EX-99.2 3 a2190827zex-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, 2008, DATED FEBRUARY 25, 2009

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 25, 2009

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, 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 42.

This MD&A should be read in conjunction with Suncor's 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 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 outlined and reconciled in Non-GAAP Financial Measures on page 40.

Certain prior year amounts 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.

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 14.

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.

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

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and the Annual Information Form (AIF), filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and 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 by reference into this MD&A.

6 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

SUNCOR OVERVIEW AND STRATEGIC PRIORITIES

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate three 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 byproducts.
•
  Natural gas, located primarily in western Canada, is a conventional exploration and development operation, focused primarily on the production of natural gas. Its natural gas production offsets Suncor's purchases for internal consumption at our oil sands operations.
•
  Refining and marketing, Suncor's downstream operations located in Ontario and Colorado, produce and market the company's refined products to industrial, commercial and retail customers. The refining and marketing business also encompasses third-party energy marketing and trading activities, and provides marketing services for the sale of crude oil, natural gas, refined products and by-products from the oil sands and natural gas segments.

In addition to Suncor's integrated oil sands-focused business activities, the company also invests in renewable energy opportunities. Suncor is a partner in four wind power projects and operates Canada's largest ethanol plant.

Suncor's strategic priorities are:

Operational:

•
  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.
•
  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 worker, contractor and community health and safety.

Financial:

•
  Controlling costs by achieving economies of scale with a strong focus on safe, reliable, cost-effective and environmentally responsible management of our operations.
•
  Reducing risk associated with commodity price volatility by entering into hedging arrangements to fix prices for crude oil production and by producing natural gas volumes that offset purchases for internal consumption at oil sands operations.
•
  Ensuring appropriate levels of debt and capital spending are in place to support growth in a fiscally responsible manner.

2008 Overview

•
  Combined oil sands and natural gas production in 2008 was 264,700 barrels of oil equivalent (boe) per day, compared to 271,400 boe per day in 2007.
•
  Oil sands cash operating costs averaged $38.50 per barrel during 2008, compared to $27.80 per barrel in 2007.
•
  Strong commodity prices in the first three quarters of the year led to an average WTI benchmark price almost 40% higher than 2007. However, prices weakened significantly through the last quarter of 2008 and into 2009.
•
  Commissioning of Suncor's $2.3 billion expansion to one of two oil sands upgraders was completed in the third quarter of 2008. With the completion of this expansion, Suncor has upgrading design capacity of 350,000 bpd.
•
  Capital spending in 2008 totalled $7.6 billion. Net debt at year-end 2008 was $7.2 billion, compared to $3.2 billion at the end of 2007.
•
  Suncor achieved a 22.5% return on capital employed (ROCE) excluding capitalized costs related to major projects in progress in 2008, compared to 29.3% in 2007.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 7

SELECTED FINANCIAL INFORMATION

Annual Financial Data

Year ended December 31 ($ millions except per share) |  | 2008 |  | 2007 |  | 2006 |
Revenues |  | 30 089 |  | 18 565 |  | 16 546 |
Net earnings |  | 2 137 |  | 2 983 |  | 2 969 |
Total assets |  | 32 528 |  | 24 509 |  | 18 959 |
Long-term debt |  | 7 875 |  | 3 811 |  | 2 363 |
Dividends on common shares |  | 180 |  | 162 |  | 127 |
Net earnings attributable to common shareholders per share – basic |  | 2.29 |  | 3.23 |  | 3.23 |
Net earnings attributable to common shareholders per share – diluted |  | 2.26 |  | 3.17 |  | 3.16 |
Cash dividends per share |  | 0.20 |  | 0.19 |  | 0.15 |

Outstanding Share Data (1)

At December 31, 2008 (thousands) |  |  |
Number of common shares |  | 935 524 |
Number of common share options |  | 46 402 |
Number of common share options – exercisable |  | 24 933 |

Net Earnings (2) Year ended December 31 ($ millions) |  |

|  | 08 |  | 07 |  | 06 |
• Oil sands |  | 2 875 |  | 2 474 |  | 2 775 |
• Natural gas |  | 89 |  | 25 |  | 106 |
• Refining and marketing |  | 51 |  | 444 |  | 244 |

Cash Flow from Operations (2), (3) Year ended December 31 ($ millions) |  |

|  | 08 |  | 07 |  | 06 |
• Oil sands |  | 3 838 |  | 3 143 |  | 3 903 |
• Natural gas |  | 368 |  | 248 |  | 281 |
• Refining and marketing |  | 278 |  | 716 |  | 451 |

Ending Capital Employed (2), (3), (4) At December 31 ($ millions) |  |

|  | 08 |  | 07 |  | 06 |
• Oil sands |  | 9 352 |  | 6 605 |  | 5 039 |
• Natural gas |  | 1 152 |  | 1 153 |  | 857 |
• Refining and marketing |  | 3 220 |  | 2 489 |  | 1 938 |

(1) | On May 14, 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares.
(2) | Excludes Corporate and Eliminations segment.
(3) | Non-GAAP measures. See page 40.
(4) | Excludes major projects in progress.

8 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

CONSOLIDATED FINANCIAL ANALYSIS

This analysis provides an overview of our consolidated financial results for 2008 compared to 2007. For a detailed analysis, see the various business segment discussions.

Net Earnings

Our net earnings were $2.137 billion in 2008, compared with $2.983 billion in 2007 (2006 – $2.969 billion). Excluding unrealized foreign exchange impacts on the company's U.S. dollar denominated long-term debt, income tax rate reductions on opening future income tax liabilities, net insurance proceeds received in 2006 (relating to a January 2005 fire), and project start-up costs, earnings were $3.013 billion in 2008, compared to $2.390 billion in 2007 (2006 – $2.348 billion). The increase in earnings is due primarily

to higher annual average price realizations for oil sands and natural gas products. This was partially offset by unscheduled maintenance – which led to higher operating expenses, lower production and increased product purchases – and decreased earnings from our downstream operations due to declining commodity prices in the latter part of the year that reduced the value of inventories.

Although annual average price realizations were stronger in 2008, this was mainly the result of high benchmark commodity prices through the first three quarters of the year. In the fourth quarter of 2008, decreased benchmark commodity prices resulted in price realizations on our oil sands products that were down more than 50% from the second quarter of 2008, and prices have remained low in the first part of 2009.

Net Earnings Components (1)

Year ended December 31 ($ millions, after-tax) |  | 2008 |  | 2007 |  | 2006 |  |
Earnings before the following items: |  | 3 013 |  | 2 390 |  | 2 348 |  |
| Impact of income tax rate reductions on opening future income tax liabilities |  | — |  | 427 |  | 419 |  |
| Oil sands fire accrued insurance proceeds (2) |  | — |  | — |  | 232 |  |
| Unrealized foreign exchange gains (loss) on U.S. dollar denominated long-term debt |  | (852 | ) | 215 |  | — |  |
| Project start-up costs |  | (24 | ) | (49 | ) | (30 | ) |
Net earnings as reported |  | 2 137 |  | 2 983 |  | 2 969 |  |

(1)
  This table highlights some of the factors impacting Suncor's after-tax net earnings. For comparability purposes, readers should rely on the reported net earnings that are prepared and presented in the Consolidated Financial Statements and notes in accordance with Canadian GAAP.
(2)
  Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown royalties.

Industry Indicators

(Average for the year) |  | 2008 |  | 2007 |  | 2006 |
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing |  | 99.65 |  | 72.30 |  | 66.20 |
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton |  | 103.05 |  | 76.65 |  | 73.05 |
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty |  | 20.10 |  | 22.25 |  | 21.45 |
Natural gas US$/thousand cubic feet (mcf) at Henry Hub |  | 8.95 |  | 6.90 |  | 7.25 |
Natural gas (Alberta spot) Cdn$/mcf at AECO |  | 8.15 |  | 6.60 |  | 7.00 |
New York Harbour 3-2-1 crack US$/barrel (1) |  | 9.10 |  | 13.70 |  | 9.80 |
Exchange rate: US$/Cdn$ |  | 0.94 |  | 0.93 |  | 0.88 |

(1)
  New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking two times the New York Harbour gasoline margin plus the New York Harbour distillate margin and dividing by three.

Revenues were $30.089 billion in 2008, compared with $18.565 billion in 2007 (2006 – $16.546 billion). The increase was primarily due to the following factors:

•
  Energy marketing and trading revenues increased to $11.725 billion in 2008, compared to $3.515 billion in 2007. The significant increase was due primarily to the implementation and further development of crude and natural gas trading strategies designed to maximize value from proprietary production and refinery optimization while gaining market expertise and establishing market presence. In addition, higher energy marketing and trading revenues also reflect the stronger average commodity prices in 2008. The results of energy marketing and trading are evaluated net of

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 9

energy marketing and trading expenses. Pretax earnings from energy marketing and trading activities in 2008 were $102 million (2007 – $49 million). For a discussion of these net results, see page 38.

•
  Operating revenues benefited from a 38% increase in average U.S. dollar WTI benchmark prices, which increased the selling price of oil sands crude oil production. In addition, stronger price realizations for sales of our oil sands sweet blend and diesel product relative to WTI also increased revenue. High commodity prices also increased revenues from our downstream and natural gas segments. As previously discussed, benchmark prices dropped significantly in the fourth quarter of 2008, negatively impacting operating revenues.

Partially offsetting these increases were the following:

•
  Oil sands production and sales volumes were lower during 2008, mainly as a result of upgrader reliability and bitumen production issues. In addition, an unplanned shutdown of facilities that supply hydrogen reduced production of higher-value sweet synthetic crude oil and diesel during the third quarter of 2008.
•
  Our refining and marketing segment experienced lower refined product demand driven by the high prices of finished products, particularly gasoline.

The cost to purchase crude oil and crude oil products was $7.184 billion in 2008, compared to $5.817 billion in 2007 (2006 – $4.670 billion). The increase was primarily due to the following:

•
  Higher benchmark crude oil prices. This had the largest impact on product purchases for our refining and marketing business, as average WTI prices were more than US$27.00/bbl higher than in 2007.
•
  Increased purchases of third-party product in our oil sands segment, primarily bitumen purchases to fill additional upgrading capacity, and also product purchases related to increasing the efficiency of cargo shipments made during 2008.

Operating, selling and general expenses were $4.044 billion in 2008 compared with $3.340 billion in 2007 (2006 – $3.066 billion). The primary reasons for the increase were:

•
  Higher planned and unplanned maintenance expenditures at our oil sands operations. The planned maintenance work was aimed at improving reliability, while the unplanned maintenance related to work on our upgrading and extraction assets.
•
  Increased energy input costs in our oil sands segment, resulting mainly from strong natural gas prices that saw the average benchmark AECO price in 2008 up almost 25% compared to 2007.

