EX-99.2 3 a2213261zex-99_2.htm EX-99.2
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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2012,
dated February 26, 2013

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 26, 2013

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's December 31, 2012 audited Consolidated Financial Statements and the accompanying notes. 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 the Annual Information Form dated March 1, 2013 (the 2012 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 a part of this MD&A, and is not incorporated into this MD&A by reference.

References to "we", "our", "Suncor", or "the company" mean Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements, unless the context requires otherwise.

MD&A – Table of Contents

1.	Advisories	18
2.	2012 Highlights	20
3.	Suncor Overview	22
4.	Consolidated Financial Information	24
5.	Segment Results and Analysis	30
6.	Fourth Quarter 2012 Analysis	44
7.	Quarterly Financial Data	47
8.	Capital Investment Update	50
9.	Financial Condition and Liquidity	54
10.	Accounting Policies and Critical Accounting Estimates	59
11.	Risk Factors	65
12.	Other Items	73
13.	Non-GAAP Financial Measures Advisory	74
14.	Advisory – Forward-Looking Information	79

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 17

1. ADVISORIES

Basis of Presentation

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which is within Part 1 of the Canadian Institute of Chartered Accountants Handbook, which itself is within the framework of International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board.

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

Non-GAAP Financial Measures

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

These non-GAAP financial measures are included because management uses the information to analyze operating 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 and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

Common Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

Measurement

bbl		barrel
bbls/d		barrels per day
mbbls/d or kbpd		thousands of barrels per day

boe		barrels of oil equivalent
boe/d		barrels of oil equivalent per day
mboe		thousands of barrels of oil equivalent
mboe/d		thousands of barrels of oil equivalent per day

mcf		thousands of cubic feet of natural gas
mcfe		thousands of cubic feet of natural gas equivalent
mmcf		millions of cubic feet of natural gas
mmcf/d		millions of cubic feet of natural gas per day
mmcfe		millions of cubic feet of natural gas equivalent
mmcfe/d		millions of cubic feet of natural gas equivalent per day

m³		cubic metres
m³/d		cubic metres per day
MW		megawatts

Places and Currencies

U.S.		United States
U.K.		United Kingdom
B.C.		British Columbia

$ or Cdn$		Canadian dollars
US$		United States dollars
£		Pounds sterling
€		Euros
Financial and Business Environment

DD&A		Depreciation, depletion and amortization

WTI		West Texas Intermediate
WCS		Western Canadian Select
SCO		Synthetic crude oil
NYMEX		New York Mercantile Exchange

18 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Risk Factors and Forward-Looking Information

The company's financial and operational performance is potentially affected by a number of factors, including, but not limited to, the volatility of commodity prices and exchange rate fluctuations; government regulation, including changes to royalty and income tax legislation and the interpretation and implementation thereof; environmental regulation, including changes to climate change and reclamation legislation; risks associated with operating in foreign countries, including geopolitical and other political risks; operating hazards and other uncertainties, including extreme weather conditions, fires, explosions and oil spills; risks associated with the execution of major projects; reputational risk; permit approval; labour and materials supply; and other issues described within the Advisory – 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 subject to a number of risks and uncertainties, including those discussed in this MD&A and Suncor's other disclosure documents, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. Refer to the Advisory – Forward-Looking Information section of this MD&A for information on the material risk factors and assumptions underlying our forward-looking information.

Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe 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, mmcfe, 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 necessarily represent 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.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 19

2. 2012 HIGHLIGHTS

•

Suncor reports strong operating earnings and cash flow from operations.

•: Net earnings for 2012 were $2.783 billion, compared to $4.304 billion in 2011.
•: Operating earnings ⁽¹⁾ for 2012 were $4.890 billion, compared to $5.674 billion in 2011.
•: Cash flow from operations ⁽¹⁾ for 2012 was $9.745 billion, compared to $9.746 billion in 2011.
•: ROCE ⁽¹⁾ (excluding major projects in progress) was 7.3% for the twelve months ended December 31, 2012, compared to 13.8% for the twelve months ended December 31, 2011. ROCE was impacted by approximately 4% due to an after-tax impairment of $1.487 billion for the Voyageur upgrader project.

•

Suncor's integrated business model translates low mid-continent crude oil prices to high refining margins.

The Refining and Marketing segment contributed over $3.1 billion to cash flow from operations in 2012 compared to $2.6 billion in 2011, reinforcing the value of an integrated business model to Suncor's consolidated results. Suncor's inland refineries benefited from discounts for mid-continent crude feedstock produced in our Oil Sands operations. Demonstrated reliability and continuous improvements of the company's refining facilities resulted in 95% overall refinery utilization in 2012, further contributing to the strength of Suncor's integrated model.

•: Suncor's balance sheet remains strong and primed for future growth.

Significant cash flow from the company's integrated and diverse operations and a disciplined approach to spending solidified Suncor's financial position.

•: Cash flow from operations for 2012 exceeded capital and exploration expenditures (including capitalized interest) by over $2.7 billion, and were higher than net debt at year end by $3.1 billion.
•: Net debt at December 31, 2012 was $6.6 billion, and decreased from $7.0 billion at December 31, 2011. Cash and cash equivalents at December 31, 2012 were $4.4 billion and increased from $3.8 billion at December 31, 2011.

•: Suncor returns cash to shareholders.

Suncor shareholders received over $2.2 billion in cash from the company during 2012 through share repurchases and dividends.

•: The company returned $1.5 billion to shareholders through the repurchase of 46.9 million common shares in 2012, at a weighted average price of $30.96 per share. The completion of the $1.5 billion share repurchase program that was initiated in 2011 and additional repurchases under the $1.0 billion program announced in 2012 resulted in a $1.0 billion increase in repurchases over the prior year.
•: The company increased its quarterly dividend by 18% to $0.13 per common share.

•: Bitumen production from Firebag increases by 75% resulting in record production for the Oil Sands.

Knowledge and expertise gained through previous Firebag construction phases were applied to Firebag Stage 4, resulting in timely execution, reliable operations and effective cost control.

•: Average production in 2012 increased to 104,000 bbls/d from 59,500 bbls/d in 2011. Suncor expects to approach production capacity of 180,000 bbls/d over the next year.
•: Cogeneration units for Stage 4 were completed ahead of schedule and steam injection for both well pads was in progress by the end of 2012. Stage 4 central processing facilities operated at 10% capacity throughout the fourth quarter, enabling the company to process incremental bitumen supply from Stage 3 wells and infill drilling projects.
•: Stage 4 was executed ahead of schedule and is expected to be approximately 15% below the announced cost estimate of $2.0 billion.

•

Execution of major capital projects adds value to Suncor.

•: The company completed the Millennium Naphtha Unit (MNU) in 2012. The company expects that the MNU will increase sweet SCO production capacity by approximately 10% and stabilize secondary upgrading processes by providing flexibility during maintenance.
•: The company completed its tailings management (TRO_TM) project in 2012, which has set the foundation for Suncor's TRO_TM process. Through the TRO_TM

20 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

process, mature fine tailings are converted more rapidly into a solid landscape suitable for reclamation.

•: The development of the North Steepbank mining area provided Suncor with access to a significant reserves base. The full ramp up of production from the North Steepbank mining area resulted in efficiencies through reduced mine congestion and lower average haul distances.

•: Suncor offers attractive prospects for long-term profitable growth.

In support of Suncor's capital discipline initiative, growth capital for 2013 is focused on high return projects, reflecting a balance between projects in the Oil Sands and Exploration and Production segments.

•: Suncor continues to focus on the optimization of assets and construction of infrastructure to enhance regional takeaway capacity and marketing flexibility of Oil Sands production. In support of these initiatives, the Wood Buffalo pipeline and two of four storage tanks at Hardisty, Alberta were commissioned in late 2012, and various debottlenecking projects in the Oil Sands operations are currently underway.
•: In the Exploration and Production segment, the company will continue to advance the Hebron and Golden Eagle Area Development (Golden Eagle) projects. In 2012, the company and the co-owners of Hebron announced project sanction. The estimated gross oil production capacity for Hebron is 150,000 bbls/d. First oil is targeted for late 2017.
•: Growth capital in Refining and Marketing will be focused on projects to prepare the Montreal refinery to receive shipments of western crude feedstock.

•

Suncor continues to evaluate a suite of growth opportunities.

•: Suncor's Oil Sands Ventures business, dedicated to ensuring the success of Suncor's joint arrangements, continued to work closely with other owners on evaluating and progressing growth projects, including the Fort Hills and Joslyn North mining projects, and the Voyageur upgrader.
•: With a significant reserves and resources base, Suncor continues to assess potential in situ growth prospects at Firebag, MacKay River, Meadow Creek and Lewis.
•: Suncor continues to explore offshore prospects in Norway and the U.K. North Sea.

•

A continued focus on operational excellence and improved reliability.

•: Demonstrated reliability and continuous improvements at Suncor's refineries resulted in nameplate capacity increases for three out of four refineries since 2011, and an overall refinery utilization rate of 95% for 2012.
•: Although 2012 was a challenging year in terms of reliability for upgrading facilities, Suncor's underlying cost discipline and performance trends were positive, as reflected in a $2/bbl decrease in cash operating costs ⁽¹⁾ per barrel from $39.05 in 2011 to $37.05 for Suncor's Oil Sands operations in 2012. Suncor continued to work towards higher reliability in 2012 with the completion of planned maintenance on several coker units and hydrotreaters at Upgrader 1 and 2.
•: Suncor executed planned maintenance on all offshore producing assets in 2012, including the repair of the propulsion system at White Rose, and the replacement of the water injection swivel and subsea infrastructure at Terra Nova. Production at Terra Nova resumed from the largest drill centre in December 2012, while production from a second drill centre was delayed until February 2013. The third drill centre is expected to be commissioned in the third quarter of 2013.

•

Operations resumed in Libya, but remained suspended in Syria.

•: Subsequent to the successful restart of production in late 2011, average production from Libya exceeded 40,000 boe/d. In 2013, Suncor plans to continue the redevelopment of existing fields and resume exploration activities.
•: As a result of the political unrest that began in Syria in the latter half of 2011 and ensuing international sanctions, Suncor declared force majeure under its contractual obligations and suspended operations in the country in December 2011. The company has ceased recording all production and revenue and continues to comply with all applicable sanctions. Suncor received $300 million in risk mitigation proceeds in 2012, which are subject to a provisional repayment should operations resume in Syria.

•

Suncor continues to invest in renewable energy assets.

The company continues to progress the Adelaide and Cedar Point wind projects through the regulatory process in 2013. The two projects are expected to add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%.

(1): Operating earnings, cash flow from operations, ROCE and Oil Sands cash operating costs are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 21

3. SUNCOR OVERVIEW

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, and we transport and refine crude oil, and 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.

Suncor has classified its operations into the following segments:

OIL SANDS

Suncor's Oil Sands segment, with assets located in the Wood Buffalo region of northeast Alberta, recovers bitumen from mining and in situ operations and upgrades the majority of this production into SCO for refinery feedstock and diesel fuel. The Oil Sands segment includes:

•

Oil Sands operations refer to Suncor's wholly owned and operated mining, extraction, upgrading and in situ assets in the Athabasca oil sands. Oil Sands operations consist of:

•: Oil Sands Base operations include the Millennium and North Steepbank mining and extraction operations, integrated upgrading facilities known as Upgrader 1 and Upgrader 2, and the associated infrastructure for these assets – including utilities, energy and reclamation facilities, such as Suncor's tailings management (TRO_TM) assets.
•: In Situ operations include oil sands bitumen production from Firebag and MacKay River and supporting infrastructure, such as central processing facilities and cogeneration units. In Situ production is either upgraded by Oil Sands Base or blended with diluent and marketed directly to customers.

•

Oil Sands Ventures assets include the company's interests in significant growth projects, including its 36.75% interest in the Joslyn North mining project, and two projects where Suncor is the operator, including its 40.8% interest in the Fort Hills mining project and its 51.0% interest in the Voyageur upgrader project. Oil Sands Ventures also includes the company's 12.0% interest in the Syncrude oil sands mining and upgrading operation.

EXPLORATION AND PRODUCTION

Suncor's Exploration and Production segment consists of offshore operations off the east coast of Canada and in the North Sea, and onshore operations in North America, Libya and Syria.

•: East Coast Canada operations include Suncor's 37.675% working interest in Terra Nova, which Suncor operates. Suncor also holds a 20.0% interest in the Hibernia base project and a 19.5% interest in the Hibernia Southern Extension Unit (HSEU), a 27.5% interest in the White Rose base project and a 26.125% interest in the White Rose Extensions, and a 22.729% interest in Hebron, all of which are operated by other companies.
•: International operations include Suncor's 29.89% working interest in Buzzard and its 26.69% interest in Golden Eagle, both in the U.K. sector of the North Sea and both of which are not operated by Suncor. Suncor also holds interests in several exploration licences offshore the U.K. and Norway. Suncor owns, pursuant to Exploration and Production Sharing Agreements (EPSAs), working interests in the exploration and development of oilfields in the Sirte Basin in Libya. Suncor also owns, pursuant to a Production Sharing Contract (PSC), an interest in the Ebla gas development in the Ash Shaer and Cherrife areas in Syria. Due to unrest in Syria, the company has declared force majeure under its contractual obligations, and Suncor's operations in Syria have been suspended indefinitely.
•: North America Onshore operations include Suncor's interests in a number of natural gas and conventional crude oil assets, primarily in Western Canada.

22 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

REFINING AND MARKETING

Suncor's Refining and Marketing segment consists of two primary operations:

•: Refining and Product Supply operations refine crude oil into a broad range of petroleum and petrochemical products. Eastern North America operations include refineries located in Montreal, Québec and Sarnia, Ontario, and a lubricants business located in Mississauga, Ontario that manufactures, blends and markets products worldwide. Western North America operations include refineries located in Edmonton, Alberta and Commerce City, Colorado. Other Refining and Product Supply assets include interests in a petrochemical plant, pipelines and product terminals in Canada and the U.S.
•: Downstream Marketing operations sell refined petroleum products and lubricants to retail, commercial and industrial customers through a combination of company-owned, branded-dealer and other retail stations in Canada and Colorado, a nationwide commercial road transport network in Canada, and a bulk sales channel in Canada.

CORPORATE, ENERGY TRADING AND ELIMINATIONS

The grouping Corporate, Energy Trading and Eliminations includes the company's investments in renewable energy projects, results related to energy marketing, supply and trading activities, and other activities not directly attributable to any other operating segment.

•: Renewable Energy interests include six operating wind power projects across Canada, two wind power projects under development in Ontario, and the St. Clair ethanol plant in Ontario.
•: Energy Trading activities primarily involve the marketing, supply and trading of crude oil, natural gas and byproducts, and the use of midstream infrastructure and financial derivatives to optimize related trading strategies.
•: Corporate activities include stewardship of Suncor's debt and borrowing costs, expenses not allocated to the company's businesses, and the company's captive insurance activities that self-insure a portion of the company's asset base.
•: Intersegment revenues and expenses are removed from consolidated results in Group Eliminations. Intersegment activity includes the sale of feedstock by the Oil Sands and Exploration and Production segments to the Refining and Marketing segment, the sale of fuels and lubricants by the Refining and Marketing segment to the Oil Sands segment, the sale of ethanol by the Renewable Energy business to the Refining and Marketing segment, and the provision of insurance for a portion of the company's operations by the Corporate captive insurance entity.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 23

4. CONSOLIDATED FINANCIAL INFORMATION

Financial Highlights

Year ended December 31 ($ millions, except per share amounts)		2012	2011	2010

Net earnings		2 783	4 304	3 829
	per common share – basic	1.80	2.74	2.45
	per common share – diluted	1.79	2.67	2.43

Operating earnings ⁽¹⁾		4 890	5 674	2 634
	per common share – basic	3.17	3.61	1.69

Cash flow from operations ⁽¹⁾		9 745	9 746	6 656
	per common share – basic	6.31	6.20	4.25

Dividends on common shares ⁽²⁾		756	664	611
	per common share – basic	0.50	0.43	0.40

Operating revenues, net of royalties ⁽³⁾		38 208	38 339	31 315

ROCE ⁽¹⁾⁽⁴⁾ (%)
	For the twelve months ended	7.3	13.8	11.4

Balance Sheet
	Total assets	76 449	74 777	68 607
	Long-term debt ⁽⁵⁾	10 249	10 016	10 347
	Net debt	6 632	6 976	11 254

Segment Highlights

Year ended December 31 ($ millions)		2012		2011		2010

Net earnings (loss)
	Oil Sands	458		2 603		1 520
	Exploration and Production	138		306		1 938
	Refining and Marketing	2 129		1 726		819
	Corporate, Energy Trading and Eliminations	58		(331	)	(448	)

Total		2 783		4 304		3 829

Operating earnings (loss) ⁽¹⁾
	Oil Sands	2 015		2 737		1 379
	Exploration and Production	850		1 358		1 193
	Refining and Marketing	2 144		1 726		796
	Corporate, Energy Trading and Eliminations	(119	)	(147	)	(734	)

Total		4 890		5 674		2 634

Cash flow from operations ⁽¹⁾
	Oil Sands	4 407		4 572		2 777
	Exploration and Production	2 227		2 846		3 325
	Refining and Marketing	3 150		2 574		1 538
	Corporate, Energy Trading and Eliminations	(39	)	(246	)	(984	)

Total		9 745		9 746		6 656

(1): Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): Dividends paid on common shares does not include a value for common share dividends granted under the company's dividend reinvestment program.
(3): The company has reclassified prior year operating revenues to reflect net presentation of certain transactions involving sales and purchases of third-party crude oil production in the Oil Sands segment that were previously presented on a gross basis.
(4): Excludes capitalized costs related to major projects in progress.
(5): Includes current portion of long-term debt.

24 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Operating Highlights

Year ended December 31		2012	2011	2010

Production Volumes (mboe/d)
	Oil Sands	359.2	339.3	318.2
	Exploration and Production	189.9	206.7	296.9

		549.1	546.0	615.1

Price Realizations ($/boe)
	Oil Sands	82.75	90.07	70.85
	Exploration and Production	84.05	79.95	61.06

		83.20	86.23	66.12

Refinery Utilization ⁽¹⁾⁽²⁾ (%)
	Eastern North America	89	94	89
	Western North America	100	91	95

		95	92	92

(1): Effective January 1, 2012, the company increased the nameplate capacity of the Montreal refinery from 130,000 bbls/d to 137,000 bbls/d and the nameplate capacity of the Commerce City refinery from 93,000 bbls/d to 98,000 bbls/d. Prior years' utilization rates have not been recalculated and reflect the lower nameplate capacities. Effective January 1, 2013, the company increased the nameplate capacity of the Edmonton refinery from 135,000 bbls/d to 140,000 bbls/d. Figures above have not been recalculated to reflect the revised nameplate capacity.
(2): 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.

Production volumes for 2012 increased relative to 2011. Suncor achieved average production in the Oil Sands segment of 359,200 bbls/d in 2012 compared to 339,300 bbls/d in 2011. The increase was due primarily to the ramp up of production from Firebag, partially offset by the impact of constrained upgrader availability on mine production, due to planned and unplanned maintenance in 2012.

Production in the Exploration and Production segment was lower in 2012 compared with 2011 due to planned maintenance activities, the suspension of operations in Syria due to political unrest and international sanctions, and the shut in of natural gas wells in 2012 in response to low North American natural gas prices. This was partially offset by the resumption of production in Libya.

Net Earnings

Suncor's net earnings for 2012 were $2.783 billion, compared to $4.304 billion in 2011. Net earnings were affected by the same factors that influenced operating earnings, which are described in this section of the MD&A under the heading Operating Earnings. Other items affecting changes in net earnings in 2012, compared with 2011, included:

Operating Earnings Adjustments

•: The after-tax unrealized foreign exchange gain on the revaluation of U.S. dollar denominated long-term debt was $157 million in 2012, compared with a loss of $161 million in 2011.
•: In 2012, the company recorded after-tax impairments (net of reversals), write-offs and provisions of $2.176 billion. Given Suncor's view of the challenging economic outlook for the Voyageur upgrader project, at December 31, 2012, Suncor performed an impairment test. Based on an assessment of expected future net cash flows, the company recorded an after-tax impairment charge of $1.487 billion. Due to political unrest and international sanctions against Syria, Suncor recorded an after-tax impairment (net of reversals) and write-offs for assets in Syria of $517 million. Additional impairments in 2012 included after-tax impairment charges of $65 million to reflect future development uncertainty relating to certain exploration assets in East Coast Canada and North America Onshore, and an after-tax impairment charge of $63 million for certain North America Onshore properties due to a decline in price forecasts. In addition, the company recorded an after-tax provision of $44 million in North America Onshore relating to future commitments for unutilized pipeline capacity.
•: In 2012, the Province of Ontario approved a budget that froze the general corporate income tax rate at 11.5%, instead of the planned reduction to 10% by 2014. As a result, the company adjusted its deferred income tax balances leading to a one-time negative adjustment to net earnings of $88 million.
•: In 2011, the company recorded net impairment charges of $503 million against assets pertaining to its operations in Libya, which were shut in as a result of political unrest. In 2011, the company also recorded $68 million of after-tax impairment charges against certain North America Onshore assets due to decreasing natural gas prices and after-tax write-offs of crude inventories of $58 million due primarily to third-party pipeline adjustments.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 25

•: In the first quarter of 2011, the U.K. government announced an increase in the tax rate on oil and gas profits in the North Sea that increased the effective tax rate on Suncor's earnings in the U.K. from 50% to 59.3% in 2011 and to 62% in future years. As a result, the company revalued its deferred income tax balances, resulting in an increase to deferred income tax expense of $442 million.
•: In 2011, the company disposed of assets resulting in after-tax losses of $107 million, consisting of $99 million on the partial disposition of interests in the Voyageur upgrader and Fort Hills projects, and $8 million for the sale of non-core Exploration and Production assets.
•: In 2011, Suncor recorded an after-tax provision of $31 million in the Exploration and Production segment related to a royalty dispute concerning the deductibility of certain costs for a period before the merger with Petro-Canada.

