EX-99.2 3 a2196757zex-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, 2009,
dated February 26, 2010

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 26, 2010

This Management's Discussion and Analysis (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. For information on material risk factors and assumptions underlying our forward-looking information, see page 54.

This MD&A should be read in conjunction with Suncor's December 31, 2009 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. The financial measures operating earnings, cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are discussed in Non-GAAP Financial Measures on page 52 and 53.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for projects that, in some cases, are still in the early stages of development. These costs are preliminary estimates only. The actual amounts are expected to differ and these differences may be material. For a further discussion of our significant capital projects, see the Significant Capital Project Update on page 15.

References to "we," "our," "us," "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 entity prior to the August 1, 2009 effective date of the merger.

On August 1, 2009, Suncor completed its merger with Petro-Canada. All closing conditions were satisfied, including approvals from shareholders, the Alberta Court of Queen's Bench, and the Competition Bureau of Canada. Under the terms of the merger, Petro-Canada shareholders received 1.28 Suncor common shares for each Petro-Canada common share held. For further information with respect to the merger transaction, please refer to note 2 of the December 31, 2009 audited Consolidated Financial Statements and the accompanying notes.

The consolidated financial statements include the results of post-merger Suncor from August 1, 2009. As such, amounts disclosed in this MD&A 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 and 2007 reflect solely the results of legacy Suncor.

Certain amounts in prior years have been reclassified to enable comparison with the current year's presentation.

Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The tables and charts in this document form an integral part of this MD&A.

Additional information about Suncor and legacy Petro-Canada filed with Canadian securities commissions and the United States Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the Annual Information Form filed with the SEC under cover of Form 40-F, is available on-line at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A and is not incorporated into the MD&A by reference.

6 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

SUNCOR OVERVIEW AND STRATEGIC PRIORITIES

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate five businesses:

•
  Oil Sands, located near Fort McMurray, Alberta, produces bitumen recovered from oil sands through mining and in-situ technology and upgrades it into refinery feedstock, diesel fuel and by-products. The company has a 12% ownership interest in the Syncrude oil sands mining and upgrading joint venture, also located near Fort McMurray, Alberta.
•
  Natural Gas, located primarily in Western Canada, explores for, acquires, develops and produces natural gas, natural gas liquids and crude oil. The sale of natural gas production offsets Suncor's purchases for internal consumption at our North American operations. Suncor is currently divesting certain non-core assets as we focus the strategy of this business.
•
  East Coast Canada, comprised of oil development activity offshore of Newfoundland and Labrador. The company has a strong position in every major oil development off Canada's east coast, including Hibernia, White Rose, Terra Nova and Hebron.
•
  International, which includes activities in key core areas such as the North Sea (including the United Kingdom, the Netherlands and Norway sectors), Libya, Syria, and offshore Trinidad and Tobago. Suncor is currently divesting certain non-core assets as we focus the strategy of this business.
•
  Refining and Marketing, includes refineries located in Alberta, Quebec, Ontario and Colorado, which produce and market the company's refined products to retail, commercial and industrial customers. Refining and Marketing also owns and operates a lubricants business in Ontario, which manufactures, blends and markets high quality products world-wide, interests in pipelines and terminals, and a network of retail service stations across Canada and the state of Colorado.

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

Suncor's strategic priorities are:

•
  Maintaining financial strength and flexibility through disciplined cost, capital and debt management, and stewardship of the balance sheet.
•
  Increasing our return on capital employed through targeting capital budgets to high-return, near-term projects.
•
  Focusing on plant and process reliability, efficiency and cost management as part of operational excellence initiatives.
•
  Developing our oil sands resource base through mining and in-situ technology and supplementing our bitumen production with third-party supply.
•
  Expanding oil sands mining, in-situ and upgrading facilities to increase crude oil production and improving reliability by providing flexible bitumen feed and upgrading options.
•
  Integrating oil sands production into the North American energy market through Suncor's refineries and third-party refineries to reduce vulnerability to supply and demand imbalances.
•
  Focusing on our East Coast Canada and International assets, which provide steady low-cost cash flows and offer stability during low commodity cycles to support our core oil sands operations.
•
  Reducing risk associated with commodity price volatility by producing natural gas volumes that offset purchases for internal consumption.
•
  Advancing environmental and social performance by closely managing impact to air, water and land while also earning continued stakeholder support for our ongoing operations and growth plans.
•
  Maintaining a strong focus on employee, contractor and community health and safety.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 7

2009 Overview

Key milestones and developments over the course of 2009 and early 2010 included:

Challenging economic environment to start the year. Low benchmark commodity prices significantly impacted earnings. We took action to protect our future revenues by entering into derivative contracts. As prices recovered later in 2009, we realized large losses as the settlement prices were lower than benchmark prices.

Capital spending plans were reduced. As cash flows were reduced, and the credit markets dried up, Suncor revised its spending plans down to $3 billion, and deferred a number of capital projects. Costs related to keeping these projects in "safe mode" totalled approximately $380 million in 2009.

Completed a merger with Petro-Canada on August 1, 2009. This resulted in Suncor becoming Canada's largest energy company by market capitalization, and provided Suncor with a number of key benefits:

•
  Steady production from established assets in East Coast Canada and International that will support Suncor's growth through the commodity cycle. Total production volumes from these two segments averaged approximately 178,000 bpd over the last five months of 2009.
•
  Additional refining capacity provides options for expanding oil sands production. Increased refining capacity from 178,000 bpd to 433,000 bpd. Observed performance improvements at our Edmonton refinery have enabled us to upwardly revise our nameplate capacity to 443,000 bpd. Sales of refined petroleum products during the final five months of 2009 averaged 84.8 million litres per day.
•
  Solid hedge for natural gas usage at our North American operations. Total production from our Natural Gas business segment averaged 677 mmcfe/d for the final five months of the year.
•
  Synergy opportunities(1). Operating synergies of approximately $400 million on an annualized basis have been identified. We expect that synergies will start to exceed merger and integration costs by the end of 2010, when we start realizing the full benefits of the merger. We also expect to achieve annual capital efficiencies of approximately $1 billion through elimination of redundant spending and targeting capital budgets to high- return, near-term projects.

Improved Oil Sands operational reliability. Annual production from our Oil Sands business segment averaged 290,600 bpd in 2009, compared to 228,000 bpd in 2008, with record production in November and cash operating costs (excluding Syncrude) averaging $33.95 per barrel during 2009, compared to $38.50 per barrel in 2008. However, fires in our Oil Sands operations in December 2009 and February 2010 have negatively impacted volumes.

Growth capital restarts. In November, Suncor announced 2010 capital spending plans that included restarting construction of our Firebag Stage 3 in-situ oil sands project.

Planned divestments. As part of its strategic business alignment, Suncor began the process of divesting a number of non-core natural gas assets, all Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands. Announced sales to date include substantially all of our oil and gas producing assets in the U.S. Rockies, non-core natural gas properties in Northeast British Columbia, and all Trinidad and Tobago assets. The effective close date of the U.S. Rockies sale was March 1, 2010. The other sales are expected to close in the first quarter of 2010 and are subject to customary closing conditions and regulatory approvals. The proceeds of these sales, expected to be between $2 billion and $4 billion, are planned to go towards reducing the company's debt. Net debt at year-end 2009 was $13.4 billion.

(1)
  Synergy estimates are based on certain assumptions that management currently believes are reasonable, including but not limited to: reduced operating costs due to restructuring synergies, acceleration of timing of planned capital projects and resulting revenues, reduced capital costs relating to divested assets and cash flow from divested assets. Please see Legal Notice – Forward-Looking Information on page 54.

8 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

SELECTED FINANCIAL INFORMATION

Annual Financial Data

Year ended December 31 ($ millions except per share) |  | 2009 |  | 2008 |  | 2007 |
Revenue (net of royalties) |  | 25 480 |  | 28 637 |  | 17 314 |
Net earnings |  | 1 146 |  | 2 137 |  | 2 983 |
Total assets |  | 69 746 |  | 32 528 |  | 24 509 |
Long-term debt |  | 13 880 |  | 7 884 |  | 3 814 |
Dividends on common shares |  | 401 |  | 180 |  | 162 |
Net earnings attributable to common shareholders per share – basic |  | 0.96 |  | 2.29 |  | 3.23 |
Net earnings attributable to common shareholders per share – diluted |  | 0.95 |  | 2.26 |  | 3.17 |
Cash dividends per share |  | 0.30 |  | 0.20 |  | 0.19 |

Outstanding Share Data

At December 31, 2009 (thousands) |  |  |
Number of common shares |  | 1 559 778 |
Number of common share options |  | 72 024 |
Number of common share options – exercisable |  | 42 755 |

Industry Indicators

(Average for the year) |  | 2009 |  | 2008 |  | 2007 |
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing |  | 61.80 |  | 99.65 |  | 72.30 |
Dated Brent crude oil US$/barrel at Sullom Voe |  | 61.50 |  | 97.00 |  | 72.50 |
Dated Brent/Maya FOB price differential US$/barrel |  | 5.00 |  | 13.15 |  | 12.65 |
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton |  | 65.80 |  | 103.05 |  | 76.65 |
Edmonton Light/Western Canadian Select price differential Cdn$/barrel |  | 6.65 |  | 19.90 |  | 24.05 |
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty |  | 9.70 |  | 20.10 |  | 22.25 |
Natural gas US$/thousand cubic feet (mcf) at Henry Hub |  | 4.00 |  | 8.95 |  | 6.90 |
Natural gas (Alberta spot) Cdn$/mcf at AECO |  | 4.15 |  | 8.15 |  | 6.60 |
New York Harbour 3-2-1 crack (1) US$/barrel |  | 7.80 |  | 9.10 |  | 13.70 |
Chicago 3-2-1 crack (1) US$/barrel |  | 7.75 |  | 10.40 |  | 16.85 |
Seattle 3-2-1 crack (1) US$/barrel |  | 11.40 |  | 11.80 |  | 19.55 |
Gulf Coast 3-2-1 (1) US$/barrel |  | 7.10 |  | 9.45 |  | 13.30 |
Exchange rate: US$/Cdn$ |  | 0.88 |  | 0.94 |  | 0.93 |

(1)
  3-2-1 crack spreads are industry indicators measuring the margin on a barrel of oil for gasoline and distillate. They are calculated by taking two times the gasoline margin at a certain location plus one times the distillate margin at that same location and dividing by three.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 9

On August 1, 2009, Suncor Energy Inc. completed its merger with Petro-Canada. The amounts ending December 31, 2009 reflect results of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1 through July 31, 2009. The comparative figures reflect solely the 2008 and 2007 results of legacy Suncor. For further information with respect to the merger transaction, please refer to note 2 of the December 31, 2009 audited Consolidated Financial Statements and the accompanying notes.

CONSOLIDATED FINANCIAL ANALYSIS

This analysis provides an overview of our consolidated financial results for 2009 compared to 2008. For a detailed analysis, see the various business segment discussions.

Net Earnings

Our net earnings were $1.146 billion in 2009, compared with $2.137 billion in 2008 (2007 – $2.983 billion). The decrease in net earnings is due primarily to lower price realizations, as average benchmark commodity prices were significantly weaker in 2009 compared to 2008, losses on commodity derivatives used for risk management compared to gains in the prior year, and costs incurred related to placing certain growth projects into safe mode due to market conditions earlier in the year.

These factors were partially offset by higher production from our existing oil sands assets resulting from improved operational performance, upstream production and refined product sales volumes resulting from the merger with Petro-Canada, unrealized foreign exchange gains on our U.S. denominated long-term debt due to the stronger Canadian dollar and a gain from the deemed settlement of the bitumen processing contract with Petro-Canada upon close of the merger (See note 2(e) to the December 31, 2009 audited Consolidated Financial Statements).

Revenues were $25.480 billion in 2009, compared with $28.637 billion in 2008 (2007 – $17.314 billion). The decrease was primarily due to the following factors:

•
  Operating revenues were adversely impacted by significantly weaker benchmark prices in 2009. In addition, losses on commodity price risk derivatives which we had initiated when commodity prices hit a low point early in 2009, also negatively affected operating revenues as prices recovered later in the year.
•
  Royalties increased to $1.199 billion in 2009 from $890 million in 2008, due primarily to royalty expense on additional production resulting from the merger with Petro-Canada, as well as increased production in legacy Suncor's oil sands operations. This was partially offset by lower commodity prices. For a discussion of Crown royalties, see pages 16 to 18.
•
  Energy trading revenues decreased to $7.577 billion in 2009, compared to $11.320 billion in 2008. Lower trading revenues partly resulted from decreased commodity prices. In addition, after the merger with Petro-Canada, we determined that certain physical trading commodity contracts exceeded the company's expected purchase, sale or usage requirements, and effective October 1, 2009, gains and losses on these contracts have been reported on a net basis. Had we continued reporting on a gross basis, energy supply and trading revenues would have been approximately $2 billion larger in 2009.

Partially offsetting these decreases were the following:

•
  Total upstream production and sales volumes were higher during 2009, mainly as a result of the merger with Petro-Canada, as well as improved reliability in legacy Suncor's oil sands operations. After completion of the merger with Petro-Canada, Suncor's total upstream production during the final five months of 2009 averaged 635,200 boe per day. Upstream production from legacy Suncor's oil sands and natural gas operations averaged 325,600 boe per day in 2009, compared to 264,700 boe per day in 2008.
•
  Other income included a $438 million gain related to the effective settlement of a pre-existing bitumen processing contract with Petro-Canada. For further details on this one-time item, see note 2(e) to the Consolidated Financial Statements on page 73.
•
  Stronger price realizations for sales of our oil sands sweet blend and diesel product relative to WTI positively impacted operating revenue.

The cost to purchase crude oil and crude oil products was $7.383 billion in 2009, compared to $7.582 billion in 2008 (2007 – $6.414 billion). The decrease was primarily due to the following:

•
  Lower benchmark crude oil prices. This had the largest impact on product purchases for our Refining and Marketing business, as average WTI prices were approximately 38% lower than in 2008.
•
  Decreased purchases of third-party product in our Oil Sands segment, primarily due to a reduction of planned and unplanned shutdowns, as 2008 results reflected higher purchases of diesel and bitumen to meet customer commitments. In addition, in 2008 Suncor purchased larger volumes of product from third parties to upgrade at Suncor facilities.

10 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Partially offsetting these decreases was the following:

•
  Increased purchases in our Refining and Marketing segment due to the addition of refining assets as a result of the merger with Petro-Canada.

Operating, selling and general expenses were $6.641 billion in 2009 compared with $4.186 billion in 2008 (2007 – $3.450 billion). The primary reasons for the increase were:

•
  The addition of Petro-Canada operations and the related operating, selling and general expenses; and higher production and sales volumes in legacy Suncor operations.
•
  Higher planned maintenance expenditures at our oil sands operations related to the implementation of reliability and operational efficiency initiatives.
•
  Incurred costs related to placing our growth projects into safe mode as a result of the company revising its 2009 capital budget due to market conditions earlier in the year.
•
  One-time costs related to a number of merger and integration activities.

Partially offsetting these increases was the following:

•
  Decreased energy input costs, resulting mainly from significantly lower natural gas prices. The average benchmark AECO price in 2009 was down almost 50% compared to 2008.

Transportation costs were $427 million in 2009, compared to $246 million in 2008 (2007 – $160 million). The increase in transportation costs was primarily due to the additional production and sales volumes as a result of the merger with Petro-Canada.

Depreciation, depletion and amortization (DD&A) was $2.306 billion in 2009, compared to $1.049 billion in 2008 (2007 – $864 million). The increase primarily reflects the addition of assets as a result of the merger.

Financing income was $487 million in 2009, compared with expense of $917 million in 2008 (2007 – income of $211 million). The decrease in financing expense was primarily due to foreign exchange gains on our U.S. dollar denominated long-term debt in 2009, compared to losses in 2008. This was partially offset by additional debt acquired through the merger with Petro-Canada, and by interest costs that were not capitalized during 2009 as a number of growth projects were in safe mode during the period.

Income tax expense was $143 million in 2009 (11% effective tax rate), compared to $995 million in 2008 (32% effective tax rate) and $566 million in 2007 (16% effective tax rate). The lower effective tax rate for 2009 compared to 2008 is primarily a result of foreign exchange gains on our U.S. dollar denominated long-term debt being taxed at a lower capital gains rate, no tax assessed on the gain on effective settlement of the pre-existing contract with Petro-Canada, and tax filing reconciliations.

Cash Flow from Operations

Cash flow from operations was $2.799 billion in 2009, compared to $4.057 billion in 2008 (2007 – $4.037 billion). The decrease in cash flow from operations was primarily due to the same factors that impacted earnings. Cash flow from operations is a non-GAAP measure that the company uses to evaluate operating performance. See page 52 and 53 for discussion of non-GAAP financial measures.

Dividends

Total dividends paid during 2009 were $0.30 per share, compared with $0.20 per share in 2008 (2007 – $0.19 per share). Suncor's Board of Directors periodically reviews the dividend policy, taking into consideration the company's capital spending profile, financial position, financing requirements, cash flow and other relevant factors.

