Interim Management's Discussion and Analysis for the second fiscal quarter ended June 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 17.

This MD&A should be read in conjunction with our June 30, 2009 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 6 to 42 of our 2008 Annual Report 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: cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in Non-GAAP Financial Measures on page 40 of our 2008 Annual Report, and page 15 of this MD&A.

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.

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.

Additional information about Suncor 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.

The information in this MD&A does not assume the completion of the proposed merger between Suncor and Petro-Canada, and forward-looking information is presented for Suncor on a stand-alone basis.

Industry Indicators

Three months ended June 30

Six months ended June 30

(average for the period)

2009

2008

2009

2008

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

59.60

124.00

51.35

110.95

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

65.30

126.40

57.70

112.30

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

7.50

21.65

8.20

21.55

Natural Gas US$/mcf at Henry Hub

3.60

10.80

4.15

9.45

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

3.65

9.35

4.65

8.25

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

8.35

11.50

9.10

10.15

Exchange rate: US$/Cdn$

0.85

0.99

0.83

0.99

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


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

Revenues		5 058		4 814		7 196		8 946	7 959	5 988	5 185	4 802
Net earnings (loss)		(51	)	(189	)	(215	)	815	829	708	1 042	627

Net earnings (loss) per common share
	Basic	(0.06	)	(0.20	)	(0.24	)	0.87	0.89	0.77	1.12	0.68
	Diluted	(0.06	)	(0.20	)	(0.24	)	0.86	0.87	0.75	1.10	0.66

Net loss for the second quarter of 2009 was $51 million, compared to net earnings of $829 million for the second quarter of 2008. Excluding unrealized foreign exchange gain on the company's U.S. dollar denominated long-term debt, mark-to-market accounting losses on commodity derivatives, and costs related to start-up or deferral of growth projects, second quarter 2009 earnings were $185 million ($0.20 per common share), compared to $920 million ($0.99 per common share) in the second quarter of 2008.

The decrease in earnings was primarily due to lower price realizations, as benchmark commodity prices were significantly weaker in the second quarter of 2009 compared to the same period in 2008, as well as higher operating expenses at oil sands associated with higher production. This was partially offset by increased production in our oil sands business segment, reduced natural gas royalty expense due to lower benchmark commodity prices, and increased refined product sales in our downstream business segment.

Cash flow used in operations in the second quarter of 2009 was $342 million, compared to cash flow from operations of $1.405 billion in the same period of 2008. The decrease was due primarily to the same factors that impacted earnings.

Net loss for the first six months of 2009 was $240 million, compared to net earnings of $1.537 billion for the same period in 2008. Excluding unrealized foreign exchange impacts on the company's U.S. dollar denominated long-term debt, mark-to-market accounting losses on commodity derivatives, and costs related to start-up or deferral of growth projects, earnings for the first six months of 2009 were $410 million, compared to $1.725 billion in the same period for 2008. Cash flow from operations for the first six months of 2009 was $137 million, compared to $2.566 billion in the first six months of 2008. The year-to-date decreases in earnings and cash flow from operations were primarily due to the same factors that impacted second quarter results.

Our effective tax rate for the first half of 2009 was 47%, compared to 30% in the first half of 2008. The higher effective tax rate in the first half of 2009 is primarily a result of foreign exchange adjustments and tax filing reconciliations. During the first six months of 2009, we recorded $204 million in current income tax expense compared to $214 million in the first six months of 2008 (see page 10 for a more detailed discussion).

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

This table explains some of the factors impacting net earnings on an after-tax basis. For comparability purposes, readers should rely on the reported net earnings presented in our unaudited interim consolidated financial statements and notes in accordance with Canadian GAAP.


