EX-99.2 3 a2184917zex-99_2.htm EXHIBIT 99.2
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Exhibit 99.2

Interim Management's Discussion and Analysis for the first fiscal quarter ended March 31, 2008

Management's Discussion and Analysis
April 23, 2008

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 16 for additional information.

This MD&A should be read in conjunction with our March 31, 2008 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 10 to 48 of our 2007 Annual Report and to our Annual Information Form (AIF) dated February 27, 2008. 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 46 of our 2007 Annual Report, and page 14 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 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 preliminary estimates only. The actual amounts are expected to differ and these differences may be material. For a further discussion of our significant capital projects, see the Significant Capital Project Update on page 10.

Selected Financial Information

Industry Indicators	Three months ended March 31
(average for the period)	2008	2007

West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	97.90	58.15
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	98.25	67.45
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty	21.55	16.25
Natural Gas US$/mcf at Henry Hub	8.10	6.95
Natural Gas (Alberta spot) Cdn$/mcf at AECO	7.15	7.45
New York Harbour 3-2-1 crack ⁽¹⁾ US$/barrel	8.75	11.35
Exchange rate: US$/Cdn$	1.00	0.85

(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 (at March 31, 2008)

Common shares		463 502 992
Common share options – total		27 886 707
Common share options – exercisable		7 972 905

Suncor Energy Inc.
004 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Summary of Quarterly Results

		2008 Three months ended	2007 Three months ended				2006 Three months ended
($ millions, except per share)		Mar 31	Dec 31	Sept 30	June 30	Mar 31	Dec 31	Sept 30	June 30

Revenues		5 988	4 958	4 666	4 358	3 951	3 787	4 114	4 070
Net earnings		708	1 042	627	738	576	334	669	1 241

Net earnings attributable to common shareholders per share
	Basic	1.53	2.25	1.36	1.60	1.25	0.73	1.46	2.70
	Diluted	1.50	2.20	1.33	1.57	1.22	0.71	1.42	2.63

Analysis of Consolidated Statements
of Earnings and Cash Flows

Net earnings for the first quarter of 2008 were $708 million, compared to $576 million for the first quarter of 2007. Excluding unrealized foreign exchange impacts on the company's U.S. dollar denominated long-term debt and project start-up costs, earnings for the first quarter of 2008 were $788 million, compared to $567 million in the first quarter of 2007.

The increase in earnings was primarily due to higher price realizations on our oil sands products, as benchmark crude prices continued to rise. This was partially offset by increased operating expenses in our oil sands business primarily due to higher maintenance costs, employee expenses, contract mining and energy input costs and increased oil sands royalties, as well as reduced margins in the refining and marketing business.

Cash flow from operations in the first quarter of 2008 was $1.161 billion, compared to $825 million in the same period of 2007. The increase was due primarily to the same factors that impacted net earnings, excluding the impact of unrealized foreign exchange losses on our U.S. dollar denominated long-term debt.

Our effective tax rate for the first quarter of 2008 was unchanged from the first quarter of 2007 at 30%. During the first three months of 2008, we recorded $156 million in current income tax expense compared to $162 million in the first three months of 2007 (see page 9 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.

Three months ended March 31
($ millions, after-tax)		2008		2007

Earnings before the following items:		788		567
	Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	(75	)	11
	Project start-up costs	(5	)	(2	)

Net earnings as reported		708		576

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 005

Analysis of Segmented Earnings and Cash Flows

Oil Sands

Oil sands recorded 2008 first quarter net earnings of $695 million, compared with $468 million in the first quarter of 2007. Excluding the impact of project start-up costs, earnings for the first quarter of 2008 were $700 million, compared to $469 million in the first quarter of 2007. Earnings increased primarily as a result of higher average price realizations for oil sands crude products, partially offset by an increase in operating expenses and higher royalty expenses.

The price increase reflects higher benchmark WTI crude oil prices and an increased premium to WTI for our sweet crude blends, partially offset by the stronger Canadian dollar and a larger discount to WTI for our sour crude blends.

Purchases of crude oil and products were $47 million in the first quarter of 2008, compared to $9 million in the first quarter of 2007. The increase was primarily a result of third-party bitumen purchases to offset reduced production from our in-situ operations as we work to meet regulatory requirements.