Quarterly Financial Data

|  | 2009 Three months ended |  | 2008 Three months ended |
($ millions except per share) |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |
Revenues (net of royalties) |  | 7 636 |  | 8 443 |  | 4 768 |  | 4 633 |  | 6 952 |  | 8 507 |  | 7 640 |  | 5 539 |
Net earnings (loss) |  | 457 |  | 929 |  | (51 | ) | (189 | ) | (215 | ) | 815 |  | 829 |  | 708 |
Net earnings (loss) attributable to common shareholders per share |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Basic |  | 0.29 |  | 0.69 |  | (0.06 | ) | (0.20 | ) | (0.24 | ) | 0.87 |  | 0.89 |  | 0.77 |
| Diluted |  | 0.29 |  | 0.68 |  | (0.06 | ) | (0.20 | ) | (0.24 | ) | 0.86 |  | 0.87 |  | 0.75 |

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 11

Variations in quarterly net earnings (loss) during 2009 and 2008 were due to a number of factors:

•
  Additional upstream production and refined product sales volumes resulting from the merger with Petro-Canada, impacting the third and fourth quarter of 2009.
•
  Changes in benchmark commodity prices throughout 2009 and 2008. WTI averaged US$61.80 per barrel (bbl) in 2009, compared to US$99.65/bbl in 2008, while AECO averaged Cdn$4.15/mcf in 2009, compared to Cdn$8.15/mcf in 2008.
•
  Oil sands production and sales volumes decreased during periods of planned and unplanned maintenance.
•
  Cash operating costs varied due to changes in oil sands production levels, the timing and amount of maintenance activities, and the price and volume of natural gas used for energy in oil sands operations.
•
  Exchange rate fluctuations impacted the realized commodity prices on our products sold in U.S. dollars, affecting the Canadian dollar revenues earned. Changes in the exchange rate also led to unrealized gains/losses on our U.S. dollar denominated long-term debt.
•
  Crown royalties varied as a result of changes in commodity prices, changes in production and the extent and timing of eligible capital and operating expenditures.
•
  Refined product prices fluctuated as a result of global and regional supply and demand, as well as seasonal demand variations.
•
  Improved reliability in legacy Suncor's refineries, resulting in increased refined product sales and margins.

For further analysis of quarterly results, refer to Suncor's quarterly reports to shareholders available on our website.

Operating Earnings

Operating earnings is a non-GAAP measure that the company uses to evaluate operating performance, which management believes allows better comparability between periods. Operating earnings is calculated by adjusting net earnings for significant one-time items and items that are not indicative of operating performance. See page 52 for a discussion of non-GAAP financial measures.

Year ended December 31 ($ millions, after-tax) |  | 2009 |  | 2008 |  | 2007 |  |
Net earnings as reported |  | 1 146 |  | 2 137 |  | 2 983 |  |
| Change in fair value of commodity derivatives used for risk management |  | 499 |  | (372 | ) | — |  |
| Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt |  | (798 | ) | 852 |  | (215 | ) |
| Mark-to-market valuation of stock-based compensation |  | 124 |  | (107 | ) | 35 |  |
| Project start-up costs |  | 40 |  | 24 |  | 49 |  |
| Impact of income tax rate adjustments on future income tax liabilities (1) |  | 4 |  | — |  | (427 | ) |
| Costs related to deferral of growth |  | 300 |  | — |  | — |  |
| Gain on effective settlement of pre-existing contract with Petro-Canada (2) |  | (438 | ) | — |  | — |  |
| Impact of recording acquired inventory at fair value (3) |  | 97 |  | — |  | — |  |
| Merger and integration costs |  | 151 |  | — |  | — |  |
| Losses and adjustments on significant disposals (4) |  | 81 |  | — |  | — |  |
Operating earnings |  | 1 206 |  | 2 534 |  | 2 425 |  |

(1)
  In the third quarter of 2009, a $152 million increase in the future income tax liabilities resulted from a revised provincial allocation for income tax purposes due to the merger with Petro-Canada. This was partially offset for the year ended December 31, 2009 by a reduction to the Ontario income tax rate in the fourth quarter of 2009, resulting in a $148 million decrease in the future income tax liabilities. See note 7 to the Consolidated Financial Statements.
(2)
  Impact from deemed settlement value assigned to bitumen processing contract with Petro-Canada upon close of merger. See note 2 to the Consolidated Financial Statements.
(3)
  Inventory acquired through the merger at fair value was sold during the third quarter of 2009, resulting in a one-time negative impact to earnings.
(4)
  Includes loss recognized when a highway interchange constructed by Suncor was transferred to the Provincial government of Alberta, and fair value adjustments to assets acquired in the merger.

Operating earnings were $1.206 billion in 2009, compared to $2.534 billion in 2008 (2007 – $2.425 billion). The decrease in operating earnings is due primarily to lower price realizations, as average benchmark commodity prices were significantly weaker in 2009 compared to 2008. In addition, we realized losses on our risk management derivative contracts, as settlement prices were lower than market prices in the latter part of 2009 as commodity prices improved. These factors were partially offset by the increased upstream production and refined product sales volumes resulting from the merger with Petro-Canada, and improved operational performance from our existing oil sands assets.

12 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

LIQUIDITY AND CAPITAL RESOURCES

Our capital resources consist primarily of cash flow from operations and available lines of credit. As a result of the merger with Petro-Canada, we added approximately $4.2 billion in unutilized credit facilities and $415 million in cash.

We believe we will have the capital resources to fund our planned capital spending program and to meet current working capital requirements through cash flow from operations and our committed credit facilities, assuming our current production outlook and other business plan assumptions are met. Our 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, we believe adequate additional financing will be available in the debt capital markets at commercial terms and rates. Our spending is subject to change due to factors such as internal and regulatory approvals and capital availability. Refer to the discussion under Risk Factors Affecting Performance on page 20 for additional factors that may have an impact on our ability to fund our capital requirements.

To significantly reduce current debt levels in 2010, the company is targeting to apply the proceeds from the announced divestment program. The expected proceeds of $2 billion to $4 billion will be used to repay debt as the transactions are completed, subject to the financial and operational factors outlined previously, as internally generated cash flow will be used to fund our capital program.

Financing Activities

Management of debt levels continues to be a priority given our long-term growth plans. We believe a phased and flexible approach to existing and future growth projects should assist us in maintaining our ability to manage project costs and debt levels.

At December 31, 2009, our net debt (short-term debt, current portion of long-term debt and long-term debt less cash and cash equivalents) was $13.377 billion, compared to $7.226 billion at December 31, 2008. The increase in debt levels was primarily a result of the debt acquired from the merger with Petro-Canada, in addition to an increase in the drawn credit facilities that supported our capital spending program. The merger also caused our net debt/cash flow from operations measure to increase significantly, as the calculation only includes five months of cash flow from operations relating to legacy Petro-Canada operations.

Interest expense on debt continues to be influenced by the composition of our debt portfolio, and we are currently benefiting from short-term floating interest rates which remain at low levels compared to historical short-term rates. To manage fixed versus floating rate exposure, we have entered into interest rate swaps with investment grade counterparties. At December 31, 2009, we had $200 million of fixed-rate to variable-rate interest swaps (December 31, 2008 – $200 million).

During the fourth quarter of 2009, we reduced our committed bilateral credit facility from $855 million to $61 million, reduced our Canadian-based demand bilateral credit facilities from $588 million to $413 million, and we increased our commercial paper program from $1.5 billion to $2.5 billion. Unutilized lines of credit at December 31, 2009 were $4.208 billion.

Excluding cash and cash equivalents, short-term debt, the current portion of long-term debt and future income taxes, Suncor had an operating working capital deficiency of $309 million at December 31, 2009, compared to a deficiency of $851 million at December 31, 2008. The reduced deficiency was primarily due to increased inventory levels as a result of the merger with Petro-Canada.

We are subject to financial and operating covenants related to our 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.

We are in compliance with our financial covenant that requires consolidated debt to not be more than 60% of our total capitalization. At December 31, 2009, our consolidated debt to total capitalization was 28.9% (where consolidated debt is short-term debt plus current portion of long-term debt plus long-term debt, and total capitalization is consolidated debt plus shareholders' equity). We are also currently in compliance with all operating covenants. In addition, a limited number of our derivative financial instrument agreements contain provisions linked to debt ratings that may result in settlement of the outstanding transactions should our debt ratings fall below investment grade status.

All of our debt ratings are currently investment grade. Suncor'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.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 13

The preceding paragraphs contain forward-looking information regarding our liquidity and capital resources based on factors and assumptions discussed above and on page 20. Users of this information are cautioned that our actual liquidity and capital resources may vary materially from our expectations. See the discussion with respect to forward-looking information on page 54.

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 |  | 2010 |  | 2011-2012 (aggregate) |  | 2013-2014 (aggregate) |  | Later Years |
Fixed-term debt and revolving-term debt (1) |  | 13 586 |  | 3 244 |  | 500 |  | 742 |  | 9 100 |
Interest payments on fixed-term debt |  | 12 197 |  | 651 |  | 1 255 |  | 1 219 |  | 9 072 |
Capital leases |  | 711 |  | 35 |  | 68 |  | 72 |  | 536 |
Employee future benefits (2) |  | 1 976 |  | 154 |  | 338 |  | 380 |  | 1 104 |
Asset retirement obligations (3) |  | 8 280 |  | 318 |  | 468 |  | 352 |  | 7 142 |
Operating lease agreements, pipeline capacity, energy services commitments and delivery obligations (4) |  | 12 724 |  | 1 090 |  | 1 787 |  | 1 550 |  | 8 297 |
Other long-term obligations (5) |  | 1 146 |  | 382 |  | 568 |  | 139 |  | 57 |
Total |  | 50 620 |  | 5 874 |  | 4 984 |  | 4 454 |  | 35 308 |

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. Commodity purchase obligations for which an active, highly liquid market exists, and which are expected to be re-sold shortly after purchase, are one example of excluded items.

(1)
  Includes $8.075 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 2009 of 1.97% on $200 million of our Medium Term Notes. Approximately $3.244 billion of revolving-term debt with an effective interest rate of 0.74% was issued and outstanding at December 31, 2009.
(2)
  Represents the undiscounted expected funding by the company to its pension plans as well as benefit payments to retirees for other post-retirement benefits.
(3)
  Represents the undiscounted amount of legal obligations associated with site restoration on the retirement of assets with determinable lives.
(4)
  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. In addition, 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 and obligations associated with reimbursing BG Gas Marketing for gas quantities in the Trinidad LNG Sales Contract.
(5)
  Includes Libya Exploration and Production Sharing Agreements (EPSA) signature bonus and Fort Hills purchase obligation. See note 16 to the Consolidated Financial Statements.

14 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Significant Capital Project Update

In November 2009, Suncor's Board of Directors approved a $5.5 billion capital spending plan for 2010. Approximately $1.5 billion will be directed toward growth project funding, primarily at the company's oil sands operations, while $4 billion in spending is targeted to sustaining existing operations.

The majority of growth spending will be directed toward the Firebag Stage 3 in-situ oil sands expansion, which was approximately 50 per cent complete before being deferred in early 2009. Suncor now expects the project to begin production in the second quarter of 2011, with volumes then beginning ramp up toward design capacity of approximately 68,000 bpd of bitumen over a period of approximately 18 months. Spending will also be directed to Firebag Stage 4 to support a target of first bitumen production in the fourth quarter of 2012. Stage 4 also has a design capacity of 68,000 bpd.

Growth capital will also be directed toward completing a naphtha unit in one of our upgraders and to expansion of Suncor's St. Clair Ethanol Plant. International growth plans include commitments in Libya and investments planned to bring the Ebla gas project in Syria into production in the second quarter of 2010.

Capital plans and sequencing for other projects in Suncor's growth portfolio are under evaluation with a further update expected in the fourth quarter of 2010.

Suncor spent $4.2 billion on capital and exploration expenditures in 2009, compared to $8.0 billion in 2008 (2007 – $5.6 billion). A summary of the progress on our significant projects under construction to support both our growth and sustaining needs is provided below. All projects listed below have received Board of Directors approval. The estimates and target completion dates do not include project commissioning and start-up.

The company continues to incur costs related to placing certain growth projects into "safe mode" as a result of the company revising its 2009 capital budget due to market conditions earlier in the year. Safe mode is defined as the costs of deferring the projects and keeping the equipment and facilities in a safe manner in order to expedite remobilization. As a result of placing the company's projects into safe mode, pre-tax costs of $382 million were incurred in 2009. Further safe mode costs of $150 million to $200 million on a pre-tax basis, including costs related to the remobilization of growth projects placed into safe mode, are expected to be incurred in 2010.

|  | Business |  |  |  | Cost Estimate |  | Estimate |  | Spent to date |  | Target Completion |
Project |  | Segment |  | Plan |  | $ millions(1) |  | % Accuracy(1) |  | $ millions |  | date |
Firebag sulphur plant |  | Oil Sands |  | Support emission abatement plan at Firebag; capacity to support Stages 1-6 |  | 404 |  | N/A |  | 415 |  | Complete |
Steepbank extraction plant |  | Oil Sands |  | New location and technologies aimed at improving operational performance |  | 980 |  | N/A |  | 1 015 |  | Complete |
Ebla gas project |  | International |  | Development of gas fields and construction of gas treatment plant |  | 1 196 |  | +7/-3 |  | 1 080 |  | Q2 2010 |
Buzzard enhancement project (2) |  | International |  | Installation of equipment to handle high sulphur content |  | 339 |  | +15/-10 |  | 163 |  | Q4 2010 |
Firebag Stage 3 |  | Oil Sands |  | Expansion is expected to increase bitumen supply |  | 3 638 |  | +10/-10 |  | 2 780 |  | Q2 2011 |
Naphtha unit (3) |  | Oil Sands |  | Increases sweet product mix |  | 850 |  | +4/-4 |  | 670 |  | Q3 2011 |
North Amethyst (2) |  | East Coast Canada |  | Extension to the White Rose field involving subsea tie-in |  | 490 |  | +10/-5 |  | 230 |  | 2012 (4) |

(1)
  Cost estimates and estimate accuracy reflect budgets approved by Suncor's Board of Directors.
(2)
  Amounts represent Suncor's net share in the project.
(3)
  As a result of labour shortages and cost escalation, the cost estimate has been revised to $850 million +4/-4% (previously $650 million +10/-10%).
(4)
  Initial production is expected in the second quarter of 2010.

The preceding paragraphs and table contain forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results, including target completion dates, for each of these projects may vary from the plans disclosed in the table. For a list of the

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 15

material risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially from those contained in the previous table, please see page 20. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 54.

The material factors used to develop target completion dates and cost estimates and expected results are: current capital spending plans, the current status of procurement, design and engineering phases of the project; updates from third parties on delivery of goods and services associated with the project; and estimates from major projects teams on completion of future phases of the project. We have assumed that commitments from third parties will be honoured and that material delays and increased costs related to the risk factors referred to above will not be encountered.

Guarantees, Variable Interest Entities and Off-Balance Sheet Arrangements

CICA Accounting Guideline 15, Consolidation of Variable Interest Entities (VIEs), provides criteria for the identification of VIEs and further criteria for determining what entity, if any, should consolidate them. Entities in which equity investors do not have the characteristic of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinate financial support are subject to consolidation by a company if that company is deemed the primary beneficiary. The primary beneficiary is the party that is subject to a majority of the risk of loss from the VIE's activities, or is entitled to receive a majority of the VIE's residual returns, or both. The company has determined that certain retail licensee and wholesale marketer agreements would constitute VIEs, even though the company has no ownership in these entities. The company, however, is not the primary beneficiary and, therefore, consolidation is not required. In certain of the retail licensee arrangements, the company has provided loan guarantees. Management is of the opinion that the company's maximum exposure to loss from these arrangements would not be significant.

The company has agreed to indemnify holders of all notes and debentures and the company's credit facility lenders (see note 17 to the Consolidated Financial Statements) for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to certain facility and equipment leases.

There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, Suncor has the option to redeem or terminate these contracts if additional costs are incurred.

ROYALTIES

Oil Sands Crown Royalties

Under the Province of Alberta's generic oil sands royalty regime in effect to December 31, 2008 (1997 Generic Regime), Alberta Crown royalties for oil sands projects were payable at the rate of 25% of the difference between a project's annual gross revenues net of reasonable quality adjustments and related allowable transportation costs (R), less allowable costs (C) including allowable capital expenditures (the R-C Royalty). This is subject to a minimum royalty at 1% of revenues should allowable costs exceed revenues as determined using the R-C Royalty Formula. The Alberta government has classified Suncor's current oil sands operations as two distinct "projects" for royalty purposes.

Royalties on our Firebag in-situ project were under the 1997 Generic Regime until the end of 2008, and assessed based on bitumen value. In December 2008, the government of Alberta enacted the New Royalty Framework which increased royalty rates from the 1997 Generic Regime to a sliding scale royalty of 25% to 40% of R-C, subject to minimum royalty of 1% to 9% of R, depending on oil price. In both cases, the sliding scale royalty moves with increases in WTI prices from Cdn$55/bbl to the maximum rate at a WTI price of Cdn$120/bbl.

The MacKay River in-situ project acquired with the merger of Suncor and Petro-Canada on August 1, 2009. Mackay River is also subject to royalties based on the New Royalty Framework.

Royalties on our base oil sands mining and associated upgrading operations are modified by Crown agreements and are assessed on the R-C royalty, subject to a minimum royalty, as follows:

•
  Based on upgraded product values until December 31, 2008 with the rates at 25% of R-C, subject to the 1% minimum royalty of R.
•
  Commencing January 1, 2009, a bitumen-based royalty applied pursuant to Suncor's exercise of its option to transition to the bitumen-based 1997 Generic Regime. The royalty rates were at 25% of R-C, subject to the 1% minimum royalty of R, but applied to a revised R-C, where R was based on bitumen value and C would exclude substantially all upgrading operating and related capital costs.

16 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

•
  From January 1, 2010 through December 31, 2015, pursuant to our January 2008 Royalty Amending Agreement (RAA) with the government of Alberta, the New Royalty Framework rates described above will apply to the bitumen royalty for current production levels, subject to a cap of 30% of R-C, and a minimum royalty of 1% to 1.2% of R. In addition, the Suncor RAA provides Suncor with a level of certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty-in-kind and certain taxes.

In 2016 and subsequent years, the royalty rates for all of our oil sands operations will be the rates prescribed under the New Royalty Framework, unless it is amended or superseded prior to that time.

The following table sets forth an estimation of royalties on our oil sands operations (excluding Syncrude) in the years 2010 – 2013 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios.