Transportation and other expenses were $275 million in 2008, compared to $182 million in 2007 (2006 – $203 million). The increase in transportation costs was primarily due to a larger number of cargo shipments resulting from increased production of sour crude oil caused by the hydrogen facilities outage in the third quarter of 2008.

Depreciation, depletion and amortization (DD&A) was $1.049 billion in 2008, compared to $864 million in 2007 (2006 – $695 million). The increase primarily reflects the construction and commissioning of the expansion to one of our two oil sands upgraders, in addition to higher DD&A in our natural gas segment resulting from increased production from areas with larger capital bases.

Royalty expenses were $890 million in 2008, compared with $691 million in 2007 (2006 – $1.038 billion). The higher royalties in 2008 were primarily due to increased revenues in our oil sands segment, resulting from high crude prices. This was partially offset by an increase in eligible operating and capital expenditures. In addition, natural gas royalties were higher than the prior year, primarily as a result of the strong natural gas benchmark pricing in 2008. For a discussion of Crown royalties, see page 15.

Taxes other than income taxes were $679 million in 2008, compared to $648 million in 2007 (2006 – $595 million). The increase was primarily due to higher property taxes in our oil sands segment as a result of increased rates and an increased asset base.

Financing expense was $917 million in 2008, compared with income of $211 million in 2007 (2006 – expense of $39 million). The increase in financing expense was primarily due to foreign exchange losses on our U.S. dollar denominated long-term debt. Although interest on our long-term debt increased from the prior year due to additional debt issuance during 2008, we continue to capitalize all of this interest expense. Capitalized interest was $352 million in 2008, compared to $189 million in 2007.

Income tax expense was $995 million in 2008 (32% effective tax rate), compared to $566 million in 2007 (16% effective tax rate) and $828 million in 2006 (22% effective tax rate). The significantly lower effective tax rates in 2007 and 2006 resulted from reductions in tax rates that reduced opening future tax rate liabilities. In addition, there was an increase in the effective tax rate in 2008 as a result of Suncor being unable to realize the full benefit of the capital loss that resulted from the unrealized

10 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

foreign exchange loss on our U.S. denominated long-term debt.

Corporate Earnings (Expense)

After-tax net corporate expense was $878 million in 2008, compared to earnings of $40 million in 2007 (2006 – $156 million expense). Excluding the impact of group elimination entries, actual after-tax net corporate expense was $869 million in 2008 (2007 – earnings of $43 million; 2006 – $150 million expense).

Breakdown of Net Corporate Earnings (Expense)

Year ended December 31 ($ millions) | 2008 |  | 2007 |  | 2006 |  |
Corporate earnings (expense) | (869 | ) | 43 |  | (150 | ) |
Group eliminations | (9 | ) | (3 | ) | (6 | ) |
Total | (878 | ) | 40 |  | (156 | ) |

The net expense in the corporate segment in 2008, compared to net earnings in 2007, was primarily due to unrealized foreign exchange losses on our U.S. denominated long-term debt as a result of the weaker Canadian dollar. As a result of debt issuances during 2008, our U.S. long-term debt balance increased to US$4.15 billion at December 31, 2008 (2007 – US$2.15 billion). After-tax unrealized foreign exchange losses on this U.S. debt were $852 million in 2008, compared to gains of $215 million in 2007 (2006 – nil). Partially offsetting the impact of these foreign exchange losses was a recovery of previously recognized stock-based compensation expense as a result of a decline in our share price.

The corporate net cash deficiency of $659 million was unchanged from 2007 (2006 – $403 million). A $146 million decrease in cash resulting from an increase in working capital was offset by less cash being used in operations and investing activities. The decrease in cash used in operations primarily relates to an operational foreign exchange gain in 2008 compared to a loss in 2007, and the decrease in cash used in investing activities is a result of higher capital spending on the Ripley Wind Power Project in 2007.

Consolidated Cash Flow from Operations

Cash flow from operations was $4.463 billion in 2008, compared to $4.009 billion in 2007 (2006 – $4.524 billion). The increase in cash flow from operations was primarily due to the same factors that impacted earnings.

Dividends

Total dividends paid during 2008 were $0.20 per share, compared with $0.19 per share in 2007 (2006 – $0.15 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

|  | 2008 Three months ended |  | 2007 Three months ended |
($ millions except per share) |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |  | Dec 31 |  | Sept 30 |  | June 30 |  | Mar 31 |
Revenues |  | 7 196 |  | 8 946 |  | 7 959 |  | 5 988 |  | 5 185 |  | 4 802 |  | 4 525 |  | 4 053 |
Net earnings (loss) |  | (215 | ) | 815 |  | 829 |  | 708 |  | 1 042 |  | 627 |  | 738 |  | 576 |
Net earnings (loss) attributable to common shareholders per share |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Basic |  | (0.24 | ) | 0.87 |  | 0.89 |  | 0.77 |  | 1.12 |  | 0.68 |  | 0.80 |  | 0.63 |
| Diluted |  | (0.24 | ) | 0.86 |  | 0.87 |  | 0.75 |  | 1.10 |  | 0.66 |  | 0.78 |  | 0.61 |

Variations in quarterly net earnings during 2008 and 2007 were due to a number of factors:

•
  Oil sands production and sales volumes decreased during periods of planned and unplanned maintenance and restricted bitumen supply.
•
  Changes in benchmark commodity prices throughout 2007 and 2008. WTI averaged US$99.65 per barrel (bbl) in 2008, compared to US$72.30/bbl in 2007.
•
  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.
•
  Reductions in federal corporate tax rates during the second and fourth quarters of 2007 increased net earnings in those quarters by $67 million and $360 million, respectively.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 11

•
  Oil sands Crown royalties varied as a result of changes in crude oil commodity prices 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.

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

LIQUIDITY AND CAPITAL RESOURCES

The current economic environment has impacted Suncor through both reduced price realizations and higher interest rates on future borrowings. As a result of the current market uncertainty, on January 20, 2009, we announced a reduction to our 2009 planned capital spending.

Our capital resources consist primarily of cash flow from operations and available lines of credit. We believe we will have the capital resources to fund our 2009 capital spending program of $3 billion and to meet current working capital requirements through cash flow from operations and our credit facilities, assuming production of 300,000 bpd and a WTI price of US$40/bbl. Our cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, downstream margins, operating expenses, taxes, royalties, and US$/Cdn$ exchange rates.

To provide an additional element of security to our cash flow from operations, we have entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into 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. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds of approximately $250 million before tax.

In addition, we are closely managing our operational spending, including a freeze on discretionary salary increases as well as implementing a variety of cost-cutting measures throughout the company.

If additional capital is required, we believe adequate additional financing will be available at commercial terms and rates (which are currently higher than in 2008). 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 19 for additional factors that may have an impact on our ability to fund our capital requirements.

In May 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares. Information related to common shares, stock-based compensation, and earnings per share has been restated to reflect the impact of the stock split.

The preceding paragraphs contain forward-looking information regarding our liquidity and capital resources and users of this information are cautioned that our actual liquidity and capital resources may vary from our expectations.

Financing Activities

Management of debt levels continues to be a priority given our 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, 2008, our net debt (short and long-term debt less cash and cash equivalents) was $7.226 billion, compared to $3.248 billion at December 31, 2007. The increase in debt levels was primarily a result of increased capital spending to fund our growth strategies.

During 2008, the company's $2 billion committed syndicated credit facility was increased to $3.75 billion and its term was extended to 2013, while the company's $330 million committed bilateral credit facility was increased to $480 million and its term extended to 2009. Undrawn lines of credit at December 31, 2008 were approximately $3.0 billion.

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on May 22, 2018. The net proceeds were added to our general funds to repay outstanding commercial paper, which originally funded our working capital needs, sustaining capital expenditures and growth capital expenditures.

In June 2008, the company issued 6.10% Notes with a principal amount of US$1.25 billion and 6.85% Notes with a principal amount of US$750 million under an amended US$3.65 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 1, 2018, and June 1, 2039, respectively.

12 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

The net proceeds were added to our general funds, which are used for our working capital needs, sustaining and growth capital expenditures and to repay outstanding commercial paper borrowings.

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, 2008, we had $200 million of fixed-rate to variable-rate interest swaps (December 31, 2007 – $200 million).

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 currently in compliance with our financial covenant that requires consolidated debt to not be more than 65% of our total capitalization. At December 31, 2008, our consolidated debt to total capitalization was 35% (where consolidated debt is short-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 very limited number of our commodity purchase agreements, off-balance sheet arrangements (for a discussion of these arrangements see page 15) and 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 Negative Outlook by Standard & Poor's; A(low), with a Negative Trend by Dominion Bond Rating Service; and Baa1, with a Stable Outlook by Moody's Investors Service.

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 |  | 2009 |  | 2010-2011 (aggregate) |  | 2012-2013 (aggregate) |  | Later Years |
Fixed-term debt and commercial paper (1) |  | 7 815 |  | 934 |  | 500 |  | — |  | 6 381 |
Interest payments on fixed-term debt |  | 8 837 |  | 435 |  | 858 |  | 803 |  | 6 741 |
Capital leases |  | 312 |  | 9 |  | 19 |  | 19 |  | 265 |
Employee future benefits (2) |  | 643 |  | 48 |  | 105 |  | 121 |  | 369 |
Asset retirement obligations (3) |  | 3 471 |  | 156 |  | 476 |  | 302 |  | 2 537 |
Non-cancellable capital spending commitments (4) |  | 470 |  | 470 |  | — |  | — |  | — |
Operating lease agreements, pipeline capacity and energy services commitments (5) |  | 8 108 |  | 383 |  | 850 |  | 873 |  | 6 002 |
Total |  | 29 656 |  | 2 435 |  | 2 808 |  | 2 118 |  | 22 295 |

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 $4.150 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 5.39% to 7.15%. We entered into interest rate swap transactions maturing in 2011 that resulted in an average effective interest rate in 2008 of 4.8% on $200 million of our Medium Term Notes. Approximately $934 million of commercial paper with an effective interest rate of 2.2% was issued and outstanding at December 31, 2008.
(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)
  Non-cancellable capital commitments related to capital projects totalled approximately $470 million at the end of 2008. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2009, we anticipate spending approximately $2 billion towards sustaining capital.
(5)
  Includes transportation service agreements for pipeline capacity, including tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta, as well as energy services agreements to obtain a portion of the power and steam generated by a cogeneration facility owned by a major energy company. Non-cancellable operating leases are for service stations, office space and other property and equipment.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 13

Significant Capital Project Update

In response to current market uncertainty, we announced an update to our Voyageur program schedule on January 20, 2009. A revised capital budget has deferred the company's growth projects. With the new plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.

