EX-99.2 3 a2198472zex-99_2.htm EXHIBIT 99.2
QuickLinks -- Click here to rapidly navigate through this document

EXHIBIT 99.2

Management's Discussion and Analysis for the First Quarter Ended
March 31, 2010

MANAGEMENT'S DISCUSSION AND ANALYSIS
May 3, 2010

This Management's Discussion and Analysis (MD&A) contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, including those discussed in this MD&A and Suncor's other disclosure documents, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. For information on material risk factors and assumptions underlying our forward-looking information, see page 31.

This MD&A should be read in conjunction with Suncor's March 31, 2010 unaudited interim Consolidated Financial Statements and the accompanying notes. All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP), unless noted otherwise. The financial measures operating earnings, cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are discussed in Non-GAAP Financial Measures on pages 29 to 31.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for 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 26.

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

On August 1, 2009, Suncor completed its merger with Petro-Canada, referred to in this MD&A as the "merger". For further information with respect to the merger, please refer to note 2 of the December 31, 2009 audited Consolidated Financial Statements and the accompanying notes.

The unaudited Interim Consolidated Financial statements include the results of post-merger Suncor from August 1, 2009. As such, amounts disclosed in this MD&A for the three month periods ended March 31, 2010, December 31, 2009, and September 30, 2009 reflect results of the post-merger Suncor whereas the comparative figures for the three month period ended March 31, 2009 and all other comparative periods prior to September 30, 2009 reflect solely the results of legacy Suncor.

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

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

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

Additional information about Suncor and legacy Petro-Canada filed with Canadian securities commissions and the United States Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the Annual Information Form dated March 5, 2010 (the 2009 AIF) filed with the SEC under cover of Form 40-F, is available on-line at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A and is not incorporated into the MD&A by reference.

Suncor Energy Inc.
006 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

OVERVIEW AND HIGHLIGHTS OF CONSOLIDATED RESULTS

Description of the Business

Suncor is an integrated energy company headquartered in Calgary, Alberta. The company operates in four business segments: Oil Sands, Natural Gas, International and Offshore, and Refining and Marketing. In addition, the company engages in third-party energy marketing and trading activities, and has investments in renewable energy opportunities, including Canada's largest ethanol plant by volume, as well as partnerships in four wind power projects.

As part of its ongoing strategic business alignment, Suncor is in the process of divesting a number of non-core Natural Gas assets, all Trinidad and Tobago assets and certain non-core North Sea assets, including all assets in The Netherlands. Assets that have been sold during the period, or that have reached a certain point in the sales process, are presented as discontinued operations, as determined in accordance with GAAP. Certain non-core Natural Gas assets that the company has targeted for sale have not met certain criteria to be classified as discontinued operations, and continue to be reported as part of the company's continuing operations at this time.

Quarterly Consolidated Financial Summary


Three months ended ($ millions, except per share)	Mar 31 2010	Dec 31 2009		Sept 30 2009		June 30 2009		Mar 31 2009		Dec 31 2008	Sept 30 2008	June 30 2008

Revenues (net of royalties) ⁽¹⁾	7 546	7 636		8 443		4 768		4 633		6 952	8 507	7 640

Net earnings (loss)
Continuing operations	475	479		940		(52	)	(192	)	(218)	801	815
Discontinued operations	241	(22	)	(11	)	1		3		3	14	14

	716	457		929		(51	)	(189	)	(215)	815	829

Net earnings (loss) from continuing operations per common share
Basic	0.30	0.31		0.75		(0.06	)	(0.21	)	(0.24)	0.86	0.88
Diluted	0.30	0.30		0.75		(0.06	)	(0.21	)	(0.24)	0.84	0.86

Net earnings (loss) per common share
Basic	0.46	0.29		0.69		(0.06	)	(0.20	)	(0.24)	0.87	0.89
Diluted	0.46	0.29		0.68		(0.06	)	(0.20	)	(0.24)	0.86	0.87

Operating earnings (loss) ⁽²⁾
Continuing operations	214	343		354		39		377		17	872	855
Discontinued operations	73	(20	)	(11	)	(1	)	3		(3)	14	14

	287	323		343		38		380		14	886	869

Operating earnings per common share	0.18	0.21		0.27		0.04		0.41		0.02	0.95	0.93

Cash flow from operations ^{(1), (2)}	1 124	1 129		574		295		801		231	1 146	1 530

Return on capital employed ^{(2), (3)}	4.9	2.6		3.7		7.3		16.0		22.5	28.7	28.8

(1): Includes continuing and discontinued operations.
(2): Non-GAAP measure. See pages 29 and 30.
(3): Excludes capitalized costs related to major projects in progress.

Highlights

•: Net earnings for the first quarter of 2010 were $716 million, compared to a net loss of $189 million for the first quarter of 2009. Operating earnings in the first quarter of 2010 were $287 million, compared to $380 million in the first quarter of 2009. The decreased operating earnings were primarily due to reduced oil sands production volumes, as the company recovered from the impact of two upgrader fires. This was partially offset by additional upstream production, as a result of

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 007

the merger with Petro-Canada. The company also benefited from higher benchmark crude oil prices in the quarter, partially offset by the stronger Canadian dollar relative to the U.S. dollar.

•: Cash flow from operations was $1.124 billion in the first quarter of 2010, compared to $801 million in the first quarter of 2009. The increase in cash flow from operations was primarily due to the increased volumes added as a result of the merger.
•: At Oil Sands, repairs were completed to Upgrader 2, during the first quarter, which was partially damaged by a fire in December 2009. The upgrader returned to normal operations in February 2010. On February 9, 2010 a second unrelated fire occurred at Upgrader 1, which was repaired and returned to full operations by April 1, 2010.
•: Total upstream production this quarter was 564,600 barrels of oil equivalent (boe) per day, compared to 314,500 boe per day in the first quarter of 2009. Although production from the Oil Sands business was significantly affected by the fires to the upgraders, production was ahead of management's expectations in the Natural Gas and International and Offshore businesses.
•: In Syria, test production from the Ebla Gas project was introduced into the Syrian Gas Network for the first time in March 2010. Commercial production was achieved on April 19, 2010.
•: In March 2010, the company received regulatory approval to develop Firebag Stages 4, 5 and 6 of its in-situ oil sands expansion. Each stage has a planned production capacity of approximately 62,500 barrels per day.
•: During the quarter, construction continued on Firebag Stage 3 in-situ oil sands project. The planned $3.6 billion expansion is currently expected to achieve first oil in the second quarter of 2011, with volumes ramping up over an estimated 18-month period toward planned production capacity of approximately 62,500 barrels of bitumen per day.
•: On March 1, 2010, Suncor completed the sale of substantially all of its U.S. Rockies upstream assets for net proceeds of US$481 million. Remaining U.S. Rockies upstream assets were sold shortly thereafter.
•: On March 31, 2010, the company completed the sale of other non-core natural gas assets in northeast British Columbia, called Jedney/Blueberry, for net proceeds of $383 million.
•: The company also entered into two additional agreements during the first quarter of 2010 to sell non-core assets. The first agreement includes certain natural gas assets in central Alberta, known as Rosevear and Pine Creek, for aggregate consideration of $235 million, while a second agreement was reached to sell all of Suncor's assets in Trinidad and Tobago for aggregate consideration of US$380 million.

Suncor Energy Inc.
008 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Volumes


Three months ended March 31 (thousands of barrels of oil equivalent per day (mboe/d))	2010	2009

Continuing operations
Oil Sands – operated	202.3	278.0
Oil Sands – Syncrude	32.3	—
Natural Gas	102.4	29.5
International and Offshore	168.6	—

	505.6	307.5

Discontinued operations
Natural Gas	19.8	7.0
International and Offshore	39.2	—

	59.0	7.0

Total	564.6	314.5

The impact of the fires at Upgrader 2 in December 2009 and Upgrader 1 in February 2010 negatively affected production. This was partially offset by Syncrude volumes contributed from the merger. As a result of the recent incidents at the upgrading facilities, Suncor's outlook for Oil Sands production for 2010 has been revised (see page 4).

