EXHIBIT 99.2
Management's Discussion and Analysis for the third quarter ended
September 30, 2009

This Management's Discussion and Analysis (MD&A) contains forward-looking information based on certain expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. For information on material risk factors and assumptions underlying our forward-looking information, see page 25.

This MD&A should be read in conjunction with our September 30, 2009 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A for the year ended December 31, 2008 and to our Annual Information Form (AIF) dated March 2, 2009. All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures: operating earnings, cash flow from operations, return on capital employed (ROCE), and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in Non-GAAP Financial Measures on pages 23 to 25 of this MD&A and page 40 of our 2008 Annual Report.

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

On August 1, 2009, Suncor completed its merger with Petro-Canada. All closing conditions were satisfied, including approvals from shareholders, the Alberta Court of Queen's Bench, and the Competition Bureau of Canada. Under the terms of the merger, Petro-Canada shareholders received 1.28 Suncor common shares for each Petro-Canada common share held. For further information with respect to the merger transaction, please refer to note 3 of the September 30, 2009 unaudited interim consolidated financial statements.

The consolidated financial statements include the results of post-merger Suncor from August 1, 2009. As such, the three and nine month amounts ending September 30, 2009 reflect results of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1, 2009 through July 31, 2009. The comparative figures reflect solely the 2008 results of legacy Suncor.

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

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

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

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

Industry Indicators

Three months ended September 30

Nine months ended September 30

(average for the period)

2009

2008

2009

2008

West Texas Intermediate (WTI) crude oil US$/barrel at Cushing

68.30

118.00

57.00

113.30

Dated Brent crude oil US$/barrel at Sullom Voe

68.25

114.80

57.15

111.00

Dated Brent/Maya FOB price differential US$/barrel

5.10

8.35

4.90

14.15

Canadian 0.3% par crude oil Cdn$/barrel at Edmonton

70.60

123.00

62.00

115.90

Edmonton Light/WCS FOB price differential Cdn$/barrel

8.80

18.35

8.15

21.05

Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty

10.10

18.05

8.85

20.40

Natural Gas US$/mcf at Henry Hub

3.40

10.10

3.90

9.65

Natural Gas (Alberta spot) Cdn$/mcf at AECO

3.00

9.25

4.10

8.55

New York Harbour 3-2-1 crack ⁽¹⁾ US$/barrel

7.50

10.65

8.55

10.30

Chicago 3-2-1 crack ⁽¹⁾ US$/barrel

7.65

16.45

8.90

12.15

Seattle 3-2-1 crack ⁽¹⁾ US$/barrel

12.80

14.70

13.20

14.40

Exchange rate: US$/Cdn$

0.91

0.96

0.86

0.98


		Three months ended
($ millions, except per share)		Sept 30 2009	June 30 2009		Mar 31 2009		Dec 31 2008		Sept 30 2008	June 30 2008	Mar 31 2008	Dec 31 2007

Revenues⁽¹⁾		8 443	4 768		4 633		6 952		8 507	7 640	5 539	4 844
Net earnings (loss)		929	(51	)	(189	)	(215	)	815	829	708	1 042

Net earnings (loss) per common share
	Basic	0.74	(0.06	)	(0.20	)	(0.24	)	0.87	0.89	0.77	1.12
	Diluted	0.74	(0.06	)	(0.20	)	(0.24	)	0.86	0.87	0.75	1.10

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

Net earnings for the third quarter of 2009 were $929 million, compared to net earnings of $815 million for the third quarter of 2008. Operating earnings for the third quarter of 2009 were $288 million, compared to $810 million in the third quarter of 2008. Cash flow from operations in the third quarter of 2009 was $574 million, compared to $1.146 billion in the same period of 2008.

Operating earnings is a non-GAAP measure that the company uses to evaluate operating performance, allowing 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.


		Three months ended September 30				Nine months ended September 30
($ millions, after-tax)		2009		2008		2009		2008

Net earnings as reported		929		815		689		2 352
	Change in fair value of commodity derivatives	(237	)	(125	)	435		(52	)
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(386	)	150		(643	)	207
	Mark-to-market valuation of stock-based compensation	72		(36	)	116		(57	)
	Project start-up costs	9		6		21		21
	Impact of income tax rate adjustments on future income tax liabilities ⁽¹⁾	152		—		152		—
	Costs related to deferral of growth projects	39		—		150		—
	Gain on effective settlement of pre-existing contract with Petro-Canada ⁽²⁾	(438	)	—		(438	)	—
	Impact of recording acquired inventory at fair value ⁽³⁾	97		—		97		—
	Merger and integration costs	51		—		67		—

Operating earnings		288		810		646		2 471

The decrease in earnings and cash flow from operations was primarily due to lower commodity price realizations, as benchmark prices were significantly weaker in the third quarter of 2009 compared to the same period in 2008, and operating expenses were higher in our Oil Sands segment due to increased production and sales volumes. These factors were partially offset by increased production resulting from the merger with Petro-Canada and improved operational performance in our existing oil sands assets.

Net earnings for the first nine months of 2009 were $689 million compared to $2.352 billion for the same period in 2008. Operating earnings in the first nine months of 2009 were $646 million, compared to $2.471 billion in the first nine months of 2008. Cash flow from operations was $1.670 billion in the first nine months of 2009, compared to $3.826 billion for the same period in 2008. The year-to-date decreases in earnings and cash flow from operations were primarily due to the same factors that impacted third quarter results.