Operating expenses before tax were $717 million in the first quarter of 2008, compared to $590 million in the first quarter of 2007. The increase in operating expenses in the first quarter of 2008 was primarily due to higher maintenance expenses as part of our efforts to improve reliability, increased employee costs resulting from higher overall salaries and an increased number of employees, and higher contract mining and energy input costs.

Depreciation, depletion and amortization (DD&A) expense was $129 million in the first quarter of 2008, compared to $100 million during the same period in 2007. The increase resulted from continued growth in the depreciable cost base for our oil sands facilities.

Alberta Crown royalty expense was $282 million in the first quarter of 2008, compared to $157 million in the first quarter of 2007. The increase was due mainly to higher revenues as a result of strong WTI crude pricing. This increase was partially offset by the impact of higher operating expenses and higher eligible capital expenditures. For a further discussion of Crown royalties, see page 7.

Cash flow from operations was $910 million in the first quarter of 2008, compared to $600 million in the first quarter of 2007. Excluding the impact of DD&A, the increase was due primarily to the same factors that impacted net earnings.

Oil sands production of 248,000 barrels per day (bpd) in the first quarter of 2008 was comparable to production of 248,200 bpd during the first quarter 2007. Based on first quarter results and expectations for the balance of the year, the oil sands production outlook has been narrowed to 275,000 to 285,000 bpd from the original outlook of 275,000 to 300,000 bpd.

Sales volumes during the first quarter of 2008 averaged 245,100 bpd, compared with 254,500 bpd during the first quarter of 2007. The proportion of higher value diesel fuel and sweet crude products decreased to 51% of total sales volumes in the first quarter of 2008, compared to 53% in the first quarter of 2007.

The average price realization for oil sands crude products increased to $96.16 per barrel in the first quarter of 2008, compared to $65.70 per barrel in the first quarter of 2007. An increase in average benchmark WTI crude oil prices of approximately 70% and an increased premium to WTI on our sweet crude blends were partially offset by the stronger Canadian dollar and a larger discount to WTI for our sour crude blends. As a result, per barrel prices for our oil sands synthetic crude oil averaged $2.14 below WTI, compared to our expectation of $4.25 to $5.25 below WTI for 2008. The expected discount to WTI benchmark prices for our full year 2008 crude sales has been reduced to WTI less $3.50 to $4.50 per barrel.

During the first quarter of 2008, cash operating costs averaged $31.55 per barrel, compared to $26.30 per barrel during the first quarter of 2007. The increase in cash operating costs per barrel was primarily due to an increase in third-party bitumen purchases and the previously noted increase in operational expenses. Based on first quarter results and expectations for the balance of the year, the oil sands cash operating cost outlook has been narrowed to $26.00 to $27.00 per barrel from the original outlook of $25.00 to $27.00 per barrel. Refer to page 14 for further details on cash operating costs as a non-GAAP financial

Suncor Energy Inc.
006 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

measure, including the calculation and reconciliation to GAAP measures.

An approximate 30-day maintenance shutdown to Upgrader 1 is expected to begin in mid-May. During the maintenance work, Upgrader 2 is expected to continue production of approximately 200,000 bpd. Completion of planned maintenance on Upgrader 1 is expected to be followed by completion of construction and final tie-ins of a third coker set and related facilities for Upgrader 2. Expansion work on Upgrader 2 remains on budget and on schedule for completion in June.

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 by the second half of 2008 with actual production ramping up towards capacity over the balance of the year. Engineering is complete and construction is substantially complete.

Construction of Suncor's $340 million Firebag sulphur plant remains on schedule and on budget. When complete, the plant is expected to play a role in reducing sulphur emissions for existing and planned in-situ developments. For further discussion of regulatory requirements related to in-situ operations, see page 12.

Suncor's Board of Directors approved the final phase of our multi-staged Voyageur growth strategy in January 2008. An investment estimated at $20.6 billion is expected to increase production capacity by 200,000 bpd, enabling production capacity of 550,000 bpd in 2012. Of the total $20.6 billion budget, $9 billion is planned for expansion of bitumen supply at our in-situ operation, while $11.6 billion is targeted for construction of a third upgrader.

