EXHIBIT 99.2

Interim Management’s Discussion and Analysis for the second fiscal quarter
ended June 30, 2007

004 Suncor Energy Inc.

2007 Second Quarter

Management’s discussion and analysis

July 26, 2007

This Management’s Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 15 for additional information.

This MD&A should be read in conjunction with our June 30, 2007 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 18 to 60 of our 2006 Annual Report and to our Annual Information Form (AIF), dated February 28, 2007. 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 58 of our 2006 Annual Report, and page 13 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.

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

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 and 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.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for significant capital projects that, in some cases, are still in the early stages of development. These costs are estimates only. The actual amounts may differ and these differences may be material. For a further discussion of our significant capital projects and the range of cost estimates associated with an “on-budget” project, see the “Significant Capital Project Update” on page 11.

Selected financial information

Industry Indicators	3 months ended June 30		6 months ended June 30
(average for the period)	2007	2006	2007	2006
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	65.05	70.70	61.60	67.10
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	71.65	78.30	69.55	73.70
Light/heavy crude oil differential US$/barrel WTI at Cushing less WCS at Hardisty	19.65	17.40	17.95	23.05
Natural Gas US$/mcf at Henry Hub	7.55	6.80	7.25	7.90
Natural Gas (Alberta spot) Cdn$/mcf at AECO	7.35	6.25	7.40	7.75
New York Harbour 3-2-1 crack (1) US$/barrel	22.90	14.65	17.15	10.90
Exchange rate: Cdn$:US$	0.92	0.90	0.89	0.88

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

Outstanding Share Data (as at June 30, 2007)
Common shares		461 237 159
Common share options – total		20 630 625
Common share options – exercisable		8 694 734

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2007 Second Quarter

Summary of Quarterly Results

	2007 quarter ended		2006 quarter ended				2005 quarter ended
($ millions, except per share data)	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30
Revenues	4 358	3 951	3 787	4 114	4 070	3 858	3 521	3 149
Net earnings	641	551	358	682	1 218	713	693	315
Net earnings attributable to common shareholders per share
Basic	1.39	1.20	0.78	1.48	2.65	1.56	1.52	0.69
Diluted	1.36	1.17	0.76	1.45	2.59	1.52	1.48	0.67

Analysis of Consolidated Statements of Earnings and Cash Flows

Net earnings for the second quarter of 2007 were $641 million, compared to $1.218 billion for the second quarter of 2006. Excluding the impact of income tax rate reductions, unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt and project start-up costs, net earnings for the second quarter of 2007 were $510 million, compared to $758 million in the second quarter of 2006.

The decrease in net earnings was primarily due to lower oil sands production and higher operating expenses, as well as lower income tax rate reductions compared to the second quarter of 2006. A shutdown of one of the company’s two oil sands upgraders impacted production volumes, and increased maintenance costs were the main reason for the increase in operating expenses. The shutdown, which began May 31 and ended July 20, reduced production rates to about 121,000 barrels per day (bpd). The shutdown was required to tie-in new facilities related to a planned expansion that is expected to increase production capacity to 350,000 bpd in the second half of 2008.

Lower Alberta Crown royalties and strong refinery margins, combined with improved refinery reliability and strong sales volumes, helped offset the decrease in net earnings.

Cash flow from operations in the second quarter of 2007 was $884 million, compared to $1.320 billion in the same period of 2006. Cash flow from operations was lower due partly to the same factors that impacted net earnings, as well as increased cash income tax expenses in the second quarter of 2007 compared to the second quarter of 2006.

Net earnings for the first six months of 2007 were $1.192 billion ($2.59 per common share), compared to $1.931 billion ($4.21 per common share) for the same period in 2006. Cash flow from operations for the first six months of 2007 was $1.674 billion, compared to $2.634 billion in the first six months of 2006. Excluding the impacts of income tax rate reductions, net insurance proceeds (relating to the January 2005 fire), the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt and the impact of project start-up costs, net earnings for the first half of 2007 were $1.053 billion compared to $1.281 billion in the same period for 2006.

Our effective tax rate for the first half of 2007 was 29%, compared to 34% in the first half of 2006. The lower effective tax rate in 2007 was due to a reduction in the federal rate enacted in the second quarter of 2007 and the fully phased-in resource tax changes that made Crown royalties fully deductible and eliminated the resource allowance. During

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006 Suncor Energy Inc.