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

Earnings before the following items:		185		920		410		1 725
	Mark-to-market accounting loss on commodity derivatives	(606	)	(99	)	(738	)	(116	)
	Costs related to deferral of growth projects	(28	)	—		(151	)	—
	Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	405		18		257		(57	)
	Project start-up costs	(7	)	(10	)	(18	)	(15	)

Net earnings as reported		(51	)	829		(240	)	1 537

Oil sands recorded a net loss of $307 million in the second quarter of 2009, compared with net earnings of $751 million in the second quarter of 2008. Excluding the impact of mark-to-market accounting losses on commodity derivatives, and costs related to start-up or deferral of growth projects, earnings for the second quarter of 2009 were $334 million, compared to $860 million in the second 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 discount to WTI for our sweet crude blends, partially offset by the weaker Canadian dollar and a smaller discount to WTI for our sour crude blends.

Purchases of crude oil and products were $164 million in the second quarter of 2009, compared to $114 million in the second quarter of 2008. The increase was primarily a result of purchases to optimize bitumen blending and sales. This increase was partially offset by the absence of any planned shutdowns, as the comparative quarter of 2008 saw higher purchases of diesel to meet customer commitments.

Operating expenses were $1.028 billion in the second quarter of 2009, compared to $640 million in the second quarter of 2008. The increase was due primarily to costs associated with higher production and sales. 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. These factors were partially offset by lower energy input costs.

We 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. Pretax safe mode costs of $40 million were incurred in the second quarter of 2009. Total pretax safe mode costs incurred in the first six months of 2009 were $215 million. Based on second quarter costs and expectations for the balance of the year, the outlook for 2009 total safe mode costs has been reduced to between $300 million and $400 million from the previously reported outlook of between $400 million and $500 million.

Depreciation, depletion and amortization (DD&A) expense was $197 million in the second quarter of 2009, compared to $132 million during the same period in 2008. The increase resulted from continued growth in the depreciable cost base for our oil sands facilities.

Alberta Crown royalty expense was $138 million in the second quarter of 2009, compared to $130 million in the second quarter of 2008. The higher expense resulted from increased production, as well as lower operating and capital allowed costs under the New Royalty Framework in 2009. These factors were partially offset by lower prices and the impact of price differentials for bitumen in 2009 compared to synthetic crude oil pricing for 2008. For a further discussion of Crown royalties, see page 8.

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

Cash flow used in operations was $401 million in the second quarter of 2009, compared to cash flow from operations of $1.174 billion in the second quarter of 2008. The decrease was due primarily to the same factors that impacted earnings.

The net loss for the first six months of 2009 was $417 million, compared to earnings of $1.446 billion in the first six months of 2008. Cash flow used in operations for the first six months of 2009 was $222 million, compared to cash flow from operations of $2.084 billion in the first six months of 2008. The year-to-date decreases in net earnings and cash flow from operations were due primarily to the same factors that impacted second quarter results.

Oil sands production was 301,000 barrels per day (bpd) in the second quarter of 2009, compared to 174,600 bpd during the second quarter of 2008. The increased production in the second quarter of 2009 was primarily due to improved upgrader reliability in the second quarter of 2009. In addition, in the comparative quarter of 2008 a planned maintenance shutdown of one of our upgraders and a regulatory cap on our Firebag in-situ operations impacted production.

Sales volumes during the second quarter of 2009 averaged 285,700 bpd, compared with 181,500 bpd during the second quarter of 2008. The increase was due primarily to increased production. Production volumes processed by Suncor for which a processing fee is received are not included in sales volume totals. The proportion of higher value diesel fuel and sweet crude products decreased to 44% of total sales volumes in the second quarter of 2009, compared to 49% in the second quarter of 2008.

The average price realization for oil sands crude products decreased to $63.93 per barrel in the second quarter of 2009, compared to $121.12 per barrel in the second quarter of 2008. This was primarily due to a significant decrease in the average benchmark WTI crude oil price of about 52%, a discount to WTI on our sweet crude blends and a change in sales mix which reflected a smaller portion of higher priced sweet products. These factors were partially offset by a smaller discount to WTI for our sour crude blends 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

During the second quarter of 2009, cash operating costs averaged $31.30 per barrel, compared to $50.85 per barrel during the second 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. Cash operating costs per barrel does not include costs related to deferral of growth projects. Refer to page 15 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

As previously announced, we deferred the company's growth projects in our revised 2009 capital budget. We do not anticipate any changes to our growth project plans until after the close of the proposed merger with Petro-Canada. At that time, all capital projects from both companies are expected to be reviewed 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.

