EX-99.2 3 a2202290zex-99_2.htm EXHIBIT 99.2
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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2010,
dated February 24, 2011

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 24, 2011

This Management's Discussion and Analysis (MD&A) should be read in conjunction with Suncor's December 31, 2010 audited Consolidated Financial Statements and the accompanying notes.

All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP), unless noted otherwise. Certain amounts in prior years have been reclassified to conform to the current year's presentation.

Additional information about Suncor filed with Canadian securities commissions and the United States (U.S.) Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the Annual Information Form dated March 3, 2011 (the 2010 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.

References to "we," "our," "Suncor," or "the company" mean Suncor Energy Inc., its subsidiaries, partnerships and joint venture investments, unless the context otherwise requires. References to "legacy Suncor" and "legacy Petro-Canada" refer to the applicable consolidated entity on a standalone basis prior to the August 1, 2009 merger date.

Petro-Canada Merger

On August 1, 2009, Suncor completed its merger with Petro-Canada, referred to in this MD&A as the "merger". Amounts disclosed in the audited Consolidated Financial Statements and this MD&A for 2009 and 2010 reflect results of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1, 2009 through July 31, 2009. The comparative figures from 2008 reflect solely the results of legacy Suncor. For further information with respect to the merger, please refer to note 3 of the December 31, 2010 audited Consolidated Financial Statements and the accompanying notes.

Non-GAAP Financial Measures

Certain financial measures referred to 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 Canadian GAAP.

Operating earnings are reconciled to GAAP net earnings in the Consolidated Financial Analysis and Segmented Earnings and Cash Flows sections of this MD&A. Oil Sands cash operating costs are reconciled to GAAP expenses in the Oil Sands – Operating Expenses section of this MD&A. Cash flow from operations and ROCE are defined in the Non-GAAP Financial Measures Advisory section of this MD&A.

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 as management uses this 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.

Legal 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 Legal Advisory – Forward-Looking Information section of this MD&A for information on material risk factors and assumptions underlying our forward-looking information.

Certain crude oil and natural gas liquids (NGL) volumes have been converted to thousands of cubic feet equivalent (mcfe) and millions of cubic feet equivalent (mmcfe) of natural gas on the basis of one barrel (bbl) to six thousand cubic feet (mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (boe) or thousands of boe (mboe) on the same basis. Mmcfe, mcfe, boe and mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or NGL 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.

6 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

SUNCOR OVERVIEW

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

•: Oil Sands, includes operations in northeast Alberta to develop and produce synthetic crude through the recovery and upgrading of bitumen from mining and in situ operations. The company has a 12% ownership interest in the Syncrude oil sands mining and upgrading joint venture, located near Fort McMurray, Alberta.
•: Natural Gas, includes exploration and production of natural gas, crude oil and NGL, primarily in Western Canada.
•: International and Offshore, includes offshore activity in East Coast Canada, with interests in the Terra Nova, Hibernia, the Hibernia South Extension, White Rose, White Rose Extensions and Hebron oilfields, and exploration and production of crude oil and natural gas in the United Kingdom (U.K.), Norway, Libya and Syria.
•: Refining and Marketing, includes the refining of crude oil products, and the distribution and marketing of these and other purchased products through refineries located in Canada and the U.S., as well as a lubricants plant located in Canada.

In addition, the company engages in third-party energy marketing and trading activities, and has investments in renewable energy assets, including Canada's largest ethanol plant by volume and partnerships in several wind power projects.

2010 HIGHLIGHTS

•: Strong financial results. Net earnings more than tripled to $3.571 billion in 2010 from $1.146 billion in 2009, and our cash flow from operations⁽¹⁾ increased to $6.656 billion in 2010, from $2.799 billion in 2009. Our 2010 results reflected the improving economic environment for crude oil and refined products, and solid performance from our assets during the first full year after the August 2009 merger with Petro-Canada. Our return on capital employed⁽¹⁾ (excluding major projects in progress) increased to 10.1% in 2010, up from 2.6% in 2009.
•: Ten-year growth strategy. In December 2010, we announced our new growth strategy. This plan begins in 2011, when we expect to direct approximately $2.8 billion towards a range of growth projects, as part of our overall 2011 capital-spending plan of $6.7 billion.
•: Strategic partnership with Total. As part of the company's growth strategy, Suncor announced a strategic partnership with Total E&P Canada Ltd. (Total), setting the terms for our two companies to develop the Fort Hills and Joslyn oil sands mining projects together with the other project partners, and restart construction of the Voyageur Upgrader. The transaction is subject to certain regulatory and other approvals, with closing targeted late in the first quarter of 2011.
•: Improved operational reliability. Oil Sands production steadily increased through 2010, finishing the year with record quarterly production volumes of 325,900 barrels per day (excluding Syncrude), compared to 202,300 barrels per day in the first quarter of this year, as a result of improved upgrader performance and strong bitumen supply across all of our Oil Sands assets. Western North America refinery utilization increased through 2010 to 101% in the fourth quarter from 92% in the first quarter.
•: Benefits of integration. International and Offshore assets acquired in the merger generated strong cash flows, and the increased refining capacity and additional locations in our Refining and Marketing business allowed us to respond to opportunities from both improved margins and logistical constraints in the second half of 2010.
•: Planned divestments. We successfully completed the planned disposal of approximately $3.5 billion of certain non-core assets from our Natural Gas and International and Offshore businesses. We also reached an agreement to sell non-core U.K. offshore assets, which we expect to complete during the first half of 2011.
•: Balance sheet strength. Proceeds from our planned divestments have been largely directed to reduce our net debt to $11.1 billion at year-end 2010, from $13.4 billion last year. This, along with our strong financial results, enabled us to improve our key debt ratios, with net debt to cash flow from operations now down to 1.7, from 4.8 last year, well below our target of less than 2.0, and our total debt to total debt plus shareholders' equity measure down to 25%, from 29% in 2009.
•: Tailings pond reclamation. During the year, Suncor became the first oil sands company to complete surface reclamation of a tailings pond. We also received regulatory approval for a new tailings management plan using the company's proprietary TRO_TM tailings management process, which is expected to significantly reduce pond reclamation time.

(1): Cash flow from operations and return on capital employed are non-GAAP measures. See the Non-GAAP Financial Measures Advisory section of this MD&A.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 7

BUSINESS ENVIRONMENT

Commodity Price Indicators and Exchange Rates

(average for the year ended December 31)		2010	2009	2008

West Texas Intermediate (WTI) crude oil at Cushing	US$/barrel	79.55	61.80	99.65
Dated Brent crude oil at Sullom Voe	US$/barrel	79.50	61.50	97.00
Dated Brent/Maya FOB price differential	US$/barrel	9.30	5.00	13.15
Canadian 0.3% par crude oil at Edmonton	Cdn$/barrel	78.05	65.80	103.05
Light/heavy crude oil differential of WTI at Cushing less Western Canadian Select (WCS) at Hardisty	US$/barrel	14.20	9.70	20.10
Natural gas (Alberta spot) at AECO	Cdn$/mcf	4.15	4.15	8.15
New York Harbour 3-2-1 crack	US$/barrel	10.55	8.80	11.05
Chicago 3-2-1 crack	US$/barrel	9.00	7.75	10.40
Seattle 3-2-1 crack	US$/barrel	13.55	11.40	12.10
Gulf Coast 3-2-1 crack	US$/barrel	7.90	7.10	9.45
Exchange rate	US$/Cdn$	0.97	0.88	0.94

Suncor's synthetic crude oil price realization is influenced by the market for light crude and our customers' alternatives. WTI crude oil at Cushing is the most common alternative benchmark. Oil prices strengthened in 2010 with WTI increasing from US$61.80/bbl to US$79.55/bbl since 2009.

Suncor's heavy crude oil price realization is influenced by customers' alternatives. WCS at Hardisty is a common reference price for Canadian heavy crude oil. The light/heavy crude differential between WTI and WCS widened in the second half of the year due to supply and demand factors including the Enbridge pipeline disruptions that limited the export capacity of heavy crude products from Western Canada, resulting in reduced and discounted sales. For the year ended December 31, 2010, this differential represented an average price discount of US$14.20/bbl to WTI, compared to US$9.70/bbl to WTI in 2009.

Suncor's price realization for International and Offshore production is influenced by the widely posted Brent crude oil price marker. Brent crude prices for the year ended December 31, 2010 averaged US$79.50/bbl, up from US$61.50/bbl for the year ended December 31, 2009.

Suncor's natural gas production is primarily referenced to the Alberta spot price at AECO. Natural gas prices for the year ended December 31, 2010 averaged $4.15/mcf, consistent with 2009.

The 3-2-1 crack spreads are industry indicators that roughly approximate the gross refining margin on a barrel of oil for gasoline and distillate. They are calculated by taking two times the spot price of gasoline at a certain location plus one multiplied by the spot price of diesel at the same location, subtracting three times the near-month contract price for NYMEX Light Sweet Crude Oil delivered at Cushing, Oklahoma, and then dividing the entire sum by three. Note that these prices do not necessarily reflect the actual crude purchase costs, product sales realizations, or product configurations of a specific refinery. These crack spreads were all higher for the year ended December 31, 2010 compared to 2009.

The majority of Suncor's revenues from the sale of oil and gas commodities receive 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 the revenues received from the sale of commodities and, correspondingly, 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.

8 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Economic Sensitivities

The following table illustrates the estimated effects that changes in certain factors would have had on Suncor's 2010 cash flow from operations and net earnings if they had occurred. Each separate line item in the sensitivity analysis shows the effects of a change in that variable only with all other variables being held constant.

	Approximate Change in
	Net Earnings ($ millions)		Cash Flow from Operations ⁽¹⁾ ($ millions)

Price
Crude oil – WTI US$1.00/bbl	89		114
Natural gas – AECO Cdn$0.10/mcf	7		9
Light/heavy differential – (WTI/WCS) US$1.00/bbl	34		44
Sales Volume
Crude oil – 10,000 bbl/day	129		163
Natural gas – 10 mmcf/d	1		11
Foreign currency ⁽²⁾
$0.01 change in US$/Cdn$	(39	)	(129	)

(1): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): The net earnings sensitivity includes the gain or loss on the revaluation of U.S. dollar denominated long-term debt, the change in interest expense on that debt, and the estimated effect on upstream sales realizations and refining margins. The cash flow from operations sensitivity includes the change in interest payments on U.S. dollar denominated long-term debt, and the estimated effect on realizations and margins.

SELECTED FINANCIAL INFORMATION

Annual Financial Data

($ millions, except as noted)	2010	2009		2008

Revenues (net of royalties)
Continuing operations	34 350	24 848		28 446
Discontinued operations ⁽¹⁾	870	632		191

	35 220	25 480		28 637

Net earnings (loss)
Continuing operations	2 688	1 206		2 082
Discontinued operations	883	(60	)	55

	3 571	1 146		2 137

Net earnings from continuing operations per common share
Basic	1.72	1.01		2.23
Diluted	1.71	1.00		2.20

Net earnings per common share ⁽²⁾
Basic	2.29	0.96		2.29
Diluted	2.27	0.95		2.26

Cash flow from operations ⁽³⁾
Continuing operations	6 164	2 434		3 888
Discontinued operations	492	365		169

	6 656	2 799		4 057

Total assets	70 169	69 746		32 528

Long-term debt, including current portion	12 187	13 880		7 884

Dividends on common shares	611	401		180

Cash dividends per common share	0.40	0.30		0.20

(1): Net of $62 million of operating revenues that would be eliminated upon consolidation in the Consolidated Statements of Earnings for the year ended December 31, 2010 (2009 – $33 million, 2008 – $24 million). See note 6 of the audited Consolidated Financial Statements.
(2): Includes continuing and discontinued operations.
(3): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 9

Upstream Production Volumes

mboe per day (mboe/d)	2010	2009	2008

Continuing operations
Oil Sands	318.2	306.7	228.0
Natural Gas	72.0	47.0	23.5
International and Offshore	170.9	58.0	—

	561.1	411.7	251.5

Discontinued operations
Natural Gas	23.8	27.4	13.2
International and Offshore	30.2	16.9	—

	54.0	44.3	13.2

Total	615.1	456.0	264.7

Downstream Sales Volumes

Thousands of cubic metres per day (thousands of m ³/d)	2010	2009	2008

Total refined product sales	87.8	54.9	31.5

CONSOLIDATED FINANCIAL ANALYSIS

Net Earnings

Positive factors impacting Suncor's net earnings from continuing operations for 2010, compared to 2009, included:

•: Upstream production for 2010 averaged 561,100 boe per day (boe/d), compared to 411,700 boe/d in 2009. Total sales of refined petroleum products averaged 87,800 cubic metres per day (m³/d) during 2010, up from 54,900 m ³/d in 2009. Both production and sales volumes increases were primarily due to the additional volumes resulting from the merger.
•: Realized prices were higher in 2010 compared to 2009. Increases in benchmark pricing were only partially offset by the widening of heavy crude differentials and the stronger Canadian dollar relative to the U.S. dollar.
•: Suncor recognized a pre-tax gain of $295 million pertaining to the redetermination of working interests for the Terra Nova oilfield, after the joint owners reached an agreement on December 1, 2010.

These positive factors were partially offset by the following:

•: Operating, selling and general expenses of $7.810 billion were higher in 2010, compared to $6.430 billion in 2009, primarily due to the inclusion of a full twelve months of legacy Petro-Canada operations in 2010, compared to only five months after the merger in 2009, as well as higher planned and unplanned maintenance activities in 2010, compared to 2009.
•: Depreciation, depletion and amortization (DD&A) of $3.813 billion was higher in 2010, compared to $1.860 billion in 2009, primarily due to the additional assets acquired through the merger and asset write-downs recorded in 2010.
•: Royalties of $1.937 billion were higher in 2010, compared to $1.150 billion in 2009, primarily due to the full year of legacy Petro-Canada production, higher royalty rates, a higher commodity price environment, and receipt of insurance proceeds from Suncor's captive insurance company. These increases were partially offset by a $140 million royalty recovery (pre-tax) booked in the fourth quarter of 2010 related to a notice received by the company from the Alberta government modifying the bitumen valuation methodology (BVM) calculation under Suncor's Royalty Amending Agreement (RAA) that expires in December 2015.
•: Financing income was $30 million in 2010, compared to financing income of $488 million in 2009, largely due to lower foreign exchange gains on U.S. dollar denominated long-term debt in 2010.
•: In 2009, net earnings included a pre-tax gain of $438 million on the effective settlement of a pre-existing processing contract with Petro-Canada, whereby Suncor processed MacKay River bitumen production for a fee.

Income tax expense was $1.860 billion in 2010 (34% effective tax rate), compared to $143 million in 2009 (11% effective tax rate). The lower effective tax rate in 2009 was primarily due to the lower tax rate applicable to the company's foreign exchange gains on U.S. dollar denominated long-term debt, and no tax impact on the gain on effective settlement of the pre-existing processing contract with Petro-Canada.

10 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Discontinued operations

In 2010, Suncor divested a number of non-core assets in the Natural Gas and International and Offshore segments. Results up to the closing date and any associated gain or loss on disposals of assets are presented as discontinued operations, as determined in accordance with GAAP. Current year net earnings from discontinued operations of $883 million includes pre-tax gains of $814 million on the asset disposals.

Cash flow from operations

Cash flow from operations was $6.656 billion in 2010, compared to $2.799 billion in 2009. The increase in cash flow from operations was primarily due to increased production volumes, higher refining and marketing sales, and higher realized prices. Cash flow from operations is a non-GAAP measure that the company uses to measure performance. See the Non-GAAP Financial Measures Advisory section of this MD&A.

