All financial figures are unaudited and in Canadian dollars unless noted otherwise. Certain financial measures referred to in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these measures, see Non-GAAP Financial Measures on page 9. This document makes reference to barrels of oil equivalent (boe). A boe conversion ratio of six thousand cubic feet of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Accordingly, boe measures may be misleading, particularly if used in isolation.

On August 1, 2009, Suncor Energy Inc. completed its merger with Petro-Canada. The three and twelve month amounts ending December 31, 2009 reflect results of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1 through July 31, 2009. The comparative figures reflect solely the 2008 results of legacy Suncor. For further information with respect to the merger transaction, please refer to note 3 to the December 31, 2009 unaudited interim consolidated financial statements.

Suncor Energy Inc. recorded fourth quarter 2009 net earnings of $457 million ($0.29 per common share), compared to a net loss of $215 million ($0.24 per common share) for the fourth quarter of 2008. Operating earnings⁽¹⁾ in the fourth quarter of 2009 were $323 million ($0.21 per common share), compared to $14 million ($0.02 per common share) in the fourth quarter of 2008. Cash flow from operations⁽²⁾ was $1.129 billion in the fourth quarter of 2009, compared to $231 million in the fourth quarter of 2008.

The increase in operating earnings and cash flow from operations in the fourth quarter of 2009 was primarily due to increased upstream production and refined product sales volumes resulting from the merger with Petro-Canada, higher price realizations due to stronger benchmark crude oil prices in the fourth quarter of 2009 compared to the same period in 2008, however these realizations were partially offset by realized losses of approximately $185 million after-tax on risk management derivative contracts, and increased production from Suncor's legacy oil sands operations resulting from improved operational reliability. These factors were partially offset by higher operating expenses that resulted from the merger with Petro-Canada and the increased production at our legacy oil sands operations, increased royalty expense due to the higher benchmark crude oil prices, and a fire at one of our upgraders in December 2009 which impacted overall production in the fourth quarter of 2009 by approximately 30,000 barrels per day.

"We started the year confronting one of the most challenging global economic downturns of the past century, but today Suncor is a larger, stronger and more financially flexible company as we continue to realize some significant synergies following the merger with Petro-Canada," said Rick George, president and chief executive officer. "We've made gains on achieving safe, reliable and cost-effective energy production across all our operations in 2009, which we intend to build on in 2010."

Operating earnings is a non-GAAP measure that the company uses to evaluate operating performance, which management believes allows better comparability between periods. Operating earnings is calculated by adjusting net earnings for significant one-time items and items that are not indicative of operating performance. See page 9 for discussion of non-GAAP financial measures.


		Three months ended December 31				Twelve months ended December 31
($ millions, after-tax)		2009		2008		2009		2008

Net earnings (loss) as reported		457		(215	)	1 146		2 137
	Change in fair value of commodity derivatives used for risk management ⁽¹⁾	(88	)	(372	)	499		(372	)
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(157	)	645		(798	)	852
	Mark-to-market valuation of stock-based compensation	6		(48	)	124		(107	)
	Project start-up costs	10		4		40		24
	Impact of income tax rate adjustments on future income tax liabilities ⁽²⁾	(148	)	—		4		—
	Costs related to deferral of growth projects	83		—		300		—
	Gain on effective settlement of pre-existing contract with Petro-Canada ⁽³⁾	—		—		(438	)	—
	Impact of recording acquired inventory at fair value ⁽⁴⁾	—		—		97		—
	Merger and integration costs	79		—		151		—
	Losses and adjustments on significant disposals⁽⁵⁾	81		—		81		—

Operating earnings		323		14		1 206		2 534

Suncor's total upstream production during the fourth quarter of 2009 averaged 638,200 barrels of oil equivalent (boe) per day, including additional production of 325,600 boe per day resulting from the merger. Upstream production from Suncor's legacy oil sands and natural gas operations averaged 312,600 boe per day in the fourth quarter of 2009, compared to 279,400 boe per day in the fourth quarter of 2008.

Oil Sands production (excluding proportionate production share from the Syncrude joint venture) contributed an average 278,900 barrels per day (bpd) in the fourth quarter of 2009, compared to fourth quarter 2008 production of 243,800 bpd. Average production increased compared to the fourth quarter of 2008 as a result of improved operational reliability during the quarter. However, production volumes were negatively impacted by unplanned maintenance activities following the upgrader fire in December 2009.

Cash operating costs for our oil sands operations (excluding Syncrude) averaged $38.70 per barrel in the fourth quarter of 2009, compared to $41.30 per barrel during the fourth quarter of 2008. The decrease in cash operating costs per barrel was primarily due to increased production and a decrease in natural gas input prices. These factors were partially offset by an increase in operational expenses due to the inclusion of operating costs from MacKay River facilities in the fourth quarter of 2009. The merger with Petro-Canada did not result in increased oil sands production volumes (excluding Syncrude), as production from MacKay

Suncor Energy Inc.
002 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

River had been included in Suncor's reported production from January 1 to July 31, 2009 as volumes processed by Suncor under a processing fee agreement. Production from MacKay River averaged 31,700 bpd in the fourth quarter of 2009.

Suncor's proportionate production share from the Syncrude joint venture contributed an average 39,300 bpd of sweet synthetic crude production during the fourth quarter of 2009.

Production from Suncor's natural gas business during the fourth quarter of 2009 averaged 764 million cubic feet equivalent (mmcfe) per day. Production from Suncor's legacy natural gas operations averaged 202 mmcfe per day in the fourth quarter of 2009, compared to 213 mmcfe per day in the fourth quarter of 2008. This decrease in production was primarily due to shut-in production in the Elmworth area and the sale of certain non-core assets in the second quarter of 2009.

During the fourth quarter of 2009, East Coast Canada production contributed an average 63,600 bpd, while production from our International segment (comprising our assets in the North Sea and other international areas) averaged 129,000 bpd. Production for both the East Coast Canada and International segments was lower than capacity primarily as a result of planned and unplanned maintenance, as well as OPEC production quota constraints in Libya.

Refining and Marketing's fourth quarter earnings reflected the merger with Petro-Canada and the impact of strong retail margins. Sales of refined petroleum products for the fourth quarter averaged 82.9 million litres per day, which included 52.7 million litres per day resulting from the merger. Suncor's legacy refining and marketing operations averaged 30.2 million litres per day in the fourth quarter of 2009, compared to 31.5 million litres per day for the same period in 2008.

At the company's annual and special meeting in June 2009, Suncor shareholders approved a merger with Petro-Canada. The merger subsequently closed on August 1, 2009, and Suncor became Canada's largest energy company and fifth largest North American-based energy company by market capitalization.

Net earnings for 2009 were $1.146 billion ($0.96 per common share), compared to $2.137 billion ($2.29 per common share) in 2008. Operating earnings in 2009 were $1.206 billion ($1.01 per common share), compared to $2.534 billion ($2.72 per common share) in 2008. Cash flow from operations was $2.799 billion in 2009, compared to $4.057 billion in 2008.

The decrease in 2009 operating earnings and cash flow from operations was primarily due to lower price realizations, as average benchmark commodity prices were significantly weaker in 2009 compared to 2008, in addition to realized losses of approximately $315 million after-tax on risk management derivative contracts as settlement prices were lower than benchmark prices for much of the year. These factors were partially offset by the increased upstream production and refined product sales volumes resulting from the merger with Petro-Canada, and improved operational performance from our existing oil sands assets.

After completion of the merger with Petro-Canada, Suncor's total upstream production during the final five months of 2009 averaged 635,200 boe per day, including additional production of 311,100 boe per day resulting from the merger.

Oil Sands production (excluding proportionate production share from the Syncrude joint venture) contributed an average 290,600 bpd in 2009, compared to 2008 production of 228,000 bpd. The increased production was primarily due to improved operational reliability in 2009, partially offset by unplanned maintenance activities following the upgrader fire in December 2009. Production in 2008 was negatively impacted by planned and unplanned maintenance shutdowns in our upgrading and extraction assets, as well as a regulatory imposed production cap on our Firebag in-situ operations. Syncrude operations contributed an average 38,500 bpd of sweet synthetic crude production in the last five months of 2009.

Oil Sands cash operating costs in 2009 (excluding Syncrude) averaged $33.95 per barrel, compared to $38.50 per barrel during 2008. The decrease in cash operating costs per barrel was primarily due to higher production and a decrease in natural gas input prices. These factors were partially offset by an increase in operational expenses due to the inclusion of operating costs from MacKay River facilities after completion of the merger.

Post-merger production from Suncor's natural gas business during the final five months of 2009 averaged 767 mmcfe per day. Production from Suncor's legacy natural gas operations averaged 210 mmcfe per day in 2009, compared to 220 mmcfe per day in 2008.

East Coast Canada production contributed an average 58,000 bpd during the final five months of 2009, while production from our International segment contributed an average 120,800 bpd in the same period. Production for both of these segments was lower than capacity primarily as a result of planned and unplanned maintenance, the tie-in of

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 003

the North Amethyst extension at White Rose, and OPEC production quota constraints in Libya.

Refining and Marketing's 2009 earnings reflected the positive impacts of the merger with Petro-Canada and improved operational reliability, partially offset by lower margins on light oil and decreased demand for refined petroleum products. Sales of refined petroleum products for the final five months averaged 84.8 million litres per day. Despite sales growth being constrained in 2009 by current economic conditions, total sales of refined petroleum products from Suncor's legacy refining and marketing operations averaged 32.6 million litres per day in 2009, compared to 31.5 million litres per day in 2008, reflecting increased refinery reliability.

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

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

"These are the first steps in our strategic plan to steadily increase oil sands production as we embark on a period of disciplined, but significant growth," said George. "Suncor enjoys the luxury of having more growth opportunity than we can immediately execute, so it's really a matter of ranking these opportunities and making sure we proceed with the right project at the right time and in the right way."

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

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

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

As part of its strategic business alignment, Suncor announced its intention to divest of a number of non-core assets. The proposed divestments identified to date include certain natural gas assets in Western Canada and the United States Rockies, all Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands.

On December 31, 2009, Suncor entered into an agreement to sell substantially all of its oil and gas producing assets in the United States Rockies for proceeds of $517 million (US$494 million), which is approximately equal to its net book value at December 31, 2009. The sale is expected to close in March 2010.

"As a result of the recent merger, Suncor now holds the largest single position in the oil sands industry," said George. "The combination of strategic investment in oil sands growth projects and strategic divestment of non-core assets will mean a steady shift in balance in favour of what has always been Suncor's core business."