During the second quarter of 2009, work continued on the Firebag sulphur plant and the Steepbank extraction plant. The sulphur plant is expected to support sulphur emissions reductions for existing and planned in-situ developments, and the extraction plant is expected to provide improved reliability and productivity for the company's oil sands assets. Both of these projects are scheduled for completion in the third quarter of 2009. The project cost for the Steepbank extraction plant is expected to exceed the previous cost estimate ($850 million +/-10%) with a final estimated cost of $980 million (+5%) as a result of labour shortages and the resulting productivity challenges, as well as premiums incurred to maintain the project schedule. For an update on our significant capital projects currently in progress see page 11.

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

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

The following table sets forth an estimation of royalties in the years 2009 through 2013 for three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios.




WTI Price/bbl (US$)	40	60	80

Natural gas (Alberta spot) Cdn$/mcf at AECO	6.50	8.00	9.50

Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	6.50	10.00	13.00

Differential of Maya at the US Gulf Coast less Western Canadian Select at Hardisty, Alberta US$	4.00	4.00	4.00

US$/Cdn$ exchange rate	0.75	0.85	0.95

Crown Royalty Expense (based on percentage of total oil sands revenue) %
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates) ⁽¹⁾	3-4	4-5	6-7
2010 to 2013 – Bitumen (new rates – with limits for mining only)	1	3-6	6-10

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

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

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

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

Our natural gas business recorded a net loss of $28 million in the second quarter of 2009, compared with net earnings of $52 million during the second quarter of 2008. The net loss was primarily due to reduced revenues resulting from lower benchmark commodity prices and decreased production. These factors were partially offset by a royalty recovery in the second quarter of 2009 compared to royalty expense in the same period 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. During the second quarter of 2009, we sold non-core assets for a pretax gain of $15 million. In the second quarter of 2008, we sold non-core assets for a pretax gain of $24 million.

Cash flow from operations for the second quarter of 2009 was $41 million, compared to $119 million in the second quarter of 2008. The decrease was primarily due to the same factors that affected net earnings, excluding the impact of the gain on sale of non-core assets.

The net loss for the first six months of 2009 was $38 million, compared to net earnings of $71 million in the first six months of 2008. Cash flow from operations for the first six months of 2009 decreased to $96 million from $201 million in the first six months of 2008. The year-to-date decreases in net earnings and cash flow from operations were primarily due to the same factors that impacted second quarter results.

Natural gas and liquids production in the second quarter of 2009 was 211 million cubic feet equivalent (mmcfe) per day, compared to 226 mmcfe per day in the second quarter of 2008. The lower production compared to the prior year was primarily due to natural reservoir declines and shut-in production in the Elmworth area. Our 2009 planned production of 210 mmcfe/day (+5%/-5%) offsets Suncor's projected purchases for internal consumption at our oil sands operations.

Realized natural gas prices in the second quarter of 2009 averaged $3.56 per thousand cubic feet (mcf), compared to an average of $9.62 per mcf in the second quarter of 2009, reflecting significantly lower benchmark prices.

Refining and marketing recorded 2009 second quarter net earnings of $72 million, compared to net earnings of $91 million in the second quarter of 2008. The decrease in net earnings was primarily due to lower diesel margins, as well as asset writedowns resulting from changes in the scope of certain projects. These factors were partially offset by an increase in refined product sales over the second quarter of 2008 (when production was negatively impacted by planned maintenance at our Sarnia refinery), an increase in gasoline margins and improved overall operational reliability.

Energy trading activities resulted in a net pretax loss of $41 million in the second quarter of 2009, compared to $13 million in the second quarter of 2008. This was due primarily to a decrease in earnings on our crude trading activities resulting from mark-to-market losses on financial crude trading activities.

Cash flow from operations was $192 million in the second quarter of 2009, compared to $210 million in the second quarter of 2008. Cash flow from operations decreased primarily due to the same factors affecting net earnings, excluding the asset writedowns.