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 009

Natural Gas total production from continuing and discontinued operations was 733 mmcfe per day. As a result of the assets divested in the first quarter of 2010, Suncor's outlook for Natural Gas production for 2010 has been revised (see page 4).

International and Offshore production was 207,800 boe per day. While production was negatively affected by minor unplanned outages at the company's North Sea operations, and by limitations on production quotas in Libya, all of the East Coast Canada assets exceeded management's expectations during the quarter. As a result of performance in the first quarter of 2010 and update to assets included in the strategic divestment plan, Suncor's outlook for production from this business has been revised (see page 4).

Commodity Prices

Average Benchmarks


Three months ended ($ average for the period)		Mar 31 2010	Dec 31 2009	Sept 30 2009	June 30 2009	Mar 31 2009	Dec 31 2008	Sept 30 2008	June 30 2008

West Texas Intermediate (WTI) crude oil at Cushing	US$/barrel	78.70	76.20	68.30	59.60	43.10	58.75	118.00	124.00
Dated Brent crude oil at Sullom Voe	US$/barrel	76.25	74.55	68.25	58.85	44.40	54.90	114.80	121.40
Dated Brent/Maya FOB price differential	US$/barrel	6.50	5.25	5.10	3.75	5.90	10.10	8.35	18.40
Canadian 0.3% par crude oil at Edmonton	Cdn$/barrel	80.45	77.00	70.60	65.30	50.10	64.65	123.00	126.40
Light/heavy crude oil differential of WTI at Cushing less Western Canadian Select at Hardisty	US$/barrel	8.95	12.10	10.10	7.50	8.95	19.30	18.05	21.65
Natural gas (Alberta spot) at AECO	Cdn$/mcf	5.35	4.25	3.00	3.65	5.65	6.80	9.25	9.35
New York Harbour 3-2-1 crack⁽¹⁾	US$/barrel	7.95	5.80	7.50	8.35	9.85	5.40	10.65	11.50
Chicago 3-2-1 crack⁽¹⁾	US$/barrel	5.65	4.15	7.65	10.15	8.95	5.25	16.45	12.90
Seattle 3-2-1 crack⁽¹⁾	US$/barrel	8.55	5.95	12.80	13.35	13.45	5.25	17.20	16.45
Gulf Coast 3-2-1 crack⁽¹⁾	US$/barrel	6.75	4.50	6.75	8.40	8.90	2.90	14.60	12.10
Exchange rate	US$/Cdn$	0.96	0.94	0.91	0.85	0.80	0.82	0.96	0.99

(1): 3-2-1 crack spreads are industry indicators measuring the margin on a barrel of oil for gasoline and distillate. They are calculated by taking two times the gasoline margin at a certain location plus one times the distillate margin at the same location and dividing by three.

SEGMENTED EARNINGS AND CASH FLOWS

Oil Sands


Three months ended March 31 ($ millions, unless otherwise noted)	2010	2009

Gross revenues	1 970	1 108
Royalties	70	8

Net revenues	1 900	1 100

Production (excluding Syncrude) (thousands of bpd)	202.3	278.0
Syncrude production (thousands of bpd)	32.3	—

Average sales price (excluding Syncrude) ($/barrel) ⁽¹⁾	70.21	59.45

Net earnings (loss)	76	(110	)
Operating earnings ⁽²⁾	104	293

Cash flow from operations ⁽²⁾	262	480

Cash operating costs (excluding Syncrude) ($/barrel) ⁽²⁾	54.85	33.70
Sales mix (light/heavy mix) (%)	38/62	54/46

ROCE ^{(2), (3)}	5.2	22.9
ROCE ^{(2), (4)}	3.1	13.9

(1): Calculated before royalties and net of related transportation costs.
(2): Non-GAAP measure. See pages 30 and 31.
(3): Excludes capitalized costs related to major projects in progress.
(4): Includes capitalized costs related to major projects in progress.

Suncor Energy Inc.
010 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Oil Sands recorded net earnings of $76 million in the first quarter of 2010, compared with a net loss of $110 million in the first quarter of 2009. Operating earnings for the first quarter of 2010 were $104 million, compared to operating earnings of $293 million in the first quarter of 2009. Operating earnings were lower primarily due to the impact of upgrader fires in December 2009 and February 2010. Reduced production volumes resulted in decreased sales, while related operating expenses remain relatively fixed, impacting both earnings and cash flow from operations. This was partially offset by higher average price realizations and the recovery of fire-related insurance proceeds from Suncor's captive insurance company. Third-party insurance recoveries related to the fires are expected to be minimal.

Cash flow from operations was $262 million in the first quarter of 2010, compared to $480 million in the first quarter of 2009. The decrease was a result of the same factors that impacted operating earnings.

Volumes

Oil Sands production averaged 202,300 bpd (excluding Syncrude) in the first quarter of 2010, compared to 278,000 bpd during the first quarter of 2009. Production was negatively impacted by a fire and subsequent maintenance at Upgrader 2 in December, 2009. Upgrader 2 returned to normal production on February 4, 2010. On February 9, 2010, a second unrelated fire occurred at Upgrader 1. The repairs related to this fire were completed and Upgrader 1 was restored to normal operations on April 1, 2010.

The fires also negatively affected sales mix during the quarter, with diesel and sweet crude products comprising 38% of total sales volume during the first quarter of 2010, compared to 54% for the same period in 2009. As a result of the fires, the company has revised its outlook for Oil Sands production for 2010 (see page 4).

Syncrude contributed an average 32,300 bpd of sweet synthetic crude oil production in the first quarter of 2010, which was 14% of Oil Sands total production. Apart from the Syncrude production, the merger did not result in increased Oil Sands production volumes. Production from MacKay River was included in Suncor's reported production during the first quarter of 2009 as volumes processed by Suncor under a processing fee agreement. However, the addition of MacKay River has resulted in increased sales volumes for Oil Sands, as volumes under the processing agreement were not included in sales prior to August 1, 2009.

Prices

Sales price realization from Oil Sands operated assets averaged $70.21 per barrel during the first quarter of 2010 compared to $59.45 per barrel during the same period in 2009. Benchmark WTI crude oil prices and premiums to WTI for sweet and sour crude blends were both higher during the three months ended March 31, 2010 as compared to the same period in 2009. However, as crude oil prices are based on U.S. dollar benchmarks, the stronger Canadian dollar in the first quarter of

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 011

2010 negatively impacted the company's realized prices. WTI crude oil price averaged US$78.70 per barrel during the first quarter of 2010, compared to US$43.10 per barrel during the same period in 2009, and the US$/Cdn$ exchange rate averaged 0.96 in the first quarter of 2010, compared to 0.80 for the same period in 2009. Lower volumes during the quarter, as a result of the fires at the upgraders, prevented Oil Sands from fully taking advantage of these higher realized prices.

Operating Expenses

Operating expenses were higher in the first quarter of 2010 compared to the first quarter of 2009, primarily due to impacts from the upgrader fires. Purchases of crude oil and products increased both to meet customer commitments and to obtain diluent as the company was unable to produce sufficient quantities to meet its operating requirements. In addition, certain planned maintenance scheduled for later in 2010 was accelerated while upgrader operations were disrupted.

During the first quarter of 2010, cash operating costs (excluding Syncrude) increased to $54.85 per barrel, from $33.70 per barrel in the first quarter of 2009, primarily due to the decrease in production. Refer to page 31 for further details on cash operating costs as non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expenses increased in the first quarter of 2010, compared to the first quarter of 2009. The depreciable cost base has grown as new assets have been commissioned and acquired, primarily as a result of the merger with Petro-Canada, since the first quarter of 2009.