Net Earnings for 2009 compared with 2008

Net earnings from continuing operations were $1.206 billion in 2009, compared with $2.082 billion in 2008. The decrease in net earnings from continuing operations was due primarily to lower price realizations, as well as costs related to deferring growth projects, and merger and integration costs associated with the merger with Petro-Canada on August 1, 2009. These impacts more than offset the increased upstream production, increased refined product sales volumes, and the gain on the effective settlement of a pre-existing processing contract with Petro-Canada. Net earnings in 2009 also included losses on commodity derivatives used for risk management, compared to a gain on these derivatives in 2008.

The merger increased Suncor's asset base by $35.8 billion, including goodwill, and long-term debt by $4.4 billion.

Operating Earnings ⁽¹⁾

Year ended December 31 ($ millions after-tax)	2010		2009		2008

Net earnings from continuing operations	2 688		1 206		2 082
Change in fair value of commodity derivatives used for risk management, net of realizations ⁽²⁾	(233	)	499		(372	)
Unrealized foreign exchange gain on U.S. dollar denominated long-term debt	(372	)	(798	)	852
Mark-to-market valuation of stock-based compensation	103		124		(107	)
Project start-up costs	58		40		24
Costs related to deferral of growth projects	94		300		—
Merger and integration costs	79		151		—
(Gain)/Loss on disposals ⁽³⁾	(121	)	39		—
Other income ⁽⁴⁾	(166	)	24		—
Adjustments to provisions ⁽⁵⁾	(51	)	50		—
Impairment and write-offs ⁽⁶⁾	317		—		—
Adjustments to provisions for assets acquired through the merger ⁽⁷⁾	68		—		—
Gain on effective settlement of pre-existing contract with Petro- Canada ⁽⁸⁾	—		(438	)	—
Impact of recording acquired inventory at fair value ⁽⁹⁾	—		97		—
Impact of income tax rate adjustments on future income tax liabilities ⁽¹⁰⁾	—		4		—

Operating earnings from continuing operations	2 464		1 298		2 479

Net earnings (loss) from discontinued operations	883		(60	)	55
Gain on disposals of discontinued operations ⁽³⁾	(689	)	—		—
Impairment and write-offs of discontinued operations ⁽⁶⁾	74		42		—

Operating earnings from total operations	2 732		1 280		2 534

(1): Operating earnings is a non-GAAP measure that adjusts net earnings for significant items that management believes are not indicative of operating performance and reduces the comparability of the underlying financial performance between periods. All reconciling items are presented on an after-tax basis. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(2): The company adjusts operating earnings for the change in fair value of significant crude oil risk management derivatives. The company also holds less significant risk management derivatives in other segments that are not adjusted.
(3): The 2010 total includes Natural Gas non-core asset sales and International and Offshore asset and share sales, a gain on unproven land in Natural Gas, and gains on Refining and Marketing sale of retail sites. The 2009 total related to a loss recognized when a highway interchange constructed by Suncor was transferred to the Government of Alberta, and fair value adjustments to assets acquired in the merger.
(4): Other income resulting from the settlement payment due to Suncor related to the Terra Nova redetermination. The payment will effectively reimburse Suncor for certain revenue related to its increased working interest (to 37.675% from 33.990%) back to the payout date of February 1, 2005. Operating earnings for 2010 and 2009 have been restated to reflect the portion of settlement attributable to the respective year.
(5): Impact from a royalty recovery related to a notice received by the company from the Alberta government modifying the BVM calculation for the interim period January 1, 2009 to December 31, 2010. As a result, the company reduced its royalty expense reserve by approximately $105 million (after-tax) in the fourth quarter of 2010. Operating earnings for prior years have been restated to effectively remove the original

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 11

provision booked. The company continues to negotiate final adjustments to the BVM calculation for the 2009 and 2010 interim period and for the term of the Suncor Royalty Amending Agreement that expires December 31, 2015.

(6): The 2010 total includes a write-down related to certain extraction equipment in the Oil Sands segment, a write-down of land leases no longer being pursued by the Natural Gas segment, an impairment of natural gas properties due to the lower gas price environment, an adjustment to spare parts inventory and an impairment of assets from the International and Offshore segment based on agreed sale price.
(7): The 2010 total includes adjustments for unfavourable pipeline commitments, adjustments made for past cost reconciliation related to the Exploration and Production Sharing Contracts (EPSAs) in Libya, a dry hole in Libya, a write-off of unproven land in Natural Gas, and a reduction to the provision related to the Montreal coker project.
(8): Impact from the deemed settlement value assigned to the bitumen processing contract with Petro-Canada upon close of the merger.
(9): Inventory acquired through the merger with Petro-Canada at fair value was sold during the third quarter of 2009, resulting in a one-time negative impact on earnings.
(10): Net impact from an increase in the future income tax liability resulting from a revised provincial allocation for income tax purposes because of the merger and a decrease in the future income tax liability resulting from the provincial rate reduction in Ontario.

Operating Earnings by Segment

Year ended December 31 ($ millions after-tax)	2010		2009		2008

Continuing operations
Oil Sands	1 535		1 116		2 522
Natural Gas	(137	)	(173	)	34
International and Offshore	993		362		—
Refining and Marketing	782		473		(23	)
Corporate, Energy Trading and Eliminations	(709	)	(480	)	(54	)

	2 464		1 298		2 479

Discontinued operations
Natural Gas	49		(14	)	55
International and Offshore	219		(4	)	—

	268		(18	)	55

Total operating earnings ⁽¹⁾	2 732		1 280		2 534

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

12 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

SEGMENTED EARNINGS AND CASH FLOWS

Oil Sands

Located in northeast Alberta, the Oil Sands operations recover bitumen from mining and in situ operations (Firebag and MacKay River) and upgrade the majority of this production into refinery feedstock, diesel fuel and byproducts. The company's marketing plan also includes sales of bitumen when market conditions are favourable or when operating conditions warrant. The Oil Sands business also includes a 12% ownership interest in the Syncrude oil sands joint venture and a share in the Fort Hills project.

On December 17, 2010, Suncor announced a strategic partnership with Total. Subject to certain conditions, the agreement provides that the two companies plan to develop the Fort Hills and Joslyn oil sands mining projects together with the other project partners, and restart construction on the Voyageur Upgrader, all with targeted operational dates ranging from 2016 to 2018.

On closing, it is expected that Total will acquire a 49% interest in Suncor's Voyageur Upgrader, and an additional 19.2% in the Fort Hills project, reducing Suncor's interest from 60% to 40.8%. In return, it is expected that Suncor will acquire a 36.75% interest in the Joslyn project and receive cash consideration of approximately $1.75 billion.

The transaction is subject to certain regulatory and other approvals, with closing targeted during the first quarter of 2011. The development of the Fort Hills and Joslyn oil sands mining projects, as well as the continued construction of the Voyageur Upgrader, is subject to approval by all of the partners in these ventures and by Suncor's Board of Directors.

Year ended December 31 ($ millions, unless otherwise noted)	2010		2009		2008

Gross revenues and other income	10 104		7 184		9 354
Less: Royalties	(681	)	(645	)	(715	)

Net revenues	9 423		6 539		8 639

Total production in thousands of barrels per day (mbbls/d)	318.2		306.7		228.0

Average sales price – includes the impact of realized risk management activities (excluding Syncrude) ($/bbl) ⁽¹⁾	69.58		61.66		95.96

Net earnings	1 492		557		2 875

Operating earnings ⁽²⁾	1 535		1 116		2 522

Cash flow from operations ⁽²⁾	2 769		1 251		3 507

Cash operating costs (excluding Syncrude) ($/bbl) ⁽²⁾	38.85		33.95		38.50
Sales mix (sweet/sour mix) (%)	37/63		47/53		43/57

(1): Before royalties and net of related transportation costs.
(2): Non-GAAP measures. Operating earnings and cash operating costs are reconciled below. Cash flow from operations is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2010		2009		2008

Net earnings	1 492		557		2 875
Change in fair value of commodity derivatives used for risk management, net of settlements	(233	)	499		(372	)
Mark-to-market valuation of stock-based compensation	31		28		(5	)
Project start-up costs	55		40		24
Costs related to deferral of growth projects	94		299		—
Losses on disposals	4		39		—
Impairment and write-offs	143		—		—
Adjustment to provisions	(51	)	50		—
Impact of income tax rate adjustments on future income tax liabilities	—		37		—
Gain on effective settlement of pre-existing contract with Petro-Canada	—		(438	)	—
Impact of recording acquired inventory at fair value	—		5		—

Operating earnings ⁽¹⁾	1 535		1 116		2 522

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

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 13

Oil Sands net earnings were $1.492 billion in 2010, compared to $557 million in 2009. Net earnings in 2010 included the impacts of higher average prices for oil sands crude products, a gain on commodity derivatives used for risk management, compared to a loss in 2009, increased total production and lower costs related to deferral of growth projects. Net earnings in 2010 also included a $140 million (pre-tax) royalty provision recovery related to a notice received by the company from the Alberta Government modifying the BVM calculation for the interim period January 1, 2009 to December 31, 2010, under Suncor's RAA. These factors were partially offset by higher 2010 operating costs, including higher project start-up costs for Firebag Stages 3 and 4, a write-down of certain extraction assets that were being developed as an alternative extraction process to crush and slurry oil sands at the mine face and a gain on the effective settlement of a pre-existing contract with Petro-Canada in 2009, whereby Suncor processed MacKay River bitumen production for a fee.

Continuing Operations

Operating earnings for 2010 were $1.535 billion, compared to $1.116 billion in 2009. The 38% increase in 2010 operating earnings was primarily due to higher realized prices and increased total production, partially offset by higher operating expenses.

Production Volumes

Year ended December 31 (mbbls/d)	2010	2009	2008

Production excluding Syncrude	283.0	290.6	228.0
Syncrude production ⁽¹⁾	35.2	16.1	—

Total production	318.2	306.7	228.0

(1): Production for the five months ended December 31, 2009 was 38.5 mbbls/d.

Total production increased 4% in 2010, compared to 2009, primarily due to additional production from Syncrude as a result of the timing of the merger. Apart from the Syncrude production, the merger did not result in increased Oil Sands production volumes, as production from MacKay River was included in Suncor's reported production during 2009 as volumes processed by Suncor under a processing fee agreement. However, the addition of seven months of MacKay River production in 2010 due to the timing of the merger has resulted in increased sales volumes for Oil Sands, as volumes under the processing agreement with Petro-Canada were not included in sales prior to August 1, 2009.

Production of 283,000 bpd in 2010, excluding Syncrude, was 3% lower compared with 290,600 bpd in 2009. The beginning of 2010 was negatively impacted by both planned and unplanned maintenance, which was partially offset by improved upgrader reliability and bitumen supply in the latter part of the year. Oil Sands completed the year with record production of 325,900 bpd in the fourth quarter of 2010. Unplanned maintenance at the beginning of the year included rebuild work on Upgrader 2 and Upgrader 1 following fires in December 2009 and February 2010. As a result, production for the year was reduced by approximately 29,500 bpd. The production impacts of the fire were mitigated by Suncor's ability to sell bitumen in the market, avoiding a shut-in of production.

Syncrude production contributed 35,200 bpd of sweet synthetic crude production in 2010, compared to 16,100 bpd in 2009. The increase was due to the additional seven months of production included in 2010, compared to 2009, as a result of the timing of the merger. Excluding the effects related to the timing of the merger, production from Syncrude decreased 9% due to planned and unplanned upgrader maintenance.

14 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Prices

Year ended December 31 (in Cdn$ per bbl)	2010	2009	2008

Average sales price – includes the impact of realized risk management activities (excluding Syncrude)	69.58	61.66	95.96
Average sales price – Syncrude	80.93	77.36	—

Sales mix (sweet/sour mix) (%)	37/63	47/53	43/57

Sales volumes (mbbls/d) – excluding Syncrude	279.3	276.2	227.0

Syncrude sales volumes (mbbl/d)	35.2	16.1	—

Oil Sands benefited from higher benchmark crude oil prices and lower realized losses in 2010 compared to 2009, partially offset by wider heavy crude differentials, change in sales mix and the stronger Canadian dollar relative to the U.S. dollar. Heavy crude oil differentials widened in the second half of 2010, as a result of the Enbridge pipeline disruptions that limited the export capacity of heavy crude products from Western Canada, resulting in reduced and discounted sales. These disruptions, and the resulting increase in supply of heavy crude products, negatively impacted both sour crude and bitumen price realizations.

Sales mix was negatively impacted in 2010 by the upgrader fires that occurred in December 2009 and February 2010, and by hydrogen supply and hydrotreating capacity issues in the latter part of 2010. This resulted in a lower percentage of higher value sweet crude product produced, increasing the sales volumes of lower value sour crude and bitumen.

In 2010, the Suncor average price realization on the crude sales basket, excluding Syncrude and derivatives used for risk management, was WTI less US$9.92 per bbl, or 88% of WTI, in comparison to 2009 when the price realization was WTI less US$5.22 per bbl, or 92% of WTI.

Operating Expenses

Operating expenses were higher in 2010, compared to 2009, primarily due to the inclusion of a full year of operating costs from the company's proportionate share of the Syncrude joint venture, higher costs from planned and unplanned maintenance, and the full year of operating costs from MacKay River operations, due to the timing of the merger. As noted previously in this MD&A, MacKay River production volumes were included in the 2009 results, whereas the associated operating expenses were not included as the volumes had originally been recorded under a processing agreement.

Third-party crude and diesel product purchases were higher in 2010, compared to 2009, to facilitate placement of Oil Sands heavy production and to fulfill contractual obligations. Product purchases have a minimal effect on earnings as these are largely offset in revenue.

Cash Operating Costs Reconciliation ⁽¹⁾⁽²⁾

Year ended December 31		2010			2009			2008
($ millions, unless otherwise noted)		$ millions		$/bbl	$ millions		$/bbl	$ millions	$/bbl

Operating, selling and general expenses		4 545			4 277			3 203
	Adjustments:
	Syncrude-related operating, selling and general expenses	(473	)		(199	)		—
	Other non-production related costs ⁽³⁾	(60	)		(479	)		9

Cash operating costs – excluding Syncrude		4 012		38.85	3 599		33.95	3 212	38.50

(1): Excludes Suncor's proportionate production share and operating costs from the Syncrude joint venture.
(2): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(3): Other adjustments includes items such as safe mode costs (the cost of placing a growth project on hold or in "safe mode"), inventory changes, stock-based compensation, gas swaps, accretion of asset retirement obligations and imported bitumen (excluding other reported product purchases). For the twelve months ended December 31, other non-production related costs were lower in 2010 compared to 2009, primarily due to lower safe mode costs ($254 million) offset by higher imported bitumen costs ($67 million).

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 15

Cash operating costs (excluding Syncrude) increased to $4.012 billion in 2010 from $3.599 billion in 2009. On a per barrel basis, these costs increased to $38.85/bbl in 2010 compared to $33.95/bbl in 2009, an increase of 14% year-over-year. The increase in cash operating costs was primarily due to the additional seven months of operating costs from the MacKay River operation, and reduced volumes and higher costs from planned and unplanned maintenance.

Cash operating costs for Suncor's interest in Syncrude operations averaged $37.95 per bbl in 2010, compared to $32.50 per bbl for the last five months of 2009. The increase in the current year was primarily due to the effects of planned maintenance on 2010 production, compared to 2009, where the five-month period included in 2009 due to the timing of the merger excluded significant effects of planned and unplanned maintenance.