Our refining and marketing business recorded net earnings of $222 million for the first six months of 2009 compared to $186 million during the first six months of 2008. Cash flow from operations for the first six months of 2008 was $447 million, compared to $400 million in the first six months of 2008. The year-to-date changes in net earnings and cash flow from operations were primarily due to increased refined product sales and higher production at our Sarnia refinery.

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

The observed performance of our Sarnia refinery in 2008, after completion of our diesel desulphurization and oil sands integration project in 2007, has enabled us to upwardly revise our nameplate capacity to 85,000 bpd from the previously disclosed 70,000 bpd. Effective January 1, 2009, refinery utilization has been calculated using the new capacity. The Commerce City refining capacity has also been increased to 93,000 bpd from 90,000 bpd effective January 1, 2009. During the second quarter of 2009, average daily crude input was 172,600 bpd (97% utilization) compared to 163,700 bpd (102% utilization) in the second quarter of 2008. The average daily crude input was lower in the second quarter of 2008 due to planned maintenance at the Sarnia refinery.

After-tax net corporate earnings were $212 million in the second quarter of 2009, compared to net expense of $65 million in the second quarter of 2008. The earnings were mainly due to a larger unrealized foreign exchange gain on our U.S. dollar denominated long-term debt, as the amount by which the Canadian dollar strengthened against the U.S. dollar was greater during the second quarter of 2009 compared to the second quarter of 2008. After-tax unrealized foreign exchange gains on U.S. dollar denominated long-term debt were $405 million in the second quarter of 2009 compared to gains of $18 million in the second quarter of 2008. This was partially offset by higher net interest expense in the second quarter of 2009, as the company expensed $99 million of interest costs that can no longer be capitalized while the growth projects are in safe mode.

Cash used in operations was $174 million in the second quarter of 2009, compared to $98 million in the second quarter of 2008. The change in cash used in operations was primarily due to the higher net interest expense.

Corporate had net expense of $7 million in the first six months of 2009, compared to net expense of $166 million in the same period of 2008. Cash used in operations was $184 million in the first half of 2009 compared to $119 million in the first half of 2008. The year-to-date changes in after-tax net corporate expense and cash used in operations were due to the same factors that impacted second quarter results.

We estimate we will have cash income taxes of approximately $350 million to $450 million 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 table on page 8, assuming there are no changes to the current income tax regime. Our outlook on cash income tax is a forward looking statement and users of this information are cautioned that actual cash income taxes may vary materially from our outlook.

Our capital resources consist primarily of cash flow from operations and available lines of credit. We believe we will have the capital resources to fund our 2009 capital spending program of $3 billion and to meet current working capital requirements through cash flow from operations and our committed credit facilities, assuming production of 300,000 bpd and a West Texas Intermediate (WTI) price of US$40/bbl. Our cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, downstream margins, operating expenses, taxes, royalties, and US$/Cdn$ exchange rates. If additional capital is required, we believe adequate additional financing will be available in the debt capital markets at commercial terms and rates.

Although benchmark oil prices have strengthened during the second quarter of 2009, we have maintained crude oil hedge contracts through the remainder of 2009 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 12.

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

We continue to closely monitor operational spending, including a freeze on discretionary salary increases, working with vendors to reduce contract rates, as well as implementation of a variety of other cost-cutting measures throughout the company.

During the second quarter of 2009, we renewed our $480 million committed credit facility, extending it one year to the second quarter of 2010 and increasing the total commitment to $855 million.

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 June 30, 2009, our net debt (short and long-term debt less cash and cash equivalents) was $9.046 billion, compared to $7.226 billion at December 31, 2008. The increase in debt levels was primarily a result of capital expenditures during the first six months of 2009. Undrawn lines of credit at June 30, 2009 were approximately $1.5 billion.

We are subject to financial and operating covenants related to our public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. We are in compliance with our financial covenant that requires consolidated debt to not be more than 65% of our total capitalization. At June 30, 2009, our consolidated debt to total capitalization was 40% (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, current portion of long-term debt and future income taxes, Suncor had an operating working capital deficiency of $446 million at the end of the second quarter of 2009, compared to a deficiency of $257 million at the end of the second quarter of 2008. The increase in the deficiency was due primarily to a reduction in inventories, partially offset by an increase in income taxes receivable relating to the timing of installment payments.

