EX-99.2 3 a2207617zex-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, 2011,
dated February 23, 2012

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 23, 2012

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's December 31, 2011 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, 2012 (the 2011 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 venture investments, unless the context requires otherwise.

MD&A – Table of Contents

1. |  | Advisories |  | 18 |
2. |  | 2011 Highlights |  | 20 |
3. |  | Suncor Overview |  | 22 |
4. |  | Consolidated Financial Information |  | 24 |
5. |  | Segment Results and Analysis |  | 31 |
6. |  | Fourth Quarter 2011 Analysis |  | 45 |
7. |  | Quarterly Financial Data |  | 48 |
8. |  | Capital Investment Update |  | 50 |
9. |  | Financial Condition and Liquidity |  | 53 |
10. |  | Accounting Policies and Critical Accounting Estimates |  | 57 |
11. |  | Risk Factors |  | 63 |
12. |  | Other Items |  | 70 |
13. |  | Non-GAAP Financial Measures Advisory |  | 71 |
14. |  | Advisory – Forward-Looking Information |  | 75 |

1. ADVISORIES

Basis of Presentation

Unless otherwise noted, all financial information has been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which are within the framework of International Financial Reporting Standards (IFRS). Effective January 1, 2011, the company's audited Consolidated Financial Statements have been prepared in accordance with IFRS, and IFRS 1 First-Time Adoption of International Financial Reporting Standards (IFRS 1) has been applied. In previous years, the company prepared its financial statements in accordance with Canadian generally accepted accounting principles in effect prior to January 1, 2011 (Previous GAAP). Comparative figures presented in this MD&A pertaining to Suncor's 2010 results have been restated to be in accordance with IFRS. The impacts of the transition to IFRS on the company's previously reported financial statements for the year ended December 31, 2010, and the opening balance sheet at January 1, 2010, are presented in the notes to the audited Consolidated Financial Statements.

Comparative figures for earnings and cash flows presented in this MD&A pertaining to Suncor's 2009 results were prepared in accordance with Previous GAAP and were not required by IFRS 1 or by the Canadian Securities Administrators to be restated in accordance with IFRS. Users of this information are cautioned that 2009 results may not be directly comparable with those for 2010 and 2011 and are advised to review the First-Time Adoption of IFRS note to the audited Consolidated Financial Statements.

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

18 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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 are defined in the Non-GAAP Financial Measures Advisory section of this MD&A and reconciled to GAAP net earnings in the Consolidated Financial Information and Segment Results and Analysis sections of this MD&A. Cash flow from operations, ROCE and Oil Sands cash operating costs are defined and reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A. The company has restated operating earnings from 2010 for the transition to IFRS and operating earnings from 2007 to 2010 for the removal of certain prior period operating earnings adjustments.

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. These non-GAAP financial measures are included because management uses the information to analyze operating performance, leverage and liquidity, 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 |  | 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
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
$ 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

Other Advisories

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.

On August 1, 2009, Suncor completed its merger with Petro-Canada, referred to in this MD&A as the "merger". Amounts disclosed in this MD&A for 2009 reflect the results of post-merger Suncor from August 1, 2009 together with the results of pre-merger Suncor only from January 1, 2009 through July 31, 2009, unless otherwise noted.

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, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 19

2. 2011 HIGHLIGHTS

•
  Record operating earnings and cash flow from operations.
  •
    Net earnings for 2011 were $4.304 billion, compared to $3.829 billion in 2010.
  •
    Operating earnings (1) for 2011 were a record $5.674 billion, compared to $2.634 billion in 2010.
  •
    Cash flow from operations (1) for 2011 was a record $9.746 billion, compared to $6.656 billion in 2010.

These record financial results were due primarily to higher average upstream price realizations and downstream refining margins, and increased production from Oil Sands.

•
  ROCE (1) (excluding major projects in progress) was 13.8% for the twelve months ended December 31, 2011, compared to 11.4% for the twelve months ended December 31, 2010. ROCE continues to improve and is at its highest level since the merger with Petro-Canada.

•
  Balance sheet strength.

The company has a strong balance sheet with reduced net debt, due to significant cash flow from its integrated operations and proceeds from asset dispositions.

•
  Net debt at December 31, 2011 was $7.0 billion, and has decreased from $11.3 billion at December 31, 2010.
•
  Cash and cash equivalents at December 31, 2011 was $3.8 billion and has increased from $1.1 billion at December 31, 2010.

Cash flow from operations exceeded 2011 capital and exploration expenditures (including capitalized interest) by $2.9 billion. Combined with proceeds from transactions with Total E&P Canada Ltd. (Total E&P) and other asset divestitures, Suncor cash balances increased significantly during the year. Suncor maintained its strong cash position throughout 2011, while increasing capital expenditures, repaying debt, completing a share repurchase program and increasing its dividend.

During 2011:

•
  The company spent $6.850 billion on capital and exploration expenditures, compared to $6.010 billion in 2010.
•
  The company repaid $500 million of long-term debt and over $1.2 billion of short-term debt.
•
  The company repurchased 17.1 million shares, returning $500 million to shareholders.
•
  Starting in the second quarter of 2011, the company increased its quarterly dividend by 10% to $0.11 per common share.

•
  Leadership transition – Suncor's long-standing CEO to retire.

In early December, Rick George, Suncor's chief executive officer (CEO), announced his plan to retire after more than 20 years at the helm. Steve Williams, Suncor's chief operating officer, was appointed as president and a member of the company's Board of Directors, and will assume the role of CEO upon Mr. George's retirement in May 2012.

•
  Record production from Oil Sands reflected improved reliability through operational excellence.

Oil Sands production averaged a record 304,700 bbls/d in 2011. Production reflected improved reliability and increased bitumen feedstock from mining and In Situ operations. Oil Sands production averaged 345,000 bbls/d in December, another record. Production results for 2011 included the impacts of the largest planned maintenance event in the company's history, which was completed safely and on schedule.

•
  In Situ production exits 2011 at 111,000 bbls/d.

Concurrent with the ramp up of production from the first well pad at the Firebag Stage 3 expansion and infill wells brought on-stream at existing well pads throughout the second half of 2011, In Situ bitumen production surpassed 100,000 bbls/d in late October, and exited 2011 at approximately 111,000 bbls/d.

The ramp up of bitumen production from the Firebag Stage 3 expansion is expected to continue in 2012.

•
  Progress on major growth projects.

Construction activity for the Firebag Stage 3 expansion is complete, while construction activity for the Firebag Stage 4 expansion is well underway. The company expects to begin production from the Stage 4 expansion late in the first quarter of 2013.

The company started mining ore from the North Steepbank Extension (NSE) in late December. The hydrogen plant for the Millennium Naphtha Unit (MNU) produced hydrogen in December, before being taken off-line for minor modifications prior to further

20 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

commissioning. The start-up of the naphtha hydrotreater for the MNU is expected in 2012.

•
  Transactions with Total E&P and the creation of Oil Sands Ventures.

After receiving the necessary regulatory approvals, in the first quarter of 2011, Suncor and Total E&P completed the transactions they had previously announced in December 2010. In exchange for net proceeds of $1.820 billion and a 36.75% interest in the Joslyn oil sands mining project, Suncor sold to Total E&P a 49% interest in the Voyageur upgrader and a 19.2% interest in the Fort Hills oil sands mining project.

In order to manage and develop these new jointly owned assets, Suncor created a new business area – Oil Sands Ventures. Throughout 2011, Oil Sands Ventures focused on ensuring the successful restart of the Fort Hills mining and Voyageur upgrader projects, and building organizational expertise and capacity to effectively manage these projects as well as Suncor's interests in Syncrude and the Joslyn mining project.

•
  Suncor's integrated business model reaps the rewards of a strong refining environment.

The Refining and Marketing segment contributed over $2.5 billion to cash flow from operations in 2011. Throughout much of the year, North American refining margins were very strong, particularly for inland refineries – such as Suncor's Edmonton, Sarnia and Commerce City refineries – due to a wider discount for WTI crude, compared to Brent crude. Despite major planned maintenance events in 2011 at each of these inland refineries, overall refining utilization averaged 92% for 2011, reflecting the company's focus on reliable operations.

•
  Unrest in Libya and Syria.

In Libya, for much of the year, production was shut-in and all operations and exploration activities were suspended due to political unrest that led to international sanctions and Suncor declaring force majeure under its contractual obligations. The transition to a new government in Libya later in 2011 resulted in the lifting of sanctions impacting Suncor's operations in Libya. Production from all major fields was successfully restarted by the joint venture operator in late 2011 and early 2012. Suncor is optimistic about a gradual return to full operations in the country.

In Syria, amid continuing unrest, sanctions were introduced that resulted in Suncor declaring force majeure under its contractual obligations and suspending its operations in the country. The company has ceased recording all production and revenue from its Syrian assets. The company continues to comply with all relevant sanctions.

•
  Non-core asset divestiture activity winds down.

During the year, the company completed dispositions of non-core assets in the U.K. portion of the North Sea and Western Canada for total net proceeds of $304 million. Due to market conditions confronting the company's North America Onshore operations, opportunities to divest additional natural gas properties that met the company's financial objectives were limited.

•
  Suncor continues investment in renewable energy assets.

Suncor completed the expansion of its ethanol plant in Ontario that doubled production capacity to 400 million litres per year and confirmed the plant as Canada's largest biofuels production facility. Suncor also commenced operations at two new wind power projects – the 88-MW Wintering Hills project in southern Alberta and the 20-MW Kent Breeze project in southwest Ontario.

•
  Systems integration project completed.

The company completed the integration of assets acquired in the merger with Petro-Canada onto a common information systems platform.

•
  Energy Trading optimizes price realizations for Oil Sands barrels.

Suncor's Energy Trading business contributed significantly to cash flow from operations in 2011. This business supports Oil Sands production by optimizing price realizations and managing inventory levels. In recent years, the Energy Trading business has entered into arrangements for midstream infrastructure, such as pipeline and storage capacity, which enables Suncor to optimize the delivery of existing and future growth production.

(1)
  Operating earnings, cash flow from operations and ROCE are non-GAAP financial measures. The company has restated operating earnings from 2010 for the transition to IFRS and for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 21

3. SUNCOR OVERVIEW

Suncor is an integrated energy company headquartered in Calgary, Alberta. Suncor has classified its operations into the following segments:

OIL SANDS

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

•
  Oil Sands operations refers to Suncor's wholly owned and operated mining, extraction, upgrading and in situ assets in the Athabasca oil sands region. Oil Sands activities consist of:
  •
    Oil Sands Base operations include the Millennium and Steepbank (including the NSE) mining and extraction operations, two 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 Tailings Reduction Operations (TROTM) 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. The majority of In Situ production is upgraded by Oil Sands Base; however, the company's marketing plan includes sales of bitumen when marketing conditions are favourable or as operating conditions at Oil Sands Base require.
•
  Oil Sands Ventures includes the company's interests in significant growth projects, including two where Suncor is the operator – the Fort Hills mining project (40.8%) and the Voyageur upgrader project (51%) – and one where Total E&P is the operator – the Joslyn mining project (36.75%). Oil Sands Ventures also includes the company's 12% interest in the Syncrude oil sands mining and upgrading joint venture.

EXPLORATION AND PRODUCTION

In January 2011, Suncor combined its International and Offshore and Natural Gas segments into the Exploration and Production segment, which 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, for which Suncor is the operator. Suncor also holds a 20% 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 a 26.69% interest in the Golden Eagle Area Development (Golden Eagle) – both of which are operated by another company – in the U.K. portion of the North Sea. Suncor also holds interests in several North Sea licences offshore the U.K. and Norway. Suncor owns, pursuant to a Production Sharing Contract (PSC), an interest in the Ebla gas development in the Ash Shaer and Cherrife areas in Syria. Suncor also owns, pursuant to Exploration and Production Sharing Agreements (EPSAs, a form of PSC), working interests in the exploration and development of oilfields in the Sirte Basin in Libya.

Due to recent unrest in both countries, the company has declared force majeure under its contractual obligations in Libya and Syria. Operations in Libya are in the process of restarting, while operations in Syria have been suspended indefinitely.

•
  North America Onshore operations include Suncor's interests in a number of assets in Western Canada, which primarily produce natural gas.

22 SUNCOR ENERGY INC. 2011 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, Quebec 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 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 supply and trading activities, and other activities not directly attributable to any other operating segment.

•
  Renewable Energy interests include six operating wind power projects and the St. Clair ethanol plant in Ontario.
•
  Energy Trading activities primarily involve the marketing and trading of crude oil, natural gas, refined petroleum products and byproducts, and the use of midstream infrastructure and financial derivatives to optimize related trading strategies.
•
  Corporate includes 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. 2011 ANNUAL REPORT 23

4. CONSOLIDATED FINANCIAL INFORMATION

Financial Highlights (1)

Year ended December 31 ($ millions, except per share amounts) |  | 2011 |  | 2010 |  | 2009 |
Net earnings |  | 4 304 |  | 3 829 |  | 1 146 |
| per common share – basic |  | 2.74 |  | 2.45 |  | 0.96 |
| per common share – diluted |  | 2.67 |  | 2.43 |  | 0.95 |
Operating earnings (2) |  | 5 674 |  | 2 634 |  | 1 115 |
| per common share – basic |  | 3.61 |  | 1.69 |  | 0.93 |
Cash flow from operations (2) |  | 9 746 |  | 6 656 |  | 2 799 |
| per common share – basic |  | 6.20 |  | 4.25 |  | 2.34 |
Dividends paid on common shares |  | 664 |  | 611 |  | 401 |
| per common share |  | 0.43 |  | 0.40 |  | 0.30 |
Operating revenues (net of royalties) |  | 39 337 |  | 32 003 |  | 17 459 |
Balance sheet |  |  |  |  |  |  |
| Total assets |  | 74 777 |  | 68 607 |  | 69 746 |
| Long-term debt (including current portion) |  | 10 016 |  | 10 347 |  | 13 880 |
| Net debt |  | 6 976 |  | 11 254 |  | 13 377 |

Segment Highlights (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings (loss) |  |  |  |  |  |  |  |
| Oil Sands |  | 2 603 |  | 1 520 |  | 557 |  |
| Exploration and Production |  | 306 |  | 1 938 |  | 78 |  |
| Refining and Marketing |  | 1 726 |  | 819 |  | 407 |  |
| Corporate, Energy Trading and Eliminations |  | (331 | ) | (448 | ) | 104 |  |
Total |  | 4 304 |  | 3 829 |  | 1 146 |  |
Operating earnings (loss) (2) |  |  |  |  |  |  |  |
| Oil Sands |  | 2 737 |  | 1 379 |  | 1 048 |  |
| Exploration and Production |  | 1 358 |  | 1 193 |  | 150 |  |
| Refining and Marketing |  | 1 726 |  | 796 |  | 455 |  |
| Corporate, Energy Trading and Eliminations |  | (147 | ) | (734 | ) | (538 | ) |
Total |  | 5 674 |  | 2 634 |  | 1 115 |  |
Cash flow from (used in) operations (2) |  |  |  |  |  |  |  |
| Oil Sands |  | 4 572 |  | 2 777 |  | 1 251 |  |
| Exploration and Production |  | 2 846 |  | 3 325 |  | 1 280 |  |
| Refining and Marketing |  | 2 574 |  | 1 538 |  | 921 |  |
| Corporate, Energy Trading and Eliminations |  | (246 | ) | (984 | ) | (653 | ) |
Total |  | 9 746 |  | 6 656 |  | 2 799 |  |

(1)
  2009 data is prepared in accordance with Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measures. Operating earnings are reconciled to net earnings in this section of the MD&A under the heading Consolidated Operating Earnings Reconciliation. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings from 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

24 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

Operating Highlights

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Production volumes (mboe/d) |  |  |  |  |  |  |
| Oil Sands |  | 339.3 |  | 318.2 |  | 306.7 |
| Exploration and Production |  | 206.7 |  | 296.9 |  | 149.3 |
|  | 546.0 |  | 615.1 |  | 456.0 |
Average price realizations |  |  |  |  |  |  |
| Oil Sands ($/bbl) |  | 90.07 |  | 70.85 |  | 62.53 |
| Exploration and Production ($/boe) |  | 80.62 |  | 59.47 |  | 57.44 |
|  | 86.49 |  | 65.32 |  | 47.47 |
Refined product sales volumes (thousands of m3/d) |  |  |  |  |  |  |
| Eastern North America |  | 43.5 |  | 45.3 |  | 27.7 |
| Western North America |  | 39.6 |  | 42.0 |  | 27.2 |
|  | 83.1 |  | 87.3 |  | 54.9 |

(1)
  The volume for divestitures compares annualized 2011 production with total production from 2010 for divested assets. Other figures presented for changes in production volumes include all other factors impacting production volumes.

The decrease in production volumes for 2011, compared with 2010, reflects primarily asset dispositions completed throughout 2010 and 2011. Suncor disposed of non-core natural gas assets in Western Canada and the U.S. Rockies, which contributed approximately 27.4 mboe/d more production than in 2011 (comprised of 23.8 mboe/d from assets disposed in 2010 and 3.6 mboe/d from assets disposed in 2011). Suncor also disposed of non-core North Sea assets, which contributed 19.7 mboe/d more production in 2010, and Trinidad and Tobago assets representing 6.7 mboe/d of 2010 production.

For Oil Sands, the production increase primarily reflected higher output from Oil Sands Base mining and extraction operations and the negative impacts of two upgrader fires at Oil Sands Base on production in the first half of 2010. Production from Syncrude in 2011 decreased slightly compared with 2010, due mainly to operational issues experienced late in 2011.

Excluding the impacts of asset divestitures, for Exploration and Production, decreases for International reflected primarily the shut-in of production in Libya for most of the year due to political unrest and outages at Buzzard for the repair of the cooling system and the completion and commissioning of the fourth platform. These decreases for International were partially offset by a year-over-year increase from Syria, which started producing in April 2010. Decreases for East Coast Canada primarily reflected the partial shut-in of production at Terra Nova due to the presence of hydrogen sulphide (H2S) in some wells. Decreases for North America Onshore primarily reflected natural declines in reservoir performance.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 25

Net Earnings

Suncor's net earnings for 2011 were $4.304 billion, compared to $3.829 billion in 2010. Net earnings were primarily 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 2011, compared with 2010, included:

Operating Earnings Adjustments

•
  The after-tax unrealized foreign exchange loss on the revaluation of U.S. dollar denominated long-term debt was $161 million in 2011, compared with a gain of $372 million in 2010. During 2011, the US$/Cdn$ exchange rate decreased from 1.01 to 0.98. During 2010, the US$/Cdn$ exchange rate increased from 0.96 to 1.01.
•
  In 2011, the company recorded net impairment charges of $503 million ($514 million initial impairment, net of $11 million of subsequent impairment reversals) against assets pertaining to its operations in Libya, which were shut-in as a result of unrest. 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.

In 2010, the company recorded after-tax write-offs of $143 million relating primarily to equipment used in an alternative mining and extraction process that was discontinued, after-tax impairment charges of $111 million against certain North America Onshore assets primarily due to decreasing natural gas prices, and after-tax impairment charges of $52 million against non-core U.K. assets that were eventually sold later in 2010 and in 2011.

•
  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 statutory 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 2010, the company sold several non-core Exploration and Production assets (described in the Segment Results and Analysis – Exploration and Production section of this MD&A) and realized after-tax gains on disposal of $826 million.

•
  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.

In 2010, Suncor recorded after-tax expenses of $68 million for several other write-offs and provisions related to assets acquired in the merger.

