(323	)

Decommissioning provision	(1 169	)

Deferred income taxes	(1 826	)

Total liabilities assumed	(6 332	)

Net assets of COS	4 326

Non-controlling interest	(1 172	)

Net assets acquired	3 154

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


($ millions)		February 5, 2016

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

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

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

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

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

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

Total Notes		2 089

Credit facility		550

Total long-term debt		2 639

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

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

Acquisition costs of $29 million have been charged to Operating, Selling and General expense in the consolidated statements of comprehensive income for the six month period ended June 30, 2016.

COS contributed $489 million to gross revenues and $226 million to consolidated net losses from the acquisition date to June 30, 2016.

Had the acquisition occurred on January 1, 2016, COS would have contributed $671 million to gross revenues and $263 million to consolidated net losses, which would have resulted in gross revenues of $12.3 billion and consolidated net loss of $741 million for the six months ended June 30, 2016.

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

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


($ millions)

Accounts receivable	8

Inventory	19

Property, plant and equipment	1 330

Exploration and evaluation	82

Total assets acquired	1 439

Accounts payable and other liabilities	(29	)

Employee future benefits	(49	)

Decommissioning provision	(187	)

Deferred income taxes	(228	)

Total liabilities assumed	(493	)

Net assets acquired	946

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

The additional interest in Syncrude contributed $3 million to gross revenues and nil to consolidated net earnings from the acquisition date to June 30, 2016.

Had the acquisition occurred on January 1, 2016, the additional interest would have contributed $88 million to gross revenues and $38 million to consolidated net loss, which would have resulted in gross revenues of $11.7 billion and consolidated net loss of $516 million for the six months ended June 30, 2016.

As at June 30, 2016, the company has reclassified the assets and liabilities related to its lubricants plant and associated infrastructure as assets held for sale. Suncor has commenced a sale process for the lubricants business and anticipates that a sale could occur within the next twelve months. The lubricants business is reported within the Refining and Marketing segment.

The table below details the assets and liabilities held for sale as at June 30, 2016:


($ millions)

Assets

Accounts Receivable		179

Prepaids		2

Inventories		242

Income taxes receivable		18

Property, plant & equipment, net		404

Total assets		845

Liabilities

Accounts payable and accrued liabilities		83

Pension liability		51

Deferred income taxes		54

Total liabilities		188


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Energy trading activities

Unrealized gains (losses) recognized in earnings during the period	6		(7	)	(18	)	—

(Losses) gains on inventory valuation	(13	)	(11	)	17		64

Risk management activities⁽¹⁾	(131	)	38		(230	)	46

Investment and interest income	30		24		48		42

Renewable energy grants	11		9		11		14

Risk mitigation and insurance proceeds⁽²⁾	26		—		26		104

Change in value of pipeline commitments and other	13		(4	)	21		36

	(58	)	49		(125	)	306

(1): Includes fair value changes related to short-term derivative contracts in the Oil Sands and Refining and Marketing segments and long-term forward starting interest rate swaps in the Corporate segment.
(2): Includes property damage insurance proceeds recorded in the second quarter of 2016 and business interruption proceeds recorded in the first quarter of 2015. The proceeds recorded in both quarters were for the Terra Nova asset in the Exploration and Production segment.

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


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Interest on debt	256		214		510		424

Capitalized interest	(140	)	(110	)	(281	)	(203	)

Interest expense	116		104		229		221

Interest on pension and other post-retirement benefits	15		11		27		26

Accretion	73		45		137		97

Foreign exchange loss (gain) on U.S. dollar denominated debt	29		(181	)	(892	)	781

Foreign exchange and other	11		(9	)	25		(17	)

Loss on extinguishment of long-term debt	99		—		99		—

	343		(30	)	(375	)	1 108

During the quarter, the company purchased US$688 million ($891 million) principal value (book value of $864 million) of subsidiary debt acquired through the acquisition of COS (note 4) for US$751 million ($973 million) including US$8 million ($10 million) of accrued interest, resulting in a debt extinguishment loss of $99 million. The company also repaid approximately $600 million of the credit facility acquired in the COS transaction.