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

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. We do not anticipate any changes to our growth project plans until after the close of the proposed merger with Petro-Canada. For a summary of progress on the projects placed into safe mode, please see page 14 of our 2008 Annual Report.

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

Cost

% complete

Target

Project

Plan

Estimate
$ millions

⁽¹⁾

Estimate
% Accuracy

⁽¹⁾

Spent
to date

Overall
Engineering

Construction

completion
date

Firebag sulphur plant

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

404

+5/-1

380

100

Q3 2009

Steepbank extraction plant ⁽²⁾

New location and technologies aimed at improving operational performance

980

910

100

Q3 2009

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

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. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 17.

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.

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

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

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

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

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 110,000 barrels per day (bpd) of production at US$50.85 and options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 for the remainder of 2009.

For the full year 2010, we have crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel. This program replaced previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts in the first quarter 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. We have recently entered into foreign exchange forward contracts to fix the Canadian dollar value we will receive on future sales of crude oil. Amounts received or paid on settlement will be recorded as part of the related hedged sales transactions.

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

The net earnings impact associated with our commodity and treasury hedging activities in the second quarter of 2009 was a pretax loss of $732 million, compared to a pretax loss of $86 million in the second quarter of 2008. The net earnings impact in the first six months of 2009 was a pretax loss of $952 million, compared to a pretax loss of $99 million in the first six months of 2008.

A reconciliation of changes in accumulated other comprehensive income (AOCI) attributable to derivative hedging activities for the six month period ending June 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 year net changes arising from cash flow hedges, net of income taxes of $nil (2008 – $23)	—	(57	)
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $nil (2008 – $1)	2	3

AOCI attributable to derivative hedging activities, at June 30, net of income taxes of $5 (2008 – $18)	15	(41	)

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 pretax loss associated with our energy trading activities in the second quarter of 2009 was $41 million (2008 – $13 million). The net pretax earnings in the first six months of 2009 were $8 million (2008 – $15 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)		June 30 2009		December 31 2008

Derivative financial instruments accounted for as hedges
	Assets	26		24
	Liabilities	—		(13	)
Derivative financial instruments not accounted for as hedges
	Assets	195		635
	Liabilities	(946	)	(14	)

Net derivative financial instruments		(725	)	632

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

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

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 had been 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, any potential impacts on pending legislation 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 our 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 June 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 June 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 and six month periods ended June 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.

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

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

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.

The company's IFRS conversion project began in 2008. There have been no significant changes in the project from the first quarter of 2009, except for those items noted below. For further information on the IFRS conversion project, please see page 16 of our first quarter 2009 Report to Shareholders.

Based on the work to date, no significant IT issues have been identified. Workshops have commenced to discuss key business process and IT changes.

Discussions have been held with Internal Audit to integrate from an internal controls perspective.

Certain financial measures referred to in this MD&A, namely 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.

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 June 30, 2009 interim basis, please refer to page 36.

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of Suncor's June 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 June 30			Six months ended June 30
	2009		2008	2009	2008

Cash flow from (used in) operations ($ millions)	(342	)	1 405	137	2 566
Weighted number of shares outstanding – basic (millions of shares)	936.9		930.5	936.6	928.6
Cash flow from operations – basic ($ per share)	(0.37	)	1.51	0.15	2.76

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

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 June 30						Six months ended June 30
		2009			2008			2009			2008
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		1 028			640			1 937			1 357
	Less: Natural gas costs, inventory changes, stock-based compensation, and other	(216	)		(3	)		(213	)		(158	)
	Less: Safe mode costs	(40	)		—			(215	)		—
	Less: Non-monetary transactions	(16	)		(30	)		(42	)		(56	)
Accretion of asset retirement obligations		25			13			52			27
Taxes other than income taxes		30			17			59			33