Operating Earnings

Consolidated Operating Earnings Reconciliation ⁽¹⁾

Year ended December 31 ($ millions)	2012		2011	2010

Net earnings as reported	2 783		4 304	3 829
Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(157	)	161	(372	)
Impairments (net of reversals), write-offs, and provisions	2 176		629	306
Impact of income tax rate adjustments on deferred income taxes	88		442	—
Loss (gain) on significant disposals ⁽²⁾	—		107	(826	)
Adjustments to provisions for assets acquired through the merger ⁽³⁾	—		31	68
Change in fair value of commodity derivatives used for risk management, net of realizations ⁽⁴⁾	—		—	(233	)
Redetermination of working interest in Terra Nova ⁽⁵⁾	—		—	(166	)
Modification of the bitumen valuation methodology ⁽⁶⁾	—		—	(51	)
Merger and integration costs	—		—	79

Operating earnings ⁽¹⁾	4 890		5 674	2 634

(1): Non-GAAP financial measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): In 2010, the company sold several Exploration and Production assets, including non-core assets in North America Onshore and the U.K. and those in the Netherlands and Trinidad and Tobago, and realized after-tax gains on the disposals of $826 million.
(3): Adjustments in 2010 were for pipeline commitments that the company determined to be unfavourable as a result of certain non-core North America Onshore asset dispositions, the write-off of certain unproven properties in the Exploration and Production segment, changes in the provision for the cancellation of the Montreal refinery coker project, a dry hole in Libya, and other cost estimates associated with the transition to EPSAs in Libya.
(4): Adjustments in 2010 represent the change in fair value of significant crude oil risk management derivatives, net of realized gains and losses recognized on the final settlement of those derivatives. The company also holds less significant risk management derivatives for which the company does not adjust net earnings.
(5): In 2010, Suncor recognized an after-tax gain of $166 million for the redetermination of its working interest in the Terra Nova oilfield, upon which the co-owners of Terra Nova reached agreement on a technical review of interests they contributed.
(6): In 2010, Suncor recognized a favourable royalty recovery related to modifications made by the Alberta government to the Bitumen Valuation Methodology (BVM) calculation applicable to Suncor for the interim period from January 1, 2009 to December 31, 2010.

26 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

(1): For an explanation of the construction of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

Suncor's consolidated operating earnings for 2012 were $4.890 billion, compared to $5.674 billion in 2011. Factors that reduced operating earnings in 2012, compared to 2011, included:

•: Production volumes from the Exploration and Production segment were lower in 2012, due primarily to planned off-station maintenance programs at Terra Nova and subsequent delays in reconnecting flow lines, planned maintenance at White Rose, the suspension of operations in Syria, and declines in production in North America Onshore, partially offset by the resumption of operations in Libya.
•: Average price realizations for production from Oil Sands operations were lower in 2012, due primarily to lower premiums for sweet SCO relative to WTI, and wider light/heavy differentials that impacted prices for sour SCO and bitumen.
•: Royalties were higher in 2012, compared with 2011, due primarily to higher production from Libya, where effective royalty rates are substantially higher than those for other Exploration and Production assets.
•: The Inventory variance factor was negative, primarily due to an inventory build in Oil Sands in 2012 to fill new logistics infrastructure, including the Wood Buffalo pipeline and storage tanks in Hardisty, Alberta.
•: Operating expenses increased due primarily to an increase in share-based compensation expense of $353 million in 2012 compared to 2011, as a result of an increase in the company's common share price from December 31, 2011 to December 31, 2012.
•: DD&A and exploration expenses were higher in 2012 relative to 2011 due primarily to a larger asset base as a result of assets commissioned in 2012 and late 2011, higher exploration write-offs, partially offset by less DD&A expense related to lower production in the Exploration and Production segment.
•: Operating earnings for International assets were also negatively impacted by a higher effective tax rate in the U.K.

The following factors had a positive impact on operating earnings in 2012 compared to 2011:

•: Production volumes in the Oil Sands segment increased to 359,200 bbls/d in 2012 from 339,300 bbls/d in 2011, primarily due to the ramp up of Firebag production.
•: Refining and marketing achieved record operating earnings in 2012 and absorbed much of the negative impact that low synthetic and heavy crude pricing had on the Oil Sands segment. Refining margins were higher in 2012 due to lower feedstock costs and higher crack spreads compared to 2011 and continued reliability from the company's refineries.

Cash Flow from Operations

Consolidated cash flow from operations for 2012 was $9.745 billion, compared to $9.746 billion in 2011. Cash flow from operations was impacted by lower price realizations in the Oil Sands segment, partially offset by strong refining margins. Lower production in the Exploration and Production segment was offset by the increase in the production from the Oil Sands segment.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 27

Results for 2011 compared with 2010

Net earnings for 2011 were $4.304 billion compared to $3.829 billion in 2010. The increase in net earnings was due mainly to the same factors impacting operating earnings, partially offset by the operating earnings adjustments described above, such as the impact of unrealized foreign exchange gains and losses on U.S. dollar denominated long-term debt, the impairment of assets in Libya, the increase in the U.K. tax rate and gains and losses on the disposal of significant assets.

Operating earnings for 2011 were $5.674 billion compared to $2.634 billion in 2010. The increase in operating earnings was due mainly to higher average upstream price realizations for crude oil production, higher refining margins and an increase in production from Oil Sands, where volumes were impacted in the first half of 2010 by two upgrader fires. These increases were partially offset by lower production volumes for the Exploration and Production segment, due mainly to the divestiture of non-core assets throughout 2010 and 2011, and higher operating expenses, primarily due to incremental costs associated with Firebag Stage 3.

Cash flow from operations was $9.746 billion in 2011, compared to $6.656 billion in 2010, and increased due mainly to the same factors impacting operating earnings.

Net debt decreased by $4.278 billion in 2011, due primarily to strong cash flow from operations that exceeded capital expenditures (including capitalized interest) by $2.890 billion and proceeds of $2.232 billion that were received from the Total E&P Canada Ltd. (Total E&P) transaction and the sale of non-core assets in 2011. These factors enabled Suncor to reduce short-term and long-term debt by $1.721 billion and maintain a larger balance of cash and cash equivalents in 2011.

Business Environment

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

Year ended December 31	2012	2011	2010

WTI crude oil at Cushing (US$/bbl)	94.20	95.10	79.55
Dated Brent crude oil at Sullom Voe (US$/bbl)	111.70	111.15	79.50
Dated Brent/Maya FOB price differential (US$/bbl)	12.15	12.50	9.30
Canadian 0.3% par crude oil at Edmonton (Cdn$/bbl)	86.60	95.75	78.05
WCS at Hardisty (US$/bbl)	73.15	77.95	65.35
Light/heavy differential for WTI at Cushing less WCS at Hardisty (US$/bbl)	21.05	17.15	14.20
Condensate at Edmonton (US$/bbl)	100.75	105.30	81.90
Natural gas (Alberta spot) at AECO (Cdn$/mcf)	2.40	3.65	4.15
New York Harbor 3-2-1 crack ⁽¹⁾ (US$/bbl)	32.90	27.00	10.55
Chicago 3-2-1 crack ⁽¹⁾ (US$/bbl)	27.40	24.65	9.00
Portland 3-2-1 crack ⁽¹⁾ (US$/bbl)	33.40	28.40	13.55
Gulf Coast 3-2-1 crack ⁽¹⁾ (US$/bbl)	29.00	24.80	9.00
Exchange rate (US$/Cdn$)	1.00	1.01	0.97
Exchange rate (end of period) (US$/Cdn$)	1.01	0.98	1.01

(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 by changes in the price for WTI at Cushing and by the supply and demand of sweet SCO from Western Canada. The average price for WTI in 2012 was US$94.20/bbl and was comparable to the average in 2011 of US$95.10/bbl. In 2012, the WTI price declined as the year progressed and reached its lowest level over the last two years. In 2012 due to oversupply, the average premium for sweet SCO was significantly lower than 2011.

Suncor produces a specific grade of sour SCO, the price realizations for which are influenced by changes to various crude benchmarks including, but not limited to, Canadian par crude at Edmonton and WCS at Hardisty, but which can also be affected by prices negotiated for spot sales. Prices for Canadian par crude at Edmonton decreased significantly in 2012, compared to 2011. The average Edmonton par price was $86.60/bbl in 2012 and $95.75/bbl in 2011. Average prices for WCS also decreased from US$77.95/bbl in 2011 to US$73.15/bbl in 2012. The differential between WTI and WCS reached its highest levels over the last two years, which was reflected in unfavourable sour SCO pricing.

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

28 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Edmonton). Diluent is sourced primarily from the company's own upgrading and refining facilities; however, purchases of diluent from third parties may be required when the company experiences operational outages. Bitumen price realizations can also be affected by bitumen quality and spot sales to manage inventory levels. Average price realizations for bitumen in 2012 were lower than those realized in 2011, due mainly to wider light/heavy differentials, offset by lower prices for diluent. Suncor's integration with inland refineries in the Refining and Marketing segment is recovering much of the impact from widening crude price differentials through lower feedstock costs.

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 remained strong throughout 2012 and averaged US$111.70/bbl, consistent with the average of US$111.15/bbl in 2011. After reaching an average of US$118.35/bbl in the first quarter of 2012, the Brent crude price stabilized throughout the remainder of the year despite the decline in WTI, resulting in significantly higher premiums to WTI in late 2012.

Suncor's price realizations for North America Onshore natural gas production are primarily referenced to Alberta spot at AECO. The AECO benchmark declined significantly with an average of $2.40/mcf in 2012 compared to $3.65/mcf in 2011.

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, which influence feedstock costs for more complex refineries that process less expensive, heavier crudes. Crack spreads do not necessarily reflect the margins of a specific refinery because these benchmarks are calculated based off of WTI. In 2012, crack spreads increased relative to 2011, in part because refined product prices reflected the higher priced Brent crude feedstock of coastal North American markets. This benefited all of Suncor's refineries for much of 2012. Specific refinery margins are further impacted by actual crude purchase costs, refinery configuration and refined product sales markets unique to that refinery's supply orbit.

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. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease revenue received from the sale of commodities. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of commodities.

Conversely, many of Suncor's assets and liabilities are denominated in U.S. dollars, most notably much of the company's long-term debt, and translated to Suncor's reporting currency (Canadian dollars) at each balance sheet date. An increase in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date decreases the Canadian dollars required to settle U.S. dollar denominated obligations.

Economic Sensitivities ^(1)(2)(3)

The following table illustrates the estimated effects that changes in certain factors would have had on 2012 net earnings and cash flow from operations if the listed changes had occurred.

(Estimated change, in $ millions)	Net Earnings		Cash Flow From Operations

Crude oil +US$1.00/bbl	88		115
Natural gas +Cdn$0.10/mcf	(3	)	(4	)
Light/heavy differential +US$1.00/bbl	30		40
3-2-1 crack spreads +US$1.00/bbl	109		140
Foreign exchange +$0.01 US$/Cdn$	(42	)	(145	)

(1): Each line item in this table shows the effects of a change in that variable only, with other variables being held consistent.
(2): Changes for a variable imply that all such similar variables are impacted, such that Suncor's average price realizations increase uniformly. For instance, "Crude oil +US$1.00/bbl" implies that price realizations influenced by WTI, Brent, SCO, WCS, par crude at Edmonton and condensate all increase by US$1.00/bbl.
(3): Differences between estimates for net earnings and cash flow from operations are due primarily to the impacts of cash taxes in certain jurisdictions.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 29

5. SEGMENT RESULTS AND ANALYSIS

OIL SANDS

Strategy and Operational Update

In 2012, the Oil Sands business achieved a number of milestones that contributed to record production.

Firebag Stage 3 reached full ramp up in 2012, while the successful execution of Firebag Stage 4 resulted in first oil from Stage 4 wells in 2012, as well as the commissioning of the central processing facilities and cogeneration units ahead of schedule. The project is near completion and expected to come in approximately 15% under the announced cost estimate. The company anticipates that bitumen production from the Firebag complex will reach production capacity of 180,000 bbls/d over the next year.

With the commissioning of the MNU in the third quarter of 2012, Suncor's upgrading facilities have the ability to generate a larger proportion of higher value SCO. The development of the North Steepbank mining area has provided access to a significant reserves base, and resulted in efficiencies in the mine through reduced mine congestion and lower average haul distances. The company also completed its tailings management project. Through the TRO_TM process, mature fine tailings are converted more rapidly into a solid landscape suitable for reclamation. As a result of this new technology and the company's capital investment to reconfigure its tailing operations, Suncor has cancelled plans for five additional tailings ponds.

While growth in 2012 was achieved through the successful execution of major capital projects, the focus in 2013 will be to optimize our current asset base through the development of new infrastructure that will enhance regional takeaway capacity and marketing flexibility, and debottlenecking projects that are expected to provide low-cost efficiencies and higher outputs in Oil Sands operations. In support of these initiatives, the Wood Buffalo pipeline and two of four storage tanks at Hardisty, Alberta were commissioned in late 2012.

The company will also continue to focus on steady production growth and sustainment through active infill and development drilling programs at both Firebag and MacKay River. In addition, the company has commenced a debottlenecking project at the MacKay River central processing facility and expects to increase production to 38,000 bbls/d by 2015.

With a significant resource base, Suncor continues to assess potential in situ growth prospects at Firebag, MacKay River, Meadow Creek and Lewis. Furthermore, Suncor's portfolio of technology projects will not only drive improvements and efficiencies in current production but facilitate in developing these future opportunities. This portfolio focuses on both subsurface and surface challenges, such as reducing steam-to-oil ratios and improving operational efficiency.

The Oil Sands business continues to focus on safe, reliable operations that achieve steady production growth while effectively controlling operating costs. We expect our operational excellence initiatives will continuously improve our plant utilization and workforce productivity. 2012 was a challenging year in terms of reliability in upgrading facilities; however, Suncor continues to work towards higher reliability.

Suncor's Oil Sands Ventures business, dedicated to ensuring the success of new joint arrangements in Alberta's oil sands, continued to work closely with other owners on evaluating and progressing growth projects, including the Fort Hills and Joslyn North mining projects, and the Voyageur upgrader.

The partners in the Fort Hills mining project expect to reach a sanction decision in the second half of 2013. Subject to the owners approving the sanction of the project, post sanction activities are expected to include the commencement of detailed engineering design, bulk equipment and material procurement, and site construction. Suncor plans to provide an update on the targeted timing for a sanction decision on the Joslyn mining project when available.

Suncor's view is that the economic outlook for the Voyageur upgrader project is challenged. Suncor and its partner continue to work diligently towards determining an outcome for the project. The partners have been considering options for the project, including the implications of cancellation or indefinite deferral. No formal decisions regarding the project have been made and the partners continue to work toward a decision by the end of the first quarter of 2013. The Voyageur upgrader project cannot be sanctioned to proceed without the approval of both partners and, in the case of Suncor, Suncor's Board of Directors. In the interim, Suncor and its partner have agreed to minimize expenditures on the project pending a decision.

30 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Financial Highlights

Year ended December 31 ($ millions)		2012		2011		2010

Gross revenues ⁽¹⁾		11 502		12 003		9 002
Less: Royalties		(684	)	(799	)	(681	)

Operating revenues, net of royalties ⁽¹⁾		10 818		11 204		8 321

Net earnings		458		2 603		1 520

Operating earnings ⁽²⁾
	Oil Sands	1 797		2 425		1 196
	Oil Sands Ventures	218		312		183

		2 015		2 737		1 379

Cash flow from operations ⁽²⁾		4 407		4 572		2 777

(1): The company has reclassified prior years' gross revenues and operating revenues to reflect net presentation of certain transactions involving sales and purchases of third-party crude oil production in the Oil Sands segment that were previously presented on a gross basis.
(2): Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Oil Sands segment net earnings for 2012 were $458 million, compared to $2.603 billion in 2011. Given the challenging economic outlook for the Voyageur upgrader project, the company performed an impairment test in 2012, based on an assessment of expected future net cash flows; the company recorded an after-tax impairment charge of $1.487 billion. Net earnings were further reduced for 2012 due to a deferred tax adjustment of $70 million related to an income tax rate change. Net earnings for 2011 included a loss of $99 million on the sale of partial interests in the Voyageur upgrader project and the Fort Hills mining project and an after-tax write-off of $35 million for third-party pipeline adjustments.

Oil Sands operations contributed $1.797 billion to operating earnings, while Oil Sands Ventures contributed $218 million. The decrease in operating earnings for Oil Sands operations from $2.425 billion in 2011 to $1.797 billion in 2012 was due primarily to lower price realizations and higher DD&A, partially offset by higher bitumen sales volumes. Operating earnings for Oil Sands Ventures decreased from $312 million in 2011 to $218 million in 2012, due primarily to lower price realizations at Syncrude.

Cash flow from operations for the Oil Sands segment was $4.407 billion in 2012, compared to $4.572 billion in 2011. The decrease was due primarily to lower price realizations, partially offset by higher bitumen sales volumes.

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2012	2011	2010

Net earnings as reported	458	2 603	1 520
Impairments and write-offs	1 487	35	143
Impact of income tax rate adjustments on deferred income taxes	70	—	—
Loss on significant disposals	—	99	—
Change in fair value of commodity derivatives used for risk management, net of realizations	—	—	(233	)
Modification of the BVM	—	—	(51	)

Operating earnings ⁽¹⁾	2 015	2 737	1 379

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

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 31

(1): For an explanation of the construction of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

Production Volumes ⁽¹⁾

Year ended December 31 (mbbls/d)	2012	2011	2010

Upgraded product (SCO)	276.7	279.7	251.4
Non-upgraded bitumen	48.1	25.0	31.6

Oil Sands	324.8	304.7	283.0

Oil Sands Ventures – Syncrude	34.4	34.6	35.2

Total	359.2	339.3	318.2

(1): Bitumen from Oil Sands Base operations is upgraded, while bitumen from In Situ operations is upgraded or sold directly to customers. Yields of SCO and diesel from Suncor's upgrading processes are approximately 79% of bitumen feedstock input. See also the Bitumen from Operations table presented below.

The Oil Sands segment achieved record production with an average of 359,200 bbls/d in 2012, increasing from 339,300 bbls/d in 2011. The increase in Oil Sands production was primarily due to the ramp up of production from Firebag.

Production of upgraded product (sweet SCO, sour SCO and diesel) averaged 276,700 bbls/d in 2012, compared to 279,700 bbls/d in 2011. Production in 2012 was impacted by planned maintenance on various coker units and hydrotreating units in Upgrader 1 and 2, as well as unplanned maintenance relating to primary and secondary upgrading at Upgrader 2. Production in 2011 was impacted by the completion of a six-week planned maintenance event at Upgrader 2 facilities and unplanned maintenance at the Upgrader 1 hydrogen plant. Although the scope of planned maintenance completed in 2012 was much smaller, the unplanned maintenance activities constrained production in the year. Non-upgraded bitumen production averaged 48,100 bbls/d in 2012, compared to 25,000 bbls/d in 2011, and increased due primarily to higher production from Firebag.

Suncor's share of Syncrude production and sales averaged 34,400 bbls/d in 2012, compared to 34,600 bbls/d in 2011. Production was impacted by a similar amount in 2012 and 2011 due to unplanned maintenance.

Bitumen from Operations

Year ended December 31		2012	2011	2010

Oil Sands Base
	Production (mbbls/d)	266.2	287.1	266.2
	Ore mined (thousands of tonnes per day)	412.3	441.1	391.9
	Bitumen ore grade quality (bbls/tonne)	0.65	0.65	0.68

In Situ bitumen production (mbbls/d)
	Firebag	104.0	59.5	53.6
	MacKay River	27.0	30.0	31.5

	Total In Situ production	131.0	89.5	85.1

In Situ steam-to-oil ratio
	Firebag	3.4	3.6	3.2
	MacKay River	2.4	2.2	2.4

Bitumen from Oil Sands Base operations averaged 266,200 bbls/d in 2012, compared to 287,100 bbls/d in 2011. The decline in bitumen production was due primarily to reduced mining activity in 2012 to coincide with lower upgrader availability that was constrained by maintenance activities. For the majority of the year, the company had been mining through a lower ore grade quality of the Millennium mining area; however, by the fourth quarter of 2012, Suncor had worked through the area of lower bitumen ore grade quality, as planned.

32 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Bitumen from In Situ operations averaged 131,000 bbls/d in 2012, increasing from 89,500 bbls/d in 2011.

•: Production from Firebag averaged 104,000 bbls/d in 2012 compared to 59,500 bbls/d in 2011. Stage 3 central processing facilities reached design rates approximately one year after achieving first oil in August 2011, while Stage 4 cogeneration units and central processing facilities were commissioned ahead of schedule, with the central processing facility operating at 10% capacity throughout the fourth quarter of 2012. Production from Firebag is expected to reach production capacity of 180,000 bbls/d over the next year.
•: Production from MacKay River averaged 27,000 bbls/d in 2012, compared to 30,000 bbls/d in 2011, and decreased primarily due to increased planned maintenance activities in 2012 and natural declines in older wells. In order to maintain production levels, the company began steaming wells on a new pad in December 2012, with first oil from these wells anticipated in the first quarter of 2013.

Sales Volumes and Mix

Year ended December 31		2012	2011	2010

Oil Sands sales volumes (mbbls/d)
	Sweet SCO	93.8	85.5	82.3
	Diesel	24.5	24.3	20.4
	Sour SCO	161.1	170.6	145.2

Upgraded Product (SCO)		279.4	280.4	247.9
Non-upgraded bitumen		44.5	24.0	31.4

		323.9	304.4	279.3

Sales volumes for Oil Sands operations increased to 323,900 bbls/d in 2012, compared to 304,400 bbls/d in 2011.

•: Sales volumes of sweet product (sweet SCO and diesel) increased in 2012, compared to 2011. The start-up of operations for the MNU in the third quarter of 2012 enabled Suncor to maintain a more profitable SCO sales mix during maintenance at Upgrader 2 in 2012. In 2011, sales of sweet product were impacted by the planned maintenance event at Upgrader 2 and unplanned maintenance at the Upgrader 1 hydrogen plant.
•: Sales volumes of non-upgraded bitumen increased in 2012, compared to 2011, mainly due to the incremental Firebag volumes in 2012 resulting in higher non-upgraded bitumen production from Firebag.