2007 Second Quarter

2007, we expect our oil sands and natural gas businesses will become partially cash taxable. During the first half of 2007 we recorded $245 million in current income tax expense compared to a recovery of $9 million in the first half of 2006 (see page 8 for a more detailed discussion).

Net Earnings Components

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.

	3 months ended June 30				6 months ended June 30
($ millions, after-tax)	2007		2006		2007		2006
Net earnings before the following items:	510		758		1 053		1 281
Unrealized foreign exchange gains on
U.S. dollar denominated long-term debt	81		44		91		43
Impact of income tax rate reductions on opening
future income tax liabilities	67		419		67		419
Oil sands fire accrued insurance proceeds (1)	—		—		—		205
Project start-up costs	(17	)	(3	)	(19	)	(17	)
Net earnings as reported	641		1 218		1 192		1 931

(1) Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown royalties.

Analysis of Segmented Earnings and Cash Flow

Oil Sands

Our oil sands business recorded 2007 second quarter net earnings of $419 million, compared with $1.100 billion in the second quarter of 2006. Excluding the impact of income tax rate reductions on opening future income tax liabilities and project start-up costs, net earnings for the second quarter of 2007 were $370 million, compared to $673 million in the second quarter of 2006. Net earnings decreased primarily as a result of lower oil sands production and related sales volumes due to the shutdown of Upgrader 2. The shutdown, which was required to tie-in facilities related to our planned expansion, was completed on July 20.

This negative impact was partially offset by lower Alberta Crown royalty expense due mainly to lower sales volumes during the second quarter of 2007 (compared to the same period in 2006) and increased anticipated eligible capital expenditures throughout 2007.

Purchases of crude oil and products were $60 million in the second quarter of 2007, compared to $14 million in the same period in 2006. This increase was primarily the result of purchases of diesel fuel from third parties in order to satisfy customer commitments during the scheduled shutdown.

Operating expenses were $656 million in the second quarter of 2007 compared to $467 million in the second quarter of 2006. The increase in operating expenses was primarily due to maintenance expenditures in the second quarter of 2007.

Depreciation, depletion and amortization expense was $108 million in the second quarter of 2007 compared to $92 million during the same period in 2006. The increase resulted from continued growth in the depreciable cost base for our oil sands facilities.

Alberta Crown royalty expense was $99 million in the second quarter of 2007 compared to $278 million in the second quarter of 2006. The decrease was due mainly to lower sales volumes during the second quarter of 2007 compared to the same period in 2006, and an increase in anticipated eligible expenditures for 2007. See page 7 for a discussion of Alberta Oil Sands Crown royalties.

Project start-up costs for the second quarter of 2007 were $21 million compared to $3 million in the second quarter of 2006. This increase is due primarily to initial start-up costs related to expansion work to increase capacity to a targeted 350,000 bpd in the second half of 2008.

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2007 Second Quarter

Cash flow from operations was $576 million in the second quarter of 2007, compared to $1.116 billion in the second quarter of 2006. Excluding the impact of depreciation, depletion and amortization, the decrease was due to the same factors that impacted net earnings. In addition, cash flows were reduced by cash income taxes in the second quarter of 2007 that were absent in the second quarter of 2006.

Net earnings for the first six months of 2007 were $872 million, compared to $1.807 billion in the first six months of 2006.

Cash flow from operations for the first six months of 2007 decreased to $1.154 billion from $2.321 billion in the first six months of 2006. The year-to-date decreases in net earnings and cash flow from operations were due to the same factors that impacted second quarter net earnings and cash flow from operations, as outlined above, as well as the absence of net insurance proceeds (relating to the January 2005 fire) in the first six months of 2007.

Oil sands production averaged 202,300 bpd in the second quarter of 2007. Production during the second quarter of 2006 averaged 267,300 bpd. Production was lower due to a shutdown to Upgrader 2 that was required to tie-in new facilities related to our planned expansion of oil sands production capacity.