In conjunction with the merger with Petro-Canada, the Competition Bureau of Canada required Suncor to divest 104 retail sites in Ontario. On December 8, 2009, Suncor entered into an agreement with Husky Energy whereby Suncor agreed to sell 98 sites with expected closing dates commencing in the first half of 2010 as ownership of individual sites is transferred to the purchaser.

While the timeline for the divestment of assets remains flexible, Suncor expects most of the sales to occur during 2010. Divestment proceeds will be used to reduce the company's debt.

Suncor Energy Inc.
004 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

A summary of the progress on our significant projects currently under construction is provided below. All projects listed below have received Board of Directors approval. The estimates and target completion dates do not include project commissioning and start-up.

Cost

Target

Project

Business
Segment

Plan

Estimate
$ millions

⁽¹⁾

Estimate
% Accuracy

⁽¹⁾

Spent
to date

completion
date

Firebag sulphur plant

Oil Sands

Support emission abatement plan at Firebag; capacity to support Stages 1-6

404

N/A

415

Complete

Steepbank extraction plant

Oil Sands

New location and technologies aimed at improving operational performance

980

N/A

1 015

Complete

Ebla gas project

International

Development of gas fields and construction of gas treatment plant

1 196

+7/-3

1 080

Q2 2010

Buzzard Enhancement Project ⁽²⁾

International

Installation of equipment to handle high sulphur content

339

+15/-10

163

Q4 2010

Firebag Stage 3

Oil Sands

Expansion is expected to increase bitumen supply

3 638

+10/-10

2 780

Q2 2011

Naphtha unit

Oil Sands

Increases sweet product mix

850

+4/-4

670

Q3 2011

North Amethyst ⁽²⁾

East Coast
Canada

Extension to the White Rose field involving sub-sea tie-in

490

+10/-5

230

2012

⁽³⁾

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 results to differ materially from those contained in the previous table, please see page 19 of our 2008 Annual Report and page 18 of legacy Petro-Canada's 2008 Annual Report. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 11.

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

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 005

Suncor's outlook provides management's targets for 2010 in certain key areas of the company's business. Users of this forward-looking information are cautioned that actual results may vary from the targets disclosed.


		2010 Full Year Outlook

Total production (boe per day) – before targeted divestitures ⁽¹⁾		644,000
Total production (boe per day) – related to targeted divestitures ⁽¹⁾		75,000

Oil Sands ⁽²⁾
Production (bpd)		300,000 (+/-5%)
Sales
	Diesel	8%
	Sweet	39%
	Sour	46%
	Bitumen	7%
Realization on crude sales basket ⁽³⁾		WTI @ Cushing less Cdn$4.75 to Cdn$5.75 per barrel
Cash operating costs ⁽⁴⁾		$35 to $39 per barrel

Syncrude production(bpd)		38,000 (+/-5%)

Natural Gas
	Production ⁽⁵⁾ (mmcfe per day) – before targeted divestitures ⁽¹⁾	680 (+/-5%)
	Production ⁽⁵⁾ (mmcfe per day) – related to targeted divestitures ⁽¹⁾	300
	Natural gas	91%
	Crude oil and liquids	9%

East Coast Canada
	Production (bpd)	55,000 (+/-5%)

International
	Production (boe per day) – before targeted divestitures ⁽¹⁾	138,000 (+/-5%)
	Production (boe per day) – related to targeted divestitures ⁽¹⁾	25,000
	Crude oil and liquids	87%
	Natural gas	13%

This outlook is based on Suncor's current estimates, projections and assumptions for the 2010 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 for the Oil Sands 2010 full year outlook include reliability and operational efficiency initiatives which we expect to minimize unplanned maintenance in 2010. Natural Gas, East Coast Canada and International 2010 outlook numbers include assumptions related to reservoir performance, drilling results, facility reliability, changes in OPEC production quotas, and execution of planned turnarounds within allotted time frames.

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

Suncor Energy Inc.
006 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The preceding paragraphs and tables contain forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the company's control. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 11.

We estimate we will have cash income taxes of approximately $800 million to $900 million during 2010. Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of deductibility of capital expenditures for income tax purposes, among other things. This estimate is based on the following assumptions: current forecasts of production, capital and operating costs and the commodity prices and exchange rates described in the royalty estimate tables on page 7 and 8, assuming there are no changes to the current income tax regime. Our outlook on cash income taxes is a forward-looking statement and users of this information are cautioned that actual cash income taxes may vary materially from our outlook.

For a description of the Alberta Crown royalty regimes in effect for our operated oil sands assets, see page 15 of our 2008 Annual Report.

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

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

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

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 007

For further information on risk factors related to royalty rates, please see page 42 of Suncor's Annual Information Form dated March 2, 2009.

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

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

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

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

Suncor Energy Inc.
008 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

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

Operating earnings (loss) represent net earnings (loss) excluding the change in fair value of commodity derivatives used for risk management, unrealized foreign exchange gain (loss) on U.S. dollar denominated long term debt, mark-to-market valuation of stock-based compensation, impact of income tax rate adjustments on future income tax liabilities, costs related to start-up or deferral of growth projects, and impacts related to the merger with Petro-Canada. Operating earnings are used by the Company to evaluate operating performance. See page 2 for a reconciliation of net earnings to operating earnings.

Cash flow from operations is expressed before changes in non-cash working capital. Cash flow from operations is the same measure as the cash flow from operating activities before changes in working capital measure that is included in the unaudited interim consolidated financial statements. Beginning in third quarter 2009, cash flow from operations adjusts for the impact of fair value changes on both the current and long-term portions of commodity derivatives and stock-based compensation (previously only adjusted the impact on the long-term portions). The company believes this provides more useful information to investors and allows better comparability between Suncor and other companies with similar adjustments for commodity derivatives and/or stock-based compensation. Prior period comparative figures have been restated. A reconciliation of net earnings to cash flow from operating activities before changes in working capital is provided in the Statement of Cash Flows and Schedules of Segmented Data, which are included in Suncor's December 31, 2009 unaudited interim consolidated financial statements.

Suncor provides a detailed numerical reconciliation of ROCE on an annual basis in the company's annual MD&A, which is to be read in conjunction with the company's annual consolidated financial statements. For a summarized narrative reconciliation of ROCE calculated on a December 31, 2009 interim basis, please refer to page 35 of Suncor's December 31, 2009 unaudited interim consolidated financial statements.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 009

A reconciliation of cash flow from operations on a per common share basis is presented in the following table:

The following tables outline the reconciliation of Oil Sands cash and total operating costs to expenses included in the Schedules of Segmented Data in the company's financial statements.


		Three months ended December 31						Twelve months ended December 31
		2009			2008			2009			2008
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		1 300			991			4 277			3 204
	Less: Natural gas costs, inventory changes, stock-based compensation, and other	(164	)		(183	)		(400	)		(524	)
	Less: Safe mode costs	(120	)		—			(380	)		—
	Less: Non-monetary transactions	(10	)		(30	)		(66	)		(111	)
	Less: Syncrude-related operating, selling and general expenses	(133	)		—			(199	)		—
Accretion of asset retirement obligations		27			14			107			55

Cash costs		900		35.10	792		35.35	3 339		31.50	2 624		31.45
Natural gas		88		3.40	91		4.05	252		2.40	438		5.25
Imported bitumen (excluding other reported product purchases)		5		0.20	43		1.90	8		0.05	150		1.80

Cash operating costs		993		38.70	926		41.30	3 599		33.95	3 212		38.50
Project start-up costs		13		0.50	6		0.30	51		0.45	35		0.40

Total cash operating costs		1 006		39.20	932		41.60	3 650		34.40	3 247		38.90
Depreciation, depletion and amortization		257		10.00	168		7.50	850		8.00	580		6.95

Total operating costs		1 263		49.20	1 100		49.10	4 500		42.40	3 827		45.85

Production excluding Syncrude (thousands of barrels per day)		278.9			243.8			290.6			228.0

Suncor Energy Inc.
010 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

This report to shareholders contains certain forward-looking statements and other information that are based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of its experience and its perception of historical trends. These statements and information are subject to a number of risks and uncertainties, many of which are beyond the company's control.

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

Suncor's outlook includes a production range 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 2010 outlook, see page 6.

The risks, uncertainties and other factors that could influence actual results include but are not limited to, those risks, uncertainties and other factors described throughout this report to shareholders and: market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; availability of third-party bitumen; success of hedging strategies; maintaining a desirable debt to cash flow ratio; changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange rates; Suncor's ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects and regulatory projects; Suncor's inability to execute planned divestitures; political, economic and socio-economic risk associated with foreign operations (including OPEC production quotas); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties; changes in environmental and other regulations (for example, the Government of Alberta's review of the unintended consequences of the proposed Crown royalty regime, the Government of Canada's current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; failure to realize anticipated synergies or cost savings; risks regarding the integration of Petro-Canada and incorrect assessments of the value of Petro-Canada. The foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout Suncor's fourth quarter 2009 Report to Shareholders and in Suncor's and legacy Petro-Canada'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.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 011


		Three months ended December 31				Twelve months ended December 31
($ millions)		2009		2008		2009		2008

Revenues
	Operating revenues	7 537		3 982		18 658		18 179
	Less: Royalties	(587	)	(86	)	(1 199	)	(890	)

	Operating revenues (net of royalties)	6 950		3 896		17 459		17 289
	Energy trading activities (note 5)	681		3 053		7 577		11 320
	Interest and other income (note 3f)	5		3		444		28

		7 636		6 952		25 480		28 637

Expenses
	Purchases of crude oil and products	2 881		1 744		7 383		7 582
	Operating, selling and general (note 9)	2 358		1 226		6 641		4 186
	Energy trading activities (note 5)	524		3 051		7 381		11 323
	Transportation costs	167		94		427		246
	Depreciation, depletion and amortization	1 072		286		2 306		1 049
	Accretion of asset retirement obligations	52		16		155		64
	Exploration	100		17		268		90
	Loss on disposal of assets	54		27		66		13
	Project start-up costs	13		6		51		35
	Financing expenses (income) (note 7)	(70	)	676		(487	)	917

		7 151		7 143		24 191		25 505

Earnings (Loss) Before Income Taxes		485		(191	)	1 289		3 132

Provisions for (Recovery of) Income Taxes(note 14)
	Current	215		108		868		514
	Future	(187	)	(84	)	(725	)	481

		28		24		143		995

Net Earnings (Loss)		457		(215	)	1 146		2 137

Net Earnings (Loss) Per Common Share(dollars), (note 8)
	Basic	0.29		(0.24	)	0.96		2.29

	Diluted	0.29		(0.24	)	0.95		2.26

Cash dividends		0.10		0.05		0.30		0.20

Suncor Energy Inc.
012 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

December 31
2009

December 31
2008

($ millions)