Our effective tax rate for the first nine months of 2009 was 14%, compared to 29% in the first nine months of 2008. The lower effective tax rate for the first nine months of 2009 compared to 2008 is primarily a result of foreign exchange gains on our U.S. dollar denominated long-term debt being taxed at a lower capital gains rate, no tax impact relating to the gain on effective settlement of the pre-existing contract with Petro-Canada, and tax filing reconciliations.

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

For comparability purposes, readers should rely on the reported net earnings presented in our September 30, 2009 unaudited interim consolidated financial statements and notes in accordance with Canadian GAAP.


		Three months ended September 30				Nine months ended September 30
($ millions, after-tax)		2009		2008		2009		2008

Oil Sands net earnings as reported		738		854		321		2 300
	Change in fair value of commodity derivatives	(237	)	(125	)	435		(52	)
	Mark-to-market valuation of stock-based compensation	19		(5	)	28		(13	)
	Project start-up costs	9		6		21		21
	Impact of income tax rate adjustments on future income tax liabilities ⁽¹⁾	140		—		140		—
	Costs related to deferral of growth projects	39		—		150		—
	Gain on effective settlement of pre-existing contract with Petro-Canada ⁽²⁾	(438	)	—		(438	)	—
	Impact of recording acquired inventory at fair value ⁽³⁾	5		—		5		—

Oil Sands operating earnings		275		730		662		2 256

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

Oil Sands recorded net earnings of $738 million in the third quarter of 2009, compared with $854 million in the third quarter of 2008. Operating earnings for the third quarter of 2009 were $275 million, compared to $730 million in the third quarter of 2008. Earnings decreased primarily as a result of lower average price realizations for oil sands crude products, partially offset by higher production.

The decrease in price realizations reflects significantly lower benchmark West Texas Intermediate (WTI) crude oil prices and a decreased premium to WTI on our sweet crude blends, partially offset by a smaller discount to WTI for our sour crude blends, increased sales of higher value sweet crude products, and a weaker Canadian dollar.

Overall cash expenses were lower in the third quarter of 2009 compared to the same period of 2008, primarily due to decreased purchases of crude oil and products, partially offset by increased cash operating expenses. Purchases of crude oil and products decreased due primarily to the absence of unplanned shutdowns, as the comparative quarter of 2008 saw higher purchases of diesel and bitumen to meet customer commitments. In addition, in the third quarter of 2008, Suncor purchased product from legacy Petro-Canada to upgrade at Suncor facilities.

The increase in cash operating expenses was due primarily to costs associated with higher production and sales volumes in legacy Suncor operations, as well as the addition of operating costs for MacKay River and Syncrude. In addition, we incurred costs related to the planned implementation of reliability and operational efficiency initiatives, increased employee costs resulting from a larger number of employees and higher overall salaries, as well as further safe mode costs (see page 12). These factors were partially offset by lower energy input costs and cost reduction initiatives in the business.

Non-cash expenses increased during the third quarter of 2009 as compared to the third quarter of 2008, due primarily to increased depreciation, depletion and amortization (DD&A) expense. The increase resulted from continued growth in the depreciable cost base for our oil sands facilities, including the addition of facilities for MacKay River and Syncrude as a result of the merger with Petro-Canada.

Alberta Crown royalty expense decreased in the third quarter of 2009, compared to the third quarter of 2008, primarily due to lower benchmark WTI prices, partially offset by increased production. For a further discussion of Crown royalties, see page 12.

Cash flow from operations was $242 million in the third quarter of 2009, compared to $1.030 billion in the third quarter of 2008. The decrease was due primarily to the same factors that impacted earnings.

Net earnings for the first nine months of 2009 were $321 million, compared to $2.300 billion in the first nine months of 2008. Operating earnings for the first nine months of 2009 were $662 million, compared to $2.256 billion in the same period of 2008. Cash flow from operations for the first nine months 2009 decreased to $896 million from $3.186 billion in the first nine months of 2008. The year-to-date decreases in earnings and cash flow from operations were due primarily to the same factors that impacted third quarter results.

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

Oil Sands production averaged 305,300 barrels per day (bpd) in the third quarter of 2009, compared to 245,600 bpd during the third quarter of 2008. The increased production was primarily due to improved operational reliability in the third quarter of 2009. Production in the comparative quarter of 2008 was negatively impacted by unplanned maintenance shutdowns in our upgrading and extraction assets, as well as wet weather that impacted mine production. Based on results from the first nine months of 2009 and our expectations for the fourth quarter, the Oil Sands production outlook has been narrowed to 290,000 to 305,000 bpd.

As a result of the merger, Suncor holds a 12% share in the Syncrude joint venture oil sands operations located close to Suncor's existing oil sands operations in Fort McMurray, Alberta, Canada. Syncrude operations contributed an average 37,400 bpd of sweet crude production for August and September, 2009.