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


	Three months ended June 30				Six months ended June 30
($ millions)	2016		2015		2016		2015

Net (loss) earnings	(735	)	729		(478	)	388

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	—		(4	)	—		(3	)

Net (loss) earnings – diluted	(735	)	725		(478	)	385

Net (loss) earnings attributable to common shareholders	(735	)	729		(489	)	388

Dilutive impact of accounting for awards as equity-settled⁽¹⁾	—		(4	)	—		(3	)

Net (loss) earnings – diluted attributable to common shareholders	(735	)	725		(489	)	385

(millions of common shares)

Weighted average number of common shares	1 590		1 446		1 553		1 445

Dilutive securities:

Effect of share options	2		1		1		2

Weighted average number of diluted common shares	1 592		1 447		1 554		1 447

(dollars per common share)

Basic and diluted (loss) earnings per share	(0.46	)	0.50		(0.31	)	0.26

Basic and diluted (loss) earnings per share attributable to common shareholders	(0.46	)	0.50		(0.31	)	0.26

(1): Cash payment alternatives are accounted for as cash-settled plans. As these awards can be exchanged for common shares of the company, they are considered potentially dilutive and are included in the calculation of the company's diluted net (loss) earnings per share if they have a dilutive impact in the period. Accounting for these awards as equity-settled was determined to have a dilutive impact for the three and six months ended June 30, 2015.

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

The following table presents the company's non-designated Energy Trading and Risk Management derivatives measured at fair value as at June 30, 2016.

The following table presents the company's financial instruments measured at fair value for each hierarchy level as at June 30, 2016.

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

The company uses forward starting interest rate swaps to mitigate its exposure to the effect of future interest rate movements on future debt issuances. As at June 30, 2016, the company had executed $1.9 billion in forward swaps. A decrease in interest rates of 0.35% during the quarter resulted in a decrease in value of $97 million associated with the swaps. A decrease in interest rates of 0.86% during the six months ended June 30, 2016 resulted in a decrease in value of $220 million associated with the swaps.

At June 30, 2016, the carrying value of fixed-term debt accounted for under amortized cost was $13.7 billion (December 31, 2015 – $13.3 billion) and the fair value was $15.5 billion (December 31, 2015 – $14.5 billion). The estimated fair value of long-term debt is based on pricing sourced from market data.

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

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

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

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

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

A decrease in the credit-adjusted risk-free interest rate to 3.8% (December 31, 2015 – 4.37%) resulted in an increase in provisions of $507 million for the six months ended June 30, 2016.

During the third quarter of 2014, the company announced that, along with The Pioneer Group Inc., it had reached an agreement to sell the assets of Pioneer Energy, including retail gas stations in Ontario and Manitoba. The company's investment in Pioneer was recorded at fair value and classified as an available for sale financial instrument. The transaction closed in the second quarter of 2015 and the company received $183 million for its 50% share of Pioneer Energy and realized an after-tax gain of $68 million in the Refining and Marketing segment.


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

Revenues and other income	5 856		5 577		6 593		7 557		8 144		11 433		15 530		29 680

Net (loss) earnings

Oil Sands	(1 063	)	(524	)	(616	)	(50	)	(44	)	(1 587	)	(190	)	(856	)

Exploration and Production	26		(34	)	(1 263	)	(1	)	44		(8	)	506		(758	)

Refining and Marketing	689		241		506		625		677		930		1 175		2 306

Corporate, Energy Trading and Eliminations	(387	)	574		(634	)	(950	)	52		187		(1 103	)	(2 687	)

	(735	)	257		(2 007	)	(376	)	729		(478	)	388		(1 995	)

Operating (loss) earnings^(A)

