EXHIBIT 99.2

Interim Management’s Discussion and Analysis for the first fiscal quarter ended
March 31, 2007

Management’s discussion and analysis

April 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 March 31, 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, 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. All such references are inactive textual references only.

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 March 31
(average for the period)	2007	2006
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	58.15	63.50
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	67.45	69.10
Light/heavy crude oil differential US$/barrel WTI Cushing less Lloyd Blend at Hardisty	16.95	29.00
Natural Gas US$/mcf at Henry Hub	6.95	9.05
Natural Gas (Alberta spot) Cdn$/mcf at AECO	7.45	9.25
New York Harbour 3-2-1 crack (1) US$/barrel	11.35	7.10
Exchange rate: Cdn$:US$	0.85	0.87

(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 March 31, 2007)
Common shares		460 218 676
Common share options – total		21 388 830
Common share options – exercisable (1)		9 636 762

(1) Options which have vested and are available for exercise.

Summary of Quarterly Results

	2007 quarter ended	2006 quarter ended				2005 quarter ended
($ millions, except per share data)	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30
Revenues	3 951	3 787	4 114	4 070	3 858	3 521	3 149	2 385
Net earnings	551	358	682	1 218	713	693	315	83
Net earnings attributable to common shareholders per share
Basic	1.20	0.78	1.48	2.65	1.56	1.52	0.69	0.18
Diluted	1.17	0.76	1.45	2.59	1.52	1.48	0.67	0.18

Analysis of Consolidated Statements of Earnings and Cash Flows

Net earnings for the first quarter of 2007 were $551 million, compared to $713 million for the first quarter of 2006 ($509 million after adjusting for unrealized foreign exchange gains and $205 million in insurance proceeds accrued in the first quarter of 2006 related to the January 2005 fire at our oil sands facility). Excluding the impact of net insurance proceeds accrued in 2006, the increase in comparable net earnings was primarily due to strong refining and retail margins in our downstream operations, lower Alberta Crown royalty expenses and lower effective federal and provincial income tax rates.

These positive factors were partially offset by lower oil sands production and higher operating expenses, both related to unplanned maintenance at the oil sands facility during the quarter. Lower earnings in our Natural Gas business as a result of lower natural gas prices reflecting lower benchmark commodity prices, also negatively impacted earnings in the first quarter of 2007.

Cash flow from operations in the first quarter of 2007 was $790 million, compared to $1,314 million in the same period of 2006. Cash flow from operations was lower due to the same factors that impacted net earnings, as well as an increase in cash income tax expenses in all of our operating business segments in the first quarter of 2007 compared to the first quarter of 2006 notwithstanding a decrease in our effective income tax rate.

Our effective tax rate for the first three months of 2007 was 30%, compared to 37% in the first three months of 2006. The first quarter 2007 effective tax rate is consistent with our expectations. The lower effective tax rate in 2007 was due to reductions in both the federal and provincial rates enacted in the second quarter of 2006. During 2007, we expect our Oil Sands and Natural Gas businesses will be partially cash taxable. During the first quarter we recorded $162 million in current income tax expense compared to a recovery of $1 million in the first quarter of 2006 (see page 7 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.

($ millions, after-tax)	Q1 2007	Q1 2006
Net earnings before the following items	539	522
Firebag in-situ start-up costs	—	(13	)
Oil Sands fire accrued insurance proceeds (1)	—	205
Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	12	(1	)
Net earnings as reported	551	713

(1) Accrued business interruption proceeds net of income taxes and Alberta Crown royalties.

Analysis of Segmented Earnings and Cash Flow

Oil Sands

Oil Sands recorded 2007 first quarter net earnings of $453 million, compared with $707 million in the first quarter of 2006 ($502 million excluding net insurance proceeds of $205 million). Net earnings were lower primarily as a result of lower oil sands production and sales volumes combined with higher operating expenses, both related to unplanned maintenance at the oil sands facility during the quarter.