Suncor spent $7.6 billion on capital and exploration expenditures in 2008, compared to $5.4 billion in 2007 (2006 – $3.6 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 Director approval. The estimates and target completion dates do not include project commissioning and start-up.

|  |  |  | Cost |  |  |  |  |  | Estimated |  | Target |
|  |  |  | Estimate |  | Estimate |  | Spent to |  | % Complete |  | Completion |
Project |  | Plan |  | $ millions(1) |  | % Accuracy(1) |  | Date |  | Engineering |  | Construction |  | Date |
Coker unit |  | Expected to increase production capacity by 90,000 bpd |  | 2 100 |  | +13/-7 |  | 2 300 |  | 100 |  | 100 |  | Complete |
Firebag sulphur plant |  | Supports emission abatement plan at Firebag; capacity to support Stages 1-6 |  | 340 |  | +10/-10 |  | 270 |  | 90 |  | 55 |  | Q2 2009 |
Steepbank extraction plant |  | Location and new technologies aimed at improving operational performance |  | 850 |  | +10/-10 |  | 690 |  | 100 |  | 70 |  | Q3 2009 |
Naphtha unit (2) |  | Increases sweet product mix |  | 650 |  | +10/-10 |  | 650 |  | 100 |  | 60 |  | TBD |
North Steepbank expansion of mine (2) |  | Expected to generate about 180,000 bpd of bitumen |  | 400 |  | +10/-10 |  | 125 |  | 55 |  | 45 |  | TBD |
Voyageur program: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Firebag (2) |  | Expansion of Firebag 3-6 is expected to increase bitumen supply |  | 9 000 |  | +18/-13 |  | 3 405 | (3) |  |  |  |  | TBD |
|  | – Stage 3 |  |  |  |  |  |  |  | 97 |  | 50 |  |  |
|  | – Stage 4 (4), (5) |  |  |  |  |  |  |  | 70 |  | 2 |  |  |
|  | – Stage 5 (4), (5) |  |  |  |  |  |  |  | 15 |  | — |  |  |
|  | – Stage 6 (4), (5) |  |  |  |  |  |  |  | 4 |  | — |  |  |
Voyageur program: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Upgrader 3 (2) |  | Expected to increase production capacity by 200,000 bpd |  | 11 600 |  | +12/-8 |  | 3 545 | (3) | 80 |  | 15 |  | TBD |

(1)
  Cost estimates and estimate accuracy reflect budgets approved by Suncor's Board of Directors.
(2)
  At this time, construction restart and completion targets for these projects is to be determined (TBD). Cost estimates for TBD projects including those currently on hold and in "safe mode" will be subject to revision upon resumption of projects.
(3)
  Spending to date includes procurement of major project components. For Firebag Stage 3, procurement at year-end 2008 was 95% complete; for Stage 4, 80% complete; for Stage 5, 15% complete; and for Stage 6, 50% complete. For Upgrader 3, procurement was 75% complete.
(4)
  Pending regulatory approval.
(5)
  Construction of shared and common services is included in Stage 3 construction.

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 material risk factors that could cause actual timing, amount of the final capital expenditures and expected

14 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

results to differ materially from those contained in the previous table, please see page 19. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 42.

The material factors used to develop target completion dates and cost estimates are: current capital spending plans, the current status of procurement, design and engineering phases of the project; updates from third parties on delivery of services and goods 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

At December 31, 2008, the company had various indemnification agreements with third parties as described below.

The company had a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2007 – $170 million) having a maturity of 45 days or less, to a third party. The third party was a multiple party securitization vehicle that provided funding for numerous asset pools. At December 31, 2008, no outstanding accounts receivable had been sold under the program (2007 – nil) and the program has expired. Although the company does not believe it had any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $57 million in 2008 and no contingent liability or earnings impact was recorded for this indemnification as the company believes it had no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2008, were $170 million and approximately $510 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2008 (2007 – $4 million; 2006 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a Variable Interest Entity (VIE) for proceeds of $30 million. The VIE's sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term covered a period of seven years and had been accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2008 and 2007, the VIE did not have any assets or liabilities.

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 related allowable transportation costs (R), less allowable costs (C) including allowable capital expenditures (the R-C Royalty), subject to a minimum royalty at 1% of R. The Alberta government has classified Suncor's current oil sands operations as two distinct "projects" for royalty purposes.

Royalties on our current 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.

Royalties on our base oil sands mining and associated upgrading operations (the "base 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 applies pursuant to Suncor's exercise of its option to transition to the bitumen-based 1997 Generic Regime. The royalty rates will remain at 25% of R-C, subject to the 1% minimum royalty of R, but will apply to a revised R-C, where R will be based on bitumen value and C would exclude substantially all upgrading costs.
•
  From January 1, 2010 through December 31, 2015, pursuant to our January 2008 Royalty Amending Agreement 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 Royalty Amending Agreement provides Suncor with a level of certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 15

In 2016 and subsequent years, the royalty rates for all of our oil sands operations (our base operation and our Firebag in-situ project) will be the rates prescribed under the New Royalty Framework, unless it is amended or superseded prior to that time.

Oil Sands Mining and In-Situ Royalties

The following table sets forth our estimates of royalties in the years 2009 through 2013, and certain assumptions on which we have based our estimates.

WTI Price/bbl US$ |  | 40 |  | 50 |  | 60 |
Natural gas (Alberta spot) Cdn$/mcf at AECO |  | 6.50 |  | 7.00 |  | 7.50 |
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$ |  | 8.00 |  | 9.00 |  | 11.00 |
Differential of Maya at the US Gulf Coast less Western Canadian Select at Hardisty, Alberta US$ |  | 7.00 |  | 7.00 |  | 7.00 |
US$/Cdn$ exchange rate |  | 0.75 |  | 0.80 |  | 0.85 |
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)) |  | 1 |  | 1 |  | 1 |
2010 to 2013 – Bitumen (new rates – with limits for mining only(1)) |  | 1 |  | 1 |  | 1-5 |

(1)
  Oil Sands royalty rates – see page 15.

The previous table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the ranges disclosed in the table. The royalty ranges 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 interpretations 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. We believe that we are sheltered through 2015 from the impact of many of these changes for our mining operations due to our January 2008 Royalty Amending Agreement and from the cost-related changes for our in-situ operations which are forecast to remain in pre-payout royalty for the near term. 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; 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.

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,

16 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

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.

CASH INCOME TAXES

We estimate we will have cash income taxes of 100% to 300% of our provision for income taxes during 2009. We anticipate this increase in 2009 because a portion of Suncor's calendar 2008 income will be included in the calculation of 2009 cash taxes as a result of a different year-end of a Suncor affiliate, and because we anticipate a decrease in the 2009 provision for income taxes. Thereafter, we anticipate our cash income tax position may fluctuate to a maximum of approximately 100% of our provision for income taxes by 2015. 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 table "Oil Sands Mining and In-Situ Royalties" on page 16, assuming there are no changes to the current income tax regime. Our outlook on cash income tax is a forward looking statement and users of this information are cautioned that actual cash income taxes may vary materially from our outlook.

DERIVATIVE FINANCIAL INSTRUMENTS

On January 1, 2008, Suncor adopted the Canadian Institute of Chartered Accountants (CICA) Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. These new disclosures have been incorporated in the following discussion and in the notes to our financial statements.

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 have estimated fair values of derivative financial instruments by assessing available market information and appropriate valuation methodologies based on industry-accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

Derivative contracts are required to be recorded on the balance sheet at fair value. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the hedged item is recognized. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both cash flow and fair value hedges.

Suncor also periodically enters into derivative financial instruments that either do not qualify for hedge accounting treatment or that Suncor has not elected to document as part of a qualifying hedge relationship. These financial instruments are accounted for using the mark-to-market method, with any changes in fair value immediately recognized in earnings.

Commodity and Treasury Hedging Activities

The company has hedged a portion of its forecasted U.S. dollar denominated sales subject to U.S. dollar West Texas Intermediate (WTI) price risk. In February 2009, we entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into 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. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds to Suncor of approximately $250 million before tax.

These contracts have not been designated for hedge accounting, and as such, any fair value changes on these contracts are recognized in earnings each period.

In addition to our strategic crude oil hedging program, Suncor uses derivative contracts to hedge risks related to

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 17

purchases and sales of natural gas and refined products, 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 and Comprehensive Income.

We periodically enter into interest rate swap contracts as part of our strategy to manage exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between ourselves and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized as an adjustment to interest expense.

The company also manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate swaps and foreign exchange forward contracts.

Significant commodity contracts outstanding at February 10, 2009 were as follows:

Crude Oil |  | Quantity (bpd) |  | Price (US$/bbl)(1) |  | Revenue Hedged (Cdn$ millions)(2) |  | Hedge Period |
Purchased puts |  | 55 000 |  | 60.00 |  | 1 319 |  | 2009 (3) |
Fixed price |  | 126 575 |  | 50.73 |  | 2 566 |  | 2009 (4) |
Purchased puts |  | 55 000 |  | 60.00 |  | 1 485 |  | 2010 (3) |
Sold puts |  | 54 753 |  | 60.00 |  | (1 479 | ) | 2010 (3) |
Collars-floor |  | 49 384 |  | 50.00 |  | 1 111 |  | 2010 (3) |
Collars-cap |  | 49 986 |  | 68.10 |  | 1 532 |  | 2010 (3) |

Natural Gas |  | Quantity (MMBtu/day) |  | Price (US$/MMBtu) |  | Consumption Hedged (Cdn$ millions) (2) |  | Hedge Period |
Fixed price |  | 25 000 |  | 6.92 |  | 10 |  | 2009 (5) |

(1)
  Price for crude oil contracts is US$ WTI per barrel at Cushing, Oklahoma.
(2)
  The revenue hedged is translated to Cdn$ at the January 31, 2009 month-end rate and is subject to change as the US$/Cdn$ exchange rate flucturates during the hedge period.
(3)
  Original hedge term is for full year.
(4)
  For the period February to December inclusive.
(5)
  For the period February to March inclusive.

Significant treasury contracts outstanding at February 10, 2009 were as follows:

Description of Swap Transaction |  | Principal Swapped ($ millions) |  | Swap Maturity |  | 2008 Effective Interest Rate |
Swap of 6.70% Medium Term Notes to floating rates |  | 200 |  | 2011 |  | 4.8% |

The earnings impact associated with our commodity and treasury hedging activities in 2008 was a pretax gain of $465 million (2007 – pretax loss of $4 million).