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

Sales volumes during the third quarter of 2009 averaged 287,600 bpd, compared with 219,000 bpd during the third quarter of 2008. The increase was due primarily to increased production and the addition of sales volumes from MacKay River as a result of the merger. The proportion of higher value diesel and sweet crude products increased to 44% of total sales volume in the third quarter of 2009, compared to 27% in the third quarter of 2008 as a result of improved operational reliability in the third quarter of 2009. In addition, in the comparative quarter of 2008, an unplanned shutdown of hydrogen facilities adversely affected the sales mix. Based on year-to-date results and expectations for the fourth quarter, our sales volume split outlook has been adjusted to diesel 11%, sweet 36%, sour 49% and bitumen 3%.

The average price realization for oil sands crude products from Suncor's operated assets decreased to $61.70 per barrel in the third quarter of 2009, compared to $116.32 per barrel in the third quarter of 2008. This was primarily due to a significant decrease in the average benchmark WTI crude oil price of about 42% and a decreased premium to WTI on our sweet crude blends. These factors were partially offset by a smaller discount to WTI for our sour crude blends, a change in sales mix which reflected a larger portion of higher priced sweet products, and the positive impact of the weaker Canadian dollar, as we received higher revenues for our production sold based on U.S. dollar benchmark prices. Based on year-to-date results and expectations for the fourth quarter of 2009, the oil sands realization on crude sales basket outlook has been adjusted to WTI @ Cushing less Cdn$5.50 to Cdn$6.00 per barrel.

During the third quarter of 2009, cash operating costs averaged $32.25 per barrel, compared to $34.00 per barrel during the third quarter of 2008. The decrease in cash operating costs per barrel was primarily due to the increase in production and a decrease in natural gas input prices. These factors were partially offset by an increase in operational expenses due to the inclusion of operating costs from MacKay River in the third quarter of 2009. Cash operating costs per barrel does not include costs related to deferral of growth projects. Based on results from the first nine months of 2009 and expectations for the fourth quarter, our cash operating costs outlook has been lowered to $32.00 to $34.00 per barrel. Refer to page 23 to 25 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

A planned maintenance shutdown of a vacuum unit at one of our upgrading facilities commenced on September 8, 2009, and was completed ahead of schedule on October 3, 2009, affecting overall production in the third and fourth quarters of 2009.

With the closure of the merger with Petro-Canada on August 1, 2009, we have begun the process of reviewing all capital projects with a view to directing capital investment toward projects with the strongest near-term cash flow potential, highest anticipated return on capital and lowest risk.

This process is expected to be completed in the coming weeks, at which time we will announce our 2010 capital budget.

During the third quarter of 2009, the Steepbank extraction plant was completed on schedule and within the revised budget disclosed in our 2009 second quarter report. The plant began operations in late September, after commissioning, and is expected to result in improved reliability and productivity within our oil sands business beginning in the fourth quarter of 2009. The Firebag sulphur plant was also completed on schedule and on budget during the third quarter of 2009. It is ready to operate and is expected to support sulphur emissions reductions for existing and planned in-situ development.

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

For an update on our significant capital projects currently in progress see page 19.

The Oil Sands segment continued to incur costs related to placing certain growth projects into "safe mode" as a result of the company revising its 2009 capital budget due to market conditions earlier in the year. Safe mode is defined as the costs of deferring the projects and keeping the equipment and facilities in a safe manner in order to expedite remobilization. As a result of placing the company's projects into safe mode, pre-tax costs of $270 million were incurred in the first nine months of 2009. These costs are expected to total between $300 million and $400 million on a pre-tax basis in 2009.

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 2009 and 2010 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios.




WTI Price/bbl US$ ⁽¹⁾	60	70	80

Natural gas (Alberta spot) Cdn$/mcf at AECO	5.50	6.00	6.50

Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	6.00	9.00	11.50

Differential of Maya at the U.S. Gulf Coast less Western Canadian Select at Hardisty, Alberta US$	3.00	3.00	3.00

US$/Cdn$ exchange rate	0.85	0.90	0.95

Crown Royalty Expense (based on percentage of total Oil Sands gross revenue) %
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates)	7-8	7-9	8-9
2010 – Bitumen (new rates – with limits for mining only)	5-6	7-9	8-10

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

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


		Three months ended September 30			Nine months ended September 30
($ millions, after-tax)		2009		2008	2009		2008

Natural Gas net earnings (loss) as reported		(111	)	18	(149	)	89
	Mark-to-market valuation of stock-based compensation	9		—	9		(1	)
	Impact of income tax rate adjustments on future income tax liabilities⁽¹⁾	9		—	9		—

Natural Gas operating earnings (loss)		(93	)	18	(131	)	88

Natural Gas recorded a net loss of $111 million in the third quarter of 2009, compared with net earnings of $18 million during the third quarter of 2008. Operating loss for the third quarter of 2009 was $93 million, compared to operating earnings of $18 million in the third quarter of 2008. The decrease in operating earnings was primarily due to reduced revenues resulting from significantly lower benchmark commodity prices, lower sulphur revenue and higher dry hole costs. This was partially offset by lower royalty expense in the third quarter of 2009 compared to the third quarter of 2008. The decrease in royalties is a result of lower revenues, royalty credits and reduced rates due to the implementation of the Alberta New Royalty Framework.