(note 3)

(restated)

Assets

Current assets

Cash and cash equivalents

505

660

Accounts receivable

3 936

1 580

Inventories

2 971

909

Income taxes receivable

587

Future income taxes

332

Total current assets

8 331

3 237

Property, plant and equipment, net (note 2)

57 485

28 882

Other assets (note 2)

536

388

Goodwill (note 3)

3 201

Future income taxes

193

—

Total assets

69 746

32 528

Liabilities and Shareholders' Equity

Current liabilities

Short-term debt

Current portion of long-term debt (note 12)

Accounts payable and accrued liabilities

6 322

3 326

Income taxes payable

1 274

Future income taxes

111

Total current liabilities

7 641

3 538

Long-term debt (note 12)

13 855

7 866

Accrued liabilities and other

5 269

1 986

Future income taxes (note 14)

8 870

4 615

Shareholders' equity (see below)

34 111

14 523

Total liabilities and shareholders' equity

69 746

32 528

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 013


		Three months ended December 31				Twelve months ended December 31
($ millions)		2009		2008		2009		2008

Operating Activities
Net earnings (loss)		457		(215	)	1 146		2 137
Adjustments for:
	Depreciation, depletion and amortization	1 072		286		2 306		1 049
	Future income taxes	(187	)	(84	)	(725	)	481
	Accretion of asset retirement obligations	52		16		155		64
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(201	)	681		(858	)	919
	Change in fair value of derivative contracts	(59	)	(507	)	980		(638	)
	Loss on disposal of assets	54		27		66		13
	Stock-based compensation	34		(36	)	262		(22	)
	Gain on effective settlement of pre-existing contract with Petro-Canada (note 3f)	—		—		(438	)	—
	Other	(151	)	50		(278	)	(7	)
	Exploration expenses	58		13		183		61

Cash flow from operating activities before changes in non-cash working capital		1 129		231		2 799		4 057
Decrease (increase) in non-cash working capital related to operating activities (note 15)		344		988		(224	)	405

Cash flow from operating activities		1 473		1 219		2 575		4 462

Investing Activities
Capital and exploration expenditures		(1 556	)	(2 670	)	(4 246	)	(7 987	)
Deferred outlays and other investments		(3	)	(15	)	(30	)	(51	)
Cash acquired through business combination (net) (note 3d)		—		—		248		—
Proceeds from disposals		112		—		148		33
Decrease (increase) in non-cash working capital related to investing activities		(83	)	176		(791	)	415

Cash flow used in investing activities		(1 530	)	(2 509	)	(4 671	)	(7 590	)

Net cash deficiency before financing activities		(57	)	(1 290	)	(2 096	)	(3 128	)

Financing Activities
Decrease in short-term debt		(1	)	—		—		(1	)
Net proceeds from issuance of long-term debt		—		—		—		2 704
Net increase (decrease) in long-term debt		116		617		2 325		422
Issuance of common shares under stock option plan		11		6		41		190
Dividends paid on common shares		(152	)	(46	)	(401	)	(180	)

Cash flow provided by (used in) financing activities		(26	)	577		1 965		3 135

Increase (Decrease) in Cash and Cash Equivalents		(83	)	(713	)	(131	)	7
Effect of Foreign Exchange on Cash and Cash Equivalents		1		58		(24	)	84
Cash and Cash Equivalents at Beginning of Period		587		1 315		660		569

Cash and Cash Equivalents at End of Period		505		660		505		660

Suncor Energy Inc.
014 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


($ millions)	Share Capital	Contributed Surplus		Accumulated Other Comprehensive Income (Loss)		Retained Earnings

At December 31, 2007	881	194		(253	)	11 074
Net earnings	—	—		—		2 137
Dividends paid on common shares	—	—		—		(180	)
Issued for cash under stock option plan	226	(36	)	—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	120		—		—
Income tax benefit of stock option deduction in the U.S.	—	10		—		—
Change in accumulated other comprehensive income (loss)	—	—		350		—

At December 31, 2008	1 113	288		97		13 025

Net earnings	—	—		—		1 146
Dividends paid on common shares	—	—		—		(401	)
Issued for cash under stock option plans	57	(16	)	—		—
Issued under dividend reinvestment plan	5	—		—		(5	)
Stock-based compensation expense	—	103		—		—
Issued for Petro-Canada acquisition (note 3c)	18 878	—		—		—
Fair value of Petro-Canada stock options exchanged for Suncor stock options (note 3c)	—	147		—		—
Income tax benefit of stock option deduction in the U.S.	—	4		—		—
Change in accumulated other comprehensive income (loss)	—	—		(330	)	—

At December 31, 2009	20 053	526		(233	)	13 765

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 015


Three months ended December 31
	Oil Sands				Natural Gas				East Coast Canada			International			Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2009		2008		2009		2008		2009		2008	2009		2008	2009		2008		2009		2008		2009		2008

EARNINGS
Revenues
Operating revenues	1 182		2 048		279		124		374		—	966		—	4 733		1 803		3		7		7 537		3 982
Less: Royalties	(280	)	(54	)	(53	)	(32	)	(154	)	—	(100	)	—	—		—		—		—		(587	)	(86	)

Operating revenues (net of royalties)	902		1 994		226		92		220		—	866		—	4 733		1 803		3		7		6 950		3 896
Energy trading activities	—		—		—		—		—		—	—		—	—		—		681		3 053		681		3 053
Intersegment revenues	1 082		264		91		13		62		—	—		—	49		—		(1 284	)	(277	)	—		—
Interest and other income	2		—		—		—		—		—	1		—	—		1		2		2		5		3

	1 986		2 258		317		105		282		—	867		—	4 782		1 804		(598	)	2 785		7 636		6 952

Expenses
Purchases of crude oil and products	83		238		—		—		17		—	—		—	3 930		1 822		(1 149	)	(316	)	2 881		1 744
Operating, selling and general	1 300		991		125		32		41		—	181		—	518		199		193		4		2 358		1 226
Energy trading activities	—		—		—		—		—		—	—		—	—		—		524		3 051		524		3 051
Transportation costs	70		89		27		4		11		—	21		—	43		6		(5	)	(5	)	167		94
Depreciation, depletion and amortization	300		168		190		56		134		—	322		—	115		54		11		8		1 072		286
Accretion of asset retirement obligations	29		14		10		2		3		—	10		—	—		—		—		—		52		16
Exploration	2		1		44		16		4		—	50		—	—		—		—		—		100		17
Loss on disposal of assets	53		23		—		—		—		—	—		—	1		4		—		—		54		27
Project start-up costs	13		6		—		—		—		—	—		—	—		—		—		—		13		6
Financing expenses (income)	1		—		—		—		1		—	(1	)	—	4		—		(75	)	676		(70	)	676

	1 851		1 530		396		110		211		—	583		—	4 611		2 085		(501	)	3 418		7 151		7 143

Earnings (loss) before income taxes	135		728		(79	)	(5	)	71		—	284		—	171		(281	)	(97	)	(633	)	485		(191	)
Income taxes	101		(153	)	29		5		2		—	(151	)	—	(13	)	107		4		17		(28	)	(24	)

Net earnings (loss)	236		575		(50	)	—		73		—	133		—	158		(174	)	(93	)	(616	)	457		(215	)

Suncor Energy Inc.
016 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


Three months ended December 31
			Oil Sands				Natural Gas				East Coast Canada			International			Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)			2009		2008		2009		2008		2009		2008	2009		2008	2009		2008		2009		2008		2009		2008

CASH FLOW BEFORE FINANCING ACTIVITIES
Operating activities:
	Net earnings (loss)		236		575		(50	)	—		73		—	133		—	158		(174	)	(93	)	(616	)	457		(215	)
	Adjustments for:
		Depreciation, depletion and amortization	300		168		190		56		134		—	322		—	115		54		11		8		1 072		286
		Future income taxes	(103	)	20		(29	)	(5	)	(2	)	—	(39	)	—	6		(79	)	(20	)	(20	)	(187	)	(84	)
		Accretion of asset retirement obligations	29		14		10		2		3		—	10		—	—		—		—		—		52		16
		Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	—		—		—		—		—		—	—		—	—		—		(201	)	681		(201	)	681
		Change in fair value of derivative contracts	(28	)	(509	)	1		1		—		—	—		—	5		22		(37	)	(21	)	(59	)	(507	)
		Loss on disposal of assets	53		23		—		—		—		—	—		—	1		4		—		—		54		27
		Stock-based compensation	14		(5	)	4		—		—		—	1		—	5		—		10		(31	)	34		(36	)
		Other	(146	)	35		(8	)	(4	)	(3	)	—	10		—	(22	)	(8	)	18		27		(151	)	50
		Exploration expenses	—		—		42		13		—		—	16		—	—		—		—		—		58		13

Cash flow from (used in) operating activities before changes in non-cash working capital			355		321		160		63		205		—	453		—	268		(181	)	(312	)	28		1 129		231
Decrease (increase) in non-cash working capital related to operating activities			1 321		744		(7	)	2		(66	)	—	(93	)	—	314		517		(1 125	)	(275	)	344		988

Total cash flow from (used in) operating activities			1 676		1 065		153		65		139		—	360		—	582		336		(1 437	)	(247	)	1 473		1 219

Investing activities:
	Capital and exploration expenditures		(734	)	(2 492	)	(66	)	(96	)	(60	)	—	(396	)	—	(256	)	(74	)	(44	)	(8	)	(1 556	)	(2 670	)
	Deferred outlays and other investments		(1	)	(2	)	—		—		—		—	—		—	(3	)	(11	)	1		(2	)	(3	)	(15	)
	Cash acquired through business combination (net)		—		—		—		—		—		—	—		—	—		—		—		—		—		—
	Proceeds from disposals		96		—		—		—		—		—	—		—	16		—		—		—		112		—
	Decrease (increase) in investing working capital		(112	)	174		(6	)	—		(28	)	—	66		—	(3	)	(5	)	—		7		(83	)	176

Total cash (used in) from investing activities			(751	)	(2 320	)	(72	)	(96	)	(88	)	—	(330	)	—	(246	)	(90	)	(43	)	(3	)	(1 530	)	(2 509	)

Net cash surplus (deficiency) before financing activities			925		(1 255	)	81		(31	)	51		—	30		—	336		246		(1 480	)	(250	)	(57	)	(1 290	)

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 017


Twelve months ended December 31
	Oil Sands				Natural Gas				East Coast Canada			International			Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2009		2008		2009		2008		2009		2008	2009		2008	2009		2008		2009		2008		2009		2008

