August 24, 2006

Mr. Gary Newberry
United States Securities and Exchange Commission
Division of Corporate Finance
100 F Street, N.E.
Washington, D.C.
20549-7010

Re:	Suncor Energy Inc.
	Form 40-F for Fiscal Year Ended December 31, 2005 (“Form 40-F”)
	Filed March 10, 2006
	File No. 1-12384

Dear Mr. Newberry,

We have received your letter of August 8, 2006 with respect to our Form 40-F for our fiscal year ended December 31, 2005. Please find below, for your consideration, each of your comments, followed by our response.

Exhibit 99.1

Summary of Significant Accounting Policies

(c) Revenues, page 61

1. We note your policy for revenue recognition under multiple element arrangements is on a straight line basis. With regard to these arrangements, tell us:

a. What types of products or services are included.

The policy statement about revenue recognition for multiple element arrangements refers to a single, non-recurring transaction with multiple deliverables entered into in 2004. The transaction involved the licensing of certain proprietary technology and the provision of associated training and services related to the technology.

b. How you determined the disclosed accounting treatment is appropriate.

Using guidance from Canadian Generally Accepted Accounting Principals (Canadian GAAP) under EIC 142 – “Revenue Arrangements With Multiple Deliverables” (EIC 142) and U.S. GAAP under EITF 00-21, “Revenue Arrangements with Multiple Deliverables” (EITF 00-21), we concluded this single transaction with

multiple deliverables did not consist of more than one unit of accounting in accordance with paragraph 9 (b) of EITF 00-21 (see Appendix “A” for excerpts from EITF 00-21).

We deferred and amortized on a straight line basis the upfront payments, representing an aggregate $80 million (Cdn.), over the term of the agreement, consistent with Staff Accounting Bulletin 104 – Revenue Recognition (see Schedule “A” for excerpts of this Bulletin applicable to license fee revenue, non-refundable upfront fees and recognition of service revenue). This amortization results in revenue of approximately Cdn $17 million per year (or approximately 0.1% of 2005 operating revenue). Given this contract represents such a small percentage of revenue, it does not merit reference under “significant accounting policies” and accordingly, we will delete the reference to “revenues associated with multi-element arrangements” in our next annual filing.

c. What consideration was given to Emerging Issue Task Force Issue 00-21 to determine what differences, if any, must be reported under U.S. Generally Accepted Accounting Principles, (“U.S. GAAP”).

We gave consideration to EITF 00-21. EITF 00-21 is consistent with the Canadian Accounting Standards (EIC 142) in respect to the recognition of revenue for multi-element arrangements. We determined there were no differences to be reported under U.S. GAAP.

Notes to the Consolidated Financial Statements

Note 7 – Accrued Liabilities and Other, page 81

2. You have disclosed you cannot determine a fair value for asset retirement obligation due to the indeterminate life of the related asset. Tell us what consideration was given to Financial Interpretation 47 in determining whether a fair value of the asset retirement obligation could be reported under U.S. GAAP.

In concluding we could not reasonably estimate an asset retirement obligation for our oil sands upgrading facilities, located in Fort McMurray, Alberta or our two oil refining facilities, located in Sarnia, Ontario and Commerce City, Colorado, we considered Financial Interpretation 47 as follows (see paragraph 4 of FIN 47 in Schedule “A”):

(a) Was there fair value of the asset retirement obligation embodied in an acquisition price?

(i) we did not acquire our upgrading facilities in Fort McMurray or our refining facilities in Sarnia from a third party;

(ii) there were no asset retirement obligations included in the acquisitions of our Commerce City refineries.

(b) Is there an active market for the transfer of the asset retirement obligation?

There is no active market for the transfer of an asset retirement obligation in respect of these assets.

(c) Is there sufficient information to apply an expected present value technique?

(See paragraph 5 of FIN 47 and footnote 9 attached in Schedule “A”)

We have concluded there is not sufficient information to apply an expected present value technique in accordance with Paragraph 5 (b), and that an asset retirement obligation is therefore, not reasonably estimable in accordance with paragraph 4 (c). There are no foreseeable plans to close or significantly alter the operations of the facilities, and expectations are to maintain the facilities through any necessary repairs and maintenance activities. Therefore, a “settlement date” is not determinable (our conclusion is consistent with Example 3 of FIN 47).

We continue to consider operational and strategic developments to identify if sufficient information exists to reasonably estimate an asset retirement obligation in respect of these assets.