Sales volumes during the second quarter of 2007 averaged 208,300 bpd, compared with 265,300 bpd during the second quarter of 2006. The proportion of higher value diesel fuel and sweet crude products remained relatively unchanged at 58% of total sales volumes in the second quarter of 2007, compared to 59% in the second quarter of 2006, as operational constraints had no significant impact on product mix.

The average price realization for oil sands crude products decreased to $71.01 per barrel in the second quarter of 2007, compared to $75.34 per barrel in the second quarter of 2006. An 8% decrease in average benchmark WTI crude oil prices was partially offset by the narrowing of differentials on our sweet and sour crude blends as a result of tighter market supply conditions during the second quarter of 2007. Prices for our oil sands synthetic crude oil averaged $0.40 below WTI, compared to our original outlook expectations of $7.50 to $8.50 below WTI for 2007. As a result, we have adjusted our full year outlook for the price realization on our oil sands crude sales basket to $3.50 to $4.50 below WTI for 2007.

During the second quarter of 2007, cash operating costs averaged $32.70 per barrel, compared to $18.30 per barrel during the second quarter of 2006. The increase in cash operating costs per barrel was due to significantly lower production volumes and increased operating expenses. Refer to page 13 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Oil Sands Growth Update

Suncor’s growth strategy includes an expansion of existing upgrading facilities that targets an increase in production capacity to 350,000 bpd in the second half of 2008. Engineering is complete and construction is approximately 85% complete. The project continues to be on schedule and on budget.

Suncor’s Firebag in-situ operations are also undergoing expansion. The project, which is expected to increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35%, also includes addition of cogeneration facilities. The cogeneration component of the project began commissioning and start-up in February 2007. Construction of the expansion component of the project was approximately 95% complete at the end of the second quarter of 2007 and is expected to be fully complete in the third quarter of 2007.

Suncor’s plans to increase production capacity to 500,000 bpd to 550,000 bpd in 2010 to 2012 involve a number of investments including new bitumen production from mining and in-situ sources, additional facility infrastructure and a third oil sands upgrader. Plans are proceeding on schedule, with fabrication of major vessels for the planned third upgrader underway.

We are targeting capital spending of approximately $3.5 billion this year on various components of our oil sands expansion.

For an update on our significant growth projects currently in progress see page 11.

Oil Sands Crown Royalties

For a description of the Alberta Crown royalty regimes in effect for our oil sands operations, see page 29 of our 2006 Annual Report.

In the second quarter of 2007, we recorded a pretax royalty estimate of $99 million ($72 million after tax) compared to $278 million ($184 million after tax) for the second quarter of 2006.

We estimate 2007 annualized oil sands Crown royalties to be approximately $590 million ($430 million after tax) compared to actual 2006 oil sands Crown royalties of $911 million ($619 million after tax). This estimate is based on six months of actual results and the balance of the year estimated on 2007 forward crude pricing of US$71.08/bbl

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008 Suncor Energy Inc.

2007 Second Quarter

as at June 30, 2007; current forecasts of production, capital and operating costs for the remainder of 2007; and a Cdn$/US$ exchange rate of $0.94. Accordingly, actual results could differ and these differences may be material.

The following table sets forth our estimates of royalties in the years 2008 through 2012, and certain assumptions on which we have based our estimates.

Anticipated Royalty Expense Based on Certain Assumptions

For the period from 2008-2012
WTI Price/bbl (US$)	40	50	60
Natural gas price per mcf at Henry Hub (US$)	6.75	8.25	10.00
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast (US$)	9.60	12.60	15.10
Cdn$/US$ exchange rate	0.80	0.85	0.90
Crown Royalty Expense (based on percentage of total Oil Sands revenue) (%)
2008	8	10	12
2009-2012 (1)	4-5	5-7	6-8

(1) During 2006, we exercised our option to transition our base operations in 2009 to the generic bitumen-based royalty regime.

The Government of Alberta is undertaking a review of Crown royalties and other revenues paid to government by industry. This review is scheduled for completion in late 2007. For a more complete discussion, please see page 29 of our 2006 Annual Report.

Cash Income Taxes

In 2007, we estimate we will incur cash taxes of approximately 70% to 100% of the expected 2007 provision for income tax expense. We do not anticipate any significant cash tax in subsequent years until the next decade. In any year we may be subject to cash tax due to sensitivity to crude oil and natural gas commodity price volatility, and the timing of recognition of capital expenditures for income tax purposes.