•
  In 2010, the Oil Sands segment recorded after-tax gains of $233 million related to the change in fair value of certain commodity derivatives, net of realizations, which the company had entered into in previous years to manage the volatility of sales prices for its production.
•
  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 joint owners of Terra Nova reached agreement on a technical review of the interests they contributed.
•
  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. 2011 ANNUAL REPORT

Consolidated Operating Earnings Reconciliation (1)(2)(3)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings as reported |  | 4 304 |  | 3 829 |  | 1 146 |  |
Unrealized foreign exchange loss (gain) on U.S. dollar denominated long-term debt |  | 161 |  | (372 | ) | (798 | ) |
Impairments and write-offs |  | 629 |  | 306 |  | 42 |  |
Impact of income tax rate adjustments on deferred income taxes |  | 442 |  | — |  | 4 |  |
Loss (gain) on significant disposals |  | 107 |  | (826 | ) | 39 |  |
Adjustments to provisions for assets acquired through the merger (4) |  | 31 |  | 68 |  | 97 |  |
Change in fair value of commodity derivatives used for risk management, net of realizations (5) |  | — |  | (233 | ) | 499 |  |
Redetermination of working interest 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 (6) |  | — |  | — |  | (438 | ) |
Costs related to deferral of growth projects (7) |  | — |  | — |  | 299 |  |
Operating earnings |  | 5 674 |  | 2 634 |  | 1 115 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Operating earnings is a non-GAAP financial measure. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3)
  The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(4)
  Adjustment in 2011 related to a royalty dispute for a period prior to the merger. 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. Adjustments in 2009 included the negative impact associated with inventory acquired at fair value.
(5)
  Adjustments 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. The company held no significant crude oil risk management derivatives in 2011.
(6)
  Impact from the deemed settlement value assigned to the bitumen processing contract with Petro-Canada upon close of the merger.
(7)
  The company incurred costs related to placing certain growth projects into "safe mode" due to unfavourable market conditions in prior years. The company stopped removing these costs from operating earnings effective January 1, 2010. After-tax safe mode costs for the years ended December 31, 2011 and 2010 were approximately $57 million and $94 million, respectively.

(1)
  Factors represent after-tax variances and include the impacts of operating earnings adjustments. These factors are analyzed in the Operating Earnings narrative immediately subsequent to this bridge analysis. This bridge analysis is presented because management uses this presentation to analyze performance.
(2)
  Calculated based on upstream production volumes and Refining and Marketing sales volumes.
(3)
  Includes upstream price realizations before royalties and transportation costs, refining and marketing margins, other operating revenues, and the net impacts of sales and purchases of third-party crude.
(4)
  The Inventory variance factor 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 variance factor in this bridge analysis permits the company to present the Volume variance factor for upstream assets based on production volumes, rather than based on sales volumes.
(5)
  This factor includes transportation expense, operating, selling and general expense and project start-up costs.
(6)
  This factor also includes changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in effective income tax rates, and other income tax adjustments.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 27

Operating Earnings

Suncor's consolidated operating earnings (1) for 2011 were $5.674 billion, compared to $2.634 billion in 2010. Positive factors impacting operating earnings in 2011, compared with 2010, included:

•
  Average price realizations for crude oil production from upstream assets were considerably higher in 2011, consistent with significant increases in benchmark prices for WTI and Brent crudes. The average price realization for the Oil Sands segment in 2011 was $90.07/bbl, compared to $70.85/bbl in 2010. The average price realization for the Exploration and Production segment was $80.62/boe in 2011, compared to $59.47/boe in 2010.
•
  Refining margins were higher in 2011, reflected by large increases in benchmarks for 3-2-1 crack spreads. Refining margins also benefited from the increasing crude price environment, whereby inventories produced during periods of lower feedstock costs were sold and replaced with inventories purchased at relatively higher feedstock costs.
•
  Oil Sands production volumes (excluding Syncrude) increased to 304.7 mbbls/d from 283.0 mbbls/d, due primarily to higher bitumen output from Oil Sands Base and In Situ operations. Production volumes from the first half of 2010 were impacted by two upgrader fires.
•
  Financing expense was lower in 2011 than 2010, due mainly to an increase in capitalized interest (approximately $225 million more capitalized after tax). Suncor capitalized a higher percentage of its borrowing costs due mainly to amounts capitalized for the Voyageur upgrader, Fort Hills and Joslyn projects, subsequent to the completion of transactions with Total E&P.
•
  Other income was higher in 2011 than 2010, due mainly to higher operating earnings from Suncor's Energy Trading business. In addition, in 2010, the company realized losses on the final settlement of risk management activities pertaining to derivatives the company had entered into in previous years to manage the volatility of sales prices for its production.
•
  Share-based compensation expense was lower in 2011 than in 2010, due mainly to a decrease in the company's common stock price during the second half of the year. Operating expense for 2011 included after-tax share-based compensation expense of $24 million, whereas operating expense for 2010 included after-tax share-based compensation expense of $146 million.
•
  The Inventory variance factor was positive, primarily for Oil Sands, because inventories that were produced during the prior year at relatively lower production costs were sold and replaced by inventories produced during the current year at relatively higher production costs.
•
  DD&A was lower in 2011 than in 2010, due mainly to lower production volumes from Exploration and Production.

The positive factors noted above were partially offset by the following:

•
  Production volumes for the Exploration and Production segment decreased to 206.7 mboe/d from 296.9 mboe/d, primarily due to the divestiture of non-core assets throughout 2010 and 2011, the shut-in of production in Libya for the majority of 2011, unplanned outages at Buzzard, and the partial shut-in of wells at Terra Nova due to the presence of H2S.
•
  Operating expenses, excluding the impacts of share-based compensation expense, were significantly higher in 2011 than in 2010, due mainly to the increase for the Oil Sands segment. Oil Sands Base mining costs were higher and reflected increased bitumen output and higher tonnes of ore moved while working through an area of lower bitumen ore grade quality. Oil Sands Base upgrading costs were higher due mainly to maintenance associated with secondary upgrading units. In Situ costs were higher due mainly to higher operating expenses and start-up costs associated with the Firebag Stage 3 expansion.
•
  Royalties were higher in 2011 than in 2010, mainly due to higher overall upstream price realizations.

Cash Flow from Operations

Consolidated cash flow from operations (1) for 2011 was $9.746 billion, compared to $6.656 billion in 2010. The increase was mainly due to the same factors that affected the increase in operating earnings, particularly higher upstream price realizations, refining margins and production from Oil Sands.

Results for 2010 compared with 2009

Net earnings for 2010 were $3.829 billion compared to $1.146 billion in 2009. Operating earnings (1) for 2010 were $2.634 billion compared to $1.115 billion in 2009. These increases were due primarily to the inclusion of a full year of operations from assets acquired in the merger with Petro-Canada on August 1, 2009 and higher upstream price realizations.

Upstream production for 2010 averaged 615.1 mboe/d, compared to 456.0 mboe/d in 2009. Downstream refined

28 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

product sales averaged 87,300 m3/d in 2010, compared to 54,900 m3/d in 2009. Both volumes increased primarily due to new assets acquired in the merger. Higher production also meant higher royalties and DD&A in 2010, compared with 2009. The merger increased Suncor's asset base by approximately $35.8 billion (including goodwill) and long-term debt by $4.4 billion. Net earnings in 2010 included $826 million of after-tax gains on disposal of non-core assets, many of which were acquired through the merger.

Average price realizations were higher in 2010 than in 2009, as increases in important crude benchmarks like WTI and Brent more than offset the impacts of an increasing light/heavy crude differential and the Canadian dollar strengthening against the U.S. dollar.

Much of 2009 was affected by the general economic downturn. Suncor incurred after-tax expenses of $299 million to place certain growth projects in safe mode.

Cash flow from operations (1) was $6.656 billion in 2010, compared to $2.799 billion in 2009, and increased due mainly to the impacts of higher upstream production volumes from assets acquired in the merger and higher average price realizations.

Net debt decreased by $2.1 billion in 2010. Suncor sold non-core assets for total proceeds of approximately $3.5 billion during 2010 and used these funds mainly to reduce total debt.

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

Business Environment

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

(average for the year ended December 31, except as noted) |  |  |  | 2011 |  | 2010 |  | 2009 |
WTI crude oil at Cushing |  | US$/bbl |  | 95.10 |  | 79.55 |  | 61.80 |
Dated Brent crude oil at Sullom Voe |  | US$/bbl |  | 111.15 |  | 79.50 |  | 61.50 |
Dated Brent/Maya FOB price differential |  | US$/bbl |  | 12.50 |  | 9.30 |  | 5.00 |
Canadian 0.3% par crude oil at Edmonton |  | Cdn$/bbl |  | 95.75 |  | 78.05 |  | 65.80 |
Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty |  | US$/bbl |  | 17.25 |  | 14.20 |  | 9.70 |
Condensate at Edmonton |  | US$/bbl |  | 105.30 |  | 81.90 |  | 60.45 |
Natural gas (Alberta spot) at AECO |  | Cdn$/mcf |  | 3.65 |  | 4.15 |  | 4.15 |
New York Harbor 3-2-1 crack (1) |  | US$/bbl |  | 27.00 |  | 10.55 |  | 8.80 |
Chicago 3-2-1 crack (1) |  | US$/bbl |  | 24.65 |  | 9.00 |  | 7.75 |
Portland 3-2-1 crack (1) |  | US$/bbl |  | 28.40 |  | 13.55 |  | 11.40 |
Gulf Coast 3-2-1 crack (1) |  | US$/bbl |  | 24.80 |  | 7.90 |  | 7.10 |
Exchange rate |  | US$/Cdn$ |  | 1.01 |  | 0.97 |  | 0.88 |
Exchange rate (end of period) |  | US$/Cdn$ |  | 0.98 |  | 1.01 |  | 0.96 |

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

Suncor's sweet SCO price realizations are influenced primarily by changes in the price for WTI at Cushing. The average WTI price for 2011 increased to US$95.10/bbl from US$79.55/bbl in 2010. The WTI price continued to fluctuate significantly throughout 2011, and at times was as high as US$113/bbl and as low as US$80/bbl. Suncor's price realizations for SCO are also influenced by the supply and demand of sweet SCO from Western Canada. In 2011, sweet SCO averaged trading at a significant premium to WTI.

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 circumstances underlying spot sales required to manage inventory levels. Similar to WTI, prices for Canadian par crude at Edmonton increased significantly in 2011, compared to 2010. The average Edmonton par price was US$95.75/bbl in 2011 and US$78.05/bbl in 2010.

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 prices for Canadian heavy crude oil (WCS at Hardisty is a common reference) and prices for diluent (Condensate at Edmonton). Diluent is sourced primarily from the company's own upgrading and refining facilities; however,

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 29

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, and bitumen quality. Average price realizations for bitumen in 2011 were higher than those realized in 2010, due mainly to higher overall crude oil prices partially offset by wider light/heavy differentials and higher prices for diluent.

Suncor's price realizations for production from East Coast Canada and International assets are influenced primarily by the price for Brent crude. Brent crude averaged US$111.15/bbl in 2011, much higher than the average of US$79.50/bbl in 2010. The Brent crude price also fluctuated significantly throughout 2011, averaging over US$100/bbl since February, and at times was as high as US$126/bbl. Brent crude also began to trade at a substantial premium to WTI, averaging US$16.05/bbl for 2011, compared to a small discount of $0.05/bbl in 2010.

Suncor's price realizations for North America Onshore natural gas production are primarily referenced to Alberta spot at AECO. The AECO benchmark averaged $3.65/mcf in 2011, which was lower than the average AECO benchmark of $4.15/mcf in 2010.

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 indicate when more complex refineries can earn greater margins by processing 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 2011, crack spreads were very high; in part because refined product prices reflected the higher priced Brent crude feedstock of coastal North American markets. This positively benefited Suncor's inland refineries (Sarnia, Edmonton and Commerce City) for much of 2011. 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 and results in unrealized translation gains.

In 2011, although the average US$/Cdn$ exchange rate of 1.01 reflected a stronger relative Canadian dollar over the entire year, the change in the US$/Cdn$ exchange rate from the beginning of the year (1.01) to the end of the year (0.98) impacted the year-end translation of U.S. dollar denominated balances as if the Canadian dollar was relatively weaker.

Economic Sensitivities (1)(2)(3)

The following table illustrates the estimated effects that changes in certain factors would have had on 2011 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 | 81 |  | 108 |  |
Natural gas +Cdn$0.10/mcf | (1 | ) | (1 | ) |
Light/heavy differential +US$1.00/bbl | 43 |  | 58 |  |
3-2-1 crack spreads +US$1.00/bbl | 109 |  | 134 |  |
Foreign exchange +$0.01 US$/Cdn$ | (37 | ) | (150 | ) |

(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.

30 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

5. SEGMENT RESULTS AND ANALYSIS

OIL SANDS

Strategy and Operational Update

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.

In 2012, Oil Sands Base expects to integrate new mining and upgrading projects that complement its core operations. Oil Sands Base is continuing the ramp up of bitumen production from the NSE, which is expected to reduce mine congestion and lower average haul distances. In addition, Oil Sands Base expects to commission and start up the MNU, which is expected to improve the reliability and availability of its upgrading facilities.

Production growth from the Firebag Stage 3 expansion is on track. Firebag Stage 4 leverages our existing infrastructure and is a smaller project to execute than Stage 3, but is anticipated to bring additional barrels of production equivalent to Stage 3. We expect our portfolio of technology projects will drive improvements and efficiencies in current production and develop future opportunities. This portfolio focuses on both subsurface and surface challenges, such as reducing steam-to-oil ratios and improving the efficiency of steam production and water treatment.

Suncor's transactions with Total E&P closed in March 2011. In order to manage and develop all of the new joint ventures, Suncor created a new business area – Oil Sands Ventures. Throughout 2011, Oil Sands Ventures focused on ensuring the successful restart of the Fort Hills mining and Voyageur upgrader projects, and bringing in operating expertise to complement existing proficiencies and commercial capabilities to effectively manage these new joint ventures. Suncor and the joint venture owners of the Fort Hills, Voyageur upgrader and Joslyn projects have developed a capital program for site preparation and are working towards making decisions regarding the sanctioning of these projects in 2013.

Financial Highlights (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Gross revenues |  | 13 001 |  | 9 690 |  | 6 744 |  |
Less: Royalties |  | (799 | ) | (681 | ) | (645 | ) |
Operating revenues, net of royalties |  | 12 202 |  | 9 009 |  | 6 099 |  |
Net earnings |  | 2 603 |  | 1 520 |  | 557 |  |
Operating earnings (2) |  | 2 737 |  | 1 379 |  | 1 048 |  |
Cash flow from operations (2) |  | 4 572 |  | 2 777 |  | 1 251 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Oil Sands net earnings for 2011 were $2.603 billion, compared to $1.520 billion in 2010. Net earnings for 2011 included an after-tax 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. Net earnings for 2010 included after-tax gains of $233 million for the change in fair value of commodity derivatives used for risk management, net of realizations, 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.

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

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 31

Operating Earnings

Operating Earnings Reconciliation (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings as reported |  | 2 603 |  | 1 520 |  | 557 |  |
Loss on significant disposals |  | 99 |  | — |  | 39 |  |
Impairments and write-offs |  | 35 |  | 143 |  | — |  |
Change in fair value of commodity derivatives used for risk management, net of realizations |  | — |  | (233 | ) | 499 |  |
Modification of the bitumen valuation methodology |  | — |  | (51 | ) | 50 |  |
Gain on effective settlement of pre-existing contract with Petro-Canada |  | — |  | — |  | (438 | ) |
Costs related to deferral of growth projects |  | — |  | — |  | 299 |  |
Impact of income tax rate adjustments on deferred income taxes |  | — |  | — |  | 37 |  |
Adjustments to provisions for assets acquired through the merger |  | — |  | — |  | 5 |  |
Operating earnings (2) |  | 2 737 |  | 1 379 |  | 1 048 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measure. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

(1)
  Factors represent after-tax variances and include the impacts of operating earnings adjustments. These factors are analyzed in the narrative immediately subsequent to this bridge analysis. This bridge analysis is presented because management uses this presentation to analyze performance.
(2)
  Includes price realizations before royalties and transportation costs, other operating revenues and the net impacts of sales and purchases of third-party crude.
(3)
  The Inventory variance factor 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 variance factor in this bridge analysis permits the company to present the Volume variance factor based on production volumes, rather than based on sales volumes.
(4)
  This factor includes transportation expense, operating, selling and general expense, and project start-up costs.
(5)
  This factor also includes changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in effective income tax rates, and other income tax adjustments.

32 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

Production Volumes

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Oil Sands (mbbls/d) |  | 304.7 |  | 283.0 |  | 290.6 |
Oil Sands Ventures (mbbls/d) |  | 34.6 |  | 35.2 |  | 16.1 |
Total (mbbls/d) |  | 339.3 |  | 318.2 |  | 306.7 |

Production volumes from Oil Sands (excluding Syncrude) in 2011 averaged 304.7 mbbls/d, compared to 283.0 mbbls/d in 2010, and increased mainly due to operational improvements at the company's mining and extraction operations, reflected by a 12% increase in bitumen ore tonnes mined. Production from the first half of 2010 was impacted by two upgrader fires. In 2011, Suncor successfully completed the largest planned maintenance event in its history at its Upgrader 2 facilities, lasting approximately six weeks; the impact of this event on 2011 production was greater than the two relatively smaller planned maintenance events completed in 2010.

Oil Sands achieved a single-month production record of 345,000 bbls/d in December, reflecting higher bitumen output from In Situ operations and an increase in bitumen ore tonnes mined, partially offset by lower bitumen ore grade quality at the Millennium mine face. Suncor anticipates that lower bitumen ore grade quality will continue to impact operations until the start of the fourth quarter of 2012, at which point the bitumen ore grade quality is expected to return to previous levels.

In Situ bitumen production volumes averaged 89.5 mbbls/d in 2011, compared to 85.1 mbbls/d in 2010. Output from Firebag averaged 59.5 mbbls/d in 2011, an 11% increase from 53.6 mbbls/d in 2010. This increase was due mainly to new production starting in the second half of 2011 from the first well pad for the Stage 3 expansion and from new infill wells completed on existing well pads. MacKay River production averaged 30.0 mbbls/d in 2011, down slightly from 2010 production of 31.5 mbbls/d. Overall MacKay River production levels have been at or around nameplate capacity (approximately 30,000 bbls/d) since 2009. The company anticipates that new wells coming on-stream in the fourth quarter of 2011 and throughout 2012, combined with well workovers, will offset natural declines from existing well pairs. Bitumen production from Suncor's In Situ operations exited 2011 at approximately 111,000 bbls/d.

For Oil Sands Ventures, Suncor's share of Syncrude production decreased to 34.6 mbbls/d in 2011, compared to 35.2 mbbls/d in 2010. Production in 2011 was negatively impacted by operational issues with a hydrogen plant following the planned maintenance event in the fall.

Average Price Realizations and Sales Volumes (1)

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |  |
Oil Sands ($/bbl) |  | 88.74 |  | 69.58 |  | 61.66 |  |
| – relative to WTI (Cdn$/bbl) |  | (5.35 | ) | (12.33 | ) | (9.59 | ) |
| Sales volumes (mbbls/d) |  | 304.4 |  | 279.3 |  | 276.2 |  |
| Sales mix (sweet/sour) (%) |  | 36/64 |  | 37/63 |  | 47/53 |  |
Oil Sands Ventures ($/bbl) |  | 101.80 |  | 80.93 |  | 77.36 |  |

(1)
  Average price realizations are before royalties and net of related transportation costs, and include the impact of realized derivative gains and losses.