Users are cautioned that the cash operating costs per barrel measure is not directly comparable to similar information calculated by other entities (including Syncrude), due to different accounting treatments for operating and capital costs amongst producers.

DD&A

The increase in DD&A expense from 2010 was due to newly commissioned assets and additional depreciation due to the assets acquired during the merger. Oil Sands assets are primarily depreciated on a straight-line basis.

Royalties

The increase in royalty expense was primarily due to the inclusion of a full twelve months of royalty payable production acquired in the merger (versus only five months in 2009) related to MacKay River and Suncor's proportionate share of Syncrude production, higher royalty rates and receipt of insurance proceeds from Suncor's captive insurance company for which royalties were payable. Suncor's MacKay River project moved to post-payout in November 2010, thereby increasing the percentage of royalties paid to approximately 31% of revenues minus costs for this period. Suncor's Firebag operation continued in the pre-payout phase and royalties were calculated at the minimum royalty percentage of revenues, which was a rate based on the Canadian dollar equivalent of WTI up to a maximum of 9%.

Safe Mode Costs

The company continues to incur costs related to placing certain growth projects into "safe mode" due to unfavourable market conditions in prior years. Safe mode costs are defined as the costs of deferring the projects, maintaining the equipment and facilities in a safe manner in order to expedite remobilization and the actual remobilization cost of growth projects placed into safe mode. As a result of placing certain projects into safe mode, pre-tax costs of $126 million were incurred in 2010, compared to $380 million in 2009. In 2010, Firebag Stage 3, Firebag Stage 4 and the Millennium Naphtha Unit (MNU) projects were all remobilized.

Planned Maintenance Turnarounds

Suncor's Oil Sands business has a six-week planned turnaround scheduled for Upgrader 2 in the second quarter of 2011. Production volumes are expected to be reduced by approximately 215,000 bpd over the duration of the turnaround.

16 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Natural Gas

Suncor's Natural Gas business, operating primarily in Western Canada, explores for, acquires, develops and produces natural gas, NGLs, oil and byproducts that are used for internal consumption and sale to customers across North America.

Year ended December 31 ($ millions, unless otherwise noted)		2010		2009		2008

Gross revenues from continuing operations		810		459		471
Less: Royalties from continuing operations		(76	)	(36	)	(107	)

Net revenues from continuing operations		734		423		364

Gross production
	Continuing operations (mmcfe per day – mmcfe/d)	432		282		141
	Discontinued operations (mmcfe/d)	143		164		79

		575		446		220

Average sales price from continuing operations
	Natural gas – includes the impacts of realized risk management activities ($/mcf) ⁽¹⁾	3.99		3.63		8.21
	Natural gas liquids and crude oil ($/bbl) ⁽¹⁾	77.37		59.41		68.05

Net earnings (loss)
	Continuing operations	(277	)	(185	)	34
	Discontinued operations	506		(14	)	55

		229		(199	)	89

Operating earnings (loss) ⁽²⁾
	Continuing operations	(137	)	(173	)	34
	Discontinued operations	49		(14	)	55

		(88	)	(187	)	89

Cash flow from operations ⁽²⁾
	Continuing operations	320		177		198
	Discontinued operations	125		152		169

		445		329		367

(1): Calculated before royalties and net of transportation costs.
(2): Non-GAAP measures. Operating earnings is reconciled below. Cash flow from operations is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2010		2009		2008

Net loss from continuing operations	(277	)	(185	)	34
Mark-to-market valuation of stock-based compensation	9		11		—
Gains on disposals	(99	)	—		—
Impact of income tax rate adjustments on future income tax liabilities	—		1		—
Impairment and write-offs	174		—		—
Adjustments to provisions for assets acquired through the merger	56		—		—

Operating loss from continuing operations ⁽¹⁾	(137	)	(173	)	34

Net earnings (loss) from discontinued operations	506		(14	)	55
Gains on disposals of discontinued operations	(479	)	—		—
Impairment and write-offs	22		—		—

Operating loss from total operations ⁽¹⁾	(88	)	(187	)	89

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

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 17

Natural Gas had total net earnings of $229 million in 2010, compared with a net loss of $199 million in 2009. Net earnings in 2010 were positively impacted, compared to 2009, by pre-tax gains of $774 million on asset dispositions for non-core assets and unproven land sold in 2010, and increased total production as a result of the merger. These factors were partially offset by a $222 million write-down (pre-tax) of certain assets where the carrying value of the assets was greater than their expected discounted future cash flows, and the $44 million write-down (pre-tax) of certain land leases in Western Canada and Alaska that the company was no longer pursuing as part of its strategic business realignment.

Continuing Operations

Operating loss from continuing operations in 2010 was $137 million, compared to an operating loss from continuing operations of $173 million in 2009. The decrease in operating loss from continuing operations in 2010 was primarily due to higher production volumes as a result of the merger, lower exploration expenses and higher realized prices. This was partially offset by higher lifting costs as a result of the merger and higher DD&A expense.

Production Volumes

Year ended December 31 (mmcfe/d)	2010	2009	2008

Natural gas	399	262	135
Natural gas liquids and crude oil	33	20	6

Gross production	432	282	141

Gross production from continuing operations increased 53% in 2010, compared to 2009. The increase primarily reflects additional production associated with the assets acquired as a result of the merger, partially offset by asset dispositions and natural declines.

Prices

Natural gas average realized prices were higher in 2010, compared to 2009, although the average AECO benchmark was unchanged year-over-year, due to the volume and timing of sales in 2009. As a result of the merger, sales were higher in the second half of 2009 when the AECO benchmark price was lower, which had an overall impact of decreasing the natural gas realized price in 2009. In 2010, sales volumes and realized prices were more consistent throughout the year and transportation costs were lower.

Operating Expenses

Operating expenses from continuing operations increased in 2010, compared to 2009, due to the operating expenses associated with the assets acquired as a result of the merger being included for the full 2010 year, compared to only five months in 2009, due to the timing of the merger. Operating expenses per unit of production of $2.18/mcfe were higher than 2009 ($1.98/mcfe), primarily due to plant turnaround costs incurred in the fourth quarter of 2010.

DD&A and Exploration Expenses

DD&A from continuing operations increased in 2010, compared to 2009, primarily due to higher production volumes from assets acquired as a result of the merger. Natural Gas assets are primarily depleted on a unit-of-production basis.

Exploration expenses from continuing operations decreased due to reduced exploration activity and increased drilling success in 2010, resulting in lower dry hole costs.

Royalties

In 2010, total Crown royalties from continuing operations increased compared to 2009. The increased royalties were primarily associated with the production acquired as a result of the merger, higher realized prices in 2010 versus 2009 and higher royalty credits received in 2009.

18 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Discontinued Operations

Natural Gas has divested a number of non-core natural gas assets throughout 2010. Discontinued operations as determined in accordance with GAAP includes the results, up to the closing date, of assets that have been sold during the year. Comparative results have been restated to reflect the impact of operations that have been classified as discontinued during 2010. The following is a summary of key divestitures:

•: On March 1, 2010, the company completed the sale of substantially all of its U.S. Rockies upstream assets for net proceeds of US$481 million. Remaining U.S. Rockies upstream assets were sold shortly thereafter.
•: On March 31, 2010, the company completed the sale of certain non-core natural gas properties located in northeast British Columbia, known as Blueberry and Jedney, for net proceeds of $383 million.
•: On May 31, 2010, the company completed the sale of non-core natural gas properties located in central Alberta, known as Rosevear and Pine Creek, for net proceeds of $229 million.
•: On August 31, 2010, the company completed the sale of its non-core natural gas properties located in west central Alberta, known as Bearberry and Ricinius, for net proceeds of $275 million.
•: On September 30, 2010, the company completed the sale of its non-core natural gas properties located in southern Alberta, known as Wildcat Hills, for net proceeds of $351 million.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 19

International and Offshore

Suncor's International and Offshore operations comprise production and exploration activity offshore Newfoundland and in the North Sea, onshore production and exploration activity in Libya and Syria, and exploration acreage in Norway.

In East Coast Canada, Suncor operates Terra Nova, holding a working interest of 37.675% that increased from 33.990% effective January 1, 2011. This working interest redetermination was finalized in December 2010 in accordance with the Terra Nova Development and Operating Agreement. Suncor also holds a 20% interest in Hibernia and a 19.5% interest in the Hibernia South Extension, a 27.5% interest in White Rose and a 26.125% interest in White Rose North Amethyst and West White Rose Extension, and a 22.7% interest in Hebron. In the North Sea, Suncor holds a 29.9% working interest in Buzzard. Suncor also operates in Libya, pursuant to EPSAs, to design and implement jointly the development of oil fields in the Sirte Basin, and in Syria, pursuant to a production sharing contract (PSC), on the Ebla gas project to develop the Ash Shaer and Cherrife areas.

In late February, civil unrest swept Libya. At the time of filing this report, the degree and duration of impact on Suncor's operations is not known.

Year ended December 31 ($ millions, unless otherwise noted)		2010		2009

Gross revenues from continuing operations		5 503		1 686
Less: Royalties		(1 180	)	(469	)

Net revenues from continuing operations		4 323		1 217

Production from continuing operations (mboe/d)
	East Coast Canada	68.6		24.3
	U.K. (Buzzard)	55.5		20.0
	Libya	35.2		13.7
	Syria	11.6		—

Total production from continuing operations (mboe/d)		170.9		58.0
Total production from discontinued operations (mboe/d)		30.2		16.9

Total production (mboe/d) ⁽¹⁾		201.1		74.9

Average sales price from continuing operations ⁽²⁾
	East Coast Canada ($/bbl)	80.20		76.86
	U.K. (Buzzard) ($/boe)	77.91		69.53
	Other International ($/boe)	78.07		77.53

Net earnings (loss)
	Continuing operations	1 114		323
	Discontinued operations	377		(46	)

		1 491		277

Operating earnings (loss) ⁽³⁾
	Continuing operations	993		362
	Discontinued operations	219		(4	)

		1 212		358

Cash flow from operations ⁽³⁾
	Continuing operations	2 512		738
	Discontinued operations	367		213

		2 879		951

(1): Production for the five months ended December 31, 2009 was 178.8 mboe/d.
(2): Calculated before royalties and net of transportation costs.
(3): Non-GAAP measure. Operating earnings is reconciled below. Cash flow from operations is reconciled in the Non-GAAP Financial Measures Advisory section of the MD&A.

20 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2010		2009

Net earnings from continuing operations	1 114		323
Mark-to-market valuation of stock-based compensation	14		10
Other income ⁽¹⁾	(166	)	24
Project start-up costs	3		—
Impact of income tax rate adjustments on future income tax liabilities	—		(20	)
Impact of recording acquired inventory at fair value	—		25
Adjustments to provisions for assets acquired through the merger	28		—

Operating earnings from continuing operations ⁽²⁾	993		362

Net earnings (loss) from discontinued operations	377		(46	)
Gains on disposals of discontinued operations	(210	)	—
Impairment and write-offs	52		42

Operating earnings from total operations ⁽²⁾	1 212		358

(1): Other income resulting from the settlement payment due to Suncor related to the Terra Nova redetermination. The payment of $220 million (after-tax) reimburses Suncor for certain net revenues related to its increased interest from the field payout date of February 1, 2005 to December 31, 2010. Operating earnings for 2010 and 2009 have been restated to include only the amount that relates to the comparative period.
(2): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of the MD&A.

International and Offshore had net earnings of $1.491 billion in 2010, compared to $277 million in 2009. Net earnings in 2010 were positively impacted by increased production as a result of the timing of the merger and new production coming on-stream in 2010, higher realized commodity prices, pre-tax gains of $170 million on asset dispositions and the $295 million pre-tax gain recognized pertaining to the Terra Nova redetermination.

Continuing Operations

Operating earnings from continuing operations were $993 million in 2010, compared to $362 million in 2009. Operating earnings from continuing operations were higher in 2010 due to increased production as a result of the timing of the merger and new production coming on-stream, and higher realized commodity prices. These increases were partially offset by increases to royalty expense and DD&A expense, due to the additional seven months of operations as a result of the timing of the merger.

Production Volumes

Year ended December 31 (mboe/d)			2010	2009

Production from continuing operations
	East Coast Canada
		Terra Nova	23.2	8.7
		Hibernia	30.9	11.4
		White Rose	14.5	4.2
	U.K.
		Buzzard	55.5	20.0
	Libya		35.2	13.7
	Syria		11.6	—

Total production⁽¹⁾			170.9	58.0

(1): Production from continuing operations for the five months ended December 31, 2009 averaged 138.4 mboe/d.

Production from continuing operations was significantly higher in 2010, compared to 2009, primarily due to the seven additional months of production included in 2010 as a result of the timing of the merger. Excluding the volume impacts due to the merger, there was higher production in 2010, compared with 2009, as a result of new production that came on-stream in 2010 in Syria and the North Amethyst portion of the White Rose Extensions (North Amethyst), and from new production from the AA Block area of Hibernia that came on-stream at the end of 2009. Buzzard also had higher production in 2010 due to the smaller scope of maintenance activity as compared to 2009.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 21

Prices

International and Offshore benefited from higher price realizations in 2010, due to higher benchmark commodity prices relative to 2009.

Operating Expenses

Operating expenses from continuing operations increased in 2010, compared to 2009, primarily due to the additional seven months of production included in 2010 as a result of the timing of the merger, and costs associated with the new production delivered from Syria and North Amethyst, partially offset by cost reduction initiatives undertaken during the year.

DD&A

DD&A from continuing operations was higher in 2010, compared to 2009. The increase was primarily due to higher production from the additional seven months of production included as a result of the timing of the merger and new production coming on-stream in 2010.

Royalties

Royalties were higher in 2010, compared to 2009, primarily due to the additional seven months of production included in 2010 as a result of the timing of the merger, additional production coming on-stream in 2010 and higher realized prices, partially offset by increases in capital and operating expenditures for East Coast Canada operations.

Royalties are not paid on U.K. production. Suncor's operations in Libya and Syria are conducted pursuant to PSCs. The royalty amounts presented reflect the difference between Suncor's working interest in the particular project and the net revenue attributable to Suncor under the terms of the applicable contract. All government interests in the operations, except for income taxes, are presented as royalties.

Planned Maintenance Turnarounds

At Terra Nova, a 15-week dockside maintenance program is planned in 2011. Production volumes are expected to be reduced by approximately 25,000 bpd over the duration of the turnaround. However, Suncor is working with partners to consider the possibility of delaying this to 2012.

Also in 2011, White Rose has a three-week routine turnaround planned and Buzzard has a one-week shutdown planned.

Discontinued Operations

International and Offshore substantially completed its strategic divestment activities and has divested a number of assets throughout 2010. Discontinued operations, determined in accordance with GAAP, include the results, up to the closing date, of assets that have been sold during the quarter, as well as results from certain assets the company expects to sell. Comparative results have been restated to reflect the impact of operations that have been classified as discontinued during the third quarter of 2010.

•: On August 5, 2010, the company completed the sale of its assets in Trinidad and Tobago, for net proceeds of US$378 million with an effective date of January 1, 2010.
•: On August 13, 2010, the company completed the sale of its shares in Petro-Canada Netherlands B.V., for net proceeds of €316 million with an effective date of January 1, 2010.
•: On September 8, 2010, the company reached an agreement to sell its non-core U.K. offshore assets (Scott/Telford and Triton) for gross proceeds of £240 million, effective July 1, 2010. The sale involves interests in 12 offshore production and exploration licences in the U.K. sector of the North Sea. Divestment of a portion of those assets was completed in 2010 for net proceeds of £55 million. The sales of the remaining assets are expected to close during the first half of 2011. The remaining divestments are subject to closing conditions, closing adjustments to the purchase price and regulatory and other approvals customary for transactions of this nature.