Royalties

Royalties increased to $70 million in the first quarter of 2010 from $8 million in the first quarter of 2009 as a result of higher commodity prices. Low bitumen reference prices in the first quarter of 2009 resulted in royalties being calculated at minimum royalty rates. In the first quarter of 2010, the impact of the upgrader fires on volumes resulted in minimum royalty rates until March, when improved volumes and higher prices increased effective royalty rates. In-situ projects continued in the pre-payout phase and royalties were calculated on the minimum royalty percentage of "Revenues", which is a rate based on the Canadian dollar equivalent of WTI up to a maximum of 9%. For a more detailed description of the Alberta Crown royalty regime in effect for the company's operated Oil Sands assets, see pages 16-18 of Suncor's 2009 Annual Report.

The following table provides an estimation of royalties for Oil Sands operations (excluding Syncrude) in the years 2010 to 2013 under three price scenarios, and certain assumptions on which we have based our estimates for those price scenarios.


WTI Price/bbl US$	60	80	100

Natural gas (Alberta spot) Cdn$/mcf at AECO	5.15	5.60	6.20

Light/heavy crude oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	8.35	8.90	11.50

Differential of Maya at the U.S. Gulf Coast less Western Canadian Select at Hardisty US$	4.40	4.55	4.60

US$/Cdn$ exchange rate	0.85	0.97	1.00

Crown Royalty Expense (based on percentage of total Oil Sands gross revenue) (excluding Syncrude))% ⁽¹⁾
2010 ⁽²⁾	4-6	9-11	9-12
2011-2013	4-7	9-11	12-14

(1): Reflects Crown's interim bitumen valuation methodology.
(2): For 2010, estimated royalty rates are based on actual year-to-date results plus forward months estimated as per assumptions.

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

Suncor Energy Inc.
012 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

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

(i): The government of Alberta enacted new Bitumen Valuation Methodology (Ministerial) Regulations as part of the implementation of the New Royalty Framework effective January 1, 2009. These interim regulations determine the valuation of bitumen for 2009 and 2010. The final regulations are being developed by the Crown that will establish the bitumen valuation methodology for future years. For Suncor's mining operations, the bitumen valuation methodology is based on the terms of Suncor's January 2008 Royalty Amending Agreement (RAA), which we believe places certain limitations on the interim bitumen valuation methodology as recently enacted. For the year 2009, Suncor filed a non-compliance notice with the Crown, citing that reasonable adjustments in the determination of the Suncor bitumen value were not considered by the Crown as permitted by the Suncor RAA. Royalty payments to the Crown for Suncor's mining operations were determined in accordance with the Suncor RAA and royalty expense was recorded under the Crown's interim bitumen valuation methodology, representing a negative difference of approximately $200 million. The Suncor RAA provides for a negotiation period with the Crown and, failing a negotiated settlement, an arbitration procedure is outlined. If a negotiated settlement or arbiter does not create a result in Suncor's favour, royalty payments could be significantly higher.
(ii): The government enacted the new Oil Sands Allowed Costs (Ministerial) Regulations as part of the implementation of the New Royalty Framework effective January 1, 2009. Further clarification of some Allowed Cost business rules is still expected. The terms of the Suncor RAA determine the royalty obligation through 2015 for the mining operations. However, potential changes to, and the interpretation of, the Allowed Cost regulations, could over time, have a significant impact on the amount of royalties payable.
(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 resulting from regulatory audits of prior year filings; further changes to applicable royalty regimes 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.

For further information on risk factors related to royalty rates, please see page 54 of Suncor's 2009 AIF.

Planned Turnarounds

There is a 45 day planned maintenance scheduled for Upgrader 2 during the second quarter, and a 35 day planned turnaround scheduled in the third quarter of 2010. Production volumes are expected to be reduced by approximately 85,000 bpd in the second quarter and 35,000 bpd in the third quarter of 2010.

Syncrude undertook an extension and advancement of maintenance during the first quarter of 2010, and is expecting a coker turnaround in the third quarter of 2010.

Growth Update

The company is continuing with its planned growth initiatives related to the Firebag Stage 3 in-situ oil sands expansion. Production is expected to begin in the second quarter of 2011, with volumes ramping up over an estimated 18-month period toward planned production capacity of approximately 62,500 barrels of bitumen per day.

Spending will also be directed to Firebag Stage 4 to support a target of first bitumen production in the fourth quarter of 2012. Firebag Stage 4 also has planned production capacity of 62,500 barrels of bitumen per day. Construction of Firebag Stage 4 remains subject to Board approval.

Remaining 2010 capital growth spending will be directed towards completion of a naphtha unit at Upgrader 2 which is intended to increase the value of the upgrader's product mix. The company expects the plant will be operational by the third quarter of 2011.

For an update on our significant capital projects currently in progress, see page 26.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 013

Risk Factors Affecting Performance

The financial and operating performance of the company's Oil Sands business is potentially affected by a number of factors, including, but not limited to, the following:

•: Production reliability risk. Our ability to reliably operate our oil sands facilities in order to meet production targets.
•: Our ability to finance oil sands growth and sustaining capital expenditures in a volatile commodity pricing environment. Also refer to Financial Condition and Liquidity on page 25.
•: Bitumen supply. Ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in-situ reservoir and equipment performance could impact 2010 production targets.
•: Performance of recently commissioned facilities. Production rates while new equipment is being lined out are difficult to predict and can be impacted by unplanned maintenance.
•: Ability to manage production operating costs. Operating costs could be impacted by inflationary pressures on labour, volatile pricing for natural gas used as an energy source in oil sands processes, and planned and unplanned maintenance. We continue to address these risks through such strategies as application of technologies that help manage operational workforce demand, offsetting natural gas purchases through internal production, investigation of technologies that mitigate reliance on natural gas as an energy source, and an increased focus on preventative maintenance.
•: Our ability to complete projects both on time and on budget. This could be impacted by competition from other projects (including other Oil Sands projects) for goods and services and demands on infrastructure in Fort McMurray and the surrounding area (including housing, roads and schools). We continue to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing oil sands expansion to reduce unit costs, seeking strategic alliances with service providers and maintaining a strong focus on engineering, procurement and project management.
•: Potential changes in the demand for refinery feedstock and diesel fuel. Our strategy is to reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding our customer base and offering a variety of blends of refinery feedstock to meet customer specifications.
•: Volatility in crude oil and natural gas prices, foreign exchange rates and the light/heavy and sweet/sour crude oil differentials. We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 27).
•: Logistical constraints and variability in market demand, which can impact crude movements. These factors can be difficult to predict and control.
•: Changes to royalty and tax legislation and related agreements that could impact our business. While fiscal regimes in Alberta and Canada are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company's planned investments, and rates of return on existing investments.
•: Our relationship with our trade unions. Work disruptions have the potential to adversely affect oil sands operations and growth projects. The Communications, Energy and Paperworkers Union Local 707 represents approximately 2,900 Oil Sands employees.

Additional risks, assumptions and uncertainties are discussed on page 31 under Forward-Looking Information.

Suncor Energy Inc.
014 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Natural Gas


Three months ended March 31 ($ millions, unless otherwise noted)		2010	2009

Gross revenues from continuing operations		344	91
Royalties from continuing operations		53	17

Net revenues from continuing operations		291	74

Average sales price from continuing operations – natural gas ($/mcf) ⁽¹⁾		5.29	5.51
Average sales price from continuing operations – natural gas liquids and crude oil ($/barrel) ⁽¹⁾		70.02	45.91

Gross production
	Continuing operations (mmcfe/d)	614	177
	Discontinued operations (mmcfe/d)	119	42

		733	219

Net earnings (loss)
	Continuing operations	34	(13	)
	Discontinued operations	187	3

		221	(10	)

Operating earnings (loss) ⁽²⁾
	Continuing operations	—	(13	)
	Discontinued operations	19	3

		19	(10	)

Cash flow from continuing operations ⁽²⁾		182	40

ROCE ⁽²⁾ %		1.2	5.0

(1): Calculated before royalties and net of transportation costs.
(2): Non-GAAP measure. See page 30.