Oil Sands sales volumes (excluding Syncrude) increased in 2011, compared with 2010. The sweet/sour sales mix for 2011 (36%/64%) was slightly lower than 2010 (37%/63%). The Upgrader 1 hydrogen plant experienced several outages over the second half of 2010 and into the first half of 2011. The company completed maintenance on these units and, as a result, the sweet/sour sales mix for the fourth quarter of 2011 was 46%/54%.

Average price realizations for Oil Sands sales were $88.74/bbl (WTI less $5.35/bbl) in 2011, compared to $69.58/bbl (WTI less $12.33/bbl) in 2010, and increased mainly due to higher benchmark prices for crude oil. The average price realization for sales relative to WTI improved due mainly to higher differentials for SCO compared to WTI. Suncor's average price realization for Syncrude sales in 2011 was $101.80/bbl, compared to $80.93/bbl in 2010, and was higher due to higher benchmark prices for crude oil and higher differentials between SCO and WTI.

Royalties

Royalties were slightly higher in 2011 than in 2010. Oil Sands royalties are influenced primarily by the valuation for bitumen, which was approximately 10% higher in 2011. In Situ royalties were also higher because MacKay River reached the higher, post-payout phase as determined by regulation in November 2010. These increases were partially offset by increased capital expenditures for royalty-eligible capital expenditures (primarily the TROTM project). Royalties in 2010 were impacted by the receipt of business interruption insurance proceeds, which were subject to royalty, related to the upgrader fires in 2009 and 2010.

For 2011, Suncor continued to remit royalty payments under its BVM for production from Oil Sands Base operations based on its view of reasonable quality adjustments; however, royalty expense was calculated based on the quality adjustment enacted by the Alberta government in December 2010. Suncor's Royalty Amending Agreement (the Suncor RAA) provides for an arbitration procedure failing settlement of these issues. Suncor filed a Notice of Commencement of Arbitration with the Alberta government on January 29, 2011.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 33

Inventory

The Inventory variance factor was positive because inventories produced during the prior year at relatively lower production costs were sold and replaced by inventories produced during the current year at relatively higher production costs.

Oil Sands Cash Operating Costs (1)

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Oil Sands cash operating costs ($ millions) |  | 4 479 |  | 3 990 |  | 3 599 |
Oil sands cash operating costs ($/bbl) |  | 40.20 |  | 38.65 |  | 33.95 |

(1)
  Oil Sands cash operating costs is a non-GAAP financial measure, and is reconciled to operating, selling and general expense in the Non-GAAP Financial Measures Advisories section of this MD&A.

Oil Sands cash operating costs per barrel increased in 2011, averaging $40.20/bbl, compared to $38.65/bbl in 2010, with the impact of higher total Oil Sands cash operating costs (+$4.40/bbl) partially offset by the impact of higher Oil Sands production (-$2.85/bbl). Oil Sands cash operating costs per barrel increased more noticeably in the fourth quarter of 2011, mainly because of the ramp up of the Firebag Stage 3 expansion and higher mining costs necessary to maintain bitumen supply while working through the lower ore grade quality zone at the Millennium mine face and to remove more tonnes of overburden.

Oil Sands cash operating costs increased to $4.479 billion in 2011 from $3.990 billion in 2010. Within this total, In Situ cash operating costs increased significantly compared to 2010, due mainly to higher expenses for labour, maintenance, natural gas and support, most of which was associated with the Firebag Stage 3 expansion. For Oil Sands Base operations, upgrading costs were higher primarily as a result of maintenance related to the restart of the Upgrader 1 hydrogen plant, and mining costs were higher, due mainly to a larger workforce and higher maintenance and rentals to support increased bitumen output.

Expenses and Other Factors

Operating expenses at Syncrude were higher in 2011 than 2010, due primarily to increased maintenance stemming from operational issues, and higher diesel fuel costs, which reflected higher prices and higher overall consumption.

In addition, other operating expenses were lower in 2011 than 2010, primarily due to lower share-based compensation expense and lower costs related to the deferral of growth projects. These decreases were partially offset by higher project start-up costs related to the Firebag Stage 3 expansion and commissioning of the MNU.

The company continues to incur costs related to remobilizing certain growth projects out of "safe mode" after the economic downturn in late 2008 and early 2009. Pre-tax safe mode costs for 2011 were $76 million, compared to $126 million in 2010. Safe mode costs include the costs for maintaining equipment and facilities related to projects still in safe mode, the costs to assess the condition of assets coming out of safe mode, and the costs of remobilizing equipment and personnel.

DD&A expense for 2011 was higher than 2010, due mainly to a larger asset base that is the result of costs capitalized for recently commissioned In Situ assets and significant planned maintenance events in 2010 and 2011.

Other income was lower in 2011 than in 2010, mainly due to insurance proceeds received from Suncor's captive insurance company in 2010 related to the 2009 and 2010 upgrader fires.

Planned Maintenance Events

During the second quarter of 2011, the company successfully completed a six-week planned maintenance event safely and on schedule. The scope of this event, associated with Oil Sands Base Upgrader 2 facilities, was the largest in Suncor's history.

In the second quarter of 2012, the company expects to shut down one coker unit at Upgrader 1. In the third quarter of 2012, the company expects to complete maintenance on the vacuum tower and shut down one coker unit at Upgrader 2. The company is also currently planning to complete maintenance on secondary upgrading units at both Upgrader 1 and Upgrader 2 during 2012.

Arrangements with Total E&P

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

34 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

allocated to its disposed interests. The after-tax loss was modified in the fourth quarter of 2011 following adjustments finalized during the closing period. 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.

Results for 2010 compared with 2009

Oil Sands net earnings for 2010 were $1.520 billion, compared to $557 million in 2009. Net earnings in 2010 were positively impacted by gains related to the change in fair value of certain risk management derivatives, but negatively impacted by the write-off of mining and extraction equipment. Net earnings in 2009 were negatively impacted by losses related to the change in fair value of certain risk management derivatives, net of realizations, and by costs related to the deferral of growth projects triggered by the general economic downturn in 2008, but positively impacted by a gain related to the merger on the effective settlement of a pre-existing contract with Petro-Canada to upgrade MacKay River bitumen production.

Operating earnings for 2010 were $1.379 billion, compared to $1.048 billion in 2009. The increase was due mainly to higher overall price realizations that reflected higher benchmark prices and a full year of production from Suncor's share in Syncrude. This increase was partially offset by lower production from Oil Sands during the first half of 2010, due mainly to the impacts of the two upgrader fires, lower sweet/sour sales mix that was negatively impacted by the upgrader fires and operational issues with secondary upgrading facilities at Upgrader 1, and higher operating expenses mainly due to the upgrader fires.

Cash flow from operations for 2010 was $2.777 billion, compared to $1.251 billion in 2009. The increase in cash flow from operations was mainly due to the same factors that affected operating earnings.

EXPLORATION AND PRODUCTION

Strategy and Operational Update

Suncor's Exploration and Production operations are comprised primarily of conventional upstream assets that have lower operating costs and require less reinvestment to maintain production than unconventional oil sands assets. Over two-thirds of 2011 production from this segment received prices based on Brent crude, which traded at a significant premium to WTI for much of 2011. As a result, the Exploration and Production segment generated significant cash flow in 2011 despite lower production volumes, and is an important source of funding for Suncor's long-term growth strategy.

Production growth from Exploration and Production is also an important element of Suncor's long-term strategy. The development of the Golden Eagle, Hibernia Southern Extension Unit (HSEU), White Rose Extensions and Hebron all provide what the company believes are attractive opportunities to grow low-cost production and generate future cash flow.

In 2011, Exploration and Production faced many challenges. Operations were suspended for much of the year in Libya and were recently suspended in Syria. Production from Terra Nova was constrained by H2S issues, and production from the non-operated Buzzard platform experienced periods of lower rates due to operational issues. Suncor continues to see opportunity to further rightsize its asset base by divesting non-core properties in North America Onshore. However, poor market conditions for natural gas assets in Western Canada in 2011 offered limited opportunities that met the company's financial objectives.

For 2012, the effective execution of projects at our offshore assets, such as the dockside maintenance program for Terra Nova, is expected to set the company up for continued success. Exploration activities in the North Sea are expected to be associated with the Beta discovery and the Romeo prospect. Elsewhere, we are directing attention to continued cost reductions and unconventional and liquids-rich plays in our North America Onshore operations, and the restart of production from Libya provides the company with a cautiously optimistic outlook about a full return to business in that country.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 35

Financial Highlights (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Gross revenues |  | 6 784 |  | 7 043 |  | 2 858 |  |
Less: Royalties |  | (1 472 | ) | (1 377 | ) | (554 | ) |
Operating revenues, net of royalties |  | 5 312 |  | 5 666 |  | 2 304 |  |
Net earnings |  | 306 |  | 1 938 |  | 78 |  |
Operating earnings (2) |  | 1 358 |  | 1 193 |  | 150 |  |
Cash flow from operations (2) |  | 2 846 |  | 3 325 |  | 1 280 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

Exploration and Production net earnings for 2011 were $306 million in 2011, compared to $1.938 billion in 2010. Net earnings in 2011 were impacted by after-tax impairment charges of $503 million against assets in Libya ($514 million initial impairment, net of $11 million of subsequent impairment reversals) as a result of the shut-in of production and $68 million against certain North America Onshore properties due to decreasing natural gas prices. Net earnings in 2011 were also impacted by a deferred income tax expense adjustment of $442 million pertaining to an increase in the U.K. tax rate on oil and gas profits in the North Sea, an after-tax provision of $31 million pertaining to a royalty dispute covering a period from before the merger, and after-tax losses on disposal of non-core assets of $8 million. Net earnings in 2010 included after-tax gains on disposal of non-core assets of $826 million, 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 for $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 sold later in 2010 and the first quarter of 2011.

Operating earnings for 2011 were $1.358 billion, compared to $1.193 billion in 2010. The increase in operating earnings was primarily due to higher average 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 in 2011, compared to $3.325 billion in 2010. The decrease in cash flow from operations relative to the increase in operating earnings is due primarily to lower production from assets in 2011 that contributed relatively more to cash flow from operations than operating earnings in 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.

Operating Earnings

Operating Earnings Reconciliation (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings as reported |  | 306 |  | 1 938 |  | 78 |  |
Impairments and write-offs |  | 571 |  | 163 |  | 42 |  |
Impact of income tax rate adjustments on deferred income taxes |  | 442 |  | — |  | (19 | ) |
Adjustments to provisions for assets acquired through the merger |  | 31 |  | 84 |  | 25 |  |
Loss (gain) on significant disposals |  | 8 |  | (826 | ) | — |  |
Redetermination of working interest in Terra Nova |  | — |  | (166 | ) | 24 |  |
Operating earnings (2) |  | 1 358 |  | 1 193 |  | 150 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measure. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

36 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

(1)
  Factors represent after-tax variances and include the impacts of operating earnings adjustments. These factors are analyzed in the narrative immediately subsequent to this bridge analysis. This bridge analysis is presented because management uses this presentation to analyze performance.
(2)
  Includes price realizations before royalties and transportation costs, other operating revenues and the net impacts of sales and purchases of third-party crude.
(3)
  The Inventory variance factor 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 variance factor in this bridge analysis permits the company to present the Volume variance factor based on production volumes, rather than based on sales volumes.
(4)
  This factor includes transportation expense and operating, selling and general expense.
(5)
  This factor also includes changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in effective income tax rates, and other income tax adjustments.

Production Volumes (1)

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Production volumes |  |  |  |  |  |  |
| East Coast Canada (mbbls/d) |  | 65.6 |  | 68.6 |  | 24.3 |
| International (mboe/d) |  | 76.4 |  | 132.5 |  | 50.6 |
| North America Onshore (mmcfe/d) |  | 388 |  | 575 |  | 446 |
Total production (mboe/d) |  | 206.7 |  | 296.9 |  | 149.3 |
Mix (liquids/gas) (%) |  |  |  |  |  |  |
| East Coast Canada |  | 100/0 |  | 100/0 |  | 100/0 |
| International |  | 82/18 |  | 87/13 |  | 84/16 |
| North America Onshore |  | 8/92 |  | 9/91 |  | 11/89 |
Total production |  | 64/36 |  | 63/37 |  | 50/50 |

(1)
  Production volumes for 2009 represent Suncor's share of production from assets acquired in the merger with Petro-Canada from August 1, 2009 to December 31, 2009.

East Coast Canada production averaged 65.6 mbbls/d in 2011, compared to 68.6 mbbls/d in 2010.

•
  Production from Terra Nova in 2011 was lower than 2010 by 7.0 mbbls/d and was affected for the entire year by the partial shut-in of certain wells due to the presence of H2S. Production from Terra Nova increased later in 2011, subsequent to the completion of a new production well and the replacement of a subsea flow line that added back production from certain shut-in wells.
•
  Production from White Rose in 2011 was higher than 2010 by 4.0 mbbls/d and increased mainly due to higher production from the North Amethyst portion of the White Rose Extensions, which began producing in 2010.
•
  Production from Hibernia in 2011 was consistent with production in 2010. In 2011, Hibernia achieved first oil from the HSEU. At this time, Suncor does not anticipate significant incremental or sustained production from the HSEU until further development drilling and subsea infrastructure comes on-stream, which is planned for 2014.

International production averaged 76.4 mboe/d in 2011 compared to 132.5 mboe/d in 2010.

•
  Production from the North Sea in 2011 decreased by 32.3 mboe/d, compared with 2010, with 12.6 mboe/d of the decrease occurring at Buzzard. In 2011, production from Buzzard was impacted by production constraints due to fluctuating rates associated with the 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. The remaining production decrease from the North Sea was due to the disposal of non-core assets in the U.K. and

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 37

the Netherlands throughout 2010 and into the first quarter of 2011.

•
  Production from Libya in 2011 averaged 12.1 mbbls/d, compared to 35.2 bbls/d in 2010. Production from Libya was shut in starting in February due to the outbreak of political unrest. As a result of the unrest and subsequent sanctions introduced against the Libyan government, the company declared force majeure under its contractual obligations. Subsequent to the government regime change and the lifting of sanctions, production was restarted later in the year in three of five fields.
•
  Production from Syria averaged 17.6 mboe/d in 2011, up from 11.6 mboe/d in 2010, primarily because first gas from the Ebla project was achieved in April 2010 and first oil in December 2010. However, unrest in Syria led to international sanctions in December 2011 that prohibited transactions with Suncor's joint venture partner, and, as a result, the company declared force majeure under its contractual obligations and ceased recording further production.
•
  Production for International in 2010 also included 6.7 mboe/d from the company's Trinidad and Tobago assets, which were divested in the third quarter of 2010.

North America Onshore production for 2011 decreased to 388 mmcfe/d from 575 mmcfe/d in 2010. The decrease was due primarily to disposals of non-core assets throughout 2010 and 2011 that contributed incremental production of approximately 164 mmcfe/d in 2010 and average production of 21 mmcfe/d in 2011. Production from remaining properties decreased approximately 10% compared with 2010, due primarily to natural declines in reservoir performance.

Average Price Realizations (1)

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
East Coast Canada ($/bbl) |  | 108.42 |  | 80.20 |  | 76.86 |
International ($/boe) |  | 100.89 |  | 74.92 |  | 72.65 |
North America Onshore ($/mcfe) |  | 4.39 |  | 4.70 |  | 4.31 |

(1)
  Average price realizations are calculated before royalties and net of transportation costs.

Average price realizations in 2011 for sales of crude oil from East Coast Canada and International assets were significantly higher than 2010, due mainly to higher Brent crude prices.

Average price realizations for North America Onshore production were lower in 2011, mainly due to lower benchmark prices for natural gas at AECO. This decrease was partially offset by higher average price realizations for sales of crude oil and natural gas liquids, due mainly to higher prices for WTI.

Royalties

Royalties were higher in 2011, compared with 2010, due to higher price realizations, partially offset by the shut-in of production in Libya and lower production volumes from North America Onshore.

Expenses and Other Factors

Operating expenses and DD&A were lower in 2011 than in 2010, mainly due to the disposition of non-core assets throughout 2010 and 2011 and the suspension of operations in Libya. Exploration expense also decreased, mainly due to exploration activities in Libya being suspended and exploration well write-offs in 2010 in the Netherlands and Norway portions of the North Sea.

Other factors that impacted operating earnings in 2011, compared with 2010, included the effects of the higher tax rate that the U.K. government enacted in the first quarter of 2011.

Planned Maintenance Events

A dockside maintenance program is scheduled for the Terra Nova FPSO vessel for an estimated 21-week period during the second half of 2012. The company anticipates a return to the field with resumption of production prior to the end of 2012. The planned work includes the replacement of the FPSO water injection swivel and the completion of the replacement of subsea infrastructure to remediate H2S issues.

An extended, 18-week off-station maintenance program is scheduled to commence in the second quarter of 2012 for the White Rose FPSO, primarily to address issues with the FPSO propulsion system.

During these outages, there will be no production from the respective assets.

Smaller planned maintenance events are scheduled to occur at Hibernia and Buzzard in the third quarter of 2012.

Asset Dispositions

During 2011, the company disposed of certain non-core asset packages from its North America Onshore operations for net proceeds of $164 million, resulting in after-tax gains on disposition of $82 million. These divested assets contributed average production of approximately 35 mmcfe/d in 2010. Current market conditions for further dispositions are limiting opportunities that meet the company's financial objectives.

On March 31, 2011, the company completed its sale of non-core U.K. offshore assets (primarily Scott and Triton). Final net proceeds were £90 million (Cdn$140 million) and the related after-tax loss on disposition was $90 million.

38 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

During 2010, the company divested other assets:

•
  Throughout the year, the company completed the sale of a number of non-core North America Onshore properties for net proceeds of approximately $1.7 billion.
•
  In the third quarter, the company completed the sale of its shares in Petro-Canada Netherlands BV for net proceeds of €316 million (Cdn$420 million).
•
  In the third quarter, the company completed the sale of its assets in Trinidad and Tobago for net proceeds of US$378 million (Cdn$383 million).
•
  A portion of the sale of the non-core U.K. offshore assets was completed in the fourth quarter for net proceeds of £55 million (Cdn$86 million).

Update on the Impacts of Events in Libya

Following the regime change in Libya in the second half of 2011, Suncor's joint venture in Libya, Harouge Oil Operations BV (Harouge), successfully restarted production in all significant fields and work continues to stabilize production levels. Suncor's share of production exiting December 2011 was approximately 30,000 bbls/d. Suncor remains optimistic about a gradual return to full operations in Libya and is working to remove its EPSAs from force majeure.

In light of the uncertainty surrounding the situation in Libya at the end of the second quarter of 2011, management made an assessment that it may not be able to re-enter Libya for a period of one to two years, if at all, and that any resumption of operations may involve additional remedial expenditure. The company, therefore, determined that its assets in Libya were impaired and recorded charges of $259 million (net of income taxes of $nil) against producing assets in property, plant and equipment, $211 million (net of income taxes of $nil) against exploration and evaluation assets and $44 million (net of income taxes of $nil) against crude oil and materials inventories. Later in the year, the company was able to confirm the existence and sale of crude inventories and reversed impairment charges of $11 million (net of income taxes of $nil).

Suncor has re-engaged with the National Oil Company of Libya to discuss current operations and future plans; however, there is still sufficient unpredictability underlying operating in this region, including the time frame for the ramp up of production, future exploration commitments, and the extent of damage to the company's assets, which has not yet been fully assessed. Therefore, as at December 31, 2011, there have been no further changes in the company's assessment of the impairment recognized in the second quarter.

For further information about the impairment process, see the Accounting Policies and Critical Accounting Estimates section of this MD&A.