WTI Price/bbl US$ |  | 60 |  | 80 |  | 100 |
Natural gas (Alberta spot) Cdn$/mcf at AECO |  | 5.75 |  | 7.50 |  | 9.50 |
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$ |  | 7.25 |  | 9.75 |  | 12.00 |
Differential of Maya at the U.S. Gulf Coast less Western Canadian Select at Hardisty, Alberta US$ |  | 4.50 |  | 6.00 |  | 7.50 |
US$/Cdn$ exchange rate |  | 0.85 |  | 0.97 |  | 1.00 |
Crown Royalty Expense (based on percentage of total Oil Sands gross revenue (excluding Syncrude)) %(1) |  |  |  |  |  |  |
2010-2013 |  | 4-6 |  | 9-11 |  | 12-14 |

(1)
  Reflects Crown's interim bitumen valuation methodology.

The previous table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the percentages disclosed in the table. The percentages disclosed in the table were developed using the following assumptions: current agreements with the Government of Alberta, royalty rates and other changes enacted effective January 1, 2009 by the Government of Alberta, current forecasts of production, capital and operating costs, and the forward estimates of commodity prices and exchange rates described in the table.

The following risk factors could cause actual royalty rates to differ materially from the rates contained in the foregoing table:

(i)
  The government of Alberta enacted new Bitumen Valuation Methodology (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 and 2010. The final regulations are being developed by the Crown that will establish the bitumen valuation methodology for future years. For Suncor's mining operations, the bitumen valuation methodology is based on the terms of the Suncor RAA, which we believe places certain limitations on the interim bitumen valuation methodology as recently enacted. For the year 2009, Suncor filed a non-compliance notice with the Crown, citing that reasonable adjustments in the determination of the Suncor bitumen value were not considered by the Crown as permitted by the Suncor RAA. Royalty payments to the Crown for our mining operations were determined in accordance with the Suncor RAA and royalty expense was recorded under the Crown's interim bitumen valuation methodology, representing a negative difference of approximately $200 million. The Suncor RAA provides for a negotiation period with the Crown and, failing a negotiated settlement, an arbitration procedure is outlined. If a negotiated settlement or arbiter does not create a result in Suncor's favour, royalty payments could be significantly higher.
(ii)
  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 the Suncor RAA determine the royalty obligation through 2015 for the mining operations. However, potential changes to, and the interpretation of, the Allowed Cost regulations, could over time, have a significant impact on the amount of royalties payable.
(iii)
  Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project; changes resulting from regulatory audits of prior year filings; further changes to applicable royalty regimes

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 17

by the government of Alberta; changes in other legislation; and the occurrence of unexpected events all have the potential to have an impact on royalties payable to the Crown.

For further information on risk factors related to royalty rates, please see page 54 of Suncor's Annual Information Form dated March 5, 2010.

Syncrude Royalties

Syncrude oil sands project is also subject to the New Royalty Framework effective January 1, 2009 and has signed a Royalty Amending Agreement with the Crown. Syncrude has also filed a non-compliance notice with the Crown with respect to the valuation of bitumen for royalty purposes. The royalty adjustment amount for Suncor's share of the Syncrude project is not material.

Alberta Natural Gas Crown Royalties

In 2008, royalty rates on natural gas production in Alberta were capped at 30% for gas discovered in 1974 or later and 35% for gas discovered prior to 1974. These rates were subject to reduction if (i) gas prices dropped below $3.70/gigajoule ($3.89/mcf), (ii) a gas well qualified for a deep gas royalty holiday incentive, or (iii) a gas well qualified as a low productivity well. The New Royalty Framework, effective from January 1, 2009, is a sliding scale that is dependent on the production rate, depth of the well, and the market price for natural gas, up to a maximum royalty rate of 50%. The framework provides some royalty relief, under the Natural Gas Deep Drilling Program, for wells drilled beyond 2,500 metres true vertical depth, based on the total depth and whether the well is exploratory or developmental. On November 19, 2008, the government of Alberta announced the Transitional Royalty Program available for wells from 1,000 metres to 3,500 metres in measured depth. Companies can elect to be subject to the Transitional Royalty Program for qualifying wells which would cap the maximum royalty at 30%, however, these wells cannot also receive royalty relief from the Natural Gas Deep Drilling Program. The Transitional Royalty Program is available from 2009 to 2013 inclusive. After January 1, 2014, all wells are subject to the New Royalty Framework.

East Coast Canada Royalties

The following table sets forth an estimation of royalties on our East Coast Canada operations in 2010 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios.

WTI Price/bbl US$ |  | 60 |  | 80 |  | 100 |
US$/Cdn$ exchange rate |  | 0.85 |  | 0.97 |  | 1.00 |
Crown Royalty Expense (based on percentage of gross revenue) % |  |  |  |  |  |  |
2010 – Crude (tiered royalty rates assessed on gross or net revenue) |  | 29-31 |  | 31-33 |  | 32-34 |

The previous table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the percentages disclosed in the table. The percentages disclosed in the table were developed using the following assumptions: current agreements with the Government of Newfoundland and Labrador, current forecasts of production, capital and operating costs, and the forward estimates of commodity prices and exchange rates described in the table.

The following risk factors could cause actual royalty rates to differ materially from the rates contained in the foregoing table:

(i)
  The government of Newfoundland and Labrador and Suncor are in discussions to resolve several outstanding issues that impact current and prior years. Settlement of these issues could impact royalties payable to the Crown.
(ii)
  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 all have the potential to have an impact on royalties payable to the Crown.

CASH INCOME TAXES

We estimate we will have cash income taxes of approximately $800 million to $900 million during 2010. Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of deductibility of capital expenditures for income tax purposes, among other things. This estimate is based on the following assumptions: current forecasts of production, capital and operating costs and the commodity prices and exchange rates described in the royalty estimate tables on page 17 and 18, assuming there are no changes to the current income tax regime. Our outlook on cash income taxes is a forward-looking

18 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

statement and users of this information are cautioned that actual cash income taxes may vary materially from our outlook.

DERIVATIVE FINANCIAL INSTRUMENTS

We periodically enter into derivative contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. We also use physical and financial energy derivatives to earn trading revenues.

Suncor accounts for its significant derivative financial instruments using the mark-to-market method. The contracts are recorded on the balance sheet at fair value at each period end, with any changes in fair value immediately recognized in net earnings.

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, the company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. The company characterizes inputs used 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.

The fair value of our derivative financial instruments at December 31, were as follows:

($ millions) |  | 2009 |  | 2008 |  |
Derivative financial instruments |  |  |  |  |  |
| Assets |  | 231 |  | 660 |  |
| Liabilities |  | (572 | ) | (27 | ) |
Net derivative financial instruments |  | (341 | ) | 633 |  |

Commodity Price Risk Management Activities

The company has hedged a portion of its forecasted U.S. dollar denominated crude oil sales subject to U.S. dollar West Texas Intermediate (WTI) price risk. For the full year 2010, we hold crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel.

In addition to our strategic crude oil hedging program, Suncor uses derivative contracts to hedge risks related to purchases and sales of natural gas and refined products, to manage exposure to interest rates, and to hedge risks specific to individual transactions.

Settlement of our commodity hedging contracts results in cash receipts or payments for the difference between the derivative contract and market rates for the applicable volumes hedged during the contract term. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings.

Significant derivative contracts outstanding at December 31, 2009 were as follows:

Crude oil |  | Quantity (bpd) |  | Average Price(1) (US$/bbl) |  | Hedge Period |
Purchased puts (2)55 000 |  | 60.00 |  | 2010 |
Sold puts (3) |  | 54 753 |  | 60.00 |  | 2010 |
Collars – floor |  | 50 041 |  | 50.00 |  | 2010 |
Collars – cap |  | 49 986 |  | 68.06 |  | 2010 |

(1)
  Average price for crude puts is US$ WTI per barrel at Cushing, Oklahoma.
(2)
  Total premium paid was US$29.5 million.
(3)
  Premium received was US$213 million.

The earnings impact associated with our commodity price risk derivatives for the twelve months ended December 31, 2009 was a net pretax loss of $1.025 billion (2008 – pretax gain of $465 million).

Energy Supply and 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 revenues and expenses in the Consolidated Statements of Earnings. The net pretax loss associated with our energy trading activities in 2009 was $70 million (2008 – earnings of $127 million).

Risks Associated with Derivative Financial Instruments

Our price risk management strategies are subject to periodic management reviews to determine appropriate hedge requirements in light of our tolerance for exposure to market volatility as well as the need for stable cash flow to finance future growth.

We 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. We minimize 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. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 19

Energy marketing 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 financial contracts and additional discussion of exposure to risks and our mitigation activities, see note 4 to the Consolidated Financial Statements on page 74.

RISK FACTORS AFFECTING PERFORMANCE

Our financial and operational performance is potentially affected by a number of factors including, but not limited to, commodity prices and exchange rates, environmental regulations, changes to royalty and income tax legislation, credit market conditions, stakeholder support for activities and growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors Affecting Performance for each of our business segments. A more detailed discussion of our risk factors is presented in our most recent Annual Information Form (AIF)/Form 40-F, filed with securities regulatory authorities. We are continually working to mitigate the impact of potential risks to our stakeholders. This process includes an entity-wide risk review. This internal review is completed annually to ensure all significant risks are identified and appropriately managed. Certain key risk factors are discussed below:

Integration Risk

The company completed the merger with Petro-Canada in order to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits including, cost savings and other operational synergies. Achieving the benefits of the merger depends in part on the ability of Suncor to effectively capitalize on its scale, scope and leadership position in the oil sands industry, to realize the anticipated capital and operating synergies, to profitably sequence the growth prospects of its asset base and to maximize the potential of its improved growth opportunities and capital funding opportunities as a result of combining the businesses and operations of Suncor and Petro-Canada. A variety of factors, including the required dedication of substantial management effort, time and resources on integration matters, which may divert focus and resources from other strategic opportunities of Suncor, and those other risk factors set forth in this MD&A, may adversely affect the ability to achieve the anticipated benefits of the merger.

Commodity Prices and Exchange Rates

Our future financial performance remains closely linked to hydrocarbon commodity prices, which may be influenced by many factors including global and regional supply and demand, seasonality, worldwide political events and weather. These factors can cause a high degree of price volatility. For example, from 2007 to 2009, the monthly average price for benchmark WTI crude oil ranged from a low of US$39.26/bbl to a high of US$134.02/bbl. During the same three-year period, the natural gas AECO benchmark monthly average price ranged from a low of $2.70/mcf to a high of $11.39/mcf.

Crude oil prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the US$/Cdn$ currency exchange rate, thereby creating an element of uncertainty. Should the Canadian dollar strengthen compared to the U.S. dollar, the resulting negative effect on net earnings would be partially offset by foreign exchange gains on our U.S. dollar denominated debt. The opposite would occur should the Canadian dollar weaken compared to the U.S. dollar. Cash flow from operations is not impacted by the effects of currency fluctuations on our U.S. dollar denominated debt. We are also impacted to a lesser extent by exchange rate fluctuations between the Canadian dollar, the Euro and the British pound.

We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 19).

20 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

SENSITIVITY ANALYSIS (1)

|  |  |  |  |  | Approximate Change in |
|  | 2009 Average |  | Change |  | Cash Flow from Operations ($ millions) |  | After-Tax Earnings ($ millions) |
Oil Sands |  |  |  |  |  |  |  |  |
| Realized crude oil price ($/barrel)(2) |  | 61.26 |  | US$1.00 |  | 86 |  | 65 |
| Sales (bpd) |  | 276 200 |  | 1 000 |  | 7 |  | 5 |
Natural Gas |  |  |  |  |  |  |  |  |
| Realized natural gas price ($/mcf)(2) |  | 3.70 |  | Cdn$0.10 |  | 13 |  | 9 |
| Natural gas sales (mmcf/d) |  | 397.2 |  | 10 |  | 10 |  | 1 |
East Coast Canada |  |  |  |  |  |  |  |  |
| Realized crude oil price ($/barrel)(2) |  | 76.86 |  | US$1.00 |  | 7 |  | 5 |
| Sales (bpd) |  | 58 000 |  | 1 000 |  | 4 |  | 3 |
International |  |  |  |  |  |  |  |  |
| Realized crude oil price ($/barrel) (2) |  | 76.11 |  | US$1.00 |  | 9 |  | 7 |
| Crude oil sales (bpd) |  | 100 500 |  | 1 000 |  | 6 |  | 5 |
| Realized natural gas price ($/mcf) (2) |  | 4.18 |  | US$0.10 |  | 1 |  | 1 |
| Natural gas sales (mmcf/d) |  | 116.2 |  | 10 |  | 4 |  | 4 |
Consolidated |  |  |  |  |  |  |  |  |
| US$/Cdn$ exchange rate effect on U.S. denominated long-term debt |  | 0.88 |  | 0.01 |  |  |  | 92 |

(1)
  The sensitivity analysis shows the main factors affecting Suncor's annual cash flow from operations and earnings based on actual 2009 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2009 results. A change in any one factor could compound or offset other factors.
(2)
  Includes the impact of hedging activities. See page 19.

Environmental Regulation and Risk

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require us to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are generally required before initiating most new projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air emissions (Criteria Air Contaminants (CACs) and Greenhouse Gases (GHGs)), will impose further requirements on companies operating in the energy industry.

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;
•
  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 lifecycle carbon content.

Changes in environmental regulation could have a potentially adverse effect on our financial results from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. 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

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 21

significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for clean-up costs and damages, and the loss of important permits and licenses.

Climate Change Legislation Suncor operates in jurisdictions that have regulated or have proposed to regulate industrial GHG emissions. Jurisdictions that currently regulate GHG emissions include Alberta and the European Union. Jurisdictions that have proposed to regulate GHG emissions include the U.S., British Columbia (B.C.), Quebec, Ontario and Canada. Those jurisdictions that have announced the intent to regulate GHG emissions generally support carbon pricing policies such as cap-and-trade systems and, in some cases, have also proposed implementing additional measures, including low carbon fuel standards. Suncor participates both directly and through industry associations in the consultation process on the design of proposed regulations, as well as efforts to harmonize regulations across jurisdictions within North America.

While these jurisdictions have not yet published details on their proposed regulations, or on their compliance mechanisms, many, most notably the U.S., have identified the importance of balancing the environment, economy and energy security when developing regulations. The Canadian government has also recently gone on record to state that its regulations will be consistent with U.S. regulations. While it is premature to predict what impact these anticipated regulations may have on the company and the broader oil and gas sector, the company will likely face increased capital and operating costs in order to comply with these regulations and these costs could be material. In addition, regulation based on life cycle analysis of fuel carbon content may impact markets for oil sands crude oils. Notwithstanding the current regulatory uncertainty, the company assumes that a price will be imposed on carbon dioxide and incorporates a range of potential carbon costs and regulatory outcomes into future capital planning.

In 2007, the Alberta government introduced the Climate Change and Emissions Management Amendment Act, which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year. Suncor's oil sands operations, the Edmonton Refinery and two Natural Gas Plants in Alberta are subject to this legislation. The act calls for intensity reductions of 12% from an approved baseline, commencing July 1, 2007.

In compliance with this new legislation, the company filed applications in December 2007 to establish baseline intensities for our Alberta facilities. In March 2010, the company must file compliance reports that demonstrate that each facility either met its intensity target for 2009, or took action to offset its emissions intensity. Compliance options available to the company include internal emission reductions, utilizing offset projects or contributing to a government climate change emission management fund.

For the compliance period of January 1 to December 31, 2009, the compliance costs to Suncor's Alberta facilities are estimated at between $3 million and $5 million. Final costs for 2009 will be determined when the company files its compliance report with the Province of Alberta in March 2010.

Suncor's operated facilities in the Netherlands North Sea are subject to the European Union Emissions Trading System and the associated National Allocation Plan. For the compliance period of January 1 to December 31, 2009, Suncor's facilities will have sufficient allocations for compliance.

There remains uncertainty around the outcome and impacts of climate change and other environmental regulations. 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 such as carbon capture and sequestration.

Tailings Management Another area of risk for Suncor is the reclamation of tailings ponds, which contain water, clay and residual bitumen produced through the extraction process. On October 15, 2009, Suncor applied to the Energy Resources Conservation Board (ERCB) and Alberta Environment (AENV) for permission to amend its existing and/or approved operations east of the Athabasca River to move from the currently adopted tailings management system, being the use of a consolidated tailings (CT) process to consolidate mature fine tailings (MFT), to Suncor's new Tailings Reduction Operations (TRO) strategy, based on MFT drying. This application is currently pending ERCB and AENV approval.

Regulatory Approvals Before proceeding with most major projects, we must obtain regulatory approvals. The regulatory approval process often involves stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow.

22 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

CRITICAL ACCOUNTING ESTIMATES

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 our Consolidated Financial Statements.

Asset Retirement Obligations (ARO)

We are required to recognize a liability for the future retirement obligations associated with our property, plant and equipment. 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 our total ARO amount. These individual assumptions can be subject to change based on experience.

Each year-end cash flow estimates are re-evaluated and increases to the ARO are discounted to present value using a credit-adjusted risk-free discount rate. The ARO accretes over time until we settle the obligation, the effect of which is included in a separate line in the Consolidated Statements of Earnings entitled accretion of asset retirement obligations. The discount rate is adjusted as appropriate, to reflect long-term changes in market rates and outlook.

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 2009, we increased our estimated undiscounted total obligation to $8.3 billion from the previous estimate of $3.5 billion. The increase was mainly due to the addition of $4.7 billion in undiscounted ARO as a result of the merger with Petro-Canada. The estimated discounted total obligation at December 31, 2009 was $3.2 billion, compared to $1.6 billion at December 31, 2008.

Employee Future Benefits

We provide a range of benefits to our employees and retired employees, including pensions and other post-retirement benefits. The determination of obligations under our 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 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 benefit liability is reported as part of accrued liabilities and other in the Consolidated Balance Sheets.

The assumed rate of return on plan assets considers the current level of expected returns on the fixed income portion of the plan assets 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.

Property, Plant and Equipment and Depreciation, Depletion and Amortization

We account for our exploration and production related to our oil and gas producing activities using the successful efforts method. This policy was selected over the alternative of the full-cost method because we believe it provides timelier accounting of the success or failure of exploration and production activities.