22 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Refining and Marketing

Refining and Marketing refines crude oil into a broad range of petroleum and petrochemical products at refineries located in Edmonton, Montreal and Sarnia in Canada, and Commerce City, Colorado in the U.S. Products are sold to retail, commercial and industrial customers through a combination of company-owned, branded-dealer and joint venture- operated retail stations in Canada and Colorado, a nationwide Canadian commercial road transport network and a bulk sales channel. Refining and Marketing also owns and operates a lubricants business located in Mississauga, Ontario that manufactures, blends and markets high quality products worldwide. Other assets include interests in a petrochemical plant, pipelines and product terminals in Canada and the United States.

Year ended December 31 ($ millions, unless otherwise noted)		2010	2009	2008

Revenues		21 062	11 851	9 258

Refined product sales (thousands of m ³/d)
	Gasoline	41.1	27.6	15.9
	Distillates	30.9	18.3	10.8
	Other, including petrochemicals	15.8	9.0	4.8

Total refined product sales ⁽¹⁾		87.8	54.9	31.5

Crude oil processed by Suncor (thousands of m ³/d) ⁽²⁾		65.1	42.2	24.7

Net earnings (loss)		801	407	(22	)

Operating earnings ⁽³⁾
	Refining and product supply	523	321	(60	)
	Marketing	259	152	37

Total operating earnings (loss)		782	473	(23	)

Cash flow from operations ⁽³⁾		1 536	921	220

(1): Total refined product sales for the five months ended December 31, 2009 was 84.8 thousands of m ³/d.
(2): Crude oil processed by Suncor for the five-month period ended December 31, 2009 was 63.5 thousands of m ³/d.
(3): Non-GAAP measure. Operating earnings is reconciled below. Cash flow from operations is reconciled in the Non-GAAP Financial Measures Advisory section of this MD&A.

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2010		2009		2008

Net earnings (loss)	801		407		(22	)
Mark-to-market valuation of stock-based compensation	29		17		(1	)
Gains on disposals	(26	)	—		—
Adjustments to provisions for assets acquired through the merger	(22	)	—		—
Impact of income tax rate reductions on opening future income tax liabilities	—		(19	)	—
Impact of recording acquired inventory at fair value	—		67		—
Costs related to deferral of growth projects	—		1		—

Operating earnings ⁽¹⁾	782		473		(23	)

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

The Refining and Marketing business recorded net earnings of $801 million in 2010 compared with $407 million in 2009. The higher net earnings in 2010 relative to 2009 were primarily due to additional refining capacity gained through the merger, favourable margins and a $67 million negative fair value adjustment (after-tax) included in 2009 net earnings related to the acquisition of inventory as part of the merger. These items were partially offset by higher operating expenses and DD&A. Operating earnings in 2010 were $782 million, which was a $309 million increase over 2009 primarily due to increased volumes from the seven additional months of merged operations in 2010 and improved refining margins, partially offset by higher operating expenses.

Refining and product supply activities contributed operating earnings of $523 million in 2010, up from $321 million in 2009. The increase was due to improved operational reliability and increased production gained from the addition of the Edmonton refinery, Montreal refinery, and the lubricants plant, as a result of the merger. The 2009 comparative period included five months of post-merger results, compared to a full year in

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 23

2010. Other positive contributions to operating earnings included wider light/heavy and light/sour synthetic crude pricing differentials and stronger distillate cracking margins. These were somewhat offset by lower utilization of the Sarnia refinery due to Enbridge pipeline disruptions that limited crude availability in the latter part of 2010.

Marketing activities contributed operating earnings of $259 million in 2010, compared with $152 million in 2009. The increase reflected higher sales volumes due to the additional seven months of operations from the retail, wholesale and lubricants businesses included in 2010 as a result of the timing of the merger.

Continuing Operations

Volumes

Year ended December 31 (thousands of m ³/d)			2010	2009	2008

Refined Product Sales
	Gasoline
		Eastern North America	22.2	14.6	7.9
		Western North America	18.9	13.0	8.0

			41.1	27.6	15.9

	Distillates
		Eastern North America	12.4	8.8	5.2
		Western North America	18.5	9.5	5.6

			30.9	18.3	10.8

	Other, including petrochemicals		15.8	9.0	4.8

Total refined product sales			87.8	54.9	31.5

Crude oil processed by Suncor
	Eastern North America		30.5	19.3	11.0
	Western North America		34.6	22.9	13.7

Total crude oil processed by Suncor			65.1	42.2	24.7

Total sales of refined petroleum products averaged 87,800 m ³/d, compared to 54,900 m ³/d in 2009. Sales volumes increased largely due to the merger. After the completion of the merger in 2009, total sales of refined petroleum product averaged 84,800 m ³/d during the last five months of 2009.

Overall, refinery utilization averaged 92% in 2010, compared to a post-merger rate of 92% in 2009, which included twelve months of results for the Sarnia and Commerce City refineries and five months for the Edmonton and Montreal refineries. Sarnia ran less crude in the latter part of 2010 primarily due to Enbridge pipeline disruptions that limited western Canadian crude availability. This shortfall was partially mitigated by processing foreign light crudes and higher utilization at the Montreal refinery to maintain product supply in Ontario.

Margins

Gross margins, in absolute terms, increased in 2010 compared to 2009 due to the additional volume resulting from the merger and improved refining crack spreads that resulted in higher price realizations for our refined products.

Refining and product supply activities benefited from more favourable light/heavy and light/sour synthetic crude price differentials and an improved business environment in 2010, with higher cracking margins in every major market area and stronger product demand compared to 2009. The Edmonton refinery benefited from lower feedstock costs due to wider light/heavy and light/sour synthetic crude differentials. The Sarnia refinery was negatively impacted by the Enbridge pipeline service disruptions that restricted deliveries of lower cost sour crude received from Western Canada and necessitated processing more expensive offshore crude.

Marketing activities continued to benefit from the merger in 2010 with increased volumes. However, the gross petroleum margin on a per litre basis was lower, compared to 2009, due to the broader geographic market base and product offering mix of the merged retail network.

Operating Expenses

Operating expenses were higher in 2010, compared to 2009, primarily due to the inclusion of an additional seven months of operations in 2010 as a result of the timing of the merger.

DD&A

DD&A expense was higher in 2010, primarily due to the larger merged asset base.

Planned Maintenance Turnarounds

Major maintenance turnaround work was completed in 2010 at three of the four refineries and the lubricants production facility. Major turnaround work is planned in

24 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

2011 at the Sarnia, Edmonton and Commerce City refineries.

For planned turnarounds, the company enters into transactions to ensure sufficient additional finished product is available to mitigate the impact of lost production on customers.

Corporate, Energy Trading and Eliminations

Corporate, Energy Trading and Eliminations includes the company's investment in renewable energy projects, results related to energy trading activities with third-parties, and activities not directly attributable to any operating segment.

Operating Earnings Reconciliation

Year ended December 31 ($ millions)	2010		2009		2008

Net (loss) earnings	(442	)	104		(805	)
Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(372	)	(798	)	852
Mark-to-market valuation of stock-based compensation	19		58		(101	)
Merger and integration costs	86		151		—
Impact of income tax rate adjustments on future income tax liabilities	—		5		—

Operating loss ⁽¹⁾	(709	)	(480	)	(54	)

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

Year ended December 31 ($ millions)		2010		2009		2008

Operating earnings (loss) ⁽¹⁾
	Renewable energy	33		29		28
	Energy trading	53		44		56
	Corporate	(808	)	(460	)	(129	)
	Group eliminations	13		(93	)	(9	)

		(709	)	(480	)	(54	)

Cash flow used in operations ⁽¹⁾		(973	)	(653	)	(37	)

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

The net loss in 2010 for the Corporate, Energy Trading and Eliminations segment was $442 million, compared to net earnings of $104 million in 2009. The decrease in net earnings of 2010 was primarily due to a smaller unrealized foreign exchange gain on U.S. dollar denominated long-term debt compared to 2009. Operating loss in 2010 was higher than 2009 primarily due to captive insurance payments made in 2010 and additional interest expense.

Renewable Energy

Renewable energy contributed $33 million of operating earnings in 2010, which was comparable with those in 2009 ($29 million). Suncor has an ethanol plant and joint ownership in four wind farm projects. The expansion to double the design capacity of the ethanol plant from 200 million litres per year to 400 million litres per year was completed in January 2011. There are two additional wind farm projects under construction.

Energy Trading

Energy trading activities primarily involve marketing and trading of crude oil, natural gas, refined products and byproducts, and the use of financial derivatives. These activities resulted in operating earnings of $53 million in 2010 compared to $44 million in 2009. In 2010, earnings were driven by buying heavy oil in Western Canada at wide price differentials relative to WTI and transporting this product to more favourable markets. In 2009 results were positively impacted by realized physical gains on crude inventory positions.

Corporate and Eliminations

Corporate experienced an operating loss of $808 million in 2010, compared to an operating loss of $460 million in 2009. The increased operating loss was primarily due to captive insurance payments made in the first and third quarters of 2010 and additional interest expense, resulting from additional debt acquired through the merger.

Group eliminations reflects the elimination of profit on crude oil sales between Oil Sands or East Coast Canada and Refining and Marketing, where profits are realized when the products are sold to third parties. During 2010, $13 million of profits previously eliminated were recognized in earnings, compared to profits of $93 million that were eliminated in 2009.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 25

QUARTERLY FINANCIAL DATA

		2010 Three months ended				2009 Three months ended
($ millions, except as noted)		Dec 31	Sept 30	June 30	Mar 31	Dec 31		Sept 30		June 30		Mar 31

Revenues (net of royalties)
Continuing operations		9 789	8 636	8 979	6 946	7 236		8 257		4 748		4 607
Discontinued operations ⁽¹⁾		150	211	207	302	400		186		20		26

		9 939	8 847	9 186	7 248	7 636		8 443		4 768		4 633

Net earnings (loss)
Continuing operations		1 297	609	318	464	476		965		(46	)	(189	)
Discontinued operations		56	413	162	252	(19	)	(36	)	(5	)	—

		1 353	1 022	480	716	457		929		(51	)	(189	)

Net earnings (loss) from continuing operations per common share
Basic		0.83	0.39	0.20	0.30	0.30		0.72		(0.05	)	(0.20	)
Diluted		0.82	0.39	0.20	0.30	0.30		0.71		(0.05	)	(0.20	)

Net earnings (loss) per common share ⁽²⁾
Basic		0.87	0.65	0.31	0.46	0.29		0.69		(0.06	)	(0.20	)
Diluted		0.86	0.65	0.31	0.45	0.29		0.68		(0.06	)	(0.20	)

Operating earnings (loss) ^(2),(3)
Continuing operations		890	600	752	220	319		398		61		398
Discontinued operations		56	75	53	84	23		(36	)	(5	)	—

		946	675	805	304	342		362		56		398

Operating earnings per common share ^(2),(3)		0.60	0.43	0.52	0.19	0.22		0.29		0.06		0.43

Cash flow from operations ^(2),(4)		2 144	1 630	1 758	1 124	1 129		574		295		801

Return on capital employed
	(twelve months ended)
	(%) ^(4),(5)	10.1	7.9	7.0	4.9	2.6		3.7		7.3		16.0

(1): Discontinued operations per note 6 of the audited Consolidated Financial Statements, excluding gain on disposal.
(2): Includes continuing and discontinued operations.
(3): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(4): Non-GAAP measure. See the reconciliation in the Non-GAAP Financial Measures Advisory section of this MD&A.
(5): Excludes capitalized costs related to major projects in progress.

In addition to changes in production and product sales, commodity price fluctuations and the impacts of changes to foreign exchange rates, variations in quarterly net earnings from continuing operations during 2010 and 2009 include the following factors:

•: The fourth quarter of 2010 included a gain for the redetermination of Terra Nova oilfield working interests and an adjustment to royalty expense with respect to the modification to the BVM calculation.
•: The third quarter of 2010 included impairments to Natural Gas assets.
•: The second quarter of 2010 included impairments of Oil Sands assets that were being used in the development of an alternative extraction process and Natural Gas properties that the company decided not to pursue.
•: The first quarter of 2010 and the fourth quarter of 2009 were negatively impacted by upgrader fires that significantly reduced Oil Sands production and altered our product mix.
•: The fourth quarter of 2009 included a gain from the impacts of income tax rate adjustments, partially offset by losses on asset disposal.
•: The third quarter of 2009 included the additional upstream production and refining product sales resulting from the merger and an effective gain on a pre-existing contract with Petro-Canada.
•: The first quarter of 2009 included significant costs associated with the deferral of certain growth projects.

26 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

CONSOLIDATED FINANCIAL ANALYSIS – FOURTH QUARTER 2010

Fourth Quarter 2010 Highlights

•: Results from Refining and Marketing in the fourth quarter of 2010 were strong, with net earnings of $372 million, which was more than double the fourth quarter of 2009, primarily as a result of higher realized margins and increased refinery utilization. Total sales of refined petroleum products averaged 91,100 m ³/d during the fourth quarter of 2010 compared to 82,900 m ³/d in the fourth quarter of 2009, reflecting more reliable operations in all of the company's facilities and improved product demand.
•: Total upstream production in the fourth quarter was 625,600 boe/d, compared to 638,200 boe/d in the fourth quarter of 2009. However, production from continuing operations increased to 605,400 boe/d in the fourth quarter of 2010, from 544,500 boe/d in the fourth quarter of 2009. Overall, lower production volumes were primarily due to asset sales in Suncor's Natural Gas and International and Offshore businesses, partially offset by production increases in continuing International and Offshore operations and improved operational reliability at Oil Sands.

Net Earnings by Segment

	Three months ended December 31				Year ended December 31
	2010		2009		2010		2009

Continuing operations
Oil Sands	487		236		1 492		557
Natural Gas	(65	)	(55	)	(277	)	(185	)
International and Offshore	452		230		1 114		323
Refining and Marketing	372		151		801		407
Corporate, Energy Trading and Eliminations	51		(86	)	(442	)	104

	1 297		476		2 688		1 206

Discontinued operations
Natural Gas	(2	)	5		506		(14	)
International and Offshore	58		(24	)	377		(46	)

	56		(19	)	883		(60	)

Net earnings	1 353		457		3 571		1 146

Upstream Production Volumes

	Three months ended December 31		Year ended December 31
(mboe/d)	2010	2009	2010	2009

Continuing operations
Oil Sands (includes Syncrude)	363.8	318.2	318.2	306.7
Natural Gas	71.5	76.8	72.0	47.0
International and Offshore	170.1	149.5	170.9	58.0

	605.4	544.5	561.1	411.7

Discontinued operations
Natural Gas	1.5	50.6	23.8	27.4
International and Offshore	18.7	43.1	30.2	16.9

	20.2	93.7	54.0	44.3

Total	625.6	638.2	615.1	456.0

Downstream Sales Volumes

	Three months ended December 31		Year ended December 31
(m ³/d)	2010	2009	2010	2009

Total refined product sales	91.1	82.9	87.8	54.9

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 27

Oil Sands

Oil Sands net earnings for the fourth quarter of 2010 were $487 million, compared to $236 million for the fourth quarter of 2009. Net earnings in the fourth quarter of 2010 compared to 2009 included the impacts of a bitumen valuation royalty provision recovery, which was partially offset by lower gains on change in fair value of commodity derivatives used for risk management and lower costs related to deferral of growth projects.