We are targeting capital spending of approximately $5.3 billion this year on various components of our oil sands expansion plans.

For an update on our significant growth projects currently in progress see page 10.

Oil Sands Crown Royalties

For a description of the Alberta Crown royalty regimes in effect for our oil sands operations, see page 19 of our 2007 Annual Report and page 34 of our first quarter report to shareholders.

In the first quarter of 2008, we recorded a pretax royalty estimate of $282 million, compared to $157 million for the first quarter of 2007. The increase was due mainly to higher revenues as a result of strong WTI crude pricing. This increase was partially offset by the impact of higher operating expenses and higher eligible capital expenditures.

In 2008, the estimation process for calculating the quarterly royalty provision was changed from being based on an annual estimate to being based on the actual eligible revenues and costs recorded in the period. If the annualized approach was used for 2008, pretax royalties would have been $17 million higher for the first quarter.

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.

Oil Sands Mining and In-Situ Royalties



WTI Price/bbl US$	80	90	100

Natural gas (Alberta spot) Cdn$/mcf at AECO	7.36	7.61	7.84

Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	18.72	20.86	22.97

US$/Cdn$ exchange rate	1.00	1.05	1.10

Crown Royalty Expense (based on percentage of total oil sands revenue) %
2008 – Mining synthetic crude oil, in-situ bitumen (25% and 1% min)	9-10	10-11	11-12
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates) ⁽¹⁾	8-9	9-10	10-12
2010 to 2012 – Bitumen (new rates – cap 30% for mining) ⁽¹⁾	9-11	9-11	10-12

(1): For additional information on royalty rates, see page 19 of our 2007 Annual Report.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 007

The foregoing table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the ranges disclosed in the table. The royalty ranges disclosed in the table were developed using the following assumptions: current agreements with the government of Alberta (assuming the government enacts their proposed framework), royalty rates proposed by the government of Alberta, current forecasts of production, capital and operating costs, and the commodity prices and exchange rates described in the table. If annual average WTI prices are above US$100, Suncor anticipates Firebag in-situ royalties may be higher than disclosed in the table.

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

(i): Pursuant to the new royalty framework, the government intends to establish a permanent generic "bitumen valuation methodology" for determining the "R" (gross revenues less related transportation costs) related to bitumen. The government is consulting with stakeholders and independent advisors with a decision on the methodology anticipated by June 30, 2008. Final determination of that methodology may have an impact on royalties payable to the Crown;
(ii): The government announced in April 2008 it will implement recommendations to enhance how the performance of the royalty regime is measured and reported. They are also in the process of reviewing technical policy details and business rules that are being changed to align with the new royalty framework announced in October 2007. Steps taken by the government may affect the calculation of royalties; and
(iii): Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project; changes to the generic royalty regime by the government of Alberta; changes in other legislation and the occurrence of unexpected events all have the potential to have an impact on royalties payable to the Crown.

The forward-looking information in the preceding paragraphs and table should not be taken as an estimate, forecast or prediction of future events or circumstances.

Natural Gas

Our natural gas business recorded net earnings of $19 million in the first quarter of 2008, compared with $4 million of net earnings during the first quarter of 2007. The increase in net earnings was primarily the result of higher revenues driven by increased production, stronger price realizations and higher sulphur prices, in addition to lower dry hole costs. These factors were partially offset by higher DD&A expense resulting from increased production and an increased capital base resulting from higher finding and developing costs, as well as higher royalties related to the increased revenues.

Cash flow from operations for the first quarter of 2008 was $82 million, compared to $64 million in the first quarter of 2007. The increase is primarily due to the same factors affecting net earnings, excluding the impact of DD&A and dry hole costs.

Natural gas and liquids production in the first quarter of 2008 was 229 million cubic feet equivalent (mmcfe) per day, compared to 209 mmcfe per day in the first quarter of 2007. The increased production compared to the prior year was primarily due to the addition of new wells and improved access to processing facilities. Our 2008 planned production (205 to 215 mmcfe per day) offsets Suncor's projected purchases for internal consumption at our oil sands operations.

