Exhibit 99.2

Second Quarter 2009 Supplemental Pro Forma Information

Suncor Energy Inc. Second Quarter 2009 Supplemental Pro Forma Information October 2, 2009

1 Forward-Looking Statements This supplemental pro-forma information contains certain forward-looking statements, including statements about Suncor’s growth strategy and expected future production, operating and financial results that are based on Suncor’s current expectations and assumptions. The forward-looking statements identified by words such as “targets”, “estimates”, “anticipated”, “plans”, “vision”, “strategy”, “expects”, “proposed”, “intention”, “may”, “outlook”, “opportunity”, “projected”, and “objectives”, are not guarantees of future performance. Users of this information are cautioned that actual results may differ materially as a result of risks associated with the assumptions regarding expected synergies and reduced capital expenditures; volatility of and assumptions regarding oil and gas prices; assumptions contained in or relevant to Suncor’s corporate guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in marketing operations (including credit risks); imprecision of reserves and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids from Suncor’s properties; the ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the ability to secure adequate product transportation; changes in royalty tax; environmental and other laws or regulations or the interpretations of such laws or regulations; applicable political and economic conditions; the risk of war, hostilities, civil insurrection, political instability and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities. Although Suncor believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of factors and assumptions is not exhaustive and actual results could differ materially from those expressed or implied as a result of changes to Suncor's plans and the impact of events, risks and uncertainties discussed in Suncor's and Petro-Canada’s 2008 annual information form/form 40-F, annual and quarterly reports to shareholders and other documents filed with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. The forward-looking information contained in this supplemental information speak only as of September 30, 2009. Disclosure in this supplemental information with respect to barrels of oil equivalent (boe) may be misleading particularly if used in isolation. A boe conversion ratio of six thousand cubic feet 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.

2 Basis of Presentation This unaudited Pro Forma Supplemental Information presentation, containing unaudited Pro Forma Segmented Statement of Earnings and Operating Summary Information, has been prepared for information purposes only on a basis consistent with the unaudited Pro Forma Consolidated Financial Statements included in the business acquisition report (the “BAR”) concerning the arrangement of Suncor and Petro-Canada, available under Suncor’s profile on www.sedar.com. In the opinion of management, the unaudited Pro Forma Segmented Statement of Earnings includes all adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles. The unaudited Segmented Statement of Earnings gives effect to the arrangement as if it had occurred on January 1, 2008. You should not rely on the pro forma amounts as being necessarily indicative of the financial position or results of operations of the combined company that would have actually occurred had the merger been effective during the period presented or of the future financial position or future results of operations of the combined company. The combined information as at and for the period presented may have been different had the companies actually been combined as at or during such period. The information provided is based on the best information available as at September 30, 2009 and assumptions that management believes are reasonable and is for illustrative purposes only and should not be considered representative of the Company’s future results of operations. The unaudited Pro Forma Segmented Statement of Earnings should be read in conjunction with the consolidated financial statements of Suncor and Petro-Canada incorporated by reference in the BAR, available under Suncor’s and Petro-Canada’s respective profiles on www.sedar.com.

3 * Pro forma depreciation, depletion and amortization expense is based on fair value adjustments calculated at March 31, 2009. This expense may be materially different in subsequent quarters. * Suncor’s energy trading activities formerly reported in our Refining and Marketing segment are now included in our Corporate, Energy Trading and Eliminations segment. (Unaudited) For the three months ended June 30, 2009 Oil Sands Natural Gas Refining and Marketing East Coast Canada International Corporate, Energy Trading and Eliminations Total ($ millions) Revenue Operating revenues 645 314 4 435 459 847 ( 101) 6 599 Less: Royalties ( 161) ( 24) - ( 134) ( 96) - ( 415) Operating revenues, net of royalties 484 290 4 435 325 751 ( 101) 6 184 Energy trading activities - - - - - 2 086 2 086 Intersegment revenues 845 61 3 137 - (1 046) - Interest and other income 17 1 3 - 3 4 28 1 346 352 4 441 462 754 943 8 298 Expenses Purchases of crude oil and products 214 50 3 379 107 - (1 052) 2 698 Operating, selling and general 1 235 130 550 49 116 208 2 288 Energy trading activities - - - - - 2 050 2 050 Transportation costs 70 30 13 13 22 - 148 Depreciation, depletion and amortization 233 135 127 211 176 6 888 Accretion of asset retirement obligations 28 11 1 3 11 - 54 Exploration 3 105 - 1 51 - 160 Taxes other than income taxes 37 15 57 1 - 1 111 Loss (gain) on disposal of assets - ( 15) 19 - - - 4 Project start-up costs 10 - - - - - 10 Financing expenses (income) - - - - - (474) (474) 1 830 461 4 146 385 376 739 7 937 Earnings (loss) before income taxes ( 484) ( 109) 295 77 378 204 361 Income taxes 165 62 ( 81) ( 28) ( 234) 100 ( 16) Net earnings (loss) ( 319) ( 47) 214 49 144 304 345 Pro Forma Segmented Statement of Earnings