Oil Sands production, excluding Suncor's share of production from Syncrude, was 17% higher in the fourth quarter of 2010 compared to the fourth quarter of 2009. Higher bitumen supply from all of the Oil Sands assets contributed to a record quarterly production average volume of 325,900 bpd in the fourth quarter of 2010. The prior year quarter was negatively impacted by the fire that occurred in December 2009 at Upgrader 2.

Syncrude production decreased 4% in the fourth quarter of 2010, compared to the fourth quarter of 2009, primarily due to upgrader outages that occurred during the quarter.

Oil Sands benefited from higher benchmark crude oil prices in the fourth quarter of 2010 compared to the fourth quarter of 2009, partially offset by wider heavy crude oil differentials and the stronger Canadian dollar relative to the U.S. dollar. Enbridge pipeline disruptions limited the export capacity of heavy crude products from Western Canada, reducing both sour crude and bitumen price realizations during the fourth quarter of 2010.

The six-week planned turnaround for Upgrader 2 that began in September continued for three weeks into the fourth quarter of 2010. Hydrogen supply and hydrotreating issues, which also surfaced initially in the third quarter of 2010, increased the percentage of sour crude produced during the fourth quarter and negatively impacted product mix and price realizations.

Natural Gas

Natural Gas had a net loss from continuing operations of $65 million in the fourth quarter of 2010, compared with a net loss of $55 million in the fourth quarter of 2009. Net loss from continuing operations in the fourth quarter of 2010 included the impacts of a $13 million write-down of spare parts inventory and higher costs related to stock-based compensation. Gross production from continuing operations decreased by 7% in the fourth quarter of 2010, compared to the fourth quarter of 2009, mainly due to natural declines.

International and Offshore

International and Offshore had net earnings from continuing operations of $452 million in the fourth quarter of 2010, compared to $230 million in the fourth quarter of 2009. Net earnings in the fourth quarter of 2010 included the settlement payment of $295 million (pre-tax) due to Suncor related to the Terra Nova redetermination. Net earnings from continuing operations in the fourth quarter of 2010 also included increased production from continuing operations and higher price realizations.

Overall, production from continuing operations was higher in the fourth quarter of 2010, compared to the fourth quarter of 2009, primarily due to Syrian gas production coming on-stream in the second quarter of 2010.

Refining and Marketing

Refining and Marketing had net earnings of $372 million in the fourth quarter of 2010, compared to $151 million in the fourth quarter of 2009, primarily due to higher margins in the fourth quarter of 2010. Increased production enabled refining and product supply activities to benefit from an improved business environment, with higher cracking margins in every major market area and stronger product demand compared to the fourth quarter of 2009. The Sarnia refinery was negatively impacted from the lingering effects of the Enbridge crude pipeline disruptions that restricted deliveries of lower cost sour crudes received from Western Canada and necessitated processing of more expensive offshore crude. The Edmonton refinery benefited from lower feedstock costs due to wider light/heavy and light/sour synthetic crude differentials.

Total sales of refined petroleum products increased 10% due to stronger operations and improved product demand as the economy recovered in the fourth quarter of 2010, compared to the fourth quarter of 2009. Overall, refinery utilization averaged 94% in the fourth quarter of 2010, compared to 90% in the fourth quarter of 2009, due largely to fewer scheduled maintenance turnarounds. The reductions to the Sarnia refinery production were partially offset by increasing throughputs at the Montreal refinery to support Ontario market demands.

Marketing network sales volumes in the fourth quarter of 2010 were marginally higher than in the fourth quarter of 2009. Strong sales in both the retail and wholesale divisions were partially offset by the loss of volume associated with the divestment of merger remedy sites.

Corporate, Energy Trading and Eliminations

Net earnings for the Corporate, Energy Trading and Eliminations were $51 million in the fourth quarter of 2010, compared to a net loss of $86 million in the fourth quarter of 2009. The increase in net earnings was due primarily to a higher unrealized foreign exchange gain on U.S. dollar denominated long-term debt.

28 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

CAPITAL INVESTMENT UPDATE

Suncor spent $5.7 billion on capital and exploration in 2010, which was marginally higher than Suncor's original 2010 budget of $5.5 billion. The capital expenditures were primarily focused on sustaining safe and reliable existing operations throughout the company, and the continued development of the Firebag Stage 3 and 4 expansions.

Year ended December 31	2010		2009

Oil Sands	3 709		2 831
Natural Gas	178		320
International and Offshore	1 096		666
Refining and Marketing	667		380
Corporate, Energy Trading and Renewable Energy	360		70
Less: Capitalized Interest	(301	)	(136	)

Total	5 709		4 131

This capital investment update contains forward-looking information. See the Legal Advisory – Forward-Looking Information section of this MD&A for the material risks and assumptions underlying this forward-looking information.

Oil Sands

Oil Sands capital expenditures were $3.709 billion in 2010. Growth spending in 2010 was primarily focused on the construction of Firebag Stage 3.

The company is continuing with its planned in situ growth initiatives:

•: Firebag Stage 3 – The planned expansion is targeted to begin production late in the second quarter of 2011, ramping up toward capacity of 62,500 bpd of bitumen over approximately 24 months thereafter. The 2010 expenditures focused primarily on construction of cogeneration and central plant facilities and well pads.
•: Firebag Stage 4 – This project was put into safe mode in early 2009, then restarted in late 2010. The planned expansion is targeted to begin production late in the first quarter of 2013, ramping up toward capacity of 62,500 bpd of bitumen over approximately 24 months thereafter. The 2010 expenditures focused primarily on remobilization of workforce.

As of December 31, 2010, cumulative capital expenditures for the Firebag Stages 3 and 4 expansions were $4.3 billion.

Capital expenditures on Suncor's TRO_TM tailings reclamation technology related to its implementation across existing operations. Project activities during 2010 included engineering, procurement of certain long-lead items, site preparation and construction of temporary facilities. The project is scheduled to be completed by the end of 2012 at a cumulative capital cost in excess of $1.0 billion.

The MNU project was also taken out of safe mode and restarted in 2010. As of December 31, 2010, cumulative capital expenditures were $763 million. Project activities during 2010 consisted primarily of the remobilization of the construction workforce to complete the remaining scope of work. The project is scheduled to be completed by the end of 2011 and will provide additional hydrogen and hydrotreating capacity to increase the percentage mix of sweet synthetic crude oil production.

With the growth plans announced in December 2010 involving the strategic partnership with Total, the company plans to restart the Voyageur Upgrader in 2011 and plans to begin the Fort Hills mine development.

•: Voyageur Upgrader – The focus in 2011 is anticipated to be the remobilization of the workforce, the confirmation of the current design and the modification of the project execution plans.
•: Fort Hills – The focus in 2011 is anticipated to be design base memorandum engineering.

In 2010, Suncor also focused on a number of sustaining capital projects required to maintain the mining, upgrading, extraction and in situ assets operating effectively. Major planned maintenance and turnarounds were completed on Upgrader 2 in the spring and fall.

Natural Gas

Natural Gas is focused on improving profitability by investing in low risk drilling programs conducive to low cost repeatable drilling and those with a high percentage of liquids production. In 2010, Natural Gas spent $178 million on exploration and development activities, of which $8 million was related to assets disposed of during the year. In 2010, spending was focused primarily on unconventional gas opportunities, as well as land acquisitions in northeast British Columbia.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 29

Suncor's key shallow gas producing properties near Medicine Hat, in southeastern Alberta, continued with drilling and tie-in activity. In total, 324 wells were drilled in 2010, with overall production from this area averaging 72 mmcfe/d during the year.

Two significant drilling programs began in the fourth quarter of 2010: one in the Ferrier area located in central Alberta and another at Pouce Coupe in western Alberta. Tie-in activities for both programs started in the first quarter of 2011.

International and Offshore

International and Offshore spent $264 million on capital and exploration in 2010 related primarily to the White Rose and Hibernia areas of East Coast Canada operations.

•: At North Amethyst, first oil was achieved May 31, 2010. Facility construction was completed during the year and the remainder of the project is focused on development drilling of 11 wells in total and is planned to continue until 2013. Data provided by a delineation well will be used to optimize future well placement.
•: Development drilling for the first phase of the West White Rose portion of the White Rose Extensions began in August 2010, with first oil expected by mid-2011. Drilling results from the first phase, combined with production evaluation and ongoing reservoir evaluation, are expected to define the full field development scope.
•: Capital spending continues on the Hibernia South Extension project, where early production from the unit is expected in mid-2011.
•: The contract for front-end engineering and design and topsides engineering, procurement and construction for Hebron was awarded in September 2010. The development plan approval submission is expected to be made in the second quarter of 2011 with first oil expected in 2017.

International and Offshore expenditures on capital and exploration in 2010 related to its other operations were $832 million, of which $169 million was related to assets disposed of during the year. Spending has been primarily focused on exploration drilling in Libya, development spending in the U.K. and Syria, and exploration drilling in Norway.

•: Seismic survey projects continue to acquire data in relation to the Libya EPSAs. Two exploration wells, four appraisal wells and 26 development wells were completed in the year with seismic data acquisition continuing into the first quarter of 2011.
•: The Buzzard enhancement project, which included the shutdown and the tie-in of a fourth platform, was completed and staged commissioning began on the sulphur handling platform in October 2010. Production disruptions during ramp-up have been less than anticipated to date. Commissioning of the new platform will continue into the first quarter of 2011.
•: In Syria, facility development was completed to support first commercial gas and condensate production, which was achieved in April 2010, and first liquefied petroleum gas, which was achieved in May 2010 from the Ebla gas project. First oil was achieved in December 2010.
•: Following the Beta Brent discovery offshore Norway completed earlier in 2010, the Beta Statfjord appraisal well was successfully tested. Additional appraisal well testing is required to delineate the discovery further.

Refining and Marketing

Refining and Marketing spent $667 million on capital in 2010, primarily focused on planned turnarounds and rebranding former Sunoco retail sites to the Petro-Canada brand.

Major maintenance turnaround work was completed in 2010 at three of the four refineries and the lubricants production facility to support continued safe and reliable operations.

Corporate, Energy Trading and Eliminations

Corporate capital expenditures were $360 million in 2010, with a focus on merger integration related activities and renewable energy. Work continues to integrate legacy Suncor and legacy Petro-Canada systems onto one common platform, where appropriate, as well as integrate processes, information and technology.

Construction on the Wintering Hills wind power project, which began in the second half of 2010, is expected to be completed by the end of 2011. At peak operation, the project is expected to generate enough electricity to power approximately 35,000 Alberta homes and displace 200,000 tonnes of carbon dioxide (CO₂) per year.

Construction on the Kent Breeze wind power project, which commenced in the second half of 2010, is expected to be completed by mid-2011.

Suncor's ethanol plant, located in Sarnia, Ontario, has a current capacity of 400 million litres per year, after a plant expansion was completed in January 2011 that doubled the capacity of the ethanol plant. The plant displaces the equivalent of 300,000 tonnes of CO₂ per year.

30 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

LIQUIDITY AND CAPITAL RESOURCES

At December 31 ($ millions, except ratios)	2010	2009

Working capital (deficit) ⁽¹⁾	1 257	(324	)

Short-term debt	2	2
Current portion of long-term debt	518	25
Long-term debt	11 669	13 855

Total debt	12 189	13 882
Less: Cash and cash equivalents	1 077	505

Net debt	11 112	13 377

Shareholders' equity	36 721	34 111

Total capitalization (total debt and shareholders' equity)	48 910	47 993

Total debt to debt plus shareholders' equity (%) ⁽²⁾	25	29

Year ended December 31		2010	2009

ROCE (%) – excludes capitalized costs related to major projects ⁽³⁾		10.1	2.6
ROCE (%) – includes capitalized costs related to major projects ⁽³⁾		7.4	1.8

Net debt to cash flow from operations (times) ⁽⁴⁾		1.7	4.8

Interest coverage on long-term debt (times)
	Net earnings ⁽⁵⁾	8.4	3.0
	Cash flow from operations ^(3),(6)	11.9	7.2

(1): Calculated as current assets less current liabilities, excluding cash and cash equivalents, short-term debt, current portion of long-term debt and future income taxes. Current assets and liabilities of discontinued operations are excluded.
(2): Short-term debt plus long-term debt divided by the sum of short-term debt, long-term debt and shareholders' equity.
(3): Non-GAAP measure. See the Non-GAAP Financial Measures Advisory section of this MD&A.
(4): Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations.
(5): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
(6): 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 and available lines of credit. Suncor's management believes the company will have the capital resources to fund its planned 2011 capital spending program and to meet current and long-term working capital requirements through cash flow from operations, proceeds from the agreement with Total, other planned asset divestitures and its available committed credit facilities. The expected proceeds from the agreement with Total are approximately $1.75 billion, subject to closing adjustments. The company's cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, 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 the debt capital markets at commercial terms and rates.

Financing Activities

Management of debt levels continues to be a priority 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, 2010, Suncor's net debt was $11.1 billion, compared to $13.4 billion at December 31, 2009. Net debt decreased by $2.3 billion largely due to proceeds from asset dispositions being directed to debt retirement and the appreciation of the Canadian dollar relative to the U.S. dollar through the period. Unutilized lines of credit at December 31, 2010 were approximately $5.3 billion, compared to $4.2 billion at December 31, 2009.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 31

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

($ millions)	2010

Facility that has a term period of one year and expires in 2011	4
Facility that is fully revolving for a period of four years and expires in 2013	199
Facilities that are fully revolving for a period of five years and expire in 2013	7 320
Facilities that can be terminated at any time at the option of the lenders	461

Total available credit facilities	7 984

Credit facilities supporting outstanding commercial paper, bankers' acceptances and LIBOR loans	(1 982	)
Credit facilities supporting standby letters of credit	(713	)

Total unutilized credit facilities	5 289

Interest expense on debt continues to be influenced by the composition of the debt portfolio, and is currently benefiting from short-term floating interest rates that remain at low levels, compared to historical short-term rates. To manage fixed versus floating rate exposure, we have entered into fixed to floating interest rate swaps with investment grade counterparties. At December 31, 2010, the company had interest rate swaps relating to $200 million of its fixed-rate debt, due in August 2011.

Suncor has an operating working capital of $1.257 billion at December 31, 2010, compared to a deficiency of $324 million at December 31, 2009. The working capital change from a deficit to a surplus during 2010 was primarily a result of increased accounts receivable balances, resulting from higher volumes and prices and the recording of the Terra Nova redetermination receivable, partially offset by an increase in accounts payable as a result of higher royalties payable from increased production.

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 be more than 60% of its total capitalization. At December 31, 2010, total debt to total capitalization was 25% (December 31, 2009 – 29%). 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 company's credit ratings have changed. In particular, the company's ability to access unsecured funding markets and to engage in certain collateralized business activities on a cost-effective basis is primarily dependent upon maintaining competitive credit ratings. A lowering of the company's credit rating may also have potentially adverse consequences for the company's funding capacity or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or hedging transactions, and may require the company to post additional collateral under certain contracts.

All of the company's debt ratings are investment grade. The company's current long-term senior debt ratings are BBB+, with a Stable Outlook from Standard & Poor's (S&P); A(low), with a Stable Trend from Dominion Bond Rating Service (DBRS); and Baa2, with a Stable Outlook from Moody's Investors Service. Suncor's current commercial paper ratings are A-1 (Low) from S&P and R-1 (low) from DBRS. These have not changed from December 31, 2009.

Outstanding Shares

At December 31, 2010 (thousands)

Common shares		1 565 489
Common share options – exercisable and non-exercisable		67 638
Common share options – exercisable		46 266

As at February 24, 2011, the total number of common shares outstanding was 1,570,039,616 and the total number of exercisable and non-exercisable common share options outstanding was 67,838,293.