Cash flow from operations for the third quarter of 2009 was $74 million, compared to $98 million in the third quarter of 2008. The decrease was primarily due to the same factors that affected net earnings, excluding the impact of dry hole costs. The net loss for the first nine months of 2009 was $149 million, compared to net earnings of $89 million in the first nine months of 2008. Operating loss for the first nine months of 2009 was $131 million, compared to operating earnings of $88 million in the same period of 2008. Cash flow from operations for the first nine months of 2009 decreased to $169 million from $304 million in the first nine months of 2008. The year-to-date decreases in earnings and cash flow from operations were primarily due to the same factors that impacted third quarter results.

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

After completion of the merger with Petro-Canada, Suncor's natural gas production during August and September averaged 772 million cubic feet equivalent (mmcfe) per day. Additional production resulting from the merger accounted for 563 mmcfe per day. Production from Suncor's legacy natural gas operations averaged 208 mmcfe per day in the third quarter of 2009 (209 mmcfe per day during August and September), compared to 213 mmcfe per day in the third quarter of 2008. The decreased production was primarily due to shut-in production in the Elmworth area as a result of low commodity prices and the sale of certain non-core assets in the second quarter of 2009.

Realized natural gas prices in the third quarter of 2009 were $2.81 per thousand cubic feet (mcf), compared to $9.10 per mcf in the third quarter of 2008, reflecting significantly lower benchmark prices.

As part of its strategic business alignment and subject to Board of Directors approval, Suncor plans to divest of a number of non-core natural gas assets. The proposed divestments identified to date include certain natural gas assets in Western Canada and the United States Rockies. Once the natural gas portion of the divestment program is complete, our natural gas assets are expected to provide a solid foundation to support long-term growth in our core oil sands business while targeting a low-cost position among North American natural gas producers, with a growing focus on unconventional gas.


		Three months ended September 30
($ millions, after-tax)		2009

East Coast Canada net earnings as reported		39
	Mark-to-market valuation of stock-based compensation	1
	Impact of recording acquired inventory at fair value⁽¹⁾	17

East Coast Canada operating earnings		57

Net earnings for East Coast Canada were $39 million in the third quarter of 2009, while operating earnings for the third quarter of 2009 were $57 million. Cash flow from operations for the third quarter of 2009 was $130 million. Lower than capacity production as a result of planned and unplanned maintenance, as well as the tie-in of the North Amethyst extension at White Rose, adversely impacted earnings in the quarter.


			Two months ended September 30
Barrels per day			2009

Terra Nova			16 000
Hibernia			28 500
White Rose			5 100

Total East Coast Canada production			49 600

In the two months ended September 30, 2009, East Coast Canada production averaged 49,600 bpd. Terra Nova production averaged 16,000 bpd, with production impacted by planned and unplanned maintenance during the two months ended September 30, 2009. Production from Hibernia averaged 28,500 bpd for the two months ended September 30, 2009, with strong reservoir capability and facility reliability in the period. White Rose production averaged 5,100 bpd during the two months ended September 30, 2009, with production negatively impacted by planned downtime for maintenance and the tie-in of the North Amethyst extension.

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

Sales volumes in the two months ended September 30, 2009 averaged 49,400 bpd, impacted by the same factors affecting production.

The East Coast Canada segment's average realized crude oil price was $75.22 per barrel in the third quarter of 2009.




WTI Price/bbl (US$) ⁽¹⁾	60	70	80

US$/Cdn$ exchange rate	0.85	0.90	0.95

Crown Royalty Expense (based on percentage of gross revenue) %
2009 – Crude (tiered royalty rates assessed on gross or net revenue)	27-29	28-30	29-31
2010 – Crude (tiered royalty rates assessed on gross or net revenue)	32-34	33-35	34-36

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:

In the third quarter of 2009, East Coast Canada royalties averaged 28% of gross revenue. Terra Nova production was subject to a Tier I royalty of 30% of net revenue and a Tier II royalty of an incremental 12.5% of net revenue. White Rose production was subject to a Tier I royalty of 20% of net revenue and a Tier II royalty of 10% of net revenue. The royalty rate on Hibernia production increased from 5% of gross revenue to 30% of net revenue during 2009 based on the terms of the Hibernia Royalty Agreement and a Memorandum of Understanding. In addition, Hibernia production was subject to a federal government net profits interest of up to 10% of net revenue.

A planned shutdown at our Terra Nova facility commenced in mid September, and was completed ahead of schedule in early October, affecting overall production in the third and fourth quarters of 2009.

A twelve-day shutdown planned for October at the Hibernia facility has been deferred to 2010.

Production from White Rose continued to be impacted during August and September after completion of the planned turnaround, as the South Drill Center remained shut-in until early October for a planned tie-in of the North Amethyst extension, affecting overall production in the third and fourth quarters of 2009.

Installation of subsea infrastructure is complete and development drilling has commenced for the North Amethyst portion of the White Rose Extensions, with the project on schedule for early 2010. Development drilling of North Amethyst will continue through 2010 and 2011.

Engineering and design activities continued for the Hebron project during the third quarter of 2009.

Drilling commenced during the third quarter of 2009 on the Hibernia South Extension project, with anticipated production starting in late 2009 or early 2010.

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


($ millions, after-tax)		Three months ended September 30 2009

International net earnings as reported		32
	Mark-to-market valuation of stock-based compensation	6
	Impact of recording acquired inventory at fair value⁽¹⁾	8

International operating earnings		46

In the third quarter of 2009, International recorded net earnings of $32 million, while operating earnings were $46 million. Lower than capacity production and high operating costs due to maintenance and dry hole costs adversely impacted earnings in the quarter.