Price Realizations

Year ended December 31 Net of transportation costs, but before royalties ($/bbl)		2012		2011		2010

Oil Sands
	Sweet SCO and diesel	96.95		103.95		74.71
	Sour SCO and non-upgraded bitumen	72.93		80.17		66.60
	Crude sales basket (all products)	81.69		88.74		69.58
	Crude sales basket, relative to WTI	(12.44	)	(5.35	)	(12.33	)

Oil Sands Ventures
	Syncrude – Sweet SCO	92.69		101.80		80.93
	Syncrude, relative to WTI	(1.50	)	7.71		(0.98	)

Average price realizations for Oil Sands operations decreased to $81.69/bbl in 2012 from $88.74/bbl in 2011, due to a higher proportion of non-upgraded bitumen sales in 2012, combined with less favourable price differentials. Although the average price for WTI remained relatively constant from 2011, the average premium for sweet SCO relative to WTI was lower by approximately $6/bbl. Sour SCO and non-upgraded bitumen prices reflected the widening discount for WCS relative to WTI. As a result, the average price realization for Oil Sands operations relative to WTI was WTI less $12.44/bbl in 2012, compared with WTI less $5.35/bbl in 2011.

Suncor's average price realization for Syncrude sales in 2012 was $92.69/bbl, compared to $101.80/bbl in 2011, primarily due to less favourable differentials between sweet SCO and WTI in 2012.

Royalties

Royalties were lower in 2012 relative to 2011 due to lower benchmark prices for WCS that influenced the company's regulated bitumen valuation methodology used to determine royalties for mining properties. Higher eligible capital costs deductions at Syncrude for large sustaining capital expenditures also contributed to lower royalties in 2012.

Inventory

The Inventory variance factor decreased operating earnings due to a large build in inventory at the end of 2012, resulting from increased non-upgraded bitumen production and line fill required for assets that were brought into service in late 2012, including the Wood Buffalo pipeline and two storage tanks in Hardisty, Alberta.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 33

Expenses and Other Factors

Operating expenses for 2012 were slightly higher than 2011. Factors contributing to the change in operating expenses included:

•: Cash operating costs for Oil Sands operations increased slightly to $4.395 billion in 2012 from $4.355 billion in 2011 due to the incremental costs required to operate assets brought into service in the current year, including Firebag Stage 4 central processing facilities and the MNU, partially offset by lower natural gas prices, the net benefit provided by higher power sales and operating efficiencies, including the benefits associated with the North Steepbank mining area.
•: Other operating expenses were higher in 2012 than 2011 due primarily to higher share-based compensation expense and higher costs related to remobilizing certain growth projects out of "safe mode" after the economic downturn in late 2008 and early 2009, partially offset by lower costs relating to the reduced scope of start-up activity for Firebag Stage 4, and the receipt of pipeline transportation credits.
•: Operating expenses at Syncrude were lower for 2012 than 2011, as a result of lower fuel costs and lower planned maintenance expenditures.

DD&A expense for 2012 was higher than 2011, due to the larger asset base that is the result of commissioning additional Firebag assets, the TRO_TM project, the MNU, the North Steepbank mining area, and the costs capitalized as part of planned maintenance events.

Cash Operating Costs Reconciliation ⁽¹⁾⁽²⁾

Year ended December 31		2012		2011		2010

Operating, selling and general expense (OS&G)		5 375		5 169		4 537
	Syncrude OS&G	(513	)	(529	)	(473	)
	Non-production costs ⁽³⁾	(338	)	(275	)	(305	)
	Other ⁽⁴⁾	(129	)	(10	)	32

Oil Sands cash operating costs ($ millions)		4 395		4 355		3 791
Oil sands cash operating costs ($/bbl)		37.05		39.05		36.70

(1): Cash operating costs and cash operating costs per barrel are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this document.
(2): Effective as of the first quarter of 2012, the calculation of cash operating costs has been revised to better reflect the ongoing cash costs of production, and prior period figures have been redetermined. See the Non-GAAP Financial Measures Advisory section of this document.
(3): Significant non-production costs include, but are not limited to, share-based compensation adjustments, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a non-monetary arrangement involving a third-party processor and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes.
(4): Other includes the impacts of changes in inventory valuation and operating revenues associated with excess power from cogeneration units.

Oil Sands cash operating costs per barrel decreased in 2012, averaging $37.05/bbl, compared to $39.05/bbl in 2011 due to higher production volumes while total cash operating costs increased slightly. Total cash operating costs in 2012 were impacted by the incremental costs required to operate assets brought into service in the current year, including Firebag Stage 4 central processing facilities and the MNU, partially offset by lower natural gas prices, the net benefit provided by higher power sales and operating efficiencies, including the benefits associated with the North Steepbank mining area.

Voyageur Upgrader Project Impairment

Given the challenging economic outlook for the Voyageur upgrader project, the company performed an impairment test in the fourth quarter of 2012. Based on an assessment of expected future net cash flows, the company recorded an after-tax impairment charge of $1.487 billion, after which the company's carrying value for net assets relating to the Voyageur upgrader project as at December 31, 2012 was approximately $345 million.

Planned Maintenance Events

The company plans to commence refurbishing the Upgrader 1 hydrogen plant late in the first quarter of 2013, which is expected to be offline for approximately 14 weeks. The decrease in sweet SCO production during this outage is expected to be partially offset by the additional hydrotreating capacity from the MNU.

The company has scheduled a planned maintenance event for its Upgrader 1 facility in the second quarter of 2013. The event is scheduled for approximately seven weeks, during which time there will be no production from Upgrader 1. Within this outage, the company anticipates completing planned maintenance at one of the Firebag central processing facilities.

Planned maintenance is also scheduled in the third quarter of 2013 for the company's Upgrader 2 facilities, which is anticipated to have an impact on SCO production.

The production impact of the maintenance discussed above has been reflected in the company's 2013 guidance.

Results for 2011 compared with 2010

Oil Sands net earnings for 2011 were $2.603 billion, compared to $1.520 billion in 2010. Net earnings in 2011

34 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

included an after-tax loss on the partial disposition of interests in the Voyageur upgrader and Fort Hills mining projects. Net earnings for 2010 included after-tax gains of $233 million for the change in fair value of commodity derivatives used for risk management and $51 million for a recovery of royalties pertaining to a change in Suncor's BVM, partially offset by after-tax write-offs of $143 million primarily associated with equipment for an alternative mining and extraction process that was discontinued.

Operating earnings for 2011 were $2.737 billion, compared to $1.379 billion in 2010, and increased primarily due to higher average price realizations and higher production volumes, offset by higher operating expenses and DD&A. Production volumes were lower during the first half of 2010 due mainly to the impacts of the two upgrader fires. Operating expenses were higher in 2011, due mainly to costs associated with the start of operations for Firebag 3 and with unplanned maintenance on secondary upgrading units at Upgrader 1. DD&A was higher, due mainly to commissioning assets such as Firebag 3 and the 2011 planned maintenance event.

Cash flow from operations for 2011 was $4.572 billion, compared to $2.777 billion in 2010, due primarily to higher margins, which were driven by higher price realizations and higher production volumes.

During the first quarter of 2011, Suncor completed transactions with Total E&P, which brought Total E&P into the Voyageur upgrader project and increased Total E&P's working interest in the Fort Hills oil sands mining project, and which brought Suncor into the Joslyn oil sands mining project. In consideration for Total E&P acquiring a 49% interest in the Voyageur upgrader project, an additional 19.2% interest in the Fort Hills project, rights to certain knowledge and technology licences, and Total E&P assuming its share of capital expenditures subsequent to the transaction effective date of January 1, 2011, Suncor received $2.662 billion from Total E&P, net of transaction costs. Suncor recorded an after-tax loss of $99 million on the partial disposition of its assets, which included a reduction of $267 million to goodwill that the company allocated to its disposed interests. In consideration for Suncor acquiring a 36.75% interest in Joslyn and assuming its share of capital expenditures subsequent to the effective date, Suncor paid Total E&P $842 million.

EXPLORATION AND PRODUCTION

Strategy and Operational Update

Suncor's Exploration and Production operations are mainly comprised of conventional upstream assets. The Exploration and Production segment continued to generate significant cash flow for Suncor, and remains an important source of funding for future growth. Profitability was also realized through high price realization as over 70% of 2012 production from this segment received prices based on Brent crude, which traded at a significant premium to WTI.

As noted, 2012 results for the Exploration and Production segment were highlighted by planned maintenance activities at all offshore facilities, including the replacement of the floating production, storage and offloading vessels (FPSO) water injection swivel and subsea infrastructure at Terra Nova and the repair of the FPSO propulsion system and other maintenance at White Rose. Production levels in Libya were strong following the restart of production after the regime change in 2011. Suncor is encouraged by this progress and is working to restart exploration activities in 2013.

The year was not without its challenges. Operations in Syria remained suspended throughout 2012 as a result of political unrest and international sanctions against that country. North American natural gas prices were very low throughout the year, resulting in the shut in of production in certain areas in Western Canada.

In support of the company's focus on long term profitable growth through its core assets, combined with a view that market conditions are improving, Suncor continues to explore opportunities to divest non-core properties, and will pursue those opportunities that meets its financial objectives.

Growth from the Exploration and Production segment is an important focus for Suncor, with approximately half of Suncor's 2013 growth capital targeted towards advancing projects within the segment. The company and co-owners announced sanction of the Hebron project offshore Newfoundland and Labrador in the fourth quarter of 2012. The estimated gross oil production capacity for Hebron is 150,000 bbls/d with initial production estimated late in 2017.

The company and co-owners of the Golden Eagle project in the UK sector of the North Sea continued to progress development in 2012, with initial production estimated in late 2014 or early 2015.

The company also plans to leverage and extend the productive life of existing offshore infrastructure, with

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 35

drilling activities in areas adjacent to producing fields, such as the HSEU, the White Rose Extensions, and the Northern Terrace area for Buzzard.

Longer term, there is potential for new prospects offshore Norway, where the company is increasingly acting as operator for its growing exploration portfolio, and in the mature U.K. North Sea and East Coast Canada basins.

Financial Highlights

Year ended December 31 ($ millions)		2012		2011		2010

Gross revenues		6 476		6 784		7 043
Less: Royalties		(1 631	)	(1 472	)	(1 377	)

Operating revenues, net of royalties		4 845		5 312		5 666

Net earnings		138		306		1 938

Operating earnings ⁽¹⁾
	East Coast Canada	422		694		407
	International	538		708		793
	North America Onshore	(110	)	(44	)	(7	)

		850		1 358		1 193

Cash flow from operations ⁽¹⁾		2 227		2 846		3 325

(1): Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Exploration and Production net earnings for 2012 were $138 million, compared to $306 million for 2011. Net earnings for 2012 included total impairments (net of reversals), write-offs and provisions of $689 million. The company recorded after-tax impairment (net of reversals) and write-offs of $517 million for assets in Syria, after-tax impairment charges of $65 million to reflect future development uncertainty relating to certain exploration assets in East Coast Canada and North America Onshore, and an after-tax impairment charge of $63 million for certain North America Onshore properties due to a decline in price forecasts. In addition, the company recorded an after-tax provision of $44 million in North America Onshore relating to future commitments for unutilized pipeline capacity. Net earnings also included a deferred income tax charge of $23 million related to an income tax rate change.

Net earnings for 2011 included after-tax impairments (net of reversals) of $571 million comprised of an after-tax impairment (net of reversals) of $503 million for assets in Libya as a result of the shut in of production, and $68 million against certain North America Onshore properties due to decreasing price forecasts. Net earnings in 2011 were also impacted by a deferred income tax charge of $442 million pertaining to an increase in the U.K. statutory income tax rate, an after-tax provision of $31 million pertaining to a royalty dispute covering a period from before the merger, and after-tax losses on the disposal of non-core assets of $8 million.

For 2012, operating earnings for East Coast Canada were $422 million, compared to $694 million for 2011, and were lower due primarily to planned off-station maintenance programs at Terra Nova, White Rose and Hibernia that decreased production. Operating earnings for International were $538 million for 2012, compared to $708 million for 2011, and were lower primarily due to the suspension of operations in Syria, higher income tax expense in the UK due to a statutory income tax rate increase, and higher exploration and well write-offs, partially offset by the resumption of operations in Libya and higher price realizations in 2012. The operating loss for North America Onshore was $110 million for 2012, compared with an operating loss of $44 million for 2011, due to lower natural gas prices and production volumes.

Cash flow from operations was $2.227 billion in 2012, compared to $2.846 billion in 2011, and decreased primarily due to the same factors that affected operating earnings.

36 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2012	2011	2010

Net earnings as reported	138	306	1 938
Impairments (net of reversals), write-offs and provisions	689	571	163
Impact of income tax rate adjustments on deferred income taxes	23	442	—
Adjustments to provisions for assets acquired through the merger	—	31	84
Loss (gain) on significant disposals	—	8	(826	)
Redetermination of working interest in Terra Nova	—	—	(166	)

Operating earnings ⁽¹⁾	850	1 358	1 193

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

(1): For an explanation of the construction of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

Production Volumes

Year ended December 31		2012	2011	2010

Production volumes (mboe/d)		189.9	206.7	296.9
	East Coast Canada (mbbls/d)	46.5	65.6	68.6
	International (mboe/d)	89.5	76.4	132.5
	North America Onshore (mmcfe/d)	323	388	575

Production Mix (liquids/gas) (%)		74/26	64/36	63/37
	East Coast Canada	100/0	100/0	100/0
	International	99/1	82/18	87/13
	North America Onshore	10/90	8/92	9/91

East Coast Canada production averaged 46,500 bbls/d in 2012, compared to 65,600 bbls/d in 2011.

•: Production from Terra Nova averaged 8,800 bbls/d in 2012, compared to 16,200 bbls/d in 2011. Production was shut in for 27 weeks during 2012 for a dockside maintenance program to replace the FPSO water injection swivel and complete other routine planned maintenance. Suncor also used this outage to perform work on subsea infrastructure to help mitigate hydrogen sulphide (H₂S) issues. Following the dockside maintenance program, production from the largest drill centre resumed in December, while production from a second drill centre was delayed until February 2013. The third drill centre is expected to be commissioned in the third quarter of 2013 when faulty flow lines can be replaced. Despite the impact on production from not commissioning the third drill centre, the company expects to meet 2013 guidance in respect of East Coast Canada production.
•: Production from White Rose averaged 11,600 bbls/d in 2012, compared to 18,500 bbls/d in 2011. Production was shut in for 15 weeks during 2012 for an off-station maintenance program to repair the FPSO propulsion system, in addition to other routine planned maintenance activities.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 37

•: Production from Hibernia averaged 26,100 bbls/d in 2012, compared to 30,900 bbls/d in 2011. Production was shut in for four weeks for planned maintenance. Natural declines from older wells were partially offset by production increases from ongoing development drilling.

International production averaged 89,500 boe/d in 2012, compared to 76,400 boe/d in 2011.

•: Production from the North Sea averaged 48,000 boe/d in 2012, compared to 46,700 boe/d in 2011. Higher production from Buzzard reflected improved reliability during 2012. In 2011, production from Buzzard was constrained due to replacement of the gas compression cooling system, downtime and capacity constraints on a third-party export pipeline, and other outages that coincided with the commissioning of the fourth platform. Production in 2011 included 3,800 boe/d from non-core U.K. assets that were divested in the first quarter of 2011.
•: Production from Libya averaged 41,500 bbls/d in 2012, compared to 12,100 bbls/d in 2011. Production from Libya was suspended throughout much of 2011 due to the outbreak of political unrest and international sanctions. Subsequent to the government regime change and the lifting of sanctions, production was restarted later in the year and had resumed in all major fields by the first quarter of 2012.
•: In December 2011, the company declared force majeure under its contractual obligations in Syria due to political unrest and international sanctions affecting that country. As a result, the company recorded no production from Syria for 2012. Production from Syria averaged 17,600 boe/d in 2011.

North America Onshore production averaged 323 mmcfe/d in 2012, compared to 388 mmcfe/d in 2011.

•: During the first half of 2012, the shut in of production from certain fields in southwest Alberta and northeast B.C., in response to low natural gas prices and the closure of a natural gas facility, contributed production of approximately 25 mmcfe/d in 2011.
•: Throughout 2011, the company divested non-core assets that contributed production of approximately 14 mmcfe/d in 2011.
•: Production from remaining properties decreased in 2012 primarily due to natural declines.

Price Realizations

Year ended December 31 Net of transportation costs, but before royalties		2012	2011	2010

Exploration and Production ($/boe)		84.05	79.95	61.06
	East Coast Canada ($/bbl)	112.15	108.42	80.20
	International ($/boe)	108.22	100.89	74.92
	North America Onshore ($/mcfe)	3.28	4.39	4.70

In 2012, average price realizations for crude oil from East Coast Canada were higher than 2011. Although the price for Brent crude for 2012 was consistent with the prior year, price realizations in East Coast Canada increased to $112.15/bbl in 2012 compared to $108.42/bbl in 2011, primarily due to higher production in the first quarter of 2012 when the price for Brent crude was at its highest for the year.

For International, average price realizations were higher in 2012 due to the mix impact of adding higher priced crude oil production from Libya and removing natural gas production from Syria.

Average price realizations for North America Onshore were lower due primarily to lower benchmark prices for natural gas.

Royalties

Royalties were higher in 2012, compared with 2011, due primarily to higher production from Libya, where effective royalty rates are substantially higher than those for other Exploration and Production assets. This increase was partially offset by lower royalties from less production in East Coast Canada and North America Onshore in comparison to 2011, and the suspension of operations in Syria in 2012.

Expenses and Other Factors

Operating expenses were lower in 2012 than in 2011 due to lower production volumes in East Coast Canada, lower production in North America Onshore and the suspension of operations in Syria, partially offset by higher incremental expenses associated with planned maintenance in 2012 and the resumption of operations in Libya.

In March 2012, while drilling an exploratory natural gas well in B.C., a fire occurred on a drilling rig. The fire was brought under control in early April, and the well was subsequently capped. Operating expenses associated with the containment and monitoring of this well were approximately $43 million before tax, partially offset by $25 million before tax in partial insurance proceeds received in the fourth quarter of 2012.

38 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

DD&A and exploration expenses were lower in 2012 due primarily to less production, partially offset by higher exploration write-offs. The company wrote off $145 million in exploration expenditures ($42 million after-tax) in 2012, primarily associated with a second appraisal well for the Beta discovery and an exploration well for the Cooper prospect.

Financing expense and other income was impacted by a higher effective tax rate in 2012 due to an increase in the statutory tax rate in the U.K. and the impact of reinvesting proceeds from U.K. asset disposals in 2011.

Impairment and Write-Off of Syrian Assets

As a result of the political unrest that began in Syria in the latter half of 2011 and ensuing international sanctions, Suncor declared force majeure under its contractual obligations and suspended operations in the country in December 2011. In the second quarter of 2012, Suncor estimated the net recoverable value of its assets in Syria based on an assessment of expected future net cash flows over a range of possible outcomes. Based on this assessment, the company recorded impairment charges of $604 million against property, plant and equipment. In the same quarter, the company recorded a further write-down of $67 million against remaining accounts receivable and a write-off of $23 million for other current assets.

In the fourth quarter of 2012, the company received risk mitigation proceeds of $300 million pertaining to the suspension of the company's operations in Syria. A portion, or all, of these proceeds may be repayable if operations in Syria resume. As a result, the proceeds were not recorded in earnings but rather as a provision. Suncor re-estimated the net recoverable value of its assets in Syria at the end of 2012, extending the future potential dates for the resumption of operations further into the future and including repayment of risk mitigation proceeds in scenarios where operations resumed. As a result of the changes, the company reversed $177 million of the impairment charges recorded earlier in the year.

Impairments (net of reversals) and write-offs in 2012 were $517 million, net of income taxes of $nil. After impairments (net of reversals) and write-offs, the carrying value of Suncor's property, plant and equipment in Syria net of the risk mitigation provision as at December 31, 2012 was approximately $130 million.

Planned Maintenance Events

Routine annual planned maintenance has been scheduled for Terra Nova, White Rose and Buzzard in the second and third quarters of 2013.

The production impact of this maintenance has been reflected in the company's 2013 guidance.

Results for 2011 compared with 2010

Exploration and Production net earnings for 2011 were $306 billion, compared to $1.938 million in 2010. Net earnings in 2010 included after-tax gains of $826 million on the disposal of non-core assets, an after-tax gain of $166 million for the redetermination of Suncor's working interest in Terra Nova, after-tax impairment charges of $111 million on certain North America Onshore assets mainly due to lower natural gas prices, an after-tax provision of $84 million related to losses on unfavourable natural gas pipeline commitments, and after-tax impairment charges of $52 million on non-core U.K. assets that were divested.

Operating earnings for 2011 were $1.358 billion, compared to $1.193 billion for 2010, and increased primarily due to higher price realizations and lower operating expenses and DD&A, partially offset by lower production volumes, higher royalties and a higher effective tax rate on U.K. earnings.

Cash flow from operations was $2.846 billion for 2011, compared to $3.325 billion for 2010. The decrease in cash flow from operations relative to the increase in operating earnings was due primarily to lower production from assets in 2011 that contributed relatively more to cash flow from operations than operating earnings for 2010. In addition, cash flow from operations in 2010 included the gain from the settlement pertaining to the redetermination of working interests in Terra Nova.

REFINING AND MARKETING

Strategy and Operational Update

Results from 2012 for the Refining and Marketing segment were strong, reinforcing the value of an integrated business model to Suncor's overall strategy. The Refining and Marketing segment translated lower price realizations impacting the Oil Sands to strong refining margins. The segments financial performance was supported by 100% utilization rates at the company's Western North America refineries.

In 2012, the company's inland refinery network (Edmonton, Sarnia and Commerce City) was again able to

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 39

capture the favourable WTI to Brent and Canadian crude differentials through strong refining margins. The integration of these refineries with crude output from Suncor's Oil Sands segment also resulted in lower feedstock costs. Suncor's focus on reliability and continuous improvements enabled the company to sustain high throughput levels, which resulted in nameplate capacity increases for the Sarnia and Commerce City refineries, effective January 1, 2012, and the Edmonton refinery, effective January 1, 2013.

In 2013, Suncor will continue to focus on optimizing overall integration. As bitumen production exceeds upgrading capacity in the Oil Sands, the company continues to explore opportunities to capture the potential value in the refining operations. In 2013, the company will focus on bringing the Montreal refinery into the inland refining network, and plans to transport western Canadian crudes via rail to the refinery.