Oil Sands	(1 063	)	(524	)	(230	)	(50	)	315		(1 587	)	169		(111	)

Exploration and Production	26		(34	)	(50	)	(1	)	77		(8	)	58		7

Refining and Marketing	689		241		506		625		645		930		1 143		2 274

Corporate, Energy Trading and Eliminations	(217	)	(183	)	(252	)	(164	)	(131	)	(400	)	(289	)	(705	)

	(565	)	(500	)	(26	)	410		906		(1 065	)	1 081		1 465

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

Oil Sands	(202	)	263		467		785		1 058		61		1 583		2 835

Exploration and Production	302		261		257		253		427		563		876		1 386

Refining and Marketing	885		404		605		814		816		1 289		1 502		2 921

Corporate, Energy Trading and Eliminations	(69	)	(246	)	(35	)	30		(146	)	(315	)	(331	)	(336	)

	916		682		1 294		1 882		2 155		1 598		3 630		6 806

Per common share

Net (loss) earnings basic and diluted	(0.46	)	0.17		(1.38	)	(0.26	)	0.50		(0.31	)	0.26		(1.38	)

Net (loss) earnings attributable to common shareholders – basic and diluted	(0.46	)	0.16		(1.38	)	(0.26	)	0.50		(0.31	)	0.26		(1.38	)

Operating (loss) earnings – basic	(0.36	)	(0.33	)	(0.02	)	0.28		0.63		(0.69	)	0.75		1.01

Cash dividends – basic	0.29		0.29		0.29		0.29		0.28		0.58		0.56		1.14

Cash flow from operations – basic	0.58		0.45		0.90		1.30		1.49		1.03		2.51		4.71


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

Total Production (mbbls/d)	213.1	565.8	470.6	458.4	448.7	389.4	462.1	463.4

Oil Sands operations

Production volumes (mbbls/d)

Upgraded product (sweet SCO, sour SCO & diesel)	86.4	322.3	292.2	314.9	327.4	204.3	336.9	320.1

Non-upgraded bitumen	91.1	130.7	147.5	115.4	96.4	110.9	95.1	113.5

Oil Sands operations production	177.5	453.0	439.7	430.3	423.8	315.2	432.0	433.6

Bitumen production (mbbls/d)

Mining	66.8	302.0	292.4	303.3	315.5	185.4	316.9	307.3

In Situ – Firebag	121.8	199.0	198.8	191.7	168.1	160.4	178.3	186.9

In Situ – MacKay River	13.1	36.8	34.5	27.4	31.5	25.0	30.4	30.7

Total bitumen production	201.7	537.8	525.7	522.4	515.1	370.8	525.6	524.9

Sales (mbbls/d)

Light sweet crude oil	29.0	132.2	100.2	112.9	102.4	80.6	107.5	107.0

Diesel	3.4	24.8	29.4	30.0	35.1	14.1	33.0	31.3

Light sour crude oil	76.3	172.7	154.2	180.7	194.4	124.5	197.8	182.5

Upgraded product (SCO and diesel)	108.7	329.7	283.8	323.6	331.9	219.2	338.3	320.8

Non-upgraded bitumen	108.1	134.5	136.3	106.3	91.8	121.3	93.8	107.7

Sales	216.8	464.2	420.1	429.9	423.7	340.5	432.1	428.5

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

Cash costs	44.55	22.55	25.70	24.95	26.15	28.75	25.95	25.65

Natural gas	2.25	1.70	2.30	2.05	1.85	1.85	2.25	2.20

	46.80	24.25	28.00	27.00	28.00	30.60	28.20	27.85

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

Cash costs	76.65	21.70	25.10	22.65	22.50	31.45	22.55	23.20

Natural gas	1.15	0.50	0.70	0.45	0.45	0.60	0.45	0.55

	77.80	22.20	25.80	23.10	22.95	32.05	23.00	23.75

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

Cash costs	10.75	7.60	8.10	8.80	9.25	8.75	9.60	9.00

Natural gas	2.20	2.80	3.55	3.75	3.80	2.55	3.95	3.80

	12.95	10.40	11.65	12.55	13.05	11.30	13.55	12.80

Syncrude

Production (mbbls/d)	35.6	112.8	30.9	28.1	24.9	74.2	30.1	29.8

Cash operating costs⁽¹⁾ ($/bbl)

