	Suncor Energy Inc.
	P.O. Box 38
	112 - 4 Avenue S.W.
	Calgary, Alberta T2P 2V5
	Tel (403) 269-8100
	Fax (403) 269-6218

September 28, 2010

H. Roger Schwall

Assistant Director

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street NE

Washington, D.C. 20549-7010

Dear Mr. Schwall:

Re: Suncor Energy Inc. (“Suncor”) — Form 40-F for the Fiscal Year Ended December 31, 2009 (the “Form 40-F”)

In response to your letter (the “Letter”) dated September 7, 2010 to Suncor, we respond as follows. For ease of reference, we have reproduced your comments in the Letter in italics below, followed by our response.

Reserves Evaluation Process and Controls, page 27

1. We note your response to comment 4 in our letter dated June 15, 2010. Please disclose the qualifications of the technical persons at Suncor who are primarily responsible for overseeing the preparation of reserves estimates.

John Palmer is Suncor’s Internal Qualified Reserves Evaluator under National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators (“NI 51-101”) with overall responsibility for Suncor’s reserves disclosure. Mr. Palmer obtained a Bachelor of Science in Electrical Engineering from the University of Calgary in 1977, is a registered professional engineer in the Province of Alberta and has in excess 34 years of petroleum engineering experience of which more than 30 years has included reserves evaluations.

For the year ended December 31, 2009, Paul Armitage, under the direction of John Palmer, was the primary technical person at Suncor responsible for overseeing the preparation of reserves for all of Suncor’s properties that were not located onshore in North America. Mr. Armitage is a qualified reserves evaluator as defined in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and obtained a Bachelor of Science in Physics/Meteorology/Math from the University of Reading in the United Kingdom in 1986. Mr. Armitage is a chartered engineer in the United Kingdom and has over 23 years of petroleum industry experience of which more than 21 years has included reserves evaluations.

For the year ended December 31, 2009, John Hoffman was the primary technical person at Suncor responsible for overseeing the preparation of reserves for Suncor’s North America onshore properties. Mr. Hoffman is a qualified reserves evaluator as defined in COGEH and obtained a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan in 1988. Mr. Hoffman is a registered professional engineer in the Province of Alberta and has over 21 years of petroleum industry experience of which more than 13 years has included reserves evaluations.

Summary of Oil and Gas Reserves After Royalties, page 31

2. We note your response to prior comment 3 in our letter dated June 15, 2010. Please expand your disclosures to provide the following additional information or tell us how you believe your current disclosure is sufficient.

a. Item 1203(b) of Regulations S-K requires that you disclose material changes in proved undeveloped reserves, including PUDs converted into proved developed reserves. Your discussion should not be limited to PUDs converted into proved developed reserves, and combined disclosures for proved undeveloped and proved developed reserves are insufficient. Your response points us to the disclosure under the heading “In-Situ” on page 30 of your filing, where you state that approximately 28 MMbbls were moved from proved undeveloped to proved developed. We note that your chart on page 32 indicates that PUDs increased by 273 MMbbls, with oil and NGL increasing by 108, SCO decreasing by 181 MMbbls, and bitumen increasing by 346 MMbbls. Expand your disclosure to provide a greater understanding of the circumstances surrounding the increases and decreases in PUDs not explained by the 28 MMbbls that were converted to proved developed.

b. Discuss investments and progress made during the year to convert proved undeveloped reserves to proved developed reserves, including, but not limited to, capital expenditures. See Item 1203(c) of Regulation S-K.

We believe that the disclosure as provided in the Form 40-F for the year ended December 31, 2009 was sufficient in all material respects in relation to the concerns raised in items 2(a)-(d) of the Letter. The majority of the year-over-year changes to proved undeveloped reserves (“PUDs”) relate to two material areas that were discussed in our Annual Information Form for Suncor for the year ended December 31, 2009 included on the Form 40-F (the “AIF”): (1) the merger of Suncor and Petro-Canada (the “Merger”) (page 30 of the AIF); and (2) the reclassification of synthetic crude oil (“SCO”) reserves as bitumen reserves (page 30 of the AIF). The following provides additional information, none of which we believe to be material, other than what is already disclosed in the Form 40-F.