A reconciliation of changes in accumulated other comprehensive income (AOCI) attributable to derivative hedging activities for the twelve month periods ending December 31 is as follows:

($ millions) |  | 2008 |  | 2007 |  |
AOCI attributable to derivative hedging activities, beginning of the period, net of income taxes of $4 (2007 – $5) |  | 13 |  | 8 |  |
Current year net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1) |  | (7 | ) | 8 |  |
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $3 (2007 – $2) |  | 7 |  | (3 | ) |
AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2007 – $4) |  | 13 |  | 13 |  |

18 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

Energy Marketing and Trading Activities

In addition to derivative contracts used for hedging activities, Suncor uses physical and financial energy derivatives to earn trading and marketing revenues. These energy contracts are comprised of crude oil, natural gas and refined products derivative contracts. The results of these trading activities are reported as energy marketing and trading revenues and expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pretax gains associated with our energy marketing and trading activities in 2008 were $102 million (2007 – $49 million).

Fair Value of Derivative Financial Instruments

The fair value of derivative financial instruments is the estimated amount we would receive (pay) to terminate the contracts. Such amounts, which also represent the unrealized gain (loss) on the contracts, were as follows at December 31:

($ millions) |  | 2008 |  | 2007 |  |
Derivative financial instruments accounted for as hedges |  |  |  |  |  |
| Assets |  | 24 |  | 20 |  |
| Liabilities |  | (13 | ) | (11 | ) |
Derivative financial instruments not accounted for as hedges |  |  |  |  |  |
| Assets |  | 635 |  | 18 |  |
| Liabilities |  | (14 | ) | (21 | ) |
Net derivative financial instruments |  | 632 |  | 6 |  |

Risks Associated with Derivative Financial Instruments

Our strategic crude oil hedging program is 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. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date. 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.

Energy marketing and trading activities, by their nature, can result in volatile and large positive or negative fluctuations in earnings. A separate risk management function reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including additional discussion of exposure to risks and our mitigation activities, see note 7 to the Consolidated Financial Statements on page 63.

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:

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 2006 to 2008, the monthly average price for benchmark WTI crude oil ranged from a low of US$42.04/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 $4.45/mcf to a high of $12.11/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 mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 17).

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 19

SENSITIVITY ANALYSIS (1)

|  |  |  |  |  |  | Approximate Change in |  |
|  | 2008 Average |  |  | Change |  | Cash Flow from Operations ($ millions) |  | After-Tax Earnings ($ millions) |  |
Oil Sands |  |  |  |  |  |  |  |  |  |  |
| Realized crude oil price ($/barrel)(2) |  | 95.96 |  | US$ | 1.00 |  | 66 |  | 48 |  |
| Sales (bpd) |  | 227 000 |  |  | 1 000 |  | 16 |  | 11 |  |
Natural Gas |  |  |  |  |  |  |  |  |  |  |
| Realized natural gas price ($/mcf)(2) |  | 8.23 |  |  | 0.10 |  | 5 |  | 4 |  |
| Sales (mmcf/d) |  | 202 |  |  | 10 |  | 18 |  | 8 |  |
Consolidated |  |  |  |  |  |  |  |  |  |  |
| Exchange rate: US$/Cdn$ |  | 0.94 |  |  | 0.01 |  |  |  |  |  |
|  | Effect on oil sands operations |  |  |  |  |  |  | 63 |  | 45 |  |
|  | Effect on U.S. denominated long-term debt |  |  |  |  |  |  |  |  | (55 | ) |
| Total exchange rate impact |  |  |  |  |  |  | 63 |  | (10 | ) |

(1)
  The sensitivity analysis shows the main factors affecting Suncor's annual cash flow from operations and earnings based on actual 2008 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2008 results. A change in any one factor could compound or offset other factors.
(2)
  Includes the impact of hedging activities. See page 17.

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 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;
•
  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 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.

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 are subject to this legislation. The act calls for intensity reductions of 12% commencing July 1, 2007.

In compliance with this new legislation, Suncor filed applications in December 2007 to establish baseline

20 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

intensities for our oil sands facility. In March 2009, Suncor must file compliance reports that show what actions the company took during the year to offset intensities. Compliance options available to Suncor 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, 2008, the compliance costs to Suncor are estimated at between $7 million and $8 million. Final costs will be determined with the company's March 2009 compliance report filing to the province of Alberta.

The Ontario provincial and Colorado state governments are also in various stages of developing greenhouse gas management legislation and regulation. At this time, no such legislation has been tabled in these jurisdictions and any potential impacts are unknown.

In 2007, the Canadian federal government introduced the Clean Air Act regulatory framework, which is expected to regulate both greenhouse gas emissions and air pollutants from industrial emitters. Suncor has been engaging in the ongoing consultations on this framework. The financial impact of this proposed legislation will be dependent on the details of Clean Air Act regulations, which were expected to be released by the end of 2008. Now that the Canadian federal government has committed to implement a North American cap and trade system with the United States, it is not certain that the Clean Air Act framework, in its current form, will be implemented.

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.

Regulatory Requirements at Oil Sands Suncor continues work to decrease emissions at our oil sands operations. At our in-situ operation, high emissions in 2007 resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board (now known as the Energy Resources Conservation Board or ERCB). The production cap, which limited production to 42,000 bpd, was lifted in the third quarter of 2008. Suncor's planned $340 million Firebag sulphur plant is expected to play a role in managing sulphur emissions for existing and planned in-situ developments.

Any regulatory requirements placed on us could have a material effect on our business and results of operations.

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. To reclaim tailings ponds, we are using a process referred to as consolidated tailings (CT) technology. At this time, no ponds have been fully reclaimed using this technology. The success of CT technology and time to reclaim the tailings ponds could increase or decrease our current asset retirement cost estimates. We continue to monitor and assess other possible technologies and/or modifications to the CT process now being used. Regulatory approval of our North Steepbank extension of mine is subject to certain conditions related to the performance of CT technology.

For the Millennium, Steepbank, and North Steepbank expansion of our mine we have posted irrevocable letters of credit equal to approximately $271 million with Alberta Environment, representing security for the maximum reclamation liability in the period January 1 through December 31, 2009. For Suncor's oil sands mining leases 86 and 17, we are required to and have posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced as security for the estimated cost of our reclamation activity. This letter of credit equalled $14 million at December 31, 2008. For more information about our reclamation and environmental remediation obligations, refer to Asset Retirement Obligations in the Critical Accounting Estimates section on page 22.

In February 2009, the ERCB released a directive, Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for CT operations, a requirement for specific approval and monitoring of CT ponds, a requirement for reporting tailings plans, and changes to the ERCB annual mine plan requirements and approval process to regulate tailings operations. We are currently assessing the impact of the directive.

A new reclamation liability management program is under review by the Province of Alberta. The new program would involve increased reporting of progressive reclamation, an asset/liability-based risk assessment, consideration of reserve life, and posting of security.

Regulatory Approvals Before proceeding with most major projects, we must obtain regulatory approvals. The regulatory approval process 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.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 21

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.

The ARO is re-measured every year-end, and incremental increases 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 and Comprehensive Income 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 2008, we increased our estimated undiscounted total obligation to $3.498 billion from the previous estimate of $2.231 billion. The increase was mainly due to a change in the oil sands estimate to $3.163 billion from $1.941 billion, primarily reflecting the inclusion of costs related to conversion of plant equipment to process consolidated tailings (CT), additional extraction operating costs related to production of CT, and increased inflationary estimates. The majority of the costs in oil sands are projected to occur over a time horizon extending to approximately 2060.

The current economic conditions resulted in our credit-adjusted risk-free discount rate increasing to 9.0% at December 31, 2008, from 6.0% at December 31, 2007. The discounted amount of our ARO liability was $1.600 billion at December 31, 2008, compared to $1.072 billion at December 31, 2007. If our credit-adjusted risk-free discount rate had remained unchanged at 6.0%, our ARO liability at December 31, 2008 would have been approximately $160 million larger. The ARO liability is reported as part of accrued liabilities and other in the Consolidated Balance Sheets.

In 2009, the increase in the ARO estimate will result in additional after-tax expenses of approximately $60 million.

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 and Comprehensive Income. 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

22 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

benefits may differ significantly if different assumptions are used. The impact of a 1% change in the assumptions at which pension benefits and other post-retirement benefit liabilities could be effectively settled is disclosed in note 10 to the Consolidated Financial Statements on page 71.

The current economic conditions resulted in an increase to the discount rate used to calculate the year-end benefit obligation to 6.50% at December 31, 2008, from 5.25% at December 31, 2007. This resulted in a $195 million decrease to the benefit obligation. This was partially offset by a $107 million decrease in the value of the plan assets that resulted from lower returns for the plan investments.

Property, Plant and Equipment

We account for our in-situ and natural gas exploration and production 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 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 and Comprehensive Income. 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 and operating 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 and Comprehensive Income. Negative revisions in natural gas and in-situ reserves estimates will result in an increase in depletion expenses.

Oil and Gas Reserves

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.

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. Changes in reserve estimates can have an impact on reported net earnings through revisions to depreciation, depletion and amortization expense, in addition to determining possible writedowns of property, plant and equipment.

RESERVES ESTIMATES

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). Prior to 2008, we presented our disclosures in accordance with U.S. disclosure requirements under an exemption from Canadian securities regulatory authorities which was not renewed following our annual disclosures at December 31, 2007.

As a result, reserves information presented for comparative years has been restated to comply fully with NI 51-101, consistent with the presentation format for December 31, 2008 reserve disclosures.

Our reserves and resources have been evaluated, at December 31, 2008, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (GLJ), in a report dated February 6, 2009 (GLJ Report). The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

Net reserves represent Suncor's undivided gross (working interest) in total reserves after deducting Crown royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about future prices, production levels, operating costs, capital expenditures, and the government of Alberta's enacted New Royalty Framework and our specific oil sands royalty agreements. For a full discussion of our Crown royalties, see page 15.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 23

Assumptions reflect market and regulatory conditions, as required, at December 31, 2008, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

The company's reserves are located primarily in Alberta and British Columbia, Canada.