Suncor's Petro-Canada branded outlets continue to be a leading retailer by market share in major urban areas of Canada. Increased competition and fluctuating demand in key retail markets are expected to be offset by growth in wholesale channels. Refining and Marketing will continue to leverage the strong brand to increase non-petroleum revenues through the company's network of convenience stores and car washes, and expand the lubricants product offering.

Financial Highlights

Year ended December 31 ($ millions)		2012	2011	2010

Operating revenues		26 321	25 713	20 860

Net earnings		2 129	1 726	819

Operating earnings ⁽¹⁾
	Refining and Product Supply	1 869	1 413	532
	Marketing	275	313	264

		2 144	1 726	796

Cash flow from operations ⁽¹⁾		3 150	2 574	1 538

(1): Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Refining and Marketing recorded net earnings of $2.129 billion and operating earnings of $2.144 billion in 2012, compared with net and operating earnings of $1.726 billion in 2011.

Refining and Product Supply operations contributed $1.869 billion to operating earnings in 2012, a significant increase compared with 2011, primarily due to higher refining margins from lower costs for inland heavy, synthetic, and conventional crude feedstock, higher benchmark refining margins, and higher refinery utilization, slightly offset by the negative impacts of a decreasing crude price environment, whereby inventories produced during periods of higher feedstock costs were sold and replaced with inventories purchased at relatively lower feedstock costs. Marketing operations contributed $275 million to operating earnings in 2012, which was lower than in 2011, due mainly to lower sales volumes and margins in the retail channel.

Cash flow from operations was $3.150 billion in 2012, compared to $2.574 billion in 2011, and increased primarily due to the same factors that affected operating earnings.

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2012	2011	2010

Net earnings as reported	2 129	1 726	819
Impact of income tax rate adjustments on deferred income taxes	15	—	—
Adjustments to provisions for assets acquired through the merger	—	—	(23	)

Operating earnings ⁽¹⁾	2 144	1 726	796

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

40 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

(1): For an explanation of the construction of this bridge analysis, see the Non-GAAP Financial Measures Advisory section of this MD&A.

Volumes

Year ended December 31		2012	2011	2010

Crude oil processed (thousands of m³/d)
	Eastern North America	31.4	32.0	30.5
	Western North America	37.2	32.8	34.6

Refinery utilization ⁽¹⁾⁽²⁾ (%)
	Eastern North America	89	94	89
	Western North America	100	91	95

Refined Product Sales (thousands of m³/d)
	Gasoline	40.2	39.7	41.1
	Distillate	31.0	30.4	30.4
	Other	14.4	13.0	15.8

		85.6	83.1	87.3

(1): Effective January 1, 2012, the company increased the nameplate capacity of the Montreal refinery from 130,000 bbls/d (20.7 m³/d) to 137,000 bbls/d (21.8 m³/d) and the nameplate capacity of the Commerce City refinery from 93,000 bbls/d (14.8 m³/d) to 98,000 bbls/d (15.6 m³/d). Prior years' utilization rates have not been recalculated and reflect the lower nameplate capacities. Effective January 1, 2013, the company increased the nameplate capacity of the Edmonton refinery from 135,000 bbls/d (21.5 m³/d) to 140,000 bbls/d (22.3 m³/d). Figures above have not been recalculated to reflect the revised nameplate capacity.
(2): 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.

Total sales of refined petroleum products increased to an average of 85,600 m³/d in 2012, compared to 83,100 m³/d in 2011. Suncor was able to meet the higher demands for gasoline and distillate in Western North America through reliability and continuous improvements in the Edmonton refinery. Suncor increased the nameplate capacity of the Edmonton refinery to 140,000 bbls/d from 135,000 bbls/d, effective January 1, 2013. Gasoline and distillate sales in Eastern North America were impacted by weaker demand and increased competition.

Refinery utilization in Eastern North America averaged 89% in 2012, compared to 94% in 2011. Refinery utilization in 2012 was impacted by an unplanned outage of a crude unit at the Sarnia refinery in the first quarter of 2012, a reduction in feedstock availability in the second quarter due to an unplanned Oil Sands upgrader outage, and a scheduled maintenance event at the Sarnia refinery in the fourth quarter of 2012.

Refineries in Western North America ran at full capacity for the majority of 2012, with an average utilization of 100% in 2012, compared to 91% in 2011. The increase over the prior year was the result of a month-long disruption to third-party hydrogen supply and a six-week planned maintenance event in the Edmonton refinery in 2011, while refinery utilization at the Commerce City refinery was also impacted by a five-week planned maintenance event during the second quarter of 2011.

Prices and Margins

For Refining and Product Supply, prices and margins for refined products were higher in 2012 compared to 2011, reflecting lower crude feedstock costs and higher crack spreads, partially offset by the inventory valuation impact of a declining crude price environment.

•: Prices for Canadian-based crude feedstock for the company's inland refineries were lower in 2012 due mainly to larger discounts reflecting increased industry supply. Sweet SCO sold at a lower premium relative to WTI compared with 2011 and in some months at discounts relative to WTI, in addition to lower prices for bitumen due to wider light/heavy crude oil differentials.
•: The impact on earnings pertaining to the declining crude price environment over 2012 decreased after-tax earnings by approximately $153 million, whereas the impact on earnings pertaining to the rising crude price

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 41

environment in 2011 increased after-tax earnings by approximately $230 million.

For Marketing, lower margins in retail were partially offset by higher margins in the wholesale channel.

Expenses and Other Factors

Operating expenses were higher in 2012 than in 2011, due to higher share-based compensation expense, partially offset by lower energy prices for natural gas.

The Financing Expense and Other Income factor was negatively impacted by lower gains on risk management activities in the current year and a gain pertaining to the company's investments in marketing entities.

Planned Maintenance Events

The company has scheduled planned maintenance events at the Edmonton refinery on its heavy sour crude train in the second quarter of 2013, with an expected duration of five weeks, and on its sweet synthetic crude unit in the third quarter of 2013, with an expected duration of two weeks. A six-week planned maintenance event is scheduled at the Sarnia refinery for one of its crude units, beginning the third quarter of 2013.

The impact of this maintenance has been reflected in the company's 2013 guidance.

Results for 2011 compared with 2010

Refining and Marketing net and operating earnings for 2011 were $1.726 billion, compared to net earnings of $819 million and operating earnings of $796 million for 2010. Earnings increased primarily due to higher refining margin and the positive impacts of an increasing crude price environment.

Cash flow from operations for 2011 were $2.574 billion, compared to $1.538 billion for 2010, and increased mainly due to the same factors that affected operating earnings.

CORPORATE, ENERGY TRADING AND ELIMINATIONS

Strategy and Operational Update

The Energy Trading business continued to add value in 2012 by accessing key logistical transportation and storage assets across North America to support planned increases in production capacity. The Energy Trading business supports the company's production by optimizing price realizations, managing inventory levels during unplanned outages at Suncor's facilities and managing the impacts of external market factors, such as pipeline disruptions or outages at refining customers, while generating trading earnings through established strategies. The Energy Trading business continues to evaluate additional pipeline agreements to support planned increases in production capacity.

For Renewable Energy, in 2013, the company will continue to progress the Adelaide and Cedar Point wind projects through the regulatory process. The two projects are expected to add 140 MW of gross installed capacity, increasing the gross installed capacity of Suncor's wind projects by 55%. The focus for the ethanol operations will be to maintain safe and reliable operations and improve plant profitability through technology improvements.

Financial Highlights

Year ended December 31 ($ millions)		2012		2011		2010

Net earnings (loss)		58		(331	)	(448	)

Operating earnings (loss) ⁽¹⁾
	Renewable Energy	57		72		33
	Energy Trading	147		149		64
	Corporate	(407	)	(346	)	(842	)
	Group Eliminations	84		(22	)	11

		(119	)	(147	)	(734	)

Cash flow used in operations ⁽¹⁾		(39	)	(246	)	(984	)

(1): Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Net earnings for Corporate, Energy Trading and Eliminations for 2012 were $58 million, compared to a net loss of $331 million for 2011. In 2012, the Canadian dollar strengthened in relation to the U.S. dollar, with the exchange rate increasing from 0.98 to 1.01, resulting in an after-tax unrealized foreign exchange gain on

42 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

U.S. dollar denominated long-term debt of $157 million. In 2011, the Canadian dollar weakened in relation to the U.S. dollar, with the US$/Cdn$ exchange rate decreasing from 1.01 to 0.98 and resulting in an after-tax unrealized foreign exchange loss on U.S. dollar denominated long-term debt of $161 million. Net earnings for 2012 also included a deferred tax reduction of $20 million related to an income tax rate change.

The operating loss for Corporate, Energy Trading and Eliminations in 2012 was $119 million, compared with an operating loss of $147 million in 2011. Operating earnings are discussed below.

Operating Earnings

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2012		2011		2010

Net earnings (loss) as reported	58		(331	)	(448	)
Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(157	)	161		(372	)
Impairments and write-offs	—		23		—
Impact of income tax rate adjustments on deferred income taxes	(20	)	—		—
Merger and integration costs	—		—		79
Adjustments to provisions for assets acquired through the merger	—		—		7

Operating loss ⁽¹⁾	(119	)	(147	)	(734	)

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

Renewable Energy

Year ended December 31	2012	2011	2010

Power generation marketed (gigawatt hours)	429	245	174
Ethanol production (thousands of m³)	412.5	381.5	206.0

Suncor's renewable energy assets contributed operating earnings of $57 million in 2012, compared to $72 million in 2011, and decreased primarily due to lower margins on ethanol sales that reflected higher prices for feedstock, partially offset by an increase in total power generation marketed from 245 gigawatt hours in 2011 compared to 429 gigawatt hours in 2012. In 2011, Suncor commissioned two new wind power projects – the 88-MW, 55-turbine Wintering Hills project in southern Alberta and the 20-MW, eight-turbine Kent Breeze project in southwest Ontario.

Energy Trading

Energy Trading activities contributed operating earnings of $147 million in 2012, compared to $149 million in 2011. Energy trading continued to contribute to operating earnings, primarily through its heavy crude trading strategies that purchase heavy crude oil in Alberta and transport it to markets with more favourable prices.

Corporate

Corporate had an operating loss of $407 million in 2012, compared with an operating loss of $346 million in 2011. The increase in operating loss was due to higher share-based compensation expense and higher DD&A due to the start of depreciation on Suncor's system integration initiative over the second half of 2011.

In 2012, the company capitalized 91% of its borrowing costs as part of the cost of major development assets and construction projects, compared to 85% in 2011.

Group Eliminations

Group 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 company determines that the refined products produced from intersegment purchases of crude feedstock have been sold to third parties. In 2012, $84 million of after-tax intersegment profit that was previously eliminated was recognized, compared to an elimination of profit of $22 million in 2011.

Results for 2011 compared with 2010

The net loss for Corporate, Energy Trading and Eliminations for 2011 was $331 million, compared to $448 million in 2010. In 2011, the Canadian dollar weakened in relation to the U.S. dollar, resulting in an after-tax unrealized foreign exchange loss of $161 million.

The operating loss for Corporate, Energy Trading and Eliminations for 2011 was $147 million, compared with an operating loss of $734 million in 2010. The lower operating loss in 2011 primarily related to after-tax claims of $243 million for the two Oil Sands Base upgrader fires paid by the company's captive insurance program in 2010 and an after-tax increase of $255 million in capitalized interest in 2011.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 43

6. FOURTH QUARTER 2012 ANALYSIS

Financial and Operational Highlights

Three months ended December 31 ($ millions, except as noted)		2012		2011

Net earnings
	Oil Sands	(1 040	)	790
	Exploration and Production	148		284
	Refining and Marketing	448		307
	Corporate, Energy Trading and Eliminations	(118	)	46

Total		(562	)	1 427

Operating earnings (loss) ⁽¹⁾
	Oil Sands	447		835
	Exploration and Production	143		372
	Refining and Marketing	448		307
	Corporate, Energy Trading and Eliminations	(38	)	(87	)

Total		1 000		1 427

Cash flow from (used in) operations ⁽¹⁾
	Oil Sands	1 090		1 417
	Exploration and Production	529		780
	Refining and Marketing	641		534
	Corporate, Energy Trading and Eliminations	(25	)	(81	)

Total		2 235		2 650

Production volumes (mboe/d)
	Oil Sands	378.7		356.8
	Exploration and Production	177.8		219.7

Total		556.5		576.5

(1): Non-GAAP financial measures. Operating earnings and cash flow from operations are reconciled below. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Segment Analysis

Oil Sands

The net loss for the Oil Sands segment was $1.040 billion for the fourth quarter of 2012, compared with net earnings of $790 million for the fourth quarter of 2011. The net loss in the fourth quarter of 2012 included an after-tax impairment charge of $1.487 billion against the Voyageur upgrader project. Oil Sands operating earnings for the fourth quarter of 2012 were $447 million, compared to $835 million for the fourth quarter of 2011. The decrease in operating earnings for Oil Sands operations, compared with the fourth quarter of 2011, was due primarily to lower average price realizations, lower overall margins due to product mix, and higher DD&A, partially offset by lower royalties. Cash flow from operations for the Oil Sands segment for the fourth quarter of 2012 was $1.090 billion, compared to $1.417 billion for the fourth quarter of 2011, and decreased mainly due to lower average price realizations and lower overall margins due to product mix.

Production volumes for Oil Sands operations averaged 342,800 bbls/d for the fourth quarter of 2012, compared to 326,500 bbls/d for the fourth quarter of 2011, and increased primarily due to the ongoing ramp up of production from Firebag. Production of upgraded product decreased to 281,100 bbls/d in the fourth quarter of 2012 from 310,100 bbls/d in the fourth quarter of 2011, primarily due to maintenance at upgrading facilities. Suncor's share of Syncrude production and sales increased to 35,900 bbls/d in the fourth quarter of 2012 from 30,300 bbls/d in the fourth quarter of 2011, due primarily to unplanned maintenance associated with a coker and hydrogen plant in the fourth quarter of 2011.

Exploration and Production

Exploration and Production net earnings were $148 million for the fourth quarter of 2012, compared to $284 million for the fourth quarter of 2011. The company reversed after-tax impairment charges of $177 million against assets in Syria. This reversal was partially offset by after-tax impairment charges of $65 million to reflect future development uncertainty relating to certain exploration assets in East Coast Canada and North America Onshore and an after-tax impairment charge of $63 million for certain North America Onshore properties due to a decline in price forecasts. In addition, the company recorded an after-tax provision of $44 million in North America Onshore relating to future commitments for unutilized pipeline capacity.

Exploration and Production operating earnings were $143 million for the fourth quarter of 2012, compared to $372 million for the fourth quarter of 2011. The decrease was due primarily to planned maintenance at Buzzard and Terra Nova, production declines in North America Onshore, the suspension of operations in Syria, partially offset by the receipt of insurance proceeds for the March 2012 drilling rig fire.

Cash flow from operations for Exploration and Production was $529 million for the fourth quarter of 2012, compared to $780 million for the fourth quarter of 2011. Cash flow from operations decreased due primarily to the same factors that decreased operating earnings.

Production volumes were 177.8 mboe/d in the fourth quarter of 2012, compared to 219.7 mboe/d in the fourth quarter of 2011. The decrease in production volumes was due mainly to planned maintenance programs at Terra Nova and Buzzard, and the suspension of operations in Syria, partially offset by higher production in Libya.

44 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Refining and Marketing

Refining and Marketing net and operating earnings were $448 million for the fourth quarter of 2012, compared with net and operating earnings of $307 million for the fourth quarter of 2011. The increase was due to high refining margins resulting from lower costs for feedstock, higher refined products sales and higher refinery utilization.

Refining and Marketing cash flow from operations was $641 million for the fourth quarter of 2012, compared to $534 million for the fourth quarter of 2011, and increased primarily due to the same factors affecting operating earnings.

Refined product sales averaged 87,000 m³/d in the fourth quarter of 2012, increasing from 81,600 m³/d in the fourth quarter of 2011, due primarily to a disruption of third-party hydrogen supply to the Edmonton refinery in the fourth quarter of 2011, and strong demand for distillate in the fourth quarter of 2012.

Corporate, Energy Trading and Eliminations

The net loss for Corporate, Energy Trading and Eliminations for the fourth quarter of 2012 was $118 million, compared to net earnings of $46 million for the fourth quarter of 2011. In the fourth quarter of 2012, the Canadian dollar weakened in relation to the U.S. dollar, resulting in an after-tax unrealized foreign exchange loss on U.S. dollar denominated long-term debt of $80 million. In the fourth quarter of 2011, the Canadian dollar strengthened in relation to the U.S. dollar.

The operating loss for Corporate, Energy Trading and Eliminations for the fourth quarter of 2012 was $38 million, compared to an operating loss of $87 million for the fourth quarter of 2011. The decrease in operating loss was due to the net recognition of $43 million of after-tax intersegment profit that was recognized as the related product had been sold to third parties. In the fourth quarter of 2011, the company eliminated $4 million after-tax of intersegment profit.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 45

Operating Earnings ⁽¹⁾

Three months ended December 31	Oil Sands			Exploration and Production			Refining and Marketing		Corporate, Energy Trading and Eliminations				Total
($ millions)	2012		2011	2012		2011	2012	2011	2012		2011		2012		2011

Net (loss) earnings as reported	(1 040	)	790	148		284	448	307	(118	)	46		(562	)	1 427
Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	—		—	—		—	—	—	80		(156	)	80		(156	)
Impairments (net of reversals), and write-offs	1 487		35	(5	)	57	—	—	—		23		1 482		115
Loss on significant disposals	—		10	—		—	—	—	—		—		—		10
Adjustments to provisions for assets acquired through the merger	—		—	—		31	—	—	—		—		—		31

Operating earnings (loss)	447		835	143		372	448	307	(38	)	(87	)	1 000		1 427

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

Cash flow from Operations ⁽¹⁾

Three months ended December 31		Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)		2012		2011		2012		2011		2012		2011		2012		2011		2012		2011

Net (loss) earnings		(1 040	)	790		148		284		448		307		(118	)	46		(562	)	1 427
Adjustments for:
	Depreciation, depletion, amortization and impairment	2 552		392		300		474		128		118		35		39		3 015		1 023
	Deferred income taxes	(357	)	270		2		(30	)	68		92		(35	)	(10	)	(322	)	322
	Accretion of liabilities	26		18		15		16		1		1		3		—		45		35
	Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	—		—		—		—		—		—		91		(179	)	91		(179	)
	Change in fair value of derivative contracts	—		—		1		—		(1	)	17		(20	)	34		(20	)	51
	Loss (gain) on disposal of assets	—		16		—		(9	)	(5	)	(5	)	—		—		(5	)	2
	Share-based compensation	17		31		3		8		10		19		13		21		43		79
	Exploration expenses	—		—		21		—		—		—		—		—		21		—
	Settlement of decommissioning and restoration liabilities	(70	)	(113	)	(10	)	(6	)	(8	)	(11	)	—		—		(88	)	(130	)
	Other	(38	)	13		49		43		—		(4	)	6		(32	)	17		20

Cash flow from (used in) operations		1 090		1 417		529		780		641		534		(25	)	(81	)	2 235		2 650
Decrease (increase) in non-cash working capital		35		(47	)	(117	)	9		(497	)	587		(481	)	(396	)	(1 060	)	153

Cash flow provided by (used in) operating activities		1 125		1 370		412		789		144		1 121		(506	)	(477	)	1 175		2 803

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

46 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

7. QUARTERLY FINANCIAL DATA

Financial Summary

Three months ended ($ millions, unless otherwise noted)			Dec 31 2012		Sept 30 2012	June 30 2012	Mar 31 2012	Dec 31 2011	Sept 30 2011	June 30 2011	Mar 31 2011

Total production (mboe/d)			556.5		535.3	542.4	562.3	576.5	546.0	460.0	601.3
	Oil Sands		378.7		378.9	337.8	341.1	356.8	362.5	277.2	360.6
	Exploration and Production		177.8		156.4	204.6	221.2	219.7	183.5	182.8	240.7

Revenues and other income
	Operating revenues, net of royalties ⁽¹⁾		9 444		9 512	9 599	9 653	9 906	10 235	9 255	8 943
	Other income		91		89	123	105	60	184	77	132

			9 535		9 601	9 722	9 758	9 966	10 419	9 332	9 075

Net (loss) earnings			(562	)	1 555	333	1 457	1 427	1 287	562	1 028
	per common share – basic (dollars)		(0.37	)	1.01	0.21	0.93	0.91	0.82	0.36	0.65
	per common share – diluted (dollars)		(0.37	)	1.01	0.20	0.93	0.91	0.76	0.31	0.65

Operating earnings ⁽²⁾			1 000		1 303	1 258	1 329	1 427	1 789	980	1 478
	per common share – basic (dollars)		0.65		0.85	0.81	0.85	0.91	1.14	0.62	0.94

Cash flow from operations ⁽²⁾			2 235		2 740	2 344	2 426	2 650	2 721	1 982	2 393
	per common share – basic (dollars)		1.46		1.78	1.51	1.55	1.69	1.73	1.26	1.52

Capital expenditures, including capitalized interest			2 205		1 670	1 606	1 478	1 814	1 519	1 941	1 576

ROCE ⁽²⁾ (%) for the twelve months ended			7.3		12.5	14.3	14.8	13.8	13.4	11.1	12.5

Common share information (dollars)
	Dividend per common share		0.13		0.13	0.13	0.11	0.11	0.11	0.11	0.10
	Share price at the end of trading
		Toronto Stock Exchange (Cdn$)	32.71		32.34	29.44	32.59	29.38	26.76	37.80	43.48
		New York Stock Exchange (US$)	32.98		32.85	28.95	32.70	28.83	25.44	39.10	44.84

(1): The company has reclassified 2011 operating revenues to reflect net presentation of certain transactions involving sales and purchases of third-party crude oil production in the Oil Sands segment that were previously presented on a gross basis.
(2): 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.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 47

Business Environment

Three months ended (average for the period ended, except as noted)		Dec 31 2012	Sept 30 2012	June 30 2012	Mar 31 2012	Dec 31 2011	Sept 30 2011	June 30 2011	Mar 31 2011

WTI crude oil at Cushing	US$/bbl	88.20	92.20	93.50	102.95	94.05	89.75	102.55	94.10
Dated Brent crude oil at Sullom Voe	US$/bbl	110.10	109.50	108.90	118.35	109.00	113.40	117.30	104.95
Dated Brent/Maya FOB price differential	US$/bbl	17.30	11.90	9.85	9.45	5.55	14.80	14.05	15.65
Canadian 0.3% par crude oil at Edmonton	Cdn$/bbl	84.35	84.70	84.45	92.80	98.20	92.50	103.85	88.40
WCS at Hardisty	US$/bbl	70.05	70.45	70.60	81.50	83.60	72.10	84.90	71.25
Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty	US$/bbl	18.15	21.75	22.90	21.45	10.45	17.65	17.65	22.85
Condensate at Edmonton	US$/bbl	98.10	96.00	99.40	110.00	108.70	101.65	112.40	98.35
Natural gas (Alberta spot) at AECO	Cdn$/mcf	3.05	2.20	1.85	2.50	3.40	3.70	3.75	3.80
New York Harbor 3-2-1 crack ⁽¹⁾	US$/bbl	35.95	37.80	31.95	25.80	22.80	36.45	29.25	19.40
Chicago 3-2-1 crack ⁽¹⁾	US$/bbl	27.85	35.15	27.85	18.80	19.20	33.30	29.70	16.45
Portland 3-2-1 crack ⁽¹⁾	US$/bbl	29.85	38.15	37.90	27.70	26.45	36.50	29.35	21.40
Gulf Coast 3-2-1 crack ⁽¹⁾	US$/bbl	27.35	33.95	29.30	25.45	20.40	33.10	27.30	18.50
Exchange rate	US$/Cdn$	1.00	1.00	0.99	1.00	0.98	1.02	1.03	1.01
Exchange rate (end of period)	US$/Cdn$	1.01	1.02	0.98	1.00	0.98	0.95	1.04	1.03

(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.