The Natural Gas business recorded net earnings of $221 million in the first quarter of 2010, compared with a net loss of $10 million in the first quarter of 2009. The $231 million increase is predominantly related to gains realized on the assets sold in the first quarter of 2010. Total operating earnings were $19 million in the first quarter of 2010, compared to an operating loss of $10 million in the first quarter of 2009. The increase primarily relates to the positive impact of incremental production volumes as a result of the merger and higher price realizations for crude oil and natural gas liquids (NGLs). Factors that negatively affected total operating earnings were a decline in natural gas prices from the first quarter of 2009 and higher operating expenses, royalties and depreciation, depletion and amortization expenses relating to the increased production levels.

Discontinued Operations

Discontinued operations include the results, up to the closing date, of assets that have been sold during the quarter, as well as results from certain assets the company expects to sell. Comparative results have been restated to reflect the impact of operations that have been classified as discontinued during the first quarter of 2010.

During the first quarter of 2010, the Natural Gas business progressed on strategic divestment activities initiated during the latter part of 2009:

•: On March 1, 2010, substantially all of Suncor's producing assets in the U.S. Rockies were sold for net proceeds of US$481 million. These assets produced an average 50 million cubic feet of natural gas (mmcf) per day and five thousand barrels of natural gas liquids and crude oil per day during the first two months of 2010. The company's remaining interests in the U.S. Rockies upstream assets were divested shortly thereafter.
•: On March 31, 2010, the company sold certain non-core natural gas properties located in northeast British Columbia, known as Jedney/Blueberry, for net proceeds of $383 million. These assets produced an average of 44 million cubic feet of natural gas equivalent (mmcfe) per day during the first quarter of 2010.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 015

•: On March 24, 2010, the company reached an agreement to sell certain non-core natural gas properties located in central Alberta, known as Rosevear and Pine Creek. These assets produced an average of 23 mmcfe per day during the first quarter of 2010. The sale, for proceeds of $235 million, is expected to close during the second quarter of 2010.

Continuing Operations

Operating earnings from continuing operations were nil in the first quarter of 2010, compared to an operating loss from continuing operations of $13 million in the first quarter of 2009. Cash flow from continuing operations was $182 million in the first quarter of 2010, compared to $40 million in the first quarter of 2009. The improvement in operating earnings and cash flow from operations was due primarily to the same factors that impacted total operating earnings.

Volumes

Continuing operations production averaged 614 mmcfe per day in the first quarter of 2010, compared to 177 mmcfe per day during the same period in 2009. The increase primarily reflects assets acquired as a result of the merger.

Price

The average realized natural gas liquids and crude oil price increased to $70.02 per barrel in the first quarter of 2010, from $45.91 per barrel in the first quarter of 2009, reflecting the increase in benchmark crude oil prices. This was partially offset by a decrease in the average realized natural gas price to $5.29 per mcf for the first quarter of 2010, from $5.51 per mcf for the first quarter of 2009 as a result of the decline in benchmark natural gas prices. The net impact of the price variance was an increase in operating earnings from continuing operations of $8 million.

Royalties

Total royalties related to continuing operations increased to $53 million in the first quarter of 2010, from $17 million in the first quarter of 2009, as a result of volume increases. On a per unit basis, royalties declined to $0.96 per mcf in the first quarter of 2010 from $1.07 per mcf in the first quarter of 2009. This is attributed to lower benchmark commodity prices and reduced rates under the Alberta Government's New Royalty Framework. For a further discussion on the Alberta Crown royalties regime, see page 48 of the 2009 AIF.

Suncor Energy Inc.
016 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Operating Expenses

The increased operating expenses relates to increased production levels, partially offset by operational efficiencies. Lifting costs from continuing operations were $1.27 per mcfe for the first quarter of 2010 compared to $1.51 per mcfe in the first quarter of 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (DD&A) expenses from continuing operations increased in the first quarter of 2010 compared to the same period in 2009 as a result of the merger. On a per unit basis, DD&A expenses have remained consistent quarter over quarter.

Gain on Asset Dispositions

During the first quarter, the disposal of a portion of our working interest in certain non-core lands in northeast British Columbia for proceeds of $40 million was included in net earnings from continuing operations.

Risk Factors Affecting Performance

The financial and operating performance of the company's Natural Gas business is potentially affected by a number of factors, including, but not limited to, the following:

•: Consistently and competitively finding and developing reserves that can be brought on stream economically.
•: Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Financial Condition and Liquidity on page 25.
•: Volatility in natural gas and liquids prices is not predictable and can significantly impact revenues.
•: The accessibility and cost of mineral rights. Market demand influences the cost and available opportunities for mineral leases and acquisitions.
•: Risk associated with a depressed market for asset sales, leading to losses on disposition.
•: Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in our operating areas. These risks could increase costs and/or cause delays to or cancellation of projects.
•: Risks and uncertainties associated with weather conditions, which can shorten the winter drilling season and impact the spring and summer drilling program, which may result in increased costs and/or delays in bringing on new production.

Additional risks, assumptions and uncertainties are discussed on page 31 under Forward-Looking Information.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 017

International and Offshore


Three months ended March 31 ($ millions, unless otherwise noted)		2010

Gross revenues from continuing operations		1 214
Royalties		339

Net revenues from continuing operations		875

Production from continuing operations
	East Coast Canada production (thousands of boe/d)	74.6
	U.K. (Buzzard) (thousands of boe/d)	58.6
	Libya (thousands of boe/d)	35.4
Production from discontinued operations (thousands of boe/d)		39.2

Total Production (thousands of boe/d)		207.8

Average sales price from continuing operations ⁽¹⁾
	East Coast Canada ($/bbl)	78.69
	North Sea ($/boe)	72.36
	Libya ($/boe)	73.40

Net earnings
	Continuing operations	209
	Discontinued operations	54

		263

Operating earnings ⁽²⁾
	Continuing operations	205
	Discontinued operations	54

		259

Cash flow from continuing operations ⁽²⁾		541

ROCE (%) ^{(2), (3)}		16.5
ROCE (%) ^{(2), (4)}		10.4

(1): Calculated before royalties and net of transportation costs.
(2): Non-GAAP measure. See page 30.
(3): Excludes capitalized costs related to major projects in progress.
(4): Includes capitalized costs related to major projects in progress.

Suncor has continuing operations in the U.K. (Buzzard – 29.9% working interest), Norway, Libya, and Syria. There are discontinued operations located in The Netherlands and certain U.K. sections of the North Sea, as well as Trinidad and Tobago.

The company also has an interest in every major producing oil development off Canada's east coast. Suncor holds a 20% interest in Hibernia, a 27.5% interest in White Rose, a 22.7% interest in Hebron, and is the operator of Terra Nova with a 34% interest. The company also has a 19.5% interest in the Hibernia South Extension and a 26.125% interest in the White Rose North Amethyst and West White Rose Extensions.

All of these interests were acquired as a result of the merger. For further details related to the company's International and Offshore interests, see page 7 of the 2009 AIF.

Total operating earnings for the International and Offshore business were positively affected by higher commodity prices, slightly offset by a weakening U.S. dollar. Negatively affecting operating earnings this quarter were unplanned maintenance activities which impacted production levels at the Buzzard and Triton assets in the North Sea, as well as ongoing production quota constraints in Libya. The East Coast Canada operations were positively impacted by strong reservoir capability and facility reliability, and the early addition of new wells in the AA Block at Hibernia.

Discontinued Operations

Discontinued operations include the results, up to the closing date, of assets that we expect to sell. Comparative results have been restated to reflect the impact of operations that have been classified as discontinued during the first quarter of 2010.