Update on the Impacts of Events in Syria

In December 2011, amid continuing unrest in Syria, sanctions were introduced that required Suncor to declare force majeure under its contractual obligations and suspend operations in the country. Suncor withdrew its expatriate staff and undertook measures to maintain support for its Syrian employees. Consequently, the company ceased recording all production and revenue associated with its Syrian assets. If force majeure is lifted in the future, the company expects it will have the right to recover its share of any production occurring during the force majeure period.

Suncor has not received payment for recent production. Suncor believes it is entitled to these receivables and will work with its joint venture partner to receive payment if and when the sanctions are removed. In accordance with GAAP, because of the uncertainty associated with collecting these amounts as a result of the political unrest and sanctions in Syria, Suncor has recorded an after-tax provision of $63 million against these receivables, which represents approximately half of the overall balance outstanding.

Suncor has 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. The result of this assessment did not require Suncor to record an impairment charge against its assets in Syria at December 31, 2011. Should the current situation in Syria be resolved in a timely manner, such that sanctions are lifted, PSCs and sales agreements resume unaltered, and payments for sale of hydrocarbons are received, we would expect that the value of Suncor's net assets in Syria would not be impaired. However, should the current situation persist or worsen, such that Suncor is unable to resume operations in the near term, the company believes its assets in Syria could be impaired in the future. Suncor's operations in Syria represented approximately 3% of the company's consolidated net earnings and cash flow from operations in 2011. The carrying value of Suncor's net assets in Syria at December 31, 2011 was approximately $900 million. For further information about the impairment process, see the Accounting Policies and Critical Accounting Estimates section of this MD&A.

As part of its normal course of operations, Suncor carries risk mitigation instruments in the aggregate amount of $405 million (pre-tax) on certain foreign operations, of which up to $300 million may apply to our assets in Syria.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 39

Results for 2010 compared with 2009

Exploration and Production net earnings in 2010 were $1.938 billion, compared to $78 million in 2009. Net earnings in 2010 included after-tax gains of $826 million on the disposal of non-core assets and an after-tax gain of $166 million for the redetermination of the company's working interest in Terra Nova, partially offset by after-tax impairments of $163 million.

Operating earnings for 2010 were $1.193 billion, compared to $150 million in 2009, and cash flow from operations was $3.325 billion in 2010, compared to $1.280 billion in 2009. All East Coast Canada and International production, and approximately 70% of 2010 North America Onshore production was acquired in the merger with Petro-Canada. Price realizations were higher in 2010 primarily due to higher benchmark prices for Brent crude.

REFINING AND MARKETING

Strategy and Operational Update

In 2011, the integrated network of Suncor's Refining and Marketing segment created significant value through its strategic assets, geographic leverage and product differentiation. The location and reliability of the Edmonton, Sarnia and Commerce City refineries enabled the capture of attractive inland crude differentials related to record high discounts for WTI compared to Brent crude. The integration of these refineries with crude output from Suncor's Oil Sands segment also resulted in lower feedstock costs. In addition, Suncor's strategy of positioning its marketing demands to exceed its refining capacity has enabled the refineries to keep crude throughputs high and spread fixed refining costs over a broader production base.

Suncor's strategy of leveraging high-value internal channels in its Marketing business was also very successful in 2011, with strong sales volumes and margins, boosting segment earnings beyond the refinery gate. Suncor's Petro-Canada branded outlets continue to be a leading retailer by market share in major urban areas of Canada.

For 2012, Refining and Marketing will continue to focus on the safety and reliability of its operations, 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 (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |
Operating revenues |  | 25 713 |  | 20 860 |  | 11 851 |
Net earnings |  | 1 726 |  | 819 |  | 407 |
Operating earnings (2) |  |  |  |  |  |  |
| Refining and Product Supply |  | 1 413 |  | 532 |  | 311 |
| Marketing |  | 313 |  | 264 |  | 144 |
|  | 1 726 |  | 796 |  | 455 |
Cash flow from operations (2) |  | 2 574 |  | 1 538 |  | 921 |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Refining and Marketing had net and operating earnings of $1.726 billion in 2011, compared with net earnings of $819 million and operating earnings of $796 million in 2010.

Refining and Product Supply operations contributed $1.413 billion to operating earnings in 2011, a significant increase compared with 2010, primarily due to higher refining margins and the positive impacts of an increasing crude price environment, whereby inventories produced during periods of lower feedstock costs were sold and replaced with inventories purchased at relatively higher feedstock costs. Marketing operations contributed $313 million to operating earnings in 2011, which was higher than in 2010, due mainly to strong demand and margins in wholesale and lubricants channels.

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

40 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

Operating Earnings

Operating Earnings Reconciliation (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings as reported |  | 1 726 |  | 819 |  | 407 |  |
Adjustments to provisions for assets acquired through the merger |  | — |  | (23 | ) | 67 |  |
Impact of income tax rate adjustments on deferred income taxes |  | — |  | — |  | (19 | ) |
Operating earnings (2) |  | 1 726 |  | 796 |  | 455 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measure. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

(1)
  Factors represent after-tax variances and include the impacts of operating earnings adjustments. These factors are analyzed in the narrative immediately subsequent to this bridge analysis. This bridge analysis is presented because management uses this presentation to analyze performance.
(2)
  This factor also includes changes in gains and losses on disposal of assets that are not operating earnings adjustments, changes in effective income tax rates, and other income tax adjustments.

Volumes

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Refined product sales (thousands of m3/d) |  |  |
| Gasoline |  | 39.7 |  | 41.1 |  | 27.6 |
| Distillate (1) |  | 30.4 |  | 30.4 |  | 18.3 |
| Other |  | 13.0 |  | 15.8 |  | 9.0 |
|  | 83.1 |  | 87.3 |  | 54.9 |
Refinery utilization (2)(3) (%) |  |  |
| Eastern North America |  | 94 |  | 89 |  | 87 |
| Western North America |  | 91 |  | 95 |  | 97 |
Crude oil processed (4) (thousands of m3/d) |  |  |
| Eastern North America |  | 32.0 |  | 30.5 |  | 29.6 |
| Western North America |  | 32.8 |  | 34.6 |  | 33.6 |

(1)
  Previously disclosed distillate sales volumes have been adjusted to remove certain volumes that originated from Oil Sands.
(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.
(3)
  Utilization rates are determined based on refinery capacities in effect prior to January 1, 2012.
(4)
  2009 figures have been adjusted to reflect operations subsequent to the merger with Petro-Canada on August 1, 2009, so that they align with refinery utilization rates.

Total sales of refined petroleum products averaged 83,100 m3/d in 2011, compared to 87,300 m3/d in 2010. Gasoline sales for 2011 in Eastern Canada decreased compared with 2010, due mainly to lower demand from higher pump prices and the disposal of numerous retail sites in 2010 as mandated by the Canadian Competition Bureau as a result of the merger. There was strong demand for distillate in 2011; however, sales volumes were impacted by a month-long disruption to third-party hydrogen supply at the Edmonton refinery. Sales of lubricants products increased approximately 5% compared to 2010, led by growth in higher margin products.

Refinery utilization in Eastern North America averaged 94% in 2011, compared to 89% in 2010. Refinery utilization in 2010 at the Sarnia refinery was negatively impacted by Enbridge pipeline disruptions.

Refinery utilization in Western North America averaged 91% in 2011, compared to 95% in 2010. Refinery utilization in 2011 for Edmonton was impacted primarily by a month-long disruption to third-party hydrogen supply

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 41

and a six-week planned maintenance event during the second quarter. Refinery utilization in 2011 for the Commerce City refinery was impacted by a five-week planned maintenance event during the second quarter.

Effective January 1, 2012, Suncor upwardly revised the nameplate capacities of the Commerce City and Montreal refineries, reflecting improvements in reliability and operations. The Commerce City refinery capacity increased from 93,000 bbls/d to 98,000 bbls/d and the Montreal refinery capacity increased from 130,000 bbls/d to 137,000 bbls/d.

Prices and Margins

Refining margins in 2011 were significantly higher than in 2010, due mainly to higher crack spreads and discounted prices for WTI-based crudes that benefited our inland refineries (Sarnia, Edmonton and Commerce City) for most of 2011. Refining margins were also higher in 2011 due to the increasing price environment for crude, whereby inventories produced during periods of lower feedstock costs were sold and replaced with inventories produced during periods of relatively higher feedstock costs.

Marketing margins for 2011 were strong in wholesale distillate channels, reflecting strong demand, and, for our lubricants operations, reflecting higher demand and increased sales of higher margin products.

Expenses and Other Factors

Operating expenses were slightly higher in 2011 than in 2010, due mainly to volume growth in wholesale channels, which resulted in higher costs for transportation and commissions, partially offset by lower share-based compensation expense. The Financing Expense and Other Income factor was positively impacted by a gain pertaining to the company's investments in marketing entities.

Planned Maintenance Events

Refining and Marketing has several smaller outages planned for 2012, but none as large as the three planned maintenance events that occurred in 2011 at the Sarnia, Edmonton and Commerce City refineries. For 2012, the company's planned maintenance events reflect crude unit maintenance at the Sarnia and Commerce City refineries and minor secondary process unit maintenance at all four refineries.

Results for 2010 compared with 2009

Refining and Marketing net earnings in 2010 were $819 million, compared to $407 million in 2009. Net earnings in 2009 included the negative impact associated with inventory acquired at fair value in the merger.

Refining and Marketing operating earnings in 2010 were $796 million, compared to $455 million in 2009, and were higher primarily as a result of the merger, which more than doubled refinery throughput capacity (from 178,000 bbls/d to 443,000 bbls/d) and increased refined product sales by approximately 60%, compared with 2009. Operating earnings were also higher due to improved operational reliability, strong distillate cracking margins and wider light/heavy and light/sour synthetic crude differentials.

Cash flow from operations in 2010 was $1.538 billion, compared to $921 million in 2009, and increased mainly due to the same factors impacting operating earnings.

42 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

CORPORATE, ENERGY TRADING AND ELIMINATIONS

Strategy and Operational Update

The Energy Trading business continues to evaluate additional pipeline and storage agreements to support planned increases in production capacity. Until the company completes its Oil Sands growth projects, Suncor's Energy Trading business expects to optimize the capacities associated with existing arrangements.

Suncor continues to evaluate new opportunities to build its renewable energy portfolio, and has a number of potential wind power project sites in various stages of evaluation.

Financial Highlights (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net (loss) earnings |  | (331 | ) | (448 | ) | 104 |  |
Operating (loss) earnings (2) |  |  |  |  |  |  |  |
| Renewable Energy |  | 72 |  | 33 |  | 40 |  |
| Energy Trading |  | 149 |  | 64 |  | 44 |  |
| Corporate |  | (346 | ) | (842 | ) | (529 | ) |
| Group Eliminations |  | (22 | ) | 11 |  | (93 | ) |
|  | (147 | ) | (734 | ) | (538 | ) |
Cash flow used in operations (2) |  | (246 | ) | (984 | ) | (653 | ) |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measures. Operating earnings are reconciled to net earnings below. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See also the Non-GAAP Financial Measures Advisory section of this MD&A.

The net loss for Corporate, Energy Trading and Eliminations in 2011 was $331 million, compared to $448 million in 2010. In 2011, the Canadian dollar weakened in relation to the U.S. dollar, with the US$/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. In 2010, the Canadian dollar strengthened in relation to the U.S. dollar, with the exchange rate increasing from 0.96 to 1.01, resulting in an after-tax unrealized foreign exchange gain on U.S. dollar denominated long-term debt of $372 million.

The operating loss for Corporate, Energy Trading and Eliminations in 2011 was $147 million, compared with an operating loss of $734 million in 2010. Operating earnings are discussed below.

Operating Earnings

Operating Earnings Reconciliation (1)

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings (loss) |  | (331 | ) | (448 | ) | 104 |  |
Unrealized foreign exchange loss (gain) on U.S. dollar denominated long-term debt |  | 161 |  | (372 | ) | (798 | ) |
Impairments and write-offs |  | 23 |  | — |  | — |  |
Merger and integration costs |  | — |  | 79 |  | 151 |  |
Adjustments to provisions for assets acquired through the merger |  | — |  | 7 |  | — |  |
Impact of income tax rate adjustments on deferred income taxes |  | — |  | — |  | 5 |  |
Operating loss (2) |  | (147 | ) | (734 | ) | (538 | ) |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Non-GAAP financial measure. The company has restated operating earnings from 2010 for the transition to IFRS and restated operating earnings for 2009 and 2010 for the removal of certain prior period operating earnings adjustments. See the Non-GAAP Financial Measures Advisory section of this MD&A.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 43

Renewable Energy

Year ended December 31 |  | 2011 |  | 2010 |  | 2009 |
Power generation marketed (gigawatt hours) |  | 245 |  | 174 |  | 177 |
Ethanol production (thousands of m3) |  | 381.5 |  | 206.0 |  | 193.7 |

Suncor's Renewable Energy assets contributed operating earnings of $72 million in 2011, compared to $33 million in 2010, and increased primarily due to higher ethanol production and higher margins for ethanol sales. At the end of January 2011, Suncor completed the expansion of its ethanol plant in Ontario, which doubled production capacity from 200 million litres per year to 400 million litres per year.

Total power generation marketed in 2011 increased to 245 gigawatt hours from 174 gigawatt hours in 2010. 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 $149 million in 2011, compared to $64 million in 2010. Energy trading continued to increase 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. The price differential between these two locations was considerably wider in 2011, consistent with the discount for WTI compared to Brent.

Corporate

Corporate had an operating loss of $346 million in 2011, compared with an operating loss of $842 million in 2010. The 2010 operating loss included after-tax claims of $243 million for the two Oil Sands Base upgrader fires paid by the company's captive insurance program. The decrease in operating loss was also due to an increase in capitalized interest (approximately $225 million more capitalized after tax) that reduced the amount of borrowing costs that were expensed, and lower share-based compensation expense, partially offset by higher DD&A due to the start of depreciation on Suncor's post-merger systems integration initiative.

In 2011, the company capitalized 85% of its borrowing costs as part of the cost of major development assets and construction projects, compared to 43% in 2010. Subsequent to the completion of transactions with Total E&P, the company resumed capitalizing interest for the Voyageur upgrader project and commenced capitalizing interest for the Fort Hills and Joslyn projects.

Group Eliminations

Group Eliminations reflects the elimination of profit on crude oil sales from Oil Sands, Syncrude 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 2011, $22 million of after-tax intersegment profit was eliminated.

Results for 2010 compared with 2009

The net loss for Corporate, Energy Trading and Eliminations for 2010 was $448 million, compared with net earnings of $104 million in 2009. In 2009, the Canadian dollar strengthened in relation to the U.S. dollar as the US$/Cdn$ exchange rate increased from 0.82 to 0.96, resulting in an after-tax unrealized foreign exchange gain on U.S. dollar denominated long-term debt of $798 million. However, results from 2009 were more significantly impacted by costs associated with the merger with Petro-Canada and resulting integration costs.

The operating loss for Corporate, Energy Trading and Eliminations for 2010 was $734 million, compared with an operating loss of $538 million in 2009. The higher operating loss in 2010 reflected the claims paid by the company's captive insurance program.

44 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

6. FOURTH QUARTER 2011 ANALYSIS

Financial and Operational Highlights

Three months ended December 31 ($ millions, except as noted) |  | 2011 |  | 2010 |  |
Net earnings |  |  |  |  |  |
| Oil Sands |  | 790 |  | 484 |  |
| Exploration and Production |  | 284 |  | 386 |  |
| Refining and Marketing |  | 307 |  | 367 |  |
| Corporate, Energy Trading and Eliminations |  | 46 |  | 49 |  |
Total |  | 1 427 |  | 1 286 |  |
Operating earnings (loss) (1) |  |  |  |  |  |
| Oil Sands |  | 835 |  | 345 |  |
| Exploration and Production |  | 372 |  | 275 |  |
| Refining and Marketing |  | 307 |  | 366 |  |
| Corporate, Energy Trading and Eliminations |  | (87 | ) | (178 | ) |
Total |  | 1 427 |  | 808 |  |
Cash flow from (used in) operations (1) |  |
| Oil Sands |  | 1 417 |  | 796 |  |
| Exploration and Production |  | 780 |  | 948 |  |
| Refining and Marketing |  | 534 |  | 610 |  |
| Corporate, Energy Trading and Eliminations |  | (81 | ) | (222 | ) |
Total |  | 2 650 |  | 2 132 |  |
Production volumes (mboe/d) |  |  |  |  |  |
| Oil Sands |  | 356.8 |  | 363.8 |  |
| Exploration and Production |  | 219.7 |  | 261.8 |  |
Total |  | 576.5 |  | 625.6 |  |

(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

Oil Sands net earnings for the fourth quarter of 2011 were $790 million, compared to $484 million in the fourth quarter of 2010. Operating earnings for the fourth quarter of 2011 were $835 million, compared to $345 million for the fourth quarter of 2010. Cash flow from operations from the fourth quarter of 2011 was $1.417 billion, compared to $796 million in the fourth quarter of 2010. These increases were due primarily to higher margins driven by higher price realizations and improved production and sales of higher margin sweet SCO and diesel, partially offset by higher In Situ operating expenses that were largely associated with the Firebag Stage 3 expansion and higher mining costs required to move more tonnes of ore to maintain bitumen supply while working through the area of lower bitumen ore grade and to remove more tonnes of overburden.

Oil Sands production (excluding Syncrude) increased slightly to 326.5 mbbls/d from 325.9 mbbls/d, reflecting higher bitumen output from Firebag and an increase in bitumen ore tonnes mined. In Situ bitumen production increased to 101.4 mbbls/d from 85.8 mbbls/d, due mainly to the ramp up of production from the first well pad for the Firebag Stage 3 expansion and recently completed infill wells on existing Firebag well pads. For Oil Sands Ventures, Suncor's share of Syncrude production decreased to 30.3 mbbls/d from 37.9 mbbls/d due primarily to operational issues with a hydrogen plant and a coker unit.

Exploration and Production

Exploration and Production net earnings for the fourth quarter of 2011 were $284 million, compared to $386 million in the fourth quarter of 2010. Net earnings in the fourth quarter of 2011 included net after-tax impairment charges of $57 million taken primarily against certain North America Onshore properties due to decreasing prices for natural gas. Net earnings in the fourth quarter of 2010 were positively impacted by after-tax adjustments of $186 million for the redetermination of Suncor's working interest in Terra Nova, but negatively impacted by after-tax impairments and write-offs of $96 million also taken primarily against certain North America Onshore properties due to decreasing prices for natural gas.

Exploration and Production operating earnings for the fourth quarter of 2011 were $372 million, compared to $275 million in the fourth quarter of 2010, and increased primarily due to higher average price realizations, partially offset by the impact of lower production volumes, the provision against accounts receivable related to Syria, and higher royalties that reflected a higher percentage of unsold production from Libya.

Production volumes were 219.7 mboe/d in the fourth quarter of 2011, compared to 261.8 mboe/d in the fourth quarter of 2010. The decrease in production volumes was due mainly to the disposal of non-core assets and lower output from Libya during the restart of production following the lifting of sanctions.

Cash flow from operations was $780 million in the fourth quarter of 2011, which was lower than $948 million for the fourth quarter of 2010, due mainly to 2010 including the gain for the redetermination of Suncor's working interest in Terra Nova.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 45

Refining and Marketing

Refining and Marketing net and operating earnings for the fourth quarter of 2011 were $307 million, compared with net earnings of $367 million and operating earnings of $366 million in the fourth quarter of 2010. Cash flow from operations was $534 million in the fourth quarter of 2011, compared to $610 million in the fourth quarter of 2010.

Sales volumes decreased to 81,600 m3/d from 89,200 m3/d. This decrease was primarily due to lower crude throughput at the Edmonton refinery due to a month-long disruption in third-party hydrogen supply. Sales volumes were also lower due to lower demand for heating oil through the wholesale channel in Eastern Canada, due mainly to warmer weather.