EARNINGS
Revenues
Operating revenues	4 135		8 045		612		696		499		—	1 434		—	11 962		9 418		16		20		18 658		18 179
Less: Royalties	(645	)	(715	)	(85	)	(175	)	(217	)	—	(252	)	—	—		—		—		—		(1 199	)	(890	)

Operating revenues (net of royalties)	3 490		7 330		527		521		282		—	1 182		—	11 962		9 418		16		20		17 459		17 289
Energy trading activities	—		—		—		—		—		—	—		—	—		—		7 577		11 320		7 577		11 320
Intersegment revenues	2 609		1 309		154		58		159		—	—		—	51		—		(2 973	)	(1 367	)	—		—
Interest and other income	440		—		—		—		—		—	1		—	—		1		3		27		444		28

	6 539		8 639		681		579		441		—	1 183		—	12 013		9 419		4 623		10 000		25 480		28 637

Expenses
Purchases of crude oil and products	325		574		—		—		33		—	—		—	9 731		8 472		(2 706	)	(1 464	)	7 383		7 582
Operating, selling and general	4 277		3 203		322		160		72		—	242		—	1 279		746		449		77		6 641		4 186
Energy trading activities	—		—		—		—		—		—	—		—	—		—		7 381		11 323		7 381		11 323
Transportation costs	248		229		58		17		19		—	33		—	87		16		(18	)	(16	)	427		246
Depreciation, depletion and amortization	922		580		448		225		184		—	400		—	323		202		29		42		2 306		1 049
Accretion of asset retirement obligations	111		55		22		8		4		—	17		—	1		1		—		—		155		64
Exploration	10		17		127		73		4		—	127		—	—		—		—		—		268		90
Loss (gain) on disposal of assets	70		36		(20	)	(22	)	—		—	—		—	16		6		—		(7	)	66		13
Project start-up costs	51		35		—		—		—		—	—		—	—		—		—		—		51		35
Financing expenses (income)	1		—		—		—		1		—	(1	)	—	4		—		(492	)	917		(487	)	917

	6 015		4 729		957		461		317		—	818		—	11 441		9 443		4 643		10 872		24 191		25 505

Earnings (loss) before income taxes	524		3 910		(276	)	118		124		—	365		—	572		(24	)	(20	)	(872	)	1 289		3 132
Income taxes	33		(1 035	)	77		(29	)	(12	)	—	(200	)	—	(139	)	19		98		50		(143	)	(995	)

Net earnings (loss)	557		2 875		(199	)	89		112		—	165		—	433		(5	)	78		(822	)	1 146		2 137


As at December 31
TOTAL ASSETS	37 553		25 795		5 003		1 862		4 771		—	9 913		—	10 568		4 687		1 938		184		69 746		32 528

Suncor Energy Inc.
018 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


Twelve months ended December 31
			Oil Sands				Natural Gas				East Coast Canada			International			Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)			2009		2008		2009		2008		2009		2008	2009		2008	2009		2008		2009		2008		2009		2008

CASH FLOW BEFORE FINANCING ACTIVITIES
Operating activities:
	Net earnings (loss)		557		2 875		(199	)	89		112		—	165		—	433		(5	)	78		(822	)	1 146		2 137
	Adjustments for:
		Depreciation, depletion and amortization	922		580		448		225		184		—	400		—	323		202		29		42		2 306		1 049
		Future income taxes	(643	)	535		(52	)	15		12		—	(56	)	—	109		(7	)	(95	)	(62	)	(725	)	481
		Accretion of asset retirement obligations	111		55		22		8		4		—	17		—	1		1		—		—		155		64
		Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	—		—		—		—		—		—	—		—	—		—		(858	)	919		(858	)	919
		Change in fair value of derivative contracts	960		(590	)	—		—		—		—	—		—	(14	)	27		34		(75	)	980		(638	)
		Loss (gain) on disposal of assets	70		36		(20	)	(22	)	—		—	—		—	16		6		—		(7	)	66		13
		Stock-based compensation	90		54		19		4		2		—	10		—	35		16		106		(96	)	262		(22	)
		Gain on effective settlement of pre-existing contract with Petro-Canada	(438	)	—		—		—		—		—	—		—	—		—		—		—		(438	)	—
		Other	(378	)	(38	)	(11	)	(13	)	21		—	19		—	60		8		11		36		(278	)	(7	)
		Exploration expenses	—		—		122		61		—		—	61		—	—		—		—		—		183		61

Cash flow from (used in) operating activities before changes in non-cash working capital			1 251		3 507		329		367		335		—	616		—	963		248		(695	)	(65	)	2 799		4 057
Decrease (increase) in operating working capital			(202	)	934		(9	)	43		(34	)	—	(35	)	—	(270	)	292		326		(864	)	(224	)	405

Total cash flow from (used in) operating activities			1 049		4 441		320		410		301		—	581		—	693		540		(369	)	(929	)	2 575		4 462

Investing activities:
	Capital and exploration expenditures		(2 807	)	(7 391	)	(320	)	(342	)	(123	)	—	(543	)	—	(409	)	(226	)	(44	)	(28	)	(4 246	)	(7 987	)
	Deferred outlays and other investments		(36	)	(39	)	—		—		—		—	—		—	(3	)	(11	)	9		(1	)	(30	)	(51	)
	Cash acquired through business combination (net)		—		—		—		—		—		—	—		—	—		—		248		—		248		—
	Proceeds from disposals		96		—		27		26		—		—	—		—	25		—		—		7		148		33
	Decrease (increase) in investing working capital		(799	)	434		(19	)	—		(29	)	—	60		—	(4	)	(19	)	—		—		(791	)	415

Total cash (used in) from investing activities			(3 546	)	(6 996	)	(312	)	(316	)	(152	)	—	(483	)	—	(391	)	(256	)	213		(22	)	(4 671	)	(7 590	)

Net cash surplus (deficiency) before financing activities			(2 497	)	(2 555	)	8		94		149		—	98		—	302		284		(156	)	(951	)	(2 096	)	(3 128	)

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 019

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and follow the same accounting policies and methods of computation as, and should be read in conjunction with, the most recent annual financial statements, except for the accounting policy changes as described in note 2, Change in Accounting Policies. Certain information and disclosures normally required to be included in notes to the annual consolidated financial statements have been condensed or omitted.

In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature necessary to present fairly Suncor Energy Inc.'s (Suncor) financial position at December 31, 2009 and 2008, and the results of its operations and cash flows for the three and twelve month periods ended December 31, 2009 and 2008.

Certain prior period comparative figures have been reclassified to conform to the current period presentation.

On January 1, 2009, the company retroactively adopted Canadian Institute of Chartered Accountants (CICA) Handbook section 3064 "Goodwill and Intangible Assets". This new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs", and focuses on the criteria for asset recognition in the financial statements, including those internally developed. At December 31, 2008, property, plant and equipment was increased by $561 million, with an equal and offsetting reduction to other assets.

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

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

In the first quarter of 2009, Suncor announced that it had agreed to merge with Petro-Canada. The transaction was accomplished through a plan of arrangement, which included a share exchange, pursuant to which holders of common shares of Petro-Canada received 1.28 common shares of Suncor for each common share of Petro-Canada held.

In the second and third quarters of 2009, the arrangement received approval from Suncor and Petro-Canada shareholders, the Alberta Court of Queen's Bench, and the Competition Bureau of Canada. The transaction closed August 1, 2009 and the merged company continues to operate as Suncor Energy Inc.

The company has accounted for this business combination as prescribed by CICA Handbook section 1581 "Business Combinations". As such, the company is required to recognize Petro-Canada assets and liabilities as at August 1, 2009. The results of Petro-Canada operations are included in the consolidated financial statements of the company from August 1, 2009.

Suncor Energy Inc.
020 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

Consideration offered to complete the merger included 621.1 million shares of Suncor with a value of $18,878 million, or $30.39 per share, that were issued to Petro-Canada shareholders and 7.1 million Suncor share options with a fair value of $147 million, that were exchanged for existing Petro-Canada share options. The replacement of stock options and other stock-based compensation plans that are accounted for as liabilities are not included in consideration (see note 9).

The total purchase price for the acquisition was $19,630 million, consisting of the following amounts:

The following estimated fair values were assigned to the assets and liabilities of Petro-Canada as at August 1, 2009:

Other assets includes $236 million for intangible assets, relating to the Petro-Canada brand, with an indefinite life, and customer lists, which will be amortized over their estimated useful lives.

This preliminary allocation of the purchase price is based on current best estimates by Suncor's management and is based principally on valuations prepared by independent valuation specialists. The completion of the purchase price allocation may result in further adjustment to the carrying value of Petro-Canada's recorded assets and liabilities and the residual amount allocated to goodwill. $3,019 million of the goodwill has been allocated to the Oil Sands segment and the remaining $159 million has been allocated to the Refining and Marketing segment. No amount that is part of goodwill is expected to be deductible for tax purposes.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 021

The fair values assigned to the pension and post-retirement benefits plans assumed, included in accrued liabilities and other, are as follows:

The valuation of the net liability assumed was based on the following assumptions:

CICA Emerging Issues Committee Abstract 154 Accounting for Pre-existing Relationships between the Parties of a Business Combination states that the consummation of a business combination between parties with a pre-existing relationship requires an evaluation to determine if a settlement of the related contract exists, and where the relationship is favourable to the acquirer, that the purchase cost of the acquisition be the sum of the consideration paid and the benefit from the settlement of the relationship. The benefit is measured as the lesser of the amount of any stated settlement provisions in the contract and the amount by which the contract is favourable, from the perspective of the acquirer, when compared to pricing for current market transactions for the same or similar items.

In 2003, Suncor entered into a fee-for-service contract where it agreed to upgrade bitumen supplied by Petro-Canada. The contract came into effect January 1, 2009. The contract processing fee included an escalation factor tied to the price of West Texas Intermediate (WTI) crude, which was intended to approximate changes in Canadian light/heavy differentials for crude oil. The contract terms included a take-or-pay volume commitment and no early settlement provisions.

Since 2003, crude prices have increased significantly and industry conditions for the supply and demand of upgraded bitumen have changed dramatically resulting in the contract being favourable to Suncor at the transaction closing date. A value of $438 million was assigned to the effective settlement of the contract, by comparing estimated future processing fees on the take-or-pay volume commitment to estimated Canadian light/heavy differentials using future pricing assumptions for WTI, synthetic crude and bitumen.

The deemed settlement amount of $438 million (net of income taxes of $nil) is included in the total purchase price of the acquisition and included in interest and other income in the Consolidated Statement of Earnings.

As a result of the business combination described in note 3, the company has reclassified its operations into the following segments.