Cash flow from operations for the third quarter of 2009 was $163 million, impacted by the same factors affecting earnings, with the exception of dry hole costs.


Boe per day			Two months ended September 30 2009

U.K. sector of the North Sea			40 800
The Netherlands sector of the North Sea			13 800

Total North Sea			54 600
Other International			54 000

Total International production			108 600

International production averaged 108,600 boe per day in the two months ended September 30, 2009. Buzzard production in the North Sea averaged 29,400 boe per day in the two months ended September 30, 2009, impacted by a planned four-week shutdown in the quarter. In the Netherlands sector of the North Sea, production was 13,800 boe per day for the two months ended September 30, 2009.

Other International consists of our producing assets in Libya and Trinidad and Tobago. Production in Libya averaged 42,700 boe per day in the two months ended September 30, 2009, with production impacted by OPEC quota constraints. Trinidad and Tobago offshore gas production averaged 67.8 mmcf per day in the two months ended September 30, 2009, with high demand from the Atlantic liquefied natural gas (LNG) terminal in the period.

The average realized price for the North Sea was $68.67 per barrel in the third quarter of 2009, while the average realized price for Other International was $62.40 per barrel of oil equivalent.

During the two months ended September 30, 2009, planned maintenance shutdowns occurred at the Buzzard and Hanze facilities in the North Sea, resulting in reduced production. Operations have since commenced and no further impact is expected. In late September 2009, planned turnaround and maintenance commenced at the Triton facility and was completed in early October, affecting overall production in the third and fourth quarters of 2009.

The Syria Ebla Gas Project remains on plan for first gas delivery in mid-2010 and was 80% complete at the end of the third quarter of 2009. Five wells have been completed and are ready for production. In addition, the 3D seismic acquisition of the Cherrife field was completed at the end of the third quarter of 2009.

Work has now commenced on implementing the projects associated with the new Libya Exploration and Production Sharing Agreements (EPSAs), with a focus on preparing the EPSA field development programs and initiating the new exploration program. Work on the exploration program is progressing, with three seismic surveys completed during the quarter and another three seismic crews continuing to acquire data in country.

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

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


		Three months ended September 30			Nine months ended September 30
($ millions, after-tax)		2009	2008		2009	2008

Refining and Marketing net earnings (loss) as reported		51	(11	)	275	169
	Mark-to-market valuation of stock-based compensation	14	(1	)	15	(2	)
	Impact of recording acquired inventory at fair value⁽¹⁾	67	—		67	—

Refining and Marketing operating earnings (loss)		132	(12	)	357	167

Refining and Marketing recorded 2009 third quarter net earnings of $51 million, compared to a net loss of $11 million in the third quarter of 2008. Operating earnings for the third quarter of 2009 were $132 million, compared to an operating loss of $12 million in the third quarter of 2008. The increase in operating earnings was primarily due to the addition of assets associated with the company's merger with Petro-Canada in the third quarter of 2009. In addition, our margins improved as a result of increased operational reliability at both the Sarnia and Commerce City refineries that enabled us to process more lower-priced crude instead of purchasing refined products.

After completion of the merger, total sales of refined petroleum products during August and September 2009 averaged 87.5 million litres per day. Additional sales resulting from the merger accounted for 53.4 million litres per day. Total sales of refined petroleum products from Suncor's legacy refining and marketing operations averaged 34.1 million litres per day during August and September 2009, compared to 32.0 million litres per day in the third quarter of 2008. This increase in sales was primarily due to increased demand and improved operational reliability as compared to the third quarter of 2008.

Refining and Product Supply contributed operating earnings of $98 million in the third quarter of 2009, up from an operating loss of $21 million in the same quarter of 2008. The increase was due primarily to increased production resulting from the addition of the Edmonton and Montreal refineries, and the lubricants plant, as a result of the merger. In addition, improved operational reliability at our existing Sarnia and Commerce City refineries resulted in higher margins, as we were able to process more lower-price crude. Lower reliability levels in the comparative quarter of 2008 resulted in higher purchases of refined product to meet customer commitments, and this negatively impacted our margins in that period.

Marketing contributed operating earnings of $34 million in the third quarter of 2009, up from $9 million in the same quarter of 2008. The increase was due primarily to the addition of the national Retail and Wholesale operations and the Lubricants business as a result of the merger with Petro-Canada during the third quarter of 2009.

Cash flow from operations was $275 million in the third quarter of 2009, compared to $19 million in the third quarter of 2008. The increase was primarily due to the same factors that affected net earnings during the quarter. Net earnings for the first nine months of 2009 were $275 million, compared to $169 million in the first nine months of 2008. Operating earnings for the first nine months of 2009 were $357 million, compared to $167 million in the same period of 2008. Cash flow from operations for the first nine months of 2009 increased to $695 million from $429 million in the first nine months of 2008. The year-to-date changes in earnings and cash flow from operations were primarily due to the same factors that impacted third quarter results, in addition to increased refined product sales from our legacy Suncor refineries.