The application of the successful efforts method of accounting requires management to determine the proper classification of activities designated as developmental or exploratory, which then determines the appropriate accounting treatment of the costs incurred. The results

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 23

from a 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 dry hole are written off and reported as part of exploration expenses in the Consolidated Statements of Earnings. Dry hole expense can fluctuate from year to year due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in the exploratory drilling and the degree of risk in drilling in particular areas.

Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance. Such changes may require a test for the potential impairment of capitalized properties based on estimates of future cash flow from the properties. An impairment test may also be required as a result of other economic events. Estimates of future cash flows are subject to significant management judgment concerning oil and gas prices, production quantities, operating costs and future development costs. Where properties are assessed by management to be fully or partially impaired, the book value of the properties is reduced to fair value and either completely removed (written off) or partially removed (written down) in our records and reported as part of depreciation, depletion and amortization expenses, in the Consolidated Statements of Earnings.

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, future commodity prices and operating 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.

Purchase Price Allocation

Business acquisitions are accounted for by the purchase method of accounting. Under this method, the purchase price is 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. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant and equipment acquired generally require the most judgment and include estimates of reserves acquired (see Oil and Gas Reserves below), future commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation. Future net earnings can be affected as a result of changes in future depreciation and depletion, asset impairment or goodwill impairment.

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 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 income tax provision in the future.

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, 2009. 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.

Oil and Gas Reserves

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. Our oil and gas reserves are evaluated by independent qualified reserves evaluators. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment.

24 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

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.

RESERVES ESTIMATES

As a Canadian issuer, Suncor is subject to the reporting requirements of the Canadian Securities Administrators (CSA), including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). In order to harmonize its oil and gas disclosure in both Canada and the United States, Suncor applied for, and received, an exemption from Canadian securities regulatory authorities permitting Suncor to report its reserves in accordance with the rules and regulations of the United States Securities and Exchange Commission (SEC). See "Reliance on Exemptive Relief" in our Annual Information Form dated March 5, 2010. The SEC has updated its oil and gas disclosure requirements with the issuance of its final rule, Modernization of Oil and Gas Reporting, on December 31, 2008. Under the new SEC rule, disclosure of probable reserves is now permitted in addition to proved reserve. Disclosure of oil sands mining and upgrading as oil and gas activities is also permitted. Suncor's 2009 reserves disclosure includes both proved and probable reserves for all of our oil and gas operations including our oil sands areas and associated upgrading facilities.

Differences in the estimates of the reserves between U.S. disclosure requirements and NI 51-101 can be material mainly due to differences in the stipulated product prices to be used for reserve evaluations. U.S. disclosure requirements mandate the use of an average of first day of the month price for the twelve months prior to the end of the reporting period, while Canadian securities regulatory authorities require a forecasted price. However this difference in pricing methodologies did not have a material impact on Suncor's 2009 reserves disclosure.

In addition to reporting our reserves in accordance with U.S. disclosure requirements, we are also providing voluntary additional disclosure (which does not conform to U.S. disclosure requirements). Our voluntary additional disclosure will differ from our required U.S. disclosure in the following ways:

•
  Disclosure of reserves on a gross basis (before royalty) voluntarily, as well as the required net basis (after royalty) under U.S. disclosure requirements.
•
  Disclosure of proved and probable reserve totals on a gross basis (before royalty) together, in addition to reporting them separately on a net basis (after royalty) as required under U.S. disclosure requirements.
•
  Disclosure of contingent resources and remaining recoverable resources on a gross basis (before royalty) following NI 51-101 requirements (disclosure of resources is not recognized under U.S. disclosure requirements).

The majority of Suncor's proved reserves and probable reserves are in Canada, both in the Canadian oil sands, and conventional type plays in Western Canada and offshore on the east coast of Canada. Suncor also has other North American proved and probable reserves in the United States and international proved and probable reserves in the North Sea, Syria, Libya, and Trinidad and Tobago.

For more information regarding our reserves and resource disclosure, please see "Reserve Estimates" in our Annual Information Form dated March 5, 2010, which section of the Annual Information Form is incorporated into this MD&A by reference.

Merger of Suncor and Petro-Canada

Effective August 1, 2009, Suncor Energy Inc. (as it existed at that time) and legacy Petro-Canada amalgamated to form a single corporation continuing under the name "Suncor Energy Inc.". The addition of the Petro-Canada properties is being shown as a purchase by Suncor. In determining the purchased volumes, Petro-Canada's 2008 closing reserve balances were used and adjusted for 2009 production volumes and any purchases or sales of assets prior to August 1, 2009. A total of 752 millions of barrels (MMbbls) of proved oil volumes on a net basis (after royalty) and 1,179 billion cubic feet (Bcf) of proved natural gas volumes on a net basis (after royalty) were added to Suncor's proved reserves base as a result of the merger.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 25

REQUIRED U.S. OIL AND GAS DISCLOSURE

The table below shows Suncor's 2009 year-end balances for proved and probable reserves, and was prepared in accordance with SEC standards for oil and gas activities:

Summary of Oil and Gas Reserves After Royalties (1), (2), (3), (5)

|  | Reserves |  |  |  | Reserves |
Reserve category |  | Oil & NGL |  | Natural Gas |  | SCO |  | Bitumen |  | Reserve category |  | Oil |  | Natural Gas |  | SCO |  | Bitumen |
|  | (MMbbls) |  | (BCF) |  | (MMbbls) |  | (MMbbls) |  |  |  | (MMbbls) |  | (BCF) |  | (MMbbls) |  | (MMbbls) |
PROVED |  |  |  |  |  |  |  |  |  | PROBABLE |  |  |  |  |  |  |  |  |
Developed |  |  |  |  |  |  |  |  |  | Developed |  |  |  |  |  |  |  |  |
North Sea (4) |  | 72 |  | 29 |  | — |  | — |  | North Sea (4) |  | 36 |  | 23 |  | — |  | — |
Other International (6), (7) |  | 38 |  | 93 |  | — |  | — |  | Other International (6), (7) |  | 30 |  | 42 |  | — |  | — |
North America Onshore |  | 35 |  | 1 229 |  | — |  | — |  | North America Onshore |  | 6 |  | 282 |  | — |  | — |
East Coast Canada |  | 41 |  | — |  | — |  | — |  | East Coast Canada |  | 39 |  | — |  | — |  | — |
Oil Sands In-situ |  | — |  | — |  | 152 |  | 22 |  | Oil Sands In-situ |  | — |  | — |  | 69 |  | 8 |
Oil Sands Mining (8) |  | — |  | — |  | 1 899 |  | — |  | Oil Sands Mining (8) |  | — |  | — |  | 287 |  | — |
Total Developed |  | 186 |  | 1 351 |  | 2 051 |  | 22 |  | Total Developed |  | 111 |  | 347 |  | 356 |  | 8 |
Undeveloped |  |  |  |  |  |  |  |  |  | Undeveloped |  |  |  |  |  |  |  |  |
North Sea (4) |  | 69 |  | — |  | — |  | — |  | North Sea (4) |  | 36 |  | 50 |  | — |  | — |
Other International (6), (7) |  | 6 |  | 294 |  | — |  | — |  | Other International (6), (7) |  | 31 |  | 222 |  | — |  | — |
North America Onshore |  | 7 |  | 48 |  | — |  | — |  | North America Onshore |  | 9 |  | 211 |  | — |  | — |
East Coast Canada |  | 26 |  | — |  | — |  | — |  | East Coast Canada |  | 60 |  | — |  | — |  | — |
Oil Sands In-situ |  | — |  | — |  | 514 |  | 389 |  | Oil Sands In-situ |  | — |  | — |  | 507 |  | 1 336 |
Oil Sands Mining (8) |  | — |  | — |  | — |  | — |  | Oil Sands Mining (8) |  | — |  | — |  | 237 |  | — |
Total Undeveloped |  | 108 |  | 342 |  | 514 |  | 389 |  | Total Undeveloped |  | 136 |  | 483 |  | 744 |  | 1 336 |
TOTAL PROVED |  | 294 |  | 1 693 |  | 2 565 |  | 411 |  | TOTAL PROBABLE |  | 247 |  | 830 |  | 1 100 |  | 1 344 |

(1)
  Numbers in the above table are rounded to the nearest 1 MMbbls or 1 Bcf.
(2)
  The reserves data are based upon evaluations by GLJ Petroleum Consultants Ltd., Sproule Associates Limited, RPS Energy Plc and Suncor with an effective date of December 31, 2009 and does not account for any planned divestiture after the effective date. GLJ, Sproule, and RPS summary reserve reports are contained in Schedules "E", "F", "G" to our Annual Information Form dated March 5, 2010.
(3)
  Proved reserves before royalties are Suncor's working interest reserves before the deduction of Crown or other royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production. Reserve quantities after royalty also reflect net overriding royalty interests paid and received.
(4)
  Reserves in the North Sea are subject to a conventional royalty and tax regime. No royalty is payable on reserves in the U.K. sector. Royalty is payable on onshore reserves in the Netherlands.
(5)
  Proved reserves include quantities of crude oil and natural gas, which will be produced under arrangements, which involve the company or its subsidiaries in upstream risks and rewards, but which do not transfer title of the product to those companies.
(6)
  In Suncor's production sharing contracts (PSCs), after royalty proved reserves have been determined using the economic interest method and includes the company's share of future production entitlement calculated using the contract's cost recovery and profit oil terms. The entitlement reserves are then adjusted to include reserves relating to income tax payable. Under this method, reported reserves will increase as oil prices decrease (and vice versa), since the bbls necessary to achieve cost recovery change with the prevailing oil prices.
(7)
  All reserves reported in "Other International" (which include reserves in Libya, Syria, and Trinidad and Tobago) are calculated as per footnote 5.
(8)
  Due to the SEC rule change in respect to reporting mining as an oil and gas activities, Suncor has included oil sands mining reserves which would have been previously reported under Mining Guide 7. For more information, see page 30 of our Annual Information Form dated March 5, 2010.

26 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

VOLUNTARY ADDITIONAL DISCLOSURE (does not conform to U.S. disclosure requirements)

Proved and Probable Reserves Before Royalties (1), (2), (3), (5), (11)

|  | Oil and Gas Activities
|  | International |  | North America |  | Totals
|  | North Sea (4) |  | Other International (6), (7) |  | North America Onshore |  | East Coast Canada |  | In-Situ |  | Oil Sands Mining (9) |  |  |  |  |  |
|  | Crude Oil & NGL |  | Natural Gas |  | Crude Oil & NGL |  | Natural Gas |  | Crude Oil & NGL |  | Natural Gas |  | Crude Oil & NGL |  | SCO |  | Bitumen |  | SCO |  | Crude Bitumen, SCO & NGL |  | Natural Gas |  |
|  | (MMbbls) |  | (Bcf) |  | (MMbbls) |  | (Bcf) |  | (MMbbls) |  | (Bcf) |  | (MMbbls) |  | (MMbbls) |  | (MMbbls) |  | (MMbbls) |  | (MMbbls) |  | (Bcf) |  |
End of Year 2008 (10) |  | — |  | — |  | — |  | — |  | 9 |  | 734 |  | — |  | 2 565 |  | 148 |  | 2 316 |  | 5 038 |  | 734 |  |
Revisions of previous estimates (8) |  | 6 |  | (18 | ) | 6 |  | 247 |  | 15 |  | (52 | ) | 16 |  | (1 587 | ) | 1 863 |  | (72 | ) | 247 |  | 177 |  |
Sale of reserves in place |  | — |  | — |  | — |  | — |  | — |  | (6 | ) | (3 | ) | — |  | — |  | — |  | (3 | ) | (6 | ) |
Purchase of reserves in place |  | 215 |  | 98 |  | 276 |  | 618 |  | 47 |  | 1 498 |  | 213 |  | 437 |  | — |  | 638 |  | 1 826 |  | 2 214 |  |
Discoveries, extensions and improved recovery |  | 3 |  | 29 |  | 9 |  | 352 |  | 1 |  | 52 |  | 7 |  | — |  | — |  | — |  | 20 |  | 433 |  |
Production |  | (11 | ) | (8 | ) | (5 | ) | (11 | ) | (4 | ) | (146 | ) | (8 | ) | (16 | ) | (1 | ) | (88 | ) | (133 | ) | (165 | ) |
End of Year 2009 |  | 213 |  | 101 |  | 286 |  | 1 206 |  | 68 |  | 2 080 |  | 225 |  | 1 399 |  | 2 010 |  | 2 794 |  | 6 995 |  | 3 387 |  |
Proved & Probable Undeveloped Reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
End of year 2009 |  | 105 |  | 50 |  | 89 |  | 1 065 |  | 19 |  | 309 |  | 114 |  | 1 160 |  | 1 977 |  | 264 |  | 3 728 |  | 1 424 |  |

(1)
  Numbers in the above table are rounded to the nearest 1 MMbbls or 1 Bcf.
(2)
  The reserves data are based upon evaluations by GLJ Petroleum Consultants Ltd., Sproule Associates Limited, RPS Energy Plc and Suncor with an effective date of December 31, 2009 and does not account for any planned divestiture after the effective date. GLJ, Sproule, and RPS summary reserve reports are contained in Schedules "E", "F", "G" to our Annual Information Form dated March 5, 2010.
(3)
  Proved reserves before royalties are Suncor's working interest reserves before the deduction of Crown or other royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production. Reserve quantities after royalty also reflect net overriding royalty interests paid and received.
(4)
  Reserves in the North Sea are subject to a conventional royalty and tax regime. No royalty is payable on reserves in the U.K. sector. Royalty is payable on onshore reserves in the Netherlands.
(5)
  Proved reserves include quantities of crude oil and natural gas, which will be produced under arrangements, which involve the company or its subsidiaries in upstream risks and rewards, but which do not transfer title of the product to those companies.
(6)
  In Suncor's production sharing contracts (PSCs), after royalty proved reserves have been determined using the economic interest method and includes the company's share of future production entitlement calculated using the contract's cost recovery and profit oil terms. The entitlement reserves are then adjusted to include reserves relating to income tax payable. Under this method, reported reserves will increase as oil prices decrease (and vice versa), since the bbls necessary to achieve cost recovery change with the prevailing oil prices.
(7)
  All reserves reported in "Other International" (which include reserves in Libya, Syria, and Trinidad and Tobago) are calculated as per footnote 5.
(8)
  Revisions include changes in previous estimates, either upward or downward, resulting from new information (except an increase in acreage) normally obtained from drilling or production history or resulting from a change in economic factors.
(9)
  Due to the SEC rule change in respect to reporting mining as an oil and gas activities, Suncor has re-stated its mining opening balance which would have been previously reported under Mining Guide 7.
(10)
  The 2008 reserve data for legacy Suncor assets has been restated per SEC guidelines, this information was previously disclosed under NI 51-101. For more information, see page 30 of our Annual Information Form dated March 5, 2010.
(11)
  The production data in the 2009 reserve tables are estimates from the third party evaluators, and may not exactly match production shown elsewhere in this Annual Report and our Annual Information Form dated March 5, 2010. Any variance in the production numbers is deemed not material in the disclosure of these reserves.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 27

REMAINING RECOVERABLE RESOURCES (does not conform to U.S. disclosure requirements)

Besides Suncor's proved plus probable reserve holdings, we also have considerable contingent resources (see table below). GLJ prepared the estimates for legacy Suncor and Syncrude mining leases as well as the Firebag in-situ leases. Sproule audited the Fort Hills estimate. Estimates for the remainder of our contingent resources were prepared internally by qualified reserves evaluators.

Remaining Recoverable Resources Before Royalties

As at December 31, 2009 (1) |  | Conventional (MMBOEs) |  | Mining (MMBOEs) |  | In-Situ (MMBOEs) |  | Total (MMBOEs) |
Total Proved |  | 751 |  | 2 203 |  | 1 177 |  | 4 131 |
Total Probable |  | 606 |  | 591 |  | 2 232 |  | 3 429 |
Total Proved Plus Probable Reserves |  | 1 357 |  | 2 794 |  | 3 409 |  | 7 560 |
Contingent Resources (2), (5), (6) – Best Estimate (3) |  | 2 935 |  | 6 080 |  | 10 881 |  | 19 896 |
Remaining Recoverable Resources (unrisked) (4) |  | 4 292 |  | 8 874 |  | 14 290 |  | 27 456 |

(1)
  Numbers in the above table are rounded to the nearest 1 million. MMBOE means millions of barrels of oil equivalent and is comprised of all liquids: 1 MMbbl = 1 MMboe and natural gas: 6 bcf = 1 MMBOE.
(2)
  Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce the contingent resources.
(3)
  Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is generally prepared independent of the risks associated with achieving commercial production.
(4)
  Remaining recoverable resources (unrisked) are the arithmetic sum of proved and probable reserves and best estimate contingent resources. Suncor has not quantified potentially recoverable volumes from either undiscovered accumulations or its carbonate leases. The contingent resources have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may be recovered. Actual recovery may be less.
(5)
  Our contingent resources are composed primarily of resources from: (i) (in-situ) Firebag, Lewis, Meadow and Chard; (ii) (mining) Voyager South, Audette (North Leases), Fort Hills and Syncrude; and (iii) (conventional) Arctic Islands and MacKenzie corridor, Libya, Hebron/BenNevis, Labrador, White Rose, Hibernia, Terra Nova, Trinidad and Tobago and the North Sea.
(6)
  All mining and in-situ contingent resources are stated in SCO.

Remaining recoverable resources were 27,456 millions of barrels of oil equivalent at December 31, 2009. The increase in 2009 was primarily due to the merger with Petro-Canada.

Approximately 85% of our contingent resources are associated with our long term mining and in-situ growth projects. The remaining contingent resources are associated with our frontier North America and International assets. Contingent resources may require additional delineation drilling, future corporate approval to proceed with development, additional regulatory approvals and other commercial factors to be put in place.

Remaining recoverable resources are the best estimate of Suncor's total resource assets, which form the basis of our long term business plans and production growth. Management believes that this metric is also useful in comparing Suncor's resource base to that of our competitors. Readers are cautioned that the manner in which remaining recoverable resources are calculated may differ across companies and for that reason, direct comparisons may not be possible in some instances.