32 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Aggregate Contractual Obligations

In the normal course of business, the company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.

	Payments Due by Period
($ millions)	Total	2011	2012-2013	2014-2015	Later Years

Fixed-term debt and revolving-term debt ⁽¹⁾	11 903	2 482	311	406	8 704
Interest payments on fixed-term debt	11 015	609	1 175	1 131	8 100
Capital lease payments	718	36	74	74	534
Asset retirement obligations ⁽²⁾	7 434	127	330	244	6 733
Operating lease agreements, pipeline capacity and energy services commitments ⁽³⁾	13 256	1 089	1 870	1 623	8 674
Exploration work commitments	425	137	288	—	—
Other long-term obligations ⁽⁴⁾	649	239	359	51	—

Total	45 400	4 719	4 407	3 529	32 745

(1): Includes $8.108 billion of U.S. and $1.800 billion of Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2011 to 2039. Interest rates vary from 4.00% to 9.25%. We entered into interest rate swap transactions maturing in 2011 that resulted in an average effective interest rate in 2010 of 1.9% on $200 million of our Medium Term Notes. Approximately $1.982 billion of revolving-term debt with an effective interest rate of 1.2% was issued and outstanding at December 31, 2010.
(2): Represents the undiscounted amount of legal obligations associated with site restoration on the retirement of assets with determinable lives.
(3): Includes annual tolls payable under transportation service agreements with major pipeline companies to use a portion of their pipeline capacity and tankage, as applicable, for transportation of product within Canada and the United States. The figure also includes commitments under long-term energy agreements to obtain a portion of the power and the steam generated by certain cogeneration facilities owned by a major third-party energy company.
(4): Includes Libya EPSA signature bonus and Fort Hills purchase obligations. See note 18 to the Consolidated Financial Statements.

In addition to the enforceable and legally binding obligations quantified in the above table, we have other obligations for goods and services and raw materials entered into in the normal course of business, which may terminate on short notice, including commodity purchase obligations for which an active, highly liquid market exists, and which are expected to be re-sold shortly after purchase.

FINANCIAL INSTRUMENTS

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to manage exposure to fluctuations in commodity prices and foreign exchange rates and to optimize the company's position with respect to interest expense. The company also uses physical and financial energy derivatives to earn trading revenues.

To estimate fair value of financial instruments, the company uses quoted market prices when available, or models that utilize observable market data. In addition to market information, Suncor incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. Inputs used are characterized in determining fair value 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.

Hedge Accounting for Fair Value Hedges

At December 31, 2010, the company had interest rate swaps classified as fair value hedges outstanding until August 2011, relating to $200 million of its fixed-rate debt. The fair value of these swaps was $8 million at December 31, 2010 (December 31, 2009 – $18 million), and was recorded in accounts receivable in the Consolidated Balance Sheets.

Risk Management Activities

Suncor uses 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 risk management derivatives are recorded in the Consolidated Statements of Earnings in the same caption as the related transaction. The earnings impact associated with our risk management derivatives for the year ended December 31, 2010 was a net pre-tax gain of $89 million (2009 – pre-tax loss of $1.024 billion). There are no significant risk management derivative contracts outstanding at December 31, 2010.

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Energy Trading Activities

Suncor uses crude oil, natural gas and refined product derivative contracts to earn supply and trading revenues. The results of these supply and trading activities are reported as energy supply and trading activities revenues and expenses in the Consolidated Statements of Earnings. The net pre-tax gain associated with our energy trading activities in 2010 was $81 million (2009 – pre-tax loss of $70 million).

The change in fair value of derivatives pertaining to risk management and energy trading activities are as follows:

($ millions)	2010

Fair value of contracts at December 31, 2009	(359	)
Fair value of contracts realized during the period	115
Change in fair value during the period	170

Fair value of derivative contracts outstanding at December 31, 2010	(74	)

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

($ millions)	2010		2009

Accounts receivable	19		213
Accounts payable and accrued liabilities	(93	)	(572	)

	(74	)	(359	)

Risks Associated with Derivative Financial Instruments

Suncor's price risk management strategies are subject to periodic management reviews to determine appropriate hedge 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.

Suncor may be exposed to certain losses in the event that the counterparties to derivative financial instruments are unable to meet the terms of the 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 the reporting date.

Energy supply and trading activities are governed by a separate risk management group which reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including a sensitivity analysis of the effect of changes in commodity prices on our derivative financial instrument contracts and additional discussion of exposure to risks and our mitigation activities, see note 21 to the 2010 audited Consolidated Financial Statements.

RISK FACTORS

We are continually working to mitigate the impact of potential risks to our business. This process includes an entity-wide risk review. The internal review is completed annually to help ensure that all significant risks are identified and appropriately managed. The following provides a list of some of the risk factors relating to Suncor and our business. A detailed discussion of additional risk factors related to Suncor and our business is presented in our most recent Annual Information Form (AIF)/Form 40-F, filed with securities regulatory authorities.

Volatility of Commodity Prices and Exchange Rate Fluctuations

Our future financial performance is closely linked to crude oil prices and, to a lesser extent, natural gas prices. The prices of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of the Petroleum Exporting Companies, and weather, among other things, can affect world oil supply and demand. Our natural gas price realizations in our Natural Gas segment are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond our control and can result in a high degree of price volatility, not only in crude oil and natural gas prices but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for sour crude oil and bitumen. Oil and natural gas prices have

34 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

fluctuated widely in recent years. Given the continued global economic uncertainty, we expect continued volatility and uncertainty in crude oil and natural gas prices in the near term and beyond, with the possibility that crude oil prices could revert to the low levels experienced in 2008 and 2009. A prolonged period of low crude oil and natural gas prices could affect the value of our crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production on some properties. Accordingly, low natural gas prices and low crude oil prices in particular could have a material adverse effect on our business, financial condition, results of operations and cash flow.

For the year ended December 31, 2010, we conducted an assessment of the carrying value of our assets to the extent required by Canadian GAAP. If crude oil and natural gas prices decline, the carrying value of our assets could be subject to downward revisions, and our earnings could be materially adversely affected.

Our downstream business is sensitive to wholesale and retail margins for its refined products, including, but not limited to, gasoline, diesel, petrochemicals and asphalt. Margin volatility is influenced by, among other things, overall marketplace competitiveness, weather, the cost of crude oil, and fluctuations in supply and demand for refined products. We expect that margin and price volatility and overall marketplace competitiveness, including the potential for new market entrants, will continue. As a result, the operating results for our Refining and Marketing business unit can be expected to fluctuate and may be materially adversely affected.

Our 2010 Consolidated Financial Statements are presented in Canadian dollars. Results of operations are affected significantly by the exchange rates between the Canadian dollar and the U.S. dollar, and are also affected by the exchange rates between the Canadian dollar, the euro and the British pound. These exchange rates may vary substantially and may give rise to foreign currency exposure, either favourable or unfavourable, creating another element of uncertainty. To the extent such fluctuation is unfavourable, it may have a material adverse effect on our business, financial condition, results of operation and cash flow.

Government Regulation

The company, and the oil and gas industry generally, operates under federal, provincial, state and municipal legislation in numerous countries. This industry is also subject to regulation and intervention by governments in such matters as land tenure, royalties, taxes (including income taxes), government fees, production rates, environmental protection controls, the reduction of greenhouse gas (GHG) and other emissions, the export of crude oil, natural gas and other products, the awarding or acquisition of exploration and production, oil sands 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. The following subsections provide more information on some of these regulations.

Environmental Regulation

The company is subject to environmental regulation under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. 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;
•: Issues relating to land reclamation, restoration and wildlife habitat protection;
•: Reformulated gasoline to support lower vehicle emissions; and
•: U.S. implementation of regulation or policy to limit its purchases of oil to oil produced from conventional sources, or
•: U.S. state or federal calculation and regulation of fuel life cycle carbon content.

Changes in environmental regulation could have a material adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production, distribution costs and financial results. For example, requirements for cleaner burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. 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. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for cleanup costs and damages, and the loss of important licences and permits,

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which may, in turn, have a material adverse effect on our business, financial condition, results of operations and cash flow.

Climate Change

While there is a well-defined GHG regulatory system with targets in place for all large industrial facilities in the province of Alberta, no other North American jurisdiction has yet enacted similar strict compliance measures. Suncor anticipates that this current situation will be replaced within the next few years by a series of regional regulatory regimes, or with an all-encompassing federal regime. In general, therefore, there remains uncertainty around the outcome and impacts of climate change and environmental laws and regulations (whether currently in force, or proposed laws and regulations as described herein or future laws and regulations); it is not currently possible to predict either the nature of any requirements or the impact on the company and its business, financial condition, results of operations and cash flow at this time.

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 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.

British Columbia has drafted regulations for a cap-and-trade system, as well as offset regulations, which are intended to be finalized later in 2011. The impact of these regulations cannot be quantified at this time, given the current lack of detail on how the system will operate.

While forthcoming laws and regulations may impose significant liabilities on a failure to comply with their requirements, the cost of meeting new environmental and climate change regulations is not expected to be so high as to cause a material disadvantage, or damage to our competitive positioning.

As part of our ongoing business planning, Suncor assesses potential costs associated with carbon dioxide (CO₂) emissions in our evaluation of future projects, based on our current understanding of pending and possible greenhouse gas 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. 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 as a base case price range of $15-$45 per tonne of CO₂ equivalent, applied against a range of regulatory policy options and price sensitivities.

California has passed AB32, which provides for a Low Carbon Fuel Standard (LCFS); although Suncor does not actively market into the state of California, the implications of other states adopting similar LCFS legislation could pose a significant barrier to our exports of oil sands derived crude, if the importing jurisdictions fail to acknowledge the mandated 12% reduction requirement imposed by the company's exporting jurisdiction (Alberta).

While it appears fairly certain that GHG regulations and targets will continue to become more stringent, and while Suncor will continue efforts to reduce the 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.

Reclamation

There are risks associated with our ability to complete reclamation work, specifically reclaiming tailings ponds, which contain water, clay and residual bitumen produced through the extraction process. In February 2009, the Energy Resources Conservation Board (ERCB) of the Government of Alberta released a directive, Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for tailings operations, a requirement for specific approval and monitoring of tailings ponds, a requirement for reporting tailings plans, and changes to the ERCB annual mine plan requirements and approval process to regulate tailings operations.

On October 15, 2009, the company applied to the ERCB and Alberta Environment for permission to amend its existing and/or approved operations east of the Athabasca River to move to the company's new planned TRO_TM strategy. In 2010, the company received regulatory approval for a new tailings management plan using the company's proprietary TRO_TM tailing management process. It is anticipated that TRO_TM will allow the company to accelerate the pace of reclamation and reduce costs in the long term.

At this time, no ponds have been fully reclaimed using this technology. The success of the TRO_TM and the time to reclaim tailings ponds could increase or decrease the current asset retirement cost estimates. Our failure to adequately implement our reclamation plans could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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Royalties

The following risk factors could cause royalty expenses to differ materially from current estimates and impact the royalties payable.

Alberta

The Alberta government enacted new Bitumen Valuation Methodology (BVM) (Ministerial) Regulations as part of the implementation of the New Royalty Framework, effective January 1, 2009. These interim regulations determine the valuation of bitumen for 2009 to 2011. The final regulations are being developed by the Crown that will establish the BVM for future years. For Suncor's mining operations, the BVM is based on the terms of Suncor's RAA, which we believe places certain limitations on the interim BVM as recently enacted. For the years 2009 and 2010, Suncor filed non-compliance notices with the Crown, citing that reasonable adjustments in the determination of the Suncor bitumen value were not considered by the Crown as permitted by Suncor's RAA. Suncor has also filed with the Crown a Notice of Commencement of Arbitration under the Suncor RAA. Syncrude has also filed a non-compliance notice in respect of the determination of the bitumen value under its agreements with the Crown. The final determination of these matters may have a material impact on future royalties payable to the Crown.

The government enacted the new Oil Sands Allowed Costs (Ministerial) Regulations as part of the implementation of the New Royalty Framework, effective January 1, 2009. Further clarification of some allowed cost business rules is still expected. The terms of Suncor's RAA, and the similar agreement entered into by Syncrude, determine the royalty obligation through 2015 for our mining operations. However, potential changes and the interpretation of the allowed cost regulations could, over time, have a significant impact on the amount of royalties payable.

In addition, royalty payments to the Crown could be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project, changes to the New Royalty Framework by the Government of Alberta, changes in other legislation, and the occurrence of unexpected events.

East Coast Canada Royalties

Suncor and the Government of Newfoundland and Labrador are in discussions to resolve several outstanding issues that impact current and prior years. Settlement of these issues could impact royalty payments to the Crown. In addition, royalty payments to the Crown could be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each project, changes resulting from regulatory audits of prior year filings, further changes to applicable royalty regimes by the Government of Newfoundland and Labrador, changes in other legislation, and the occurrence of unexpected events.

Production Sharing Contracts

Payments pursuant to PSCs could be impacted by changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs; changes resulting from regulatory audits of prior year filings, further changes to applicable royalty regimes by governments or other applicable regulatory bodies, changes in other legislation, and the occurrence of unexpected events, all which have the potential to have an impact on royalties payable in respect of our international operations in Libya and Syria.

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, 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, renegotiation of contracts with governmental entities and quasi-governmental agencies, changes in laws and policies governing operations of foreign-based companies, economic and legal sanctions (such as restrictions against countries that the U.S. government may deem to sponsor terrorism) and other uncertainties arising from foreign government sovereignty over the company's international operations. 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. Additionally, 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.

Operating Hazards and Other Uncertainties

Each of our principal operating businesses – Oil Sands, Natural Gas, International and Offshore, and Refining and Marketing – demand significant levels of investment and therefore carry economic risks and opportunities. Generally, our operations are subject to hazards and risks

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such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts, power outages and oil spills, any of which can cause personal injury, death, damage to property, information technology systems and related data and control systems, equipment, and the environment, as well as interrupt operations.

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 in our crude oil and natural gas business. Risks associated with access to skilled labour to support our operations in a safe and effective manner are also discussed in "Labour and Materials Supply" below.

At Oil Sands, mining oil sands and producing bitumen through in situ methods, extracting bitumen from the oil sands, and upgrading bitumen into synthetic crude oil 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. Severe climatic conditions at Oil Sands can cause reduced production during the winter season and, in some situations, can result in higher costs. While there are virtually no finding costs associated with oil sands resources, the costs to delineate the resources, the costs associated with production, including mine development and drilling wells for in situ operations, and the costs associated with upgrading bitumen into synthetic crude oil can entail significant capital outlays. The costs associated with oil sands production are largely fixed in the short term. As a result, operating costs per unit are largely dependent on levels of production.

There are risks and uncertainties associated with our Natural Gas operations, including all of the risks normally associated with drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, fires, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks.

Our International and Offshore 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 or other extreme weather conditions, and the 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 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. Damage to the environment, particularly through oil spillage in our operations or extensive uncontrolled fires or death, could result from these operations.

Our Refining and Marketing business is subject to all of the risks normally inherent in the operation of a refinery, terminals, pipelines and other distribution facilities as well as service stations, including loss of product, slowdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock, oil spills or other incidents.

We are also subject to operational risks such as sabotage, terrorism, trespass, related damage to remote facilities, theft and malicious software or network attacks.