Oil Sands includes the company's operations in northeast Alberta to produce synthetic crude through the recovery and upgrading of bitumen from mining and in-situ development.

Natural Gas includes exploration and production of natural gas, crude oil and natural gas liquids in western Canada and the U.S. Rockies.

The East Coast Canada segment comprises activity offshore Newfoundland and Labrador, and includes interests in the Hibernia, Terra Nova, White Rose and Hebron oilfields.

Suncor Energy Inc.
022 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The International segment includes the exploration for, and production of, crude oil and natural gas in the United Kingdom, the Netherlands, Trinidad and Tobago, Libya and Syria.

Refining and Marketing includes the purchase and sale of crude oil, the refining of crude oil products, and the distribution and marketing of these and other purchased products through refineries located in eastern and western Canada and the U.S., as well as a lubricants plant located in eastern Canada. Energy trading activities that were previously included in the Refining and Marketing segment are now included within Corporate, Energy Trading and Eliminations. Prior period amounts have been restated to reflect this change in presentation.

The Corporate, Energy Trading and Eliminations includes third-party energy trading activities and activities not directly attributable to an operating segment.

The recent merger has provided Suncor with the ability to capitalize on future trading opportunities due to increased transactional and trading capacity. As a result, we performed a review of our energy trading activities, and determined that certain physical trading commodity contracts have grown beyond their original intent and are no longer being used for the company's expected purchase, sale or usage requirements. Effective October 1, 2009, these contracts are now considered derivative financial instruments whereby realized and unrealized gains and losses, and the underlying settlement of these contracts is recognized and reported on a net basis in Energy Trading Activities revenue. The related inventory is carried at fair value less costs to sell, with changes in fair value recognized as gains or losses within Energy Trading Activities revenue.

The company's financial instruments in the Consolidated Balance Sheets consist of cash and cash equivalents, accounts receivable, derivative contracts, substantially all current liabilities (except for the current portions of income tax, asset retirement and pension obligations), long-term debt, and a portion of non-current accrued liabilities and other. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of recognized financial instruments have been determined based on the company's assessment of 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.

The company's fixed-term debt is accounted for under the amortized cost method. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. Gains or losses on our U.S. dollar denominated long-term debt resulting from changes in the exchange rate are recognized in the period in which they occur. At December 31, 2009, the carrying value of our fixed-term debt accounted for under the amortized cost method was $10.1 billion (December 31, 2008 – $6.7 billion) and the fair value was $10.7 billion (December 31, 2008 – $5.4 billion).

At December 31, 2009, the company had interest rate swaps classified as fair value hedges outstanding until August 2011, relating to fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the three and twelve month periods ended December 31, 2009 and December 31, 2008.

The earnings impact associated with hedge ineffectiveness on derivative contracts to hedge risks specific to individual transactions during the three month period ended December 31, 2009 was a loss of $2 million, net of income taxes of nil (2008 – nil). During the twelve month period ended December 31, 2009, there was no earnings impact (2008 – loss of $4 million, net of income taxes of $2 million).

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 023

Up to October 31, 2009, the company had hedged a portion of its forecasted cash flows subject to natural gas price risk. There was no earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the three and twelve month periods ended December 31, 2009 and December 31, 2008.

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

A reconciliation of changes in AOCI attributable to derivative hedging activities for the twelve-month periods ending December 31 is as follows:

The company periodically enters into derivative contracts for the purpose of managing price risk exposure associated with the sale and purchase of commodities. While these contracts are not accounted for as hedges because they have not been documented as such or do not qualify under GAAP, the company believes such contracts to be economically effective at mitigating its risk to adverse commodity price movements and is an important component of our overall risk management program. These contracts are accounted for using the mark-to-market method and, as such, they are recorded at fair value at each balance sheet date. The earnings impact associated with these contracts for the three months period ended December 31, 2009, was a loss of $100 million, net of income taxes of $34 million (2008 – a gain of $354 million, net of income taxes of $144 million). During the twelve month period ended December 31, 2009, the earnings impact was a loss of $763 million, net of income taxes of $261 million (2008 – a gain of $348 million, net of income taxes of $142 million).

Suncor Energy Inc.
024 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The company's Energy Trading division also uses physical and financial energy contracts, including swaps, forwards and options to earn trading and marketing revenues. These energy contracts are comprised of crude oil, natural gas and refined products contracts. Financial and physical energy trading activities are accounted for using the mark-to-market method, the associated gains and losses and the underlying settlement of these contracts is recognized and reported on a net basis in Energy Trading Activities Revenue in the Consolidated Statements of Earnings and Comprehensive Income.

The earnings impact associated with these contracts for the three months period ended December 31, 2009, was a loss of $13 million, net of income taxes of $4 million (2008 – a gain of $88 million, net of income taxes of $36 million). During the twelve month period ended December 31, 2009, the earnings impact was a loss of $52 million, net of income taxes of $18 million (2008 – a gain of $90 million, net of income taxes of $37 million).

The fair values of unsettled (unrealized) energy derivative assets and liabilities above are as follows:

The company is exposed to a number of different financial risks arising from normal course business exposures, as well as the company's use of financial instruments. These risk factors include market risks relating to commodity prices, foreign currency risk and interest rate risk, as well as liquidity risk and credit risk.

The company maintains a formal governance process to manage its financial risks. The company's Risk Management Committee (RMC) is charged with the oversight of the company's risk management for trading risk management activities which are defined as strategic hedging, optimization trading, marketing and speculative trading. The RMC, acting under board authority, meets regularly to monitor limits on risk exposures, review policy compliance and validate risk-related methodologies and procedures. All risk management activity is carried out by specialist teams that have the appropriate skills, experience and supervision with the appropriate financial and management controls.

At December 31, 2009, the company's exposure to risks associated arising from the use of financial instruments had not changed significantly from December 31, 2008.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 025

Changes in commodity prices on our financial contracts would have the following impact on our net earnings and other comprehensive income for the three months ended December 31, 2009:

For a full discussion of the company's financial risk factors, see page 67 of our 2008 Annual Report.

The company's primary capital management objective is to maintain a solid investment-grade credit rating profile. This objective affords the company the financial flexibility and access to the capital it requires to execute on its growth objectives.

The company monitors capital through two key ratios: net debt to cash flow from operations ⁽¹⁾ and total debt to total debt plus shareholders' equity.

Net debt to cash flow from operations is calculated as short-term debt plus total long-term debt less cash and cash equivalents divided by the twelve-month trailing cash flow from operations.

Total debt to total debt plus shareholders' equity is calculated as short term-debt plus total long-term debt divided by short-term debt plus total long-term debt plus shareholders' equity.

The company's strategy during the fourth quarter of 2009 was to maintain the measure set out in the following schedule. The company believes that maintaining our capital target helps to provide the company access to capital at a reasonable cost by maintaining solid investment-grade credit ratings. The company operates in a cyclical business environment and ratios may periodically fall outside of management targets.

At December 31, ($ millions)

Capital Measure
Target

2009

2008

Components of ratios

Short-term debt

Current portion of long-term debt

Long-term debt

13 855

7 866

Total debt

13 882

7 886

Cash and equivalents

505

660

Net debt

13 377

7 226

Shareholders' equity

34 111

14 523

Total capitalization (total debt + shareholders' equity)

47 993

22 409

Cash flow from operations ⁽¹⁾ (trailing twelve months)

2 799

4 057

Net debt/cash flow from operations

< 2.0 times

4.8

1.8

Total debt/total debt plus shareholders' equity

29%

35%

Suncor Energy Inc.
026 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The increase in debt levels as a result of the merger with Petro-Canada has caused our net debt/cash flow from operations measure to increase significantly, as the calculation only includes five months of cash flow from operations relating to legacy Petro-Canada operations.

The company's capital management strategy, objectives, definitions, monitoring measures and targets have not changed significantly from the prior period.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 027

A stock option gives the holder the right, but not the obligation, to purchase common shares at a predetermined price over a specified period of time.

After the date of grant, employees and non-employee directors that hold options must earn the right to exercise them. The holder must fulfill a time requirement for service to the company, at which time the option is considered vested. Certain options are subject to accelerated vesting should the company meet predetermined performance criteria.

The predetermined price at which an option can be exercised is equal to or greater than the market price of the common shares on the date the option is granted.

Certain stock options with a cash payment alternative (CPA) entitle the holder to surrender vested options for cancellation in return for a direct cash payment based on the excess of the then current market price of the underlying common share over the option exercise price or for a common share in the company at the option exercise price.

A stock appreciation right unit (SAR) entitles the holder to receive a cash payment equal to the difference between the stated exercise price and the market price of the company's common shares on the date the vested option is surrendered.

A performance share unit (PSU) is a time-vested award entitling employees to receive cash to varying degrees contingent upon the company's shareholder return relative to a peer group of companies.

A restricted share unit (RSU) is a time-vested award entitling employees to receive cash.

A deferred share unit (DSU) is a notional share unit, redeemable for cash or a common share for a period of time after a unitholder ceases employment or Board membership. The DSU plan is only for executives and members of the company's Board of Directors.

Granting of options under this plan ended on July 31, 2009. A total of 1,204,000 options were granted in the twelve months ended December 31, 2009 (851,000 options granted during the fourth quarter of 2008; 2,637,000 options granted during the twelve months ended December 31, 2008) to all eligible permanent full-time and part-time employees, both executive and non-executive, under its SunShare 2012 performance stock option plan. During 2008, in connection with the achievement of a predetermined performance criterion, 25% of the outstanding options vested under the SunShare 2012 plan and will become exercisable on January 1, 2010. The remaining 75% of outstanding options may vest on January 1, 2013 if further specified performance targets are met. All unvested options which have not previously expired or been cancelled will automatically expire on January 1, 2013.

Granting of options under this plan ended on July 31, 2009. A total of 711,000 options were granted in the twelve months ended December 31, 2009 (25,000 options granted during the fourth quarter of 2008; 895,000 granted in the twelve months ended December 31, 2008) to non-employee directors and certain executives and other senior members of the company. Options granted have a ten-year life and vest annually over a three-year period.

Granting of options under this plan ended on July 31, 2009. A total of 571,000 options were granted in the twelve months ended December 31, 2009 (2,000 options granted during the fourth quarter of 2008; 2,375,000 granted in the twelve months ended December 31, 2008) to non-insider senior managers and key employees. Options granted have a ten-year life and vest annually over a three-year period.

Granting of options under this plan ended on July 31, 2009. In conjunction with the business combination transaction described in note 3, each outstanding option issued under the Petro-Canada Stock Option Plan to purchase Petro-Canada common shares was exchanged on August 1, 2009 for 1.28 options to purchase Suncor common shares, for a total of

Suncor Energy Inc.
028 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

29.9 million options outstanding at August 1, 2009. The same exchange ratio was applied to the exercise price of these options.