During August 2009, an unplanned shutdown occurred at the Edmonton refinery and an unplanned outage occurred at the Sarnia refinery, resulting in reduced throughput. Operations have since commenced and no further impact is expected. In the fourth quarter of 2009, planned turnarounds are scheduled for the Montreal and Commerce City refineries. As with all planned refining turnarounds, supply arrangements are in place to meet market demand during these outages.

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


		Three months ended September 30				Nine months ended September 30
($ millions, after-tax)		2009		2008		2009		2008

Corporate, energy trading and eliminations net earnings (loss) as reported		180		(46	)	171		(206	)
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(386	)	150		(643	)	207
	Mark-to-market valuation of stock-based compensation	23		(30	)	57		(41	)
	Impact of income tax rate adjustments on future income tax liabilities⁽¹⁾	3		—		3		—
	Merger and integration costs	51		—		67		—

Corporate, energy trading and eliminations operating earnings (loss)		(129	)	74		(345	)	(40	)

Corporate, Energy Trading and Eliminations recorded an operating loss of $129 million in the third quarter of 2009, compared to operating earnings of $74 million in the third quarter of 2008. Results reflected higher net interest expense in the third quarter of 2009 due to additional debt acquired through the merger with Petro-Canada and the expensing of $134 million of interest costs relating to growth projects now in safe mode. In addition, results reflected lower energy trading earnings and an increase in profits eliminated on crude oil sales between upstream segments and Refining and Marketing, where this crude oil still resides in Refining and Marketing's inventories.


	Three months ended September 30
($ millions, after-tax)	2009		2008

Corporate net earnings (loss)	222		(115	)
Energy trading	25		57
Group eliminations	(67	)	12

Total net earnings (loss)	180		(46	)

Energy trading activities resulted in net pre-tax earnings of $35 million in the third quarter of 2009, compared to $85 million in the third quarter of 2008, due primarily to a decrease in earnings on our crude trading activities.

Cash used in operations was $310 million in the third quarter of 2009, compared to $1 million in the third quarter of 2008.

Corporate net earnings were $171 million in the first nine months of 2009, compared to a net loss of $206 million in the same period of 2008. Operating loss for the first nine months of 2009 was $345 million, compared to $40 million in the same period of 2008. Cash used in operations for the first nine months of 2009 increased to $383 million from $93 million in the first nine months of 2008. The year-to-date changes in earnings and cash flow used in operations were primarily due to the same factors that impacted third quarter results.

We estimate we will have cash income taxes of approximately $900 million to $1.0 billion during 2009. 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 12 and 15, 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.

Our capital resources consist primarily of cash flow from operations and available lines of credit. As a result of the merger with Petro-Canada, we added approximately $4.2 billion in undrawn credit facilities and obtained $415 million in cash, of which $364 million was used to reduce outstanding short-term borrowings.

We believe we will have the capital resources to fund our planned capital spending program and to meet current working capital requirements through cash flow from operations and our committed credit facilities, assuming our current production outlooks are met. Our cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, refining and marketing margins, operating expenses, taxes, royalties, and US$/Cdn$ exchange rates. If additional capital is required, we believe adequate additional financing will be available in the debt capital markets at commercial terms and rates.

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

Although benchmark oil prices have continued to strengthen through 2009, we have maintained crude oil hedge contracts through the remainder of the year and into 2010 that provide an element of security to our cash flow from operations. For further details on our derivative hedging programs, see page 20.

Management of debt levels continues to be a priority given our long-term growth plans. We believe a phased and flexible approach to existing and future growth projects should assist us in maintaining our ability to manage project costs and debt levels. At September 30, 2009, our net debt (short-term debt and long-term debt less cash and cash equivalents) was $13.263 billion, compared to $7.226 billion at December 31, 2008. The increase in debt levels resulting from the merger with Petro-Canada caused our net debt/cash flow from operations measure to increase significantly, as the calculation only includes two months of cash flow from operations relating to legacy Petro-Canada operations. Undrawn lines of credit at September 30, 2009 were approximately $5.4 billion.

Subsequent to the end of the third quarter, we reduced our committed bilateral credit facility from $855 million to $330 million, and we increased our commercial paper program from $1.5 billion to $2.5 billion. As well, in October Dominion Bond Rating Service confirmed our A (low) rating with a Stable Trend, and Moody's Investors Service moved our senior unsecured rating to Baa2; outlook stable (from Baa1; under review for potential downgrade).

We are subject to financial and operating covenants related to our public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. We are in compliance with our financial covenant that require consolidated debt to not be more than 60% of our total capitalization. At September 30, 2009, our consolidated debt to total capitalization was 29% (where consolidated debt is short-term debt plus long-term debt, and total capitalization is consolidated debt plus shareholders' equity). We are also in compliance with all operating covenants.

Excluding cash and cash equivalents, short-term debt, the current portion of long-term debt and future income taxes, Suncor had operating working capital of $15 million at the end of the third quarter of 2009, compared to a deficiency of $111 million at the end of the third quarter of 2008.

The preceding paragraphs contain forward-looking information regarding our liquidity and capital resources based on factors and assumptions discussed above and on page 25. Users of this information are cautioned that our actual liquidity and capital resources may vary materially.

With the deferral of the company's growth projects and the reduction of capital spending announced in January 2009, construction on the Voyageur upgrader and Firebag in-situ facilities has been wound down and the projects placed into safe mode, pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. For a summary of the projects placed into safe mode, please see page 14 of our 2008 Annual Report.