48 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Significant or Unusual Items Impacting Net Earnings

Trends in Suncor's quarterly earnings results and cash flow from operations are driven primarily by production volumes, which can be significantly impacted by major planned maintenance events – such as the maintenance that occurred at many Exploration and Production assets in the third and fourth quarters of 2012 and the maintenance that occurred at Upgrader 2 in Oil Sands in the second quarter of 2011 – and unplanned maintenance outages, such as the one that occurred at Upgrader 2 in the first half of 2012.

Trends in Suncor's quarterly earnings results and cash flow from operations are also affected by changes in commodity prices, refining crack spreads and foreign exchange rates.

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 significant one-time adjustments:

•: Given Suncor's view of the challenging economic outlook for the Voyageur upgrader project, the company performed an impairment test in the fourth quarter of 2012. Based on an assessment of expected future net cash flows, the company recorded an after-tax impairment charge of $1.487 billion.
•: The fourth quarter of 2012 included an after-tax impairment reversal of $177 million of the impairment charges recorded against its assets in Syria in the second quarter of 2012, due to a revised assessment of the net recoverable value of the underlying assets following the receipt of risk mitigation proceeds.
•: The fourth quarter of 2012 included total after-tax impairment charges of $128 million for certain exploration, development and production assets in the Exploration and Production segment.
•: The second quarter of 2012 included after-tax impairment charges and write-offs of $694 million against assets in Syria, which reflected the shut in of production due to political unrest and international sanctions. The company ceased recording all production and revenue from its Syrian assets in the fourth quarter of 2011.
•: The second quarter of 2011 included after-tax impairment charges of $514 million against assets in Libya, which reflected the shut in of production due to political unrest and international sanctions. Production from all major fields in Libya was successfully restarted by the first quarter of 2012.
•: The first quarter of 2011 included a $442 million adjustment to deferred income tax expense related to an increase in U.K. tax rates on oil and gas profits in the North Sea.
•: As part of its strategic business alignment subsequent to the merger with Petro-Canada, Suncor divested a number of non-core assets in its Exploration and Production segment throughout 2010 and 2011. Decreases in production volumes in 2011 and the second half of 2010 were due in part to the disposition of these assets. The resulting gains and losses on the disposition of these assets had one-time impacts on net earnings in the quarters in which they occurred.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 49

8. CAPITAL INVESTMENT UPDATE

The Capital Investment Update section contains forward-looking information. See the Advisory – Forward-Looking Information section of this MD&A for the material risks and assumptions underlying this forward-looking information.

Capital and Exploration Expenditures by Segment

Year ended December 31 ($ millions)	2012		2011		2010

Oil Sands	4 957		5 100		3 709
Exploration and Production	1 261		874		1 274
Refining and Marketing	646		633		667
Corporate, Energy Trading and Eliminations	95		243		360

Total	6 959		6 850		6 010
Less: capitalized interest on debt	(587	)	(559	)	(301	)

	6 372		6 291		5 709

Capital and Exploration Expenditures by Type ^(1)(2)(3)

Year ended December 31 ($ millions)		Sustaining	Growth	Total

Oil Sands		2 293	2 114	4 407
	Oil Sands Base	1 342	604	*1 946*
	In Situ	625	810	*1 435*
	Oil Sands Ventures	326	700	*1 026*
Exploration and Production		233	994	1 227
Refining and Marketing		637	6	643
Corporate, Energy Trading and Eliminations		91	4	95

		3 254	3 118	6 372

(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 2012, Suncor spent $6.372 billion on capital for property, plant and equipment and exploration activities, and capitalized $587 million of interest on debt towards major development assets and construction projects. Activity in 2012 included the following.

Oil Sands Base

Oil Sands Base capital expenditures were $1.946 billion, of which $1.342 billion was directed towards sustaining activities. Sustaining capital expenditures related primarily to planned maintenance events and the company's TRO_TM initiative, and included $496 million towards the construction of infrastructure and mature fine tailings drying facilities that will facilitate the company's TRO_TM process going forward. The company commissioned the TRO_TM project in the second quarter of 2012.

Oil Sands Base growth capital focused on infrastructure required to support growth in production from Oil Sands operations, including the Wood Buffalo pipeline, which connects the company's Athabasca terminal at the base plant in Fort McMurray to other third-party pipeline infrastructure in Cheecham, Alberta, and the first two of four new storage tanks in Hardisty, Alberta, which will be connected to the Enbridge Mainline system in 2013. Both assets are operated by third parties and subject to long-term arrangements.

In Situ

In Situ capital and exploration expenditures were $1.435 billion, of which $810 million was directed towards growth projects. As a result of the successful execution of Firebag Stage 4, the company commissioned the cogeneration units in the fourth quarter ahead of schedule, while the central processing facilities operated at 10% capacity throughout the fourth quarter of 2012. Steam injection was in progress for both Stage 4 well pads and first oil was achieved by the end of 2012. Capital expenditures for Firebag Stage 4 were $445 million in 2012, bringing total project expenditures to $1.634 billion.

50 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

In addition, Suncor continues to construct an insulated pipeline, which will transport bitumen without the requirement for additional diluent between Firebag and Suncor's Athabasca terminal starting in the second quarter of 2013.

In Situ sustaining capital expenditures of $625 million were directed primarily to the design and construction of well pads that are expected to maintain existing production levels from MacKay River and Firebag in future years. In December 2012, the company began steaming wells on a new pad at MacKay River. The company anticipates first oil from these wells in the first quarter of 2013.

Oil Sands Ventures

Suncor's share of capital expenditures for the Syncrude joint operation was $326 million, which included $150 million for mine train replacement at the Mildred Lake mining area and equipment relocation at the Aurora mining area, and $63 million for a composite tailings plant and a centrifuge plant as part of its tailings management plans.

Oil Sands Ventures growth capital expenditures were $700 million in 2012. The Voyageur upgrader project expenditures were focused on validating project scope, developing the project execution plan, engineering and progressing site preparation. The Fort Hills mining project expenditures were directed towards engineering, progressing with site preparation and the procurement of long-lead items. The Joslyn North mining project, which is in the earliest stage of development of the three projects, was focused on design engineering and site preparation.

Exploration and Production

Exploration and Production capital and exploration expenditures were $1.227 billion in 2012, of which $994 million was directed towards growth and exploration.

Growth spending included $217 million for Golden Eagle, which focused on detailed engineering and construction of topsides and platform jackets.

The company and co-owners of Hebron announced project sanction in the fourth quarter of 2012, for which Suncor has a 22.729% interest. Growth spending for Hebron was $200 million in 2012, which focused on engineering, site preparation, and the start of construction of the gravity-based structure.

Other growth capital included development drilling for Hibernia, White Rose, Terra Nova and Buzzard, and for North America Onshore in the Cardium oil formation in Western Canada, which started producing late in 2012.

During 2012, Suncor participated in two exploration wells offshore Norway: the second appraisal well for the Beta discovery and the first exploration well for the PL 477 licence, known as Cooper. The wells were deemed to be dry holes; therefore, the related exploration expenditures were expensed in 2012. For the Beta discovery, the company will continue to evaluate the prospect, and plans to acquire new seismic data in 2013 and participate in further appraisal drilling in 2014.

The company also participated in various exploration wells offshore the U.K. – including the Northern Terrace area of the Buzzard field and the Romeo prospect. The Northern Terrace well was successful while results for the Romeo well are currently being evaluated.

Sustaining capital expenditures focused primarily on the planned maintenance programs for East Coast Canada assets, including the replacement of the FPSO water injection swivel and subsea infrastructure at Terra Nova, and the propulsion system for the White Rose FPSO.

Other Capital Expenditures

Refining and Marketing spent $643 million on capital expenditures in 2012, largely focused on planned maintenance at the Sarnia and Commerce City refineries, and the lubricants plant. The company also completed the project to reduce benzene content in gasoline production at the Commerce City refinery.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 51

Significant Growth Projects Update

Description

Current
Cost Estimate
($ millions)

Project
Spend to Date
($ millions)

Target
Completion

Estimated
% Complete
Engineering

Estimated
% Complete
Construction

Operated

Firebag Stage 4

62.5 mbbls/d bitumen

1 668

1 634

Q1 2013

100

Non-operated ⁽¹⁾

Golden Eagle ⁽²⁾

18.7 mboe/d (net)

1 000

280

Q4 2014/

(±10%

)

Q1 2015

Hebron ⁽²⁾

34.2 mboe/d (net)

3 185

306

Q4 2017

(±10%

)

(1): Estimated completion percentages not provided for non-operated projects. Cost estimates are based on the most recent estimate provided by the operator.
(2): Cost Estimate and Project Spend to Date figures do not include fair market value adjustments recorded as part of the merger with Petro-Canada in 2009.

The table above provides a review and update at December 31, 2012 of major growth projects that have been sanctioned for development by the company. Other growth projects, such as the Fort Hills and Joslyn North oil sands mining projects and the Voyageur upgrader project, have not yet received a final investment decision by the company or its Board of Directors and the respective owners of each of the individual projects. These projects are discussed under Other Capital Projects below.

Firebag Stage 4 is nearly complete and expected to be approximately 15% under the announced cost estimate of $2.0 billion. The company anticipates that bitumen production from Firebag will reach production capacity of 180,000 bbls/d over the next year.

The field development plan for the Golden Eagle Area Development includes stand-alone facilities designed for 70,000 boe/d of gross production. Activity in 2013 will focus on the completion and installation of platform jackets and wellhead topsides, followed by the start of development drilling. Capital expenditures for 2012 were $217 million, bringing total project expenditures to date to $280 million. The cost estimate of $1.0 billion has increased over the prior year primarily due to a change in the foreign exchange rate.

The co-owners for the Hebron project officially sanctioned development on December 31, 2012. The Hebron field includes a gravity-based structure design supporting an oil production rate of 150,000 bbls/d. The initial gross cost estimate for this project is $14 billion, of which Suncor's total project expenditures to date associated with the project scope are $306 million.

Other Capital Projects

Suncor also anticipates 2013 capital expenditures to be focused on the following projects and initiatives:

Oil Sands Base and In Situ

The company plans to focus growth capital efforts on optimizing the existing asset base by building new infrastructure to enhance marketing flexibility and takeaway capacity, and through the advancement of various debottlenecking projects in mining and extraction, and In Situ. These projects will be less capital intensive but are expected to result in high returns and efficiencies throughout the Oil Sands operations. The company has commenced a debottlenecking project at the MacKay River central processing facility, which is expected to increase production capacity to 38,000 bbls/d by 2015.

Sustaining capital includes planned maintenance events for the Upgrader 1 and Upgrader 2 facilities, a central processing facility at Firebag, and refurbishment of the Upgrader 1 hydrogen plant. Infrastructure and facilities to support the ongoing TRO_TM process will continue in 2013.

Suncor plans to focus on the completion of the well pads in Firebag Stage 4, and continue infill well programs and development drilling in Firebag and MacKay River to maintain an inventory of future bitumen supply as production from older wells experience natural declines.

Oil Sands Ventures

Capital expenditures in 2013 for Syncrude are expected to focus on the mine train replacement for the Mildred Lake mining area, the mine train relocation at the Aurora mining area and sustaining maintenance initiatives.

Suncor continues to work closely with co-owners on evaluating and progressing Oil Sands Venture growth projects, including the Fort Hills and Joslyn North mining projects, and the Voyageur upgrader.

The partners of the Fort Hills mining project expect to reach a sanction decision in the second half of 2013.

52 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Subject to the owners sanctioning the project, post sanction activities are expected to include the commencement of detailed engineering design, bulk equipment and material procurement, and site construction.

Suncor plans to provide an update on the targeted timing for a sanction decision on the Joslyn project when available. Design engineering and site preparation activities will be a continued focus in 2013.

Exploration and Production

In addition to Golden Eagle and Hebron, capital expenditures for Exploration and Production operations are expected to focus on development drilling for Terra Nova, Hibernia, White Rose and Buzzard, the procurement of subsea equipment for the development of the HSEU, development of the South White Rose Extension initially as an alternate gas storage site that will permit ongoing development and production, and reliability enhancement projects for Buzzard.

In the North Sea, the company will act as operator for a planned exploration well in licence P1658 (Block 20/05b) known as the Scotney prospect. In addition, the company plans to participate in two non-operated exploration wells in the U.K. and evaluate development options on the Buzzard Northern Terrace and CPZ areas in 2013.

The company is participating in two non-operated exploration wells in Norway in 2013. On the Beta licence, Suncor will continue to evaluate the prospect, and plans to acquire new seismic data in 2013 and participate in further appraisal drilling in 2014.

For North America Onshore operations, the company plans to continue developing its play in the Cardium oil formation in Western Canada and further delineate its play in the Kobes/Altares region of B.C. in the Montney shale gas formation.

Refining and Marketing

The company expects that sustaining capital will focus on planned maintenance events and routine asset replacement, and that growth capital is expected to be deployed on projects to prepare the Montreal refinery to receive shipments of western crude feedstock.

Renewable Energy

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 53

9. FINANCIAL CONDITION AND LIQUIDITY

Indicators

At December 31 ($ millions, except as noted)		2012	2011

Return on Capital Employed (%) ⁽¹⁾⁽²⁾
	Excluding major projects in progress	7.3	13.8
	Including major projects in progress	5.9	10.1

Net debt to cash flow from operations ⁽³⁾ (times)		0.7	0.7

Interest coverage on long-term debt (times)
	Earnings basis ⁽⁴⁾	7.9	10.7
	Cash flow from operations basis ⁽³⁾⁽⁵⁾	17.6	16.4

(1): Non-GAAP financial measure. The calculations for ROCE are detailed in the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): The after-tax impairment of $1.487 billion for the Voyageur upgrader project impacted ROCE by approximately 4% in 2012.
(3): 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.
(4): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
(5): Cash flow from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest.

Capital Resources

Suncor's capital resources consist primarily of cash flow from operations, cash and cash equivalents, and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2013 capital spending program of $7.3 billion and meet current and long-term working capital requirements through existing cash balances and short-term investments, cash flow from operations, available committed credit facilities, issuing commercial paper and issuing long-term notes or debentures. The company's cash flow from operations 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. If additional capital is required, Suncor's management believes adequate additional financing will be available to the company in debt capital markets at commercial terms and rates.

Cash and cash equivalents increased by $590 million to $4.393 billion during 2012, primarily due to strong cash flow from operations that exceeded capital expenditures, and the receipt of $300 million in risk mitigation proceeds related to the company's Syrian assets, partially offset by $1.451 billion of share repurchases, and $756 million in dividends. For the year ended December 31, 2012, the company's net debt to cash flow from operations measure was 0.7 times, which met management's target of less than 2.0 times.

Unutilized lines of credit at December 31, 2012 were $4.735 billion, compared to $4.428 billion at December 31, 2011.

A summary of available and utilized credit facilities is as follows:

At December 31, 2012 ($ millions)

Fully revolving for a period of one year after term-out date (November 2013)		2 000
Fully revolving and expires in 2013-2014		924
Fully revolving for a period of four years and expires in 2016		3 000
Can be terminated at any time at the option of the lenders		379

Total available credit facilities		6 303
Less:
Credit facilities supporting outstanding commercial paper		775
Credit facilities supporting standby letters of credit		793

Total unutilized credit facilities		4 735

Financing Activities

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

Suncor's interest on debt (before capitalized interest) in 2012 was $643 million, compared to $661 million in 2011. The reduction of short-term debt and the repayment of certain medium term notes in the third quarter of 2011 resulted in lower interest in 2012 compared to 2011, partially offset by the interest paid on two new finance leases in 2012.

54 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Change in Net Debt

($ millions)

Net debt – December 31, 2011		6 976
Decrease in net debt		(344	)

Net debt – December 31, 2012		6 632

Decrease in net debt
	Cash flow from operations	9 745
	Capital and exploration expenditures and Other investments	(6 962	)
	Proceeds from divestitures	68
	Dividends less proceeds from exercise of share options	(568	)
	Repurchase of common shares	(1 451	)
	Change in non-cash working capital and other	(650	)
	Foreign exchange on cash, long-term debt and other balances	162

		344

At December 31, 2012, Suncor's net debt was $6.632 billion, compared to $6.976 billion at December 31, 2011. During 2012, net debt decreased by $344 million, largely due to cash flow from operations that exceeded capital and exploration expenditures, the receipt of $300 million in risk mitigation proceeds related to the company's Syrian assets, the impact of the strengthening Canadian dollar relative to the U.S. dollar on the valuation of long-term debt, partially offset by cash returned to shareholders in the form of share repurchases and dividends, and an increase in non-cash working capital.

Total Debt to Total Debt Plus Shareholders' Equity

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 60% of its total debt plus shareholders' equity. At December 31, 2012, total debt to total debt plus shareholders' equity was 22% (December 31, 2011 – 22%). The company is also currently in compliance with all operating covenants.

At December 31 ($ millions, except as noted)		2012	2011

	Short-term debt	776	763
	Current portion of long-term debt	311	12
	Long-term debt	9 938	10 004

Total debt		11 025	10 779
	Less: Cash and cash equivalents	4 393	3 803

Net debt		6 632	6 976

Shareholders' equity		39 223	38 600

Total debt plus shareholders' equity		50 248	49 379

Total debt to total debt plus shareholders' equity (%)		22	22

Short-Term Investments

The company has invested excess cash in short-term financial instruments that are presented as cash and cash equivalents. The objectives of the company's short-term investment portfolio are to ensure the preservation of capital, maintain adequate liquidity to meet Suncor's cash flow requirements and deliver competitive returns consistent with the quality and diversification of investments within acceptable risk parameters. The maximum weighted average term to maturity of the short-term investment portfolio will not exceed six months, and all investments will be with counterparties with investment grade debt ratings. As at December 31, 2012, the weighted average term to maturity of the short-term investment portfolio was approximately 30 days. In 2012, the company earned approximately $32.0 million of interest income on this portfolio.

Credit Ratings

The following information regarding the company's credit ratings is provided as it relates to the company's cost of funds and liquidity and indicates whether or not the company's credit ratings have changed. In particular, the company's ability to access unsecured funding markets and to engage in certain collateralized business activities on a cost-effective basis is primarily dependent upon maintaining competitive credit ratings. A lowering of the company's credit rating may also have potentially adverse consequences for the company's funding capacity or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or hedging transactions, and may require the company to post additional collateral under certain contracts.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 55

The company's long-term senior debt ratings are:

Long-Term Senior Debt	Rating		Long-Term Outlook

Standard & Poor's	BBB+		Stable
Dominion Bond Rating Service	A (low	)	Stable
Moody's Investor Services	Baa1		Stable

The company's commercial paper ratings are:

Commercial Paper	Cdn$ Rating		US$ Rating

Standard & Poor's	A-1 (low	)	A-2
Dominion Bond Rating Service	R-1 (low	)	Not rated
Moody's Investors Service	Not rated		P-2

In 2012, Moody's Investors Service upgraded the company's long-term senior debt rating from Baa2 to Baa1, and changed its long-term outlook from positive to stable. All other credit ratings are consistent with 2011. Refer to the Description of Capital Structure – Credit Ratings section of Suncor's 2012 AIF for a description of credit ratings listed above.

Common Shares

Outstanding Shares

December 31, 2012 (thousands)

Common shares		1 523 057
Common share options – exercisable and non-exercisable		47 366
Common share options – exercisable		29 879

As at February 22, 2013, the total number of common shares outstanding was 1,523,644,237, and the total number of exercisable and non-exercisable common share options outstanding was 75,233,036. Once exercisable, each outstanding common share option is convertible into one common share.

Share Repurchases

During the first quarter of 2012, the company obtained regulatory approval from the Toronto Stock Exchange (TSX) to recommence a Normal Course Issuer Bid (the 2011 NCIB) under which the company was authorized to purchase for cancellation up to an additional $1.0 billion of Suncor's common shares between February 28, 2012 and September 5, 2012.

For the 2011 NCIB, the company repurchased 33,032,400 shares during 2012 at an average price of $30.28 per share, for a total repurchase cost of $1.0 billion.

During the second quarter of 2012, the company obtained regulatory approval in Canada for a program to issue put options on the company's common shares as part of the 2011 NCIB. Under this program, Suncor was permitted to issue put options to a Canadian financial institution, which entitled the purchaser, on the expiry date of the relevant options, to sell to Suncor a specified number of Suncor common shares at a price agreed to on the date the options were issued.