The Adjusted Options, issued to officers and certain employees, have a term of ten years if granted prior to 2004 and seven years if granted subsequent to 2003. Holders of options granted after 2003 are entitled to exercise the options in exchange for a cash payment alternative (CPA). A total of 22.8 million of the Adjusted Options outstanding on August 1, 2009 had a CPA and are recorded in accrued liabilities and other on the Consolidated Balance Sheets, based on their intrinsic value at each period end. All Adjusted Options vest over periods of up to four years.

As at December 31, 2009, there were 27.9 million Adjusted Options outstanding with a weighted-average exercise price per share of $28.05.

The company did not grant options under this plan in the fourth quarter of 2009. A total of 4,000 options were granted in 2009. This plan came into effect on August 1, 2009 and replaces the pre-merger stock option plans of legacy Petro-Canada and Suncor. Outstanding Adjusted Options that are cancelled, expire or are terminated or otherwise result in no underlying common share being issued will be available for issuance as options under this plan.

The following table summarizes outstanding and exercisable common share options as at December 31, 2009:

The fair values of all legacy Suncor common share options granted during the period and Adjusted Options granted in 2003 are estimated as at the grant date using the Monte Carlo simulation approach for the SunShare 2012 option plan and the Black-Scholes option-pricing model for all other option plans. Adjusted Options which have a CPA granted subsequent to 2003 are accounted for based on the intrinsic value at each period end. The weighted-average fair values of the options granted during the various periods and the weighted-average assumptions used in their determination are as noted below:

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 029

In conjunction with the business combination described in note 3, each outstanding SAR issued under the Petro-Canada Stock Option Plan was exchanged with 1.28 SARs resulting in the addition of 15,353,000 SARs at August 1, 2009.

The following table summarizes outstanding and exercisable Adjusted SARs as at December 31, 2009:

The company did not issue any PSUs in the fourth quarter of 2009 (2008 – 13,000). For the twelve months ended December 31, 2009, the company issued 1,149,000 PSUs (2008 – 795,000). In conjunction with the business combination described in note 3, each outstanding Petro-Canada PSU was adjusted by 1.28, resulting in the addition of 945,000 PSUs at August 1, 2009.

In the fourth quarter of 2009, the company issued 66,000 RSUs (2008 – 53,000). For the twelve months ended December 31, 2009, the company issued 2,715,000 RSUs (2008 – 1,078,000). In conjunction with the business combination described in note 3, each outstanding Petro-Canada RSU was adjusted by 1.28, resulting in the addition of 1,018,000 RSUs at August 1, 2009.

In the fourth quarter of 2009, the company issued 18,000 DSUs (2008 – nil). For the twelve months ended December 31, 2009, the company issued 48,000 DSUs (2008 – 30,000). In conjunction with the business combination described in note 3, each outstanding Petro-Canada PSU was adjusted by 1.28, resulting in the addition of 1,008,000 DSUs at August 1, 2009.

The following table summarizes the stock based compensation expense (recovery) recorded for all plans within operating, selling and general expense on the Consolidated Statements of Earnings:

Suncor Energy Inc.
030 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The following is the status of the net periodic benefit cost for the three and twelve months ended December 31:

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 031


($ millions)		December 31 2009		December 31 2008

Fixed-term debt, redeemable at the option of the company
6.85% Notes, denominated in U.S. dollars, due in 2039 (US$750)		785		918
6.80% Notes, denominated in U.S. dollars, due in 2038 (US$900)		972		—
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150)		1 204		1 408
5.95% Notes, denominated in U.S. dollars, due in 2035 (US$600)		578		—
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)		523		612
5.35% Notes, denominated in U.S. dollars, due in 2033 (US$300)		266		—
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)		523		612
6.10% Notes, denominated in U.S. dollars, due in 2018 (US$1250)		1 308		1 531
6.05% Notes, denominated in U.S. dollars, due in 2018 (US$600)		643		—
5.00% Notes, denominated in U.S. dollars, due in 2014 (US$400)		429		—
4.00% Notes, denominated in U.S. dollars, due in 2013 (US$300)		313		—
7.00% Debentures, denominated in U.S. dollars, due in 2028 (US$250)		271		—
7.875% Debentures, denominated in U.S. dollars, due in 2026 (US$275)		325		—
9.25% Debentures, denominated in U.S. dollars, due in 2021 (US$300)		402		—
5.39% Series 4 Medium Term Notes, due in 2037		600		600
5.80% Series 4 Medium Term Notes, due in 2018		700		700
6.70% Series 2 Medium Term Notes, due in 2011		500		500

		10 342		6 881
Revolving-term debt, with interest at variable rates
Commercial paper, bankers' acceptances and LIBOR loans		3 244		934

Total unsecured long-term debt		13 586		7 815
Secured long-term debt		13		13
Capital leases		326		103
Fair value of interest swaps		18		25
Deferred financing costs		(63	)	(72	)

		13 880		7 884

Current portion of long-term debt
	Capital leases	(14	)	(9	)
	Fair value of interest swaps	(11	)	(9	)

Total current portion of long-term debt		(25	)	(18	)

Total long-term debt		13 855		7 866

Certain of the notes and debentures of the company were acquired in the business combination described in note 3 and were accounted for at their fair value at the date of acquisition. The difference between the fair value and the principal amount of these debts of $121 million is being amortized over the remaining life of the debt acquired.

Suncor Energy Inc.
032 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

The components of accumulated other comprehensive income (loss), net of income taxes, are as follows:

In the fourth quarter of 2009, the Ontario provincial government substantively enacted a 4% reduction to its provincial corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $148 million related to the revaluation of its opening future income tax balances, allocated to the segments as follows: Oil Sands – $103 million, Natural Gas – $8 million, East Coast Canada – $20 million, Refining and Marketing – $19 million, Corporate, Energy Trading and Eliminations – ($2) million.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 033

Non-cash working capital is comprised of current assets and current liabilities, other than cash and cash equivalents, future income taxes and the current portion of long-term debt.

On December 31, 2009, Suncor entered into an agreement to sell substantially all of its oil and gas producing assets in the United States Rockies for proceeds of $517 million (US$494 million) which is approximately equal to its net book value as at December 31, 2009. The sale is expected to close in March 2010.

In conjunction with the merger with Petro-Canada, the Competition Bureau of Canada required Suncor to divest 104 retail sites in Ontario. On December 8, 2009, Suncor agreed to sell 98 sites with expected closing dates commencing in the first half of 2010 as ownership of individual sites is transferred to the purchaser.

Suncor Energy Inc.
034 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


		2009	2008

Cash Flow From Operations
(dollars per common share – basic)
For the three months ended December 31
Cash flow from operations ⁽¹⁾		0.72	0.25

For the twelve months ended December 31
Cash flow from operations ⁽¹⁾		2.34	4.36

Ratios
For the twelve months ended December 31
Return on capital employed (%) ⁽²⁾		2.6	22.5
Return on capital employed (%) ⁽³⁾		1.8	16.3

Net debt to cash flow from operations (times) ⁽⁴⁾		4.8	1.8
Pro forma – Net debt to cash flow from operations (times) ⁽⁵⁾		3.2	N/A

Interest coverage on long-term debt (times)
	Net earnings ⁽⁶⁾	3.0	8.9
	Cash flow from operations ⁽⁷⁾	7.2	13.0

As at December 31
Debt to debt plus shareholders' equity (%) ⁽⁸⁾		28.9	35.2

Common Share Information
As at December 31
Share price at end of trading
	Toronto Stock Exchange – Cdn$	37.21	23.72
	New York Stock Exchange – US$	35.31	19.50

Common share options outstanding (thousands)		72 024	46 402

For the twelve months ended December 31
Average number outstanding, weighted monthly (thousands)		1 197 710	931 524

Refer to the Quarterly Operating Summary for a discussion of financial measures not prepared in accordance with Canadian generally accepted accounting principles (GAAP).

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 035


		Three months ended						Twelve months ended
		Dec 31	Sept 30		June 30	Mar 31	Dec 31	Dec 31		Dec 31

		2009	2009		2009	2009	2008	2009		2008

OIL SANDS
Production ^(1),(a)
Total production (excluding Syncrude)		278.9	305.3		301.0	278.0	243.8	290.6		228.0
	Firebag ^(k)	51.1	54.3		48.3	42.4	39.7	49.1		37.4
	MacKay River ^(k)	31.7	26.5	^***	—	—	—	29.7	^***	—
Syncrude		39.3	37.4	^***	—	—	—	38.5	^***	—
Sales ^(a) (excluding Syncrude)
Light sweet crude oil		100.8	89.6		99.4	108.8	95.7	99.6		77.0
Diesel		31.4	36.9		25.3	22.8	19.1	29.1		19.8
Light sour crude oil		142.4	146.8		150.5	102.7	144.2	135.7		128.7
Bitumen		13.0	14.3		10.5	9.1	3.1	11.8		1.5

Total sales		287.6	287.6		285.7	243.4	262.1	276.2		227.0

Average sales price ^(2),(b) (excluding Syncrude)
Light sweet crude oil*		77.71	71.99		65.83	54.64	63.69	67.26		98.66
Other (diesel, light sour crude oil and bitumen) *		72.93	67.51		62.71	48.80	59.77	64.18		95.14
Total *		74.61	68.91		63.79	52.78	61.20	65.29		96.33
Total		64.81	61.70		59.00	59.14	61.53	61.26		95.96

Syncrude average sales price ^(2),(b)		78.81	75.17		—	—	—	77.36		—

Cash operating costs and Total operating costs – Total operations (excluding Syncrude) ^(c)
Cash costs		35.10	30.65		29.65	30.65	35.35	31.50		31.45
Natural gas		3.40	1.55		1.65	3.00	4.05	2.40		5.25
Imported bitumen		0.20	0.05		—	0.05	1.90	0.05		1.80

Cash operating costs ⁽³⁾		38.70	32.25		31.30	33.70	41.30	33.95		38.50
Project start-up costs		0.50	0.45		0.35	0.65	0.30	0.45		0.40

Total cash operating costs ⁽⁴⁾		39.20	32.70		31.65	34.35	41.60	34.40		38.90
Depreciation, depletion and amortization		10.00	7.60		7.20	7.30	7.50	8.00		6.95

Total operating costs ⁽⁵⁾		49.20	40.30		38.85	41.65	49.10	42.40		45.85

Cash operating costs and Total operating costs – Syncrude ^(c)****
Cash costs		29.65	29.50		—	—	—	29.60		—
Natural gas		3.45	2.10		—	—	—	2.90		—