Losses resulting from the occurrence of any of these risks identified above could have a material adverse effect on our 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. Losses beyond the scope of insurance could have a material adverse effect on our business, financial condition, results of operations and cash flow. In 1990, 2003 and 2005, we formed three self-insurance entities to provide additional business interruption coverage for potential losses. In the first quarter of 2010, these three entities were merged into one single entity.

Project Delivery

There are certain risks associated with the execution of our major projects. These risks include: our ability to obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; 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. The commissioning and integration of new facilities within our existing asset base could cause delays in achieving targets and objectives. Management believes the execution of major projects presents issues that require prudent risk management. There are also risks associated with project cost estimates provided by us. Some cost estimates are provided at the conceptual stage of projects and prior to commencement or completion of the final scope design and detailed

38 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

engineering needed to reduce the margin of error. Accordingly, actual costs can vary from estimates, and these differences can be material. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Our Oil Sands business is susceptible to loss of production 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, we added a second upgrader, which provides us with the flexibility to conduct periodic plant maintenance on one operation while continuing production and cash flow generation from the other. Our inability to sufficiently manage these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Reputational Risk

The public perception of oil companies and their operations, including GHG emissions related to current and planned projects in the oil sands area of Alberta, may pose issues related to development and operating approvals or market access for products, which may directly or indirectly impair profitability.

Permit Approval

Before proceeding with most major projects, including significant changes to existing operations, we must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions, including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis 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 our business, financial condition, results of operations and cash flow. Such regulations may be changed from time-to-time in response to numerous factors, including economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase our costs and have a material adverse effect on our business, financial condition, results of operations and cash flow.

Labour and Materials Supply

The successful operation of the company's business and ability to expand its operations will depend upon the availability of, and competition for, skilled labour and materials supply. The demand for and supply of skilled labour remains limited, even in uncertain economic conditions, and there is a risk that we may have difficulty sourcing the required labour for current and future operations. As well, materials may 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. Risks associated with completion of significant capital projects are discussed in "Project Delivery" above.

Suncor's Governance Process

Suncor believes that the responsibility for managing climate change related issues should be a shared responsibility across the company. A comprehensive "roles and responsibilities" matrix has been developed as part of Suncor's GHG management program.

The Environment, Health, Safety and Sustainable Development Committee of the Board of Directors reviews Suncor's effectiveness in meeting its obligations pertaining to environment, health and safety (EHS). The committee also reviews the effectiveness with which Suncor establishes appropriate environment, health and safety policies, including GHG performance and emission reduction plans given legal, industry and community standards. Management systems are maintained by the committee to implement such policies and ensure compliance with them.

Suncor's Chief Operating Officer holds top executive responsibility for sustainability issues. Together with the Vice President, Sustainable Development, the business units' EHS Managers and selected internal technical representatives are responsible for the stewardship of the GHG management system. The GHG strategy team is responsible for developing company-wide strategies and operational goals and assessing sustainability progress, including GHG intensity reduction, across all areas of our business.

In advance of clear regulations in all jurisdictions that we operate, Suncor will continue to be guided by the seven-point climate change action plan we first adopted in 1997, which calls on us to:

•: Manage our own GHG emissions;
•: Develop renewable sources of energy;

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•: Invest in environmental and economic research through joint venture initiatives with other industry groups, and through internal initiatives focused on our core business;
•: Use domestic and international offsets;
•: Collaborate on policy development;
•: Educate employees and the public; and
•: Measure and report our progress;

Suncor remains committed to reducing overall greenhouse gas emission intensity, in addition to other goals related to improving energy efficiency, reducing water use, increasing land reclamation, and reducing air emissions. We continue to actively work to mitigate our environmental impact, including taking action to reduce greenhouse gas emissions, investing in renewable forms of energy such as wind power and biofuels, accelerating land reclamation, installing new emission abatement equipment and pursuing other opportunities both internally, as well as through joint venture initiatives, such as our role in the Oil Sands Leadership Initiative, with other like-minded energy companies.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates, judgments and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. These estimates and assumptions are subject to change based on experience and new information. Critical accounting estimates are defined as estimates that are important to the portrayal of our financial position and operations, and require management to make judgments based on underlying assumptions about future events and their effects. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as our operating environment changes. 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 Consolidated Financial Statements.

Asset Retirement Obligations (ARO)

Suncor is required to recognize a liability for the future retirement obligations associated with the legal requirement to retire tangible long-lived assets such as tailings ponds, producing well sites, and crude oil and natural gas processing plants. An ARO liability is only recognized to the extent there is a legal obligation associated with the retirement of a tangible long-lived asset that we are 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. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying Suncor's total ARO amount. These individual assumptions can be subject to change based on experience.

The estimated fair values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred. Retirement costs equal to the estimated fair value of the ARO are capitalized as part of the cost of associated capital assets and are amortized to expense through DD&A over the life of the asset. The fair value of the ARO is estimated by discounting the expected future cash flows to settle the ARO at the company's weighted average credit-adjusted risk-free interest rate, which is currently 5.4% (2009 – 6.2%). In subsequent periods, the ARO is adjusted for the passage of time, adjusted to estimated costs to settle the liability, and changes to the timing of the underlying future cash flows. These changes to estimates impact both the DD&A on the retirement cost and the accretion expense on the ARO reported in the Consolidated Statements of Earnings. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to settle the obligation and future inflation rates may result in gains and losses on the final settlement of the ARO.

An ARO is not recognized for assets with an indeterminate useful life because the amount cannot be reasonably estimated. An ARO for these assets will be recorded in the first period in which the lives of the assets are determinable.

In connection with company and third-party reviews of ARO during 2010, Suncor decreased the estimated undiscounted total obligation to $7.4 billion from the previous estimate of $8.3 billion. The decrease was primarily due to significant disposals in the International and Offshore segment and the Natural Gas segment, where the ARO obligation was assumed by the purchasing entity. In addition, the Oil Sands segment decreased its obligation mainly due to the 2010 ARO obligation being calculated using the company's proprietary TRO_TM tailings management process, compared to a combination of methods in 2009. The company anticipates that TRO_TM will allow the company to accelerate the pace of reclamation and reduce costs in the long term. The estimated discounted total obligation at December 31, 2010, was

40 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

$2.4 billion, compared to $3.2 billion at December 31, 2009.

Employee Future Benefits

Suncor provides a range of benefits to employees and retired employees, including pensions and other post-retirement benefits. The determination of obligations under these benefit plans and related expenses requires the use of 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, return on plan assets, mortality rates and future medical costs. The fair value of plan assets is determined using market values. Actuarial valuations are subject to management judgment. Management continually reviews these assumptions in light of considering actual experience and expectations for the future. Changes in assumptions are accounted for on a prospective basis. Employee future benefit costs are reported as part of operating, selling and general expenses in our Consolidated Statements of Earnings. The accrued net benefit liability is reported as part of accrued liabilities and other.

The assumed rate of return on plan assets considers the current level of expected returns on the fixed income portion of the plan's asset portfolio, the historical level of risk premium associated with other asset classes in the portfolio and the expected future returns on each asset class. The discount rate assumption is based on the year-end interest rate on high-quality bonds with maturity terms equivalent to the benefit obligations. The rate of compensation increases is based on management's judgment. The accrued benefit obligation and net periodic benefit cost for both pensions and other post-retirement benefits may differ significantly if different assumptions are used.

Successful Efforts Accounting

Suncor follows the successful efforts method for exploration and production development activities related to conventional oil and gas producing properties.

The application of the successful efforts method of accounting requires management apply judgment to determine, among other things, the designation of activities as developmental or exploratory. All development costs are capitalized. Costs of drilling exploratory wells are initially capitalized, pending the evaluation of commercially recoverable reserves. The results of an exploratory drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Where it is determined that exploratory drilling will not result in commercial production, the drilling costs of the exploratory well are charged to exploration expense.

Asset Impairment

Producing properties and significant unproved properties are assessed annually, or as economic events dictate, for potential impairment. Impairment is assessed by comparing the estimated net undiscounted future cash flows with the carrying value of the asset. The cash flows used in the impairment assessment require management to make assumptions and estimates about recoverable reserves, production quantities, future commodity prices, operating costs and future development costs. Changes in any of the assumptions, such as a downward revision in reserves, a decrease in future commodity prices or an increase in operating costs, could result in an impairment of an asset's carrying value. Where properties are assessed by management to be fully or partially impaired, the book value of the properties is reduced to fair value, with the difference reported as part of DD&A expense.

Assets held for sale are also required to undergo an impairment test and are valued at the lower of carrying value and net recoverable value, which often equates to discounted cash flow estimates, or expected sale proceeds when an offer has been received.

Oil and Gas Reserves

Our oil and gas reserves are evaluated by independent qualified reserves evaluators. The estimation of reserves is a subjective process. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty and interpretation. Reserves estimates can be revised either upwards or downwards based on updated information such as future drilling, testing and production levels. Reserves estimates, although not reported as part of the company's Consolidated Financial Statements, can have a significant effect on net earnings as a result of their impact on depreciation and depletion rates, asset impairments and goodwill impairments.

For December 31, 2010, reserves estimates for our Syria assets were reduced to reflect only those parts of the Ash Shaer field with existing well control, and to reflect interpreted higher porosity cut-offs in a significant secondary zone.

Income Taxes

The company follows the liability method of accounting for income taxes, whereby future income taxes are recognized based on the differences between the carrying

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 41

amounts of assets and liabilities reported in the financial statements and their respective tax bases. The determination of the income tax provision is an inherently complex process, requiring management to interpret continually changing regulations and to make certain judgments. While income tax filings are subject to audits and reassessments, management believes adequate provision has been made for all income tax obligations. However, changes in the interpretations or judgments may result in an increase or decrease in the company's current and future income tax provisions, future income tax assets and liabilities, and net earnings.

Contingencies

The company is involved in litigation and claims in the normal course of operations. Management is of the opinion that any resulting settlements would not materially affect the financial position of the company as at December 31, 2010. However, the determination of contingent liabilities relating to litigation and claims is a complex process that involves judgments as to the outcomes and interpretation of laws and regulations. Changes in the judgments or interpretations may result in an increase or decrease in the company's contingent liabilities in the future.

Purchase Price Allocation

The 2009 merger with Petro-Canada was treated as a business acquisition and accounted for by the purchase method of accounting. Under this method, the purchase price was allocated to the assets acquired and the liabilities assumed based on the fair value at the time of the acquisition. The excess purchase price over the fair value of identifiable assets and liabilities acquired is goodwill. Management finalized the purchase price allocation during the second quarter of 2010 and did not make any amendments to the preliminary allocation.

CHANGES IN ACCOUNTING POLICIES

International Financial Reporting Standards (IFRS)

IFRS Conversion Project

The company's IFRS conversion project continues to be on target to release first quarter 2011 IFRS financial statements. The following is a status update of the IFRS conversion project.

IFRS Financial Statement Preparation

First quarter and annual 2011 IFRS financial statements and disclosures have been drafted and provided to senior management and the company's external auditor for review. The first quarter 2011 financial statements and disclosures will be presented to the IFRS Steering Committee and Audit Committee in the first quarter of 2011.

IFRS Training

IFRS training and communication sessions continued for key individuals, senior management and the Audit Committee.

IFRS Infrastructure

Significant IFRS information technology activities were completed during the fourth quarter, including recording of IFRS entries for the first three quarters of 2010 into the company's dual reporting system. Testing of the 2011 conversion plan was completed in 2010. Comprehensive training for implementation of business process changes will occur in the first quarter of 2011 with implementation targeted for the second quarter of 2011.

IFRS Control Environment

The company has completed testing of internal control documentation related to the preparation of the 2010 IFRS financial statements. Review of internal and disclosure controls over financial reporting for 2011 will be completed in the first quarter of 2011. No material changes are expected to the controls over financial reporting.

IFRS Expected Accounting Policy Impacts

In addition to the policy changes outlined below, the company continues to monitor IFRS developments. Accounting policies selected for the draft IFRS opening Consolidated Balance Sheets remain subject to change. The company is not required to finalize IFRS accounting policies prior to the release of the first annual audited IFRS financial statements for the year ending December 31, 2011.

The following discussion provides further details on the impacts of accounting policy choices and changes on the draft IFRS opening Consolidated Balance Sheets, including exemptions available under IFRS 1 First-Time Adoption of International Financial Reporting Standards. IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS.

•: Property, Plant and Equipment (PP&E)

Although the principles of componentization and derecognition exist under both IFRS and Canadian GAAP, the standards differ in certain respects. Under

42 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

IFRS, the basis that the company has used to apply these principles will be at a lower component level, resulting in a decrease to the January 1, 2010 PP&E balance of approximately $110 million.

Upon adoption of IFRS, Suncor will reclassify approximately $4.5 billion of Exploration and Evaluation (E&E) assets from PP&E to E&E. E&E assets include unproven land, exploratory drilling and exploratory project costs.

IFRS 1 contains an exemption where an entity may elect to use fair value as its deemed cost for assets at the date of transition. The company elected to use this exemption for certain Natural Gas and Refining and Marketing assets. As a result, approximately $900 million of asset value was derecognized and charged to retained earnings.

•: Provisions, Contingent Liabilities and Contingent Assets

The company is planning to utilize the IFRS 1 exemption permitting the recalculation of the ARO cost included in PP&E as at January 1, 2010, using a simplified retrospective calculation. The company has made a preliminary decision to discount the estimated fair value of its ARO using the credit-adjusted risk-free rate. However, the discount rate under IFRS at transition differs from the credit-adjusted risk-free rate utilized for Canadian GAAP. These differences have resulted in an increase of approximately $300 million to the ARO liability, a decrease of approximately $700 million to the related PP&E assets and a corresponding reduction to retained earnings at January 1, 2010. If the company elected to use a risk-free discount rate the adjustment to opening retained earnings would be significantly higher.

•: Share-Based Payments

IFRS 2 Share-based Payment requires that cash-settled share-based payments be measured (both initially and at each reporting period) at the fair values of the awards. Canadian GAAP requires that such awards be measured based on the intrinsic values of the awards. This difference has resulted in an increase to the company's share-based payments liability of approximately $120 million at January 1, 2010 with a corresponding reduction to retained earnings. In addition, a change to the graded vesting method for stock-based compensation has resulted in a $10 million increase in the contributed surplus balance at January 1, 2010. The company will elect to use the IFRS 1 exemption under which IFRS 2 is not required to be applied to equity-settled instruments.

•: Employee Future Benefits

The company has opted to elect to use the IFRS 1 exemption to recognize immediately in retained earnings all cumulative actuarial gains and losses existing at the date of transition (approximately $60 million). This impact will be partially offset by approximately $30 million for a change to the attribution method for post-retirement benefits and recognition of unamortized past service costs not fully vested.

•: Foreign Exchange

First-time adopters of IFRS can elect to deem cumulative translation differences to be zero at the date of transition. The company has elected to take this IFRS 1 exemption which has resulted in a reclassification of approximately $250 million from other reserves (previously termed "accumulated other comprehensive income") to retained earnings.

•: Income Taxes

In transitioning to IFRS, the company's future tax liability is impacted by the tax effects resulting from the IFRS changes discussed above. The company expects to recognize a decrease in the deferred tax liability of approximately $600 million at January 1, 2010.

•: Business Combinations and Joint Ventures

Business combinations and joint ventures entered into prior to January 1, 2010 will not be retrospectively restated using IFRS principles as permitted by IFRS 1.

Additional IFRS accounting policy choices and changes have not had a material impact on the IFRS opening Consolidated Balance Sheets and will continue to be monitored throughout 2011.