Corporate, Energy Trading and Eliminations

Net earnings for this group in the fourth quarter of 2011 were $46 million, compared with net earnings of $49 million in the fourth quarter of 2010. In the fourth quarter of 2011, the Canadian dollar strengthened in relation to the U.S. dollar, with the US$/Cdn$ exchange rate increasing from 0.95 to 0.98 and resulting in an after-tax unrealized foreign exchange gain on U.S. dollar denominated long-term debt of $156 million. In the fourth quarter of 2010, the Canadian dollar strengthened in relation to the U.S. dollar as the exchange rate increased from 0.97 to 1.01, resulting in an after-tax unrealized foreign exchange gain on U.S. dollar denominated long-term debt of $252 million.

The operating loss for this group in the fourth quarter of 2011 was $87 million, compared with an operating loss of $178 million in the fourth quarter of 2010. The decrease in operating loss was due mainly to an increase in capitalized interest related to more major projects being under construction. This decrease was partially offset by higher Renewable Energy earnings that reflected higher ethanol production from the plant expansion, higher Energy Trading earnings that reflected price differences between Alberta and U.S. Gulf Coast markets for heavy crude oil, and lower share-based compensation expense.

Operating Earnings (1)

Three months ended December 31 |  | Oil Sands |  | Exploration and Production |  | Refining and Marketing |  | Corporate Energy Trading and Eliminations |  | Total |  |
($ millions) |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  |
Net earnings as reported |  | 790 |  | 484 |  | 284 |  | 386 |  | 307 |  | 367 |  | 46 |  | 49 |  | 1 427 |  | 1 286 |  |
Unrealized foreign exchange gain on U.S. dollar denominated long-term debt |  | — |  | — |  | — |  | — |  | — |  | — |  | (156 | ) | (252 | ) | (156 | ) | (252 | ) |
Impairments and write-offs |  | 35 |  | 2 |  | 57 |  | 96 |  | — |  | — |  | 23 |  | — |  | 115 |  | 98 |  |
Loss (gain) on significant disposals |  | 10 |  | — |  | — |  | (21 | ) | — |  | — |  | — |  | — |  | 10 |  | (21 | ) |
Adjustments to provisions for assets acquired through the merger |  | — |  | — |  | 31 |  | — |  | — |  | (1 | ) | — |  | 7 |  | 31 |  | 6 |  |
Change in fair value of commodity derivatives used for risk management, net of realizations |  | — |  | (48 | ) | — |  | — |  | — |  | — |  | — |  | — |  | — |  | (48 | ) |
Redetermination of working interest in Terra Nova |  | — |  | — |  | — |  | (186 | ) | — |  | — |  | — |  | — |  | — |  | (186 | ) |
Modification of the bitumen valuation methodology |  | — |  | (93 | ) | — |  | — |  | — |  | — |  | — |  | — |  | — |  | (93 | ) |
Merger and integration costs |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | 18 |  | — |  | 18 |  |
Operating earnings (loss) |  | 835 |  | 345 |  | 372 |  | 275 |  | 307 |  | 366 |  | (87 | ) | (178 | ) | 1 427 |  | 808 |  |

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

46 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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) |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  | 2011 |  | 2010 |  |
Net earnings |  | 790 |  | 484 |  | 284 |  | 386 |  | 307 |  | 367 |  | 46 |  | 49 |  | 1 427 |  | 1 286 |  |
Adjustments for: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Depreciation, depletion, amortization and impairment |  | 392 |  | 308 |  | 474 |  | 530 |  | 118 |  | 114 |  | 39 |  | 26 |  | 1 023 |  | 978 |  |
| Deferred income taxes |  | 270 |  | 140 |  | (30 | ) | 11 |  | 92 |  | 134 |  | (10 | ) | (64 | ) | 322 |  | 221 |  |
| Accretion of liabilities |  | 18 |  | 52 |  | 16 |  | 42 |  | 1 |  | — |  | — |  | — |  | 35 |  | 94 |  |
| Unrealized foreign exchange gain on U.S. dollar denominated long-term debt |  | — |  | — |  | — |  | — |  | — |  | — |  | (179 | ) | (290 | ) | (179 | ) | (290 | ) |
| Change in fair value of derivative contracts |  | — |  | (66 | ) | — |  | — |  | 17 |  | — |  | 34 |  | 34 |  | 51 |  | (32 | ) |
| Loss (gain) on disposal of assets |  | 16 |  | 3 |  | (9 | ) | (26 | ) | (5 | ) | (11 | ) | — |  | 38 |  | 2 |  | 4 |  |
| Share-based compensation |  | 31 |  | 11 |  | 8 |  | 29 |  | 19 |  | 27 |  | 21 |  | 39 |  | 79 |  | 106 |  |
| Exploration expense |  | — |  | — |  | — |  | 10 |  | — |  | — |  | — |  | — |  | — |  | 10 |  |
| Other |  | (100 | ) | (136 | ) | 37 |  | (34 | ) | (15 | ) | (21 | ) | (32 | ) | (54 | ) | (110 | ) | (245 | ) |
Cash flow from (used in) operations |  | 1 417 |  | 796 |  | 780 |  | 948 |  | 534 |  | 610 |  | (81 | ) | (222 | ) | 2 650 |  | 2 132 |  |
(Increase) decrease in non-cash working capital |  | (47 | ) | (186 | ) | 9 |  | (74 | ) | 587 |  | (8 | ) | (396 | ) | (120 | ) | 153 |  | (388 | ) |
Cash flow provided by (used in) operating activities |  | 1 370 |  | 610 |  | 789 |  | 874 |  | 1 121 |  | 602 |  | (477 | ) | (342 | ) | 2 803 |  | 1 744 |  |

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

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 47

7. QUARTERLY FINANCIAL DATA

Financial and Operating Highlights

Three months ended ($ millions, unless otherwise noted) |  | Dec 31 2011 |  | Sept 30 2011 |  | June 30 2011 |  | Mar 31 2011 |  | Dec 31 2010 |  | Sept 30 2010 |  | June 30 2010 |  | Mar 31 2010 |
Total production (mboe/d) |  | 576.5 |  | 546.0 |  | 460.0 |  | 601.3 |  | 625.6 |  | 635.5 |  | 633.9 |  | 564.6 |
| Oil Sands |  | 356.8 |  | 362.5 |  | 277.2 |  | 360.6 |  | 363.8 |  | 338.3 |  | 334.4 |  | 234.6 |
| Exploration and Production |  | 219.7 |  | 183.5 |  | 182.8 |  | 240.7 |  | 261.8 |  | 297.2 |  | 299.5 |  | 330.0 |
Revenues and other income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Operating revenues, net of royalties |  | 10 077 |  | 10 494 |  | 9 510 |  | 9 256 |  | 8 982 |  | 7 717 |  | 8 174 |  | 7 130 |
| Other income (1) |  | 60 |  | 184 |  | 77 |  | 132 |  | 358 |  | (45 | ) | 287 |  | 1 |
|  | 10 137 |  | 10 678 |  | 9 587 |  | 9 388 |  | 9 340 |  | 7 672 |  | 8 461 |  | 7 131 |
Net earnings |  | 1 427 |  | 1 287 |  | 562 |  | 1 028 |  | 1 286 |  | 1 224 |  | 540 |  | 779 |
| per common share (dollars) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Basic |  | 0.91 |  | 0.82 |  | 0.36 |  | 0.65 |  | 0.82 |  | 0.78 |  | 0.35 |  | 0.50 |
|  | Diluted |  | 0.91 |  | 0.76 |  | 0.31 |  | 0.65 |  | 0.82 |  | 0.78 |  | 0.34 |  | 0.46 |
Operating earnings (2) |  | 1 427 |  | 1 789 |  | 980 |  | 1 478 |  | 808 |  | 617 |  | 839 |  | 370 |
| per common share – basic (2) (dollars) |  | 0.91 |  | 1.14 |  | 0.62 |  | 0.94 |  | 0.52 |  | 0.39 |  | 0.54 |  | 0.24 |
Cash flow from operations (2) |  | 2 650 |  | 2 721 |  | 1 982 |  | 2 393 |  | 2 132 |  | 1 630 |  | 1 770 |  | 1 124 |
| per common share – basic (2) (dollars) |  | 1.69 |  | 1.73 |  | 1.26 |  | 1.52 |  | 1.36 |  | 1.04 |  | 1.13 |  | 0.72 |
ROCE (2)(3) (%) for the twelve months ended |  | 13.8 |  | 13.4 |  | 11.1 |  | 12.5 |  | 11.4 |  | 9.3 |  | 7.9 |  | 4.8 |
Common share information |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Dividend per common share (dollars) |  | 0.11 |  | 0.11 |  | 0.11 |  | 0.10 |  | 0.10 |  | 0.10 |  | 0.10 |  | 0.10 |
| Share price at the end of trading |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Toronto Stock Exchange (Cdn$) |  | 29.38 |  | 26.76 |  | 37.80 |  | 43.48 |  | 38.28 |  | 33.50 |  | 31.33 |  | 33.03 |
|  | New York Stock Exchange (US$) |  | 28.83 |  | 25.44 |  | 39.10 |  | 44.84 |  | 38.29 |  | 32.55 |  | 29.44 |  | 32.54 |

(1)
  In 2011, the company completed a review of its energy supply and trading activities and determined that the nature and purpose of transactions previously presented on a gross basis in Energy Supply and Trading Income and Expenses in the Consolidated Statements of Comprehensive Income have evolved such that they are more appropriately reflected through net presentation. See the Accounting Policies and Critical Accounting Estimates section of this MD&A.
(2)
  Non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3)
  Excludes capitalized costs related to major projects in progress.

Business Environment

Three months ended (average for the period ended, except as noted) |  | Dec 31 2011 |  | Sept 30 2011 |  | June 30 2011 |  | Mar 31 2011 |  | Dec 31 2010 |  | Sept 30 2010 |  | June 30 2010 |  | Mar 31 2010 |
WTI crude oil at Cushing |  | US$/bbl |  | 94.05 |  | 89.75 |  | 102.55 |  | 94.10 |  | 85.20 |  | 76.20 |  | 78.05 |  | 78.70 |
Dated Brent crude oil at Sullom Voe |  | US$/bbl |  | 109.00 |  | 113.40 |  | 117.30 |  | 104.95 |  | 86.50 |  | 76.85 |  | 78.30 |  | 76.25 |
Dated Brent/Maya FOB price differential |  | US$/bbl |  | 5.55 |  | 14.80 |  | 14.05 |  | 15.65 |  | 10.85 |  | 9.35 |  | 10.45 |  | 6.50 |
Canadian 0.3% par crude oil at Edmonton |  | Cdn$/bbl |  | 98.20 |  | 92.50 |  | 103.85 |  | 88.40 |  | 80.70 |  | 74.90 |  | 75.50 |  | 80.95 |
Light/heavy crude oil differential for WTI at Cushing less WCS at Hardisty |  | US$/bbl |  | 10.45 |  | 17.65 |  | 17.65 |  | 22.85 |  | 18.10 |  | 15.65 |  | 14.00 |  | 9.05 |
Condensate at Edmonton |  | US$/bbl |  | 108.70 |  | 101.65 |  | 112.40 |  | 98.35 |  | 85.70 |  | 74.50 |  | 82.70 |  | 84.65 |
Natural gas (Alberta spot) at AECO |  | Cdn$/mcf |  | 3.40 |  | 3.70 |  | 3.75 |  | 3.80 |  | 3.60 |  | 3.50 |  | 3.85 |  | 5.35 |
New York Harbor 3-2-1 crack (1) |  | US$/bbl |  | 22.80 |  | 36.45 |  | 29.25 |  | 19.40 |  | 12.20 |  | 9.60 |  | 12.50 |  | 7.95 |
Chicago 3-2-1 crack (1) |  | US$/bbl |  | 19.20 |  | 33.30 |  | 29.70 |  | 16.45 |  | 9.20 |  | 10.15 |  | 11.05 |  | 5.65 |
Portland 3-2-1 crack (1) |  | US$/bbl |  | 26.45 |  | 36.50 |  | 29.35 |  | 21.40 |  | 13.50 |  | 16.60 |  | 15.50 |  | 8.55 |
Gulf Coast 3-2-1 crack (1) |  | US$/bbl |  | 20.40 |  | 33.10 |  | 27.30 |  | 18.50 |  | 8.50 |  | 8.60 |  | 11.20 |  | 7.70 |
Exchange rate |  | US$/Cdn$ |  | 0.98 |  | 1.02 |  | 1.03 |  | 1.01 |  | 0.99 |  | 0.96 |  | 0.97 |  | 0.96 |
Exchange rate (end of period) |  | US$/Cdn$ |  | 0.98 |  | 0.95 |  | 1.04 |  | 1.03 |  | 1.01 |  | 0.97 |  | 0.94 |  | 0.98 |

(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. 2011 ANNUAL REPORT

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 one that occurred for Oil Sands Base operations at Upgrader 2 in the second quarter of 2011, and by changes in commodity prices, refining crack spreads and foreign exchange rates, which are summarized above and discussed in the Consolidated Financial Information – Business Environment section of this MD&A.

Over the last eight quarters, Suncor's results were impacted by several important events:

•
  Results in the first quarter of 2010 were significantly impacted by two upgrader fires that decreased Oil Sands production.
•
  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 are due in part to the disposition of these assets. In addition, the resulting gains and losses on disposition of these assets had one-time impacts on net earnings in the quarters in which they occurred.

Net earnings over the last eight quarters were also affected by other one-time adjustments, including:

•
  The fourth quarter of 2011 included net after-tax impairments and write-offs of $115 million, taken primarily against North America Onshore assets due to decreasing natural gas prices and against crude inventories due to third-party pipeline adjustments.
•
  The second quarter of 2011 included impairment charges of $514 million (net of income taxes of $nil, $11 million was later reversed in 2011) against assets in Libya that were associated with the shut-in of production due to political unrest, which also decreased production volumes for 2011.
•
  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.
•
  The fourth quarter of 2010 included an after-tax gain of $186 million for the redetermination of working interests in the Terra Nova oilfield and an after-tax royalty recovery of $93 million with respect to the modification of the BVM.
•
  The second quarter of 2010 included an after-tax write-off of $141 million for Oil Sands Base assets that were being used in the development of an alternative extraction process that was discontinued.

SUNCOR ENERGY INC. 2011 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

Year ended December 31 ($ millions) |  | 2011 |  | 2010 |  | 2009 |
Oil Sands |  | 5 100 |  | 3 709 |  | 2 831 |
Exploration and Production |  | 874 |  | 1 274 |  | 986 |
Refining and Marketing |  | 633 |  | 667 |  | 380 |
Corporate, Energy Trading and Eliminations |  | 243 |  | 360 |  | 70 |
Total capital and exploration expenditures |  | 6 850 |  | 6 010 |  | 4 267 |
Capitalized interest (included in above figures) |  | 559 |  | 301 |  | 136 |

Capital and exploration expenditures do not include the purchase of the company's interest in the Joslyn project, which is shown as an acquisition in the audited Consolidated Statements of Cash Flows.

Oil Sands

Oil Sands capital and exploration expenditures were $5.100 billion in 2011. Growth spending in 2011 focused primarily on the following significant projects:

•
  Capital expenditures for Firebag Stage 3 were $570 million in 2011, bringing total project expenditures to $4.370 billion. In 2011, the company completed construction of all well pads and the central processing facilities. The first well pad began bitumen production in July. The second and third well pads are being steamed, with initial bitumen production expected in the first half of 2012. Peak production from Firebag Stage 3 is anticipated in the next 18 to 24 months.
•
  Capital expenditures for Firebag Stage 4 were $670 million in 2011, bringing total project expenditures to $1.2 billion. Construction continued on infrastructure, central processing facilities, cogeneration units and the two well pads. Some infrastructure required for Stage 4 was completed as part of Stage 3.
•
  The company completed construction of the hydrogen plant portion of the MNU, which produced hydrogen in December 2011 and January 2012 before being taken off-line for minor modifications prior to further commissioning. The company expects to have the hydrogen plant operating at design rates by the middle of 2012.
•
  The company started mining ore from the NSE late in 2011, and operations are expected to ramp up over the next twelve months. The NSE project develops a new mining resource, and is expected to improve productivity of overall mining operations and decrease operating costs by alleviating congestion in the Millennium mining area and reducing average haul distances. The company has applied for regulatory approval to increase the NSE project area. If approved, the expanded area is expected to provide additional recoverable bitumen.

In 2011, the company spent $622 million on the implementation its TROTM infrastructure project and an additional $110 million on tailings drying facilities. The infrastructure project included the construction of pumping and pipeline facilities for tailings and water transfers across Oil Sands Base mining operations.

Other significant capital expenditures for 2011 focused on the planned maintenance event at Upgrader 2, the acquisition of additional land adjacent to one of our oil sands mining properties, preparation of the NSE, major refurbishments and welding of coker units, the mine train replacement project for Syncrude and the restart of our Fort Hills and Voyageur upgrader projects.

Exploration and Production

Exploration and Production capital and exploration expenditures were $874 million in 2011.

For East Coast Canada operations, capital expenditures focused on the replacement of a flow line for partial H2S remediation and the drilling and completion of a new production well at Terra Nova, the continued development of the HSEU, the completion (including initial production) of the first of two pilot wells in the West White Rose field that is part of the White Rose Extensions, an exploratory well for the Ballicatters discovery, and front-end engineering and project development activities for Hebron.

For International operations in the North Sea, capital expenditures focused on the commissioning of the fourth platform at Buzzard, installed to remove H2S in the oil production from some segments of the field, pre-sanction activity and preliminary design for Golden Eagle, which received regulatory and partner approval during the year, exploratory drilling at the Butch prospect offshore Norway where a discovery was made, and the acquisition of new exploration licences offshore Norway (four operated and

50 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

one non-operated) and the U.K. (one operated and one non-operated).

For International operations in Libya and Syria, capital expenditures were limited in 2011. Operations were suspended in Libya throughout much of 2011. The company completed one oil production well in Syria before suspending the drilling program mid-year because of unrest, and prior to the introduction of sanctions, which resulted in Suncor suspending all operations in Syria in December 2011.

For North America Onshore operations, capital expenditures focused on the development of production wells in the Wilson Creek and Ferrier areas of the Cardium oil formation, and exploration in the Kobes area of the Montney shale gas formation.

Refining and Marketing

Refining and Marketing spent $633 million on capital expenditures in 2011. Expenditures focused on a variety of projects, including one to reduce benzene content in gasoline production at the Commerce City refinery, which is expected to be completed by the second quarter of 2012.

Corporate, Energy Trading and Eliminations

In 2011, the Renewable Energy business completed the construction and commissioning of the Wintering Hills and Kent Breeze wind projects, and the expansion of the ethanol plant.

Corporate capital expenditures focused on Suncor's initiative to integrate pre-merger information systems onto one common platform.

Significant Growth Projects Update

|  | Description |  | Cost Estimate ($ millions) |  | Project Spend to Date ($ millions) |  | Target Completion |  | Estimated % Complete Engineering |  | Estimated % Complete Construction |
Operated |  |  |  |  |  |  |  |  |  |  |  |  |
| Firebag Stage 3 expansion |  | 62.5 mbbls/d bitumen |  | 4 400 |  | 4 370 |  | Q1 2012 |  | 100 |  | 100 |
| Firebag Stage 4 expansion |  | 62.5 mbbls/d bitumen |  | 2 000 |  | 1 189 |  | Q1 2013 |  | 99 |  | 60 |
|  |  |  | (±10% | ) |  |  |  |  |  |  |  |
Non-operated (1) |  |  |  |  |  |  |  |  |  |  |  |  |
| Golden Eagle |  | 70 mboe/d (gross) |  | 880 |  | 64 |  | Q4 2014 |  |  |  |  |
|  |  |  | (±10% | ) |  |  |  |  |  |  |  |

(1)
  Cost estimate as per the operator of Golden Eagle, Nexen Petroleum U.K. Limited. Estimated completion percentages not provided for non-operated projects.