Merger of Suncor and Petro-Canada

Of the 752 MMbbls of proved oil reserves that were added as a result of the Merger, approximately 238 MMbbls were PUDs. Approximately 62% of these PUDs were associated with the MacKay River in-situ steam assisted gravity drainage (“SAGD”) project, 30% were associated with the North Sea Buzzard property, 7% were associated with the Canada East Coast - Hibernia project and the remaining amounts were associated with various properties across Suncor’s upstream operations.

Of the 1179 Bcf of proved natural gas reserves that were added as a result of the Merger, approximately 207 Bcf were PUDs. Approximately 62% of these PUDs were associated with our Trinidad properties, 33% were associated with various North America Onshore properties and 4% were associated with the North Sea Buzzard property.

Reclassification of SCO to Bitumen

As at December 31, 2009, it was expected that approximately one third of our future bitumen production from our oil sands in-situ SAGD projects would be sold directly into the market instead of being upgraded by Suncor and sold as SCO, as compared to the year ended December 31, 2008 when we expected all bitumen would be upgraded. In 2009, proved reserves incurred a reduction of 22% in volume when being upgraded to SCO. Accordingly, 222 million barrels of SCO proved reserves (15 MMbbls of proved developed (“PD”) and 207 MMbbls of proved undeveloped (“PU”)) were required to be converted to 285 MMbbls of bitumen proved reserves (19 MMbbls of PD and 266 MMbbls of PU).

Changes by Product

Changes to Oil and NGLs PUDs and Development Progress

The net increase of 108 MMbbls of proved undeveloped oil and natural gas liquids (“NGLs”) was related to the addition of conventional oil and gas properties in North American Onshore (7 MMbbls), East Coast Canada (26 MMbbls), North Sea (69 MMbbls) and Other International (6 MMbbls) as a result of the Merger.

The North American Onshore PUDs were associated with additional drilling potential in properties located in the Denver Juels basin area of the United States which were sold during 2010. The East Coast PUDs were almost entirely associated with a Hibernia project step out development, in which planning is well advanced and regulatory approval has been obtained. The North Sea PUDs were associated with infill drilling opportunities in the Buzzard field. Development is in progress with initial requests for funds issued by Nexen, the project operator. The infill drilling program is expected to be completed in the next few years. The Other International PUDs were NGLs associated with the Syria Ebla gas development project which came on stream in 2010 and which is expected to be moved to developed reserves for the year ended December 31, 2010.

Changes to SCO and Bitumen PUDs and Development Progress

The changes in SCO PUDs (decrease of 181 MMbbls) and bitumen PUDs (increase of 346 MMbbls) were associated with our in-situ SAGD oil sands projects.

There were no PUDs associated with our oil sands mining projects as at the year ended December 31, 2009 (see discussion below) in relation to SCO. At this point in time, bitumen PUDs are only associated with our in-situ oil sands projects.

The in-situ SCO “purchase” volume shown in the table on page 32 of the AIF is associated with the MacKay River project, which was acquired as a result of the Merger.

Approximately 148 MMbbls of the 178 MMbbls of the total proved in-situ SCO reserves were PUDs.

The in-situ SCO and bitumen revision amounts shown in the table on page 32 of the AIF are comprised of two main components. As discussed herein and in the AIF, a significant amount of the revision came as a result of our decision to sell approximately one third of our future SAGD bitumen production into the market instead of refining the bitumen into SCO. As most of the future production will come from currently undeveloped areas, most of this impact is seen in our in-situ SCO and bitumen PUDs (resulting in a decrease in PUDs for SCO of 207 MMbbls and an increase in PUDs for bitumen of 266 MMbbls). Technical revisions primarily related to favourable results of ongoing development drilling and demonstrated production performance from the currently producing well pairs which increased our confidence in ultimate recoveries in both developed and undeveloped areas. The impact of these revisions was to offset a portion of the negative impact of the switch to bitumen sales resulting in a total net SCO in-situ PUD reduction to 181 MMbbls. Similarly, the total net increase in bitumen PUDs was 346 MMbbls as captured in the table on page 32 of the AIF.