Cash costs	111.40	30.25	38.55	39.70	54.45	49.85	42.65	40.35

Natural gas	2.15	1.10	1.60	1.95	1.65	1.35	1.55	1.65

	113.55	31.35	40.15	41.65	56.10	51.20	44.20	42.00

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Bitumen ($/bbl)

Average price realized	23.90		12.00		25.63		33.39		43.11		17.30		36.33		32.18

Royalties	(0.24	)	—		(0.32	)	(0.71	)	(1.17	)	(0.11	)	(0.31	)	(0.41	)

Transportation costs	(5.69	)	(5.57	)	(7.05	)	(6.40	)	(5.48	)	(5.63	)	(5.59	)	(6.26	)

Net operating expenses⁽²⁾	(14.65	)	(9.81	)	(11.32	)	(10.32	)	(12.22	)	(12.01	)	(12.92	)	(11.76	)

Operating netback	3.32		(3.38	)	6.94		15.96		24.24		(0.45	)	17.51		13.75

SCO and diesel ($/bbl)

Average price realized	52.58		43.27		54.39		57.45		70.01		45.58		63.27		59.81

Royalties	(0.33	)	(0.57	)	(0.48	)	(0.91	)	(0.67	)	(0.52	)	(0.61	)	(0.65	)

Transportation costs	(5.07	)	(3.83	)	(3.06	)	(3.95	)	(3.12	)	(4.14	)	(3.20	)	(3.36	)

Net operating expenses⁽²⁾ – bitumen	(50.90	)	(21.98	)	(26.81	)	(24.85	)	(24.48	)	(29.34	)	(24.16	)	(24.91	)

Net operating expenses⁽²⁾ – upgrading	(12.02	)	(5.51	)	(7.02	)	(5.18	)	(5.46	)	(6.90	)	(5.86	)	(5.96	)

Operating netback	(15.74	)	11.38		17.02		22.56		36.28		4.68		29.44		24.93

Average Oil Sands operations ($/bbl)

Average price realized	38.28		34.21		45.05		51.50		64.18		35.50		57.42		52.87

Royalties	(0.29	)	(0.41	)	(0.43	)	(0.86	)	(0.77	)	(0.37	)	(0.54	)	(0.59	)

Transportation costs	(5.38	)	(4.34	)	(4.36	)	(4.55	)	(3.63	)	(4.67	)	(3.72	)	(4.09	)

Net operating expenses⁽²⁾ – bitumen and upgrading	(38.85	)	(22.36	)	(26.53	)	(25.16	)	(26.10	)	(27.61	)	(26.31	)	(26.07	)

Operating netback	(6.24	)	7.10		13.73		20.93		33.68		2.85		26.85		22.12

Syncrude ($/bbl)

Average price realized	59.34		44.93		60.43		61.23		74.03		52.08		62.64		60.28

Royalties	(0.98	)	(0.18	)	2.78		(5.36	)	(3.68	)	(0.37	)	(2.56	)	(1.89	)

Transportation costs	(1.70	)	(0.86	)	(0.60	)	(0.70	)	(0.69	)	(1.06	)	(0.46	)	(0.54	)

Net operating expenses⁽²⁾ – bitumen and upgrading	(102.35	)	(27.75	)	(36.11	)	(35.36	)	(47.29	)	(44.34	)	(37.35	)	(35.69	)

Operating netback	(45.69	)	16.14		26.50		19.81		22.37		6.31		22.27		22.16

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Total Sales Volume (mboe/d)	120.4		133.4		101.4		101.2		111.5		127.0		120.2		110.6