Suncor Energy Inc.
018 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

In accordance with the company's strategic plans, Suncor entered into an agreement to sell all of its assets in Trinidad and Tobago, for gross proceeds of US$380 million. The sale is currently expected to close during the second quarter of 2010. Average production of offshore natural gas at the Trinidad and Tobago operations was 11,700 boe per day during the first quarter of 2010. Divestiture plans are also proceeding for certain other non-core North Sea assets, including all of the company's investments in The Netherlands. U.K. North Sea assets that are planned to be divested include Scott/Telford and Triton. The company expects to maintain its ownership positions in the producing Buzzard field, and exploration assets in the Hobby, Golden Eagle and Pink fields. Production volumes related to these assets averaged 27,500 boe per day during the first quarter of 2010.

Continuing Operations

Operating earnings from continuing operations were $205 million in the first quarter of 2010, impacted by the same factors affecting total operating earnings.

Cash flow from continuing operations of $541 million in the first quarter of 2010 has been impacted by the same factors affecting earnings.

Volumes

Net production from the Buzzard development in the U.K. sector of the North Sea averaged 58,600 boe per day, which was lower than management's expectations as a result of unplanned maintenance to the separator unit. Suncor's share of production in Libya, with an average of 35,400 barrels of oil per day in the first quarter of 2010, continues to be negatively affected by production quotas.

Suncor's share of Terra Nova production averaged 29,600 bpd during the quarter. The company's share of production from Hibernia also averaged 30,200 bpd for the quarter ended March 31, 2010, with strong reservoir capability and facility reliability continuing throughout the period. Suncor's share of White Rose's average production for the first quarter of 2010 was 14,800 bpd.

Prices

The average sales price for the U.K. (Buzzard) production was $72.36 per boe in the first quarter of 2010, while the average realized price for the sale of Libya production was $73.40 per boe.

East Coast Canada offshore average price realizations, which were $78.69 per barrel, benefited from strong benchmark crude oil prices this quarter.

Royalties

Total royalties in the International and Offshore segment during the first quarter of 2010 were $339 million, or 28% of gross revenue from continuing operations.

The following table sets forth an estimation of royalties related to Suncor's East Coast assets in 2010 for three price scenarios, and certain assumptions on which the estimates for those price scenarios have been based.


WTI Price/bbl US$	60	80	100

US$ / Cdn$ exchange rate	0.85	0.97	1.00

Crown Royalty Expense (based on percentage of gross revenue) %⁽¹⁾
2010 – Crude (tiered royalty rates assessed on gross or net revenue)	31-33	32-34	33-35

(1): For 2010, estimated royalty rates are based on actual year-to-date results plus forward months estimated as per assumptions.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 019

For a further discussion on Crown royalties see page 18 of the 2009 Annual Report. The previous table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the percentages disclosed in the table. The percentages disclosed in the table were developed using the following assumptions: current agreements with the Government of Newfoundland and Labrador, current forecasts of production, capital and operating costs, and the forward estimates of commodity prices and exchange rates described in the table.

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

(i): The government of Newfoundland and Labrador and Suncor are in discussions to resolve several outstanding issues that impact current and prior years. Settlement of these issues could impact royalties payable to the Crown.
(ii): Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each project; changes resulting from regulatory audits of prior year filings; further changes to applicable royalty regimes by the government of Newfoundland and Labrador; changes in other legislation; and the occurrence of unexpected events all have the potential to have an impact on royalties payable to the Crown.

Operating Expenses

Operating expenses were favourably impacted by foreign exchange rates during the quarter, with minor offsets for unplanned maintenance at the Buzzard operations, and the ongoing seismic program in Libya.

Lifting and administrative costs at the East Coast Canada operations were all below management's expectations this quarter.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization expenses were higher than expected during the first quarter of 2010, as a result of higher than anticipated production levels.

Planned Turnarounds

There were no planned turnarounds at any of the International and Offshore assets during the first quarter of 2010.

For our continuing operations, the company has the following planned turnarounds in 2010. In the U.K., there is a three-week maintenance turnaround planned at the Buzzard operation in the second quarter of 2010. In East Coast Canada, there is a four-week turnaround scheduled for Terra Nova beginning in late June 2010, as well as turnarounds planned for White Rose and Hibernia, during the fourth quarter of 2010.

Growth Update

In Syria, test production from the Ebla gas project was introduced into the Syrian Gas Network for the first time in March 2010. Commercial production was achieved on April 19, 2010.

Two seismic surveys continue to acquire data in relation to the new Libya Exploration and Production Sharing Agreements. The results of seismic surveys, completed in 2009, are currently being processed. Site construction for the first of the exploration wells due to be drilled this year is complete and rig mobilization has commenced.

Development drilling continues for the North Amethyst portion of the White Rose Extensions, with first oil expected during the second quarter of 2010. Development drilling of North Amethyst will continue through 2012.

The West White Rose development is divided into two stages. The first stage was approved during the second quarter of 2009. Drilling for the first of two pilot wells is planned to commence later in 2010, with first oil expected to result by early in 2011. Drilling results from the first stage, combined with production evaluation and ongoing reservoir evaluation, will define the full field development scope.

Drilling commenced and first oil was achieved during the latter part of 2009 on the AA Block area of Hibernia South, in which Suncor holds a 20% interest. First oil is expected between 2013 and 2014 from the remainder of the Hibernia South Extension project, in which Suncor holds a 19.5% interest. In February 2010 final agreements were executed among the

Suncor Energy Inc.
020 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

co-venturers and the Government of Newfoundland and Labrador, including the settlement of transportation deductions for royalty purposes.

For an update on our significant capital projects currently in progress, see page 26.

Risk Factors Affecting Performance

The financial and operating performance of the company's International and Offshore business is potentially affected by a number of factors, including, but not limited to, the following:

•: Risks and uncertainties associated with international and offshore operations normally inherent in such activities such as development drilling, operation and development of such properties including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, pollution and other environmental risks.
•: Consistently and competitively finding and developing reserves that can be brought on stream economically.
•: Volatility in crude oil prices is not predictable and can significantly impact revenues.
•: Performance after completion of maintenance not predictable and can significantly impact production rates.
•: Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities. These risks could increase costs and/or cause delays to or cancellation of projects and expansions to existing projects.
•: Risks and uncertainties associated with weather conditions, which may result in increased costs and/or delays in bringing on new production.
•: Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Financial Condition and Liquidity on page 25.
•: Risks associated with applicable legal and other regulatory requirements, including changes to tax, environmental and other legal and regulatory requirements, the outcome of which is not predictable and could result in changes to the company's planned investments, and rates of return on the company's existing investments.

Additional risks, assumptions and uncertainties are discussed on page 31 under Forward-Looking Information.

Refining and Marketing


Three months ended March 31 ($ millions, unless otherwise noted)		2010	2009

Revenues		4 809	1 413
Refined product sales volumes (thousands of cubic metres per day)
	Gasoline	38.3	16.4
	Distillate	28.4	10.5
	Other	15.5	4.5

		82.2	31.4

Net earnings		139	112
Operating earnings ⁽¹⁾		131	111
Cash flow from operations ⁽¹⁾		328	205

ROCE (%) ⁽¹⁾		6.6	0.6

(1): Non-GAAP measure. See page 30.

The Refining and Marketing business operates refineries in Edmonton, Alberta; Montreal, Quebec; Sarnia, Ontario; and Commerce City, Colorado with a total aggregate production capacity of 443,000 bpd, as well as a lubricants plant that is the largest producer of lubricant-base stocks in Canada. In addition, the Refining and Marketing business markets refined products to retail, commercial and industrial customers, primarily in Canada and Colorado, through a combination of

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 021

company-owned, branded-dealer and joint venture-operated retail stations, a large Canadian national commercial road transport network and a bulk sales channel. Assets also include interests in pipelines and product terminals in Canada and the United States.

The nameplate capacity of our Edmonton refinery has been upwardly revised to 135,000 bpd from the previously disclosed 125,000 bpd. See page 22 of Suncor's 2009 AIF for further information. Starting January 1, 2010, refinery utilization will be calculated using the 135,000 bpd capacity.