During the second quarter of 2007 oil sands recorded $13 million in current income tax expense, compared to nil in the comparative quarter in 2006.

The 2007 federal budget proposes to phase out the accelerated capital cost allowance that was originally intended to offset some of the risk associated with the large capital investment required to bring oil sands projects to production. The accelerated capital cost allowance will continue to be available for assets acquired before 2012 on projects where major construction commenced before March 19, 2007. We believe Suncor’s Voyageur expansion, targeted for completion in 2012, will fall under the current accelerated capital cost allowance provisions. If not, the accelerated capital cost allowance will be gradually phased out between 2011 and 2015.

Uncertainties and Sensitivities

The forward-looking information in the preceding “Oil Sands Crown Royalties” and “Cash Income Taxes” sections incorporates operating and capital cost assumptions included in our current budget and long-range plan, and is not an estimate, forecast or prediction of actual events or circumstances.

Anticipated royalty and cash taxes are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project. In addition, all aspects of the current Alberta Oil Sands Crown royalty regime (including royalty rates, the royalty base and the value of bitumen for royalty purposes), and income tax legislation (including taxation rates), are subject to alteration by the government.

In light of proposed legislative changes, other uncertainties, and the potential for unanticipated events, we strongly caution that it is impossible to accurately predict even a range of annualized royalty expense as a percentage of revenues or approximate cash tax, or the impact these royalties and cash taxes may have on our financial results. Differences may be material.

Natural Gas

Our natural gas segment recorded a 2007 second quarter net loss of $4 million, compared with $60 million of net earnings during the second quarter of 2006. Excluding the impact of income tax rate reductions on opening future income tax liabilities, the net loss for the second quarter of 2007 was $10 million, compared to net earnings of $7 million in the second quarter of 2006. The decrease

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Suncor Energy Inc. 009

2007 Second Quarter

in net earnings was primarily the result of higher royalty expense; higher dry hole exploration costs; higher lifting costs; and higher depreciation, depletion and amortization expense as a result of increased finding and development costs. These factors were partially offset by higher price realizations and lower seismic expenditures in the second quarter of 2007 compared to the second quarter of 2006.

Cash flow from operations for the second quarter of 2007 was $70 million compared to $66 million from the second quarter of 2006. The increase is primarily due to the same factors affecting net earnings, excluding depreciation, depletion and amortization expenses and dry hole exploration costs, and the impact of the revaluation of future income tax liabilities in the second quarter of 2006.

Year-to-date net earnings were nil, compared to $100 million in the first six months of 2006. The decrease in earnings is due mainly to a larger revaluation of opening future tax liabilities in 2006 compared with 2007 as a result of income tax rate reductions. In addition, lower price realizations, higher exploration dry hole expenses, higher lifting costs, higher depreciation, depletion and amortization expenses, and lower production volumes contributed to the decrease in net earnings. Cash flow from operations for the first six months of the year was $134 million, compared to $165 million reported in the same period in 2006. The year-to-date decreases in cash flow from operations were primarily due to lower price realizations, lower production volumes, and higher lifting costs.

Natural gas and liquids production in the second quarter of 2007 was 209 million cubic feet equivalent (mmcfe) per day, compared to 211 mmcfe per day in the second quarter of 2006. Our 2007 production outlook targets an average of 215 to 220 mmcfe per day for the year, offsetting Suncor’s projected purchases for internal consumption at our oil sands operations.

Realized natural gas prices in the second quarter of 2007 were $6.85 per thousand cubic feet (mcf) compared to $6.38 per mcf in the second quarter of 2006, reflecting higher benchmark commodity prices.

Refining and Marketing

Consistent with the company’s organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment — refining and marketing. Comparative figures have been reclassified to reflect the combination of the previously disclosed Energy Marketing & Refining — Canada (EM&R) and Refining & Marketing — U.S.A. (R&M) segments. There was no impact to previously reported net earnings as a result of the combination. The results of company-wide energy marketing and trading will continue to be included in this segment. The financial results relating to the sales of oil sands and natural gas production will continue to be reported in their respective business segments.