The Firebag sulphur plant was also completed on schedule and on budget during the third quarter of 2009. The plant is ready to operate and is expected to support sulphur emissions reductions for existing and planned in-situ development.

Development drilling has commenced and installation of subsea infrastructure is underway for the North Amethyst portion of the White Rose Extensions, with the project on schedule to deliver first oil in early 2010. The West White Rose development will be divided into two stages. Stage 1 was approved in Q2 2009, and development drilling and subsea installation of this stage will take place in 2010, with first oil expected in late 2010 or early 2011. Results of Stage 1, combined with ongoing evaluation, will help define the full field development scope.

Work has now commenced on implementing the projects associated with the new Libya Exploration and Production Sharing Agreements (EPSAs), with a focus on preparing the Amal field development program and initiating the new exploration program. Work on the exploration program is progressing, with three seismic surveys completed during the

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

The preceding paragraphs 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.

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

For a list of the additional risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially, please see page 19 of Suncor's 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 25.

We periodically enter into derivative contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices.

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

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

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

The company has hedged a portion of its forecasted U.S. dollar denominated sales subject to U.S. dollar West Texas Intermediate (WTI) price risk. We continue to hold contracts to sell approximately 105,000 barrels per day (bpd) of production at US$51.00 and options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 for the remainder of 2009.

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

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

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

We periodically enter into interest rate swap contracts as part of our strategy to manage exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between ourselves and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized as an adjustment to interest expense. Amounts received or paid on settlement will be recorded as part of the related hedged sales transactions.

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

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

Significant commodity contracts outstanding at September 30, 2009 were as follows:

The net earnings impact associated with our commodity and treasury hedging activities in the third quarter of 2009 was a pre-tax gain of $55 million, compared to $68 million in the third quarter of 2008. The earnings impact in the first nine months of 2009 was a pre-tax loss of $897 million, compared to a pre-tax loss of $31 million in the first nine months of 2008.

A reconciliation of changes in accumulated other comprehensive income (AOCI) attributable to derivative hedging activities for the nine month periods ending September 30 is as follows:


($ 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 – $3)	1	(7	)
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $nil (2008 – $2)	2	5

AOCI attributable to derivative hedging activities, at September 30, net of income taxes of $5 (2008 – $3)	16	11

In addition to derivative contracts used for hedging activities, Suncor uses physical and financial energy derivatives to earn trading revenues. These energy contracts are comprised of crude oil, natural gas and refined products derivative contracts. The results of these trading activities are reported as energy trading revenues and expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pre-tax earnings associated with our energy trading activities in the third quarter of 2009 were $35 million (2008 – $85 million). The net pre-tax earnings in the first nine months of 2009 were $34 million (2008 – $100 million).

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


($ millions)		September 30 2009		December 31 2008

Derivative financial instruments accounted for as hedges
	Assets	20		24
	Liabilities	—		(13	)
Derivative financial instruments not accounted for as hedges
	Assets	209		635
	Liabilities	(627	)	(14	)

Net derivative financial instruments		(398	)	632

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

Our strategic crude oil hedging program is subject to periodic management reviews to determine appropriate hedge requirements in light of our tolerance for exposure to market volatility as well as the need for stable cash flow to finance future growth.

We may be exposed to certain losses in the event that the counterparties to derivative financial instruments are unable to meet the terms of the contracts. We minimize this risk by entering into agreements with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date.

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

For a description of risk factors that may affect performance, including but not limited to political, environmental, socio-economic, operational, market and other business risk factors, see Suncor's 2008 Annual Information Form and Petro-Canada's 2008 Annual Information Form.

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

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

Currently in the UK, a review of regulations which may impact the disposal of naturally occurring radioactive material (NORM) is in consultation stage with the government. At this time, no such legislation has been tabled in this jurisdiction and any potential impacts are unknown.

There remains uncertainty around the outcome and impacts of climate change and other environmental regulations. Depending on the scope of any final regulations, these impacts may have an adverse effect on our operational and financial results in the future. We continue to actively work to mitigate our environmental impact, investing in renewable energy such as wind power and biofuels, accelerating land reclamation, installing new emission abatement equipment and investigating other mitigation opportunities.

In early 2009, a number of frameworks, proposals and directives were issued by the various provincial regulators that oversee oil sands development. These relate to tailings management, water use and land use to name a few. While the financial implications of such directives are yet unknown, Suncor is committed to working with the appropriate regulatory bodies as they develop new policies and to fully comply with all existing and new regulations and directives as they apply to the company's operations. In Suncor's recently released 2009 Report on Sustainability, we announced environmental targets for air emissions, land reclamation and water use. For details on these targets, refer to the Report on Sustainability located at www.suncor.com.

Based on their evaluation as of September 30, 2009, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed by us in reports that we file or submit to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as of September 30, 2009, there were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) – 15d-15(f)) that occurred during the three month period ended September 30, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal control over financial reporting and will make any modifications from time-to-time as deemed necessary.

Management continues to integrate the acquired company historical internal control over financial reporting with

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

Suncor's internal control over financial reporting. This integration will lead to changes in these controls in future fiscal periods but management does not yet know whether these changes will materially affect the Company's internal control over financial reporting. Management expects this integration process to be completed during 2010.