The Refining and Marketing business recorded net earnings of $139 million in the first quarter of 2010, compared with $112 million in the first quarter of 2009. Operating earnings for the first quarter of 2010 were $131 million, compared with $111 million for the first quarter of 2009. As a result of the merger, refining capacity increased by 265,000 bpd. This increase, combined with the addition of the Petro-Canada national retail and wholesale businesses and the lubricants plant, enabled Refining and Marketing to deliver higher operating earnings in the first quarter of 2010, compared to the first quarter of 2009, despite a much weaker business environment.

Cash flow from operations was $328 million in the first quarter of 2010, compared to $205 million in the same period of 2009. The increase was a result of the same factors that affected earnings.

Volumes

Total sales of refined petroleum products averaged 82,200 cubic metres per day during the first quarter of 2010 compared to 31,400 cubic metres per day during the first quarter of 2009. Sales volumes were positively impacted by the merger through Suncor acquiring additional refining assets, national retail and wholesale businesses and an international lubricants business.

Overall refinery utilization averaged 92% in the first quarter of 2010, with utilization of the legacy Suncor refineries averaging 93% compared to 90% over the same period in 2009.


Three months ended March 31 (thousands of cubic metres per day)		2010	2009

Eastern North America
	Gasoline	23.5	8.2
	Distillate	14.0	5.1

		37.5	13.3

Western North America
	Gasoline	14.8	8.2
	Distillate	14.4	5.4

		29.2	13.6

Other		15.5	4.5

Total		82.2	31.4

Suncor Energy Inc.
022 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Margins

Cracking margins declined quarter-over-quarter, resulting in a negative impact to operating earnings. In particular, distillate cracking margins were weaker, at US$8.35 per barrel for the first quarter of 2010, in comparison to US$14.20 per barrel for the same period in 2009, which had a significant impact on overall realized margins.

Operating Expenses

Operating expenses were $256 million higher in the first quarter of 2010 compared to the first quarter of 2009, which is a result of the merger. In April 2010, an arbitration panel awarded damages against Suncor relating to a claim made by Greenfield Ethanol Inc. The amount awarded and recorded in the first quarter results was $14 million, plus additional costs that Suncor is unable to quantify at this time.

Planned Turnarounds

Turnarounds are planned for the Edmonton, Montreal and Sarnia refineries in the second quarter of 2010. In October 2010, there is a turnaround planned for the lubricants plant. As with all planned turnarounds, the company enters into transactions to ensure sufficient additional finished product is available to mitigate the impact of lost production on customers.

Risk Factors Affecting Performance

The financial and operating performance of the company's Refining and Marketing business is potentially affected by a number of factors, including, but not limited to, the following:

•: Production reliability risk. Our ability to reliably operate our refining and marketing facilities in order to meet production targets.
•: Management expects that fluctuations in demand and supply for refined products, margin and price volatility, and market competition, including potential new market entrants, will continue to impact the business environment.
•: There are certain risks associated with the execution of capital projects, including the risk of cost overruns. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.
•: Our relationship with our trade unions. Hourly employees at our London, Ontario terminal operation, our Sarnia, Ontario refinery, our Commerce City, Colorado refinery, our Montreal refinery, certain of our lubricants operations, certain of our terminalling operations and at Sun-Canadian Pipeline Company Limited are represented by labour unions or employee associations. Any work interruptions involving our employees, and/or contract trades utilized in our projects or operations, could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Additional risks, assumptions and uncertainties are discussed on page 31 under Forward-Looking Information.

Corporate, Energy Trading and Eliminations

Corporate, Energy Trading and Eliminations includes the company's investment in renewable energy projects, results related to third-party energy supply and trading activities and other activities not directly attributable to any other operating segment.


Three months ended March 31 ($ millions, unless otherwise noted)		2010		2009

Net earnings (loss)
	Renewable energy	15		10
	Energy trading	(11	)	28
	Corporate	10		(208	)
	Group eliminations	3		(11	)

		17		(181	)

Operating earnings (loss) ⁽¹⁾
	Renewable energy	15		10
	Energy trading	(11	)	28
	Corporate	(233	)	(41	)
	Group eliminations	3		(11	)

		(226	)	(14	)

Cash flow from (used in) operations ⁽¹⁾		(314	)	63

(1): Non-GAAP measure. See page 30.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 023

Renewable Energy

The company's renewable energy interests include four wind power projects and Canada's largest ethanol plant by production volume. Suncor's four wind projects, located in Saskatchewan, Alberta and Ontario, have a total generating capacity of 147 megawatts, offsetting the equivalent of 284,000 tonnes of carbon dioxide (CO₂) per year. The ethanol plant has a current capacity of 200 million litres per year, offsetting the equivalent of 300,000 tonnes of CO₂ per year. A $120 million expansion of the plant is currently underway, estimated to be complete by the end of 2010, with a planned doubling of production capacity. Net earnings of $15 million were contributed from the company's renewable energy operations in the first quarter of 2010, compared to $10 million for the same period in 2009, due primarily to the receipt of retroactive government contributions received in March 2010.

Energy Trading

Suncor's energy trading activities involve marketing and trading of crude oil, natural gas, refined products and by-products, and the use of financial derivatives. These activities resulted in a net loss of $11 million in the first quarter of 2010, compared to net earnings of $28 million in the first quarter of 2009.

The first quarter of 2010 has been negatively impacted by unrealized losses on physical trading strategies. In first quarter of 2009, results were positively impacted by realized gains on physical trading strategies in place to take advantage of rising crude oil prices.

Corporate and Eliminations

Corporate experienced an operating loss of $233 million in the first quarter of 2010, compared to an operating loss of $41 million operating loss in the first quarter of 2009. The increase was primarily the result of captive insurance expenses related to the December 2009 Oil Sands upgrader fire and increased net interest expense, due to additional debt acquired through the merger.

Group eliminations reflects the elimination of profit on crude oil sales between upstream segments and Refining and Marketing, where this crude oil still resides in Refining and Marketing's inventories. During the first quarter of 2010, $3 million of profits previously eliminated were recovered, compared to profits of $11 million that were eliminated in the first quarter of 2009.

Corporate, energy trading and eliminations net earnings were $17 million in the first quarter of 2010, compared with a $181 million net loss in the first quarter of 2009. The increase was primarily due to a $230 million after-tax foreign exchange gain related to U.S. dollar denominated long-term debt in the first quarter of 2010, compared to an after-tax loss of $148 million in the first quarter of 2009 due to the strengthening of the Canadian dollar relative to the U.S. dollar and higher levels of U.S. debt, as a result of the merger.

CASH INCOME TAXES

The company estimates that it will have cash income taxes of approximately $900 million to $1 billion during 2010. Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of deductibility of capital expenditures for income tax purposes, among other things. This estimate is based on the following assumptions: current forecasts of production, capital and operating costs and the commodity prices and exchange rates described in the royalty estimate tables on pages 12 and 19, assuming there are no changes to the current income tax regime. The company's outlook on cash income taxes is a forward-looking statement and users of this information are cautioned that actual cash income taxes may vary materially from this outlook. For further information related to risk factors that could affect this estimate; refer to pages 54 to 62 of the 2009 AIF.

Suncor Energy Inc.
024 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

FINANCIAL CONDITION AND LIQUIDITY


($ millions, except ratios)	March 31 2010	December 31 2009

Working capital (deficit) ⁽¹⁾	616	(315	)

Short-term debt	2	2
Current portion of long-term debt	39	25
Long-term debt	13 730	13 855

Total debt	13 771	13 882
Less: Cash and equivalents	602	505

Net Debt	13 169	13 377
Shareholders' equity	34 273	34 111

Total capitalization (total debt & shareholders' equity)	48 044	47 993

		Three months ended March 31

		2010	2009

Return on capital employed (%) ^(2),(3)		4.9	16.0
Return on capital employed (%) ^(2),(4)		3.3	11.3

Net debt to cash flow from operations (times) ⁽⁵⁾		4.2	2.3

Interest coverage on long-term debt (times)
	Net earnings ⁽⁶⁾	4.9	4.8
	Cash flow from operations ⁽⁷⁾	7.2	10.4
Debt to debt plus shareholders' equity (%) ⁽⁸⁾		28.7	38.7

(1): Calculated as current assets less current liabilities, excluding cash and cash equivalents, short-term debt, current portion of long-term debt and future income taxes. Current assets and liabilities of discontinued operations are excluded.
(2): Non-GAAP measure. See page 30.
(3): Excludes capitalized costs related to major projects in progress.
(4): Includes capitalized costs related to major projects in progress.
(5): Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations for the twelve-month period then ended.
(6): Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
(7): Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(8): Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders' equity.