Estimates of contingent resources have not been adjusted for risk based on the chance of development. Such estimates are not estimates of volumes that may be recovered and actual recovery is likely to be less and may be substantially less or zero. There is no certainty as to the timing of such development.

There is no certainty that all or any portion of the contingent resource will be commercially viable to produce. For movement of resources to reserves categories, all projects must have an economic depletion plan and may require, among other things: (i) additional delineation drilling and/or new technology for unrisked contingent resources; (ii) regulatory approvals; and (iii) company approvals to proceed with development, among other things.

For a discussion of the properties and projects that are associated with our remaining recoverable resources, see our Annual Information Form dated March 5, 2010.

28 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2009, our chief executive officer and chief financial officer concluded that our 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 us in reports that we file or submit 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, 2009, there were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) – 15d-15(f)) that occurred during 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We will continue to periodically evaluate our 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, 2009, based on that evaluation, the company's internal controls were found to be operating free of any material weaknesses.

On August 1, 2009, Suncor completed its merger with Petro-Canada. As permitted by the Securities and Exchange Commission, management has excluded Petro-Canada from its evaluation of the effectiveness of Suncor's internal control over financial reporting as of December 31, 2009. Assets attributable to Petro-Canada as of August 1, 2009 represented approximately 50% of Suncor's total assets as of August 1, 2009, and revenues attributable to Petro-Canada for the period August 1 – December 31, 2009 represented approximately 25% of Suncor's total revenues for the year ended December 31, 2009.

The effectiveness of our internal control over financial reporting as at December 31, 2009 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, 2009.

Based on their inherent limitations, disclosure control 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.

CHANGES IN ACCOUNTING POLICIES

(a) Goodwill and Intangible Assets

On January 1, 2009, the company retroactively adopted Canadian Institute of Chartered Accountants (CICA) Handbook section 3064 "Goodwill and Intangible Assets." This new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs," and focuses on the criteria for asset recognition in the financial statements, including those internally developed. The impact of adopting this standard resulted in a change in the classification of our deferred maintenance shutdown costs that had previously been classified within other assets and amortized over the period to the next shutdown. At December 31, 2008, property, plant and equipment was increased by $566 million, with an equal and offsetting reduction to other assets.

(b) Financial Instruments Disclosures

On September 30, 2009, the company prospectively adopted amendments to CICA Handbook section 3862 "Financial Instruments: Disclosures". The section has been amended to include additional disclosure requirements about fair value measurements of financial instruments and to enhance liquidity risk disclosure requirements. The additional disclosures required by these amendments are provided in note 4 to the December 31, 2009 audited Consolidated Financial Statements.

(c) Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

On January 1, 2009, the company adopted the recommendations of CICA Emerging Issues Committee Abstract 173 relating to the fair value of financial assets and liabilities. The Abstract requires that an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. The Abstract is to be applied retroactively without restatement of prior periods. The company has evaluated the new abstract and concluded that the adoption of the new requirements did not have a material impact on Suncor's financial statements.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 29

(d) International Financial Reporting Standards

In February 2008, the Canadian Accounting Standards Board confirmed that International Financial Reporting Standards (IFRS) will replace Canadian GAAP in 2011 for publicly accountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies that must be evaluated.

The company has successfully completed the integration of the legacy Petro-Canada and Suncor's IFRS conversion projects. Key activities included integrating the project plans, reviewing the accounting documentation, aligning the IFRS accounting conclusions, and reviewing the design of the Information Technology dual reporting solutions.

The company is currently engaged in the implementation phase of its IFRS project and continues to be on target to meet the changeover date. Please see the following table for select project activities within the implementation phase and an assessment of progress. Note that new and revised IFRS developments will be monitored throughout the project but may result in changes to the project activities described below.

IFRS Conversion Project

Key Activity |  | Key Milestones |  | Status
Financial Statement Preparation: – Identify differences in Canadian GAAP/IFRS accounting policies. – Select Suncor's ongoing IFRS policies. – Develop financial statement format. – Quantify effects of change in initial IFRS disclosure and 2010 financial statements. |  | Senior management and steering committee sign-off for all key IFRS accounting policy choices to occur during 2009. Develop draft financial statement format to occur during 2009. |  | Completed integrated technical analysis of IFRS differences. Initial analysis of IFRS accounting policy choices completed and presented to senior management including an evaluation of IFRS 1 transition exemptions. Further analysis will be ongoing throughout 2010. Prepared initial draft pro-forma financial statements and continued to review draft disclosures for the merged company.
Training: Define and introduce appropriate level of IFRS expertise for each of the following: – Financial reporting group and operating accounting staff. – Suncor management. – Audit Committee. |  | Financial reporting group and operating accounting staff training to occur during 2009 as needed. Additional training will occur throughout the project as needs are reassessed. Suncor management and Audit Committee training scheduled to occur during 2009. |  | Training and communication sessions provided for senior management, Financial Reporting and key individuals within the Business. Education and training sessions will continue throughout the company in 2010. Regular reporting and training has continued for the company's senior executive management and the Audit Committee. IFRS disclosure in the financial statements and MD&A will be updated throughout the project.
Infrastructure: Confirm that business processes and systems are IFRS compliant, including: – Program upgrades/changes. – Gathering data for disclosures. |  | Confirm that systems can address 2010 dual reporting requirements by 2009 and identify areas requiring change. Confirmation that business processes and systems are IFRS compliant will occur throughout the project. |  | Development and initial testing of approved IFRS Information Technology solution is underway including creation of IFRS dual reporting accounts. Identified business process and implementation changes and initiated detailed implementation plans.
Control Environment: – For all accounting policy changes identified, assess control design and effectiveness implications. – Implement appropriate changes. |  | All key control and design effectiveness implications to be assessed as part of the key IFRS differences and accounting policy choices through 2009. |  | Completed preliminary review of control environment and do not anticipate material changes to internal and disclosure controls over financial reporting.
External Communications: Assess the effects of key IFRS related accounting policy and financial statement changes on external communications. In particular: – Confirm 2011 investor communications are IFRS compliant regarding guidance and and expected earnings. – Monitor and update MD&A communications package. – Confirm investor relations process can respond to IFRS-related queries. |  | Analyze and publish the effect of IFRS on the financial statements throughout the project. |  | IFRS disclosures in the MD&A are updated throughout the project. Vice President, Investor Relations is part of the IFRS Steering Committee.

30 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

The company has not yet determined the full effects of adopting IFRS. The company's preliminary view of the key areas where changes in accounting policies are expected that may impact the company's consolidated financial statements are listed below. The list and comments below should not be regarded as a complete list of changes that will result from the transition to IFRS. It is intended to highlight those areas the company believes to be most significant; however, analysis of changes is still in progress and not all decisions have been made where choices of accounting policies are available. At this stage, the company has not quantified the impacts expected on its consolidated financial statements for these differences.

Note that most adjustments required on transition to IFRS will be made retrospectively, against opening retained earnings in the first comparative balance sheet. Transitional adjustments relating to those standards where comparative figures are not required to be restated because they are applied prospectively will only be made as of the first day of the year of transition.

IFRS 1 "First-Time Adoption of International Financial Reporting Standards" 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. The company is analyzing the various accounting policy choices available and will implement those determined to be most appropriate in the company's circumstances.

Property, Plant & Equipment

International Accounting Standard (IAS) 16 "Property, Plant & Equipment" and Canadian GAAP contain the same basic principles, however there are some differences. IFRS requires that significant parts of an asset be depreciated separately and depreciation commences when the asset is available for use. IFRS also permits property, plant and equipment to be measured using the fair value model or the historical cost model. The company is not planning on adopting the fair value measurement model for its property, plant and equipment.

IFRS 1 contains an elective exemption where an entity may elect to reset as the new cost basis for property, plant and equipment, its fair value at the date of transition. The company is not planning on adopting this exemption and will continue to measure its property, plant and equipment at cost.

Impairment of Assets

Impairments under IAS 36 "Impairment of Assets" are based on discounted cash flows. Under Canadian GAAP, if an asset's estimated undiscounted future cash flows are below its carrying amount a writedown is required and is determined by the amount which the carrying amount exceeds the discounted cash flows. There is no undiscounted test under IFRS. This may result in more frequent write-downs where carrying values of assets were previously supported under Canadian GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis.

In addition, under IAS 36 a favorable change in the circumstance that resulted in an impairment of an asset, other than goodwill, would trigger the requirement for a redetermination of the amount of the impairment with any reversal being recognized in income to the extent the asset had previously been impaired. Under Canadian GAAP, impairments are not reversed.

Provisions, Contingent Liabilities and Contingent Assets

IAS 37 "Provisions, Contingent Liabilities and Contingent Assets," requires a provision to be recognized when: there is a present obligation as a result of a past transaction or event; it is probable that an outflow of resources will be required to settle the obligation; and a reliable estimate can be made of the obligation. "Probable" in this context means more likely than not. Under Canadian GAAP, the criterion for recognition in the financial statements is "likely," which is a higher threshold than "probable." Therefore, it is possible that there may be some contingent liabilities, which would meet the recognition criteria under IFRS that were not recognized under Canadian GAAP.

Other differences between IFRS and Canadian GAAP exist in relation to the measurement of provisions, such as the methodology for determining the best estimate where there is a range of equally possible outcomes (IFRS uses the mid-point of the range, whereas Canadian GAAP used the low-end of the range) and the requirement under IFRS for provisions to be discounted where material. In addition, IFRS requires changes to timing, cash flow estimates and discount rates be applied prospectively. Canadian GAAP is similar; however, changes to the discount rates for ARO are only applied to the incremental increases in the liability and not the entire liability.

Share-Based Payments

IFRS 2 "Share-based Payment," requires that cash-settled share-based payments to employees are measured (both initially and at each reporting period) based on the fair values of the awards. Canadian GAAP on the other hand requires that such payments be measured based on the intrinsic values of the awards. This difference is expected to impact the accounting measurement of some of Suncor's cash-settled employee incentive plans.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 31

Income Taxes

Under IAS 12 "Income Taxes," current and deferred tax are normally recognized in the income statement, except to the extent that tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share-based payment transaction. If a deferred tax asset or liability is remeasured subsequent to initial recognition, the impact of remeasurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the remeasurement of taxes back to the item which originally triggered the recognition is commonly referred to as "backwards tracing." Canadian GAAP prohibits backwards tracing except on business combinations and financial reorganizations.

Employee Benefits

IAS 19 "Employee Benefits," requires the past service cost element of defined benefit plans to be expensed on an accelerated basis, with vested past service costs expensed immediately and unvested past service costs recognized on a straight line basis until the benefits become vested. Under Canadian GAAP, past service costs are generally amortized on a straight line basis over the expected average remaining service period of active employees in the plan. In addition, actuarial gains and losses are permitted under IAS 19 to be recognized directly in equity rather than through profit or loss. IFRS 1 also provides an option to recognize all cumulative actuarial gains and losses existing at the date of transition immediately in retained earnings.

RECENTLY ISSUED CANADIAN ACCOUNTING STANDARDS

Business Combinations

In January 2009, the CICA issued section 1582 "Business Combinations" to replace section 1581. The CICA concurrently issued section 1601 "Consolidated Financial Statements" and section 1602 "Non-Controlling Interests" which replace section 1600 "Consolidated Financial Statements." Prospective application of the standards is effective for fiscal years beginning on or after January 1, 2011, with early adoption permitted. The new standards revise guidance on the determination of the carrying amount of the assets acquired and liabilities assumed, goodwill and accounting for non-controlling interests at the time of a business combination. The company applied section 1581 to the Petro-Canada business combination; however, the company will continue to consider the application of section 1582 to business combinations in 2010.

32 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

OIL SANDS

Located in northeast Alberta, our oil sands business forms the foundation of our operations and represents the most significant portion of our assets. Our oil sands operations recover bitumen through mining and in-situ development and upgrade it into refinery feedstock, diesel fuel and byproducts. Our marketing plan also allows for sales of bitumen when market conditions are favourable or when operating conditions warrant. The majority of our oil sands assets are owned and operated solely by Suncor. Following the merger with Petro-Canada, our oil sands business also includes a 12% share in the Syncrude oil sands joint venture and a 60% share in the proposed Fort Hills oil sands project.

Oil sands strategy focuses on:

•
  Developing long-life leases with substantial bitumen resources in place.
•
  Sourcing low-cost bitumen supply through mining in-situ development and third-party supply agreements, and upgrading this bitumen supply into high value crude oil products.
•
  Increasing production capacity and improving reliability through staged expansion, continued focus on operational excellence and worksite safety.
•
  Reducing costs through the application of technologies, economies of scale, direct management of growth projects, strategic alliances with key suppliers and continuous improvement of operations.
•
  Pursuing new technology applications to increase production, mitigate costs and reduce environmental impacts.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 |  | 2008 |  | 2007 |  |
Revenue (net of royalties) |  | 6 539 |  | 8 639 |  | 6 175 |  |
Production (excluding Syncrude) (thousands of bpd) |  | 290.6 |  | 228.0 |  | 235.6 |  |
Syncrude production (thousands of bpd) (1) |  | 38.5 |  | — |  | — |  |
Average sales price (excluding Syncrude) ($/barrel) |  | 61.26 |  | 95.96 |  | 74.01 |  |
Net earnings |  | 557 |  | 2 875 |  | 2 474 |  |
Operating earnings (2) |  | 1 066 |  | 2 522 |  | 2 137 |  |
Cash flow from operations (2),(3) |  | 1 251 |  | 3 507 |  | 3 165 |  |
Total assets |  | 37 553 |  | 25 795 |  | 18 172 |  |
Cash used in investing activities |  | (3 546 | ) | (6 996 | ) | (4 248 | ) |
Sales mix (light/heavy mix) |  | 47/53 |  | 43/57 |  | 54/46 |  |
Cash operating costs (excluding Syncrude) ($/barrel) (2) |  | 33.95 |  | 38.50 |  | 27.80 |  |
ROCE (%) (2), (4) |  | 4.2 |  | 35.5 |  | 43.0 |  |
ROCE (%) (2), (5) |  | 2.5 |  | 21.8 |  | 27.9 |  |

(1)
  Reflects results of operations since the merger with Petro-Canada on August 1, 2009.
(2)
  Non-GAAP measures. See pages 52 and 53.
(3)
  Calculation of this measure has been revised, and prior period comparative figures have been restated. See page 52.
(4)
  Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.
(5)
  Includes capitalized costs related to major projects in progress.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 33

2009 Overview

•
  Low benchmark prices and losses on derivative contracts used for risk management purposes significantly reduced Oil Sands price realizations in 2009. The average WTI crude oil price was 38% lower in 2009 than in 2008. Derivative contracts entered into to protect our future revenues ended up negatively impacting our results when crude prices strengthened later in the year, and settlement prices were lower than benchmark prices.
•
  Production (excluding proportionate production share from Syncrude joint venture) averaged 290,600 bpd in 2009, compared to 228,000 bpd in 2008, with record production reported in November 2009. Production volumes were up year-over-year primarily as the result of improved upgrader reliability and increased bitumen supply. However, unplanned maintenance following a fire in December negatively impacted production, and a subsequent fire in February 2010 will reduce production volumes in 2010.
•
  Cash operating costs for our oil sands operations (excluding Syncrude) averaged $33.95 per barrel during 2009, compared to $38.50 per barrel in 2008. The lower costs in 2009 are primarily due to the increase in production and a decrease in natural gas prices and third-party bitumen purchases. These factors were partially offset by an increase in operational expenses primarily due to the inclusion of operating costs from MacKay River as a result of the merger with Petro-Canada.
•
  In response to market uncertainty at the beginning of 2009, a revised capital spending plan deferred Oil Sands growth projects. Although the 2010 capital plan announced in November 2009 has restarted construction of certain projects, the costs associated with keeping projects in "safe mode" totalled $380 million pre-tax in 2009.

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 |  | 2008 |  | 2007 |  |
Oil Sands net earnings as reported |  | 557 |  | 2 875 |  | 2 474 |  |
| Change in fair value of commodity derivatives used for risk management |  | 499 |  | (372 | ) | — |  |
| Mark-to-market valuation of stock-based compensation |  | 28 |  | (5 | ) | 27 |  |
| Project start-up costs |  | 40 |  | 24 |  | 49 |  |
| Impact of income tax rate reductions on opening future income tax liabilities (2) |  | 37 |  | — |  | (413 | ) |
| Costs related to deferral of growth projects |  | 299 |  | — |  | — |  |
| Gain on effective settlement of pre-existing contract with Petro-Canada (3) |  | (438 | ) | — |  | — |  |
| Impact of recording acquired inventory at fair value (4) |  | 5 |  | — |  | — |  |
| Losses and adjustments on significant disposals (5) |  | 39 |  |  |  |  |  |
Oil Sands operating earnings |  | 1 066 |  | 2 522 |  | 2 137 |  |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  In the third quarter of 2009, an increase in the future income tax liabilities resulted from a revised provincial allocation for income tax purposes due to the merger with Petro-Canada. This was partially offset for the year ended December 31, 2009 by a reduction to the Ontario income tax rate in the fourth quarter of 2009, resulting in a decrease in the future income tax liabilities. See note 7 to the Consolidated Financial Statements.
(3)
  Impact from deemed settlement value assigned to bitumen processing contract with Petro-Canada upon close of merger (see note 2 to the Consolidated Financial Statements).
(4)
  Inventory acquired through the merger at fair value was sold during the third quarter of 2009, resulting in a one-time negative impact to earnings
(5)
  Includes loss recognized when a highway interchange constructed by Suncor was transferred to the Provincial government of Alberta.

Net earnings were $557 million in 2009, compared to $2.875 billion in 2008 (2007 – $2.474 billion). Operating earnings for 2009 were $1.066 billion, compared to $2.522 billion in 2008 (2007 – $2.137 billion). Earnings decreased primarily as a result of lower average price realizations for oil sands crude products, partially offset by higher production and sales volumes.