All of the reserves disclosures presented below reflect forecast pricing. No supplemental constant pricing disclosures have been made.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves

|  | Oil(1) |  | Natural Gas |  | Natural Gas Liquids |
As at December 31, 2008 |  | Working Interest MMbbl |  | Net MMbbl |  | Working Interest Bcf |  | Net Bcf |  | Working Interest MMbbl |  | Net MMbbl |
Proved Producing |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | 2 |  | 2 |  | 459 |  | 352 |  | 5 |  | 4 |
| SCO – Mining |  | 1,571 |  | 1,335 |  | — |  | — |  | — |  | — |
| SCO – In-Situ |  | 94 |  | 91 |  | — |  | — |  | — |  | — |
| Total Proved Producing |  | 1,667 |  | 1,428 |  | 459 |  | 352 |  | 5 |  | 4 |
Proved Developed Non-Producing |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | — |  | — |  | 50 |  | 38 |  | — |  | — |
| SCO – In-Situ |  | 45 |  | 43 |  | — |  | — |  | — |  | — |
| Total Proved Developed Non-Producing |  | 45 |  | 43 |  | 50 |  | 38 |  | — |  | — |
Proved Undeveloped |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | — |  | — |  | 30 |  | 24 |  | — |  | — |
| SCO – In-Situ |  | 766 |  | 658 |  | — |  | — |  | — |  | — |
| Total Proved Undeveloped |  | 766 |  | 658 |  | 30 |  | 24 |  | — |  | — |
Total Proved |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | 2 |  | 2 |  | 539 |  | 414 |  | 5 |  | 4 |
| SCO – Mining |  | 1,571 |  | 1,335 |  | — |  | — |  | — |  | — |
| SCO – In-Situ |  | 905 |  | 792 |  | — |  | — |  | — |  | — |
| Total Proved |  | 2,478 |  | 2,129 |  | 539 |  | 414 |  | 5 |  | 4 |
Total Probable |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | 1 |  | — |  | 216 |  | 153 |  | 2 |  | 1 |
| SCO – Mining |  | 745 |  | 626 |  | — |  | — |  | — |  | — |
| SCO – In-Situ |  | 1,808 |  | 1,506 |  | — |  | — |  | — |  | — |
| Total Probable |  | 2,554 |  | 2,132 |  | 216 |  | 153 |  | 2 |  | 1 |
Total Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |  |  |
| Conventional |  | 3 |  | 2 |  | 755 |  | 567 |  | 7 |  | 5 |
| SCO – Mining |  | 2,316 |  | 1,961 |  | — |  | — |  | — |  | — |
| SCO – In-Situ |  | 2,713 |  | 2,298 |  | — |  | — |  | — |  | — |
| Total Proved Plus Probable |  | 5,032 |  | 4,261 |  | 755 |  | 567 |  | 7 |  | 5 |

(1)
  Represents light and medium oil for our conventional reserves, and synthetic crude oil (SCO) for our mining and in-situ reserves.

24 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

Pricing Assumptions

The following table outlines the benchmark reference prices, as at December 31, 2008, reflected by GLJ in their independent reserves report.

Forecast Prices Used in Preparing Reserves Estimates

Year |  | Inflation % |  | Bank of Canada Average Noon Exchange Rate $US/$Cdn |  | NYMEX WTI Crude Oil at Cushing Oklahoma $US/bbl |  | Light, Sweet Crude Oil at Edmonton (40 API, 0.3%S) $Cdn/bbl |  | NYMEX Natural Gas at Henry Hub $US/mmbtu |  | Natural Gas at AECO $Cdn/mmbtu |
2009 |  | 2.0 |  | 0.825 |  | 57.50 |  | 68.61 |  | 7.00 |  | 7.58 |
2010 |  | 2.0 |  | 0.850 |  | 68.00 |  | 78.94 |  | 7.50 |  | 7.94 |
2011 |  | 2.0 |  | 0.875 |  | 74.00 |  | 83.54 |  | 8.00 |  | 8.34 |
2012 |  | 2.0 |  | 0.925 |  | 85.00 |  | 90.92 |  | 8.75 |  | 8.70 |
2013 |  | 2.0 |  | 0.950 |  | 92.01 |  | 95.91 |  | 9.20 |  | 8.95 |
2014 |  | 2.0 |  | 0.950 |  | 93.85 |  | 97.84 |  | 9.38 |  | 9.14 |
2015 |  | 2.0 |  | 0.950 |  | 95.73 |  | 99.82 |  | 9.57 |  | 9.34 |
2016 |  | 2.0 |  | 0.950 |  | 97.64 |  | 101.83 |  | 9.76 |  | 9.54 |
2017 |  | 2.0 |  | 0.950 |  | 99.59 |  | 103.89 |  | 9.96 |  | 9.75 |
2018 |  | 2.0 |  | 0.950 |  | 101.59 |  | 105.99 |  | 10.16 |  | 9.95 |
2019+ |  | 2.0 |  | 0.950 |  | +2%/yr |  | +2%/yr |  | +2%/yr |  | +2%/yr |

The company's weighted average historical prices realized for the year ended December 31, 2008 were $95.96/bbl for synthetic crude oil, $8.23/mcf for natural gas, and $70.89/bbl for natural gas liquids.

Remaining Recoverable Resources

Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca region of Alberta. Based upon independent evaluations conducted by GLJ effective December 31, 2008, our best estimate of remaining recoverable synthetic crude oil resources are as follows:

As at December 31, 2008 (millions of barrels of SCO) |  | Mining |  | In-Situ |  | Total
Total Proved (1) |  | 1,600 |  | 900 |  | 2,500
Total Probable (1) |  | 700 |  | 1,800 |  | 2,500
Total Proved Plus Probable Reserves |  | 2,300 |  | 2,700 |  | 5,000
Contingent Resources – Best Estimate (2), (3) |  | 3,500 |  | 6,500 |  | 10,000
Remaining Recoverable Resources (4) |  | 5,800 |  | 9,200 |  | 15,000

(1)
  Total proved and total probable reserves as per Summary of Oil and Gas Reserves table.
(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)
  Contingent Resources – 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 are the unrisked arithmetic sum of proved and probable reserves and best estimate contingent resources.

Remaining recoverable resources were 15,500 millions of barrels of SCO at December 31, 2007. The decrease in 2008 was primarily due to additional data and modeling for the Audet leases.

The contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable timeframe, and in some cases due to higher uncertainty as a result of lower core-hole drilling density. Our Voyageur South development area, for which we submitted a regulatory application in 2007, is part of our mining contingent resources. Significant mining contingent resources are also associated with our Audet leases, located north of our Firebag leases and immediately adjacent to leases proposed for mining development by other operators. All of our in-situ leases are associated with our Firebag leases. While we consider the contingent resources to be potentially recoverable under reasonable economic and operating conditions, there is no certainty that it will be commercially viable to produce any portion of them.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 25

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2008, 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, 2008, 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 2008 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, 2008, based on that evaluation, the company's internal controls were found to be operating free of any material weaknesses.

The effectiveness of our internal control over financial reporting as at December 31, 2008 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, 2008.

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.

CHANGE IN ACCOUNTING POLICIES

Inventories

On January 1, 2008, the company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook section 3031 "Inventories". Under the new standard, the use of a LIFO (last-in, first-out) based valuation approach for inventory has been eliminated. The standard also required any impairment to net realizable value of inventory to be written down at each reporting period, with subsequent reversals when applicable. The company transitioned to a FIFO (first-in, first-out) based valuation approach for inventory effective January 1, 2008. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase) | As at December 31 2008 |  | As at December 31 2007 |
Inventories | 110 |  | 404 |
Total assets | 110 |  | 404 |
Future income taxes | 30 |  | 121 |
Retained earnings | 80 |  | 283 |
Total liabilities and shareholders' equity | 110 |  | 404 |

Change in Consolidated Statements of Earnings (Loss) and Comprehensive Income

| Twelve months ended December 31
($ millions, increase/(decrease)) | 2008 |  | 2007 |  | 2006 |  |
Purchases of crude oil and products | 270 |  | (153 | ) | (5 | ) |
Operating, selling and general | 24 |  | (51 | ) | 14 |  |
Future income taxes | (91 | ) | 53 |  | (7 | ) |
Net earnings (loss) | (203 | ) | 151 |  | (2 | ) |
Per common share – basic (dollars) | (0.22 | ) | 0.16 |  | — |  |
Per common share – diluted (dollars) | (0.22 | ) | 0.16 |  | — |  |

26 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

Segmented Net Earnings Impact

| Twelve months ended December 31
($ millions, increase/(decrease)) | 2008 |  | 2007 |  | 2006 |  |
Net earnings |  |  |  |  |  |  |
| Oil sands | (19 | ) | 40 |  | (8 | ) |
| Refining and marketing | (202 | ) | 99 |  | 9 |  |
| Corporate and eliminations | 18 |  | 12 |  | (3 | ) |
Total | (203 | ) | 151 |  | (2 | ) |

Capital Disclosures

On January 1, 2008, the company adopted CICA Handbook section 1535 "Capital Disclosures". This section establishes disclosure requirements for management's policies and processes in defining and managing its capital. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard.

Financial Instruments – Disclosures and Presentation

On January 1, 2008, the company adopted CICA Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard.

International Financial Reporting Standards

In February 2008, the 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. More disclosures will be required under IFRS.

The company's IFRS conversion project began in 2008. A formal project plan, governance structure, and a project team, including an external advisor, have been established. The project philosophy is to align with current accounting practices and policies, where possible, to minimize the impact of any changes to the business. Regular reporting is provided to senior management and the Audit Committee of the Board of Directors.

The IFRS conversion project consists of four phases: Diagnostic; Design & Planning/Solution Development; Implementation; and Post Implementation.

To date, the IFRS conversion project team has completed the Diagnostic phase, which involved a high-level review of the major differences between Canadian GAAP and IFRS. This assessment has provided insight on the high risk and complex areas relating to the conversion. These areas include accounting for property, plant and equipment, exploration and evaluation of mineral resources, the effects of changes in foreign currency exchange rates, and alternatives available under IFRS 1 – First Time Adoption of IFRS.

Please see the associated table for certain elements of the transition plan, and an assessment of progress. Note that the project team is working through a detailed project plan and that certain project activities and milestones could change.

Given the progress of the project and outcomes identified, we could change our intentions between the time of communicating these key milestones below and the changeover date. Further, changes in regulation or economic conditions at the date of the changeover or through the project could result in changes to the project activities communicated in the following chart.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 27

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 the IFRS diagnostic during 2008, which involved a high level review of the major differences between Canadian GAAP and IFRS. In-depth analysis of issues and accounting policy choices is currently underway.
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. |  | Project team expert resources have been identified to provide insights and training. Training for project team members is occurring 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 parallel processing requirements by 2009 and identify deficiency areas. Confirmation that business processes and systems are IFRS compliant will occur throughout the project. |  | Diagnostic analysis regarding current IT systems completed. Currently reviewing options to address business process changes and parallel processing during 2010.
Control Environment: – For all accounting policy changes identified, assess control design and effectiveness implications. – Implement appropriate changes. |  | All key control and design effectiveness implications are being assessed as part of the key IFRS differences and accounting policy choices through 2009. |  | Analysis of control issues is underway in conjunction with review of accounting issues and policies.
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 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 disclosure in the MD&A will be updated throughout the project. Vice President, Investor Relations is part of the IFRS Conversion Steering Committee.

RECENTLY ISSUED CANADIAN ACCOUNTING STANDARDS

Goodwill and Intangible Assets

In February 2008, the CICA approved Handbook section 3064 "Goodwill and Intangible Assets". Effective January 1, 2009, this new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs". The standard focuses on the criteria for asset recognition in the financial statements, including those internally developed. The new standard will not materially impact net earnings or financial position, however will result in the reclassification and presentation of certain balances on the balance sheet. At December 31, 2008, $566 million of turnaround costs would have been reclassified as part of property, plant and equipment (December 31, 2007 – $296 million).