The table above provides a review and update at December 31, 2011 of major growth projects that have been sanctioned for development by the company. Other growth projects, such as the Fort Hills and Joslyn oil sands mining projects and the Voyageur upgrader, have not yet received a final investment decision by the company's Board of Directors. These projects are discussed under the Other Capital Projects section below.

The Firebag Stage 3 expansion is nearly complete. The company expects to commission the cogeneration units in the first quarter of 2012. The ramp up of production from the Stage 3 expansion is continuing, and the company expects to reach peak production levels during the second half of 2013. Stage 3 facilities have a planned bitumen capacity of 62,500 bbls/d.

The primary focus for growth capital in 2012 will be the Firebag Stage 4 expansion. In 2012, the company anticipates that construction will continue on the two well pads, central processing facilities and cogeneration units, and plans to initiate steaming of the first well pad in the fourth quarter of 2012, so that first oil can be achieved late in the first quarter of 2013. Stage 4 facilities also have a planned bitumen capacity of 62,500 bbls/d.

The field development plan for the Golden Eagle Area Development in the U.K. portion of the North Sea includes stand-alone facilities designed for 70,000 boe/d of gross production. Activity in 2012 for the development of Golden Eagle is anticipated to focus on the construction and fabrication of the topsides and jacket for the fixed gravity base structure (GBS).

There are risks associated with project cost estimates provided by Suncor. Accordingly, actual costs can vary from estimates, and these differences can be material. Some of these risks are described in the Risk Factors section of this MD&A under the heading Project Execution and Partner Risk.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 51

Other Capital Projects

Suncor also anticipates 2012 capital expenditures focused on the following projects and initiatives:

Oil Sands Base

Suncor will continue implementing its TROTM tailings reclamation technology across Oil Sands Base operations. The infrastructure project is on schedule to be completed by the fourth quarter of 2012. The company also plans to construct more tailings drying facilities.

Other capital spending for Oil Sands Base is expected to focus on sustaining capital investments, which maintain production capacities at existing facilities, and include costs for planned maintenance events, catalyst, truck and shovel replacement, and the replacements for utilities, roads and other facilities.

In Situ

Capital spending is expected to focus on continuing to build well pads at Firebag and MacKay River and continuing the infill well program at Firebag. This activity, separate from the Firebag Stage 3 and Stage 4 expansions, maintains an inventory of future bitumen supply for central processing facilities as older wells experience natural production declines.

Oil Sands Ventures

In 2013, the company plans to present for sanctioning the budget for the combined development of the Voyageur upgrader, Fort Hills and Joslyn projects to Suncor's Board of Directors. For 2012, Suncor anticipates capital expenditures for:

•
  The Voyageur upgrader project will focus primarily on validating project scope, developing the project execution plan, engineering and progressing site preparation.
•
  Fort Hills will focus primarily on progressing design basis memorandum engineering and site preparation, and procuring long-lead items.
•
  Joslyn will focus on further design work, progressing front-end engineering and site preparation.

Capital expenditures in 2012 for Syncrude are expected to focus on the mine train replacement for the Mildred Lake mine, the mine train relocation at the Aurora mine and sustaining maintenance initiatives.

Exploration and Production

The company anticipates that the second pilot well for water injection support in the West White Rose field of the White Rose Extensions will be completed in the second quarter of 2012. Results from the pilot project, along with other ongoing evaluations, will help define the scope of future development for the West White Rose field.

The Hebron project development plan application was submitted to the Canada Newfoundland and Labrador Offshore Petroleum Board on April 15, 2011. In 2012, the company expects front-end engineering to be finalized, detailed design to commence and major construction contracts to be awarded. The company expects a regulatory approval decision in 2012, followed by a sanction decision by joint venture owners.

Other capital expenditures for East Coast Canada operations are expected to focus on development drilling for Terra Nova, Hibernia and White Rose, the water injection swivel replacement for the FPSO and H2S remediation activity at Terra Nova, the propulsion system maintenance for the White Rose FPSO, and the procurement of subsea equipment for the development of the HSEU.

The company has secured a rig to drill its third appraisal well for the Beta discovery in the Norway portion of the North Sea under the PL375 licence. Drilling is expected to commence in the first quarter of 2012. Suncor has secured a rig to drill an exploration well for the Romeo joint venture prospect in the U.K. portion of the North Sea and also expects to participate in a non-operated exploration well in the Norway portion of the North Sea. The company expects the drilling of both of these wells will commence in 2012.

For North America Onshore operations, the company plans to continue exploration in the Cardium oil formation and Montney shale gas formation.

52 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

9. FINANCIAL CONDITION AND LIQUIDITY

Indicators

At December 31 ($ millions, except as noted) |  | 2011 |  | 2010 |
Working capital (1) |  | 786 |  | 1 148 |
| Short-term debt |  | 763 |  | 1 984 |
| Current portion of long-term debt |  | 12 |  | 518 |
| Long-term debt |  | 10 004 |  | 9 829 |
Total debt |  | 10 779 |  | 12 331 |
| Less: Cash and cash equivalents |  | 3 803 |  | 1 077 |
Net debt |  | 6 976 |  | 11 254 |
Shareholders' equity |  | 38 600 |  | 35 192 |
Total debt plus shareholders' equity |  | 49 379 |  | 47 523 |
Total debt to total debt plus shareholders' equity (%) |  | 22 |  | 26 |

(1)
  Current assets less current liabilities, excluding cash and cash equivalents, short-term debt, current portion of long-term debt, and current assets and liabilities associated with assets held for sale.

Twelve months ended December 31 |  | 2011 |  | 2010 |
Return on Capital Employed (%) (1) |  |  |  |  |
| Excluding major projects in progress |  | 13.8 |  | 11.4 |
| Including major projects in progress |  | 10.1 |  | 8.2 |
Net debt to cash flow from operations (2) (times) |  | 0.7 |  | 1.7 |
Interest coverage on long-term debt (times) |  |  |  |  |
| Earnings basis (3) |  | 10.7 |  | 8.8 |
| Cash flow from operations basis (2)(4) |  | 16.4 |  | 11.7 |

(1)
  Non-GAAP financial measure. The calculations for ROCE are detailed in the Non-GAAP Financial Measures Advisory section of this MD&A.
(2)
  Cash flow from operations and metrics that use cash flow from operations are non-GAAP financial measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3)
  Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
(4)
  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 2012 capital spending program of $7.5 billion and meet current and long-term working capital requirements. 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 in debt capital markets at commercial terms and rates.

For the year ended December 31, 2011, 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.

In 2011, cash and cash equivalents increased $2.726 billion to $3.803 billion, due mainly to higher cash flow from operations and net proceeds from transactions with Total E&P. These increases were partially offset by the company reducing its short-term debt by $1.221 billion, repaying $500 million of Medium Term Notes that came due in 2011, higher capital and exploration expenditures, the return of $500 million to shareholders through the share repurchase plan, and a 10% increase to the company's quarterly dividend (to $0.11 per common share) declared in the second quarter of 2011.

Unutilized lines of credit at December 31, 2011 were approximately $4.428 billion, compared to $5.289 billion at December 31, 2010.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 53

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

($ millions) |  |  |
Facility that is fully revolving for a period of one year and expires in 2013 |  | 2 000 |
Facilities that are fully revolving for a period of four years and expire in 2013 |  | 203 |
Facility that is fully revolving for a period of four years and expires in 2016 |  | 3 000 |
Facilities that can be terminated at any time at the option of the lenders |  | 612 |
Total available credit facilities |  | 5 815 |
Less: |  |  |
Credit facilities supporting outstanding commercial paper |  | 761 |
Credit facilities supporting standby letters of credit |  | 626 |
Total unutilized credit facilities |  | 4 428 |

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.

At December 31, 2011, Suncor's net debt was $6.976 billion, compared to $11.254 billion at December 31, 2010.

Change in Net Debt

($ millions) |  |  |  |
Net debt – December 31, 2010 |  | 11 254 |  |
Decrease in net debt |  | (4 278 | ) |
Net debt – December 31, 2011 |  | 6 976 |  |
Decrease in net debt |  |  |  |
| Cash flow from operations |  | 9 746 |  |
| Capital and exploration expenditures and other investments |  | (6 856 | ) |
| Proceeds from divestitures, net of costs for acquisitions |  | 2 232 |  |
| Dividends less proceeds from exercise of share options |  | (451 | ) |
| Repurchase of common shares |  | (500 | ) |
| Change in non-cash working capital and other |  | 268 |  |
| Foreign exchange on cash, long-term debt and other balances |  | (161 | ) |
|  | 4 278 |  |

The company expects to maintain access to short-term commercial paper borrowing at competitive interest rates by keeping short-term debt at existing levels. During 2011, the company transitioned the majority of its short-term debt to U.S. dollar denominated commercial paper.

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 is expected not to exceed six months, and all investments are expected to be with counterparties with investment grade debt ratings. As at December 31, 2011, the weighted average term to maturity of the short-term investment portfolio was 31 days. In 2011, the company earned approximately $21 million of interest income on this portfolio.

Suncor's interest on debt (before capitalized interest) in 2011 was $661 million, compared to $704 million in 2010. The decrease in interest reflects the decrease in short-term debt and the repayment of the Medium Term Notes. Fixed-to-floating interest rate swaps on the company's long-term debt in place at December 31, 2010 matured during the year, coinciding with the repayment of the Medium Term Notes.

The company obtained regulatory approval for a Normal Course Issuer Bid (NCIB) with the Toronto Stock Exchange authorizing the purchase for cancellation of up to $500 million of its common shares. The NCIB was announced on August 20, 2011 and began on September 6, 2011. The purchase of $500 million of the company's common shares was completed by December 31, 2011. Pursuant to the NCIB, the company repurchased 17,128,065 shares at an average price of $29.19 per share in 2011. All common shares acquired under the NCIB have been cancelled.

Suncor is subject to financial and operating covenants related to its public market and bank 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, 2011, total debt to total debt plus shareholders' equity was 22% (December 31, 2010 – 26%). The company is also currently in compliance with all operating covenants.

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

54 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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 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.

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 Investors Service |  | Baa2 |  | Positive |

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 2011, Moody's upgraded its long-term outlook for senior debt from stable to positive, and Suncor initiated access to the U.S. market for U.S. dollar commercial paper. Otherwise, these credit ratings are unchanged from December 31, 2010.

Outstanding Shares

December 31, 2011 (thousands) |  |  |
Common shares |  | 1 558 636 |
Common share options – exercisable and non-exercisable |  | 59 178 |
Common share options – exercisable |  | 39 482 |

As at February 17, 2012, the total number of common shares outstanding was 1,561,658,318 and the total number of exercisable and non-exercisable common share options outstanding was 60,712,741. Once exercisable, each outstanding common share option is convertible into one common share.

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

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

|  | Payments Due by Period |
($ millions) |  | Total |  | 2012 |  | 2013 to 2014 |  | 2015 to 2016 |  | Thereafter |
Fixed- and revolving-term debt (1) |  | 10 287 |  | 762 |  | 725 |  | — |  | 8 800 |
Interest payments on fixed-term debt |  | 10 607 |  | 596 |  | 1 181 |  | 1 129 |  | 7 701 |
Finance lease payments |  | 1 026 |  | 53 |  | 106 |  | 109 |  | 758 |
Decommissioning and restoration costs (2) |  | 7 275 |  | 426 |  | 887 |  | 309 |  | 5 653 |
Operating lease agreements, pipeline capacity and energy services commitments |  | 13 633 |  | 1 080 |  | 2 088 |  | 1 680 |  | 8 785 |
Exploration work commitments |  | 608 |  | 287 |  | 286 |  | 35 |  | — |
Other long-term obligations (3) |  | 691 |  | 335 |  | 320 |  | 36 |  | — |
Total |  | 44 127 |  | 3 539 |  | 5 593 |  | 3 298 |  | 31 697 |

(1)
  Includes debt that is redeemable at Suncor's option.
(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 Fort Hills purchase obligations. See the Other Long-Term Liabilities note to the 2011 audited Consolidated Financial Statements.

In addition to the enforceable and legally binding obligations quantified in the table presented above, 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 the 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.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 55

Financial Instruments

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars. We use these derivative contracts to hedge risks related to purchases and sales of commodities, to manage exposure to interest rates and to hedge risks specific to individual transactions. Gains or losses on the revaluation and settlement of derivative contracts used for these risk management activities are recorded as Other Income in the Consolidated Statements of Comprehensive Income. For the year ended December 31, 2011, the pre-tax earnings impact for risk management activities was a loss of $22 million (2010 – pre-tax gain of $89 million).

The company's Energy Trading business uses crude oil, natural gas, refined product and other derivative contracts to generate net earnings, recorded as Other Income. For the year ended December 31, 2011, the pre-tax earnings impact for Energy Trading activities was $301 million (2010 – pre-tax earnings of $106 million).

Year ended December 31 ($ millions) | 2011 |  | 2010 |  |
Fair value of contracts at beginning of period | (74 | ) | (359 | ) |
Fair value of contracts realized during the period | (239 | ) | 90 |  |
Change in fair value during the period | 279 |  | 195 |  |
Fair value of derivative contracts at end of period | (34 | ) | (74 | ) |

During 2011, interest rate swaps classified as fair value hedges relating to $200 million of fixed-rate debt expired. At December 31, 2010, the fair value of the interest rate swaps was an $8 million asset. Suncor is not applying hedge accounting to any derivative contracts as at December 31, 2011.

The fair value of derivatives pertaining to risk management and Energy Trading activities are recorded in the Consolidated Balance Sheets as follows:

Fair value of derivative contracts at December 31 ($ millions) | 2011 |  | 2010 |  |
Accounts receivable | 37 |  | 27 |  |
Accounts payable | (71 | ) | (93 | ) |
| (34 | ) | (66 | ) |

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 2011 audited Consolidated Financial Statements.

Canadian Federal Budget Proposal

On December 15, 2011, Bill C-13 received Royal Assent and is considered enacted under IFRS. This new legislation includes the limitation of deferral opportunities for corporate partnerships, the change in the future treatment of oil sands lease purchases to Canadian oil and gas property expense from Canadian development expense, and the change in future treatment of pre-production development expenses for oil sands mines to Canadian development expense from Canadian exploration expense.

The company has completed an assessment of the new legislation and expects that, in future years, it will decrease cash flow from operations by accelerating the payment of cash income taxes, but will not have a significant impact on net earnings.

56 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

10. ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

Changes in Accounting Policies

Suncor's significant accounting policies are described in note 3 to the December 31, 2011 audited Consolidated Financial Statements.

Adoption of IFRS

Effective January 1, 2011, the company began reporting under IFRS. The accounting policies referenced above have been applied in preparing the financial results for the years ended December 31, 2011 and 2010, and the company's opening balance sheet as at January 1, 2010. Detailed reconciliations of amounts reported under Previous GAAP to those presented in this MD&A are provided in the First-Time Adoption of IFRS note to the December 31, 2011 audited Consolidated Financial Statements.

The following table provides a summary reconciliation of consolidated net earnings reported under Previous GAAP to that reported under IFRS:

Year ended December 31, 2010 ($ millions) |  |  |  |
Net earnings, as reported under Previous GAAP |  | 3 571 |  |
Adjustments to net earnings: |  |  |  |
| Depreciation, depletion, amortization and impairment |  | 274 |  |
| Gain on disposal of assets |  | 54 |  |
| Other |  | 17 |  |
| Provision for deferred income taxes |  | (87 | ) |
Net earnings, as reported under IFRS |  | 3 829 |  |

The transition to IFRS included adjustments of $1.632 billion that decreased the carrying amount of Suncor's property, plant and equipment as at January 1, 2010. Suncor applied an IFRS exemption that permitted it to revalue the amount of decommissioning and restoration costs included in the carrying value of the related assets. Suncor also applied an IFRS exemption that permitted it to record certain assets at fair value less costs to sell on the date of transition. The increase in net earnings for 2010 under IFRS compared to Previous GAAP is primarily a result of applying these exemptions to decrease the company's carrying value of property, plant and equipment, and consequently decrease subsequent depreciation of those assets and increase any gains or decrease any losses on the disposal of those assets.

The transition to IFRS also required that the company adopt accounting policies that are different to those previously reported. Changes to accounting policies that may have a significant impact on the company's net earnings or presentation of net earnings include:

•
  Impairment of assets – Under Previous GAAP, an asset was not impaired if estimates of its recoverable amount using undiscounted expected future cash flows exceeded its net carrying value. Under IFRS, discounted cash flows must form the estimate of recoverable amount, essentially making it more likely that asset impairments will occur. For its 2010 net earnings under Previous GAAP, the company had recorded a pre-tax impairment charge of $220 million that would have been required earlier under IFRS because of this difference in accounting policy. Under IFRS, this impairment was reflected in the opening balance sheet as at January 1, 2010.
•
  Classification of discontinued operations – Under Previous GAAP, most of the company's 2010 asset dispositions met the definition of discontinued operations, whereas under IFRS only an immaterial amount of the 2010 dispositions met the IFRS definition of discontinued operations. As a result, the company has restated amounts previously reported and is not presenting any discontinued operations for 2010 comparative figures.

Energy Supply and Trading Activities

During 2011, the company completed a review of its energy supply and trading activities and determined that the nature and purpose of transactions previously presented on a gross basis in Energy Supply and Trading Activities Income and Expenses in the Consolidated Statements of Comprehensive Income have evolved such that they are more appropriately reflected through net presentation. Realized and unrealized gains and losses, and the underlying settlement of these transactions, are now recognized and recorded on a net basis in Other Income. Prior period comparative figures have been reclassified for comparability with the current period presentation. Changes to the Consolidated Statements of Comprehensive Income are as follows:

Year ended December 31, 2010 ($ millions, increase/(decrease)) |  |  |  |
Energy supply and trading activities income |  | (2 700 | ) |
Other income |  | 102 |  |
Energy supply and trading activities expenses |  | (2 598 | ) |
Net earnings |  | — |  |

Recently Announced Accounting Standards

Financial Instruments: Recognition and Measurement

In November 2009, as part of the International Accounting Standards Board (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. The

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 57

standard contains requirements for the classification and measurement of financial assets. The new standard was further revised in October 2010 to include requirements regarding the classification and measurement of financial liabilities. The standard is applicable for Suncor's fiscal year beginning January 1, 2015. The full impact of the standard will not be known until the phases of the IASB's financial instruments project that address hedging and impairments have been completed.

Reporting Entity

In May 2011, the IASB issued IFRS 10 Consolidated Financial Statements, 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 principles-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. IFRS 12 is a comprehensive disclosure standard for all forms of interests in other entities, including subsidiaries, joint arrangements, associates and unconsolidated structured entities. Amendments to IAS 27 and IAS 28 reflect requirements in the new standards.

These standards and amendments are effective for Suncor's fiscal year beginning January 1, 2013. The company is currently assessing the impact of these standards and amendments; therefore, the impact of these standards is not known at this time.

Fair Value Measurements

In May 2011, the IASB issued IFRS 13 Fair Value Measurement, which establishes a single source of guidance for all fair value measurements, clarifies the definition of fair value and enhances the disclosures on fair value measurements. This standard is effective for Suncor's fiscal year beginning January 1, 2013. The company does not anticipate significant changes to its fair value measurements and related disclosures as a result of this standard.