Total Production (mboe/d)	117.6		125.6		112.3		107.7		111.2		121.6		118.9		114.4

Production Volumes

Exploration and Production Canada

East Coast Canada

Terra Nova (mbbls/d)	5.4		12.8		13.1		10.4		7.3		9.0		15.3		13.5

Hibernia (mbbls/d)	24.6		24.1		15.6		16.6		18.3		24.4		20.1		18.1

White Rose (mbbls/d)	11.7		13.7		14.8		9.9		11.4		12.7		12.0		12.2

North America Onshore (mboe/d)	2.7		3.0		3.1		3.7		2.4		2.9		3.0		3.2

	44.4		53.6		46.6		40.6		39.4		49.0		50.4		47.0

Exploration and Production International

Buzzard (mboe/d)	52.7		53.4		45.5		50.0		52.4		53.0		51.9		49.8

Golden Eagle (mboe/d)	20.5		18.6		17.7		17.0		14.5		19.6		12.2		14.8

United Kingdom (mboe/d)	73.2		72.0		63.2		67.0		66.9		72.6		64.1		64.6

Libya (mbbls/d)	—		—		2.5		0.1		4.9		—		4.4		2.8

	73.2		72.0		65.7		67.1		71.8		72.6		68.5		67.4

Netbacks

East Coast Canada ($/bbl)

Average price realized	62.39		46.17		52.51		59.09		78.23		53.19		71.10		65.12

Royalties	(11.06	)	(5.51	)	(5.79	)	(4.39	)	(16.38	)	(7.91	)	(17.10	)	(12.49	)

Transportation costs	(2.05	)	(1.68	)	(2.81	)	(2.97	)	(1.73	)	(1.84	)	(1.74	)	(2.18	)

Operating costs	(14.76	)	(13.72	)	(16.86	)	(17.66	)	(16.63	)	(14.14	)	(12.39	)	(14.15	)

Operating netback	34.52		25.26		27.05		34.07		43.49		29.30		39.87		36.30

United Kingdom ($/boe)

Average price realized	55.43		43.02		54.91		62.86		72.84		49.28		68.87		63.85

Transportation costs	(2.00	)	(1.97	)	(2.22	)	(2.43	)	(2.66	)	(1.98	)	(2.50	)	(2.41	)

Operating costs	(4.68	)	(5.75	)	(6.20	)	(5.99	)	(5.86	)	(5.21	)	(6.50	)	(6.29	)

Operating netback	48.75		35.30		46.49		54.44		64.32		42.09		59.87		55.15

See accompanying footnotes and definitions to the quarterly operating summaries.


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

Refined product sales (mbbls/d)	532.5	489.5	501.2	546.4	525.5	511.0	522.7	523.3

Crude oil processed (mbbls/d)	400.2	420.9	430.2	444.8	416.8	410.5	426.6	432.1

Utilization of refining capacity (%)	87	91	93	96	90	89	92	94

Refining margin ($/bbl)	21.65	19.10	23.20	26.60	21.10	20.35	24.85	24.90

Refining operating expense ($/bbl)	5.40	5.10	4.70	4.70	5.20	5.25	5.30	5.10

Eastern North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	117.8	107.8	116.1	119.1	121.8	112.7	120.2	118.9

Distillate	71.8	75.5	86.2	90.5	91.8	73.7	93.9	91.1

Total transportation fuel sales	189.6	183.3	202.3	209.6	213.6	186.4	214.1	210.0

Petrochemicals	7.7	12.0	8.9	10.4	10.6	9.9	11.9	10.8

Asphalt	15.3	11.9	14.1	18.4	12.0	13.6	9.8	13.1

Other	39.4	35.4	28.2	24.8	31.8	37.4	31.5	28.9

Total refined product sales	252.0	242.6	253.5	263.2	268.0	247.3	267.3	262.8

Crude oil supply and refining

Processed at refineries (mbbls/d)	181.7	212.1	208.0	200.5	211.6	196.9	212.0	208.1