28 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

OIL SANDS

Located near Fort McMurray, Alberta, our oil sands business forms the foundation of our operations and represents the most significant portion of our assets. The oil sands business recovers bitumen through mining and in-situ development and upgrades 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.

Oil sands strategy focuses on:

•
  Acquiring 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) |  | 2008 |  | 2007 |  | 2006 |
Revenue |  | 9 386 |  | 6 775 |  | 7 407 |
Production (thousands of bpd) |  | 228.0 |  | 235.6 |  | 260.0 |
Average sales price ($/barrel) |  | 95.96 |  | 74.01 |  | 68.03 |
Net earnings |  | 2 875 |  | 2 474 |  | 2 775 |
Cash flow from operations (1) |  | 3 838 |  | 3 143 |  | 3 903 |
Total assets |  | 25 795 |  | 18 172 |  | 13 727 |
Cash used in investing activities |  | 6 996 |  | 4 248 |  | 2 230 |
Net cash surplus (deficiency) before financing activities |  | (2 555 | ) | (519 | ) | 2 113 |
Sales mix (light/heavy mix) |  | 43/57 |  | 54/46 |  | 53/47 |
Cash operating costs ($/barrel) (1) |  | 38.50 |  | 27.80 |  | 21.70 |
ROCE (%) (1), (2) |  | 35.5 |  | 43.0 |  | 53.1 |
ROCE (%) (1), (3) |  | 21.8 |  | 27.9 |  | 39.8 |

(1)
  Non-GAAP measure. See page 40.
(2)
  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.
(3)
  Includes capitalized costs related to major projects in progress.

2008 Overview

•
  Oil sands production averaged 228,000 bpd in 2008, compared to 235,600 bpd in 2007. Production was down year-over-year primarily as the result of upgrader reliability and bitumen production issues. In addition, an unplanned shutdown of facilities that supply hydrogen reduced production of higher-value sweet synthetic crude oil and diesel during the third quarter of 2008.
•
  Oil sands cash operating costs averaged $38.50 per barrel during 2008, compared to $27.80 per barrel in 2007. The higher costs in 2008 are primarily due to increases in operating expenses, natural gas input costs and third-party bitumen purchases being spread over lower production.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 29

•
  On January 20, 2009, Suncor's Board of Directors approved a revised capital budget which deferred the company's growth projects in light of recent market conditions. With the revised plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.
•
  During 2008, progress was made on a variety of capital projects that are expected to benefit operational reliability, production and sales. The addition of a new $2.3 billion set of cokers to our upgrading complex, which increased design capacity to 350,000 bpd, was completed during the year. Other work included construction of a naphtha unit (which is intended to enhance product mix) which was approximately 60% complete at year-end, and the Steepbank extraction plant which was approximately 70% complete at year-end.
•
  During 2008, we continued to make progress on our Voyageur growth strategy. At December 31, 2008, we had spent approximately $7.0 billion out of the total Voyageur program budget of $20.6 billion.
•
  Production from Suncor's Firebag in-situ operations had been limited by regulators to 42,000 bpd due to sulphur emissions that exceeded regulatory limits in 2007. This production cap was lifted during the third quarter of 2008.

Analysis of Net Earnings

Net earnings were $2.875 billion in 2008, compared to $2.474 billion in 2007 (2006 – $2.775 billion). Excluding the impacts of income tax rate reductions on opening future income tax liabilities, net insurance proceeds received in 2006 (relating to the January 2005 fire) and project start-up costs, earnings were $2.899 billion in 2008, compared to $2.104 billion in 2007 (2006 – $2.140 billion).

(1)
  Future income tax.

The increase in earnings primarily reflects strong price realizations due to high average benchmark WTI crude oil prices during the first three quarters of the year. This was partially offset by increased operating expenses, decreased production of higher-value sweet crude oil products, and significantly lower price realizations in the fourth quarter of 2008.

Oil sands average production was 228,000 bpd in 2008, compared to 235,600 bpd in 2007. Sales volumes in 2008 averaged 227,000 bpd, compared with 234,700 bpd in 2007. Lower sales volumes decreased 2008 net earnings by $206 million. Production and sales volumes were lower in 2008 due mainly to upgrader reliability and bitumen supply issues. This was partially offset by a shorter planned maintenance shutdown during 2008 (38 days in 2008, compared to a 50-day shutdown in 2007).

Sales price realizations averaged $95.96 per barrel in 2008 (including the impact of pretax hedging losses of $31 million), compared with $74.01 per barrel in 2007 (with pretax hedging losses of $5 million). The average sales price realization was favourably impacted by stronger WTI benchmark crude oil prices and strengthening differentials on our sweet crude blend and diesel products relative to WTI, partially offset by an increased discount to WTI for our sour crude blends and an increased proportion of lower priced sour products in our sales mix.

The net impact of the above sales mix and pricing factors increased net earnings by $2.084 billion in 2008.

30 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

Cash Expenses

Cash expenses, which include purchases of crude oil and products, operating, selling and general expenses, transportation and other costs, exploration expenses, and taxes other than income taxes, were $4.055 billion in 2008, compared to $2.782 billion in 2007 (2006 – $2.560 billion). Expenses increased year-over-year primarily due to higher maintenance expenditures aimed at improving reliability, increased energy input costs as a result of strong natural gas pricing, and a significant increase in purchases of both third-party bitumen and product related to transportation of sour crude shipments.

Overall, increased cash expenses reduced net earnings by $941 million.

Royalties

Alberta oil sands Crown royalties increased to $715 million in 2008, compared to $565 million in 2007 (2006 – $911 million). The increased royalty expense is due primarily to higher revenues resulting from strong WTI crude pricing during the first nine months of the year. This was partially offset by the impact of higher operating expenses, lower volumes, and higher capital expenditures eligible for deduction under Crown royalty formulas. Alberta oil sands Crown royalties are subject to completion of audits for 2008 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 page 15.

Non-Cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $580 million in 2008 from $462 million in 2007 (2006 – $385 million). The increase primarily resulted from continued growth in the depreciable cost base after the commissioning of new assets throughout the year. Higher non-cash expenses decreased net earnings by $95 million.

Revaluation of Future Income Taxes

Reductions to the federal income tax rate in the second and fourth quarters of 2007 resulted in a total decrease of $413 million in the oil sands opening future income tax (FIT) liability balance, and a corresponding increase in the net earnings of the oil sands segment. There were no adjustments to income tax rates during 2008.

Cash Operating Costs

Cash operating costs increased to $3.212 billion in 2008, compared to $2.391 billion in 2007. On a per barrel basis, these costs increased to $38.50 per barrel from $27.80 per barrel in 2007. The increase in cash operating costs per barrel is a result of increases in operating expenses, natural gas input costs and third-party bitumen purchases being spread over lower production. Refer to page 40 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Net Cash Surplus (Deficiency) Analysis

Cash flow from operations was $3.838 billion in 2008, compared to $3.143 billion in 2007 (2006 – $3.903 billion). The increase was primarily due to the same factors that impacted net earnings.

Cash flow used in investing activities increased to $6.996 billion in 2008 from $4.248 billion in 2007 (2006 – $2.230 billion). During 2008, capital spending related primarily to our Voyageur program, Steepbank extraction plant and naphtha unit projects.

Combined, the above factors resulted in a net cash deficiency of $2.555 billion in 2008, compared with a deficiency of $519 million in 2007 (2006 – net cash surplus of $2.113 billion).

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 31

Future Expansion

In 2001, Suncor announced plans to pursue a multi-phased growth strategy to increase production capacity at its oil sands plant from 225,000 barrels per day (bpd) to 550,000 bpd in 2012.

The first step in that plan was completed in 2005 when Suncor increased production capacity by 35,000 bpd (bringing total production capacity to 260,000 bpd). During 2008, we completed a $2.3 billion expansion to one of our two upgraders, increasing production design capacity to 350,000 bpd.

Suncor's Board of Directors approved the final phase of this multi-staged growth strategy in January 2008. Our total estimated investment of $20.6 billion for the Voyageur program was comprised of $11.6 billion targeted for construction of a third upgrader and $9 billion for expanding bitumen supply at our Firebag in-situ operation.

In response to current market uncertainty, we announced an update to our Voyageur program schedule on January 20, 2009. A revised capital budget has deferred the company's growth projects. With the new plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.

For further details, see the Significant Capital Projects table on page 14.

Risk Factors Affecting Performance

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

•
  Our ability to finance oil sands growth and sustaining capital expenditures in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 12.
•
  Production reliability risk. Our ability to reliably operate our oil sands facilities in order to meet production targets. We implemented planned maintenance shutdowns in 2008 that are expected to improve reliability.
•
  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 the Fort McMurray infrastructure (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. Current prices are well below the average price realized in 2008. We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 17).
•
  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 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 2,300 oil sands employees. The current collective agreement with the union expires on April 30, 2010.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

32 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

NATURAL GAS

Suncor's natural gas business, operating primarily in western Canada, acts as a natural price hedge against the company's purchases for internal consumption at our oil sands operations.

Natural gas strategy focuses on:

•
  Building competitive operating areas.
•
  Improving base business efficiency, with a focus on operational excellence and work site safety.
•
  Pursuing new, low-capital business opportunities.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2008 |  | 2007 |  | 2006 |  |
Revenue |  | 754 |  | 553 |  | 578 |  |
Natural gas production (mmcf/d) |  | 202 |  | 196 |  | 191 |  |
Average natural gas sales price ($/mcf) |  | 8.23 |  | 6.32 |  | 7.15 |  |
Net earnings |  | 89 |  | 25 |  | 106 |  |
Cash flow from operations (1) |  | 368 |  | 248 |  | 281 |  |
Total assets |  | 1 862 |  | 1 811 |  | 1 503 |  |
Cash used in investing activities |  | 316 |  | 532 |  | 443 |  |
Net cash surplus (deficiency) before financing activities |  | 94 |  | (262 | ) | (189 | ) |
ROCE (%) (1) (2) |  | 7.7 |  | 2.5 |  | 14.9 |  |

(1)
  Non-GAAP Measure. See page 40.
(2)
  ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.

2008 Overview

•
  Total production averaged 220 million cubic feet equivalent per day (mmcfe/d) in 2008, compared to 215 mmcfe/d in 2007. Production during 2008 comprised 92% natural gas and 8% natural gas liquids and crude oil.
•
  Purchases of natural gas for internal consumption at our oil sands operations were approximately 143 million cubic feet per day (mmcf/d) during 2008, compared to natural gas production of 202 mmcf/d in 2008.
•
  During the second quarter of 2008, Suncor disposed of Arctic properties for proceeds of $24 million.
•
  In September, Suncor, together with a partner, successfully bid for a large offshore parcel in the Newfoundland and Labrador Offshore Area. This land is adjacent and complementary to an existing holding in the Bjarni area and provides Suncor with a long-term option for future potential natural gas growth. In order to retain the lands, the exploration license requires Suncor to commit to spend net $30 million in exploration work on the lands within six years.