These negative impacts were partially offset by:

· Lower Alberta Crown royalty expense as a result of lower production, higher operating and capital costs, and the absence of insurance proceeds subject to Crown royalties.

· Lower effective federal and Alberta provincial income taxes as a result of the reduction of federal and provincial rates in the second quarter of 2006. In addition, the absence of taxable insurance proceeds in 2007 also reduced our effective income tax rates.

Operating expenses before tax were $612 million in the first quarter of 2007 compared to $526 million in the first quarter of 2006. The increase in operating expenses was primarily due to unplanned maintenance in the first quarter of 2007. Operating expenses in the first quarter of 2007 also increased due to the inclusion of three months of costs associated with Firebag Stage 2; in 2006, Firebag Stage 2 was in commercial operations for only part of the first quarter. These factors were partly offset by lower sales volumes in the first quarter of 2007 compared to the first quarter of 2006.

Depreciation, depletion and amortization expense was $100 million in the first quarter of 2007 compared to $93 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 $157 million in the first quarter of 2007 compared to $285 million in the first quarter of 2006. The decrease was due mainly to the lower sales revenues during the first three months of 2007 compared to the same period in 2006, an increase in anticipated eligible expenditures for 2007, and the absence of insurance proceeds subject to Crown royalties. See page 7 for a discussion of Alberta Oil Sands Crown royalties.

Cash flow from operations was $578 million in the first quarter of 2007, compared to $1,209 million in the first 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 to cash taxes incurred during the first three months of 2007 that were not present in the first quarter of 2006.

Oil Sands production averaged 248,200 barrels per day (bpd). First quarter production was lower than full capacity due to unplanned maintenance. Comparative production during the first quarter of 2006 averaged 264,400 bpd. As a result of the production issues encountered during

the first quarter of 2007, we have revised our 2007 annual production outlook downward to 255,000 bpd to 265,000 bpd from 260,000 bpd to 270,000 bpd.

Sales volumes during the first quarter of 2007 averaged 254,500 bpd, compared with 275,300 bpd during the first quarter of 2006. The proportion of higher value diesel fuel and sweet crude products decreased to 53% of total sales volumes in the first quarter of 2007, compared to 56% in the first quarter of 2006, reflecting operational constraints.

The average price realization for Oil Sands crude products was relatively unchanged at $65.70 per barrel in the first quarter of 2007, compared to $65.75 per barrel in the first quarter of 2006. An 8% decrease in average benchmark WTI crude oil prices was offset by the narrowing of differentials on our sweet and sour crude blends as a result of production issues at both our facility and at other oil sands producers during the first quarter of 2007. As a result, per barrel prices for our oil sands synthetic crude oil averaged $2.44 below WTI, compared to our outlook expectations of $7.50 to $8.50 below WTI for 2007. We have not adjusted our full year outlook for sales realizations.

During the first quarter of 2007, cash operating costs averaged $26.30 per barrel, compared to $19.05 per barrel during the first quarter of 2006. The increase in cash operating costs per barrel is due to a combination of higher cash operating expenses, reflecting unplanned maintenance, being applied to a lower production volume. As a result, we have revised our full year outlook for 2007 cash operating costs per barrel upward to $23.50 to $24.50 from $21.50 to $22.50. 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 next major growth phase includes an expansion of existing upgrading facilities that targets an increase in production capacity to 350,000 bpd in 2008. Engineering on this portion of the project is substantially complete and construction is approximately 75% complete. The project remains on schedule and on budget. A targeted 50-day shutdown to Upgrader 2 to tie in new facilities related to the expansion is expected to begin on May 31. During the tie-in work, Upgrader 1 is expected to continue normal production.

Work underway also includes the expansion of Suncor’s Firebag in-situ operations, with construction targeted for completion in 2007. 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 65% complete at the end of the first quarter.

Suncor’s plans to increase production to 500,000 bpd to 550,000 bpd in 2010 to 2012, which were announced in 2001, involve a number of investments including increased 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 upgrader underway.