IFRS Quarterly Earnings Impacts

The company is currently finalizing the 2010 quarterly earnings impacts, but expects earnings to be impacted by:

•: Lower depreciation expense as a result of opening Balance Sheet impairments, derecognition of assets and a reduction to the ARO asset;
•: Lower accretion expense due to a decrease in the discounted rate;
•: Restated share-based compensation expense due to remeasurement of cash-settled awards at fair value for each reporting period;
•: Reclassifications for assets held for sale, to the respective financial statement line items, previously reported as discontinued operations under Canadian

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 43

GAAP. Dispositions did not meet the definition of discontinued operations under IFRS, resulting in additional reclassifications on the Consolidated Statements of Comprehensive Income.

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2010, our 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, 2010, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) – 15d-15(f)) that occurred during 2010 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 disclosure controls and procedures and internal control over financial reporting and will make any modifications from time-to-time as deemed necessary.

The company has undertaken a comprehensive review of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). For the year ended December 31, 2010, based on that evaluation, the company's internal controls were found to be operating free of any material weaknesses.

The company continues to integrate legacy Petro-Canada's historical internal control over financial reporting with Suncor's internal control over financial reporting. This integration will lead to changes in these controls in future fiscal periods, but it is not yet known whether these changes will materially affect internal control over financial reporting. This integration process is expected to be substantially completed by the end of 2011.

The effectiveness of our internal control over financial reporting as at December 31, 2010 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, 2010.

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

OUTLOOK

Detailed guidance on 2011 capital expenditures and production outlook can be found in Suncor's December 17, 2010 press release and on the Suncor website at www.suncor.com/guidance, which is not incorporated by reference herein.

NON-GAAP FINANCIAL MEASURES ADVISORY

Certain financial measures referred to in this MD&A, namely operating earnings, cash flow from operations, return on capital employed and Oil Sands cash operating costs, are not prescribed by Canadian 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 this 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 measure that adjusts net earnings for significant items that management believes are not indicative of operating performance and that reduce the comparability of the underlying financial performance between periods. 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.

44 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

Return on Capital Employed (ROCE)

ROCE is included because management uses this information to analyze operating performance, leverage and liquidity.

For the year ended December 31 ($ millions, except ROCE)		2010		2009		2008

Adjusted net earnings
Net earnings		3 571		1 146		2 137
Add: after-tax financing expense (income)		(80	)	(509	)	852

	A	3 491		637		2 989

Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents		13 377		7 226		3 248
Shareholders' equity		34 111		14 523		11 896

	B	47 488		21 749		15 144

Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents		11 112		13 377		7 226
Shareholders' equity		36 721		34 111		14 523

	C	47 833		47 488		21 749

Average capital employed ⁽¹⁾	D	47 519		35 128		18 447

Average capitalized costs related to major projects in progress	E	12 889		10 655		5 149

ROCE (%)	A/(D-E)	10.1		2.6		22.5

(1): Average capital employed for 2008 is calculated on a simple-average basis (B+C)/2. For 2009 and 2010, as a result of the significant capital employed that was acquired during the year due to the merger with Petro-Canada, average capital employed is now calculated on a monthly weighted average basis.

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 45

Cash Flow from Operations

Cash flow from operations is expressed before changes in non-cash working capital.

Year ended December 31			Oil Sands						Natural Gas						International and Offshore
($ millions)			2010		2009		2008		2010		2009		2008		2010	2009	2008

Net earnings (loss) from continuing operations			1 492		557		2 875		(277	)	(185	)	34		1 114	323	—
	Adjustments for:
		Depreciation, depletion and amortization	1 318		922		580		773		287		137		1 172	299	—
		Future income taxes	484		(643	)	535		(96	)	(47	)	(7	)	108	48	—
		Accretion of asset retirement obligations	120		111		55		29		14		4		27	10	—
		Unrealized (gain) loss on translation of U.S. dollar denominated long-term debt	—		—		—		—		—		—		—	—	—
		Change in fair value of derivative contracts	(316	)	960		(590	)	—		—		—		—	—	—
		Loss (gain) on disposal of assets	14		70		36		(132	)	(20	)	(22	)	2	—	—
		Stock-based compensation	48		90		54		12		19		4		18	12	—
		Gain on effective settlement of pre-existing contract with Petro-Canada	—		(438	)	—		—		—		—		—	—	—
		Other	(391	)	(378	)	(38	)	(6	)	(11	)	(13	)	8	40	—
		Exploration expenses	—		—		—		17		120		61		63	6	—

Cash flow from (used in) operations from continuing operations			2 769		1 251		3 507		320		177		198		2 512	738	—

Cash flow provided by discontinued operations			—		—		—		125		152		169		367	213	—

Total cash flow from (used in) operations			2 769		1 251		3 507		445		329		367		2 879	951	—

Year ended December 31			Refining and Marketing						Corporate, Energy Trading and Eliminations						Total
($ millions)			2010		2009		2008		2010		2009		2008		2010		2009		2008

Net earnings (loss) from continuing operations			801		407		(22	)	(442	)	104		(805	)	2 688		1 206		2 082
	Adjustments for:
		Depreciation, depletion and amortization	475		317		198		75		35		46		3 813		1 860		961
		Future income taxes	261		99		(14	)	(202	)	(85	)	(55	)	555		(628	)	459
		Accretion of asset retirement obligations	2		1		1		—		—		—		178		136		60
		Unrealized (gain) loss on translation of U.S. dollar denominated long-term debt	—		—		—		(426	)	(858	)	919		(426	)	(858	)	919
		Change in fair value of derivative contracts	—		(14	)	27		31		34		(75	)	(285	)	980		(638	)
		Loss (gain) on disposal of assets	(30	)	16		6		39		—		(7	)	(107	)	66		13
		Stock-based compensation	40		35		16		(4	)	106		(96	)	114		262		(22	)
		Gain on effective settlement of pre-existing contract with Petro-Canada	—		—		—		—		—		—		—		(438	)	—
		Other	(13	)	60		8		(44	)	11		36		(446	)	(278	)	(7	)
		Exploration expenses	—		—		—		—		—		—		80		126		61

Cash flow from (used in) operations from continuing operations			1 536		921		220		(973	)	(653	)	(37	)	6 164		2 434		3 888

Cash flow provided by discontinued operations			—		—		—		—		—		—		492		365		169

Total cash flow from (used in) operations			1 536		921		220		(973	)	(653	)	(37	)	6 656		2 799		4 057

46 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

LEGAL ADVISORY – FORWARD LOOKING INFORMATION

This Management's Discussion and Analysis 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 its experience and its perception of historical trends including expectations and assumptions concerning the accuracy of reserve and resource 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. All 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, commodity prices, costs, schedules, production volumes, operating and financial results and 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", and similar expressions. Forward-looking statements in this Management's Discussion and Analysis include references to:

•: Our plan in 2011 to direct approximately $2.8 billion towards a range of oil sands growth projects, as part of our overall $6.7 billion 2011 capital-spending plan;
•: Suncor's strategic partnership with Total, which is expected to close in the first quarter of 2011, and the terms of same, including the consideration to be received by Suncor (approximately $1.75 billion) and the expected assets to be exchanged between the parties: Total will acquire a 49% interest in Suncor's Voyageur Upgrader, and an additional 19.2% in the Fort Hills project; and Suncor will acquire a 36.75% interest in the Joslyn project;
•: Timelines and plans for the Voyageur Upgrader, the Fort Hills mine and the Joslyn mine;
•: Suncor's sale of certain of its U.K. offshore assets, and the expected completion of same during the first half of 2011;
•: Suncor's proprietary TRO_TM tailings reclamation, which is expected to significantly reduce pond reclamation time, and the plan to have it completed by the end of 2012 at a cumulative capital cost in excess of $1.0 billion;
•: Oil Sands' six-week planned turnaround scheduled for Upgrader 2 in the second quarter of 2011 and the expectation that production volumes will be reduced by approximately 215,000 bpd over the duration of the turnaround;
•: Fifteen-week dockside maintenance program at Terra Nova planned for 2011, where production volumes are anticipated to be reduced by approximately 25,000 bpd over the duration of the turnaround;
•: Turnarounds, including the three-week routine turnaround planned at White Rose, the one-week planned shutdown at Buzzard and planned major turnarounds for the Sarnia, Edmonton and Commerce City refineries in 2011;
•: Planned expansions for Firebag Stage 3, where production is targeted to begin late in the second quarter of 2011, ramping up toward capacity of 62,500 bpd of bitumen over approximately 24 months thereafter;
•: Planned expansion for Firebag Stage 4, where production is targeted to begin late in the first quarter of 2013, ramping up toward capacity of 62,500 bpd of bitumen over approximately 24 months thereafter;
•: Suncor's MNU project, which is expected to be completed by the end of 2011;
•: Expected tie-in during the first quarter of 2011 of Suncor's drilling programs in the Ferrier area located in central Alberta and the Pouce Coupe area in western Alberta;
•: Planned drilling at North Amethyst and the White Rose Extensions;
•: Expected production for the first phase of the West White Rose portion of the White Rose Extension (first oil expected by mid-2011), the Hibernia South Extension project (early production from the unit is expected in mid-2011) and Hebron (first oil expected in 2017);
•: Projected completion by the end of 2011 of Suncor's Wintering Hills wind power project, and the expectation that the project will generate enough electricity to power approximately 35,000 Alberta homes and displace 200,000 tonnes of carbon dioxide per year;
•: Anticipated completion of the Kent Breeze wind power project (mid-2011);
•: Suncor's management's belief that Suncor will have the capital resources to fund its planned 2011 capital spending program 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; and
•: Expected effects of changeover to IFRS.

This Management's Discussion and Analysis also contains forward-looking statements and information concerning the anticipated completion and timing of the proposed transaction with Total E&P Canada Ltd. and our transaction to sell our non-core U.K. assets. Suncor has provided these anticipated times in reliance on certain assumptions that we believe are reasonable at this time,

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 47

including assumptions as to the timing of receipt of the necessary regulatory, court and other third-party approvals, and the time necessary to satisfy the conditions to the closing of the transaction. These dates may change for a number of reasons, including unforeseen delays in the ability to secure necessary regulatory or other third party approvals or the need for additional time to satisfy the conditions to the completion of the transaction. The transaction may not close as scheduled or at all. As a result of the foregoing, readers should not place undue reliance on the forward-looking statements and information contained in this Management's Discussion and Analysis concerning these items.

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 and information and readers are cautioned not to place undue reliance on them.

The financial and operating performance of the company's business segments, including Oil Sands, Natural Gas, International and Offshore and Refining and Marketing, may be affected by a number of factors, including, but not limited to, the following:

Factors that affect our Oil Sands business:

•: Production reliability risk. Our ability to reliably operate our oil sands facilities in order to meet production targets.
•: Our ability to finance oil sands growth and sustaining capital expenditures in a volatile commodity pricing environment.
•: Bitumen supply. The unavailability of third party bitumen, poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in situ reservoir and equipment performance could impact production targets.
•: Performance of recently commissioned facilities. Production rates while new equipment is being lined out are difficult to predict and can be impacted by unplanned maintenance.
•: Our ability to manage production operating costs. Operating costs could be impacted by inflationary pressures on labour, volatile pricing for natural gas used as an energy source in oil sands processes, and planned and unplanned maintenance. We continue to address these risks through strategies such as application of technologies that help manage operational workforce demand, offsetting natural gas purchases through internal production, investigation of technologies that mitigate reliance on natural gas as an energy source, and an increased focus on preventative maintenance.
•: Our ability to complete projects both on time and on budget. This 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). We continue to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing Oil Sands expansion to reduce unit costs, seeking strategic alliances with service providers and maintaining a strong focus on engineering, procurement and project management.
•: Potential changes in the demand for refinery feedstock and diesel fuel. Our strategy is to reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding our customer base and offering a variety of blends of refinery feedstock to meet customer specifications.
•: Volatility in light/heavy and sweet/sour crude oil differentials.
•: Logistical constraints and variability in market demand, which can impact crude movements. These factors can be difficult to predict and control.
•: Changes to royalty and tax legislation and related agreements that could impact our business (including our current dispute with the Alberta Department of Energy in respect of the Bitumen Valuation Methodology Regulation). While fiscal regimes in Alberta and Canada are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company's planned investments, and lower rates of return on existing investments.
•: Our relationship with our trade unions. Work disruptions have the potential to adversely affect Oil Sands operations and growth projects.

Factors that affect our Natural Gas business:

•: Volatility in natural gas prices.
•: Risk associated with a depressed market for asset sales, leading to losses on disposition.
•: The accessibility and cost of mineral rights. Market demand influences the cost and available opportunities for mineral leases and acquisitions.
•: Risks and uncertainties associated with weather conditions, which can shorten the winter drilling season and impact the spring and summer drilling program, which may result in increased costs and/or delays in bringing on new production.

Factors that affect our International and Offshore business:

•: Risks and uncertainties associated with international and offshore operations normally inherent in such activities such as drilling, operation and development of such properties including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs,

48 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, pollution and other environmental risks.

•: Performance after completion of maintenance is not predictable and can significantly impact production rates.
•: Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities.

These risks could increase costs and/or cause delays to or cancellation of projects and expansions to existing projects.

•: Risks and uncertainties associated with weather conditions, which may result in increased costs and/or delays in exploration, operations or abandonment activities.
•: Suncor's foreign operations and related assets are subject to a number of political, economic and socio-economic risks. Suncor's operations in Libya may be constrained by production quotas.

Factors that affect our Refining and Marketing business:

•: Production reliability risk. Our ability to reliably operate our refining and marketing facilities in order to meet production targets.
•: Management expects that fluctuations in demand and supply for refined products, margin and price volatility, and market competition, including potential new market entrants, will continue to impact the business environment.
•: There are certain risks associated with the execution of capital projects, including the risk of cost overruns. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.
•: Our relationship with our trade unions. Hourly employees at our London, Ontario terminal operation, our Sarnia refinery, our Commerce City refinery, our Montreal refinery, certain of our lubricants operations, certain of our terminalling operations and at Sun-Canadian Pipeline Company Limited are represented by labour unions or employee associations. Any work interruptions involving our employees, and/or contract trades utilized in our projects or operations, could have an adverse effect on our business, financial condition, results of operations and cash flow.

Additional Risks, Uncertainties and Other Factors

Additional risks, uncertainties and other factors that could influence the actual results of all of Suncor's business segments include but are not limited to, market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; consistently and competitively finding and developing reserves that can be brought on-stream economically; success of hedging strategies; maintaining a desirable debt to cash flow ratio; changes in the general economic, market and business conditions; our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange; volatility in natural gas and liquids prices is not predictable and can significantly impact revenues; Suncor's ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects and regulatory projects; risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in Suncor's operating areas (these risks could increase costs and/or cause delays to or cancellation of projects); effective execution of planned turnarounds; 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 needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; 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; uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations (for example, our negotiations with the Alberta Department of Energy in respect of the Bitumen Valuation Methodology Regulation; the Government of Canada's current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us (including in respect of any planned divestitures); risks and uncertainties associated with the ability of closing conditions to be met with respect to the sale of any of Suncor's assets, the timing of closing and the consideration to be received with respect to the planned sale of any of Suncor's assets, including 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; the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; failure to realize anticipated synergies or cost savings; risks regarding the integration of Suncor and Petro-Canada after the merger;

SUNCOR ENERGY INC. 2010 ANNUAL REPORT 49

and incorrect assessments of the values of 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 this Management's Discussion and Analysis, including under the heading "Risk Factors" and its Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) 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.

50 SUNCOR ENERGY INC. 2010 ANNUAL REPORT

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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2010, dated February 24, 2011