(1)
  Purchases for internal consumption at our oil sands operations.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 33

Analysis of Net Earnings

Natural gas net earnings were $89 million in 2008, compared to $25 million in 2007 (2006 – $106 million). Excluding the impact of income tax rate reductions on opening future income tax liabilities, earnings for 2008 were $89 million, compared to a loss of $14 million in 2007 (2006 – net earnings of $53 million). The increase in earnings was primarily due to higher revenues driven by stronger price realizations including higher sulphur prices and increased production, in addition to a gain on sale of non-core assets and lower dry hole costs. These factors were partially offset by higher royalties and increased depreciation, depletion and amortization expense resulting from increased production from areas with larger capital bases relative to assigned reserves.

The average realized price for natural gas was $8.23 per thousand cubic feet (mcf) in 2008, compared to an average of $6.32 per mcf in 2007, reflecting higher benchmark natural gas prices in the first three quarters of 2008. There was also an increase in price realizations for crude oil and natural gas liquids resulting from higher benchmark prices for those products in the first three quarters of 2008. The net impact of the price variance was an increase in net earnings of $94 million. Strong pricing was also experienced on our sulphur products, resulting in a $36 million positive impact to net earnings.

Natural gas total production was 220 mmcfe/d in 2008, compared to 215 mmcfe/d in the prior year. The increase in 2008 production was primarily due to increased volumes from positive drilling results, offset by natural declines. Increased production volumes positively impacted 2008 net earnings by $11 million.

Cash Expenses

Operating costs, including general and administrative expenses, were $155 million in 2008, a slight increase from $151 million in 2007 (2006 – $119 million). An increase in lifting costs resulting from increased volumes from areas with higher processing costs and reduced third-party processing credits, was partially offset by a reduction in administration costs.

Exploration expenses were $73 million in 2008, compared to $82 million in 2007 (2006 – $82 million). The decrease was mainly due to lower dry hole costs in 2008.

Non-Cash expenses

DD&A expense was $225 million in 2008, compared to $189 million in 2007 (2006 – $152 million). The increase was due to production increases in areas with a higher cost structure.

Royalties

Royalties on production of natural gas, liquids and sulphur were $175 million ($2.17 per thousand cubic feet equivalent (mcfe)) in 2008, an increase from $126 million ($1.61 per mcfe) in 2007 (2006 – $127 million; $1.67 per mcfe). The current year saw both higher production and higher sales price realizations. In 2008 the government of Alberta announced the New Royalty Framework which changed the royalty rates beginning January 1, 2009. Natural gas generated about 76% of its production from Alberta in 2008. For a further discussion on Crown royalties, see page 15.

34 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

Net Cash Surplus/Deficiency Analysis

Natural gas net cash surplus was $94 million in 2008, compared with a $262 million deficiency in 2007 (2006 – $189 million deficiency). Cash flow from operations increased to $368 million compared with $248 million in the prior year (2006 – $281 million), mainly due to increased revenues.

Cash used in investing activities decreased to $316 million, compared with $532 million in 2007 (2006 – $443 million) primarily due to a large purchase of developed and undeveloped land made in 2007, as well as reduced drilling activity in 2008.

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 12.
•
  Volatility in natural gas and liquids prices is not predictable and can significantly impact revenues. Current prices are well below the average price realized in 2008.
•
  The impact of market demand for land. Market demand also influences the cost and available opportunities for acquisitions.
•
  The impact of market demand for labour and equipment, which in a heated exploration and development market, could increase costs and/or cause delays to projects for natural gas and its competitors.
•
  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 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 35

REFINING AND MARKETING

Refining and marketing operates an 85,000 barrel per day (bpd) capacity refinery in Sarnia, Ontario and a 93,000 bpd capacity refining complex in Commerce City, Colorado, and markets refined products to industrial, wholesale and commercial customers primarily in Ontario and Colorado. Through a combination of joint venture-operated, company-owned and branded-reseller retail stations, we market products to retail customers in Ontario and the Denver area. Assets also include a 200-million litre per year ethanol plant in St. Clair, Ontario, the 480-kilometre Rocky Mountain pipeline system, the 140-kilometre Centennial pipeline system, two product terminals in Ontario, and two product terminals in Colorado. This business also supports Suncor's sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

The refining and marketing business also encompasses third-party energy marketing and trading activities, as well as providing marketing services for the sale of crude oil, natural gas, refined products and by-products from the oil sands and natural gas segments.

Refining and marketing's strategy is focused on:

•
  Enhancing the profitability of refining operations by improving reliability and 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.
•
  Reducing costs through the application of technologies, economies of scale, an increased focus on reliability through carefully managed maintenance scheduling, strategic alliances with key suppliers and customers and continuous improvement of operations.
•
  Increasing the profitability and efficiency of our retail networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted) |  | 2008 |  | 2007 |  | 2006 |  |
Revenue |  | 21 371 |  | 11 805 |  | 9 310 |  |
Refined product sales (millions of litres) |  |  |  |  |  |  |  |
| Gasoline |  | 5 819 |  | 6 132 |  | 5 804 |  |
| Total |  | 11 529 |  | 12 228 |  | 10 803 |  |
Net earnings breakdown: |  |  |  |  |  |  |  |
| Downstream earnings |  | 58 |  | 403 |  | 239 |  |
| Energy marketing and trading activities |  | 71 |  | 35 |  | 22 |  |
| Inventory valuation and marketing expense |  | (78 | ) | 6 |  | (17 | ) |
| Total net earnings |  | 51 |  | 444 |  | 244 |  |
Cash flow from operations (1) |  | 278 |  | 716 |  | 451 |  |
Total assets |  | 4 666 |  | 4 825 |  | 4 219 |  |
Cash used in investing activities |  | (256 | ) | (491 | ) | (787 | ) |
Net cash deficiency before financing activities |  | (8 | ) | (29 | ) | (446 | ) |
ROCE (%) (1) (2) |  | 1.7 |  | 20.0 |  | 19.3 |  |
ROCE (%) (1) (3) |  | 1.7 |  | 17.4 |  | 12.2 |  |

(1)
  Non-GAAP measure. See page 40.
(2)
  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.
(3)
  Includes capitalized costs related to major projects in progress.

36 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

2008 Overview

•
  Lower gasoline margins and demand, weak asphalt and residual pricing, and a decline in crude oil prices at the end of 2008 that reduced the value of our inventories negatively impacted earnings in 2008. This was partially offset by stronger distillate fuel margins.
•
  Significantly increased energy marketing and trading activities as a result of the implementation and further development of crude and natural gas trading strategies to maximize value from proprietary production and for refinery optimization and gain market expertise and market presence. Increased earnings from these activities were largely the result of gains on crude oil financial contracts.
•
  During the second quarter, additional capital equipment improvements were identified that will be required before the Sarnia refinery can achieve full benefit from modifications made in 2007 to increase sour synthetic crude capacity at the facility. We are currently evaluating our options relating to these capital expenditures.
•
  Refinery utilization levels were slightly lower due to softening demand for petroleum products as well as additional scheduled and unscheduled maintenance.
•
  The observed performance of our Sarnia refinery in 2008, after completion of our diesel desulphurization and oil sands integration project in 2007, has enabled us to upwardly revise our nameplate capacity to 85,000 bpd from the previously disclosed 70,000 bpd. Starting January 1, 2009, refinery utilization will be calculated using the 85,000 bpd capacity. The Commerce City refining capacity has also been increased from 90,000 bpd to 93,000 bpd effective January 1, 2009.

Analysis of Net Earnings

Refining and marketing results include the impact of our third-party energy marketing and trading activities that are discussed separately on page 38.

Refining and marketing's net earnings decreased to $51 million in 2008 from $444 million in 2007 (2006 – $244 million). This decrease was primarily due to reduced margins on gasoline, asphalt and other heavy products, as well as softening demand for petroleum products due initially to historically high prices and later to general economic conditions. This was partially offset by increased margins on distillate fuels.

Volumes

Total sales volumes averaged 31.5 10 3m 3/d (thousands of cubic metres per day), compared to 33.5 10 3m 3/d in 2007. The decrease in sales was the result of softening demand for petroleum products. Total gasoline sales volumes through our Sunoco and Phillips 66® branded retail network were 1,700 million litres in 2008, down from 1,900 million litres in 2007.

Fuel Margins

Gasoline margins were significantly lower in 2008 as a result of reduced demand for gasoline. We also encountered reduced margins on asphalt mainly due to the high crude price environment. Asphalt margins did recover in the fourth quarter as the price of crude lowered. These factors were partially offset by increased margins on distillate fuels resulting from strong market demand for diesel and jet fuel throughout the year. Crude and product purchases were $8.074 billion in 2008, compared to $6.250 billion in 2007 (2006 – $5.297 billion). The increase was primarily the result of higher crude oil prices during the first three quarters of 2008.

Refinery Utilization

Overall crude refinery utilization averaged 97% in 2008, compared with 98% in 2007. The decrease in refinery utilization was primarily the result of softening demand for petroleum products and additional scheduled and unscheduled maintenance.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 37

Cash and Non-Cash Expenses

Overall, cash and non-cash operating expenses increased by $38 million after-tax in 2008. Cash expenses increased by $18 million after-tax in 2008, primarily due to higher energy and employee related costs. Non-cash expenses increased by $20 million after-tax in 2008, due to increased depreciation, depletion and amortization expense mainly resulting from a full year's depreciation being taken on both the Sarnia refinery oil sands integration project that was completed in 2007 and a comprehensive maintenance turnaround at Sarnia that was completed in the fall of 2007.

Related Party Transactions

The Pioneer and UPI retail facilities joint ventures and the Sun Petrochemicals Company (SPC) joint venture are considered to be related parties to Suncor under Canadian GAAP. Refining and marketing supplies refined petroleum products to the Pioneer and UPI joint ventures, and petrochemical products to SPC. Suncor has a separate supply agreement with each of Pioneer, UPI and SPC.

The following table summarizes our related party transactions with Pioneer, UPI and SPC, after eliminations, for the year. These transactions are in the normal course of operations and have been conducted on the same terms as would apply with third parties.

($ millions) |  | 2008 |  | 2007 |  | 2006 |
Operating revenues |  |  |  |  |  |  |
| Sales to refining and marketing joint ventures: |  |  |  |  |  |  |
|  | Refined products |  | 368 |  | 329 |  | 294 |
|  | Petrochemicals |  | 188 |  | 163 |  | 136 |

At December 31, 2008, amounts due from refining and marketing joint ventures were $13 million, compared to $17 million at December 31, 2007.