In February 2007 Suncor filed a public disclosure document outlining our intent to apply for permission to develop our proposed Voyageur South mining and extraction project. If approved, construction could commence as early as 2009.

While approval of final cost estimates for portions of planned growth from 2008 through 2012 are still pending, Suncor capital spending plans of $5.3 billion for 2007 includes spending of approximately $2.5 billion this year on various components of the 500,000 bpd to 550,000 bpd expansion phase.

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

Oil Sands Crown Royalties and Cash Income Taxes

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

In the first quarter of 2007, we recorded a pretax royalty estimate of $157 million ($110 million after tax) compared to $285 million ($182 million after tax) for the first quarter of 2006. We estimate 2007 annualized Crown royalties to be approximately $665 million ($465 million after tax) based on three months of actual results and the balance of the year estimated on 2007 forward crude pricing of US$63.14 per barrel as at March 31, 2007; current forecasts of production, capital and operating costs for the remainder of 2007; and a Cdn$/US$ exchange rate of $0.87. Accordingly, actual results may differ, and these differences may be material. Alberta Crown royalties payable in 2007 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates, the valuation of bitumen, and total capital and operating costs for each project.

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.

In 2007, we estimate we will incur cash taxes of approximately 70% to 100% of the expected 2007 provision for income tax expense. During the first quarter of 2007, Oil Sands recorded $143 million in current income expense reflecting this expectation. The increase in current income tax expense impacted cash flow from operations for all business segments, excluding our U.S. downstream operations presented in our Refining and Marketing segment.

We do not expect any significant cash tax in subsequent years until the next decade. In any particular year, our Oil Sands and Natural Gas operations may be subject to some cash income 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.

The forward-looking information in the preceding paragraphs and table under “Oil Sands Crown Royalties and Cash Income Taxes” 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.

As with the estimate of 2007 Alberta Crown royalties, 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.

The Government of Alberta has undertaken 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.

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 current accelerated capital cost allowance will continue to be available for assets acquired before 2011, and assets acquired before 2012 on projects where major construction commenced before March 19, 2007. We believe Suncor’s Voyageur expansion phase, targeted for completion in 2012, will fall under the current accelerated capital cost allowance provisions.

In light of proposed legislative changes, other uncertainties, and the potential for unanticipated events, we strongly caution 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

Natural Gas recorded 2007 first quarter net earnings of $4 million, compared with $40 million during the first quarter of 2006. The decrease in net earnings was primarily as a result of lower price realizations. In addition, higher lifting costs, depreciation, depletion and amortization expense as a result of increased finding and development costs as well as higher dry hole exploration expenses negatively impacted earnings in the first quarter of 2007 compared to the first quarter of 2006. These negative impacts were partially offset by lower royalty expenses.

Cash flow from operations for the first quarter of 2007 was $64 million compared to $100 million from the first quarter of 2006. The decrease is due to the same factors affecting net earnings, excluding depreciation, depletion and amortization expense and dry hole costs.

Realized natural gas prices in the first quarter of 2007 were $7.01 per thousand cubic feet (mcf) compared to $9.03 per mcf in the first quarter of 2006, reflecting lower benchmark commodity prices.

Natural gas and liquids production in the first quarter of 2007 was 209 million cubic feet equivalent (mmcfe) per day, compared to 215 mmcfe per day in the first 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 and refining operations.

During the first quarter 2007, Suncor acquired developed and undeveloped lands in British Columbia for future development for approximately $160 million.

Refining & Marketing

Consistent with the company’s organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream refining and marketing operations have been combined into a single business segment — Refining & 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 activities 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 & Marketing recorded 2007 first quarter net earnings of $99 million, compared to net earnings of $11 million in the first quarter of 2006. Net earnings were higher as a result of:

· Stronger refining and retail margins in our downstream operations due to tighter supply of refined products in both the Ontario and U.S. Rocky Mountain markets.