Refining and marketing recorded 2007 second quarter net earnings of $206 million, compared to net earnings of $116 million in the second quarter of 2006. Net earnings were higher primarily as a result of strong refining margins due to tighter supply of refined products in both the Ontario and U.S. Rocky Mountain markets and increased sales volumes in the second quarter of 2007.

These positive impacts were partially offset by increased maintenance expense and depreciation, depletion and amortization costs associated with the completion of major capital projects during 2006.

Energy marketing and trading activities, including physical trading activities, resulted in a net pretax gain of $18 million in the second quarter of 2007, compared to a $6 million net pretax gain in the second quarter of 2006.

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010 Suncor Energy Inc.

2007 Second Quarter

Cash flow from operations was $292 million in the second quarter of 2007, compared to $184 million in the second quarter of 2006. This increase reflects the impact of the same factors affecting net earnings excluding depreciation, depletion and amortization costs.

During the second quarter of 2007, refinery crude oil utilization was 108%, compared to 96% in the second quarter of 2006. The higher utilization rate in the second quarter of 2007 was largely due to improved reliability at our Commerce City refinery.

Our refining & marketing business recorded net earnings of $305 million for the first half of 2007 compared to $127 million during the first half of 2006. This increase reflects strong refining margins resulting from tight supply of refined products as well as increased sales volumes in the period compared to the first six months of 2006 when operational issues lowered refinery utilizations.

Cash flow from operations for the first six months of 2007 was $463 million, compared to $237 million in the first six months of 2006. The increase in cash flows was primarily due to the same factors that affected net earnings.

Work continues on our oil sands integration project at our Sarnia, Ontario refinery. Suncor plans to begin a shutdown of the refinery in the third quarter of 2007 (with completion scheduled in the fourth quarter of 2007) to tie-in modified facilities that are expected to enable the facility to process up to 40,000 bpd of oil sands sour crude. A planned maintenance shutdown at the Commerce City refinery is scheduled for the fourth quarter of 2007 and is targeted to take approximately four weeks. Portions of these refineries are expected to continue production during the shutdown periods.

For an update on our significant growth projects currently in progress see page 11.

Corporate

During the first quarter of 2007, we began allocating stock-based compensation expense from the corporate segment to each of the reportable business segments. Comparative figures have been reclassified to reflect this change in presentation. There was no impact to consolidated net earnings as a result of the allocation.

Corporate recorded $20 million net earnings in the second quarter of 2007, compared to a net loss of $58 million during the second quarter of 2006. Excluding the impact of income tax rate revaluations on opening future income tax liabilities, the net earnings for the second quarter of 2007 were $27 million, compared to net earnings of $10 million in the second quarter of 2006. Net expenses decreased mainly due to the larger foreign exchange gains on our U.S. dollar denominated long-term debt as a result of the continued strengthening of the Canadian dollar. There were also costs incurred during the second quarter of 2006 relating to the implementation of our new Enterprise Resource Planning system.

After-tax unrealized foreign exchange gains on U.S. dollar denominated long-term debt were $81 million in the second quarter of 2007 compared to a gain of $44 million in the second quarter of 2006.

Cash used in operations was $54 million in the second quarter of 2007 compared to $46 million in the second quarter of 2006. The increase in cash used in operations is mainly due to increased operating expenses.

Corporate had net earnings of $15 million in the first six months of 2007, compared to a net loss of $103 million in the same period of 2006. Expenses decreased primarily due to the same factors that affected net expenses in the second quarter. Year-to-date 2007 after-tax unrealized foreign exchange gains on our U.S. dollar denominated debt were $91 million, compared to a $43 million gain in 2006.

Cash used in operations was $77 million in the first half of 2007 compared to $89 million in the first half of 2006. The decreased use of cash in 2007 was due primarily to the absence of system implementation costs, partially offset by an increase in operating expenses.

Breakdown of Net Corporate Expense

3 months ended June 30 ($ millions)	2007		2006
Corporate earnings (expenses)	22		(55	)
Group eliminations	(2	)	(3	)
Total	20		(58	)

Analysis of Financial Condition and Liquidity

Excluding cash and cash equivalents, short-term debt and future income taxes, Suncor had an operating working capital deficiency of $895 million at the end of the second quarter of 2007, compared to a surplus of $111 million at the end of the second quarter of 2006. This change in working capital is due primarily to an increase in our accounts payable and accrued liabilities.