Utilization of refining capacity (%)	82	96	94	90	95	89	96	94

Western North America

Refined product sales (mbbls/d)

Transportation fuels

Gasoline	133.5	122.4	127.7	135.3	126.7	127.9	123.0	127.3

Distillate	118.2	96.6	100.8	115.8	100.7	107.4	105.4	106.9

Total transportation fuel sales	251.7	219.0	228.5	251.1	227.4	235.3	228.4	234.2

Asphalt	11.7	8.7	10.8	13.9	13.9	10.2	11.8	11.9

Other	17.1	19.2	8.4	18.2	16.2	18.2	15.2	14.4

Total refined product sales	280.5	246.9	247.7	283.2	257.5	263.7	255.4	260.5

Crude oil supply and refining

Processed at refineries (mbbls/d)	218.5	208.8	222.2	244.3	205.2	213.6	214.6	224.0

Utilization of refining capacity (%)	91	87	93	102	86	89	89	93

See accompanying footnotes and definitions to the quarterly operating summaries.

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

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

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


	Three months ended June 30		Six months ended June 30
Net of transportation costs, but before royalties	2016	2015	2016	2015

Exploration and Production

E&P Canada – Crude oil and natural gas liquids ($/bbl)	60.30	75.44	51.35	68.39

E&P Canada – Natural gas ($/mcfe)	1.14	2.03	1.26	2.18

E&P International ($/boe)	53.43	70.18	47.30	66.37


(thousands)		June 30, 2016

Common shares		1 664 381

Common share options – exercisable		21 035

Common share options – non-exercisable		14 072


	Twelve months ended June 30
($ millions)	2016		2015

Cash flow from operations	4 774		7 403

Less: Capital and exploration expenditures	7 083		6 608

Free Cash Flow	(2 309	)	795




Number of COS common shares tendered (millions)		353.3

Multiplied by share exchange ratio		0.28

Number of Suncor common shares issued (millions)		98.9

Share price on acquisition date		$31.88

Fair value of consideration ($ millions)		3 154


1.	Advisories	5
2.	Second Quarter Highlights	7
3.	Consolidated Financial Information	8
4.	Segment Results and Analysis	13
5.	Capital Investment Update	25
6.	Financial Condition and Liquidity	27
7.	Quarterly Financial Data	31
8.	Other Items	33
9.	Non-GAAP Financial Measures Advisory	35
10.	Common Abbreviations	39
11.	Forward-Looking Information	40


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

Long-term debt	63	157	410	1 121	1 751

Decommissioning and restoration costs	18	53	78	2 746	2 895

Pipeline commitments	55	110	140	2 423	2 728

Other long-term obligations	107	142	27	49	325

Total	243	462	655	6 339	7 699


($ millions)	Energy Trading		Risk Management		Total

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

Cash Settlements – (received) paid during the period	(13	)	(26	)	(39	)

Unrealized gains (losses) recognized in earnings during the period (note 7)	(18	)	(230	)	(248	)

Fair value outstanding at June 30, 2016	(49	)	(236	)	(285	)


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

Accounts receivable	12		69		—	81

Accounts payable	(78	)	(288	)	—	(366	)

	(66	)	(219	)	—	(285	)


($ millions)

Fair value of Kent Breeze wind farm		47

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

Fair value of deferred financing arrangement		303

Total purchase consideration		427


($ millions)

Working capital	36

Property, plant and equipment	393

Decommissioning provision	(2	)

Net assets acquired	427


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

Return on capital employed^(A)

– excluding major projects in progress (%)	(4.9	)	(2.2	)	0.6	5.1	7.2

– including major projects in progress (%)	(4.1	)	(1.9	)	0.5	4.5	6.3


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