As disclosed in the AIF, approximately 28 MMbbls of in-situ SCO reserves were moved from the proved undeveloped to proved developed reserves as a result of ongoing development work that was completed in 2009. It is expected that on average, similar in-situ SCO plus bitumen undeveloped reserves volumes will be moved to the developed reserves category annually as development work continues for several years to come. Additional information on the development activities and their time lines is provided in our response below (1(c)).

Changes to Natural Gas PUDs and Development Progress

The net increase of 314 Bcfs for natural gas PUDs for the year ended December 31, 2009 was a result of three main components, the Merger, revisions of previous estimates and the discovery & extensions that resulted from activities carried out in 2009.

Approximately 207 Bcf of proved undeveloped natural gas reserves were added as result of the Merger. Approximately 129 Bcf of these PUDs were associated with Other International properties in Trinidad, which were sold in August of 2010. Approximately 69 Bcf of these PUDs were associated with our North American Onshore properties, of which a significant portion has also been sold (including all of our upstream reserves in the United States). Approximately 9 Bcf of these PUDS were associated with our North Sea Buzzard field. However, this increase was offset by negative reserves revisions based on updated production performance analysis and the impact of lower gas prices in 2009 as compared to 2008. As a result, there were no additional natural gas PUDs allotted to our North Sea properties at year end.

For North America Onshore, the net negative proved gas revisions of — 50 Bcf were associated with PUDs. This negative revision was based on updated technical appraisals and negative price revisions as a result of the lower prices for gas in 2009 as compared to 2008. This negative revision offset a large portion of the PU reserves added as a result of the Merger. For the Other International properties, natural gas PUDs had a net negative revision in 2009 as a result of PUDs moving to PD due to

development activities in the Trinidad properties and lower gas prices seen in 2009 as compared to 2008.

The 229 Bcf of discoveries & extensions shown for the Other International properties in the AIF was all PUDs associated with the Syria — Ebla field project that received approval in 2009. This project came on stream in 2010 and the reserves will be moving to the developed categories in 2010.

c. With regard to your response concerning Item 1203(d) of Regulation S-K, please provide to us the time frame within which the in-situ proved undeveloped reserves that have not been converted to proved develop reserves within five years will be moved to the proved developed category.

Suncor has two producing in-situ projects that have PUDs, namely its Firebag and MacKay River operations (collectively, the “In-Situ Properties”). The proved developed areas within the In-Situ Properties are well delineated with core holes and have received regulatory approval. In addition, the In-Situ Properties have ongoing developmental activities, including construction of facilities to increase additional bitumen handling capacity and drilling of new well pairs to ensure that there is sufficient production capacity from the SAGD well pairs to fully utilize any surface equipment that may exist or be installed in the future.

In relation to the MacKay River SAGD project, the tie-in of 10 existing well pairs is currently scheduled for 2011 and it is expected that approximately 166 additional SAGD well pairs will be drilled and brought into production over the next 18 years with production of proved reserves to extend to approximately 2034. In relation to the Firebag SAGD project, additional bitumen handling capacity is currently being installed and it is expected that approximately 508 SAGD well pairs will be brought onto production over the next 24 years with production of proved reserves to extend to approximately 2041. Reserves associated with the well pairs for the In-Situ Properties will move from proved undeveloped to proved developed as they are brought on to production.

d. We note that 100% of your proved “Oil Sands — Mining” reserves have been categorized as proved developed. Please explain how you have determined that all of these reserves meet the definition of proved developed as required by Regulation S-X, Rule 4-10(a)(6)(ii), and that additional development costs will not be incurred to obtain access to the reserves, such as additional costs to remove overburden. Refer also to Regulations S-X, Rule 4-10(a)(7).