34 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

The decrease in price realizations reflects significantly lower benchmark West Texas Intermediate (WTI) crude oil prices, as well as realized losses of approximately $315 million after-tax on risk management derivative contracts as the settlement prices were lower than benchmark prices for much of the year. This was partially offset by a decreased discount to WTI on our sweet crude blends and sour crude blends, increased sales of higher value sweet crude products, and a weaker Canadian dollar.

Oil Sands Production

Year ended December 31 |  |  |
Thousands of barrels per day |  | 2009 |  | 2008 |  | 2007 |  | 2006 |  | 2005 |
Oil Sands production (excluding Syncrude) |  | 290.6 |  | 228.0 |  | 235.6 |  | 260.0 |  | 171.3 |
Syncrude (1) |  | 38.5 |  | — |  | — |  | — |  | — |

(1)
  Reflects our share of Syncrude production since the merger with Petro-Canada on August 1, 2009.

Oil Sands average production (excluding Syncrude) was 290,600 bpd in 2009, compared to 228,000 bpd in 2008. Production was higher in 2009 due mainly to improved upgrader reliability and increased bitumen supply. In addition, production in 2008 was negatively impacted by planned and unplanned maintenance shutdowns in our upgrading and extraction assets, as well as a regulatory cap on our Firebag in-situ operations, which was lifted in July 2008.

As a result of the merger, Suncor holds a 12% share in the Syncrude joint venture oil sands operations located close to Suncor's existing oil sands operations in Fort McMurray, Alberta, Canada. Syncrude operations contributed an additional average 38,500 bpd of sweet synthetic crude production in the last five months of 2009.

The merger with Petro-Canada did not result in increased oil sands production (excluding Syncrude), as production from MacKay River was included historically in Suncor's reported production from January 1 to July 31, 2009 as volumes processed by Suncor under a processing fee agreement. However, the addition of MacKay River has resulted in increased sales volumes for Oil Sands, as volumes under the processing agreement were not previously included in sales from January 1 to July 31, 2009.

Sales volumes in 2009 averaged 276,200 bpd, compared with 227,000 bpd in 2008. The increase was due primarily to increased production in legacy Suncor's oil sands operations and the addition of sales volumes from MacKay River as a result of the merger.

Production for 2009 was reduced due to unplanned maintenance activities following a December 2009 fire at one of our upgraders. Overall average production volumes in 2009 were impacted by approximately 7,600 barrels per day as a result of the fire. Repairs of the upgrader were completed and operations returned to normal in early February 2010.

Sales price realizations averaged $61.26 per barrel in 2009, compared with $95.96 per barrel in 2008. This was primarily due to a significant decrease in the average benchmark WTI crude oil price of about 38%. This was partially offset by a decreased discount to WTI on our sweet crude blends and sour crude blends and an increased proportion of higher priced sweet crude products in our sales mix.

Cash Expenses

Cash expenses increased year-over-year, primarily due to increased costs associated with higher production and sales volumes in 2009 as compared to 2008, as well as additional costs from Petro-Canada operations. These factors were partially offset by reduced energy input costs as a result of lower natural gas pricing and a decrease in purchases of third-party bitumen. Overall, increased cash expenses reduced operating earnings by $65 million.

Royalties

Alberta Crown royalties decreased in 2009 as compared to 2008, due primarily to lower benchmark WTI prices, partially offset by increased production. Oil Sands royalties are subject to completion of audits for 2009 and prior years. Changes to the estimated amounts previously recorded will be reflected in our financial statements on a prospective basis and may be significant. For a further discussion on Crown royalties, see pages 16 to 18.

Non-Cash Expenses

Non-cash expenses increased in 2009 as compared to 2008, primarily due to the addition of facilities for MacKay River and Syncrude as a result of the merger with Petro-Canada, as well as continued growth in the depreciable cost base after the commissioning of new assets throughout the year. Higher non-cash expenses decreased operating earnings by $185 million.

Tax Rate

As a result of decreases to the Oil Sands effective tax rate and taxable income in 2009 as compared to 2008, tax rate adjustments resulted in an increase to operating earnings of $94 million.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 35

Cash Operating Costs

Cash operating costs (excluding Syncrude) increased to $3.599 billion in 2009, compared to $3.212 billion in 2008. On a per barrel basis, these costs decreased to $33.95 per barrel from $38.50 per barrel in 2008. The decrease in cash operating costs per barrel is a result of an increase in production and a decrease in natural gas input prices. These factors were partially offset by an increase in operational expenses due to the inclusion of operating costs from MacKay River as of August 1, 2009. Cash operating costs per barrel does not include costs related to deferral of growth projects.

Cash operating costs for our interest in Syncrude operations averaged $32.50 per barrel for the last five months of 2009. Users are cautioned that the Syncrude cash operating costs per barrel measure may not be fully comparable to similar information calculated by other entities (including Suncor's own cash operating costs per barrel excluding Syncrude) due to differing treatments for operating and capital costs among producers.

Refer to page 52 and 53 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Net Cash Deficiency Analysis

Cash flow from operations was $1.251 billion in 2009, compared to $3.507 billion in 2008 (2007 – $3.165 billion). The decrease was primarily due to the same factors that impacted operating earnings.

Cash flow used in investing activities decreased to $3.546 billion in 2009 from $6.996 billion in 2008 (2007 – $4.248 billion). The decrease was primarily due to reduced capital spending resulting from the deferral of the company's growth projects in response to economic conditions. During 2009, capital spending related primarily to our Steepbank extraction plant and Firebag sulphur plant.

These were the primary factors that resulted in a net cash deficiency of $2.497 billion in 2009, compared with $2.555 billion in 2008 (2007 – net cash deficiency of $519 million).

Future Expansion

In January 2009, in response to market uncertainty, we deferred a number of our growth projects, pending construction restart. On November 13, 2009, Suncor's Board of Directors approved the 2010 capital budget, and we resumed construction on key growth projects.

The majority of our planned growth spending in 2010 will be directed toward the Firebag Stage 3 in-situ oil sands expansion, which was approximately 50 per cent complete before being deferred in early 2009. The project is now expected to begin production in the second quarter of 2011, with volumes then beginning to ramp up toward design capacity of approximately 68,000 barrels per day (bpd) of bitumen over a period of approximately 18 months. Spending will also be directed to Firebag Stage 4 to support a target of first bitumen production in the fourth quarter of 2012. Stage 4 also has a design capacity of 68,000 bpd. Remaining 2010 growth spending will be directed towards completion of a naphtha unit in one of our upgraders, which is intended to enhance product mix.

For further details, see the Significant Capital Project Update table on page 15.

The Oil Sands segment continued to incur costs related to placing certain growth projects into "safe mode" as a result of the company revising its 2009 capital budget due to market conditions earlier in the year. Safe mode is defined as the costs of deferring the projects and keeping the equipment and facilities in a safe manner in order to expedite remobilization. As a result of placing the company's Oil Sands projects into safe mode, pre-tax costs of $380 million were incurred in 2009. Further safe mode costs of $150 million to $200 million on a pre-tax basis, including costs related to remobilization of certain growth projects placed into safe mode, are expected to be incurred in 2010.

36 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Planned Turnarounds

We have planned turnarounds scheduled for Upgrader 2 of approximately 45 days during the second quarter of 2010 and approximately 35 days during the third quarter of 2010.

February 2010 Fire

One of our oil sands upgraders was damaged by fire in early February. We have completed our assessment and repairs are currently underway. The company expects the damaged upgrader to return to production in early April 2010.

During the repair period, the company's second upgrader is expected to continue normal operations. Combined production of synthetic crude oil and bitumen sold directly to markets during this period is targeted at an average of approximately 210,000 barrels per day (bpd) in February and 230,000 bpd in March (these volumes do not include Suncor's proportionate production share from the Syncrude joint venture). Based on the damage assessment and repair schedule, and applicable waiting periods and deductibles, the company does not expect insurance to play a significant role in mitigating losses from this incident.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•
  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. Also refer to Liquidity and Capital Resources on page 13.
•
  Bitumen supply. Ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in-situ reservoir and equipment performance could impact 2010 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.
•
  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 such strategies 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 crude oil and natural gas prices, foreign exchange rates and the light/heavy and sweet/sour crude oil differentials. We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 20).
•
  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. 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 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. The Communications, Energy and Paperworkers Union Local 707 represents approximately 2,900 Oil Sands employees. The current collective agreement with the union expires on April 30, 2010. Negotiations are ongoing.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 20. Additional risks, assumptions and uncertainties are discussed on page 54 under Forward-Looking Information.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 37

NATURAL GAS

Suncor's Natural Gas business, operating primarily in Western Canada, acts as a natural price hedge against the company's purchases of natural gas for internal consumption.

Natural gas strategy focuses on:

•
  Upgrading our asset portfolio by divesting non-core conventional assets.
•
  Achieving a lower cost structure.
•
  Improving return on capital employed, with a focus on improved capital efficiency.
•
  Moving from an exploration to an execution focus in order to reliably and cost effectively manage our internal consumption.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 (1) |  | 2008 |  | 2007 |  |
Revenue (net of royalties) |  | 681 |  | 579 |  | 427 |  |
Western Canada gross production (mmcfe/d) |  | 412 |  | 220 |  | 215 |  |
U.S. Rockies gross production (mmcfe/d) |  | 34 |  | — |  | — |  |
Western Canada average natural gas sales price ($/mcf) |  | 3.70 |  | 8.23 |  | 6.32 |  |
U.S. Rockies average natural gas sales price ($/mcf) |  | 3.93 |  | — |  | — |  |
Net earnings (loss) |  | (199 | ) | 89 |  | 25 |  |
Operating earnings (loss) (2) |  | (187 | ) | 89 |  | (12 | ) |
Cash flow from operations (2), (3) |  | 329 |  | 367 |  | 251 |  |
Cash used in investing activities |  | (312 | ) | (316 | ) | (532 | ) |
Total assets |  | 5 003 |  | 1 862 |  | 1 811 |  |
ROCE (%) (2), (4) |  | (8.4 | ) | 7.7 |  | 2.5 |  |

(1)
  Amounts for 2009 includes the results of five months of legacy Petro-Canada operations since the close of the merger on August 1, 2009.
(2)
  Non-GAAP measures. See pages 52 and 53.
(3)
  Calculation of this measure has been revised, and prior period comparative figures have been restated. See page 52.
(4)
  ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.

2009 Overview

•
  Low benchmark prices significantly reduced Natural Gas price realizations in 2009. The average natural gas spot price at AECO was approximately 50% lower in 2009 than in 2008.
•
  Post-merger production from Suncor's Natural Gas business during the last five months of 2009 averaged 767 million cubic feet equivalent (mmcfe) per day, comprised of 88% natural gas and 12% natural gas liquids and crude oil. Production from legacy Suncor's natural gas operations averaged 210 mmcfe per day in 2009 compared to 220 mmcfe per day in 2008.
•
  Suncor has begun the process of divesting of a number of non-core natural gas assets.
  •
    On December 31, 2009, Suncor entered into an agreement to sell substantially all of its oil and gas producing assets in the U.S. Rockies for proceeds of $517 million (US$494 million) before closing adjustments. The effective close date of the sale was March 1, 2010.
  •
    On February 9, 2010, Suncor entered into an agreement to sell certain non-core natural gas properties located in northeast British Columbia for proceeds of $390 million. The sale is expected to close in March 2010 and is subject to customary closing conditions and regulatory approvals.

(1)
  Reflects only the results of the five months of operations after the merger with Petro-Canada on August 1, 2009.
(2)
  In 2009, purchases represent all internal consumption within our North American operations, while in prior periods purchases for internal consumption were for our oil sands operations only.

38 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 |  | 2008 |  | 2007 |  |
Natural Gas net earnings (loss) as reported |  | (199 | ) | 89 |  | 25 |  |
| Mark-to-market valuation of stock-based compensation |  | 11 |  | — |  | 2 |  |
| Impact of income tax rate adjustments on future income tax liabilities (2) |  | 1 |  | — |  | (39 | ) |
Natural Gas operating earnings (loss) |  | (187 | ) | 89 |  | (12 | ) |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  In the third quarter of 2009, an increase in future income tax liabilities resulted from a revised provincial allocation for income tax purposes due to the merger with Petro-Canada. This was partially offset for the year ended December 31, 2009 by a reduction to the Ontario income tax rate in the fourth quarter of 2009, resulting in a decrease in future income tax liabilities. See note 7 to the Consolidated Financial Statements.

Natural Gas recorded a net loss of $199 million in 2009, compared to net earnings of $89 million in 2008 (2007 – net earnings of $25 million). The operating loss was $187 million in 2009, compared to operating earnings of $89 million in 2008 (2007 – operating loss of $12 million). The decrease in earnings was primarily due to significantly lower benchmark commodity prices, higher operating, selling and general and depreciation, depletion and amortization expense resulting from the merger with Petro-Canada, decreased legacy Suncor production due to shut-in volumes in the Elmworth area and the sale of certain non-core assets in the second quarter of 2009, lower sulphur revenue and higher dry hole costs. This was partially offset by lower royalty expense in 2009 compared to 2008 as a result of lower revenues, royalty credits and reduced rates due to the implementation of the Alberta New Royalty Framework.

The average realized price for natural gas was $3.71 per thousand cubic feet (mcf) in 2009, compared to an average of $8.23 per mcf in 2008, reflecting significantly lower benchmark natural gas prices. There was also a decrease in price realizations for crude oil and natural gas liquids, as well as sulphur, resulting from lower benchmark prices for those products in 2009. The net impact of the price variance was a decrease in operating earnings of $280 million.

Natural Gas Production

Year ended December 31 Average mmcfe per day |  | 09 |  | 08 |  | 07 |  | 06 |  | 05 |
Legacy Suncor operations |  | 210 |  | 220 |  | 215 |  | 209 |  | 209 |

Average mmcfe per day |  | 2009 (1) |
Legacy Petro-Canada Western Canada |  | 482 |
Legacy Petro-Canada U.S. Rockies |  | 80 |
Total legacy Petro-Canada Natural Gas production |  | 562 |

(1)
  Production for 2009 is only the results of five months of operations since the merger with Petro-Canada on August 1, 2009

After completion of the merger with Petro-Canada, Suncor's natural gas production during the last five months of 2009 averaged 767 million cubic feet equivalent (mmcfe) per day, comprised of 88% natural gas and 12% natural gas liquids and crude oil. Production from legacy Suncor's natural gas operations averaged 210 mmcfe per day in 2009 compared to 220 mmcfe per day in 2008 which decreased primarily due to shut-in production in the Elmworth area as a result of low commodity prices and the sale of certain non-core assets during the second quarter of 2009.

Cash Expenses

Cash expenses decreased in 2009 as compared to 2008, primarily due to lower production from our legacy Suncor natural gas operations. Overall, decreased cash expenses increased operating earnings by $4 million.

Lifting and Administration Costs

($/mcfe) |  | 05 |  | 06 |  | 07 |  | 08 |  | 09 (1) |
Administration |  | 0.42 |  | 0.67 |  | 0.70 |  | 0.56 |  | 0.53 |
Lifting |  | 0.86 |  | 0.91 |  | 1.26 |  | 1.38 |  | 1.35 |
Total |  | 1.28 |  | 1.58 |  | 1.96 |  | 1.94 |  | 1.88 |

(1)
  Amounts for 2009 includes the results of five months of legacy Petro-Canada operations since the close of the merger on August 1, 2009.

Non-Cash Expenses

Non cash expenses increased in 2009 as compared to 2008, primarily due to higher dry hole costs in 2009. Overall, increased non-cash expenses decreased operating earnings by $39 million.

Royalties

Royalties on production of natural gas, liquids and sulphur were $85 million ($0.53 per thousand cubic feet equivalent (mcfe)) in 2009, a decrease from $175 million

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 39

($2.17 per mcfe) in 2008 (2007 – $126 million; $1.61 per mcfe). The decrease in royalty expense for the year was due to significantly lower benchmark commodity prices, royalty credits and reduced rates due to the implementation of the Alberta New Royalty Framework, which was partially offset by increased royalty expense as a result of the merger. For a further discussion on Crown royalties, see page 18.

Overall, decreased royalties increased operating earnings by $105 million.

Net Cash Surplus (Deficiency) Analysis

Natural Gas net cash surplus was $8 million in 2009, compared with $94 million in 2008 (2007 – net cash deficiency of $262 million). Cash flow from operations decreased to $329 million, compared with $367 million in 2008 (2007 – $251 million), impacted by the same factors that affected net earnings, excluding the impact of dry hole costs.

Cash used in investing activities decreased to $312 million, compared with $316 million in 2008 (2007 – $532 million) primarily due to a decrease in drilling activity in 2009, partially offset by the inclusion of five months of Petro-Canada results.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•
  Consistently and competitively finding and developing reserves that can be brought on stream economically.
•
  Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 13.
•
  Volatility in natural gas and liquids prices is not predictable and can significantly impact revenues.
•
  The accessibility and cost of mineral rights. Market demand influences the cost and available opportunities for mineral leases and acquisitions.
•
  Risk associated with a depressed market for asset sales, leading to losses on disposition.
•
  Risk in our ability to successfully change focus from a conventional to unconventional gas producer.
•
  Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in our operating areas. These risks could increase costs and/or cause delays to or cancellation of projects.
•
  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.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 20. Additional risks, assumptions and uncertainties are discussed on page 54 under Forward-Looking Information.

40 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

EAST COAST CANADA

Suncor has a strong position in every major producing oil development off Canada's east coast. The company holds a 20% interest in Hibernia, a 27.5% interest in White Rose * and a 22.7% interest in Hebron, and is the operator of Terra Nova with a 34% ** interest.