Cash operating costs ⁽³⁾		33.10	31.60		—	—	—	32.50		—
Project start-up costs		—	—		—	—	—	—		—

Total cash operating costs ⁽⁴⁾		33.10	31.60		—	—	—	32.50		—
Depreciation, depletion and amortization		11.80	12.70		—	—	—	12.15		—

Total operating costs ⁽⁵⁾		44.90	44.30		—	—	—	44.65		—

Cash operating costs and Total operating costs – In-situ bitumen production only ^(c)
Cash costs		11.35	10.25		11.15	10.50	16.55	10.90		13.00
Natural gas		6.05	4.30		5.25	7.90	9.65	5.70		12.30

Cash operating costs ⁽⁶⁾		17.40	14.55		16.40	18.40	26.20	16.60		25.30
In-situ start-up costs		1.25	0.65		1.50	3.35	—	1.30		0.65

Total cash operating costs ⁽⁷⁾		18.65	15.20		17.90	21.75	26.20	17.90		25.95
Depreciation, depletion and amortization		6.65	5.95		6.00	7.10	6.55	6.35		6.35

Total operating costs ⁽⁸⁾		25.30	21.15		23.90	28.85	32.75	24.25		32.30

Ending capital employed excluding major projects in progress ⁽ⁱ⁾		16 141	14 833		10 008	10 610	9 352
(for the twelve months ended)
Return on capital employed ^(j)		4.2	8.4		11.1	22.9	35.5
Return on capital employed ^(j)**		2.5	4.9		6.5	13.9	21.8

Suncor Energy Inc.
036 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


		Three months ended									Five months ended		Twelve months ended
			Dec 31 2009		Sept 30 2009		June 30 2009		Mar 31 2009	Dec 31 2008		Dec 31 2009		Dec 31 2009	Dec 31 2008

NATURAL GAS
Gross production
Natural gas ^(d)
	Western Canada		620		477		192		200	195		621		374	202
	U.S. Rockies		54		40		—		—	—		56		24	—
Natural gas liquids and crude oil ^(a)
	Western Canada		10.8		8.3		3.2		3.1	3.1		11.0		6.4	3.1
	U.S. Rockies		4.2		2.4		—		—	—		4.0		1.7	—
Total gross production ^(f)
	Western Canada		685		527		211		219	213		687		412	220
	U.S. Rockies		79		54		—		—	—		80		34	—

Average sales price ⁽²⁾
Natural gas ^(g)
	Western Canada		4.46		2.88		3.56		5.63	6.90		3.94		4.11	8.23
	U.S. Rockies		4.62		3.01		—		—	—		3.93		3.93	—
Natural gas ^(g)*
	Western Canada		4.45		2.86		3.52		5.61	6.84		3.93		4.09	8.25
	U.S. Rockies		4.62		3.01		—		—	—		3.93		3.93	—
Natural gas liquids and crude oil ^(b)
	Western Canada		60.06		53.28		41.39		39.03	39.31		57.67		52.97	70.89
	U.S. Rockies		74.19		67.08		—		—	—		71.62		71.62	—

Ending capital employed ⁽ⁱ⁾			3 349		3 632		1 200		1 195	1 152
(for the twelve months ended)
Return on capital employed ^(j)			(8.4	)	(9.6	)	(1.7	)	5.0	7.7

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 037


		Three months ended						Twelve months ended
			Dec 31 2009	Sept 30 2009 ^***	June 30 2009	Mar 31 2009	Dec 31 2008		Dec 31 2009 ^***	Dec 31 2008

EAST COAST CANADA
Production ^(a)
Terra Nova			24.0	16.0	—	—	—		20.8	—
Hibernia			26.3	28.5	—	—	—		27.2	—
White Rose			13.3	5.1	—	—	—		10.0	—

Total production			63.6	49.6	—	—	—		58.0	—

Average sales price ⁽²⁾			77.71	75.22	—	—	—		76.86	—
Ending capital employed excluding major projects in progress ⁽ⁱ⁾			2 142	2 050	—	—	—
(for the twelve months ended)
Return on capital employed ^(j)			10.7	12.2	—	—	—
Return on capital employed ^(j)**			6.5	7.4	—	—	—

INTERNATIONAL
Production ^(e)
North Sea
	Buzzard		59.9	29.4	—	—	—		47.8	—
	Other U.K.		18.2	11.4	—	—	—		15.5	—
	The Netherlands sector of the North Sea		12.9	13.8	—	—	—		13.2	—

Total North Sea			91.0	54.6	—	—	—		76.5	—
Other International
	Libya		26.0	42.7	—	—	—		32.6	—
	Trinidad & Tobago		12.0	11.3	—	—	—		11.7	—

Total Other International			38.0	54.0	—	—	—		44.3	—

Total production			129.0	108.6	—	—	—		120.8	—

Average sales price ⁽²⁾ – North Sea ^(l)			71.46	68.67	—	—	—		71.63	—
Average sales price ⁽²⁾ – Other International ^(l)			59.04	62.40	—	—	—		61.25	—

Ending capital employed excluding major projects in progress ⁽ⁱ⁾			2 828	2 230	—	—	—
(for the twelve months ended)
Return on capital employed ^(j)			11.5	7.3	—	—	—
Return on capital employed ^(j)**			7.5	4.8	—	—	—

Suncor Energy Inc.
038 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


				Three months ended						Five months ended		Twelve months ended
					Dec 31 2009	Sept 30 2009	June 30 2009	Mar 31 2009	Dec 31 2008		Dec 31 2009		Dec 31 2009	Dec 31 2008

REFINING & MARKETING
	Eastern North America
		Refined product sales ^(h)
			Transportation fuels
			Gasoline – retail		16.5	12.5	4.0	3.8	3.9		16.6		9.3	3.9
			– other		6.5	5.8	4.7	4.4	5.0		6.4		5.3	4.0
			Distillate		13.9	10.3	5.4	5.1	5.4		13.4		8.8	5.2

			Total transportation fuel sales		36.9	28.6	14.1	13.3	14.3		36.4		23.4	13.1
			Petrochemicals		1.2	1.7	1.0	1.0	1.0		1.7		0.8	0.8
			Asphalt		2.0	2.4	0.7	0.8	0.5		2.5		1.5	0.6
			Other		1.9	3.0	1.0	0.5	0.5		2.7		2.0	1.0

		Total refined product sales			42.0	35.7	16.8	15.6	16.3		43.3		27.7	15.5

		Crude oil supply and refining
			Processed at refineries ^(h)		28.3	25.5	11.8	11.3	11.2		29.9		29.6	11.0
			Utilization of refining capacity ^(j)		83	94	87	84	101		88		87	99

	Western North America
		Refined product sales ^(h)
			Transportation fuels
			Gasoline – retail		5.0	3.8	0.6	0.7	0.7		5.1		2.6	0.7
			– other		13.4	12.3	8.3	7.5	7.1		13.8		10.4	7.3
			Distillate		15.6	11.8	5.0	5.4	5.5		15.4		9.5	5.6

			Total transportation fuel sales		34.0	27.9	13.9	13.6	13.3		34.3		22.5	13.6
			Asphalt		0.9	1.7	1.4	1.2	1.0		1.2		1.3	1.2
			Other		6.0	4.6	1.8	1.0	0.9		6.0		3.4	1.2

		Total refined product sales			40.9	34.2	17.1	15.8	15.2		41.5		27.2	16.0

		Crude oil supply and refining
			Processed at refineries ^(h)		33.4	27.8	15.6	14.2	13.6		33.6		33.6	13.7
			Utilization of refining capacity ^(j)		96	100	106	96	95		97		97	96

Ending capital employed excluding major projects in progress ⁽ⁱ⁾					8 304	8 300	3 224	2 985	2 974
(for the twelve months ended)
Return on capital employed ^(j)					7.5	2.5	3.0	3.7	1.8

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 039


			Three months ended											Twelve months ended
				Dec 31 2009		Sept 30 2009		June 30 2009		Mar 31 2009		Dec 31 2008			Dec 31 2009		Dec 31 2008

NETBACKS
Natural Gas ^(g)
	Western Canada
		Average price realized ⁽⁹⁾		5.05		3.76		3.88		5.77		6.99			4.58		9.35
		Royalties		(0.72	)	(0.24	)	0.33		(1.14	)	(1.60	)		(0.49	)	(2.17	)
		Operating costs		(1.77	)	(1.90	)	(1.71	)	(1.65	)	(1.46	)		(1.79	)	(1.60	)

		Operating netback		2.56		1.62		2.50		2.98		3.93			2.30		5.58
		Depreciation, depletion and amortization		(2.62	)	(2.73	)	(2.92	)	(2.97	)	(2.98	)		(2.74	)	(2.89	)
		Administrative expenses and other		(1.09	)	(1.60	)	(1.63	)	(0.78	)	(1.23	)		(1.29	)	(1.23	)

		Earnings before income taxes		(1.15	)	(2.71	)	(2.05	)	(0.77	)	(0.28	)		(1.73	)	1.46

	U.S. Rockies
		Average price realized ⁽⁹⁾		7.15		5.20		—		—		—			6.35		—
		Royalties		(1.13	)	(0.82	)	—		—		—			(1.01	)	—
		Operating costs		(1.83	)	(1.79	)	—		—		—			(1.82	)	—

		Operating netback		4.19		2.59		—		—		—			3.52		—
		Depreciation, depletion and amortization		(3.44	)	(3.20	)	—		—		—			(3.35	)	—
		Administrative expenses and other		(0.66	)	(0.47	)	—		—		—			(0.58	)	—

		Earnings before income taxes		0.09		(1.08	)	—		—		—			(0.41	)	—

	Total Natural Gas
		Average price realized ⁽⁹⁾		5.26		3.89		3.88		5.77		6.99			4.71		9.35
		Royalties		(0.76	)	(0.29	)	0.33		(1.14	)	(1.60	)		(0.53	)	(2.17	)
		Operating costs		(1.78	)	(1.89	)	(1.71	)	(1.65	)	(1.46	)		(1.79	)	(1.60	)

		Operating netback		2.72		1.71		2.50		2.98		3.93			2.39		5.58
		Depreciation, depletion and amortization		(2.70	)	(2.78	)	(2.92	)	(2.97	)	(2.98	)		(2.79	)	(2.89	)
		Administrative expenses and other		(1.05	)	(1.49	)	(1.63	)	(0.78	)	(1.23	)		(1.23	)	(1.23	)

		Earnings before income taxes		(1.03	)	(2.56	)	(2.05	)	(0.77	)	(0.28	)		(1.63	)	1.46