· Increased sales volumes at our Commerce City refinery in the first quarter of 2007. Comparative first quarter 2006 sales volumes were significantly reduced due to a planned maintenance shutdown.

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

Energy marketing and trading activities, including physical and financial trading activities, resulted in a pretax net loss of $2 million in the first quarter of 2007, compared to an $8 million pretax gain in the first quarter of 2006.

Cash flow from operations was $171 million in the first quarter of 2007, compared to $51 million in the first quarter of 2006. This increase reflects the impact of the same factors affecting net earnings excluding depreciation, depletion and amortization expense.

During the first quarter of 2007, refinery utilization was 97%, compared to 74% in the first quarter of 2006. The lower utilization rate in the first quarter of 2006 was due to the planned maintenance shutdown at our Commerce City refinery.

Work continues on our oil sands integration project at our Sarnia, Ontario refinery. Original cost estimates have been revised upward to $960 million from the previous estimate of $800 million due to labour shortages and material supply issues. Suncor plans to begin a shutdown

of the Sarnia 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. Portions of the refinery will continue production during the shutdown period.

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

Corporate

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

Corporate recorded net expenses of $5 million in the first quarter of 2007, compared to net expenses of $45 million during the first quarter of 2006. After-tax unrealized foreign exchange gains on U.S. dollar denominated long-term debt were $12 million in the first quarter of 2007 compared to a loss of $1 million in the first quarter of 2006.

Net expenses decreased mainly due to the following:

· a reduction in stock-based compensation expense reflecting a decline in our share price during the first quarter of 2007 compared to an increase in the same period in 2006.

· higher costs incurred during the first quarter of 2006 relating to the implementation of our new Enterprise Resource Planning system.

Cash used in operations was $23 million in the first quarter of 2007 compared to $46 million in the first quarter of 2006. Cash used in operations is lower primarily due to the earnings factors described above.

Breakdown of Net Corporate Expense

Three months ended March 31 ($ millions)	2007		2006
Corporate expenses	(3	)	(45	)
Group eliminations	(2	)	—
Total	(5	)	(45	)

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 $447 million at the end of the first quarter of 2007, compared to a surplus of $254 million at the end of the first quarter of 2006.

During the first three months of 2007, net debt increased to approximately $2.3 billion from $1.9 billion at December 31, 2006. The increase in net debt levels was primarily a result of capital spending on our growth program in the first quarter of 2007. In March 2007, Suncor issued $600 million of 5.39% Medium Term Notes under an outstanding $2 billion debt shelf prospectus. The proceeds were used to repay outstanding commercial paper borrowings.

At March 31, 2007 our undrawn lines of credit were approximately $1.8 billion. We believe we have the capital resources from our undrawn lines of credit, 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. 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)

Status (1)

Oil Sands

Coker unit

$2 100

$160

$1 750

Project is on schedule

and on budget

Millennium naphtha unit (2)

$650

$40

$125

Project is on schedule

and on budget

Steepbank extraction plant (3)

$880

$45

$110

Project is on schedule

and on budget.

Firebag cogeneration and expansion

$400

$25

$340

Cogeneration component

completed in Q1 2007.

Full project is on schedule

and on budget.

Refining and Marketing

Diesel desulphurization and

$960

$35

$835

Diesel desulphurization component

oil sands integration

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.

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

(3) The Steepbank extraction plant will replace and enhance originally constructed 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 cost figures included 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 by the Board of Directors for preparatory work related to project design for the third upgrader, including engineering, site preparation and fabrication of some major vessels.

Suncor’s Firebag Stage 3 project is expected to be submitted for final Board of Director’s approval in the third quarter of 2007. To date approximately $550 million has been approved for planning and scoping initiatives related to project design.

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.

The company has hedged a portion of its 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 March 31, 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 to a total of up to approximately 30% of our annual planned crude oil production if strategic opportunities are available.