The company received $1.3 million in premiums for issuing 1,250,000 put options. No shares were repurchased through the exercise of put options, as all options expired unexercised. Cash premiums received by Suncor for issuing the put options were recorded as an increase to shareholders' equity and netted against the cash paid for the purchase of common shares for cancellation. Premiums received by Suncor for issuing put options do not impact the company's earnings.

In the third quarter of 2012, the company obtained regulatory approval for another Normal Course Issuer Bid (the 2012 NCIB) with the TSX authorizing the purchase for cancellation of up to $1.0 billion of its common shares. The 2012 NCIB commenced on September 20, 2012 and will end no later than September 19, 2013. Pursuant to the 2012 NCIB, Suncor has agreed that it will not purchase more than 38,392,005 common shares, which represented approximately 2.5% of issued and outstanding common shares as at September 14, 2012. The company subsequently announced it had entered into an automatic purchase plan with a designated broker to allow for the repurchase of common shares during scheduled and unscheduled share-trading blackout periods. Shareholders may obtain a copy of the company's Notice of Intention to make a Normal Course Issuer Bid by contacting Investor Relations.

For the 2012 NCIB, the company repurchased 13,829,900 shares during 2012 at an average price of $32.68 per share, for a total repurchase cost of $452 million. Subsequent to December 31, 2012, the company had repurchased an additional 3,915,646 shares under the 2012 NCIB at an average price of $32.45 per share for a total repurchase cost of $127 million, as of February 22, 2013.

56 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

At December 31 ($ millions, except as noted)		2012		2011

Share repurchase activities (thousands of common shares)
	Shares repurchased directly	46 862		17 128
	Shares repurchased through exercise of put options	—		—

		46 862		17 128

Share repurchase cost ($ millions)
	Repurchase cost	1 452		500
	Option premiums received	(1	)	—

		1 451		500

Weighted average repurchase price per share, net of option premiums (dollars)		30.96		29.19

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

In addition to the enforceable and legally binding obligations quantified in the table presented below, Suncor has other obligations for goods and services that were entered into in the normal course of business, which may terminate on short notice, including commitments for purchase of commodities for which an active, highly liquid market exists, and which are expected to be re-sold shortly after purchase.

The company does not believe 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 condition or financial performance, including liquidity and capital resources.

In the normal course of business, the company is obligated to make future payments, including contractual obligations and non-cancellable commitments.

	Payments Due by Period
($ millions)	Total	2013	2014 to 2015	2016 to 2017	Thereafter

Fixed and revolving-term debt ⁽¹⁾	19 950	1 662	1 543	1 112	15 633
Finance lease payments	2 487	94	189	189	2 015
Decommissioning and restoration costs ⁽²⁾	8 154	413	779	694	6 268
Operating lease agreements, pipeline capacity and energy services commitments	13 721	1 572	2 276	1 697	8 176
Exploration work commitments	272	67	205	—	—
Other long-term obligations ⁽³⁾	449	149	300	—	—

Total	45 033	3 957	5 292	3 692	32 092

(1): Includes debt that is redeemable at Suncor's option and interest payments on fixed-term debt.
(2): Represents the undiscounted amount of obligations associated with land and tailings reclamation and site restoration and decommissioning costs.
(3): Includes the Libya ESPA signature bonus and merger consent, and Fort Hills purchase obligations. See the Accrued Liabilities and Other – Long-Term Financial Liabilities note to the 2012 audited Consolidated Financial Statements.

Transactions with Related Parties

The company enters into transactions with related parties in the normal course of business. These transactions primarily include sales to associated entities in the company's Refining and Marketing segment. For more information on these transactions and for a summary of Compensation of Key Management Personnel, refer to the Related Party Disclosures note to the 2012 audited Consolidated Financial Statements.

Financial Instruments

Suncor periodically enters into derivative contracts for risk management purposes. The derivative contracts hedge risks related to purchases and sales of commodities, to manage exposure to interest rates and to hedge risks specific to individual transactions. For the year ended December 31, 2012, the pre-tax earnings impact for risk management activities was a gain of $1 million (2011 – pre-tax loss of $22 million).

The company's Energy Trading business uses crude oil, natural gas, refined product and other derivative contracts to generate net earnings. For the year ended December 31, 2012, the pre-tax earnings impact for Energy Trading activities was a gain of $246 million (2011 – pre-tax gain of $301 million).

Gains or losses related to derivatives are recorded as Other Income in the Consolidated Statements of Comprehensive Income.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 57

($ millions)	Risk Management		Energy Trading		Total

Fair value of contracts outstanding – January 1, 2011	13		(87	)	(74	)
Fair value of contracts realized during the year	9		(248	)	(239	)
Changes in fair value during the year	(22	)	301		279

Fair value of contracts outstanding – December 31, 2011	—		(34	)	(34	)
Fair value of contracts realized during the year	(2	)	(255	)	(257	)
Changes in fair value during the year	1		246		247

Fair value of contracts outstanding – December 31, 2012	(1	)	(43	)	(44	)

The fair value of derivatives are recorded in the Consolidated Balance Sheets as follows:

Fair value of derivative contracts at December 31 ($ millions)	2012		2011

Accounts receivable	53		37
Accounts payable	(97	)	(71	)

	(44	)	(34	)

Risks Associated with Derivative Financial Instruments

Suncor may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to fulfil their obligations under these contracts. The company minimizes this risk by entering into agreements with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties. Suncor's exposure is limited to those counterparties holding derivative contracts with net positive fair values at a reporting date.

Suncor's risk management activities are subject to periodic reviews by management to determine appropriate hedging requirements based on the company's tolerance for exposure to market volatility, as well as the need for stable cash flow to finance future growth. Energy Trading activities are governed by a separate risk management group that reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including assumptions made in the calculation of fair value, a sensitivity analysis of the effect of changes in commodity prices on our derivative financial instruments, and additional discussion of exposure to risks and mitigation activities, see the Financial Instruments and Risk Management note in our 2012 audited Consolidated Financial Statements.

58 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

10. ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

Changes in Accounting Policies

There were no changes to Suncor's significant accounting policies in 2012, which are described in note 3 to the December 31, 2012 audited Consolidated Financial Statements.

Recently Announced Accounting Standards

Financial Instruments: Recognition and Measurement

In November 2009, as part of the International Accounting Standards Board's (IASB) project to replace International Accounting Standard (IAS) 39 Financial Instruments: Recognition and Measurement, the IASB issued the first phase of IFRS 9 Financial Instruments. It contained requirements for the classification and measurement of financial assets, and was updated in October 2010 to incorporate financial liabilities. The standard is applicable for annual periods starting on or after January 1, 2015. The full impact of this standard will not be known until the phases addressing hedging and impairments have been completed.

Fair Value Measurements

In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for most fair value measurements, clarifies the definition of fair value, and enhances the disclosures on fair value measurement. Prospective application of this standard is effective for fiscal years beginning on or after January 1, 2013. The company does not expect any changes to its fair value measurements; however, expanded disclosures on fair value measurements are required.

Offsetting Financial Assets and Financial Liabilities

In December 2011, the IASB issued amendments to IFRS 7 Financial Instruments: Disclosures and IAS 32 Financial Instruments: Presentation to clarify the current offsetting model and develop common disclosure requirements to enhance the understanding of the potential effects of offsetting arrangements. Retrospective application of amendments to IFRS 7 are effective for annual and interim periods starting on or after January 1, 2013. Retrospective application of amendments to IAS 32 are effective for annual periods starting on or after January 1, 2014, with earlier application permitted. The adoption of these amended standards is not expected to have a material impact on the company's financial statements; however, expanded disclosures on financial instruments that are offset in the Consolidated Balance Sheets will be required.

Presentation of Items of Other Comprehensive Income

In June 2011, the IASB issued amendments to IAS 1 Presentation of Items of Other Comprehensive Income to group items presented within Other Comprehensive Income based on whether they may be subsequently reclassified to net earnings. The amendment is required to be retrospectively adopted for periods beginning on or after July 1, 2012. The company does not expect a significant change to its presentation of items of other comprehensive income.

Scope of a Reporting Entity

In May 2011, the IASB issued IFRS 10 Consolidated Financial Statement, IFRS 11 Joint Arrangements, IFRS 12 Disclosures of Interests in Other Entities, and amendments to IAS 27 Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures.

IFRS 10 creates a single consolidation model by revising the definition of control in order to apply the same control criteria to all types of entities, including joint arrangements, associates and structured entities. IFRS 11 establishes a principle-based approach to the accounting for joint arrangements by focusing on the rights and obligations of the arrangement and limits the application of proportionate consolidation accounting to arrangements that meet the definition of a joint operation. Arrangements that meet the definition of a joint venture are required to apply the equity method of accounting. IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and unconsolidated structured entities. IAS 27 has been amended to conform to the changes made in IFRS 10 but retains the guidance on separate financial statements. IAS 28 has also been amended to conform to the changes made in IFRS 10 and 11.

Retrospective application of these standards with relief for certain transactions is effective for fiscal years beginning on or after January 1, 2013. The company has identified two existing joint arrangements in the Refining and Marketing segment that will be required to change from proportionate consolidation to equity accounting as a result of IFRS 11. This change will not have a material impact to the consolidated financial statements, but will result in the netting of revenues and expenses (2012 – approximately $100 million and $90 million, respectively) for these entities into Other Income. In addition, the

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 59

company's net investment in these entities will be presented in Other Assets.

Employee Benefits

In June 2011, the IASB issued amendments to IAS 19 Employee Benefits, which revises the recognition, presentation and disclosure requirements for defined benefit plans. The revised standard requires immediate recognition of actuarial gains and losses in other comprehensive income thereby eliminating the previous options that were available, changes the calculation and presentation of the interest cost component of annual pension expense and enhances the disclosure requirements for defined benefit plans. Retrospective application of this standard is effective for fiscal years beginning on or after January 1, 2013. The company anticipates a net incremental increase to expenses of approximately $50 million for 2012 as a result of these amendments.

Production Stripping Costs

In October 2011, the IASB issued International Financial Reporting Interpretation Committee (IFRIC) 20 Stripping Costs in the Production Phase of a Surface Mine. This interpretation requires the capitalization and depreciation of stripping costs in the production phase if an entity can demonstrate that it is probable that future economic benefits will be realized, the costs can be reliably measured and the entity can identify the component of the ore body for which access has been improved. Retrospective application of this interpretation is effective for annual periods beginning on or after January 1, 2013. The company does not anticipate significant impacts as a result of this interpretation as the company generally performs stripping activities that provide access to ore to be mined in the current period.

Critical Accounting Estimates and Judgments

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues, expenses, gains, losses, and disclosures of contingencies. These estimates and assumptions are subject to change based on experience and new information.

Critical accounting estimates are those estimates that require management to make assumptions about matters that are highly uncertain at the time the estimate is made, and those estimates where changes in critical assumptions that are within a range of reasonably possible outcomes would have a material impact on the company's financial condition, changes in financial condition or financial performance.

Critical accounting estimates are reviewed annually by the Audit Committee of the Board of Directors. The following are the critical accounting estimates used in the preparation of Suncor's December 31, 2012 audited Consolidated Financial Statements.

Oil and Gas Reserves and Resources

Certain measurements of depletion, depreciation, amortization, impairment and decommissioning and restoration obligations are determined in part based on the company's estimate of oil and gas reserves and resources. Although not reported as part of the company's 2012 audited Consolidated Financial Statements, these estimates of reserves and resources can have a significant impact on the Consolidated Financial Statements.

The estimation of reserves involves the exercise of professional judgment. Reserves and certain resources were evaluated or reviewed as at December 31, 2012 by qualified reserves evaluators in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Where possible assumptions reflect market and regulatory conditions existing at December 31, 2012, which could differ significantly from other points in time throughout the year or in future periods.

Oil and Gas Activities

The company is required to use judgment when designating the nature of oil and gas activities as exploration, evaluation, development or production, and when determining whether the initial costs of these activities are capitalized.

Exploration and Evaluation Costs

The costs of drilling exploratory wells are initially capitalized pending the evaluation of commercially recoverable resources. The determination that commercial resources have been discovered requires judgment. If a judgment is made that there are no commercially recoverable resources, the associated exploration costs are charged to exploration expense. Evaluation costs incurred when management is assessing whether there are commercially recoverable resources and designing development and front-end engineering plans are capitalized. Exploration and evaluation assets are subject to ongoing technical, commercial and management review

60 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

to confirm the continued intent to develop and extract the underlying resources. When management is making this assessment, changes to project economics, quantities of resources, expected production techniques, unsuccessful drilling, and estimated production costs and projected capital expenditures are important factors. If a judgment is made that extraction of the resources is not commercially viable, the associated exploration and evaluation assets are impaired and charged to depreciation, depletion, amortization and impairment expense.

Development Costs

Management uses judgment to determine when exploration and evaluation assets are reclassified to property, plant and equipment. This decision considers several factors, including the existence of reserves, the receipt of the appropriate approvals from regulatory bodies and the company's internal project approval processes. After an oil and gas property is reclassified to property, plant and equipment, all subsequent development costs are capitalized.

Impairment of Assets

A cash-generating unit (CGU) is the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of the company's assets into CGUs requires significant judgment with respect to the integration between assets, the use of shared infrastructure, the existence of active markets for the company's products and the way in which management monitors operations.

At the end of each reporting period, the company is required to identify events or conditions that indicate that the net carrying value of a CGU might be impaired. Management uses judgment to determine if a specific event or condition is an indication of impairment for a CGU. If any such indication exists, the company must complete an impairment assessment for the CGU. A CGU is impaired when the net carrying value of the CGU exceeds management's estimate of the recoverable amount of the CGU, which is the higher of the CGU's fair value less costs to sell and its value-in-use.

Regardless of any indication of impairment, the company must complete an annual impairment assessment for any CGU, or group of CGUs, whose net carrying value includes indefinite-life intangible assets or an allocation of goodwill. For Suncor, this includes impairment assessments of the Oil Sands segment and the Refining and Marketing segment. For 2012, the company completed this review as at July 31, 2012, and determined that the underlying CGUs were not impaired.

At the end of each reporting period, the company must exercise judgment to determine if there are indicators that conditions causing a previous impairment have reversed. Where new estimates of recoverable amount exceed net carrying value, previously recorded impairment adjustments are reversed, up to the amount of the original impairment. An impairment of goodwill cannot be reversed.

For Suncor, the estimated recoverable amount of a CGU is predominantly determined using discounted net future cash flow models. The key assumptions the company uses for estimating future cash flows are estimates of future commodity prices, reserves and resources estimates, expected production volumes, estimated future operating and development costs, and estimated refining margins. The estimated useful life of the CGU, the timing of future cash flows and discount rates are also important assumptions made by management. Management may also be required to make judgments about the likelihood of occurrence of a future event, which may have an impact on key assumptions. Changes to these estimates and judgments will affect the recoverable amount of a CGU and may require a material impairment to the net carrying value of that CGU.

The company also assesses the impairment of assets when they are classified as held for sale or when they are reclassified from Exploration and evaluation assets to Property, plant and equipment. Assets held for sale are measured at the lower of net carrying value and fair value less costs to sell, which may be determined based on expected sale proceeds.

The following discusses important impairment assessments completed during 2012:

Voyageur Upgrader Project

At December 31, 2012, Suncor's view was that the economic outlook for the Voyageur upgrader project was challenged and, therefore, performed an impairment test, resulting in an after-tax impairment charge of $1.487 billion. The net recoverable amount was estimated under a fair value less costs to sell methodology and determined using an expected cash flow approach.

Key assumptions included current forecasts for the price of commodities, an estimate of price realizations, estimates of future operating and capital expenditures, and an after-tax risk-adjusted discount rate of 10%. As at December 31, 2012, the company's carrying value for assets relating to the Voyageur upgrader project was approximately $345 million.

Syria

As a result of political unrest and international sanctions announced in December 2011, the company suspended its

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 61

operations in Syria and ceased recording production or revenues. Suncor performed an impairment test on its assets in Syria at December 31, 2011 and determined that the assets were not impaired at that time.

As there had been no resolution of the political situation at the end of the second quarter of 2012, another impairment test on the company's Syrian assets was performed. As a result, the company recognized an after-tax impairment charge of $604 million against Property, plant and equipment, a write-down of receivables of $67 million and a write-down of $23 million against current assets.

During the fourth quarter of 2012, the company received risk mitigation proceeds of $300 million in respect of its Syrian operations. A portion, or all of these proceeds, may be repayable if operations in Syria resume and, therefore, were recorded as a provision in 2012 rather than to earnings. After receipt of the risk mitigation proceeds, an additional impairment test was performed at December 31, 2012, resulting in an after-tax impairment reversal of $177 million against assets in Syria.

The carrying value as at December 31, 2012 was based on a net recoverable amount that was estimated under a value-in-use methodology and determined using an expected cash flow approach, under probability weighted scenarios representing i) resumption of operations in one year, ii) resumption of operations in five years, and iii) total loss. The two scenarios where the company resumes operations incorporated repayment of the risk mitigation proceeds in accordance with the terms of the agreement.

Scenarios involving the company resuming normal operations used current forecasts for the price of commodities, the company's estimate of price realizations, estimates of operating and development expenditures based on the field development anticipated by Suncor's business plans prior to the suspension of operations, a discount rate (19%) that represented management's best estimate of the ongoing risk involved with operating in Syria, and management's best estimate of the incremental rebuilding costs to bring operations back on-stream. Management's forecasts for production were based on the most recently available estimate of future production volumes evaluated by Suncor's internal qualified reserves evaluators. The resulting carrying value of the company's property, plant, and equipment in Syria net of the risk mitigation provision at December 31, 2012 was approximately $130 million.

Fair Value of Financial Instruments

To estimate the fair value of financial instruments, the company uses quoted market prices when available, or models that use observable market data. In addition to market information, Suncor incorporates transaction-specific details that market participants would use in a fair value measurement, including the impact of non-performance risk. Inputs used in determining fair value are characterized using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The company's estimate of fair value may differ from amounts that could be realized or settled in a current market transaction.

Provisions for Decommissioning and Restoration Costs

The company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. Management applies judgment in assessing the existence and extent of the company's decommissioning and restoration obligations at the end of each reporting period, as well as in determining whether the nature of the activities performed is related to decommissioning and restoration activities or normal operating activities.

These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible future use of the site. Since these estimates are specific to the assets involved, there are many individual judgments and assumptions underlying Suncor's total provision. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and changes in prices. The expected timing of future decommissioning and restoration activities may change due to certain factors, including oil and gas reserves life. Changes to assumptions related to future expected costs, discount rates and timing may have a material impact on the amounts presented.

The fair value of these provisions is estimated by discounting the expected future cash flows using the company's credit-adjusted risk-free interest rate. In subsequent periods, the provision is adjusted for the passage of time by charging an amount to accretion of liabilities in financing expenses, based on the discount rate.

Suncor's provision for decommissioning and restoration costs increased by $887 million in 2012 to $4.688 billion. The most significant change in the provision was with respect to the revised future cost estimates and increased disturbance. The provision also increased due to a decrease in the average discount rate (2012 – 3.75%; 2011 – 4.3%).

62 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Other Provisions

The determination of other provisions, including, but not limited to, provisions for royalty disputes, onerous contracts, litigation and constructive obligations, is a complex process that involves judgments about the outcomes of future events, the interpretation of laws and regulations, expected future cash flows and discount rates.

The company is involved in litigation and claims in the normal course of operations. As at December 31, 2012, management believes the result of any settlements related to such litigation or claims would not materially affect the financial position of the company.

Employee Future Benefits

The company provides benefits to employees and retired employees, including pensions and other post-retirement benefits.

The obligations and costs of defined benefit pension and other post-retirement benefit plans are determined based on actuarial valuation methods and assumptions. Assumptions typically used in determining these amounts include estimates of, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, the return on plan assets, mortality rates and future medical costs. The accrued net benefit liability is reported as other long-term liabilities in the Consolidated Balance Sheets.

The fair value of plan assets is determined using market values. The estimated rate of return on plan assets in the portfolio considers the current level of returns on fixed income assets, the historical level of risk premium associated with other asset classes and the expected future returns on all asset classes. The discount rate assumption is based on the year-end interest rates for high-quality bonds that mature at times concurrent with the company's benefit obligations. The estimated rate for compensation increases is based on management's judgment.

Actuarial valuations are subject to management's judgment. Actuarial gains and losses comprise changes to assumptions related to discount rates, expected return on plan assets and annual rates for compensation increases. They are accounted for on a prospective basis and may have a material impact on the amounts presented. Actuarial gains and losses are recognized in other comprehensive income in the Consolidated Statements of Comprehensive Income in the period incurred.

Control and Significant Influence

Control is defined as the power to govern the financial and operating decisions of an entity so as to obtain benefits from its activities and significant influence is defined as the power to participate in the financial and operating decisions of the investee. The assessment of whether the company has control, joint control, or significant influence over another entity requires judgment of the impact it has over the financial and operating decisions of the entity and the extent of the benefits it obtains.

Income Taxes

The determination of the company's income tax provision is an inherently complex process, requiring management to interpret continually changing regulations and to make other judgments, including those about deferred income taxes that are discussed below.

Management believes that adequate provisions have been made for all income tax obligations, although the results of audits and reassessments and changes in the interpretations of standards may result in a material increase or decrease in the company's assets, liabilities and net earnings.

In January 2013, the company received a proposal letter from the Canada Revenue Agency (CRA) relating to the income tax treatment of realized losses in 2007 on the settlement of the Buzzard derivative contracts. The company strongly disagrees with the CRA's position and will respond to the proposal letter; however, the CRA may proceed to issue a notice of reassessment (NOR) to increase the amount payable by approximately $1.2 billion. The company firmly believes it will be able to successfully defend its original filing position so that ultimately no increased income tax payable will result from the CRA's actions. However, notwithstanding the filing of an objection to dispute this matter, the company would be required to make a minimum payment of 50% of the amount payable under the NOR, estimated to be $600 million, which would remain on account until the dispute is resolved.

Deferred Income Taxes

A taxable or a deductible temporary difference may exist when there is a difference between the carrying value of an asset or liability and its respective tax basis. The reversal of deductible temporary differences results in deductible amounts when determining taxable income in future periods. The reversal of taxable temporary differences results in taxable amounts when determining taxable income of future periods.

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the

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company's estimate, the ability of the company to realize the deferred tax assets could be impacted.