Note 18 – Differences Between Canadian and U.S. Generally Accepted Accounting Principles, page 93

3. In reconciling to net earnings under U.S. GAAP, you have reported $83 million as gross income from derivatives and hedging activities and an additional $140 million as part of other comprehensive income in fiscal 2005. Tell us how these amounts reconcile with the amounts disclosed in the narrative section of this footnote with respect to $2 million of hedge ineffectiveness on page 94, $5 million of realized and unrealized hedge ineffectiveness on page 95 and the amounts reported in the reconciliation of changes in accumulated other comprehensive income for 2005.

Reconciliation of cash flow hedge ineffectiveness:

Ineffective Portion of Derivatives Designated as Cash Flow Hedges

	Gross		Taxes		Net
Balance at 12/31/2004	(86	)	(29	)	(57	)	[A1]

- Change in ineffectiveness for contracts open at 12/31/2004	8		3		5		[B1]
- Change in ineffectiveness for contracts open at 12/31/2004, realized in 2005	(8	)	(3	)	(5	)
- Ineffectiveness at 12/31/2004 realized in 2005	86		29		57		[D1]
- Change in ineffectiveness for contracts designated as cash flow hedges during 2005	(3	)	(1	)	(2	)	[D2]
- Change in ineffectiveness for contracts designated as cash flow — hedges during 2005, realized in 2005	—		—		—

Balance at 12/31/2005	(3	)	(1	)	(2	)	[A2], [B2], [C]

[A1] minus [A2]: $83 million ($55 million after tax). The total change in the ineffective portion of our cash flow hedges equals the required adjustment from Canadian GAAP to US GAAP. This is amount (a) included in the table on page 93 “Differences Between Canadian and U.S. Generally Accepted Accounting Principles.”

[B1] plus [B2]: $5 million ($3 million after tax). This represents the amount referred to on page 95: “The earnings loss associated with realized [B1] and unrealized [B2] hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $3 million, net of income taxes of $2 million.”

[C]: $3 million ($2 million after tax). This represents the amount referred to on Page 94: “Under U.S. GAAP, for the year ended December 31, 2005, the company would have recognized $2 million of hedge ineffectiveness relating to forecasted cash flows in 2006 and 2007 primarily due to foreign exchange fluctuations during the period.”

[D1]; [D2]: The statement on page 94 “During 2005, the company recognized $2 million of hedging losses that, under U.S. GAAP, would have been recognized as hedge ineffectiveness losses in prior periods” was added for additional clarification and should have referred to [D1] instead of [D2]. This error has no impact on “Net earnings from continuing operations, U.S. GAAP” or “Comprehensive income, U.S.

GAAP” as stated on page 93. We will amend this statement in our next filing to show the correct prior year amount.

Reconciliation of changes in accumulated other comprehensive income (OCI):

Effective Portion of Derivatives Designated as Cash Flow Hedges

	Gross		Taxes		Net
Balance at 12/31/2004	(207	)	(69	)	(138	)	to reconciliation of OCI on page 95

- Change in effectiveness for contracts open at 12/31/2004	(274	)	(86	)	(188	)	[E]
- Change in effectiveness for contracts open at 12/31/2004, realized in 2005	258		81		177		[E]
- Effectiveness at 12/31/2004, realized in 2005	215		72		143		To reconciliation of OCI on page 95
- Change in effectiveness for contracts designated as hedges during 2005	11		3		8		[E]
- Change in effectiveness for contracts designated as hedges during 2005, realized in 2005	—		—		—

Balance at 12/31/2005	3		1		2		to reconciliation of OCI on page 95

Sum of [E]: ($3 million) after tax. Equal to “Current period net changes arising from cash flow hedges, net of income taxes of $2 million” as shown in the reconciliation of OCI on page 95.

4. Revise these certifications in an amended filing to conform the title and wording exactly as set forth in General Instruction B(6)(a) of Form 40-F.

We have reviewed our certifications and found a minor discrepancy (a missing “the” in paragraph 5). We also note we were advised by our counsel, Shearman & Sterling, that you requested we delete our officers’ titles from the certifications. We note in future filings we will amend our certifications as attached in Schedule “B”.

Engineering Comments

Required U.S. Oil and Gas and Mining Disclosure, page 22

Net Proved Reserves, page 25

5. We note 78% of your proved bitumen reserves are undeveloped. Please tell us the estimated hydrocarbon volumes, if any, you have claimed as proved reserves:

a. In undrilled fault blocks;

No proved reserves have been claimed in undrilled fault blocks.

b. Below the lowest known – penetrated and assessed – structural occurrence of hydrocarbons;

No proved reserves have been claimed below the lowest known and penetrated and assessed structural occurrence of hydrocarbons.

c. At locations that are not offsetting (adjacent to) productive wells.