Cash costs		811		29.65	637		40.10	1 578		30.15	1 203		31.30
Natural gas		45		1.65	139		8.75	120		2.30	250		6.50
Purchased bitumen (excluding other reported product purchases)		1		—	32		2.00	2		0.05	65		1.70

Cash operating costs		857		31.30	808		50.85	1 700		32.50	1 518		39.50
Project start-up costs		10		0.35	14		0.90	26		0.50	21		0.55

Total cash operating costs		867		31.65	822		51.75	1 726		33.00	1 539		40.05
Depreciation, depletion and amortization		197		7.20	132		8.30	380		7.25	261		6.80

Total operating costs		1 064		38.85	954		60.05	2 106		40.25	1 800		46.85

Production (thousands of barrels per day)		301.0			174.6			289.0			211.0


		Three months ended June 30						Six months ended June 30
		2009			2008			2009			2008
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		67			76			132			165
	Less: Natural gas costs	(24	)		(46	)		(54	)		(91	)
Taxes other than income taxes		6			2			11			4

Cash costs		49		11.15	32		10.10	89		10.80	78		12.35
Natural gas		24		5.25	46		14.55	54		6.50	91		14.40

Cash operating costs		73		16.40	78		24.65	143		17.30	169		26.75
In-situ (Firebag) start-up costs		6		1.50	5		1.65	19		2.35	6		0.95

Total cash operating costs		79		17.90	83		26.30	162		19.65	175		27.70
Depreciation, depletion and amortization		26		6.00	21		6.70	53		6.45	43		6.70

Total operating costs		105		23.90	104		33.00	215		26.10	218		34.40

Production (thousands of barrels per day)		48.3			34.7			45.4			34.7

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

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 of +5%/-10% based on our current expectations, estimates, projections and assumptions. Uncertainties in the estimating process and the impact of future events may cause actual results to differ, in some cases materially, from our estimates. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. For a description of assumptions and risk factors specifically related to the 2009 outlook, see page 3 of our second 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 (for example, the emissions reduction modifications at our Firebag in-situ development); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies 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; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive.

The forward-looking statements and information relating to the proposed transaction between Suncor and Petro-Canada are based on certain key expectations and assumptions made by us, including expectations and assumptions concerning: the accuracy of reserve and resource estimates; customer demand for the merged company's products; commodity prices and interest and foreign exchange rates; planned synergies, capital efficiencies and cost-savings; applicable royalty rates and tax laws; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; and the receipt, in a timely manner, of regulatory and other third party approvals in respect of the proposed merger. In addition, forward-looking statements and information concerning the anticipated completion of the proposed transaction and the anticipated timing for completion of the transaction are provided in reliance on certain assumptions that we believe are reasonable at this time, including; the timing of receipt of the necessary regulatory and other third party approvals; and the time necessary to satisfy the conditions to the closing of the transaction. These dates may change for a number of reasons, including the inability to secure necessary regulatory, court or other third party approvals in the time assumed or the need for additional time to satisfy the conditions to the completion of the transaction. As a result of the foregoing, readers should not place undue reliance on the forward-looking statements and information concerning these times. Although we believe that the expectations and assumptions on which such forward-looking statements and information are based are reasonable, undue reliance should not be placed on the forward-looking statements and information because we can give no assurance that they will prove to be correct.

Since forward-looking statements and information relating to the proposed transaction address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. There are risks also inherent in the nature of the proposed transaction, including: failure to realize anticipated synergies or cost savings; risks regarding the integration of the two entities; incorrect assessments of the values of the other entity; and failure to obtain any required regulatory and other third party approvals (or to do so in a timely manner). 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 the company's Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available upon request without charge from the company.

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


Outstanding Share Data (at June 30, 2009)

Common shares			937 130 633
Common share options – total			46 127 204
Common share options – exercisable			25 791 569


Three months ended June 30 ($ millions)	2009		2008

Corporate earnings (expense)	232		(42	)
Group eliminations	(20	)	(23	)

Total	212		(65	)


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

Purchased puts	55 000	60.00		2009
Fixed price	108 652	50.85		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 June 30 2009		As at December 31 2008

Property, plant and equipment, net	492		566
Other assets	(492	)	(566	)