During the first six months of 2007, net debt increased to $2.2 billion from $1.8 billion December 31, 2006. The increase in net debt levels was primarily a result of capital spending on our growth program in the first half of 2007. In March, Suncor issued $600 million of 5.39% Medium Term Notes under an outstanding $2.0 billion debt shelf prospectus, and in June, issued US$750 million of 6.50% Notes under an outstanding US$2.0 billion debt shelf prospectus. The proceeds of both issuances were used for general corporate purposes, including repayment of short term borrowings, supporting Suncor’s ongoing capital spending program and for working capital requirements.

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Suncor Energy Inc. 011

2007 Second Quarter

At June 30, 2007 our undrawn credit facilities were approximately $2.0 billion. Outstanding debt shelf prospectuses filed in 2007 in Canada and the U.S. enable the company to issue, respectively, up to $1.4 billion in debt in Canada and US$1.25 billion in debt in the U.S. We believe we have the capital resources from our undrawn credit facilities, cash flow from operations, and access to debt capital markets to fund the remainder of our 2007 capital spending program and to meet our current working capital requirements. If additional capital is required, we believe adequate additional financing will continue to be available at market terms and rates. As reported in our 2006 Annual Report, we anticipate capital spending of approximately $5.3 billion for 2007.

Significant Capital Project Update

A summary of the progress on our significant projects under construction is provided below. All projects listed below have received Board of Directors approval.

		Spent 2007	Total spent
	Cost Estimate (1)	Year-to-date	to date
Description	($ millions)	($ millions)	($ millions)	Status (1)
Oil Sands
Coker unit	$2 100	$340	$1 930	Project is on schedule
				and on budget.
Millennium naphtha unit (2)	$650	$105	$190	Project is on schedule
				and on budget.
Steepbank extraction plant (3)	$880	$115	$180	Project is on schedule
				and on budget.
Firebag cogeneration and expansion	$400	$50	$365	Project is on schedule
				and on budget.
Refining and Marketing
Diesel desulphurization and oil sands integration	$960	$60	$860	Diesel desulphurization component
				complete. Oil sands integration component is scheduled for completion in Q4 2007. (4)

(1) Estimating and budgeting for major capital projects is a process that involves uncertainties and that evolves in stages, each with progressively more refined data and a correspondingly narrower range of uncertainty. At very early stages, when broad engineering design specifications are developed, the level of uncertainty can result in price ranges with -30%/+50% (or similar) levels of uncertainty. As project engineering progresses, vendor bids are studied, goods and materials ordered and we move closer to the build stage, the level of uncertainty narrows. Generally, when projects receive final approval from our Board of Directors, our cost estimates have a range of uncertainty that has narrowed to the -10%/+10% or similar range. These ranges establish an expected high and low capital cost estimate for a project. When we say that a project is “on budget”, we mean that we still expect the final project capital cost to fall within the current range of uncertainty for the project. Even at this stage, the uncertainties in the estimating process and the impact of future events, can and will cause actual results to differ, in some cases materially, from our estimates. Cost estimates do not include commissioning and start-up expenses.

(2) The Millennium naphtha unit project is expected to enhance the product mix of our oil sands production.

(3) The Steepbank extraction plant is intended to replace and enhance existing base plant extraction facilities.

(4) See page 9 for discussion.

The addition of a third upgrader has not received final approval by Suncor’s Board of Directors. Suncor has not yet announced a firm capital cost estimate for this project as the cost estimates, together with the final configuration of the project, are still under development. However, preliminary figures including those in Suncor’s Voyageur regulatory approval application are under upward pressure. Initial engineering is expected in late 2007, at which time final approval to proceed with the project will be considered by Suncor’s Board of Directors. Subject to final Board approval, the project will be included in the above table at that time.

To date approximately $900 million has been approved for preparatory work related to project design for the third upgrader, including engineering, site preparation and fabrication of some major vessels.

To date approximately $1.4 billion capital spending has been approved by the Board of Directors for future Firebag in-situ growth expansion projects. Our Firebag Stage 3 project is expected to be submitted for final Board of Directors approval in the fourth quarter of 2007. Spending for Firebag Stage 3 will include infrastructure and related ancillary costs expected to benefit future planned Firebag in-situ projects.