Realized natural gas prices in the first quarter of 2008 were $7.30 per thousand cubic feet (mcf), compared to $7.01 per mcf in the first quarter of 2007, reflecting favourable pricing terms.

Refining and Marketing

Refining and marketing recorded 2008 first quarter net earnings of $95 million, compared to net earnings of $106 million in the first quarter of 2007. The decrease in net earnings primarily resulted from reduced margins on gasoline and other petroleum products as well as softening demand for petroleum products due to historically high prices. Net earnings were also negatively impacted by the loss of third-party hydrogen supply in January at our Sarnia refinery, which negatively affected production and resulted in increased finished product purchases. A required retroactive change to inventory accounting policy resulted in refining

Suncor Energy Inc.
008 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

and marketing recording an $80 million positive adjustment to net earnings in the first quarter of 2008. For further details of this change, see page 13.

Energy marketing and trading activities, including physical trading activities, resulted in a net pretax gain of $29 million in the first quarter of 2008, compared to a net pretax loss of $2 million in the first quarter of 2007. The higher earnings in the first quarter of 2008 were due to stronger crude trading margins.

Cash flow from operations was $190 million in the first quarter of 2008, compared to $180 million in the first quarter of 2007. Despite decreased net earnings in the first quarter of 2008, cash flow from operations was up in the quarter due to an increase in non-cash expenses.

During the first quarter of 2008, refinery crude oil utilization was 90%, compared to 97% in the first quarter of 2007. The utilization rate at the Sarnia refinery was negatively impacted in the first quarter of 2008 due to the loss of third-party hydrogen supply.

Maintenance is underway to portions of the Sarnia refinery. The work, which began in early April, includes minor planned maintenance and equipment improvements that are expected to allow the refinery to achieve full benefit from modifications made in 2007 to increase sour synthetic crude capacity at the facility. All work is scheduled for completion in early May.

We are assessing plans to expand ethanol production at the St. Clair plant site. Final approval of the project remains subject to approval of government support under the Federal ecoAgricultural Biofuels Capital (ecoABC) Initiative.

For an update on our significant growth projects currently in progress see page 10.

Corporate and Eliminations

After-tax net corporate expense was $101 million in the first quarter of 2008, compared to $2 million in the first quarter of 2007. Excluding the impact of group elimination entries, after-tax net corporate expense was $73 million in the first quarter of 2008 (nil in the first quarter of 2007). Net expense increased mainly due to unrealized foreign exchange losses on our U.S dollar denominated long-term debt as the U.S. dollar strengthened against the Canadian dollar during the first quarter of 2008. After-tax unrealized foreign exchange losses on U.S. dollar denominated long-term debt were $75 million in the first quarter of 2008 compared to a gain of $11 million in the first quarter of 2007. Group elimination entries increased to $28 million in the first quarter of 2008, from $2 million in the first quarter of 2007, primarily as a result of profit elimination on inventory sold from oil sands to refining and marketing.

Breakdown of Net Corporate Expense

Three months ended March 31 ($ millions)	2008		2007

Corporate expense	(73	)	—
Group eliminations	(28	)	(2	)

Total	(101	)	(2	)

Cash used in operations was $21 million in the first quarter of 2008, compared to $19 million in the first quarter of 2007.

Cash Income Taxes

The 2007 federal budget proposed 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 for Voyageur will be gradually phased out between 2011 and 2015.

We estimate we will have cash income taxes of 30% to 50% of our effective tax rate during 2008 to 2010 inclusive. Thereafter, we do not anticipate any significant cash income tax until the middle of the next decade. Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of deductibility of capital expenditures for income tax purposes. This estimate is based on the following assumptions: current forecasts of production, capital and operating costs, the commodity prices and exchange rates described in the table "Oil Sands Mining and In-Situ Royalties" on page 7 and effective income tax rates within 2% of the statutory income tax rate, assuming there are no changes to the current income tax regime. Our outlook on cash income tax is a forward-looking statement and users of this information are cautioned that actual cash income taxes may vary from our outlook.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 009

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 $347 million at the end of the first quarter of 2008, compared to a deficiency of $212 million at the end of the first quarter of 2007, due primarily to increases in accounts payable and accrued liabilities.