Deferred tax liabilities are recognized when there are taxable temporary differences that will reverse and result in a future outflow of funds to a taxation authority. The company records a provision for the amount that is expected to be settled, which requires the application of judgment as to the ultimate outcome. Deferred tax liabilities could be impacted by changes in the company's estimate of the likelihood of a future outflow, the expected settlement amount, and the tax laws in the jurisdictions in which the company operates.

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11. RISK FACTORS

Suncor is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification of risks inherent to its assets, activities and operations. The company's enterprise risk committee (ERC), comprised of senior representatives from business and functional groups across Suncor, oversees entity-wide processes to identify, assess and report on the company's principal risks. A principal risk is an exposure that has the potential to materially impact the ability of one of our businesses or functions to meet or support a Suncor objective. Risks facing Suncor's business are listed below.

Volatility of Commodity Prices and Light/Heavy Differentials

Our financial performance is closely linked to prices for crude oil in our upstream business and prices for refined petroleum products in our downstream business, and, to a lesser extent, to natural gas prices in our upstream business, where natural gas is both an input and output of production processes. The values for all of these commodity prices can be influenced by global and regional supply and demand factors.

Crude oil prices are also affected by, among other things, global economic health and global economic growth (particularly in emerging markets), pipeline constraints, regional and international supply and demand imbalances, political developments, compliance or non-compliance with quotas imposed on Organization of Petroleum Exporting Countries (OPEC) members, access to markets for crude oil and weather. These factors impact the various types of crude oil and refined products differently and can impact differentials between light and heavy grades of crude oil (including blended bitumen), and between conventional and synthetic crude oil.

Suncor anticipates higher production of bitumen in future years, due mainly to production growth from Firebag. Due to its low viscosity, bitumen is blended with a light diluent or SCO and sold as a heavy crude oil. The markets for heavy crude are more limited than those for light crude, making them more susceptible to supply and demand changes and imbalances (whether as a result of pipeline constraints or otherwise). Heavy crude oil generally receives lower market prices than light crude, due principally to the lower quality and value of the refined product yield, and the higher cost to transport the more viscous product on pipelines, and this price differential can be amplified due to supply and demand imbalances, as has been experienced over the last twelve months, due primarily to pipeline constraints and the inability to efficiently bring products to market. The price differential between light crude and WCS is particularly important for Suncor. The market price for WCS is influenced by regional supply and demand factors, including the availability and price of diluent, and by the availability and cost of accessing primary markets through pipeline systems. For the reasons noted above, the price differential between light crude and WCS in 2012 was at its widest level since 2008. Future light/heavy differentials are uncertain and continued widening of these light/heavy differentials could have a negative impact on our business, especially price realizations for WCS and bitumen that Suncor is unable to upgrade or process at its refineries.

Refined petroleum product prices and refining margins are also affected by, among other things, crude oil prices, the availability of crude oil and other feedstocks, levels of refined product inventories, regional refinery availability, marketplace competitiveness, and other local market factors.

Natural gas prices in North America are affected primarily by supply and demand, and by prices for alternative energy sources. All of these factors are beyond our control and can result in a high degree of price volatility.

Commodity prices and refining margins have fluctuated widely in recent years. Given the recent global economic uncertainty, we expect continued volatility and uncertainty in commodity prices in the near term. Constrained market access for oil sands production due to insufficient pipeline takeaway capacity, growing inland production and refinery outages create risk of widening differentials or shut-in of production that could have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, oil and natural gas producers in North America, and particularly in Canada, currently receive discounted prices for their production relative to certain international prices, due to constraints on the ability to transport and sell such products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers such as Suncor. A prolonged period of low prices could affect the value of our upstream and downstream assets and the level of spending on growth projects, and could result in the curtailment of production from some properties and/or the impairment of that property's carrying value. Accordingly, low commodity prices, particularly for crude oil, could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow, and may also lead to impairments or write-offs of the values of Suncor's assets or projects in development.

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Government Policy

Suncor operates under federal, provincial, state and municipal legislation in numerous countries. The company is also subject to regulation and intervention by governments in oil and gas industry matters, such as land tenure, royalties, taxes (including income taxes), government fees, production rates, environmental protection controls, safety performance, the reduction of greenhouse gas (GHG) and other emissions, the export of crude oil, natural gas and other products, the company's interactions with foreign governments, the awarding or acquisition of exploration and production rights, oil sands leases or other interests, the imposition of specific drilling obligations, control over the development and abandonment of fields and mine sites (including restrictions on production), and possibly expropriation or cancellation of contract rights.

Changes in government policy or regulation, or interpretation thereof, have a direct impact on Suncor's business, financial condition, results of operations and cash flow, as evidenced by such initiatives as the Alberta government's royalty review program in 2007, and, more recently, by trade sanctions in Libya (which have since been lifted) and Syria imposed by Canadian and other international governments, and increased production taxes in the U.K. Changes in government policy or regulation can also have an indirect impact on Suncor, including opposition to new North American pipeline systems, such as the Keystone XL or the Northern Gateway proposals, or incrementally over time, through increasingly stringent environmental regulations or unfavourable income tax and royalty regimes. The result of such changes can also lead to additional compliance costs and staffing and resource levels, and also increase exposure to other principal risks of Suncor, including environmental or safety non-compliance and permit approvals.

Environmental Regulation

Changes in environmental regulation could have a material adverse effect on our business, financial condition, results of operations and cash flow by impacting the demand, formulation or quality of our products, or by requiring increased capital expenditures or distribution costs, which may or may not be recoverable in the marketplace. The complexity and breadth of changes in environmental regulation make it extremely difficult to predict the potential impact to Suncor. The company anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Failure to comply with environmental regulation may result in the imposition of significant fines and penalties, liability for cleanup costs and damages, and the loss of important licences and permits, which may, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flow. Through industry associations, Suncor participates, both directly and indirectly, in the consultation process for the design of proposed regulations and other efforts to harmonize regulations across jurisdictions within North America.

Some of the issues that are or may in future be subject to environmental regulation include:

•: The possible cumulative regional impacts of oil sands development;
•: The manufacture, import, storage, treatment and disposal of hazardous or industrial waste and substances;
•: The need to reduce or stabilize various emissions to air;
•: Withdrawals, use of, and discharges to water;
•: The use of hydraulic fracturing to assist in the recovery and production of oil and natural gas;
•: Issues relating to land reclamation, restoration and wildlife habitat protection;
•: Reformulated gasoline to support lower vehicle emissions;
•: U.S. state or federal calculation and regulation of fuel life-cycle carbon content; and
•: Regulation or policy by foreign governments or other organizations to limit purchases of oil produced from unconventional sources, such as the oil sands.

Climate Change Regulation

Future laws and regulations may impose significant liabilities on a failure to comply with their requirements; however, Suncor expects the cost of meeting new environmental and climate change regulations will not be so high as to cause material disadvantage to the company or material damage to its competitive positioning. While it currently appears that GHG regulations and targets will continue to become more stringent, and while Suncor will continue efforts to reduce the intensity of its GHG emissions, the absolute GHG emissions of our company will continue to rise as we pursue a prudent and planned growth strategy.

As part of its ongoing business planning, Suncor assesses potential costs associated with carbon dioxide (CO₂) emissions in its evaluation of future projects, based on the company's current understanding of pending and possible GHG regulations. Both the U.S. and Canada have indicated that climate change policies that may be implemented will attempt to balance economic, environmental and energy security concerns. In the future,

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the company expects that regulation will evolve with a moderate carbon price signal, and that the price regime will progress cautiously. Suncor will continue to review the impact of future carbon constrained scenarios on its strategy, using a price range of $15-$60 per tonne of CO₂ equivalent as a base case, applied against a range of regulatory policy options and price sensitivities.

The Canadian federal government has indicated a preference for a sector-specific approach to climate change regulation; however, it is unclear what form any regulation will take for the oil and gas sector, and what type of compliance mechanisms will be available to large emitters. At this time, the company does not believe it is possible to predict the nature of any requirements or the impact on Suncor's business, financial condition, results of operations and cash flow. The impact of developing regulations cannot be quantified at this time in the absence of detail on how systems will operate.

Although Suncor does not actively market into California, the implications of other states or countries adopting similar Low Carbon Fuel Standard (LCFS) legislation could pose a significant barrier to its exports of oil sands crude if the importing jurisdictions do not acknowledge efforts undertaken by the oil sands industry to meet the emissions intensity reductions legislated by the Government of Alberta.

Land Reclamation

There are risks associated specifically with the company's ability to reclaim tailings ponds containing mature fine tailings, with TRO_TM or other methods and technologies. Suncor expects that TRO_TM will help the company reclaim existing tailings ponds by reducing tailings. The success of TRO_TM or any other methods of technology and the time to reclaim tailings ponds could increase or decrease Suncor's decommissioning and restoration cost estimates. The company's failure or inability to adequately implement its reclamation plans could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Alberta's Land-Use Framework

Alberta's Land-Use Framework (LUF) has been implemented under the Alberta Land Stewardship Act (ALSA), which sets out the Government of Alberta's approach to managing Alberta's land and natural resources to achieve long-term economic, environmental and social goals. ALSA contemplates the amendment or extinguishment of previously issued consents such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or policy resulting from the implementation of a regional plan.

On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (LARP), the first regional plan under the LUF. The LARP identifies management frameworks for air, land, water and biodiversity that will incorporate cumulative limits and triggers, as well as identifying areas related to conservation, tourism and recreation.

The implementation of, and compliance with the terms of, the LARP may adversely impact our current properties and projects in northern Alberta due to, among other things, environmental limits and thresholds. Due to the cumulative nature of the plan, the impact of the LARP on Suncor's operations may be outside of the control of the company, as Suncor's operations could be impacted as a result of restrictions imposed due to the cumulative impact of development in the area, and not solely in relation to Suncor's direct impact.

Alberta Environment Water Licences

We currently rely on fresh water, which is obtained under licences from Alberta Environment, to provide domestic and utility water at our Oil Sands operations. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added to these licences. There can be no assurance that the company will not have to pay a fee for the use of water in the future or that any such fees will be reasonable. In addition, the expansion of the company's projects relies on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted on terms favourable to Suncor, or at all, or that such additional water will in fact be available to divert under such licences.

Royalties

Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs, by changes to existing legislation or PSCs, and by results of regulatory audits of prior year filings and other unexpected events. Some of the issues where settlement with regulatory bodies may cause royalties expense or royalties payable to differ materially from provisions currently recorded include:

•: For Suncor's Oil Sands Base mining operations, the Suncor BVM is based on the terms of the Suncor Royalty Amending Agreement (RAA), which modifies the application of the Suncor BVM as recently enacted by requiring additional quality and transportation adjustments. Suncor has filed non-compliance notices with the Alberta government, citing that reasonable quality adjustments in the determination of the Suncor BVM were not considered by the Alberta government as permitted by the Suncor RAA. Suncor has also filed with

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the Alberta government a Notice of Commencement of Arbitration under the Suncor RAA. The co-owners of Syncrude have also filed a non-compliance notice in respect of the determination of the bitumen value under its 2008 agreements with the Alberta government.

•: Suncor has also appealed the disallowance of certain costs under the New Royalty Framework in Alberta and certain costs under royalty agreements in Newfoundland and Labrador, such as insurance premiums.

The final determination of these matters may have a material impact on royalties payable to the respective governments and on the company's royalties expense.

Foreign Operations

The company has operations in a number of countries with different political, economic and social systems. As a result, the company's operations and related assets are subject to a number of risks and other uncertainties arising from foreign government sovereignty over the company's international operations, which may include, among other things:

•: Currency restrictions and exchange rate fluctuations;
•: Loss of revenue, property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks;
•: Increases in taxes and governmental royalties;
•: Compliance with existing and emerging anti-corruption laws, including the Foreign Corrupt Practices Act of the United States, the Corrupt Foreign Officials Act of Canada and the United Kingdom Bribery Act;
•: Renegotiation of contracts with governmental entities and quasi-governmental agencies, including risks around the current negotiations with the National Oil Company on the period in which Suncor was in force majeure under its EPSAs.
•: Changes in laws and policies governing operations of foreign-based companies; and
•: Economic and legal sanctions (such as restrictions against countries experiencing political violence, or countries that other governments may deem to sponsor terrorism).

If a dispute arises in the company's foreign operations, the company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S. In addition, as a result of activities in these areas and a continuing evolution of an international framework for corporate responsibility and accountability for international crimes, the company could also be exposed to potential claims for alleged breaches of international law.

In response to international sanctions and escalating political unrest in Syria, Suncor declared force majeure in December 2011, withdrew its expatriate staff and stopped recording production from Syria. Since this time, the company's prospects for resuming operations in Syria have not improved. As a result, Suncor recorded impairment charges against its assets in Syria during 2012. There is no assurance as to if or when Suncor's operations in Syria will resume or return to previous levels.

The impact that future potential terrorist attacks, regional hostilities or political violence may have on the oil and gas industry, and on our operations in particular, is not known at this time. This uncertainty may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or collateral damage of, an act of terror, political violence or war. Suncor may be required to incur significant costs in the future to safeguard our assets against terrorist activities or to remediate potential damage to our facilities. There can be no assurance that Suncor will be successful in protecting itself against these risks and the related financial consequences.

Operational Outages and Major Environmental or Safety Incidents

Each of Suncor's primary operating businesses – Oil Sands, Exploration and Production, and Refining and Marketing – demand significant levels of investment in the design, operation and maintenance of facilities, and, therefore, carry the additional economic risk associated with operating reliably or enduring a protracted operational outage. These businesses also carry the risks associated with environmental and safety performance, which is closely scrutinized by governments, the public and the media, and could result in a suspension of or inability to obtain regulatory approvals and permits, or, in the case of a major environmental or safety incident, civil suits or charges against the company.

Generally, Suncor's operations are subject to operational hazards and risks such as fires, explosions, blow-outs, power outages, severe winter climate conditions, and the migration of harmful substances such as oil spills, gaseous leaks, or a release of tailings into water systems, any of which can interrupt operations or cause personal injury or death, or damage to property, equipment, the environment, and information technology systems and related data and control systems.

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The reliable operation of production and processing facilities at planned levels and Suncor's ability to produce higher value products can also be impacted by failure to follow operating procedures or operate within established operating parameters, equipment failure through inadequate maintenance, unanticipated erosion or corrosion of facilities, manufacturing and engineering flaws, and labour shortage or interruption. The company is also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software or network attacks.

The efficient operation of Suncor's business is dependent on computer hardware and software systems. Information systems are vulnerable to security breaches by computer hackers and cyberterrorists. We rely on industry accepted security measures and technology to securely maintain confidential and proprietary information stored on our information systems. However, these measures and technology may not adequately prevent security breaches. In addition, the unavailability of the information systems or the failure of these systems to perform as anticipated for any reason could disrupt our business and could result in decreased performance and increased operating costs, causing our business and results of operations to suffer. Any significant interruption or failure of our information systems or any significant breach of security could adversely affect our business and results of operations.

In addition, some of Suncor's operations are subject to all of the risks connected with transporting, processing and storing crude oil, natural gas and other related products. Pipeline capacity constraints combined with plant capacity constraints could negatively impact our ability to produce at capacity levels. Disruptions in pipeline service could adversely affect commodity prices, Suncor's price realizations, refining operations and sales volumes, or limit our ability to deliver production. These interruptions may be caused by the inability of the pipeline to operate or by the oversupply of feedstock into the system that exceeds pipeline capacity. There can be no certainty that short-term operational constraints on pipeline systems arising from pipeline interruption and/or increased supply of crude oil will not occur. In addition, planned or unplanned shutdowns or closures of our refinery customers may limit our availability to deliver feedstock. All of these events could have negative implications on sales and cash from operating activities.

For Suncor's Oil Sands operations, mining oil sands ore, extracting bitumen from mined ore, producing bitumen through in situ methods, and upgrading bitumen into SCO and other products involve particular risks and uncertainties. Oil Sands operations are susceptible to loss of production, slowdowns, shutdowns or restrictions on our ability to produce higher value products, due to the interdependence of its component systems. Through growth projects, the company expects to further mitigate adverse impacts of interdependent systems and to reduce the production and cash flow impacts of complete plant-wide shutdowns. For example, the company expects the MNU will stabilize secondary upgrading processes by providing flexibility during planned or unplanned maintenance.

For Suncor's upstream businesses, there are risks and uncertainties associated with drilling for oil and natural gas, the operation and development of such properties and wells (including encountering unexpected formations, pressures, ore grade qualities, or the presence of H₂S), premature declines of reservoirs, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, other accidents, and pollution and other environmental risks.

Suncor's Exploration and Production operations include drilling offshore of Newfoundland and Labrador and in the North Sea offshore of the U.K. and Norway, which are areas subject to hurricanes and other extreme weather conditions. Drilling rigs in these regions may be exposed to damage or total loss by these storms, some of which may not be covered by insurance. The consequence of catastrophic events, such as blow-outs, occurring in offshore operations can be more difficult and time-consuming to remedy. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death of rig personnel. Successful remediation of these events may be adversely affected by the water depths, pressures and cold temperatures encountered in the ocean, shortages of equipment and specialists required to work in these conditions, or the absence of appropriate technology to resolve the event. Damage to the environment, particularly through oil spillage or extensive, uncontrolled fires or death, could result from these offshore operations. Suncor's offshore operations could also be affected by the actions of Suncor's contractors and agents that could result in similar catastrophic events at their facilities, or could be indirectly affected by catastrophic events occurring at other third-party offshore operations. In either case, this could give rise to liability, damage to the company's equipment, harm to individuals, force a shutdown of our facilities or operations, or result in a shortage of appropriate equipment or specialists required to perform our planned operations.

In particular, East Coast Canada operations can be impacted by winter storms, pack ice, icebergs and fog. During the winter storm season (October to March), the company may have to reduce production rates at its offshore facilities as a result of limited storage capacity and the inability to offload to shuttle tankers due to wave

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height restrictions. During the spring, pack ice and icebergs drifting in the area of our offshore facilities have resulted in precautionary shut in of FPSO production and drilling delays. In late spring and early summer, fog also impacts our ability to transfer personnel to the offshore facilities by helicopter. In 2012, harsh weather conditions delayed the company's efforts to reconnect flow lines to drill centres for Terra Nova subsequent to a dockside maintenance program for the FPSO.

Suncor's Refining and Marketing operations are subject to all of the risks normally inherent in the operation of refineries, terminals, pipelines and other distribution facilities and service stations, including loss of product, slowdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock or other incidents.

Losses resulting from the occurrence of any of these risks identified above could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow. Although the company maintains a risk management program, which includes an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. It is possible that our insurance coverage will not be sufficient to address the costs arising out of the allocation of liabilities and risk of loss arising from offshore operations. Suncor also has a captive insurance entity to provide additional business interruption coverage for potential losses.

Environment Health and Safety (EH&S) Regulatory Non-Compliance

The company is required to comply with a large number of EH&S regulations under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations, some of which are described in the Industry Conditions – Environmental Regulation section of the 2012 AIF. Failure to comply with these regulations may result in the imposition of fines and penalties, censure, liability for cleanup costs and damages, and the loss of important licences and permits, which could also have a material adverse effect on our business, financial condition, results of operations and cash flow. Compliance can be affected by the loss of skilled staff, inadequate internal processes and compliance auditing.

Project Execution

There are certain risks associated with the execution of our major projects and the commissioning and integration of new facilities within our existing asset base, the occurrence of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Project execution risk consists of three related primary risks:

•: Engineering – a failure in the specification, design or technology selection;
•: Construction – a failure to build the project in the approved time and at the agreed cost; and
•: Commissioning and start-up – a failure of the facility to meet agreed performance targets, including operating costs, efficiency, yield and maintenance costs.

Management believes the execution of major projects presents issues that require prudent risk management. Suncor may provide cost estimates for major projects at the conceptual stage, prior to commencement or completion of the final scope design and detailed engineering necessary to reduce the margin of error of such cost estimates. Accordingly, actual costs can vary from estimates, and these differences can be material. Project execution can also be impacted by:

•: Failure to comply with Suncor's project implementation model;
•: The availability, scheduling and cost of materials, equipment and qualified personnel;
•: The complexities associated with integrating and managing contractor staff and suppliers in a confined construction area;
•: Our ability to obtain the necessary environmental and other regulatory approvals;
•: The impact of general economic, business and market conditions;
•: The impact of weather conditions;
•: Our ability to finance growth if commodity prices were to decline and stay at low levels for an extended period;
•: Risks relating to restarting projects placed in safe mode, including increased capital costs; and
•: The effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment.

In addition, there are certain risks associated with the execution of our exploration, production and refining projects. These risks include, but are not limited to:

•: Our ability to obtain the necessary environmental and regulatory approvals;

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•: Risks relating to scheduling, resources and costs, including the availability and cost of materials, equipment and qualified personnel;
•: The impact of general economic, business and market conditions;
•: The impact of weather conditions;
•: The accuracy of project cost estimates;
•: Our ability to finance growth;
•: Our ability to source or complete strategic transactions;
•: The effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment; and
•: The commissioning and integration of new facilities within our existing asset base could cause delays in achieving guidance, targets and objectives.

The failure to sanction or build a project could result in additional costs, including abandonment and reclamation costs, to shut down the project, and such costs could be material to Suncor.

Corporate Reputation

The public perception of integrated oil and gas companies and their operations may pose issues related to development and operating approvals or market access for products, which may have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Development of the oil sands has figured prominently in recent political, media and activist commentary on the subjects of pipeline transportation, climate change, GHG emissions, water usage and environmental damage, which may directly or indirectly harm the profitability of our current oil sands projects and the viability of future oil sands projects in a number of ways, including:

•: Creating significant regulatory uncertainty that challenges economic modelling of future projects and potentially delays sanctioning;
•: Motivating extraordinary environmental and emissions regulation of those projects by governmental authorities that could result in changes to facility design and operating requirements, thereby potentially increasing the cost of construction, operation and abandonment; and
•: Compelling legislation or policy that limits the purchase of crude oil produced from the Athabasca oil sands by governments and other institutional consumers that, in turn, limits the market for this crude oil and reduces its price.

Concerns such as those raised above may also harm our corporate reputation and limit our ability to transport our products or access land and joint arrangements in other jurisdictions throughout the world. Investors may respond by applying a discount to Suncor's shares, thereby diminishing the company's value, or may hinder Suncor in its ability to influence government policy.