Energy Marketing and Trading Activities

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 net earnings after-tax of $71 million in 2008 compared to $35 million in 2007 (2006 – $22 million). The higher earnings in 2008 compared to 2007 were the result of gains on crude oil financial contracts. For further details on our energy marketing and trading activities, see page 17.

Net Cash Deficiency Analysis

Refining and marketing's net cash deficiency was $8 million in 2008 compared to a net cash deficiency of $29 million in 2007 (2006 – $446 million). Cash flow from operations was $278 million in 2008 compared to $716 million in 2007 (2006 – $451 million). The decrease was primarily due to the same factors that impacted net earnings.

Cash used in investing activities was $256 million in 2008 compared to $491 million in 2007 (2006 – $787 million). Capital expenditures in 2008 were significantly lower than the previous year, as the work related to the Sarnia oil sands integration projects was completed in 2007. Capital spending in 2008 related mainly to planned refinery shutdowns as well as other regulatory related project spending.

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.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

38 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

OUTLOOK

During 2009, 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.
•
  Achieve annual oil sands production of 300,000 bpd (+5%/-10%) at a cash operating cost average of $33 to $38 per barrel. Increased bitumen supply and reliability improvements in extraction and upgrading are expected to increase production from existing capital assets.
•
  Target production from our natural gas business of 210 mmcf equivalent per day (+5%/-5%). Continue to pursue exploration and development of natural gas assets to offset natural gas purchases for internal consumption at our oil sands operations.
•
  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.
•
  Maintain a strong balance sheet. Planned capital spending has been reduced to $3 billion for 2009, with major growth capital investment deferred. Strategic hedging of 60% of target 2009 production provides a degree of insurance to the balance sheet.
•
  Continue efforts to reduce environmental impact intensity. We expect to complete the sulphur recovery plant at Firebag in mid-2009 with start-up and commissioning taking place throughout the remainder of the year, while work will continue on developing accelerated reclamation technology. Improved oil sands plant reliability is expected to contribute to lower energy and emissions intensity.

Suncor's outlook provides management's targets for 2009 in certain key areas of the company's business. Users of this information are cautioned that the actual results in 2009 may vary materially from the targets disclosed. Readers are cautioned against placing undue reliance on this outlook.

|  | 2009 Full-Year Outlook |
Oil Sands |  |  |
Production (1) (bpd) |  | 300,000 (+5%/-10%) |
Sales |  |  |
| Diesel |  | 11% |
| Sweet |  | 39% |
| Sour |  | 48% |
| Bitumen |  | 2% |
Realization on crude sales basket |  | WTI @ Cushing less Cdn$4.50 to Cdn$5.50 per barrel |
Cash operating costs (2) |  | $33 to $38 per barrel |
Natural Gas |  |  |
Production (3) (mmcf equivalent per day) |  | 210 (+5%/-5%) |
| Natural gas |  | 92% |
| Liquids |  | 8% |

(1)
  Includes volumes transferred to Suncor for processing for which the company receives a processing fee. Volumes received under this arrangement are not included as purchases for financial statement presentation.
(2)
  Cash operating cost estimates are based on the following assumptions: (i) production volumes and sales mix as described in the table above; and (ii) a natural gas price of $7.10 per gigajoule at AECO. This goal also includes costs incurred for third-party bitumen processing. Cash operating costs per barrel are not prescribed by Canadian generally accepted accounting principles (GAAP). This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Suncor includes this non-GAAP financial measure because investors may use this information to analyze operating performance. This information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See Non-GAAP Financial Measures on page 40.
(3)
  Production target includes natural gas liquids (NGL) and crude oil converted into mmcf equivalent at a ratio of one barrel of NGL/crude oil: six thousand cubic feet of natural gas. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This mmcf equivalent may be misleading, particularly if used in isolation.

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 39

The 2009 outlook is based on Suncor's current estimates, projections and assumptions for the 2009 fiscal year and is subject to change. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. Assumptions of the 2009 outlook include implementing reliability and operational efficiency initiatives which we expect to minimize unplanned maintenance in 2009.

Factors that could potentially impact Suncor's operations and financial performance in 2009 include:

•
  Bitumen supply. Ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in-situ reservoir performance could impact 2009 production targets. Production could also be impacted by the availability of third-party bitumen.
•
  Performance of recently commissioned upgrading 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 or pipeline assets.
•
  Crude oil hedges. Suncor has hedging agreements for approximately 60% of targeted production in 2009 and for 50,000 bpd in 2010.
•
  Market instability. Suncor's ability to borrow in the capital debt markets at acceptable rates may be affected by market instability.

For additional information on risk factors that could cause actual results to differ, please see page 19.

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.

Cash Flow from Operations per Common Share

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of our Consolidated Financial Statements.

For the year ended December 31 |  |  |  | 2008 |  | 2007 |  | 2006 |
Cash flow from operations ($ millions) |  |  |  | 4 463 |  | 4 009 |  | 4 524 |
Weighted average number of common shares outstanding – basic (millions of shares) |  |  |  | 932 |  | 922 |  | 918 |
Cash flow from operations – basic ($ per share) |  |  |  | 4.79 |  | 4.35 |  | 4.93 |

40 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

ROCE

For the year ended December 31 ($ millions, except ROCE) |  |  |  | 2008 |  | 2007 |  | 2006 |
Adjusted net earnings |  |  |  |  |  |  |  |  |
Net earnings |  |  |  | 2 137 |  | 2 983 |  | 2 969 |
Add: after-tax financing expenses (income) |  |  |  | 852 |  | (179 | ) | 26 |
|  | A |  | 2 989 |  | 2 804 |  | 2 995 |
Capital employed – beginning of year |  |  |  |  |  |  |  |  |
Short-term and long-term debt, less cash and cash equivalents |  |  |  | 3 248 |  | 1 849 |  | 2 868 |
Shareholders' equity |  |  |  | 11 896 |  | 9 084 |  | 6 130 |
|  | B |  | 15 144 |  | 10 933 |  | 8 998 |
Capital employed – end 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 |
|  | C |  | 21 749 |  | 15 144 |  | 10 933 |
Average capital employed |  | (B+C)/2=D |  | 18 447 |  | 13 039 |  | 9 966 |
Average capitalized costs related to major projects in progress |  | E |  | 5 149 |  | 3 454 |  | 2 476 |
ROCE (%) |  | A/(D-E) |  | 22.5 |  | 29.3 |  | 40.0 |

Oil Sands Operating Costs – Total Operations

|  | 2008 |  | 2007 |  | 2006 |
(unaudited) |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |
Operating, selling and general expenses |  | 3 124 |  |  |  | 2 384 |  |  |  | 2 212 |  |  |
| Less: natural gas costs, inventory changes, stock-based compensation and other |  | (524 | ) |  |  | (301 | ) |  |  | (375 | ) |  |
| Less: non-monetary transactions |  | (111 | ) |  |  | (102 | ) |  |  | (126 | ) |  |
Accretion of asset retirement obligations |  | 55 |  |  |  | 40 |  |  |  | 28 |  |  |
Taxes other than income taxes |  | 80 |  |  |  | 55 |  |  |  | 36 |  |  |
Cash costs |  | 2 624 |  | 31.45 |  | 2 076 |  | 24.15 |  | 1 775 |  | 18.70 |
Natural gas |  | 438 |  | 5.25 |  | 307 |  | 3.55 |  | 276 |  | 2.90 |
Imported bitumen (net of other reported product purchases) |  | 150 |  | 1.80 |  | 8 |  | 0.10 |  | 6 |  | 0.10 |
Cash operating costs |  | 3 212 |  | 38.50 |  | 2 391 |  | 27.80 |  | 2 057 |  | 21.70 |
Project start-up costs |  | 35 |  | 0.40 |  | 60 |  | 0.95 |  | 38 |  | 0.40 |
Total cash operating costs |  | 3 247 |  | 38.90 |  | 2 451 |  | 28.75 |  | 2 095 |  | 22.10 |
Depreciation, depletion and amortization |  | 580 |  | 6.95 |  | 462 |  | 5.40 |  | 385 |  | 4.05 |
Total operating costs |  | 3 827 |  | 45.85 |  | 2 913 |  | 34.15 |  | 2 480 |  | 26.15 |
Production (thousands of barrels per day) |  |  |  | 228.0 |  |  |  | 235.6 |  |  |  | 260.0 |

Oil Sands Operating Costs – In-Situ Bitumen Production Only

|  | 2008 |  | 2007 |  | 2006 |
(unaudited) |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |  | $ millions |  | $/barrel |
Operating, selling and general expenses |  | 334 |  |  |  | 273 |  |  |  | 209 |  |  |
Less: natural gas costs and inventory changes |  | (168 | ) |  |  | (134 | ) |  |  | (103 | ) |  |
Taxes other than income taxes |  | 12 |  |  |  | 7 |  |  |  | 4 |  |  |
Cash costs |  | 178 |  | 13.00 |  | 146 |  | 10.85 |  | 110 |  | 8.95 |
Natural gas |  | 168 |  | 12.30 |  | 134 |  | 9.90 |  | 103 |  | 8.35 |
Cash operating costs |  | 346 |  | 25.30 |  | 280 |  | 20.75 |  | 213 |  | 17.30 |
In-situ (Firebag) start-up costs |  | 9 |  | 0.65 |  | — |  | — |  | 21 |  | 1.70 |
Total cash operating costs |  | 355 |  | 25.95 |  | 280 |  | 20.75 |  | 234 |  | 19.00 |
Depreciation, depletion and amortization |  | 87 |  | 6.35 |  | 83 |  | 6.20 |  | 68 |  | 5.55 |
Total operating costs |  | 442 |  | 32.30 |  | 363 |  | 26.95 |  | 302 |  | 24.55 |
Production (thousands of barrels per day) |  |  |  | 37.4 |  |  |  | 36.9 |  |  |  | 33.7 |

SUNCOR ENERGY INC. 2008 ANNUAL REPORT 41

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 made by the company in light of its experience and its perception of historical trends.

All statements and other information that address expectations or projections about the future, including statements about Suncor's strategy for growth, expected 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," 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 outlook includes a production range of +5%/-10% 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 the 2009 outlook, see page 40.

The risks, uncertainties and other factors that could influence actual results include, but are not limited to, 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 cashflow 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 (for example, the emissions reduction modifications at our Firebag in-situ development); 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 and 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; and 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. These foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in the company'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.

42 SUNCOR ENERGY INC. 2008 ANNUAL REPORT

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EXHIBIT 99-2

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008, DATED FEBRUARY 25, 2009