During the first three months of 2008, net debt increased to $3.902 billion from $3.248 billion at December 31, 2007. The increase in net debt levels was primarily a result of increased capital spending to fulfill our growth strategies.

In February, Suncor's $330 million bilateral credit facility was increased to $410 million and, in March, our $2 billion syndicated credit facility was increased to $3.5 billion and its term was extended to 2013.

At March 31, 2008, our undrawn credit facilities were approximately $2.5 billion. Outstanding debt shelf prospectuses filed in 2007 in Canada and the U.S. enable the company to issue up to $1.4 billion in debt in Canada and US$850 million 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 2008 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 commercial terms and rates. As reported in our 2007 Annual Report, we anticipate capital spending of approximately $7.5 billion for 2008.

Significant Capital Project Update

A summary of the progress on our significant projects under construction to support both our growth and sustaining needs is provided below. All projects listed below have received Board of Directors approval.

		Cost						% complete		Target
Project	Plan	Estimate $ millions	⁽¹⁾	Estimate % Accuracy	⁽¹⁾	Spent to date		Overall engineering	Construction	completion date

Coker unit	Expected to increase production capacity by 90,000 bpd	2 100		+13/–7		2 200		100	98	Q2 2008

Naphtha unit	Increases sweet product mix	650		+10/–10		420		97	25	2009

Steepbank extraction plant	New location and technologies aimed at improving operational performance	850		+10/–10		390		97	30	2009

North Steepbank mine extension	Expected to generate about 180,000 bpd of bitumen	400		+10/–10		70		50	15	2009

Firebag sulphur plant	Support emission abatement plan at Firebag; capacity to support stages 1-6	340		+10/–10		130		80	15	2009

Voyageur program: Firebag ⁽²⁾	Expansion of Firebag 3-6 is expected to generate about 270,000 bpd of bitumen	9 000		+18/–13		1 825	⁽³⁾

	– Stage 3							85	25	2009

	– Stage 4 ⁽⁴⁾							35	—	2010

	– Stage 5 ⁽⁴⁾							10	—	2011

	– Stage 6 ⁽⁴⁾							10	—	2011

Voyageur program: Upgrader 3 ⁽⁵⁾	Expected to increase production capacity by 200,000 bpd	11 600		+12/–8		1 435	⁽³⁾	50	4	2011

(1): Excludes commissioning and start-up costs. Cost estimates and estimate accuracy reflect budgets approved by Suncor's Board of Directors.
(2): Ramp-up to full capacity of each stage can take up to eighteen months from completion of construction.
(3): Spending to date includes procurement of major project components. For Firebag Stage 3, procurement at March 31, 2008, was 73% complete; for Stage 4, 72% complete; and for Stage 5, 4% complete. For Upgrader 3, procurement was 48% complete.
(4): Pending regulatory approval.
(5): Construction completion targeted in 2011 with ramp-up to full capacity during 2012.

Suncor Energy Inc.
010 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

The previous table contains forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results for each of these projects may vary from the plans disclosed in the table. The target completion dates and cost estimates are based on information and assumptions from the procurement, design and engineering phases of the projects. The more preliminary the project, the greater the range of uncertainty that is projected in connection with the project.

For a list of the material risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially from those contained in the previous table, please see our 2007 Annual Report, pages 21 to 26. The forward-looking information in the preceding paragraphs and table should not be taken as an estimate, forecast or prediction of future events or circumstances.

Derivative Financial Instruments

On January 1, 2008, the company adopted the Canadian Institute of Chartered Accountants (CICA) Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. These new disclosures have been incorporated in the following discussion and in the notes to our unaudited financial statements.

We periodically enter into derivative contracts to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. We also use physical and financial energy contracts to earn trading and marketing revenues.

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

Commodity Hedging Activities To provide an element of stability to future earnings and cash flow, we have Board of Directors approval to fix a price or range of prices for up to approximately 30% of our total planned production of crude oil for specified periods of time. The company has hedged a portion of its forecasted U.S. dollar denominated sales subject to U.S. dollar West Texas Intermediate (WTI) commodity price risk. At March 31, 2008, costless collar crude oil hedges totaling 10,000 bpd of production were outstanding for the remainder of 2008. Prices for these barrels are fixed within a range from an average of US$59.85/bbl up to an average of US$101.06/bbl. In addition to these hedges, during the first quarter of 2008, we purchased crude oil puts for 55,000 bpd of production for 2009 and 2010 which provide us with a floor price of US$60.00/bbl.