Inquiries John Rogers (403) 269-8670

012 Suncor Energy Inc.

2007 Second Quarter

Derivative Financial Instruments

Effective January 1, 2007, new accounting standards were implemented relating to financial instruments. For a more detailed discussion, see Change in Accounting Policies on page 13. These changes did not significantly impact earnings as a result of the adoption.

We have hedged a portion of our forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar West Texas Intermediate (WTI) commodity price risk for 2007 and 2008. At June 30, 2007, costless collar crude oil hedges totaling 60,000 bpd of production were outstanding for the remainder of 2007 and 10,000 bpd for 2008. Prices for these barrels are fixed within a range from an average of US$51.64/bbl up to an average of US$101.06/bbl.

We intend to consider additional costless collars of up to approximately 30% of our annual planned crude oil production if strategic opportunities are available.

We had no hedging gains or losses from our crude oil hedges in the second quarter of 2007, and $2 million of hedging gains from our crude oil hedges in the first six months of 2007. There were no hedging gains in the first six months of 2006.

The fair value of strategic derivative hedging instruments is the estimated amount, based on brokers’ quotes and/or internal valuation models, the company would receive (pay) to terminate the contracts. In addition to our strategic hedging program, we also use derivative instruments to hedge risks specific to individual transactions. Such amounts, which also represent the unrecognized and unrecorded gain (loss), on the contracts, were as follows at June 30:

Fair Value of Hedging Derivative Financial Instruments

($ millions)	2007	2006
Revenue hedge swaps and collars	6	(48	)
Interest rate and cross-currency interest rate swaps	5	9
Specific cash flow hedges of individual transactions	2	8
Total	13	(31	)

Energy Marketing and Trading Activities

The net pretax earnings (loss) for the three months ended June 30, were as follows:

Net Pretax Earnings (Loss)

($ millions)	2007		2006
Physical energy contracts trading activity	19		6
Financial energy contracts trading activity	(1	)	—
General and administrative costs	—		—
Total	18		6

The fair value of unsettled (unrealized) financial energy trading assets and liabilities at June 30, 2007 and December 31, 2006 are as follows:

Fair Value of Unsettled (Unrealized) Financial Energy Trading Assets and Liabilities

($ millions)	2007		2006
Energy trading assets	1		21
Energy trading liabilities	11		13
Net trading assets (liabilities)	(10	)	8

Environmental Regulation and Risk

On March 8, 2007 the Alberta government introduced the Climate Change and Emissions Management Amendment Act, which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year. Suncor’s oil sands operations are subject to this legislation. The act calls for an intensity reduction of 12% from an average 2003 to 2005 baseline, by July 1, 2007.

To comply with this new legislation, Suncor must, by the end of 2007, determine and file baseline emission data with regulators. In March 2008, compliance with the legislation will commence. Mitigation options available to Suncor include internal emission reductions, utilizing offset projects or contributing to a climate change emission management fund.

The actual costs to Suncor will be dependent on a variety of factors that are not yet certain, including baseline calculation, facilities definition and potential offset credits.

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

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc. 013

2007 Second Quarter

While there remains uncertainty around the outcome and impacts of climate change regulation, we continue to actively manage our emissions and to advance opportunities such as carbon capture and sequestration and renewable energy development.

Control Environment

Based on their evaluation as of June 30, 2007, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13(a) — 15(e) and 15(d) — 15(e) under the United States Securities and Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, other than as described below, as of June 30, 2007, there were no changes in our internal control over financial reporting that occurred during the three month period ended June 30, 2007 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.

Change in Accounting Policies

On January 1, 2007 the company adopted CICA Handbook Section 3855 “Financial Instruments, Recognition and Measurement”, Section 1530 “Comprehensive Income” and Section 3865 “Hedging”. These sections establish the accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. The comparative interim consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

Transaction costs and the related cash flow impacts are included in the fair value assessments of each financial asset and financial liability instrument.

Generally, all derivatives, whether designated in hedging relationships or not, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. 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 each period are recognized in the Consolidated Statements of Earnings. 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 each period and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in the Consolidated Statements of Earnings immediately for both fair value and cash flow hedges.