Employee Benefits

In June 2011, the IASB issued amendments to IAS 19 Employee Benefits, which revise the recognition, presentation and disclosure requirements for defined benefit plans. These amendments are effective for Suncor's fiscal year beginning January 1, 2013. The company does not anticipate significant impacts 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 of stripping costs from the production phase of a mine if an entity can demonstrate that it is probable that future economic benefits will be realized, that costs can be reliably measured, and that the component of the ore body for which access has been improved can be identified. 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.

Critical Accounting Estimates

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, 2011 audited Consolidated Financial Statements.

Oil and Gas Reserves and Resources

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 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 resources were evaluated or reviewed as at December 31, 2011 by qualified reserves evaluators in accordance with National

58 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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. Assumptions reflect market and regulatory conditions existing at December 31, 2011, 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 reserves, 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. Capitalized costs associated with exploration and evaluation assets are subject to ongoing technical, commercial and management review 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 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 net earnings as part of 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. 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. Fair value less costs to sell is the amount obtainable from the sale of the CGU in an arm's-length transaction between knowledgeable, willing parties, less costs of disposal. In determining fair value less costs to sell, recent market transactions are taken into account if available; however, in the absence of such transactions, an appropriate valuation model is used. Value-in-use is assessed using the present value of the future cash flows that the company expects to derive from the CGU. Where management determines that a CGU is impaired, the net carrying value of the CGU is reduced to the estimated recoverable amount, with the difference reported as part of depreciation, depletion, amortization and impairment expense.

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 2011, the company completed this review as at July 31, 2011, at which time there were no indications that goodwill was impaired.

At the end of each reporting period, the company must also assess 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

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cash flow models. The key assumptions the company uses for estimating future cash flows are future commodity prices, expected production volumes, future operating and development costs, and 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. Changes to these assumptions 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 in the Consolidated Balance Sheets. Assets held for sale are measured at the lower of net carrying value and fair value less costs to sell, which in this situation may also be determined based on expected sale proceeds when an offer has been received.

The following discusses important impairment assessments completed during 2011:

Libya

In the second quarter of 2011, the company recorded impairment charges of $259 million against property, plant and equipment, $211 million against exploration and evaluation assets, and $44 million against inventories pertaining to its operations in Libya, which had been shut-in at that time due to unrest. All impairment charges for Libyan assets are net of income taxes of $nil.

The net recoverable amount was estimated under a value-in-use premise and determined using discounted cash flow models under probability-weighted scenarios representing i) resumption of normal operations after one year; ii) resumption of normal operations after two years; and iii) total loss.

Scenarios involving the company resuming normal operations used current forecasts for the price of crude oil, estimates of operating and development expenditures based on the field redevelopment anticipated by Suncor's business plans prior to the suspension of operations, a discount rate (17%) that represented management's best estimate of the ongoing risk involved with operating in Libya, and management's best estimate of the incremental rebuilding costs to bring operations back on-stream. Management's forecasts for production were based on proved and probable reserves evaluated by external qualified reserves evaluators and risk-adjusted best estimates of contingent resources evaluated by Suncor's internal qualified reserves evaluators, both evaluated as at December 31, 2010. The scenario involving the company not resuming operations in Libya included the effects of the company not paying certain liabilities.

Later in 2011, a change in the Libyan government resulted in the lifting of certain sanctions that were impacting the company's operations in the country, and the company's joint venture partner was able to restart production in three of five fields by the end of 2011. The company started to receive production payments in January 2012, and the joint venture partner confirmed the existence of crude oil inventories that the company had written off, resulting in the company reversing $11 million of impairment charges.

Discussions with the Libyan authorities have commenced on the status of existing contract terms, including production volumes and time frames for future exploration commitments. There is also still unpredictability concerning production levels, expectations about the ramp up of production, and the extent of damage to the company's assets, which has not yet been fully assessed. Therefore, at December 31, 2011, there has been no change in the company's overall assessment of the impairment, and no reversal of impairment has been recognized, except for the $11 million associated with crude inventories noted above.

Syria

As a result of international sanctions announced in December 2011, the company suspended its operations in Syria and ceased recording production or revenues. Suncor performed an impairment test on its assets in Syria that determined that the assets were not impaired at December 31, 2011. The carrying value of the company's net assets in Syria at December 31, 2011 was approximately $900 million.

The net recoverable amount for the company's Syrian assets was estimated under a value-in-use premise and determined using discounted cash flow models, which take into account the long-term nature of the natural gas and light and medium oil reserves associated with these assets, under probability-weighted scenarios representing i) resumption of normal operations after six months; ii) resumption of normal operations after one year; iii) resumption of normal operations after two years; and iv) total loss. This calculation is most sensitive to management's assumption on the timing of the resumption of normal operations. If the probability weighting in the cash flow model was adjusted to reflect a 0% probability of the company resuming normal operations within the next twelve months, the company's Syrian assets may be impaired.

Scenarios involving the company resuming normal operations used current forecasts for the price of commodities, 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 (17%) that represented

60 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

management's best estimate of the ongoing risk involved with operating in Syria, and an assumption that the company will receive payment for any production during its absence in Syria. Management's forecasts for production were based on proved and probable reserves evaluated by external qualified reserves evaluators as at December 31, 2011.

North America Onshore

As a result of decreases in price forecasts for natural gas, the company recorded pre-tax impairment charges of $100 million against certain CGUs in the North America Onshore business.

Net recoverable amounts for these CGUs were determined under a fair value less costs to sell premise, and determined using discounted cash flow models based on proved and probable reserves evaluated by external qualified reserves evaluators as at December 31, 2011, third-party price forecasts and a discount rate of 12%.

IFRS Transition Exemption

The company applied an IFRS transition exemption to record certain assets at fair value less costs to sell on the date of transition. The exemption was applied to refinery assets located in Eastern Canada and certain natural gas assets in Western Canada, and resulted in a total reduction of $906 million in the net carrying value of these assets. These adjustments are not impairments and cannot be reversed because they were applied as part of the IFRS transition. The company's estimates of fair value less costs to sell for these assets required management to make judgments and use assumptions at the transition date that were similar to those described above.

Summary

As at December 31, 2011, the company had $715 million of impairments on assets in the Exploration and Production segment, consisting of $503 million of impairments for Libya assets and $212 million of impairments on North America Onshore assets (2010 – $112 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. However, these fair value estimates may not necessarily be indicative of the 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, including, but not limited to, the reclamation of lands disturbed by mining oil sands, tailings ponds, producing well sites, and crude oil and natural gas processing plants. The provision for such liabilities is recognized only to the extent that there is a legal or constructive obligation associated with the retirement of an asset that the company is required to settle as a result of an existing or enacted law, statute, ordinance, written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel.

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 costs. 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.

When these provisions are initially recognized, an equal amount is capitalized as part of the cost of the associated asset and is amortized to expense over the life of the asset.

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 $1.168 billion in 2011. The most significant change in the provision resulting from a change in estimates was with respect to the expected timing of future reclamation activity, which has accelerated primarily as a result of recent advancements from the use of TROTM. The provision also increased due to a decrease in the average discount rate (2011 – 4.3%; 2010 – 5.4%) and new liabilities primarily associated with land disturbance in 2011, offset by the settlement of certain liabilities and the impacts of asset disposals.

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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.

An onerous contract is one in which the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received under it.

A constructive obligation is one where Suncor, by an established pattern of past practice, published policies, or a sufficiently current statement, has indicated that it will accept certain responsibilities and has created a valid expectation in other parties that it will discharge those responsibilities.

The company is involved in litigation and claims in the normal course of operations. As at December 31, 2011, 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, 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.

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.

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 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

The company is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification of risks inherent to the assets and activities of Suncor. The company's enterprise risk committee, 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 the company's businesses or functions to meet or support a Suncor objective. The following provides a list of some of the risk factors relating to Suncor and its operations.

Commodity Price Volatility

Our financial performance is closely linked to prices for crude oil in our upstream businesses and prices for refined petroleum products in our downstream business, and, to a lesser extent, to natural gas prices in our upstream businesses, 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), political developments, compliance or non-compliance with quotas imposed on members of the Organization of Petroleum Exporting Countries (OPEC), 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 non-upgraded bitumen in future years, due mainly to expansion at Firebag. Due to its low viscosity, bitumen is blended with a light diluent or synthetic crude oil and sold as a heavy crude oil. The markets for heavy crude oil are more limited than those for light crude, making them more susceptible to supply and demand changes. Heavy crude oil 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. The price differential between light crude and WCS is particularly important for Suncor. WCS is a pool of heavy crude oil and blended bitumen production from Western Canada. 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. Future price differentials are uncertain and widening light/heavy differentials could have a negative impact on our business, especially price realizations for bitumen that Suncor is unable to upgrade.

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, with the possibility that crude oil and refined petroleum products prices could revert to the low levels experienced in 2008 and 2009. 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 on some properties or include an impairment of 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.

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 have a direct impact on Suncor's business, financial condition, results of operations and cash flow, as evidenced by such initiatives

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as the Alberta government's royalty review program in 2007, and, more recently, by trade sanctions in Libya 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, such as opposition to new North American pipeline systems, such as Keystone XL, 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. Management 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.

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 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 carbon dioxide (CO2) unit intensity of our operations, the absolute CO2 emissions of our company will continue to rise as we pursue a prudent and planned growth strategy.

As part of our ongoing business planning, Suncor assesses potential costs associated with CO2 emissions in our evaluation of future projects, based on our 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, we expect 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 our strategy, using a price range of $15-$45 per tonne of CO2 equivalent as a base case, applied against a range of regulatory policy options and price sensitivities.

Although Suncor does not actively market into California, the implications of other states or countries adopting Low Carbon Fuel Standard legislation could pose a significant barrier to our 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.

In general, there remains uncertainty around the outcome and impacts of proposed or potential future climate change and other related environmental regulation. The Canadian federal government has gone on record as saying that it will align GHG emissions legislation with the U.S. Since it remains unclear what approach the U.S. will take, or when, it also is unclear whether the Canadian federal government will implement economy-wide climate change legislation, or a sector-specific approach, and what type of compliance mechanisms will be available to large emitters. At this time, the company does not believe it is

64 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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 given the current lack of detail on how systems will operate.

Land Reclamation

There are risks associated specifically with our ability to reclaim tailings ponds containing mature fine tailings with TROTM or other methods and technologies. Suncor expects that TROTM will help the company reclaim existing tailings ponds. The success of TROTM or any other methods of technology and the time to reclaim tailings ponds could increase or decrease our decommissioning and restoration cost estimates. Our failure or inability to adequately implement our reclamation plans, including our planned implementation of TROTM, could have a material adverse effect on Suncor's business, financial condition, results of operations and cash flow. In recent years, Suncor has increased collaboration with other participants in the oil sands industry to share technology and knowledge and to research alternative methods for tailings management.

Royalties

Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs, 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 mining operations (not including Syncrude), the BVM is based on the terms of Suncor's RAA, which we believe places certain limitations on the interim BVM as recently enacted, which modified the BVM for additional quality and transportation adjustments. For the years 2009 to 2010, Suncor 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 Suncor's RAA. Suncor has also filed with the Alberta government a Notice of Commencement of Arbitration under the Suncor RAA. The owners of the Syncrude joint venture 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 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;
•
  Changes in laws and policies governing operations of foreign-based companies; and
•
  Economic and legal sanctions (such as restrictions against countries experiencing political unrest, 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 2011, operations in both Libya and Syria were suspended as a result of the outbreak of political unrest and the resulting sanctions imposed by international governments. Discussions with the Libyan authorities continue on the status of existing contract terms, including production volumes and exploration commitments. There is still sufficient unpredictability underlying operations in this region, including the ramp up of production, the sustainability of current production rates and the extent of damage to the company's assets, which has not yet been fully assessed. As a result, there is

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no assurance that production will return to previous levels or continue at current levels.

In response to sanctions and escalating political unrest in Syria, Suncor declared force majeure in December 2011, withdrew its expatriate staff and stopped recording production from Syria. Suncor's assessment of the situation as at December 31, 2011 did not require the company to record an impairment charge against its assets in Syria; however, should the current situation persist or worsen, such that Suncor is unable to resume operations in the near term, the company believes its assets in Syria could be impaired in the future. There is no assurance as to when Suncor's production from Syrian assets will resume or return to previous levels. Suncor's operations in Syria represented approximately 3% of the company's consolidated net earnings and 3% of the company's cash flow from operations in 2011. The carrying value of Suncor's net assets in Syria at December 31, 2011 was approximately $900 million.

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. We 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 we will be successful in protecting ourselves against these risks and the related financial consequences.

Environmental Health and Safety (EHS) Regulatory Non-Compliance

The company is required to comply with a large number of EHS regulations under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations, as described in the Industry Conditions – Environmental Regulation section of the 2011 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.

Operational Outages and Major Environmental or Safety Incidents

Each of our primary operating segments – 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, non-government organizations, 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, our 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.

The reliable operation of production and processing facilities at planned levels and our 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. We are also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software or network attacks.

The efficient operation of our 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.

66 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

In addition, all of our 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 or third-party suppliers 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, we expect to further mitigate adverse impacts of interdependent systems and to reduce the production and cash flow impacts of complete plant-wide shutdowns. For example, Suncor has two upgrader facilities that include three secondary upgrading units, which provide us with the flexibility to conduct periodic planned maintenance events on one facility while continuing production from the other.

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.

Our 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. Our offshore operations could also be affected by the actions of our 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 our 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 (typically October to March), we may have to reduce production rates at our offshore facilities as a result of limited storage capacity and the inability to offload to shuttle tankers due to wave 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.

Our Refining and Marketing operations are subject to all of the risks normally inherent in the operation of refineries, terminals, pipelines, 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 we maintain 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.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 67

Project Execution and Partner Risk

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.

Other entities operate a portion of the assets in which Suncor has ownership interests. Suncor's dependence on its partners – the operator and other working interest owners for these assets – and its limited 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 operated by 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 partners may have objectives and interests that do not coincide with and may conflict with Suncor's interests. Major capital decisions affecting jointly owned assets may require agreement among the partners, 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, no assurance can be provided that the future demands or expectations of either party relating to such assets will be met satisfactorily or in a timely manner. Failure to satisfactorily meet demands or expectations by either party may affect our participation in the operation of such assets, our ability to obtain or maintain necessary licences or approvals, and the timing for undertaking various activities.

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

68 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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 venture opportunities 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 and higher crude oil prices. 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 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. There is also a perception among many stakeholders that the oil sands industry, including Suncor, has little ability to control costs. Suncor is exposed to the risks of growing or uncontrollable operating costs, 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.

Other Risk Factors

A detailed discussion of additional risk factors is presented in our most recent Annual Information Form/Form 40-F, filed with securities regulators.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 69

12. OTHER ITEMS

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2011, 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 (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, 2011, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) to 15d-15(f)) that occurred during 2011 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 facilities, including whether certain facilities have suffered damages. Suncor has assessed and is continually monitoring the control environment in these countries and does not consider the changes to have 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, 2011 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, 2011.

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.

CORPORATE GUIDANCE

Detailed guidance on the company's outlook for 2012 production, capital expenditures and other items can be found in Suncor's 2011 Annual Report, available on www.sedar.com, and Suncor's corporate guidance available on its website at www.suncor.com/guidance.

70 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

13. NON-GAAP FINANCIAL MEASURES ADVISORY

Certain financial measures in this MD&A – namely operating earnings, cash flow from operations, ROCE and Oil Sands cash operating costs – are not prescribed by GAAP. 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. These non-GAAP financial measures are included because management uses the information to analyze operating performance, leverage and liquidity. 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.

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. All reconciling items are presented on an after-tax basis.

Prior period operating earnings have been restated in this MD&A. In the first quarter of 2011, three operating earnings adjustments – mark-to-market valuation of stock-based compensation, project start-up costs and costs related to the deferral of growth projects – were eliminated from the operating earnings reconciliation due to their relatively minor impact on operating earnings, except for the after-tax impact of $299 million for costs related to the deferral of growth projects in the Oil Sands segment, which was not eliminated from 2009 operating earnings as an operating earnings adjustment. Less significant individual gains and losses on disposals were also removed from operating earnings reconciling items reported in 2010. Finally, adjustments to net earnings for the transition to IFRS also had an impact on operating earnings and existing operating earnings adjustments.

The following is a reconciliation of operating earnings as reported in Suncor's MD&A dated February 24, 2011 to operating earnings as reported in this MD&A:

Year ended December 31 (1) |  | Oil Sands |  | Exploration and Production |  | Refining and Marketing |  | Corporate Energy Trading and Eliminations |  | Total |  |
($ millions) |  | 2010 |  | 2009 |  | 2010 |  | 2009 |  | 2010 |  | 2009 |  | 2010 |  | 2009 |  | 2010 |  | 2009 |  |
Operating earnings (loss), as previously reported (2) |  | 1 535 |  | 1 116 |  | 1 124 |  | 171 |  | 782 |  | 473 |  | (709 | ) | (480 | ) | 2 732 |  | 1 280 |  |
Removal of operating earnings adjustments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mark-to-market valuation of stock-based compensation |  | (31 | ) | (28 | ) | (23 | ) | (21 | ) | (30 | ) | (17 | ) | (19 | ) | (58 | ) | (103 | ) | (124 | ) |
| (Loss) gain on significant disposals |  | (4 | ) | — |  | — |  | — |  | 26 |  | — |  | — |  | — |  | 22 |  | — |  |
| Project start-up costs |  | (55 | ) | (40 | ) | (3 | ) | — |  | — |  | — |  | — |  | — |  | (58 | ) | (40 | ) |
| Costs related to deferral of growth projects |  | (94 | ) | — |  | — |  | — |  | — |  | (1 | ) | — |  | — |  | (94 | ) | (1 | ) |
IFRS adjustments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net earnings |  | 28 |  | — |  | 218 |  | — |  | 18 |  | — |  | (6 | ) | — |  | 258 |  | — |  |
| Operating earnings reconciling items: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Impairments and write-offs |  | — |  | — |  | (85 | ) | — |  | — |  | — |  | — |  | — |  | (85 | ) | — |  |
|  | Gain on significant disposals |  | — |  | — |  | (38 | ) | — |  | — |  | — |  | — |  | — |  | (38 | ) | — |  |
Operating earnings (loss), as restated in this MD&A |  | 1 379 |  | 1 048 |  | 1 193 |  | 150 |  | 796 |  | 455 |  | (734 | ) | (538 | ) | 2 634 |  | 1 115 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Operating earnings (loss) includes amounts classified as discontinued operations in 2010 under Previous GAAP.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 71

The following is a reconciliation of net earnings to operating earnings for Suncor's last five years of operations. Operating earnings for 2007 to 2009 are reported under Previous GAAP and have been adjusted from operating earnings previously reported for the removal of project start-up costs and mark-to-market valuation of stock-based compensation.

($ millions) |  | 2011 |  | 2010 |  | 2009 |  | 2008 |  | 2007 |  |
Net earnings as reported |  | 4 304 |  | 3 829 |  | 1 146 |  | 2 137 |  | 2 983 |  |
Unrealized foreign exchange loss (gain) on U.S. dollar denominated long-term debt |  | 161 |  | (372 | ) | (798 | ) | 852 |  | (215 | ) |
Impairments and write-offs |  | 629 |  | 306 |  | 42 |  | — |  | — |  |
Impact of income tax rate adjustments on deferred income taxes |  | 442 |  | — |  | 4 |  | — |  | (427 | ) |
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 |  | 5 674 |  | 2 634 |  | 1 115 |  | 2 617 |  | 2 341 |  |

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. The following is a reconciliation of ROCE for Suncor's last five years of operations. ROCE for 2007 to 2009 are reported under Previous GAAP.