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

Settlement of our hedging contracts result in cash receipts or payments for the difference between the derivative contract and market rates for the applicable volumes hedged during the contract term. Cash received or paid offsets corresponding decreases or increases in our sales revenues or product purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings and Comprehensive Income.

Treasury Hedging Activities We periodically enter into interest rate swap contracts as part of our strategy to manage exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between ourselves and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized as an adjustment to interest expense. In addition to our interest rate swap contracts, the company also manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate locks and foreign exchange forward contracts.

The earnings impact associated with changes in the fair values of our commodity and treasury hedging derivative financial instruments in the first quarter of 2008 was a pretax loss of $16 million (2007 – pretax loss of $2 million).

Energy Marketing and Trading Activities In addition to derivative contracts used for hedging activities, the company uses physical and financial energy derivatives to earn trading and marketing revenues. The results of these trading activities are reported as revenue and as energy marketing and trading expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pretax earnings associated with our energy marketing and trading activities in the first quarter of 2008 were $29 million (2007 – pretax loss of $2 million).

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 011

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

($ millions)		March 31 2008		December 31 2007

Derivative financial instruments accounted for as hedges
	Assets	26		20
	Liabilities	(19	)	(11	)
Derivative financial instruments not accounted for as hedges
	Assets	70		18
	Liabilities	(39	)	(21	)

Net derivative financial instruments		38		6

For further details on our derivative financial instruments, see note 3 to the unaudited interim consolidated financial statements on page 24.

Environmental Regulation and Risk

Suncor is making progress to reduce emissions at our in-situ operation. Late last year, air emissions exceeding regulatory limits at the facility resulted in government regulators capping production at 42,000 bpd until emissions are stable at compliant levels. Suncor is continuing its work to construct a $340 million Firebag sulphur plant to help manage sulphur emissions.

In compliance with the Alberta government's Climate Change and Emissions Management Amendment Act, Suncor filed applications in December 2007 to establish baseline intensities for our oil sands facility. In March 2008, Suncor filed the Alberta Specified Gas Compliance Report (July 1 – December 31, 2007 Compliance Period) and remitted a payment of approximately $0.5 million to Alberta Environment.

In April 2007, the Canadian federal government introduced the Clean Air regulatory framework, which is expected to regulate both greenhouse gas (GHG) emissions and air pollutants from industrial emitters. Further details on the GHG framework were released in March, 2008. Suncor has been engaged in the ongoing consultations on this framework. In support of developing regulation, the federal government has required the submission of production, operations and emissions information for designated facilities by May 31, 2008. Draft GHG regulations are expected in fall 2008, with final regulations in fall 2009 and the provisions coming into force January 1, 2010. The financial impact of this proposed legislation will be dependent on the details of Clean Air Act regulations.

There remains uncertainty around the outcome and impacts of climate change and other environmental regulations. We continue to actively work to mitigate our environmental impact, including taking action to reduce GHG emissions, investing in renewable and alternate forms of energy such as wind power and biofuels, accelerating land reclamation, the installation of new emission abatement equipment and pursuing other opportunities such as carbon capture and sequestration.

Control Environment

Based on their evaluation as of March 31, 2008, 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, as of March 31, 2008, there were no changes in our internal control over financial reporting that occurred during the three month period ended March 31, 2008 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.