Capital Structure

Suncor's capital resources consist primarily of cash flow from operations and available lines of credit. Management of debt levels continues to be a priority given the company's long-term growth plans. Suncor's management believes a phased and flexible approach to existing and future growth projects should assist Suncor in maintaining its ability to manage project costs and debt levels.

At March 31, 2010, Suncor's net debt was $13.2 billion, compared to $13.4 billion at December 31, 2009. Undrawn lines of credit at March 31, 2010 were approximately $3.9 billion compared to $4.2 billion at December 31, 2009. During the first quarter of 2010, the company reduced a committed bilateral credit facility from $61 million to $15 million and reduced a demand credit facility from $175 million to $50 million.

Suncor's management believes it will have the capital resources to fund its planned capital spending program and to meet current working capital requirements through cash flow from operations and its committed credit facilities, assuming current production outlooks and other business plan assumptions are met. The company's cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, refining and marketing margins, operating expenses, taxes, royalties, and foreign exchange rates. If additional capital is required, the company believes adequate additional financing will be available in the debt capital markets at commercial terms and rates.

Suncor is subject to financial and operating covenants related to its public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations. The company is in compliance with its

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 025

financial covenant that requires total debt to not be more than 60% of its total capitalization. At March 31, 2010, total debt to total capitalization was 29% (December 31, 2009 – 29%). The company is also in compliance with all operating covenants.

The preceding paragraphs contain forward-looking information regarding our liquidity and capital resources based on factors and assumptions discussed above and on page 31. Users of this information are cautioned that our actual liquidity and capital resources may vary materially.

Outstanding Shares


At March 31, 2010			thousands

Common shares			1 561 104
Common share options – total			73 892

Credit Ratings

The company's debt ratings have not changed from December 31, 2009. For further information refer to page 13 of Suncor's 2009 Annual Report.

Contractual Obligations, Commitments and Guarantees

In the normal course of business, the company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable. Suncor has included these obligations and commitments and guarantees in its 2009 Annual Report. There have been no significant developments since December 31, 2009.

Significant Capital Project Update

Suncor spent $1.1 billion on capital and exploration in the first quarter of 2010, out of a Board approved budget of $5.5 billion for 2010. A summary of the progress on significant projects under construction to support both growth and sustaining needs is provided below. All projects listed below have received Board approval. The estimates and target completion dates do not include project commissioning and start-up.

Project

Business
Segment

Plan

Cost
Estimate
$ millions ⁽¹⁾

Estimate % Accuracy ⁽¹⁾

Spent
to date

Target
completion
date

Ebla gas project

International and Offshore

Development of gas fields and construction of gas treatment plant

1 196

+7/-3

1 091

Q2 2010

⁽²⁾

Buzzard enhancement project ⁽³⁾

International and Offshore

Installation of equipment to handle high sulphur content

339

+15/-10

176

Q4 2010

Firebag Stage 3

Oil Sands

Expansion is expected to increase bitumen supply

3 638

+10/-10

3 007

Q2 2011

Naphtha unit

Oil Sands

Increases sweet product mix

850

+4/-4

678

Q3 2011

North Amethyst ⁽³⁾

International and Offshore

Extension to the White Rose field involving sub-sea tie-in

490

+10/-5

294

2012

⁽⁴⁾

(1): Cost estimates and estimate accuracy reflect budgets approved by Suncor's Board of Directors.
(2): Commercial production began in April 2010.
(3): Amounts represent Suncor's net share in the project.
(4): Initial production is expected in the second quarter of 2010.

The company continues to incur costs related to placing certain growth projects into "safe mode" due to market conditions last year. Safe mode is defined as the costs of deferring the projects and keeping the equipment and facilities in a safe

Suncor Energy Inc.
026 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

manner in order to expedite remobilization. As a result of placing certain projects into safe mode, pre-tax costs of $40 million were incurred in the first quarter of 2010. Safe mode costs of approximately $150 million to $200 million on a pre-tax basis, including costs related to the remobilization of growth projects placed into safe mode, are expected to be incurred in 2010.

The preceding paragraphs contain forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results, including target completion dates, for each of these projects may vary from the plans disclosed.

The material factors used to develop target completion dates and cost estimates are: current capital spending plans, the current status of procurement, design and engineering phases of the project; updates from third parties on delivery of goods and services associated with the project; and estimates from major projects teams on completion of future phases of the project. We have assumed that commitments from third parties will be honoured and that material delays and increased costs related to the risk factors referred to above will not be encountered.

For a list of the additional risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially, please see page 53 of Suncor's 2009 AIF.

FINANCIAL INSTRUMENTS

Suncor periodically enters into derivative contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. The company also uses physical and financial energy derivatives to earn trading revenues.

Suncor accounts for its significant derivative financial instruments using the mark-to-market method. The contracts are recorded on the balance sheet at fair value at each period end, with any changes in fair value immediately recognized in net earnings.

To estimate fair value of financial instruments, the company uses quoted market prices when available, or models that utilize observable market data. In addition to market information, Suncor incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. Inputs used are characterized in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

The fair values of the company's derivative financial instruments are as follows:


($ millions)	March 31 2010		December 31 2009

Assets	168		213
Liabilities	(447	)	(572	)

Net derivative financial instruments	(279	)	(359	)

For further details on the company's derivative financial instruments at March 31, 2010, see note 5 to the March 31, 2010 unaudited interim Consolidated Financial Statements. For a more complete discussion of Suncor's exposure to financial risks and the company's mitigation activities, see note 5 to the 2009 Audited Consolidated Financial Statements.

Risks Associated with Derivative Financial Instruments

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

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

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 027

counterparties. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date.

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

RISK FACTORS AFFECTING PERFORMANCE

The company's financial and operational performance is potentially affected by a number of factors including, but not limited to, commodity prices and foreign currency exchange rates, environmental regulations, changes to royalty and income tax legislation, credit market conditions, stakeholder support for activities and growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors Affecting Performance for each of Suncor's business segments. A more detailed discussion of the company's risk factors is presented on pages 54 to 62 of the 2009 AIF, filed with securities regulatory authorities. The company is continually working to mitigate the impact of potential risks to its stakeholders. This process includes an entity-wide risk review. This internal review is completed annually to ensure all significant risks are identified and appropriately managed.

Environmental Regulation and Risk

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require us to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are generally required before initiating most new projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air emissions (Criteria Air Contaminants (CACs) and Greenhouse Gases (GHGs)), will impose further requirements on companies operating in the energy industry.

For further discussion of environmental regulation and risks affecting the company, see page 21 in Suncor's 2009 Annual Report.

CRITICAL ACCOUNTING ESTIMATES

Critical accounting estimates are defined as estimates that are important to the portrayal of the company's financial position and operations, and require management to make judgments based on underlying assumptions about future events and their effects. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as the company's operating environment changes. Critical accounting estimates are reviewed annually by the Audit Committee of the Board of Directors. A detailed description of the critical accounting estimates used in the preparation of the March 31, 2010 unaudited interim Consolidated Financial Statements is presented on pages 23 to 25 of the 2009 Annual Report.

ACCOUNTING POLICIES

International Financial Reporting Standards

The following is a status update of the company's international financial reporting standards (IFRS) conversion project. A description of key activities, milestones and IFRS accounting policies selected are presented on pages 30 to 32 of the 2009 Annual Report. The major accounting policy choices outlined in the 2009 Annual Report should not be regarded as a complete list of changes that will result from the transition to IFRS. It is intended to highlight those areas the company believes to be most significant; however, analysis of changes will be ongoing throughout 2010. Note that new and revised IFRS developments will be monitored throughout the project and may result in changes to the project activities.