The East Coast Canada strategy focuses on:

•
  Delivering top quartile operating performance and maximizing cash flow.
•
  Sustaining profitable production through reservoir extensions and add-ons.
•
  Pursuing high potential, near field development and exploration projects.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 (1) |  |
Revenue (net of royalties) |  | 441 |  |
Production (bpd) |  | 58 000 |  |
Average sales price ($/bbl) |  | 76.86 |  |
Net earnings |  | 112 |  |
Operating earnings (2) |  | 111 |  |
Cash flow from operations (2) |  | 335 |  |
Total assets |  | 4 771 |  |
Cash used in investing activities |  | (152 | ) |
ROCE (%) (2), (3) |  | 10.7 |  |
ROCE (%) (2), (4) |  | 6.5 |  |

(1)
  Reflects the results of operations since the merger with Petro-Canada on August 1, 2009.
(2)
  Non-GAAP measures. See pages 52 and 53.
(3)
  Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.
(4)
  Includes capitalized costs related to major projects in progress.

2009 Overview

•
  Total production volume averaged 58,000 bpd in the last five months of 2009. Production was lower than capacity as a result of planned and unplanned maintenance, including the successful completion of the subsea tie-in of the North Amethyst extension at White Rose.
•
  Average crude sales price was $76.86 per barrel during the last five months of 2009. Sales price realizations were negatively impacted by low benchmark prices.

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 (1) |  |
East Coast Canada net earnings as reported |  | 112 |  |
| Mark-to-market valuation of stock-based compensation |  | 2 |  |
| Impact of income tax rate reductions on opening future income tax liabilities (2) |  | (20 | ) |
| Impact of recording acquired inventory at fair value (3) |  | 17 |  |
East Coast Canada operating earnings |  | 111 |  |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  In the fourth quarter of 2009, a decrease in the future income tax liabilities resulted from a reduction to the Ontario income tax rate. See note 7 to the Consolidated Financial Statements.
(3)
  Inventory acquired through the merger at fair value was sold during 2009, resulting in a one-time negative impact to earnings.

Net earnings for East Coast Canada were $112 million in 2009, while operating earnings for 2009 were $111 million. Lower than capacity production as a result of planned and unplanned maintenance, as well as the tie-in of the North Amethyst extension at White Rose, adversely impacted earnings in the period.

East Coast Canada Net Production (1)

Five months ended December 31 Barrels per day |  | 2009 |
Terra Nova |  | 20 800 |
Hibernia |  | 27 200 |
White Rose |  | 10 000 |
Total East Coast Canada net production |  | 58 000 |

(1)
  Production since the close of the merger on August 1, 2009

In the five months ended December 31, 2009, East Coast Canada production averaged 58,000 bpd. Terra Nova production averaged 20,800 bpd, with production impacted by planned and unplanned maintenance during August, September and early October. Production from Hibernia averaged 27,200 bpd for the five months ended December 31, 2009, with strong reservoir capability and facility reliability in the period. White Rose production averaged 10,000 bpd during the five months ended December 31, 2009, with production negatively impacted by planned downtime for maintenance and the tie-in of the North Amethyst extension during the period.

*
  Suncor holds a 26.125% interest in the White Rose North Amethyst and West White Rose extensions.
**
  Under the Terra Nova Development and Operating Agreement, a redetermination of working interests is required following payout. The owners have been working through a process to redetermine what the future working interests will be. This process is ongoing.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 41

Sales volumes in the five months ended December 31, 2009 averaged 58,000 bpd, impacted by the same factors affecting production, and average realized crude oil price was $76.86 per barrel.

Non-cash expenses were impacted by an increase in the depreciable asset base for Hibernia, White Rose and Terra Nova as a result of the fair value allocation upon merger. Cash expenses were in line with expectations for the period.

Royalties

East Coast Canada royalties were $217 million ($23.82 per barrel) in 2009, averaging 33% of gross revenue. Terra Nova production was subject to a Tier I royalty of 30% of net revenue and a Tier II royalty of an incremental 12.5% of net revenue. White Rose production was subject to a Tier I royalty of 20% of net revenue and a Tier II royalty of 10% of net revenue. The royalty rate on Hibernia production increased from 5% of gross revenue to 30% of net revenue during 2009 based on the terms of the Hibernia Royalty Agreement and a Memorandum of Understanding. In addition, Hibernia production was subject to a federal government net profits interest of up to 10% of net revenue.

For a further discussion on Crown royalties, see page 18.

Net Cash Surplus Analysis

East Coast Canada's net cash surplus was $149 million in 2009. Cash flow from operations was $335 million in 2009, impacted by the same factors affecting earnings. Cash used in investing activities was $152 million primarily due to work performed on East Coast Canada growth projects, including the North Amethyst and Hibernia South extension projects.

Growth Update

Installation of subsea infrastructure is complete and development drilling continues for the North Amethyst portion of the White Rose Extensions, with first oil targeted during the second quarter of 2010. Development drilling of North Amethyst will continue through 2012.

Preliminary engineering and design activities continued for the Hebron project during 2009.

Drilling commenced during 2009 on the Hibernia South Extension project, in which the company holds a 19.5% interest, with production expected to begin in the first quarter of 2010. Final fiscal agreements were made between co-venturers and the Government of Newfoundland and Labrador in February 2010.

For further details, see the Significant Capital Project Update table on page 15.

Planned Turnarounds

During the second quarter of 2010, we have planned turnarounds scheduled of approximately 18 days for Terra Nova and 12 days for Hibernia. In addition, we have a planned turnaround scheduled for White Rose of approximately 20 days during the third quarter of 2010 and a planned turnaround during the fourth quarter of 2010 of approximately 10 days scheduled for Terra Nova.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•
  Consistently and competitively finding and developing reserves that can be brought on stream economically.
•
  Volatility in crude oil prices is not predictable and can significantly impact revenues.
•
  Performance after completion of maintenance 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 bringing on new production.
•
  Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 13.
•
  Risks associated with applicable legal and other regulatory requirements, including changes to tax, environmental and other legal and regulatory requirements, the outcome of which is not predictable and could result in changes to the company's planned investments, and rates of return on the company's existing investments.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 20. Additional risks, assumptions and uncertainties are discussed on page 54 under Forward-Looking Information.

42 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

INTERNATIONAL

Suncor has International activities in two core areas: the North Sea (the United Kingdom (U.K.), the Netherlands and Norway sectors) and Other International areas (Libya, Syria, and offshore Trinidad and Tobago).

The International strategy focuses on:

•
  Delivering top quartile operating performance and maximizing cash flow.
•
  Sustaining profitable production through reservoir extensions and add-ons.
•
  Pursuing high potential, near field development and exploration projects.
•
  Divesting non-core North Sea assets (The Netherlands and other U.K.), as well as Trinidad and Tobago.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 (1) |  |
Revenue (net of royalties) |  | 1 183 |  |
North Sea net production (boe/d) |  | 76 500 |  |
Other International net production (boe/d) |  | 44 300 |  |
Average North Sea sales price ($/bbl) |  | 71.63 |  |
Average Other International sales price ($/boe) |  | 61.25 |  |
Net earnings |  | 165 |  |
Operating earnings (2) |  | 223 |  |
Cash flow from operations (2) |  | 616 |  |
Total assets |  | 9 913 |  |
Cash used in investing activities |  | (483 | ) |
ROCE (%) (2), (3) |  | 11.5 |  |
ROCE (%) (2), (4) |  | 7.5 |  |

(1)
  Reflects the results of operations since the merger with Petro-Canada on August 1, 2009.
(2)
  Non-GAAP measures. See pages 52 and 53.
(3)
  Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.
(4)
  Includes capitalized costs related to major projects in progress.

2009 Overview

•
  Net production volumes averaged 120,800 boe per day in the last five months of 2009.
•
  Production in the North Sea was lower than capacity as a result of planned maintenance shutdowns. After completion of the shutdown at the Buzzard development in the third quarter of 2009, production did not return to full production capacity as quickly as planned, but this development was back operating at expected capacity by year-end.
•
  Production in Libya was adversely impacted by OPEC production quota constraints.
•
  Average sales price in the last five months of 2009 was $71.63 per barrel for the North Sea, and $61.25 per boe for Other International. The combined average sales price for the International segment in this period was $67.82 per boe.
•
  Suncor has announced plans to divest of a number of non-core assets from the International segment. The proposed divestments identified to date include all Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands.

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 |
International net earnings as reported |  | 165 |
| Mark-to-market valuation of stock-based compensation |  | 8 |
| Impact of recording acquired inventory at fair value (2) |  | 8 |
| Losses and adjustments on significant disposals (3) |  | 42 |
International operating earnings |  | 223 |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  Inventory acquired through the merger at fair value was sold during 2009, resulting in a one-time negative impact to earnings.
(3)
  Fair value adjustments to assets acquired in the merger with Petro-Canada.

Net earnings for International were $165 million in the five months ended December 31, 2009, while operating earnings for the same period were $223 million. Lower than capacity production as a result of planned and unplanned maintenance, as well as OPEC quota constraints, adversely impacted earnings in the period. These factors were partially offset by improved price realizations.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 43

International Net Production (1)

Five months ended December 31 Boe per day |  | 2009 |
U.K. sector of the North Sea |  | 63 300 |
The Netherlands sector of the North Sea |  | 13 200 |
North Sea |  | 76 500 |
Other International |  | 44 300 |
Total International net production |  | 120 800 |

(1)
  Production since the close of the merger with Petro-Canada on August 1, 2009

International net production averaged 120,800 boe per day in the five months ended December 31, 2009. Net production from the Buzzard development in the U.K. sector of the North Sea averaged 47,800 boe per day in the same period, impacted by a planned four-week shutdown during the third quarter of 2009. In the Netherlands sector of the North Sea, production was 13,200 boe per day for the five months ended December 31, 2009.

Other International consists of producing assets in Libya and Trinidad and Tobago. Production in Libya averaged 32,600 boe per day in the five months ended December 31, 2009, with production impacted by OPEC production quota constraints. Trinidad and Tobago offshore gas production averaged 11,700 boe per day in the same period, with high demand from the Atlantic liquefied natural gas terminal.

The average sales price for North Sea production was $71.63 per barrel in the five months ended December 31, 2009, while the average sales price for Other International was $61.25 per barrel of oil equivalent.

During 2009, planned maintenance shutdowns occurred at the Buzzard and Hanze facilities in the North Sea, resulting in reduced production. In late September 2009, planned turnaround and maintenance commenced at the Triton facility in the U.K. sector of the North Sea and was completed in early October, affecting overall production in 2009.

Cash Expenses

Cash expenses for 2009 were impacted by maintenance expenses incurred in the period, as well as the continued seismic program in Libya.

Non-Cash Expenses

Non-cash expenses were impacted by an increase in the depreciable base for assets as a result of the fair value allocation upon merger and dry hole costs incurred in the U.K. and The Netherlands.

Net Cash Surplus Analysis

International's net cash surplus was $98 million in 2009. Cash flow from operations was $616 million in 2009, impacted by the same factors affecting earnings. Cash used in investing activities was $483 million primarily due to work performed to advance International growth projects, including the Buzzard Enhancement project and Ebla Gas project.

Growth Update

Syria

The Ebla Gas Project remains on plan for first gas delivery in mid 2010 and was 90% complete at the end of 2009. Five gas wells have been completed and are ready for production. The 3D seismic acquisition of the Cherrife field was completed during the third quarter of 2009 and is currently being interpreted, while the 3D seismic survey of the Ash Shaer field was completed during the second quarter of 2009 and is also now being interpreted.

For further details, see the Significant Capital Project Update table on page 15.

Libya

Work has commenced on implementing the projects associated with the Libya Exploration and Production Sharing Agreements (EPSAs), with a focus on preparing the EPSA field development programs and progressing with the new exploration program. Work on the exploration program is progressing, with seven seismic surveys completed in 2009 and two seismic crews continue to acquire data in country. Seismic surveys completed in 2009 are being processed. Drilling of the first exploration well is expected to commence early in the second quarter of 2010.

44 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Planned International Divestments

As part of its strategic business alignment and subject to Board of Directors approval, Suncor plans to divest of a number of non-core assets. The proposed divestments identified to date include all Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands.

On February 25, 2010, Suncor entered into an agreement to sell its assets in Trinidad and Tobago for proceeds of $396 million (US$380 million). The sale is expected to close in March 2010 and is subject to customary closing conditions, Trinidad and Tobago government approval and other regulatory approvals.

Planned Turnarounds

During the second quarter of 2010, we have planned turnarounds of approximately 14 days for Buzzard, 14 days for Triton, 14 days for De Ruyter and 7 days for Hanze. In the third quarter of 2010, we have scheduled planned turnarounds of approximately 21 days for Triton and 7 days for Buzzard.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•
  Consistently and competitively finding and developing reserves that can be brought on stream economically.
•
  Volatility in commodity prices is not predictable and can significantly impact revenues. Current commodity prices are well below the average price realized in the last three years.
•
  Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in our operating areas. These risks could increase costs and/or cause delays to or cancellation of projects.
•
  Risks and uncertainties associated with operations in a number of foreign countries with different political, taxation, economic and social systems. These risks could decrease revenue, increase costs and/or cause delays to or nationalization, expropriation or cancellation of production and/or projects.
•
  Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 13.
•
  Risks associated with applicable legal and other regulatory requirements, including changes to tax, environmental and other legal and regulatory requirements, the outcome of which is not predictable and could result in changes to the company's planned investments, and rates of return on the company's existing investments.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 20. Additional risks, assumptions and uncertainties are discussed on page 54 under Forward-Looking Information.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 45

REFINING AND MARKETING

Refining and Marketing operates refineries in Edmonton, Alberta, Montreal, Quebec, Sarnia, Ontario and Commerce City, Colorado with a total capacity of 443,000 bpd, as well as a lubricants plant that is the largest producer of lubricant-base stocks in Canada. In addition, Refining and Marketing markets refined products to retail, commercial and industrial customers primarily in Canada and Colorado through a combination of company-owned, branded-dealer and joint venture-operated retail stations, a large Canadian national commercial road transport network and a robust bulk sales channel. Assets also include interests in pipelines and product terminals in Canada and the U.S.

Refining and Marketing's strategy is focused on:

•
  Enhancing the profitability of refining operations by improving reliability, product yields and enhancing operational flexibility to process a variety of feedstock, including crude oil streams from oil sands operations.
•
  Creating downstream market opportunities to capture greater long-term value from oil sands production.
•
  Increasing the profitability of our retail and wholesale networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 |  | 2008 |  | 2007 |  |
Revenue |  | 12 013 |  | 9 419 |  | 8 391 |  |
Refined product sales (millions of litres) |  |  |  |  |  |  |  |
| Gasoline |  | 9 975 |  | 5 819 |  | 6 132 |  |
| Total |  | 19 672 |  | 11 529 |  | 12 228 |  |
Net earnings (loss) |  | 433 |  | (5 | ) | 442 |  |
Operating earnings breakdown: |  |  |  |  |  |  |  |
| Refining and product supply |  | 347 |  | (43 | ) | 396 |  |
| Marketing |  | 152 |  | 37 |  | 36 |  |
Total operating earnings (loss) (1) |  | 499 |  | (6 | ) | 432 |  |
Cash flow from operations (1),(2) |  | 963 |  | 248 |  | 711 |  |
Total assets |  | 10 568 |  | 4 687 |  | 4 846 |  |
Cash used in investing activities |  | (391 | ) | (256 | ) | (491 | ) |
ROCE (%) (1),(3) |  | 7.5 |  | 1.8 |  | 20.0 |  |
ROCE (%) (1),(4) |  | 7.5 |  | 1.8 |  | 17.4 |  |

(1)
  Non-GAAP measures. See pages 52 and 53.
(2)
  Calculation of this measure has been revised, and prior period comparative figures have been restated. See page 52.
(3)
  Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. Prior years have not been restated for the movement of energy trading activities to Corporate, Energy Trading and Eliminations.
(4)
  Includes capitalized costs related to major projects in progress.

2009 Overview

•
  Strong operational and positive financial performance despite a softening demand for petroleum products during 2009 as a result of poor economic conditions.
•
  After completion of the merger with Petro-Canada, Suncor's total sales of refined petroleum products during the last five months of 2009 averaged 84.8 million litres per day, including additional sales of 53.1 million litres per day resulting from the merger.
•
  Significant increase in refined product sales due to the addition of the Edmonton and Montreal refineries, national retail and wholesale businesses, and an international lubricants business as a result of the merger with Petro-Canada.
•
  The observed performance of our Edmonton refinery in 2009, after improvements completed in previous years, has enabled us to upwardly revise our nameplate capacity to 135,000 bpd from the previously disclosed 125,000 bpd. Starting January 1, 2010, refinery utilization will be calculated using the 135,000 bpd capacity.

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 |  | 2008 |  | 2007 |  |
Refining and Marketing net earnings (loss) as reported |  | 433 |  | (5 | ) | 442 |  |
| Mark-to-market valuation of stock-based compensation |  | 17 |  | (1 | ) | 7 |  |
| Impact of income tax rate reductions on opening future income tax liabilities (2) |  | (19 | ) | — |  | (17 | ) |
| Costs related to deferral of growth projects |  | 1 |  | — |  | — |  |
| Impact of recording acquired inventory at fair value (3) |  | 67 |  | — |  | — |  |
Refining and Marketing operating earnings (loss) |  | 499 |  | (6 | ) | 432 |  |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  In the fourth quarter of 2009, a decrease in the future income tax liabilities resulted from a reduction to the Ontario income tax rate. See note 7 to the Consolidated Financial Statements.
(3)
  Inventory acquired through the merger at fair value was sold during the third quarter of 2009, resulting in a one-time negative impact to earnings.

46 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

Refining and Marketing's net earnings increased to $433 million in 2009 from a net loss of $5 million in 2008 (2007 – net earnings of $442 million). Operating earnings were $499 million in 2009, compared to an operating loss of $6 million in 2008 (2007 – operating earnings of $432 million). The increase in earnings was primarily due to improved operational reliability at our existing Sarnia and Commerce City refineries that resulted in higher gross margins in 2009, compared to 2008 and the addition of assets associated with the company's merger with Petro-Canada in the third quarter of 2009, partially offset by the impact of lower overall demand for refined petroleum products associated with general economic conditions.