Permit Approvals

Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain various federal, provincial or state permits and regulatory approvals. Suncor must also obtain licences to operate certain assets. These processes can involve, among other things, stakeholder consultation, environmental impact assessments and public hearings, and may be subject to conditions, including security deposit obligations and other commitments. Suncor can also be indirectly impacted by a third party's inability to obtain regulatory approval for a shared infrastructure project.

Failure to obtain regulatory approvals, or failure to obtain them on a timely basis or on satisfactory terms, could result in delays, abandonment or restructuring of projects and increased costs, all of which could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow.

Skills and Resource Shortage

The successful operation of Suncor's businesses and our ability to expand operations will depend upon the availability of, and competition for, skilled labour and materials supply. There is a risk that we may have difficulty sourcing the required labour for current and future operations. The risk could manifest itself primarily through an inability to recruit new staff without a dilution of talent, to train, develop and retain high-quality and experienced staff without unacceptably high attrition, and to satisfy an employee's work/life balance and desire for competitive compensation. The labour market in Alberta is particularly tight due to the growth of the oil sands industry. The increasing age of our existing workforce adds further pressure to this situation. Materials may also be in short supply due to smaller labour forces in many manufacturing operations. Our ability to operate safely and effectively and complete all our projects on time and on budget has the potential to be significantly impacted by these risks.

Change Capacity

In order to achieve Suncor's business objectives, the company must operate efficiently, reliably and safely, and, at the same time, deliver growth and sustaining projects

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safely, on budget and on schedule. The ability to balance these two sets of objectives is critically important to Suncor to deliver value to shareholders and stakeholders. These objectives demand a large number of improvement initiatives that compete for resources, and may negatively impact the company should there be inadequate screening of project requests or consideration of the cumulative impacts of prior and parallel initiatives on people, processes and systems. There is a risk that these objectives may exceed Suncor's capacity to adopt and implement change.

Cost Management

Production from oil sands through mining, upgrading and in situ recovery is, relative to most major conventional hydrocarbon reserves, a higher cost resource to develop and produce. Suncor is exposed to the risk of escalating operating costs, in both its oil sands business and other businesses which could reduce profitability and cash flow that might otherwise be directed towards growth or dividends, and major project capital costs, which could constrain Suncor's ability to execute high-quality projects that deliver lower operating costs. Factors contributing to these risks include, but are not limited to, the skills and resource shortage, the long-term success of existing and new in situ technologies, and the geology and reserves characterization of in situ reserves that can lead to higher steam-to-oil ratios and lower production.

Co-owner Management

Suncor has entered into joint arrangements and other contractual arrangements with third parties with respect to certain of its projects where other entities operate assets in which Suncor has ownership or other interests. Suncor's dependence on its co-owners and its constrained ability to influence operations and associated costs could materially adversely affect Suncor's business, financial condition, results of operations and cash flow. The success and timing of Suncor's activities on assets and projects operated by others, or developed jointly with others, depend upon a number of factors that are outside of Suncor's control, including the timing and amount of capital expenditures, the timing and amount of operational and maintenance expenditures, the operator's expertise, financial resources and risk management practices, the approval of other participants, and the selection of technology.

These co-owners may have objectives and interests that do not coincide with and may conflict with Suncor's interests. Major capital decisions affecting joint arrangements may require agreement among the co-owners, while certain operational decisions may be made solely at the discretion of the operator of the applicable assets. While the partners generally seek consensus with respect to major decisions concerning the direction and operation of the assets and the development of projects, no assurance can be provided that the future demands or expectations of the parties relating to such assets and projects will be met satisfactorily or in a timely manner. Failure to satisfactorily meet demands or expectations by all of the parties may affect our participation in the operation of such assets or in the development of such projects, our ability to obtain or maintain necessary licences or approvals, or the timing for undertaking various activities. In addition, disputes may arise pertaining to the timing and/or capital commitments with respect to projects that are being jointly developed, which could materially adversely affect the development of such projects and Suncor's business and operations.

Other Risk Factors

A detailed discussion of additional risk factors is presented in our 2012 AIF / Form 40-F, filed with securities regulators.

72 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

12. OTHER ITEMS

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2012, 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 of December 31, 2012, 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 year ended December 31, 2012 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.

As a result of past unrest in Libya and current events in Syria, Suncor is not able to monitor the status of all of its assets in these countries, including whether certain facilities have suffered damages. Suncor is continually assessing the control environment in these countries to the extent permitted by applicable law and does not consider the changes in these countries to have had a material impact on the company's overall internal control over financial reporting.

The effectiveness of our internal control over financial reporting as at December 31, 2012 was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2012.

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 ENERGY INC. 2012 ANNUAL REPORT 73

13. NON-GAAP FINANCIAL MEASURES ADVISORY

Certain financial measures in the MD&A – namely operating earnings, ROCE, cash flow from operations and Oil Sands cash operating costs – are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze operating 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 measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Operating Earnings

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

The following is a reconciliation of net earnings to operating earnings for Suncor's last five years of operations. Operating earnings for 2009 and 2008 are reported under Previous GAAP and have been adjusted from operating earnings previously reported to include the effect of project start-up costs and mark-to-market valuation of stock-based compensation, which were previously excluded when calculating operating earnings.

($ millions)	2012		2011	2010		2009		2008

Net earnings as reported	2 783		4 304	3 829		1 146		2 137
Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(157	)	161	(372	)	(798	)	852
Impairments and write-offs	2 176		629	306		42		—
Impact of income tax rate adjustments on deferred income taxes	88		442	—		4		—
Loss (gain) on significant disposals	—		107	(826	)	39		—
Adjustments to provisions for assets acquired through the merger	—		31	68		97		—
Change in fair value of commodity derivatives used for risk management, net of realizations	—		—	(233	)	499		(372	)
Redetermination of working interests in Terra Nova	—		—	(166	)	24		—
Modification of the bitumen valuation methodology	—		—	(51	)	50		—
Merger and integration costs	—		—	79		151		—
Gain on effective settlement of pre-existing contract with Petro-Canada	—		—	—		(438	)	—
Costs related to deferral of growth projects	—		—	—		299

Operating earnings	4 890		5 674	2 634		1 115		2 617

Bridge Analyses of Operating Earnings

Throughout this MD&A, the company presents charts that illustrate the change in operating earnings from the comparative period through key variance factors. Factors represent after-tax variances and include the impacts of operating earnings adjustments. These factors are analyzed in the Operating Earnings narratives following the bridge analyses in a particular section of the MD&A. This bridge analysis is presented because management uses this presentation to analyze performance.

The factor for Volumes is calculated based on production volumes and mix for the Oil Sands and Exploration and Production segments and sales volumes for the Refining and Marketing segment.

The factor for Price, Margin and Other Revenue includes upstream price realizations before royalties, refining and marketing margins, other operating revenues, and the net impacts of sales and purchases of third-party crude.

74 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

The factor for Inventory reflects the opportunity cost of building production volumes in inventory or the additional margin earned by drawing down inventory produced in previous periods. The calculation of the Inventory factor in a bridge analysis permits the company to present the factor for Volumes for upstream assets based on production volumes, rather than based on sales volumes.

The factor for Operating Expense includes transportation expense, project start-up costs, and operating, selling and general expense (adjusted for impacts of changes in inventory).

The factor for Financing Expense and Other Income includes financing expense, other income, operational foreign exchange gains and losses, changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in statutory income tax rates, and other income tax adjustments.

Return on Capital Employed (ROCE)

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 thirteen-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.

Year ended December 31 ($ millions, except as noted)				2012		2011	2010		2009		2008

Adjustments to net earnings
	Net earnings			2 783		4 304	3 829		1 146		2 137
	Add after-tax amounts for:
		Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt		(157	)	161	(372	)	(858	)	852
		Net interest expense		41		83	327		349		—

			A	2 667		4 548	3 784		637		2 989

Capital employed – beginning of twelve-month period
	Net debt			6 976		11 254	13 516		7 226		3 248
	Shareholders' equity			38 600		35 192	32 485		14 523		11 896

			D	45 576		46 446	46 001		21 749		15 144

Capital employed – end of twelve-month period
	Net debt			6 632		6 976	11 254		13 377		7 226
	Shareholders' equity			39 223		38 600	35 192		34 111		14 523

				45 855		45 576	46 446		47 488		21 749

Average capital employed ⁽¹⁾			B	45 342		44 956	46 075		35 128		18 447

ROCE – including major projects in progress (%)			A/B	5.9		10.1	8.2		1.8		16.2

Average capitalized costs related to major projects in progress			C	8 729		12 106	12 890		10 655		5 149

ROCE – excluding major projects in progress (%)			A/(B-C)	7.3		13.8	11.4		2.6		22.5

(1): For 2009 to 2012, average capital employed is calculated as a thirteen-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. For 2008, average capital employed is calculated on the basis of a simple average (B+D)/2. This change in calculation was made as a result of the significant capital employed acquired in the merger with Petro-Canada in 2009. 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.

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 75

Cash Flow from Operations

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

		Oil Sands						Exploration and Production						Refining and Marketing
Year ended December 31 ($ millions)		2012		2011		2010		2012		2011		2010		2012		2011		2010

Net earnings (loss)		458		2 603		1 520		138		306		1 938		2 129		1 726		819
Adjustments for:
	Depreciation, depletion, amortization and impairment	3 964		1 374		1 310		1 857		2 035		1 978		468		444		440
	Deferred income taxes	266		895		487		28		354		196		529		494		269
	Accretion of liabilities	109		85		130		62		69		103		4		3		2
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	—		—		—		—		—		—		—		—		—
	Change in fair value of derivative contracts	—		—		(316	)	—		—		—		(1	)	3		—
	(Gain) loss on disposal of assets	(29	)	122		14		(1	)	31		(998	)	(13	)	(16	)	(30	)
	Share-based compensation	95		(35	)	55		14		(4	)	24		48		(21	)	39
	Exploration expenses	—		—		—		145		28		96		—		—		—
	Settlement of decommissioning and restoration liabilities	(380	)	(458	)	(375	)	(32	)	(19	)	(23	)	(21	)	(19	)	(19	)
	Other	(76	)	(14	)	(48	)	16		46		11		7		(40	)	18

Cash flow from (used in) operations		4 407		4 572		2 777		2 227		2 846		3 325		3 150		2 574		1 538
(Increase) decrease in non-cash working capital		(781	)	(676	)	(890	)	(205	)	398		(320	)	(485	)	600		(260	)

Cash flow provided by (used in) operating activities		3 626		3 896		1 887		2 022		3 244		3 005		2 665		3 174		1 278

		Corporate, Energy Trading and Eliminations						Total
Year ended December 31 ($ millions)		2012		2011		2010		2012		2011		2010

Net earnings (loss)		58		(331	)	(448	)	2 783		4 304		3 829
Adjustments for:
	Depreciation, depletion, amortization and impairment	161		99		75		6 450		3 952		3 803
	Deferred income taxes	(80	)	(99	)	(201	)	743		1 644		751
	Accretion of liabilities	7		—		—		182		157		235
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(181	)	183		(426	)	(181	)	183		(426	)
	Change in fair value of derivative contracts	11		(43	)	31		10		(40	)	(285	)
	(Gain) loss on disposal of assets	(1	)	(1	)	39		(44	)	136		(975	)
	Share-based compensation	57		(42	)	(5	)	214		(102	)	113
	Exploration expenses	—		—		—		145		28		96
	Settlement of decommissioning and restoration liabilities	—		—		—		(433	)	(496	)	(417	)
	Other	(71	)	(12	)	(49	)	(124	)	(20	)	(68	)

Cash flow from (used in) operations		(39	)	(246	)	(984	)	9 745		9 746		6 656
Decrease (increase) in non-cash working capital		572		(80	)	300		(899	)	242		(1 170	)

Cash flow provided by (used in) operating activities		533		(326	)	(684	)	8 846		9 988		5 486

The following is a reconciliation of cash flow from operations for Suncor's last five years of operations. Cash flow from operations for 2008 and 2009 are reported under Previous GAAP.

($ millions)	2012	2011		2010	2009	2008

Cash flow provided by operating activities	8 846	9 988		5 486	2 575	4 462
Increase (decrease) in non-cash working capital	899	(242	)	1 170	224	(405	)

Cash flow from operations	9 745	9 746		6 656	2 799	4 057

76 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

Oil Sands Cash Operating Costs

Oil Sands cash operating costs and cash operating costs per barrel are non-GAAP financial measures, which are derived by adjusting Oil Sands segment operating, selling and general expense (a GAAP measure based on sales volumes) 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, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a non-monetary arrangement involving a third-party processor, and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes; iii) excess power generated and sold that is recorded in operating revenue; and iv) the impacts of changes in inventory levels, such that the company is able to present cost information based on production volumes.

Year ended December 31 ($ millions)		2012		2011		2010

Operating, selling and general expense		5 375		5 169		4 537
	Syncrude operating, selling and general expense	(513	)	(529	)	(473	)
	Non-production costs ⁽¹⁾	(338	)	(275	)	(305	)
	Other ⁽²⁾	(129	)	(10	)	32

Cash operating costs		4 395		4 355		3 791
Cash operating costs ($/bbl)		37.05		39.05		36.70

(1): Significant non-production costs include, but are not limited to, share-based compensation adjustments, costs related to the remobilization or deferral of growth projects, research, the expense recorded as part of a non-monetary arrangement involving a third-party processor and feedstock costs for natural gas used to create hydrogen for secondary upgrading processes.
(2): Other includes the impacts of changes in inventory valuation and operating revenues associated with excess power from cogeneration units.

Effective 2012, the calculation of Oil Sands cash operating costs has been updated to better reflect the ongoing cash cost of production, and prior period figures have been redetermined. The cost of natural gas feedstock for secondary upgrading processes, the cost of diluent purchased for transportation of product to markets, and non-cash costs related to the accretion of liabilities for decommissioning and restoration provisions are no longer included in cash operating costs. Certain cash costs relating to safety programs, which were previously considered non-production costs, are now included in cash operating costs. The following table reconciles amounts previously reported to those presented in this MD&A:

Year ended December 31 ($ millions)	2011		2010

Cash operating costs, as previously reported	4 479		3 990
Elements added to cash operating costs definition:
Safety programs	33		18
Elements removed from cash operating costs definition:
Natural gas feedstock for secondary upgrading processes	(53	)	(49)
Accretion of liabilities	(64	)	(93)
Purchased diluent	(40	)	(75)

Cash operating costs, as restated in this MD&A	4 355		3 791

Cash operating costs, as previously reported ($/bbl)	40.20		38.65
Cash operating costs, as restated in this MD&A ($/bbl)	39.05		36.70

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

GAAP requires the use of a first-in, first-out inventory (FIFO) 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 reflect 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 last-in, first-out (LIFO) methodology, because management uses the information to analyze operating performance and

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 77

compare itself against refining peers that are permitted to use LIFO inventory valuation under United States GAAP (U.S. GAAP).

Generally, during times of increasing crude prices, a FIFO inventory valuation positively impacts net earnings, compared with LIFO inventory valuation, as inventories purchased during periods of lower relative feedstock costs are replaced by inventories purchased during periods of higher relative feedstock costs. Conversely, during times of decreasing crude prices, FIFO inventory valuation generally negatively impacts net earnings, compared with LIFO inventory valuation, as inventories purchased during periods of higher relative feedstock costs are replaced by inventories purchased during periods of lower relative feedstock costs.

The company's estimate of the impact of using a FIFO inventory valuation methodology compared to a LIFO methodology is a relatively simple calculation that replaces the FIFO-based costs of goods sold with an average purchase cost over the same period, and does not incorporate all of the elements of a more complex and precise LIFO inventory valuation methodology that an entity using U.S. GAAP might include. The company's estimate is not derived from a standardized calculation and, therefore, is unlikely to be 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.

78 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

14. ADVISORY – FORWARD-LOOKING INFORMATION

The MD&A contains certain forward-looking information and forward-looking statements (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian and U.S. securities laws. Forward-looking statements and other information is 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" and similar expressions.

Forward-looking statements in this MD&A include references to:

Suncor's expectations about production volumes and the performance of its existing assets, including that:

•: Production at Firebag will reach 180,000 bbls/d over the next year;
•: The MNU will increase sweet SCO production capacity by approximately 10% and stabilize secondary upgrading processes by providing flexibility during maintenance;
•: Production capacity at Hebron will be 150,000 bbls/d with first oil late in 2017;
•: There will be an increase of gross installed capacity of 140 MW from the Adelaide and Cedar Point wind projects and an increase of production to 38,000 bbls/d by 2015 at the MacKay River central processing facility;
•: First oil from newly steamed wells at Mackay River will occur in the first quarter of 2013; and
•: Golden Eagle will achieve first oil in late 2014 or early 2015.

The anticipated duration and impact of planned maintenance events, including that:

•: The refurbishment of the Upgrader 1 hydrogen plant will take place late in the first quarter of 2013, and is expected to be offline for approximately 14 weeks;
•: The decrease in sweet SCO production during the refurbishment of the Upgrader 1 hydrogen plant will be partially offset by the additional hydrotreating capacity from the MNU;
•: The maintenance event for the Upgrader 1 facility will take place in the second quarter of 2013, and is scheduled for approximately seven weeks, and that, within this outage, Suncor anticipates no production from Upgrader 1;
•: Suncor will complete maintenance at one of the Firebag central processing facilities during the maintenance of the Upgrader 1 facility;
•: Maintenance will take place in the third quarter of 2013 for Suncor's Upgrader 2 facilities, which is anticipated to have an impact on SCO production;
•: The commissioning of the third drill centre at Terra Nova will take place in the third quarter of 2013;
•: Routine annual maintenance will take place for Terra Nova, White Rose and Buzzard in the second and third quarters of 2013;
•: Maintenance events at the Edmonton refinery on the heavy sour crude train will occur in the second quarter of 2013 for an expected duration of five weeks and on the sweet synthetic crude unit in the third quarter of 2013 for an expected duration of two weeks; and
•: Maintenance at the Sarnia refinery for one of its crude units will take place in the third quarter of 2013 for an expected duration of six weeks.

Suncor's expectations about capital expenditures, and growth and other projects, including:

•: Suncor's belief that Firebag Stage 4 will come in approximately 15% below the announced cost estimate of $2.0 billion;

SUNCOR ENERGY INC. 2012 ANNUAL REPORT 79

•: Growth capital for 2013 will be focused on high return projects;
•: Growth capital in Refining and Marketing will be focused on projects to prepare the Montreal refinery to receive shipments of western crude feedstock;
•: Sanctioning of the Fort Hills mining project will occur in the second half of 2013, and, if sanctioned and subject to approval, post sanction development activities will commence, including detailed engineering design, bulk equipment and material procurement and site construction;
•: The first two of four new storage tanks in Hardisty, Alberta will be connected to the Enbridge Mainline system in 2013;
•: The completion of an insulated pipeline to allow transport of bitumen without the requirement for additional diluent between Firebag and the company's Athabasca terminal starting in the second quarter of 2013;
•: The acquisition of new seismic data in 2013 and appraisal drilling in 2014 at the Beta discovery;
•: Cost estimates, target completion dates and project details provided in the Significant Growth Projects Update and Other Capital Projects sections of the MD&A; and
•: Plans to leverage and extend the production life of existing offshore infrastructure, with drilling activities in areas adjacent to producing fields, such as the Hibernia Extension, the White Rose Extensions, and the Northern Terrace area for Buzzard.

Suncor's strategy for 2013, including:

•: Suncor's plans to continue redevelopment of existing fields in Libya and resume exploration activities in the country;
•: Plans for Suncor to focus on optimization of its current asset base in the Oil Sands through the development of new infrastructure that will enhance regional takeaway capacity and marketing flexibility in 2013, and debottlenecking projects that are expected to provide low cost efficiencies and higher outputs in Oil Sands operations;
•: The company's portfolio of in situ technology projects, which is expected to drive improvements and efficiencies in current production and develop future opportunities, and the focus of this portfolio on subsurface and surface challenges;
•: Operational excellence initiatives will continuously improve Suncor's plant utilization and workforce productivity in 2013;
•: A decision being made on the Voyageur project by the end of the first quarter of 2013; and
•: Suncor will focus in 2013 on bringing the Montreal refinery into the inland refining network, and plans to transport western crudes via rail to the refinery.

Also:

•: The plan for Suncor to pursue opportunities to divest non-core properties in its North American Onshore operations that meet its financial objectives;
•: Increased competition and fluctuating demand in key retail markets for Suncor's Refining and Marketing business is expected to be offset by growth in wholesale channels;
•: The company's assessment in respect of the proposal letter received from the CRA relating to the income tax treatment of realized losses in 2007 on the settlement of certain derivative contracts relating to Buzzard and the company's belief that it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA's action;
•: The company's assessment of asset impairment in Syria, including the amounts recorded as impairment charges in 2012 and the carrying value of such assets as at December 31, 2012;
•: The company's assessment of the situation in Libya, including the amounts recorded as impairment charges in 2011;
•: Management's belief that Suncor will have the capital resources to fund its planned 2013 capital spending program of $7.3 billion and to meet current and long-term working capital requirements through existing cash balances and short-term investments, cash flow from operations, available committed credit facilities, issuing commercial paper, and issuing long-term notes or debentures, and that, if additional capital is required, adequate additional financing will be available to Suncor in the debt capital markets at commercial terms and rates;
•: Management's belief that a phased and flexible approach to existing and future growth projects should assist Suncor in maintaining its ability to manage project costs and debt levels;
•: The company's expectations that the maximum weighted average term to maturity of its short-term

80 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

investment portfolio will not exceed six months, and that all investments will be with counterparties with investment grade debt ratings; and

•: The company's belief that it does not have 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 condition or financial performance, including liquidity and capital resources.

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, Exploration and Production, 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, such as our current dispute with the Alberta Department of Energy in respect of the Bitumen Valuation Methodology Regulation; 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 Exploration and Production 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 and that operations in Syria continue to be impacted by sanctions or 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

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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, and changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; 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 and information are discussed in further detail throughout this MD&A, including under the heading Risk Factors, and the company's 2012 AIF dated March 1, 2013 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.

82 SUNCOR ENERGY INC. 2012 ANNUAL REPORT

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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2012, dated February 26, 2013