If we based our estimation of proved reserves on a ¼ section offset from producing wells, then 48% of our net proved reserves are not offsetting (adjacent to) productive wells. However, we and our third party reserves evaluators have concluded that such an offset criterion is not appropriate to determine with “reasonable certainty” the quantities of proved reserves recoverable in future years from known reservoirs. Instead, we rely on 100% of our proved reserves being within core-hole control.

We are confident that reliance on core-hole control is appropriate to estimate proved reserves recoverable in future years from known reservoirs under assumed economic and operating conditions with reasonable certainty for the following reasons:

(i) our in-situ bitumen property is being developed by proven Steam Assisted Gravity Drainage technology through 1000 m horizontal wells drilled from pads. These wells provide an effective drainage length of approximately 1.2 km;

(ii) our evaluation is based on data from 684 vertical wells drilled on the property, coupled with economic field production;

(iii) core data from vertical wells confirms the presence of analogous reservoir properties in the proved undeveloped areas, when compared to the area currently producing with horizontal wells averaging over 1500 bopd/well;

(iv) of the 684 vertical wells, 135 have been drilled, 130 of which have been cored within the lands designated as proved;

(v) adjacent to and within 1200 m from the proved lands, an additional 58 wells have been drilled and cored;

(vi) the drilling densities of these 193 wells referred to in paragraphs (iv) and (v) are between 8 and 16 wells per section and all the data is incorporated into the field mapping;

(vii) in addition to the numerous wells, 2D and 3D seismic surveys have been conducted supporting the interpretation;

(viii) detailed geological mapping generated based upon these evaluation wells has allowed us to:

a. drill and complete 40 SAGD horizontal well pairs within the proved lands (not all horizontal wells are currently on production due to facility capacity constraints);

b. partially drill an additional 17 SAGD well pairs by December 31, 2005 (these wells will be completed in the future as required to maintain plant capacity); and

c. gain regulatory approval to drill an additional 18 well pairs;

(viii) the aerial extent of the proved reserves has been limited to regions within close proximity to existing wells/pads, generally within approximately 1 km of existing wells/pads, and no farther than 2.4 km from existing wells/pads; and

(ix) the aerial extent of the proved reserves has been limited to regions within close proximity to existing, partially drilled or planned and approved wells/pads and no farther than 1.2 km from those wells/pads.

It is for these reasons, we believe extensive well control, in field analogy and aerial constraints provide the necessary reasonable certainty for our estimation of proved reserves.

6. Please explain the role of “3D seismic control” (page 22) in your proved reserve estimates.

The main use of 3D seismic control is to accurately identify the top and bottom of the reservoir between core-holes to enable accurate placement of horizontal producing wells near the bottom of the reservoir to maximize recovery. The 3D data also confirms reservoir continuity between core-holes and absence of faulting.

Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes, page 28

7. Please amend your standardized measure to disclose your estimated future development costs separately from your estimated future production costs as required by Statement of Financial Accounting Standard 69, paragraph 30(b).

The amended disclosure table below outlines future production and future development costs separately:

($ millions)	2005		2004		2003
Future cash flows	16,444		3,355		11,655
Future production costs	(10,181	)	(640	)	(3,903	)
Future development costs	(1,705	)	(64	)	(1,238	)
Other related future costs	(464	)	(367	)	(391	)
Future income tax expenses	(1,216	)	(460	)	(1,694	)
Subtotal	2,878		1,824		4,429
*Discount at 10%	(1,214	)	(750	)	(2,578	)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	1,664		1,074		1,851

We commit to amend our standardized measure to disclose our estimated future development costs separately from our estimated production costs in future filings.

Production Costs, page 29

8. Your disclosed 2005 unit production cost here is $10.86/BOE while that derived from Results of Operation (page 26) is $13/BOE (=$213 million/16.3 MMBOE). Please reconcile this difference for us and revise your document as necessary.

We note the $13/BOE unit production cost derived from Results of Operation is based on net production volumes. Our per BOE unit production cost disclosure is based on gross production volumes. As required, we noted such costs were disclosed on a “gross” basis. The 2005 cost of $10.86/BOE is derived from the total lifting costs divided by the gross production volumes ($213 million/19.6 MMBOE). Gross production volumes are obtained from our audited consolidated financial statements, page 98 for in-situ production and page 99 for Natural Gas.