4 Operating Summary Information – Oil Sands * For the three months ended June 30, 2009, bitumen production from Firebag in-situ operations averaged 48.3 thousands of barrels/day and bitumen production from MacKay River in-situ operations averaged 28.3 thousands of barrels/day. For the three months ended June 30, 2009 OPERATED SYNCRUDE TOTAL OIL SANDS Production (thousands of barrels/day) Total production(1) 301.0 * 24.7 325.7 Sales (thousands of barrels/day) Light sweet crude oil 99.4 24.7 124.1 Diesel 25.3 - 25.3 Light sour crude oil 173.2 - 173.2 Bitumen 10.5 - 10.5 Total sales 308.4 24.7 333.1 Average sales price (dollars/barrel)(2) Light sweet crude oil 66.24 68.26 66.64 Other (diesel, light sour crude oil and bitumen) 62.95 - 62.95 Total 64.00 68.26 64.32 Total (excluding the impact of realized hedging activities) 63.87 68.26 64.20

5 Operating Summary Information – Oil Sands Cont’d * Syncrude cash operating costs and total operating costs are to be provided in Suncor’s Q3 2009 Report to Shareholders For the three months ended June 30, 2009 OPERATED SYNCRUDE * TOTAL * (dollars/barrel rounded to nearest $0.05) Cash costs 30.55 - - Natural gas 2.05 - - Imported bitumen - - - Cash operating costs(3) 32.60 - - Project start-up costs 0.35 - - Total cash operating costs(4) 32.95 - - Depreciation, depletion and amortization 7.55 - - Total operating costs(5) 40.50 - - (dollars/barrel rounded to nearest $0.05) Cash costs 10.75 Natural gas 4.90 Cash operating costs(6) 15.65 Project start-up costs 0.85 Total cash operating costs(7) 16.50 Depreciation, depletion and amortization 5.15 Total operating costs(8) 21.65 Cash operating costs and Total operating costs – Total operations Cash operating costs and Total operating costs – In-situ bitumen

6 Operating Summary Information – Natural Gas For the three months ended June 30, 2009 NATURAL GAS Gross production Natural gas (millions of cubic feet/day) 720 Western Canada 653 U.S. Rockies 67 Natural gas liquids and crude oil (thousands of barrels/day) 16.5 Western Canada 12.2 U.S. Rockies 4.3 Total gross production (millions of cubic feet equivalent/day) 819 Western Canada 726 U.S. Rockies 93

7 Operating Summary Information – Natural Gas Cont’d For the three months ended June 30, 2009 NATURAL GAS Average sales price(2) Natural gas (dollars/thousand cubic feet) 3.36 Western Canada 3.40 U.S. Rockies 3.05 Natural gas (excluding the impact of realized hedging activities) (dollars/thousand cubic feet) 3.35 Western Canada 3.39 U.S. Rockies 3.05 Natural gas liquids and crude oil (dollars/barrel) 51.74 Western Canada 48.10 U.S. Rockies 62.04

8 Operating Summary Information – East Coast Canada For the three months ended June 30, 2009 EAST COAST CANADA Production (thousands of barrels/day) Terra Nova 29.1 Hibernia 18.9 White Rose 21.2 Total production 69.2 Average sales price (dollars/barrel)(2) 68.14

9 Operating Summary Information – International International production volumes and average sales price are to be provided in Suncor’s Q3 2009 Report to Shareholders For the three months ended June 30, 2009 INTERNATIONAL Production (thousands of barrels of oil equivalent/day) North Sea Buzzard - Other U.K. - Netherlands - Other International Libya - Trindad & Tobago - Total gross production 150.6 Average sales price - North Sea - Average sales price - Other International -

10 Operating Summary Information – Refining and Marketing Future presentation of refining and marketing operating summary information may be split by geographic region. For the three months ended June 30, 2009 REFINING AND MARKETING Total Refined product sales (thousands of cubic Transportation fuels Gasoline – retail 21.6 – other 20.1 Distillate 26.9 Total transportation fuel sales 68.6 Lubricants 2.0 Petrochemicals 2.0 Asphalt 4.1 Other 7.2 Total refined product sales 83.9 Crude oil supply and refining Processed at refineries (thousands of cubic 61.8 Utilization of refining capacity (percentage) 90