	East Coast Canada ^(b)
		Average price realized ⁽⁹⁾		79.69		77.85		—		—		—			79.07		—
		Royalties		(25.26	)	(21.02	)	—		—		—			(23.82	)	—
		Operating costs		(7.89	)	(13.36	)	—		—		—			(9.76	)	—

		Operating netback		46.54		43.47		—		—		—			45.49		—
		Depreciation, depletion and amortization		(26.56	)	(17.48	)	—		—		—			(23.47	)	—
		Administrative expenses and other		(1.33	)	(0.52	)	—		—		—			(1.05	)	—

		Earnings before income taxes		18.65		25.47		—		—		—			20.97		—

Suncor Energy Inc.
040 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com


			Three months ended								Twelve months ended
				Dec 31 2009		Sept 30 2009		June 30 2009	Mar 31 2009	Dec 31 2008		Dec 31 2009		Dec 31 2008

International
	North Sea ^(b)
		Average price realized ⁽⁹⁾		71.46		72.06		—	—	—		71.63		—
		Operating costs		(8.08	)	(14.04	)	—	—	—		(9.78	)	—

		Operating netback		63.38		58.02		—	—	—		61.85		—
		Depreciation, depletion and amortization		(34.63	)	(24.54	)	—	—	—		(31.76	)	—
		Administrative expenses and other		(4.62	)	(7.61	)	—	—	—		(5.48	)	—

		Earnings before income taxes		24.13		25.87		—	—	—		24.61		—

	Other International
	*North Africa/Near East* ^(b)
		Average price realized ⁽⁹⁾		79.97		76.02		—	—	—		78.19		—
		Royalties		(32.12	)	(46.46	)	—	—	—		(39.88	)	—
		Operating costs		(6.03	)	(2.21	)	—	—	—		(4.05	)	—

		Operating netback		41.82		27.35		—	—	—		34.26		—
		Depreciation, depletion and amortization		(7.70	)	(2.31	)	—	—	—		(4.89	)	—
		Administrative expenses and other		(10.15	)	(5.21	)	—	—	—		(7.57	)	—

		Earnings before income taxes		23.97		19.83		—	—	—		21.80		—

	Other International
	*Northern Latin America* ^(g)
		Average price realized ⁽⁹⁾		2.58		2.09		—	—	—		2.42		—
		Royalties		(0.10	)	(1.58	)	—	—	—		(0.69	)	—
		Operating costs		(0.13	)	(0.46	)	—	—	—		(0.26	)	—

		Operating netback		2.35		0.05		—	—	—		1.47		—
		Depreciation, depletion and amortization		(1.84	)	(0.79	)	—	—	—		(1.44	)	—
		Administrative expenses and other		0.04		0.12		—	—	—		0.08		—

		Earnings before income taxes		0.55		(0.62	)	—	—	—		0.11		—

	Total International ^(l)
		Average price realized ⁽⁹⁾		67.96		67.42		—	—	—		67.86		—
		Royalties		(6.52	)	(19.25	)	—	—	—		(11.17	)	—
		Operating costs		(6.99	)	(8.22	)	—	—	—		(7.44	)	—

		Operating netback		54.45		39.95		—	—	—		49.25		—
		Depreciation, depletion and amortization		(27.02	)	(13.74	)	—	—	—		(22.27	)	—
		Administrative expenses and other		(5.29	)	(5.79	)	—	—	—		(5.46	)	—

		Earnings before income taxes		22.14		20.42		—	—	—		21.52		—

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2009 Fourth Quarter 041

Certain financial measures referred to in the Highlights and Quarterly Operating Summary are not prescribed by Canadian generally accepted accounting principles (GAAP). Suncor includes operating earnings, cash flow from operations, return on capital employed 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 GAAP.


(1) Total operations production	–	Total operations production includes total production from both mining and in-situ operations.
(2) Average sales price	–	This operating statistic is calculated before royalties (where applicable) and net of related transportation costs and excludes the realized impact of hedging activities unless stated.
(3) Cash operating costs	–	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non-GAAP financial measure for total operations (excluding Syncrude), see Management's Discussion and Analysis.
(4) Total cash operating costs	–	Include cash operating costs as defined above and cash start-up costs. Per barrel amounts are based on total production volumes.
(5) Total operating costs	–	Include total cash operating costs as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes.
(6) Cash operating costs – In-situ bitumen production	–	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes only.
(7) Total cash operating costs – In-situ bitumen production	–	Include cash operating costs – In-situ bitumen production as defined above and cash start-up operating costs. Per barrel amounts are based on in-situ production volumes only.
(8) Total operating costs – In-situ bitumen production	–	Include total cash operating costs – In-situ bitumen production as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes only.
(9) Average price received	–	This operating statistic is calculated before transportation costs and royalties and excludes the impact of hedging activities.

Suncor Energy Inc.
042 2009 Fourth Quarter For more information about Suncor Energy, visit our website www.suncor.com

Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V5
tel: (403) 269-8100 fax: (403) 269-6217 info@suncor.com www.suncor.com




WTI Price/bbl US$	60	80	100

Natural gas (Alberta spot) Cdn$/mcf at AECO	5.75	7.50	9.50

Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	7.25	9.75	12.00

Differential of Maya at the U.S. Gulf Coast less Western Canadian Select at Hardisty, Alberta US$	4.50	6.00	7.50

US$/Cdn$ exchange rate	0.85	0.97	1.00

Crown Royalty Expense (based on percentage of total Oil Sands gross revenue)% ⁽¹⁾
2010-2013 – Bitumen (new rates – with limits for mining only 30% and 1% min)	4-6	9-11	12-14




WTI Price/bbl US$	60	80	100

US$/Cdn$ exchange rate	0.85	0.97	1.00

Crown Royalty Expense (based on percentage of gross revenue)%
2010 – Crude (tiered royalty rates assessed on gross or net revenue)	29-31	31-33	32-34


		Other
	Pension	Post- Retirement
($ millions)	Benefits	Benefits		Total

Market value of plan assets	1 255	—		1 255
Accrued benefit obligation	1 912	265		2 177

Net liability assumed	(657)	(265	)	(922	)


		Other
	Pension	Post- Retirement
(percent)	Benefits	Benefits

Discount rate	5.25	5.25
Rate of compensation increase	3.00	3.00

Expected return on plan assets	6.75	N/A


	Quantity	Average Price	⁽¹⁾
Crude oil	(bpd)	(US$/bbl)		Period

Purchased puts ⁽²⁾	55 000	60.00		2010
Sold puts ⁽³⁾	54 753	60.00		2010
Collars – floor	50 041	50.00		2010
Collars – cap	49 986	68.06		2010


FOURTH QUARTER 2009
Report to shareholders for the period ended December 31, 2009


($ millions)

621.1 million common shares issued to Petro-Canada shareholders			18,878
7.1 million Petro-Canada share options exchanged for share options of Suncor			147
Transaction costs			167
Effective settlement of pre-existing contract with Petro-Canada (note f)			438

Total purchase price			19,630


($ millions)

Current assets		4,645
Property, plant and equipment		27,407
Other assets		537

	Total assets	32,589

Current liabilities		3,741
Long-term debt		4,410
Accrued liabilities and other		3,416
Future income taxes		4,570

	Total liabilities	16,137

Net assets purchased		16,452
Goodwill		3,178

	Total purchase price	19,630


($ millions)	2009	2008

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

AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2008 – $5)	15	13


($ millions)	2009

Fair value of contracts at December 31, 2008	621
Fair value of contracts realized during the period	448
Fair value of contracts entered into during the period	(983	)
Changes in fair value during the period	(445	)

Fair value of contracts outstanding at December 31, 2009	(359	)


	Common Shares
	Number (thousands)	Amount ($ millions)

Balance as at December 31, 2008	935 524	1 113
Shares issued to Petro-Canada shareholders (note 3)	621 142	18 878
Issued for cash under stock option plans	2 968	57
Issued under dividend reinvestment plan	144	5

Balance as at December 31, 2009	1 559 778	20 053


	Outstanding			Exercisable

Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life (years)	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)

7.84 – 12.99	2 476	1	10.03	2 476	10.03
13.00 – 17.99	13 984	2	14.18	13 984	14.18
18.00 – 29.99	15 157	4	22.31	10 788	22.93
30.00 – 44.99	17 736	4	38.91	10 863	39.72
45.00 – 49.99	21 216	5	47.45	4 557	46.51
50.00 – 72.68	1 455	5	57.62	87	52.75

Total	72 024	4	32.52	42 755	26.16


	Three months ended December 31				Pension Benefits Twelve months ended December 31
($ millions)	2009		2008		2009		2008

Current service costs	18		14		67		56
Interest costs	39		13		96		49
Expected return on plan assets	(32	)	(12	)	(76	)	(45	)
Amortization of net actuarial loss	6		5		21		22

Net periodic benefit cost	31		20		108		82


	Three months ended December 31		Other Post-Retirement Benefits Twelve months ended December 31
($ millions)	2009	2008	2009	2008

Current service costs	2	1	7	4
Interest costs	6	2	15	9
Amortization of net actuarial loss	—	1	—	3

Net periodic benefit cost	8	4	22	16


($ millions)			2009

Facility that is fully revolving for 364 days, has a term period of one year and expires in 2010			61
Facility that is fully revolving for a period of four years and expires in 2013			209
Facility that is fully revolving for a period of five years and expires in 2013			7 320
Facilities that can be terminated at any time at the option of the lenders			598

Total available credit facilities			8 188

Credit facilities supporting outstanding commercial paper, bankers' acceptances and LIBOR loans			3 244
Credit facilities supporting standby letters of credit			736

Total undrawn credit facilities			4 208


*		Excludes the impact of realized hedging activities.
**		If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
***		For the three months ended September 30, 2009, and the twelve months ended December 31, 2009, operating summary information reflects results of operations since the merger with Petro-Canada on August 1, 2009.
****		Users are cautioned that the Syncrude cash costs per barrel measure may not be fully comparable to similar information calculated by other entities (including Suncor's own cash costs per barrel excluding Syncrude) due to differing treatments for operating and capital costs among producers.


(a)	thousands of barrels per day	(e)	thousands of barrels of oil equivalent per day	(i)	$ millions
(b)	dollars per barrel	(f)	millions of cubic feet equivalent per day	(j)	percentage
(c)	dollars per barrel rounded to the nearest $0.05	(g)	dollars per thousand cubic feet equivalent	(k)	thousands of barrels of bitumen per day
(d)	millions of cubic feet per day	(h)	thousands of cubic metres per day	(l)	dollars per barrel of oil equivalent


Crude oil, refined products, etc.		1m ³ (cubic metre) = approx. 6.29 barrels