Refining and product supply contributed operating earnings of $347 million in 2009, up from an operating loss of $43 million in 2008. The increase was due to improved operational reliability at our existing Sarnia and Commerce City refineries and increased production resulting from the addition of the Edmonton and Montreal refineries, and the lubricants plant, as a result of the merger. These factors were partially offset by the impact of a weak business environment in 2009, resulting in softening demand for refined petroleum products.

Marketing contributed operating earnings of $152 million in 2009, up from $37 million in 2008, despite a weak business environment. The increase was due to the addition of the national Retail and Wholesale operations and the lubricants business as a result of the merger with Petro-Canada during the third quarter of 2009.

Volumes

After completion of the merger with Petro-Canada, Suncor's total sales of refined petroleum products during the last five months of 2009 averaged 84.8 million litres per day, including additional sales of 53.1 million litres per day resulting from the merger. Despite sales growth being constrained in 2009 by current economic conditions, total sales of refined petroleum products from legacy Suncor's refining and marketing operations averaged 32.6 million litres per day in 2009, compared to 31.5 million litres per day in 2008 reflecting improved refinery reliability.

Fuel Margins

Improved operational reliability at our existing Sarnia and Commerce City refineries resulted in higher gross margins in 2009, compared to 2008, as we were able to process more crude rather than purchasing refined product to meet customer commitments, which negatively impacted our margins in the comparative period.

Cash and Non-Cash Expenses

Cash expenses decreased $28 million in 2009, primarily due to lower input energy costs, as well as lower maintenance at the Sarnia and Commerce City refineries due to improved refinery reliability. Non-cash expenses increased by $25 million in 2009, primarily due to increased depreciation associated with recently completed projects and the cancellation of other partially completed projects. Overall, lower cash and non-cash expenses increased operating earnings by $3 million in 2009.

Refinery Utilization

Overall crude refinery utilization averaged 92% in 2009, with utilization for the legacy Suncor refineries averaging 96% compared to 97% in 2008. Although average utilization for the legacy Suncor refineries was down slightly from 2008, this was primarily due to an increase in capacity for both refineries effective January 1, 2009, offset by an increase in processed crude oil as a result of improved operational reliability.

Net Cash Surplus (Deficiency) Analysis

Refining and Marketing's net cash surplus was $302 million in 2009 compared to $284 million in 2008 (2007 – deficiency of $27 million). Cash flow from operations was $963 million in 2009 compared to $248 million in 2008 (2007 – $711 million). The decrease was primarily due to the same factors that impacted net earnings.

Cash used in investing activities was $391 million in 2009 compared to $256 million in 2008 (2007 – $491 million). The increase was due primarily to the addition of the Montreal and Edmonton refineries and lubricants plant as a result of the merger, as well as spending on sustaining and growth projects at our legacy Suncor refineries in 2009.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 47

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•
  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, Ontario refinery, our Commerce City, Colorado 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 a material adverse effect on our business, financial condition, results of operations and cash flow.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 20. Additional risks, assumptions and uncertainties are discussed on page 54 under Forward-Looking Information.

48 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

CORPORATE, ENERGY TRADING AND
ELIMINATIONS

Corporate, Energy Trading and Eliminations includes third-party energy supply and trading activities and activities not directly attributable to an operating segment. It also supports Suncor's sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

Operating Earnings (1)

Year ended December 31 ($ millions, after-tax) |  | 2009 |  | 2008 |  | 2007 |  |
Net earnings (loss) as reported |  | 78 |  | (822 | ) | 42 |  |
| Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt |  | (798 | ) | 852 |  | (215 | ) |
| Mark-to-market valuation of stock-based compensation |  | 58 |  | (101 | ) | (1 | ) |
| Impact of income tax rate adjustments on future income tax liabilities (2) |  | 5 |  | — |  | 42 |  |
| Merger and integration costs |  | 151 |  | — |  | — |  |
Operating loss |  | (506 | ) | (71 | ) | (132 | ) |

(1)
  Non-GAAP measure. See page 52 for a discussion of operating earnings.
(2)
  In the third quarter of 2009, an increase in the future income tax liabilities resulted from a revised provincial allocation for income tax purposes due to the merger with Petro-Canada. This was partially offset for the year ended December 31, 2009 by a reduction to the Ontario income tax rate in the fourth quarter of 2009, resulting in a decrease in the future income tax liabilities. See note 7 of the Consolidated Financial Statements.

Corporate, Energy Trading and Eliminations net earnings were $78 million in 2009, compared to a net loss of $822 million in 2008 (2007 – net earnings of $42 million). Corporate, Energy Trading and Eliminations recorded an operating loss of $506 million in 2009, compared to $71 million in 2008 (2007 – $132 million). Results reflected higher net interest expense in 2009 due to additional debt acquired through the merger with Petro-Canada and $437 million of interest costs on debt used to finance growth projects. In 2009, these interest costs were expensed while growth projects were in safe mode, compared to 2008 when interest expense was capitalized. In addition, 2009 results reflected lower energy supply and trading earnings and an increase in profits eliminated on crude oil sales between upstream segments and Refining and Marketing, where this crude oil still resides in Refining and Marketing's inventories.

Summary of Results

Year ended December 31 ($ millions) |  | 2009 |  | 2008 |  | 2007 |  |
Net earnings (loss) |  | 78 |  | (822 | ) | 42 |  |
Operating loss |  |  |  |  |  |  |  |
| Corporate |  | (457 | ) | (118 | ) | (138 | ) |
| Energy supply and trading |  | 44 |  | 56 |  | 9 |  |
| Group eliminations |  | (93 | ) | (9 | ) | (3 | ) |
Total operating loss |  | (506 | ) | (71 | ) | (132 | ) |
Cash flow used in operations |  | (695 | ) | (65 | ) | (90 | ) |
Total assets |  | 1 938 |  | 184 |  | (320 | ) |
Cash from (used in) investing activities |  | 213 |  | (22 | ) | (91 | ) |
Renewable energy net earnings |  | 28 |  | 28 |  | 31 |  |

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 49

Energy Supply and Trading Activities

Year ended December 31 ($ millions unless otherwise noted) |  | 2009 |  | 2008 |  | 2007 |  |
Settlement of non-trading physical contracts |  | 8 008 |  | 11 295 |  | 2 931 |  |
Settlement of trading physical contracts |  | 20 |  | — |  | — |  |
Gains (losses) on trading derivatives |  | (70 | ) | 127 |  | (39 | ) |
Gains on inventory valuation |  | 47 |  | — |  | — |  |
Energy Supply and Trading Activities Revenue |  | 8 005 |  | 11 422 |  | 2 892 |  |
Settlement of non-trading physical contracts |  | (7 929 | ) | (11 331 | ) | (2 871 | ) |
Operating, selling & general expense |  | (13 | ) | (11 | ) | (10 | ) |
Energy Supply and Trading Activities Earnings (pre-tax) |  | 63 |  | 80 |  | 11 |  |

These activities involve marketing and trading of crude oil, natural gas, refined products and by-products, and the use of financial derivatives. These activities resulted in pre-tax earnings of $63 million in 2009 compared to $80 million in 2008 (2007 – $11 million). Marketing and trading profits were generated primarily by transporting crude oil to more attractive markets and by holding crude oil in storage to realize higher future prices. The lower earnings in 2009 are primarily attributable to financial derivatives designed to protect the value of physical positions. A portion of the gains on financial derivatives realized in 2008, on a fair value basis, are offset by losses on the physical positions realized in 2009. For further details on our energy supply and trading activities, see page 19.

Renewable Energy

Our renewable energy interests include four wind power projects and Canada's largest ethanol plant by production volume. Net earnings from renewable energy were $28 million in 2009, compared to $28 million in 2008 (2007 – $31 million).

Our four wind projects, located in Saskatchewan, Alberta and Ontario, have a total generating capacity of 147 megawatts, offsetting the equivalent of 284,000 tonnes of carbon dioxide (CO2) per year.

The St. Clair Ethanol Plant has a current capacity of 200 million litres per year, offsetting the equivalent of 300,000 tonnes of CO2 per year. A $120 million expansion of the ethanol plant currently underway, estimated to be completed in the first quarter of 2011, is expected to double the production capacity.

50 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

OUTLOOK

During 2010, management will focus on the following priorities:

•
  Operational excellence. Focusing on operational excellence to enhance personal and process safety management, environmental excellence and sustainability, reliability, and people.
•
  Continue to focus on safety. Continue efforts to identify and reduce potential process safety hazards and implement enhanced company-wide occupational hygiene and health standards.
•
  Strengthen balance sheet. Planned capital spending has been set at $5.5 billion for 2010, with expected near-term cash flow from operations as key criteria for investment. Applying proceeds from planned divestitures to reduce net debt is expected to contribute to a target of two-times cash flow from operations.
•
  Continue efforts to reduce environmental impact intensity. We expect to reclaim the industry's first tailings pond to a trafficable surface. As well, work will continue on developing accelerated reclamation technology.

Update to Production Outlook Issued February 4, 2010

One of our oil sands upgraders was damaged by fire in February 2010. Repairs are currently underway and the company expects the damaged upgrader to return to production in early April 2010.

During the repair period, the company's second upgrader is expected to continue normal operations. Combined production of synthetic crude oil and bitumen sold directly to markets during this period is targeted at an average of approximately 210,000 barrels per day (bpd) in February and 230,000 bpd in March (these volumes do not include Suncor's proportionate production share from the Syncrude joint venture). Accordingly, Suncor's production outlook issued on February 4, 2010 will be impacted and will be updated with the release of the company's first quarter results on May 4, 2010.

This update contains forward-looking statements identified by the word "targeted" and similar expressions that address expectations or projections about the future. Forward-looking statements are based on Suncor's current goals, expectations, estimates, projections and assumptions made in light of its experiences and the risks, uncertainties and other factors related to its business. Assumptions used to develop our production targets and outlook are based on year-to-date performance and management's best estimates for the remainder of the year.

Factors that could potentially impact Suncor's operations and financial performance in 2010 include:

•
  Bitumen supply. Ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in-situ reservoir and facilities performance could impact 2010 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.
•
  Unplanned maintenance. Production estimates could be impacted if unplanned work is required at any of our mining, production, upgrading, refining, pipeline or offshore assets.
•
  Planned maintenance. Production estimates could be impacted due to unexpected events impacting the timing or duration of planned maintenance.
•
  Planned divestitures. Our inability to execute planned divestitures could impact our debt management and capital expenditure plans.
•
  Commodity prices. Significant declines in natural gas commodity prices could result in the shut-in of some of our natural gas production.
•
  Foreign operations. 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 OPEC quotas.

For additional information on risk factors that could cause actual results to differ, please see page 20.

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 51

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this MD&A are not prescribed by Canadian generally accepted accounting principles (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. We include cash flow from operations (dollars and per share amounts), return on capital employed (ROCE), and cash and total operating costs per barrel data because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with Canadian GAAP.

Operating Earnings

Operating earnings (loss) represent net earnings (loss) excluding the change in fair value of commodity derivatives used for risk management purposes, unrealized foreign exchange gain (loss) on U.S. dollar denominated long term debt, mark-to-market valuation of stock-based compensation, impact of income tax rate adjustments on future income tax liabilities, costs related to start-up or deferral of growth projects, and impacts related to the merger with Petro-Canada. Operating earnings are used by the Company to evaluate operating performance. See page 12 for a reconciliation of consolidated net earnings to consolidated operating earnings.

Cash Flow from Operations per Common Share

Cash flow from operations is expressed before changes in non-cash working capital. Cash flow from operations is the same measure as the cash flow from operating activities before changes in working capital measure that is included in the Consolidated Financial Statements. Beginning in third quarter 2009, cash flow from operations adjusts for the impact of fair value changes on both the current and long-term portions of commodity derivatives and stock-based compensation (previously only adjusted the impact on the long-term portions). The company believes this provides more useful information to investors and allows better comparability between Suncor and other companies with similar adjustments for commodity derivatives and/or stock-based compensation. Prior period comparative figures have been restated. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are included in our Consolidated Financial Statements.

For the year ended December 31 |  |  |  | 2009 |  | 2008 |  | 2007 |
Cash flow from operations ($ millions) |  |  |  | 2 799 |  | 4 057 |  | 4 037 |
Weighted number of shares outstanding – basic (millions of shares) |  |  |  | 1 198 |  | 932 |  | 922 |
Cash flow from operations – basic ($ per share) |  |  |  | 2.34 |  | 4.36 |  | 4.38 |

52 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

ROCE

For the year ended December 31 ($ millions, except ROCE) |  |  |  | 2009 |  | 2008 |  | 2007 |  |
Adjusted net earnings |  |  |  |  |  |  |  |  |  |
Net earnings |  |  |  | 1 146 |  | 2 137 |  | 2 983 |  |
Add: after-tax financing expenses (income) |  |  |  | (509 | ) | 852 |  | (179 | ) |
|  | A |  | 637 |  | 2 989 |  | 2 804 |  |
Capital employed – beginning of year |  |  |  |  |  |  |  |  |  |
Short-term and long-term debt, less cash and cash equivalents |  |  |  | 7 226 |  | 3 248 |  | 1 849 |  |
Shareholders' equity |  |  |  | 14 523 |  | 11 896 |  | 9 084 |  |
|  | B |  | 21 749 |  | 15 144 |  | 10 933 |  |
Capital employed – end 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 |  |
|  | C |  | 47 488 |  | 21 749 |  | 15 144 |  |
Average capital employed (1) |  | D |  | 35 128 |  | 18 447 |  | 13 039 |  |
Average capitalized costs related to major projects in progress |  | E |  | 10 655 |  | 5 149 |  | 3 454 |  |
ROCE (%) (2) |  | A/(D-E) |  | 2.6 |  | 22.5 |  | 29.3 |  |

(1)
  Average capital employed for 2008 and 2007 is calculated on a simple-average basis (B+C)/2. In 2009, 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.
(2)
  The increase in capital employed as a result of the merger with Petro-Canada has caused our return on capital employed measure to decrease significantly, as the calculation only includes five months of results relating to legacy Petro-Canada operations.

Oil Sands Operating Costs – Total Operations (1)

|  | 2009 |  | 2008 |  | 2007 |
(unaudited) |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |
Operating, selling and general expenses |  | 4 277 |  |  |  | 3 204 |  |  |  | 2 439 |  |  |
| Less: natural gas costs, inventory changes, stock-based compensation and other |  | (400 | ) |  |  | (524 | ) |  |  | (301 | ) |  |
| Less: Safe mode costs |  | (380 | ) |  |  | — |  |  |  | — |  |  |
| Less: non-monetary transactions |  | (66 | ) |  |  | (111 | ) |  |  | (102 | ) |  |
| Less: Syncrude-related operating, selling and general expenses |  | (199 | ) |  |  | — |  |  |  | — |  |  |
Accretion of asset retirement obligations |  | 107 |  |  |  | 55 |  |  |  | 40 |  |  |
Cash costs |  | 3 339 |  | 31.50 |  | 2 624 |  | 31.45 |  | 2 076 |  | 24.15 |
Natural gas |  | 252 |  | 2.40 |  | 438 |  | 5.25 |  | 307 |  | 3.55 |
Imported bitumen (excluding other reported product purchases) |  | 8 |  | 0.05 |  | 150 |  | 1.80 |  | 8 |  | 0.10 |
Cash operating costs |  | 3 599 |  | 33.95 |  | 3 212 |  | 38.50 |  | 2 391 |  | 27.80 |
Project start-up costs |  | 51 |  | 0.45 |  | 35 |  | 0.40 |  | 60 |  | 0.95 |
Total cash operating costs |  | 3 650 |  | 34.40 |  | 3 247 |  | 38.90 |  | 2 451 |  | 28.75 |
Depreciation, depletion and amortization |  | 850 |  | 8.00 |  | 580 |  | 6.95 |  | 462 |  | 5.40 |
Total operating costs |  | 4 500 |  | 42.40 |  | 3 827 |  | 45.85 |  | 2 913 |  | 34.15 |
Production (thousands of barrels per day) |  |  |  | 290.6 |  |  |  | 228.0 |  |  |  | 235.6 |

(1)
  Excludes Suncor's proportionate production share and operating costs from the Syncrude joint venture

SUNCOR ENERGY INC. 2009 ANNUAL REPORT 53

Legal Notice – Forward-Looking Information

This Management's Discussion and Analysis contains certain forward-looking statements and other information that are 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. These statements and information are subject to a number of risks and uncertainties, many of which are beyond the company's control.

All statements and other information that address expectations or projections about the future, including statements 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 may be identified by words like "expects," "anticipates," "estimates," "plans," "scheduled," "intends," "believes," "projects," "indicates," "could," "focus," "vision," "goal," "outlook," "proposed," "target," "objective," "will" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

Suncor's production targets are based on our current expectations, estimates, projections and assumptions. Uncertainties in the estimating process and the impact of future events may cause actual results to differ, in some cases materially, from our estimates. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. For a description of assumptions and risk factors specifically related to these production targets, see page 51.

Certain financial measures referred to in MD&A, namely operating earnings, cash flow from operations, return on capital employed (ROCE) and oil sands cash and total operating costs per barrel, are not prescribed by GAAP. These non-GAAP financial measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. Suncor includes these non-GAAP financial measures because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. For a further description of these measures please refer to pages 52 and 53.

The risks, uncertainties and other factors that could influence actual results include but are not limited to, those risks, uncertainties and other factors described throughout this MD&A and: market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; availability of third-party bitumen; success of hedging strategies; maintaining a desirable debt to cash flow ratio; changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange rates; 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; Suncor's inability to execute planned divestitures; political, economic and socio-economic risk associated with foreign operations (including OPEC production quotas); 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, the Government of Alberta's review of the unintended consequences of the proposed Crown royalty regime, and 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; 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 associated with our merger with Petro-Canada; risks regarding the integration of Petro-Canada and incorrect assessments of the value of Petro-Canada. The foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout this MD&A and in Suncor's 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 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.

54 SUNCOR ENERGY INC. 2009 ANNUAL REPORT

QuickLinks

EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2009, dated February 26, 2010