11 Netbacks Future netback disclosure information is planned for Natural Gas and East Coast Canada. Netback disclosure for other segments may be considered. For the three months ended June 30 2009 Total Gross Price - Royalties - Operating costs - Operating netback - DD&A - Administrative expenses and other - Earnings before income taxes -

12 Oil Sands Crown Royalties This Oil Sands Crown royalty estimate has not been updated from our Q2 2009 MD&A. It will be updated in our Q3 2009 MD&A and may differ materially from the above presentation. Refer to Appendix A for important information on our Oil Sands Crown royalty estimate, including risks that may cause our estimates to differ materially. The following table sets forth an estimation of royalties in the years 2009 through 2013 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios. WTI Price/bbl (US$) 40 60 80 Natural gas (Alberta spot) Cdn$/mcf at AECO 6.50 8.00 9.50 Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$ 6.50 10.00 13.00 Differential of Maya at the US Gulf Coast less Western Canadian Select at Hardisty, Alberta US$ 4.00 4.00 4.00 US$/Cdn$ exchange rate 0.75 0.85 0.95 Crown Royalty Expense (based on percentage of total oil sands revenue) % 2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates)(1) 3-4 4-5 6-7 2010 to 2013 – Bitumen (new rates – with limits for mining only) 1 3-6 6-10 * For 2009, estimated royalty rates are based on actual year-to-date results plus forward months estimated as per assumptions.

13 East Coast Canada Crown Royalties East Coast Canada Crown royalties estimate to be disclosed in our Q3 2009 MD&A. The following table sets forth an estimation of royalties in the years 2009 through 2010 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios. WTI Price/bbl US$ - - - US$/Cdn$ exchange rate - - - Crown Royalty Expense (based on percentage of gross revenue)% 2009 – Crude (tiered royalty rates assessed on gross or net revenue) - - - 2010 – Crude (tiered royalty rates assessed on gross or net revenue) - - -

14 Income Taxes • Estimated tax rates for 2009: Canada 26 - 31% International 50 - 70% Overall 45 - 55% • Estimated cash income taxes for 2009 = $900 million to $1 billion • 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 factors. 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 previous Oil Sands Crown royalty estimate table, assuming there are no changes to the current income tax regime. Our estimate of cash income tax is a forward-looking statement and users of this information are cautioned that actual cash income taxes may differ materially from our estimate.

15 Definitions (1) Total operations production Total operations production includes total production from both mining and in-situ operations. (2) Average sales price This operating statistic is calculated before royalties and net of related transportation costs. (3) Cash operating costs – Total operations Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non-GAAP financial measure see Suncor's 2009 second quarter MD&A. (4) Total cash operating costs – Total operations Include cash operating costs – Total operations as defined above and cash start-up costs. Per barrel amounts are based on total production volumes. (5) Total operating costs – Total operations Include total cash operating costs – Total operations as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes. (6) Cash operating costs – In-situ bitumen production Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on insitu production volumes only. (7) Total cash operating costs – In-situ bitumen production Include cash operating costs – In-situ bitumen production as defined above and cash start-up operating costs. Per barrel amounts are based on in-situ production volumes only. (8) Total operating costs – In-situ bitumen production Include total cash operating costs – In-situ bitumen production as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes only.

16 Appendix A – Oil Sands Crown Royalties 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 material risk factors could cause actual royalty rates to differ materially from the rates contained in the foregoing table: (i) The government has enacted new Bitumen Valuation Methodology regulations as part of the implementation of the New Royalty Framework effective January 1, 2009. While the interim bitumen valuation methodology in 2009 has been enacted, the permanent valuation methodology for 2010 has yet to be finalized. For our mining operations, the bitumen valuation methodology is based on our interpretation of the terms of our January 2008 Royalty Amending Agreement. That agreement places certain limitations on the bitumen valuation methodology as recently enacted. If our interpretation of these limitations changes, this could impact the royalties payable to the Crown. (ii) The government enacted new Allowed Cost 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 our January 2008 Royalty Amending Agreement shelter us through 2015 from the impact of many of these changes for our mining operations. In addition, since our in-situ operations are forecast to remain in pre-payout royalty for the near term, the changes in the Allowed Cost regulations will not have a near term impact on our payment of royalties. However, potential changes and the interpretation of the Allowed Cost regulations could, over time, have a significant impact on our calculation of royalties. (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 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 42 of Suncor’s AIF dated March 2, 2009.

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