Suncor Energy Inc.
028 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Financial Statement Preparation Preparation of the IFRS January 1, 2010 opening Balance Sheet has commenced and is to be presented to the Audit Committee during the second quarter of 2010. Preparation of draft disclosures is ongoing.

Training Training and communication sessions continued for the Board of Directors, senior management, finance and business personnel in the first quarter of 2010.

Infrastructure IFRS Information Technology (IT) Assessment is ongoing. This includes testing of the dual reporting IFRS IT solution and developing the 2011 conversion plan. Implementation of business process changes are underway.

Control Environment The Company's analysis to date supports a preliminary assessment that no material changes will be required to internal controls or disclosure controls over financial reporting. A detailed review of the control environment is to commence in the second quarter of 2010.

Control Environment

Based on their evaluation as of March 31, 2010, Suncor's chief executive officer and chief financial officer concluded that the company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed by the company in reports that are filed or submitted to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as of March 31, 2010, there were no changes in the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) – 15d-15(f)) that occurred during the three-month period ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting. Management will continue to periodically evaluate the company's disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

The company continues to integrate Petro-Canada's historical internal control over financial reporting with its internal control over financial reporting. This integration will lead to changes in these controls in future fiscal periods but it is not yet known whether these changes will materially affect internal control over financial reporting. This integration process is expected to be completed by the end of 2010.

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

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this MD&A, namely operating earnings, cash flow from operations, return on capital employed (ROCE), and cash and total operating costs are not prescribed by Canadian 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. These non-GAAP financial measures are included 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 Canadian GAAP.

Operating Earnings

Operating earnings is a non-GAAP measure that the company uses to evaluate operating performance, which management believes allows better comparability between periods. Operating earnings is calculated by adjusting net earnings for significant one-time items and items that are not indicative of operating performance. All reconciling items presented on an after-tax basis.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 029

A reconciliation of after-tax net earnings to after-tax operating earnings is presented in the following table:


Three months ended March 31	Oil Sands				Natural Gas				International and Offshore			Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2010		2009		2010		2009		2010		2009	2010		2009		2010		2009		2010		2009

Net earnings (loss) from continuing operations as reported	76		(110	)	34		(13	)	209		—	139		112		17		(181	)	475		(192	)
Change in fair value of commodity derivatives used for risk management⁽¹⁾	(8	)	266		—		—		—		—	—		—		—		—		(8	)	266
Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	—		—		—		—		—		—	—		—		(230	)	148		(230	)	148
Mark-to-market valuation of stock-based compensation	(2	)	1		(7	)	—		(5	)	—	(8	)	(1	)	(29	)	19		(51	)	19
Project start-up costs	8		11		—		—		1		—	—		—		—		—		9		11
Costs related to deferral of growth projects	30		125		—		—		—		—	—		—		—		—		30		125
Merger and integration costs	—		—		—		—		—		—	—		—		16		—		16		—
Gains on significant disposals	—		—		(27	)	—		—		—	—		—		—		—		(27	)	—

Operating earnings (loss) from continuing operations	104		293		—		(13	)	205		—	131		111		(226	)	(14	)	214		377

Net earnings from discontinued operations as reported	—		—		187		3		54		—	—		—		—		—		241		3
Gains on disposals of discontinued operations	—		—		(168	)	—		—		—	—		—		—		—		(168	)	—

Operating earnings (loss) from total operations	104		293		19		(10	)	259		—	131		111		(226	)	(14	)	287		380

(1): The company adjusts operating earnings for the change in fair value of significant crude oil risk management derivatives. The company also holds less significant risk management derivatives in other segments which are not adjusted for.

Return on Capital Employed (ROCE)

ROCE is included because investors may use this information to analyze operating performance, leverage and liquidity. A detailed numerical reconciliation of ROCE is provided 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, 2010 interim basis, please refer to page 50.

Cash Flow from Operations

Cash flow from operations is included because investors may use this information to analyze operating performance. Cash flow from operations is expressed before changes in non-cash working capital.


Three months ended March 31	Oil Sands				Natural Gas			International and Offshore			Refining and Marketing				Corporate, Energy Trading and Eliminations			Total
($ millions)	2010		2009		2010		2009	2010		2009	2010		2009		2010		2009	2010		2009

Total cash flow from (used in) operating activities	(812	)	(877	)	195		56	557		—	128		(30	)	198		1 128	266		277
Less: Decrease (increase) in non-cash working capital related to continuing operating activities	(1 074	)	(1 357	)	(32	)	—	(35	)	—	(200	)	(235	)	512		1 065	(829	)	(527	)
Less: Decrease (increase) in non-cash working capital related to discontinued operating activities	—		—		30		3	(59	)	—	—		—		—		—	(29	)	3

Total cash flow from (used in) operations	262		480		197		53	651		—	328		205		(314	)	63	1 124		801

Suncor Energy Inc.
030 2010 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Cash Operating Costs

Operating cost information is included because investors may use this information to analyze operating performance.

The following tables outline the reconciliation of Oil Sands expenses included in the Schedules of Segmented Data in the March 31, 2010 unaudited interim Consolidated Financial Statements to total and per barrel cash operating costs, total cash operating costs and total operating costs:

Oil Sands Operating Costs – Total Operations ⁽¹⁾


Three months ended March 31	2010			2009
	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses	1 118			938
Less: Natural gas costs, inventory changes, stock-based compensation, and other	(122	)		3
Less: Safe mode costs	(40	)		(175	)
Less: Non-monetary transactions	(14	)		(26	)
Less: Syncrude-related operating, selling and general expenses	(122	)		—
Accretion of asset retirement obligations	27			27

Cash costs	847		46.50	767		30.65
Natural gas	98		5.40	75		3.00
Imported bitumen (excluding other reported product purchases)	54		2.95	1		0.05

Cash operating costs	999		54.85	843		33.70
Project start-up costs	10		0.55	16		0.65

Total cash operating costs	1 009		55.40	859		34.35
Depreciation, depletion and amortization	230		12.65	183		7.30

Total operating costs	1 239		68.05	1 042		41.65

Production excluding Syncrude (thousands of barrels per day)	202.3			278.0

(1): Excludes Suncor's proportionate production share and operating costs from the Syncrude joint venture.

Legal Notice – Forward-Looking Information

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

All statements and other information that address expectations or projections about the future, including statements about Suncor's strategy for growth, expected and future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like "expects," "anticipates," "estimates," "plans," "scheduled," "intends," "believes," "projects," "indicates," "could," "focus," "vision," "goal," "outlook," "proposed," "target," "objective," and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

Suncor's outlook includes a production range based on our current expectations, estimates, projections and assumptions. Uncertainties in the estimating process and the impact of future events may cause actual results to differ, in some cases materially, from our estimates. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. For a description of assumptions and risk factors specifically related to the 2010 outlook, see pages 3 to 5 of our first quarter 2010 Report to Shareholders.

The risks, uncertainties and other factors that could influence actual results include but are not limited to, market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; availability of third-party bitumen; success of hedging strategies, maintaining a desirable debt to cash flow ratio; changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange rates; Suncor's ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects and regulatory projects; effective execution of planned turnaround; the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations (for example, the Government of Alberta's review of the unintended consequences of the proposed Crown royalty regime, the Government of Canada's current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; political, economic and socio-economic risk associated with foreign operations (including OPEC production quotas); the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; failure to realize anticipated synergies or cost savings; risks regarding the integration of the two businesses after the merger; and incorrect assessments of the values of the other entity. The foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in Suncor's Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

Suncor Energy Inc.
Inquiries John Rogers (403) 269-8670 2010 First Quarter 031

QuickLinks

EXHIBIT 99.2