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same Consolidated Statements of Earnings caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

In addition to containing the effective portions of the gains/losses on our cash flow hedges, the accumulated other comprehensive income account will also contain the cumulative foreign currency translation adjustment of our foreign operations.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments were recorded to the balance sheet:

Financial assets		$42 million
Financial liabilities		$29 million
Retained earnings		$ 5 million
Accumulated other comprehensive loss		$63 million

The comparative interim consolidated financial statements have not been restated, except for presentation of the foreign currency translation adjustment of $71 million.

Non-GAAP Financial Measures

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.

Inquiries John Rogers (403) 269-8670

014 Suncor Energy Inc.

2007 Second Quarter

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, 2007 interim basis, please refer to page 32 of the second quarter 2007 Report to Shareholders.

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, 2007 unaudited interim consolidated financial statements.

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

			3 months ended June 30		6 months ended June 30
			2007	2006	2007	2006
Cash flow from operations ($ millions)	A		884	1 320	1 674	2 634
Weighted-average number of shares outstanding (millions of shares)	B		460.7	459.0	460.4	458.6
Cash flow from operations ($ per share)	(A/B	)	1.92	2.88	3.64	5.74

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. Amounts included in the tables below for base operations and Firebag in-situ reconcile to the schedules of segmented data when combined.

Oil Sands Operating Costs — Total Operations

		3 months ended June 30						6 months ended June 30
		2007			2006			2007			2006
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		656			467			1 268			993
Less: natural gas costs, inventory changes and stock-based compensation		(124	)		(71	)		(240	)		(196	)
Less: non-monetary transactions		(31	)		(31	)		(63	)		(79	)
Accretion of asset retirement obligations		10			7			20			14
Taxes other than income taxes		12			9			24			19
Cash costs		523		28.40	381		15.65	1 009		24.75	751		15.60
Natural gas		77		4.20	62		2.55	177		4.35	144		3.00
Imported bitumen (net of other reported product purchases)		2		0.10	2		0.10	3		0.10	3		0.05
Total cash operating costs	A	602		32.70	445		18.30	1 189		29.20	898		18.65
Project start-up costs	B	21		1.15	3		0.10	23		0.55	24		0.50
Total cash operating costs after start-up costs	A+B	623		33.85	448		18.40	1 212		29.75	922		19.15
Depreciation, depletion and amortization		108		5.85	92		3.80	208		5.10	185		3.85
Total operating costs		731		39.70	540		22.20	1 420		34.85	1 107		23.00
Production (thousands of barrels per day)		202.3			267.3			225.1			266.0

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc. 015

2007 Second Quarter

Oil Sands Operating Costs – In-situ Bitumen Production Only

	3 months ended June 30						6 months ended June 30
	2007			2006			2007			2006
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	68			52			137			84
Less: natural gas costs and inventory changes	(35	)		(26	)		(70	)		(45	)
Taxes other than income taxes	2			1			3			2
Cash costs	35		10.60	27		8.50	70		10.80	41		7.25
Natural gas	35		10.60	26		8.15	70		10.80	45		7.95
Cash operating costs	70		21.20	53		16.65	140		21.60	86		15.20
In-situ (Firebag) start-up costs	—		—	—		—	—		—	21		3.70
Total cash operating costs	70		21.20	53		16.65	140		21.60	107		18.90
Depreciation, depletion and amortization	19		5.75	12		3.75	36		5.55	29		5.10
Total operating costs	89		26.95	65		20.40	176		27.15	136		24.00
Production (thousands of barrels per day)	36.2			35.0			35.8			31.3

Legal notice – forward-looking information

This management’s discussion and analysis contains certain forward-looking statements 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 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,” “goal,” “proposes,” “target,” “objective,” “may,” “outlook,” “looking forward,” “investigating,” “continue,” “strategy,” 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.

The risks, uncertainties and other factors that could influence actual results include but are not limited to changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; commodity prices 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 (for example the Firebag in-situ development and Voyageur) 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; 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; 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 current review of the Crown Royalty regime, and the Government of Canada’s current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as 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. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

Inquiries John Rogers (403) 269-8670