Oil and Gas Acreage, page 29

9. Please expand your tables here to disclose material undeveloped acreage subject to expiration in each of the next three years per SEC Industry Guide 2, paragraph 5.

There is no undeveloped acreage subject to expiration in each of the next three years per SEC Industry Guide 2, paragraph 5.

In addition, we acknowledge that:

· Suncor Energy Inc. is responsible for the adequacy and accuracy of the disclosure in our Form 40-F;

· Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to our Form 40-F; and

· Suncor Energy Inc. may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

We trust this information assists you with your review.

Sincerely,

J. Kenneth Alley,

Senior Vice President and Chief Financial Officer

Suncor Energy Inc.

Appendix “A”

Summary of Significant Accounting Policies

(c) Revenues, page 61

Excerpts from EITF 00-21

Paragraph 7

“Revenue arrangements with multiple deliverables should be divided into separate units of accounting if the deliverables in the arrangement meet the criteria in paragraph 9.”

Paragraph 9

“In an arrangement with multiple deliverables, the delivered item (or items) should be considered a separate unit of accounting if all of the following criteria are met:

(a) The delivered item has value to the customer on a stand-alone basis. That item has value on a stand-alone basis if it is sold separately by any vendor or the customer could resell the delivered item on a stand-alone basis. In the context of a customer’s ability to resell the delivered item, the Committee observed that this criterion does not require the existence of an observable market for that deliverable.

(b) There is objective and reliable evidence of the fair value of the undelivered item (or items).

(c) If the arrangement includes a general right of return relative to the delivered item, delivery or performance of the undelivered item is considered probable and substantially in the control of the vendor.”

Excerpts from Staff Accounting Bulletin 104 – Revenue Recognition:

3(d) – License Fee Revenue

“Upon inception of the license term, revenue should be recognized in a manner consistent with the nature of the transaction and the earnings process”

3(f) – Non refundable upfront fees

Question 1 Interpretive Response – “Unless the up-front fee is in exchange for products delivered or services performed that represent the culmination of a separate earnings process, the deferral of revenue is appropriate.”

Question 2 Interpretive Response – “The staff believes that, provided all other revenue recognition criteria are met, service revenue should be recognized on a straight-line basis, unless evidence suggests that the revenue is earned or obligations are fulfilled in a different pattern, over the contractual term of the

arrangement or the expected period during which those specified services will be performed, whichever is longer.”

Notes to the Consolidated Financial Statements

Note 7 – Accrued Liabilities and Other, page 81

Excerpts from FIN 47:

Paragraph 4:

“An asset retirement obligation would be reasonably estimable if (a) it is evident that the fair value of the obligation is embodied in the acquisition price of the asset, (b) an active market exists for the transfer of the obligation, or (c) sufficient information exists to apply an expected present value technique.”

Paragraph 5:

“An entity would have sufficient information to apply an expected present value technique and therefore an asset retirement obligation would be reasonably estimable if either of the following conditions exists:

a. The settlement date and method of settlement for the obligation have been specified by others.

b. The information is available to reasonably estimate (1) the settlement date or the range of potential settlement dates, (2) the method of settlement or potential methods of settlement, and (3) the probabilities associated with the potential settlement dates and potential methods of settlement. Examples of information that is expected to provide a basis for estimating the potential settlement dates, potential methods of settlement, and the associated probabilities include, but are not limited to, information that is derived from the entity’s past practice, industry practice, management’s intent, or the asset’s estimated economic life. In many cases, the determination as to whether the entity has the information to reasonably estimate the fair value of the asset retirement obligation is a matter of judgment that depends on the relevant facts and circumstances.

Footnote 9:

“The estimated economic life of the asset might indicate a potential settlement date for the asset retirement obligation. However, the original estimated economic life of the asset may not, in and of itself, establish that date because the entity may intend to make improvements to the asset that could extend the life of the asset or the entity could defer settlement of the obligation beyond the economic life of the asset. In those situations, the entity would look beyond the economic life of the asset in determining the settlement date or range of potential settlement dates to use when estimating the fair value of the asset retirement obligation.”

Appendix “B”

CERTIFICATION

I, J. KENNETH ALLEY, certify that:

1. I have reviewed this annual report on Form 40-F of Suncor Energy Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this annual report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent function):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

	SUNCOR ENERGY INC.


DATE:	PER:	“J. KENNETH ALLEY”
		J. KENNETH ALLEY
		Senior Vice President and
		Chief Financial Officer