Suncor Energy Inc.
012 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Change in Accounting Policies

(a) Inventories

On January 1, 2008 the company was required to retroactively adopt CICA Handbook section 3031 "Inventories". Under the new standard, the use of a LIFO (last-in-first-out) based valuation approach for inventory has been eliminated. The standard also requires any impairment to net realizable value of inventory to be written down at each reporting period, with subsequent reversals when applicable. The company transitioned to a FIFO (first-in-first-out) based valuation approach for inventory effective January 1, 2008. The impact of adopting this standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase/(decrease))	March 31 2008		December 31 2007

Inventory	415		404

Total assets	415		404

Accounts payable and accrued liabilities	(43	)	—
Future income taxes	146		121
Retained earnings	312		283

Total liabilities and shareholders' equity	415		404

Change in Consolidated Statements of Earnings and Comprehensive Income

	Three months ended March 31
($ millions, increase/(decrease))	2008		2007

Purchases of crude oil and products	(120	)	(9	)
Operating, selling and general	66		(26	)
Future income taxes	25		10
Net earnings ⁽¹⁾	29		25
Per common share – basic (dollars)	0.06		0.05
Per common share – diluted (dollars)	0.06		0.05

(1): Net earnings impact for 2008 is as follows: oil sands – $(34) million, refining and marketing – $80 million, corporate – $(17) million (2007 – oil sands – $15 million, refining and marketing – $7 million, corporate – $3 million).

(b) Capital Disclosure

On January 1, 2008, the company adopted CICA Handbook section 1535 "Capital Disclosures". This section establishes disclosure requirements for management's policies and processes in defining and managing its capital. There is no financial impact to previously reported financial statements as a result of the implementation of this new standard.

(c) Financial Instruments – Disclosures and Presentation

On January 1, 2008, the company adopted CICA Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. There is no financial impact to previously reported financial statements as a result of the implementation of this new standard.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 013

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, 2008 interim basis, please refer to page 36.

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of Suncor's March 31, 2008 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			2008	2007

Cash flow from operations ($ millions)	A		1 161	825
Weighted number of shares outstanding – basic (millions of shares)	B		463.1	460.1
Cash flow from operations – basic ($ per share)	(A/B	)	2.51	1.79

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.

Oil Sands Operating Costs – Total Operations

		Quarter ended March 31
		2008			2007 ⁽¹⁾
(unaudited)		$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		717			590
	Less: natural gas costs, inventory changes and stock-based compensation	(155	)		(94	)
	Less: non-monetary transactions	(26	)		(32	)
Accretion of asset retirement obligations		14			10
Taxes other than income taxes		16			12

Cash costs		566		25.10	486		21.75
Natural gas		111		5.00	100		4.50
Purchased bitumen (excluding other reported product purchases)		33		1.45	1		0.05

Cash operating costs		710		31.55	587		26.30
Project start-up costs		7		0.30	2		0.10

Total cash operating costs		717		31.85	589		26.40
Depreciation, depletion and amortization		129		5.75	100		4.45

Total operating costs		846		37.60	689		30.85

Production (thousands of barrels per day)		248.0			248.2

(1): Prior period amounts have been restated to reflect the change in accounting policy noted on page 13.

Suncor Energy Inc.
014 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Oil Sands Operating Costs – In-situ Bitumen Production Only

		Quarter ended March 31
		2008			2007
(unaudited)		$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses		89			69
	Less: natural gas costs and inventory changes	(45	)		(35	)
Taxes other than income taxes		2			1

Cash costs		46		14.60	35		11.05
Natural gas		45		14.10	35		11.05

Cash operating costs		91		28.70	70		22.10
In-situ (Firebag) start-up costs		1		0.35	—		—

Total cash operating costs		92		29.05	70		22.10
Depreciation, depletion and amortization		21		6.75	17		5.35

Total operating costs		113		35.80	87		27.45

Production (thousands of barrels per day)		34.6			35.3

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2008 First Quarter 015

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," "invests," "could," "focus," "goal," "proposed," "target," "objective," "potential," "forecast," "predict," "enable," 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, interest rates and currency exchange rates; Suncor's ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example, the Voyageur project, including our Firebag in-situ development) and regulatory projects (for example, the emissions reduction modifications at our Firebag in-situ development); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations (for example, the Government of Alberta's implementation of recommendations to enhance how the performance of the royalty regime is measured and reported, the Government of Canada's proposed Clean Air regulatory framework and the development of greenhouse gas regulation by other provincial and state governments); the future potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change; unexpected issues associated with management and reclamation of our tailings ponds; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive.

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.

Suncor Energy Inc.
016 2008 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

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