We realized $2 million of hedging gains from our crude oil hedges in the first quarter of 2007 compared to no hedging gains for the comparable period in 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 March 31:

Fair Value of Hedging Derivative Financial Instruments

($ millions)	2007	2006
Revenue hedge swaps and collars	6	(22	)
Interest rate and cross-currency interest rate swaps	13	13
Specific cash flow hedges
of individual transactions	2	5
Total	21	(4	)

Energy Marketing and Trading Activities

The net pretax earnings (loss) for the three months ended March 31, were as follows:

Net Pretax Earnings (Loss)

($ millions)	2007		2006
Physical energy contracts trading activity	3		10
Financial energy contracts trading activity	(4	)	(1	)
General and administrative costs	(1	)	(1	)
Total	(2	)	8

The fair value of unsettled financial energy trading assets and liabilities at March 31, 2007 and December 31, 2006 were as follows:

Fair Value of Unsettled Financial

Energy Trading Assets and Liabilities

($ millions)	2007		2006
Energy trading assets	3		16
Energy trading liabilities	10		13
Net trading assets (liabilities)	(7	)	3

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 CO2 equivalent per year. Suncor’s oil sands operations and several of our natural gas facilities would be included in this legislation. The Act calls for intensity reductions at these facilities of 12% by July 1, 2007 from an average 2003 to 2005 baseline.

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 Canadian federal government is also considering greenhouse gas management legislation and regulation. At this time, no such legislation has been tabled and any potential impacts are unknown.

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 March 31, 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 March 31, 2007, there were no changes in our internal control over financial reporting that occurred during the three month period ended March 31, 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 are recognized in the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge each period, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income 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 Statement 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 also contains 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 cumulative 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.

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 March 31, 2007 interim basis, please refer to page 29 of the first 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 March 31, 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:

For the three months ended March 31		2007	2006
Cash flow from operations ($ millions)	A	790	1 314
Weighted number of shares outstanding (millions of shares)	B	460.1	458.2
Cash flow from operations (per share)	(A / B)	1.72	2.87

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 In-situ bitumen production reconcile to the schedules of segmented data when combined.

Oil Sands Operating Costs – Total Operations

		Quarter ended March 31
		2007			2006
(unaudited)		$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		612			526
Less: natural gas costs, stock-based compensation, and inventory changes		(116	)		(125	)
Less: non-monetary transactions		(32	)		(48)
Accretion of asset retirement obligations		10			7
Taxes other than income taxes		12			10
Cash costs		486		21.75	370		15.55
Natural gas		100		4.50	82		3.45
Imported bitumen (net of other reported product purchases)		1		0.05	1		0.05
Total cash operating	A	587		26.30	453		19.05
In-situ (Firebag) start-up costs	B	—		—	21		0.90
Total cash operating costs after start-up costs	A+B	587		26.30	474		19.95
Depreciation, depletion and amortization		100		4.45	93		3.90
Total operating costs		687		30.75	567		23.85
Production (thousands of barrels per day)		248.2			264.4

Oil Sands Operating Costs – In-situ Bitumen Production Only

	Quarter ended March 31
	2007			2006
(unaudited)	$millions		$/barrel	$millions		$/barrel
Operating, selling and general expenses	69			32
Less: natural gas costs and inventory changes	(35	)		(19	)
Taxes other than income taxes	1			1
Cash costs	35		11.05	14		5.70
Natural gas	35		11.05	19		7.70
Cash operating costs	70		22.10	33		13.40
In-situ (Firebag) start-up costs	—		—	21		8.50
Total cash operating costs after start-up costs	70		22.10	54		21.90
Depreciation, depletion and amortization	17		5.35	17		6.90
Total operating costs	87		27.45	71		28.80
Production (thousands of barrels per day)	35.3			27.4

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,” “proposed,” “target,” “objective,” “may,” “outlook,” “on our way,” “investigating,” “continue,” 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.