Year ended December 31 ($ millions, except as noted) |  |  |  | 2011 |  | 2010 |  | 2009 |  | 2008 |  | 2007 |  |
Adjustments to net earnings |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Net earnings |  |  |  | 4 304 |  | 3 829 |  | 1 146 |  | 2 137 |  | 2 983 |  |
| Add after-tax amounts for: |  |  |  |  |  |  |  |  |  |  |  |  |  |
|  | Unrealized foreign exchange loss (gain) on U.S. dollar denominated long-term debt |  | 161 |  | (372 | ) | (798 | ) | 852 |  | (215 | ) |
|  | Net interest expense |  |  |  | 83 |  | 327 |  | 289 |  | — |  | 36 |  |
|  | A |  | 4 548 |  | 3 784 |  | 637 |  | 2 989 |  | 2 804 |  |
Capital employed – beginning of twelve-month period |  |  |  |  |  |  |  |  |  |  |  |
| Net debt |  |  |  | 11 254 |  | 13 516 |  | 7 226 |  | 3 248 |  | 1 849 |  |
| Shareholders' equity |  |  |  | 35 192 |  | 32 485 |  | 14 523 |  | 11 896 |  | 9 084 |  |
|  | D |  | 46 446 |  | 46 001 |  | 21 749 |  | 15 144 |  | 10 933 |  |
Capital employed – end of twelve-month period |  |  |  |  |  |  |  |  |  |  |  |
| Net debt |  |  |  | 6 976 |  | 11 254 |  | 13 377 |  | 7 226 |  | 3 248 |  |
| Shareholders' equity |  |  |  | 38 600 |  | 35 192 |  | 34 111 |  | 14 523 |  | 11 896 |  |
|  |  |  | 45 576 |  | 46 446 |  | 47 488 |  | 21 749 |  | 15 144 |  |
Average capital employed (1) |  | B |  | 44 956 |  | 46 075 |  | 35 128 |  | 18 447 |  | 13 039 |  |
ROCE – including major projects in progress (%) |  | A/B |  | 10.1 |  | 8.2 |  | 1.8 |  | 16.2 |  | 21.5 |  |
Average capitalized costs related to major projects in progress |  | C |  | 12 106 |  | 12 890 |  | 10 655 |  | 5 149 |  | 3 454 |  |
ROCE – excluding major projects in progress (%) |  | A/(B-C) |  | 13.8 |  | 11.4 |  | 2.6 |  | 22.5 |  | 29.3 |  |

(1)
  For 2009 to 2011, 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 2007 and 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.

72 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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, fluctuations for the timing or payment of risk management positions, offshore feedstock purchases, and fuel and income taxes, which management believes reduces comparability between periods.

|  | Oil Sands |  | Exploration and Production |  | Refining and Marketing |  |
Year ended December 31 ($ millions) (1) |  | 2011 |  | 2010 |  | 2009 |  | 2011 |  | 2010 |  | 2009 |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings (loss) |  | 2 603 |  | 1 520 |  | 557 |  | 306 |  | 1 938 |  | 78 |  | 1 726 |  | 819 |  | 407 |  |
Adjustments for: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Depreciation, depletion, amortization and impairment |  | 1 374 |  | 1 310 |  | 922 |  | 2 035 |  | 1 978 |  | 1 032 |  | 444 |  | 440 |  | 317 |  |
| Deferred income taxes |  | 895 |  | 487 |  | (643 | ) | 354 |  | 196 |  | (96 | ) | 494 |  | 269 |  | 99 |  |
| Accretion of liabilities |  | 85 |  | 130 |  | 111 |  | 69 |  | 103 |  | 43 |  | 3 |  | 2 |  | 1 |  |
| Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Change in fair value of derivative contracts |  | — |  | (316 | ) | 960 |  | — |  | — |  | — |  | 3 |  | — |  | (14 | ) |
| Loss (gain) on disposal of assets |  | 122 |  | 14 |  | 70 |  | 31 |  | (998 | ) | (20 | ) | (16 | ) | (30 | ) | 16 |  |
| Share-based compensation |  | (35 | ) | 55 |  | 90 |  | (4 | ) | 24 |  | 31 |  | (21 | ) | 39 |  | 35 |  |
| Exploration expense |  | — |  | — |  | — |  | 28 |  | 96 |  | 183 |  | — |  | — |  | — |  |
| Gain on effective settlement of pre-existing contract with Petro-Canada |  | — |  | — |  | (438 | ) | — |  | — |  | — |  | — |  | — |  | — |  |
| Other |  | (472 | ) | (423 | ) | (378 | ) | 27 |  | (12 | ) | 29 |  | (59 | ) | (1 | ) | 60 |  |
Cash flow from (used in) operations |  | 4 572 |  | 2 777 |  | 1 251 |  | 2 846 |  | 3 325 |  | 1 280 |  | 2 574 |  | 1 538 |  | 921 |  |
(Increase) decrease in non-cash working capital |  | (676 | ) | (890 | ) | (202 | ) | 398 |  | (320 | ) | (78 | ) | 600 |  | (260 | ) | (270 | ) |
Cash flow provided by (used in) operating activities |  | 3 896 |  | 1 887 |  | 1 049 |  | 3 244 |  | 3 005 |  | 1 202 |  | 3 174 |  | 1 278 |  | 651 |  |

|  |  |  |  |  |  |  | Corporate, Energy Trading and Eliminations |  | Total |  |
Year ended December 31 ($ millions) (1) |  |  |  |  |  |  |  | 2011 |  | 2010 |  | 2009 |  | 2011 |  | 2010 |  | 2009 |  |
Net earnings (loss) |  |  |  |  |  |  |  | (331 | ) | (448 | ) | 104 |  | 4 304 |  | 3 829 |  | 1 146 |  |
Adjustments for: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Depreciation, depletion, amortization and impairment |  |  |  |  |  |  |  | 99 |  | 75 |  | 35 |  | 3 952 |  | 3 803 |  | 2 306 |  |
| Deferred income taxes |  |  |  |  |  |  |  | (99 | ) | (201 | ) | (85 | ) | 1 644 |  | 751 |  | (725 | ) |
| Accretion of liabilities |  |  |  |  |  |  |  | — |  | — |  | — |  | 157 |  | 235 |  | 155 |  |
| Unrealized foreign exchange loss (gain) on U.S. dollar denominated long-term debt |  |  |  |  |  |  |  | 183 |  | (426 | ) | (858 | ) | 183 |  | (426 | ) | (858 | ) |
| Change in fair value of derivative contracts |  |  |  |  |  |  |  | (43 | ) | 31 |  | 34 |  | (40 | ) | (285 | ) | 980 |  |
| Loss (gain) on disposal of assets |  |  |  |  |  |  |  | (1 | ) | 39 |  | — |  | 136 |  | (975 | ) | 66 |  |
| Share-based compensation |  |  |  |  |  |  |  | (42 | ) | (5 | ) | 106 |  | (102 | ) | 113 |  | 262 |  |
| Exploration expense |  |  |  |  |  |  |  | — |  | — |  | — |  | 28 |  | 96 |  | 183 |  |
| Gain on effective settlement of pre-existing contract with Petro-Canada |  |  |  |  |  |  |  | — |  | — |  | — |  | — |  | — |  | (438 | ) |
| Other |  |  |  |  |  |  |  | (12 | ) | (49 | ) | 11 |  | (516 | ) | (485 | ) | (278 | ) |
Cash flow from (used in) operations |  |  |  |  |  |  |  | (246 | ) | (984 | ) | (653 | ) | 9 746 |  | 6 656 |  | 2 799 |  |
(Increase) decrease in non-cash working capital |  |  |  |  |  |  |  | (80 | ) | 300 |  | 326 |  | 242 |  | (1 170 | ) | (224 | ) |
Cash flow provided by (used in) operating activities |  |  |  |  |  |  |  | (326 | ) | (684 | ) | (327 | ) | 9 988 |  | 5 486 |  | 2 575 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 73

The following is a reconciliation of cash flow from operations for Suncor's last five years of operations. Cash flow from operations for 2007 to 2009 is reported under Previous GAAP.

($ millions) |  | 2011 |  | 2010 |  | 2009 |  | 2008 |  | 2007 |
Cash flow provided by operating activities |  | 9 988 |  | 5 486 |  | 2 575 |  | 4 462 |  | 3 893 |
(Decrease) increase in non-cash working capital |  | (242 | ) | 1 170 |  | 224 |  | (405 | ) | 144 |
Cash flow from operations |  | 9 746 |  | 6 656 |  | 2 799 |  | 4 057 |  | 4 037 |

Oil Sands Cash Operating Costs

Oil Sands cash operating costs and cash operating costs per barrel are non-GAAP financial measures that adjust operating, selling and general expense for significant items that do not reflect production costs for Oil Sands that are within the company's control or that do not directly affect routine production activities. Management uses cash operating costs to evaluate operating performance because management believes it provides better comparability between periods.

($ millions) |  | 2011 |  | 2010 |  | 2009 |  |
Operating, selling and general expense (1) |  | 5 169 |  | 4 537 |  | 4 277 |  |
| Less: Syncrude-related operating expenses |  | (529 | ) | (473 | ) | (199 | ) |
| Less: Other non-production costs (2) |  | (299 | ) | (201 | ) | (517 | ) |
| Other adjustments (3) |  | 138 |  | 127 |  | 38 |  |
Oil Sands cash operating costs |  | 4 479 |  | 3 990 |  | 3 599 |  |
Oil Sands cash operating costs ($/bbl) |  | 40.20 |  | 38.65 |  | 33.95 |  |

(1)
  2009 data is prepared under Previous GAAP. See the Advisories – Basis of Presentation section of this MD&A.
(2)
  Significant non-production costs include, but are not limited to, share-based compensation adjustments, costs related to the remobilization and deferral of growth projects, and the expense recognized as part of a non-monetary arrangement involving a third-party processor.
(3)
  Other adjustments include the effects of changes in inventory valuation, the accretion of liabilities for reclamation and restoration provisions, and the cost of purchased diluent.

Cash operating costs have also been restated for the transition to IFRS. The following table reconciles amounts previously reported to those presented in this MD&A:

|  | Year ended December 31, 2010 |
|  | $ millions |  | $/bbl |
Oil Sands cash operating costs, as previously reported |  | 4 012 |  | 38.85 |
IFRS adjustments: |  |  |  |  |
| Accretion of liabilities |  | (16 | ) |  |
| Operating, selling and general expense |  | (6 | ) |  |
Oil Sands cash operating costs, as restated in this MD&A |  | 3 990 |  | 38.65 |

74 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

14. ADVISORY – FORWARD-LOOKING INFORMATION

This MD&A contains certain forward-looking statements and other information 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", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue" 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:

•
  Lower bitumen ore grade quality at the Millennium mine face will impact operations until the start of the fourth quarter of 2012, at which point the bitumen ore grade quality is expected to return to previous levels;
•
  New wells coming on-stream at MacKay River in the fourth quarter of 2011 and throughout 2012, combined with well workovers, will offset natural declines from existing well pairs;
•
  Significant incremental or sustained production from the HSEU will not occur until further development drilling and subsea infrastructure comes on-stream, which is expected by 2014;
•
  The continuation of the ramp up of bitumen production from the NSE, and that the NSE will improve productivity of overall mining operations and decrease operating costs by alleviating congestion in the Millennium mining area and reducing average haul distances; and
•
  If regulatory approval is obtained to increase the NSE project area, Suncor's expectation that the expanded area will provide additional recoverable bitumen.

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

•
  The event scheduled for the second quarter of 2012 at Oil Sands Base, when the company expects to shut down one coker unit at Upgrader 1;
•
  The event scheduled for the third quarter of 2012 at Oil Sands Base, when the company expects to complete maintenance on the vacuum tower and shut down one coker unit at Upgrader 2;
•
  Suncor's expectations that it will complete maintenance on secondary upgrading units at both Upgrader 1 and Upgrader 2 during 2012;
•
  The 21-week dockside maintenance program planned for Terra Nova in 2012 in the second half of 2012, during which the company plans to replace the FPSO water injection swivel and complete the replacement of subsea infrastructure anticipated to remediate H2S issues, and that the company expects a return to the field with resumption of production prior to the end of 2012;
•
  The 18-week off-station maintenance program for White Rose that is scheduled to commence during the second quarter of 2012, primarily to address issues with the FPSO propulsion system;
•
  Events scheduled to occur at Hibernia and Buzzard in the third quarter of 2012;
•
  Suncor's expectation that there will be no production from Terra Nova during its dockside maintenance program and no production from White Rose during its off-station maintenance program, and that effective execution of these programs will set the company up for continued success; and
•
  Outages planned for 2012 at the company's refineries, including crude unit maintenance at the Sarnia and Commerce City refineries and minor secondary process unit maintenance at all four refineries.

Suncor's expectations about where future capital expenditures will be directed, the timing for completion of growth and other significant projects, and the results of such projects, including:

•
  The project to reduce benzene content in gasoline production at the Commerce City refinery is expected to be completed by the second quarter of 2012;
•
  Cost estimates and target completion dates provided in the Significant Growth Projects Update table;

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 75

•
  Suncor's expectations that it will commission the Firebag Stage 3 cogeneration units in the first quarter of 2012;
•
  Initial bitumen production from the second and third well pads for the Firebag Stage 3 expansion is expected in the first half of 2012, and the ramp up of production from the Firebag Stage 3 expansion is expected to continue throughout 2012 and reach peak production levels during the second half of 2013;
•
  Planned capacity for facilities at each of the Firebag Stage 3 and Stage 4 expansions is 62,500 bbls/d of bitumen and that Stage 4 will add equivalent barrels of production to Stage 3;
•
  Suncor's expectations for the Firebag Stage 4 expansion that in 2012 it will continue construction of well pads, central processing facilities and cogeneration units, and initiate steaming of the first well pad in the fourth quarter of 2012 so that first oil can be achieved late in the first quarter of 2013;
•
  Suncor's expectations that the hydrotreater portion of the MNU will start up in 2012, commissioning of the MNU hydrogen plant will be completed by the middle of 2012, and that the MNU will improve the reliability and availability of Suncor's upgrading facilities;
•
  Suncor's expectations that the Golden Eagle Area Development will include stand-alone facilities designed for 70,000 boe/d of gross production, and that 2012 capital expenditure activity in 2012 will focus on construction and fabrication of topsides and the jacket for the GBS;
•
  The company's plans to construct more tailings drying facilities and expectations that it will complete the TROTM infrastructure project by the fourth quarter of 2012;
•
  Other capital spending for Oil Sands Base is expected to focus on sustaining capital investments, which maintain production capacities at existing facilities, and include costs for planned maintenance events, catalyst, truck and shovel replacement, and the replacements for utilities, roads and other facilities;
•
  In situ capital spending is expected to focus on continuing to build well pads at Firebag and MacKay River and continuing the infill well program at Firebag;
•
  The company's plan to present to Suncor's Board of Directors for sanctioning the budget for the combined development of the Voyageur upgrader, Fort Hills and Joslyn projects in 2013;
•
  Suncor's expectations that capital spending in 2012 for the Voyageur upgrader project will focus primarily on validating project scope, developing the project execution plan, engineering and progressing site preparation;
•
  Suncor's expectations that capital spending in 2012 for the Fort Hills project will focus primarily on progressing design basis memorandum engineering and site preparation, and procuring long-lead items;
•
  Suncor's expectations that capital spending in 2012 for the Joslyn project will focus on further design work, progressing front-end engineering and site preparation;
•
  Capital expenditures in 2012 for Syncrude will focus on the mine train replacement for the Mildred Lake mine, the mine train relocation at the Aurora mine and sustaining maintenance initiatives;
•
  Suncor's expectations that the second pilot well for water injection support in the White Rose Extensions will be completed in the second quarter of 2012 and that results from the pilot project, along with ongoing evaluations, will help define the scope of future development for the West White Rose field;
•
  The company's expectations for the Hebron project that front-end engineering will be finalized, detailed design will commence and major construction contracts will be awarded, and that it will receive a regulatory approval decision in 2012, followed by a sanction decision by joint venture owners;
•
  For 2012, the company's expectations that it will commence drilling an exploration well for the Romeo joint venture prospect in the U.K. portion of the North Sea and participate in a non-operated exploration well in the Norway portion of the North Sea;
•
  Suncor's expectations that other capital expenditures for East Coast Canada operations will focus on development drilling for Terra Nova, Hibernia and White Rose, the water injection swivel replacement for the FPSO and H2S remediation activity at Terra Nova, the propulsion system maintenance for the White Rose FPSO, and the procurement of subsea equipment for the development of the HSEU;
•
  The company's expectations that it will commence the drilling of an appraisal well in its Beta discovery in the first quarter of 2012 and that it will participate in an exploration well offshore Norway; and
•
  For North America Onshore operations, the company's plans to continue exploration in the Cardium oil formation and Montney shale gas formation.

Other elements of Suncor's strategy and operational update for 2012, including:

•
  The expectation that Oil Sands operational excellence initiatives will continuously improve plant utilization and workforce productivity;
•
  The company's portfolio of in situ technology projects, which is expected to drive improvements and efficiencies

76 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

in current production and develop future opportunities, and the focus of this portfolio on subsurface and surface challenges;

•
  The company's expectations that the development of the Golden Eagle, HSEU, White Rose Extensions and Hebron will be an attractive opportunity to provide low-cost production and generate future cash flow;
•
  That North America Onshore operations will direct attention to cost reduction while pursuing unconventional and liquids-rich plays;
•
  Expectations that Refining and Marketing will continue to focus on the safety and reliability of its operations, leverage the company's strong brand to increase non-petroleum revenues through our network of convenience stores and car washes, and expand the lubricants product offering; and
•
  The Energy Trading business will optimize capacities associated with existing arrangements for pipeline and storage capacity, and optimize existing and future production.

Also:

•
  Suncor's assessment of the situation in Syria, including its determination of the net recoverable value of net assets in Syria that did not indicate than an impairment charge is required at this time, Suncor's expectations about recovering its share of any production during the period of force majeure, if force majeure is lifted, and Suncor's belief that it is entitled to certain receivables;
•
  Suncor's optimism about a gradual return to full operations in Libya and its assessment of the situation in Libya, including the impairment of net assets, the status of physical assets, and sustainability of production rates;
•
  Management's belief that Suncor will have the capital resources to fund its planned 2012 capital spending program of $7.5 billion and to meet current and long-term working capital requirements, 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 plans to maintain access to short-term commercial paper borrowing at competitive interest rates by keeping short-term debt at existing levels;
•
  Steve Williams assuming the role of CEO in May 2012;
•
  The company's expectations that the maximum weighted average term to maturity of its short-term investment portfolio will not exceed six months, and that all investments will be with counterparties with investment grade debt ratings; and
•
  Suncor's assessment of the impact of Bill C-13, which expects that, in future years, the legislation will decrease cash flow from operations by accelerating the payment of cash income taxes, but will not have a significant impact on net earnings.

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, 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 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 Fort McMurray 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

SUNCOR ENERGY INC. 2011 ANNUAL REPORT 77

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 the possibility 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 that represent employees at our refineries and distribution facilities.

Additional risks, uncertainties and other factors that could influence 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 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; 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; failure to realize anticipated synergies or cost-savings; and incorrect assessments of the values of assets acquired and liabilities assumed in the merger with Petro-Canada. 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 the MD&A, including under the heading Risk Factors, and the company's 2011 AIF dated March 1, 2012 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.

78 SUNCOR ENERGY INC. 2011 ANNUAL REPORT

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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2011, dated February 23, 2012