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

On January 1, 2009, the company retroactively adopted Canadian Institute of Chartered Accountants (CICA) Handbook section 3064 "Goodwill and Intangible Assets". This new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs", and focuses on the criteria for asset recognition in the financial statements, including those internally developed. The impact of adopting this standard resulted in a change in the classification of our deferred maintenance shutdown costs that had previously been classified within other assets and amortized over the period to the next shutdown, as follows:

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

In the third quarter of 2009, the company began integration of the legacy Petro-Canada and Suncor's IFRS conversion projects. Key activities included integrating the project plans, reviewing the accounting documentation, aligning the IFRS accounting conclusions, and reviewing of the design of the Information Technology dual reporting solutions.

The IFRS project continues to be on target to meet the changeover date. New and revised IFRS developments will be reviewed throughout the project and changes made as necessary.

Certain financial measures referred to in this MD&A, namely operating earnings, cash flow from operations, return on capital employed (ROCE) and oil sands cash 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, 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 8 of this MD&A for a reconciliation of net earnings to operating earnings.

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 September 30, 2009 interim basis, please refer to page 48.

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 includes the impact of fair value changes on both the current and long-term portions of commodity derivatives and stock-based compensation (previously only included the impact on the long-term portions). Prior period comparative figures have been restated. A reconciliation of net earnings

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

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 an integral part of Suncor's September 30, 2009 unaudited interim consolidated financial statements.

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

Three months ended
September 30

Nine months ended
September 30

2009

2008

2009

2008

Cash flow from operations ($ millions)

574

1 146

1 670

3 826

Weighted number of shares outstanding – basic (millions of shares)

1 247.9

934.5

1 061.1

930.4

Cash flow from operations – basic ($ per share)

0.46

1.23

1.57

4.11

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 September 30						Nine months ended September 30
		2009			2008			2009			2008
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		981			822			2 977			2 213
	Less: Natural gas costs, inventory changes, stock-based compensation, and other	(23	)		(182	)		(236	)		(341	)
	Less: Safe mode costs	(45	)		—			(260	)		—
	Less: Non-monetary transactions	(14	)		(25	)		(56	)		(81	)
	Less: Syncrude-related operating, selling and general expenses	(66	)		—			(66	)		—
Accretion of asset retirement obligations		27			14			80			41

Cash costs		860		30.65	629		27.80	2 439		30.30	1 832		30.00
Natural gas		44		1.55	97		4.30	164		2.05	347		5.70
Imported bitumen (excluding other reported product purchases)		2		0.05	42		1.90	3		0.05	107		1.75

Cash operating costs		906		32.25	768		34.00	2 606		32.40	2 286		37.45
Project start-up costs		12		0.45	8		0.35	38		0.45	29		0.50

Total cash operating costs		918		32.70	776		34.35	2 644		32.85	2 315		37.95
Depreciation, depletion and amortization		214		7.60	151		6.70	593		7.35	412		6.75

Total operating costs		1 132		40.30	927		41.05	3 237		40.20	2 727		44.70

Production excluding Syncrude (thousands of barrels per day)		305.3			245.6			294.8			222.6

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


		Three months ended September 30						Nine months ended September 30
		2009			2008			2009			2008
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		113			82			307			251
	Less: Natural gas costs	(29	)		(42	)		(82	)		(133	)
	Less: Safe mode costs	(16	)		—			(66	)		—

Cash costs		68		10.25	40		10.75	159		10.65	118		11.75
Natural gas		29		4.30	42		11.30	82		5.55	133		13.25

Cash operating costs		97		14.55	82		22.05	241		16.20	251		25.00
In-situ start-up costs		4		0.65	3		0.80	19		1.30	9		0.90

Total cash operating costs		101		15.20	85		22.85	260		17.50	260		25.90
Depreciation, depletion and amortization		39		5.95	20		5.40	92		6.25	63		6.30

Total operating costs		140		21.15	105		28.25	352		23.75	323		32.20

Production (thousands of barrels per day)		71.9			40.4			54.3			36.6

This Management's Discussion and Analysis contains certain forward-looking statements and other information that are based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of its experience and its perception of historical trends.

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," 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 2009 outlook, see page 4 of our third quarter 2009 report to Shareholders.

The risks, uncertainties and other factors that could influence actual results include but are not limited to, market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; availability of third-party bitumen; success of hedging strategies, maintaining a desirable debt to 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; 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; political, economic and socio-economic risk associated with foreign operations (including OPEC production quotas); 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 the two entities; and incorrect assessments of the values of the other entity. The foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in 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 Third Quarter 025


Outstanding Share Data⁽¹⁾ (at September 30, 2009)

Common shares			1 558 900 869
Common share options – total			73 784 398
Common share options – exercisable			44 813 379


Crude Oil	Quantity (bpd)	Price (US$/bbl)	⁽¹⁾	Hedge Period

Purchased puts	55 000	60.00		2009
Fixed price	104 391	51.00		2009
Purchased puts	55 000	60.00		2010
Sold puts	54 753	60.00		2010
Collars – floor	50 041	50.00		2010
Collars – cap	49 986	68.06		2010


($ millions, increase/(decrease))	As at September 30 2009		As at December 31 2008

Property, plant and equipment, net	475		566
Other assets	(475	)	(566	)