Suncor and our external evaluators have taken the following operational considerations into account as the basis for classifying oil sands mining reserves as proved developed as required by Regulation S-X, Rule 4-10(a) - (6)(ii) and (7):

· Overburden stripping operations are ongoing. The need to remove overburden, and the placement location of waste material, are not considered to affect the classification of reserves as being developed.

· Capital projects required to support the existing production capacity levels are generally considered by the industry to be sustaining in nature unless they result in material production growth. While sustaining capital may be significant in terms of absolute level of expenditures involved, the need

for sustaining capital is not considered to affect the classification of reserves as developed unless the level is significant in relation to the cost to replace the installed project facilities.

· The need to plan to replace or relocate the existing crushers to reduce haul distances is not considered to affect the classification of reserves as developed.

· Separate pits adjacent to the current mining area are considered to be developed if they are intended to be processed by the existing, operational infrastructure that is located downstream of the current crushers.

Undeveloped reserves that do not meet the above criteria are classified as either probable undeveloped reserves (or contingent resources) as there are usually significant regulatory and/or project owner approvals that need to be obtained.

Schedules E, F and G

3. We note your response to comment 5 in our letter dated June 15, 2010. Please disclose in the third party engineering reports the weighted average prices from the total company reserve report.

In response to your comments, we have obtained drafts of revised summary reserves reports, which we have provided to you supplementally under separate cover. Suncor would propose filing the revised engineering reports under the cover of Form 6-K.

4. We note your response to comment 7 in our letter dated June 15, 2010, and we reissue the comment. We note your reference in your response to Sproule’s consent regarding your use of the report. However, statements in the Sproule report under the heading “Exclusivity” suggest a limited audience and a limit on investor reliance, including the statement in the report that “[t]his report is solely for the information for Suncor and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of Suncor,” and the statement in the report that the report “should not be used, circulated or quoted for any other purpose without the express written consent of the undersigned or except as required by law.” Please revise.

Please see the revised summary reserves report referred to in our response to comment 3 above.

5. We note your response to comment 8 in our letter date June 15, 2010. Please omit the reference to “generally accepted engineering and evaluation principals” in the third party engineering reports.

Please see the revised summary reserves report referred to in our response to comment 3 above.

6. We note your response to comment 9 in our letter dated June 15, 2010. Please tell us the primary economic assumptions used by RPS Energy. In addition, please provide a sample of your proposed disclosure.

Please see the revised summary reserves report referred to in our response to comment 3 above.

*****

As a result of discussions with the Alberta Securities Commission, unrelated to the Letter or the related letter dated June 15, 2010, we no longer intend to seek exemptive relief to permit Suncor to report its reserves in accordance with Subpart 1200. Accordingly, Suncor’s Annual Report on Form 40-F for the year ended December 31, 2010 will report our reserves in accordance with the requirements of NI 51-101. Consequently, we expect that our future filings with the SEC will not be subject to Subpart 1200. This decision to report our reserves in accordance with the requirements of NI 51-101 was made prior to the receipt of the Letter or the related letter dated June 15, 2010.

As requested in the Letter, we hereby confirm that: (i) Suncor is responsible for the adequacy and accuracy of its disclosure; (ii) SEC staff comments or changes to disclosure in response to SEC staff comments do not foreclose the SEC from taking any action with respect to a filing; and (iii) Suncor may not assert SEC staff comments as a defense in any proceeding initiated by the SEC or any person under the federal securities laws of the United States.

Please do not hesitate to contact the undersigned if you have any further comments or questions.

Yours truly,

SUNCOR ENERGY INC.

/s/ Shawn P. Poirier

Shawn P. Poirier
Assistant Corporate Secretary