Imperial Oil Limited


Imperial Oil Limited 237 Fourth Avenue SW P.O. Box 2480, Station M Calgary, AB, Canada T2P 3M9		Paul A. Smith Controller and Senior Vice-President Finance and Administration		Tel. (403) 237-4304 Fax (403) 237-2060

September 14, 2006

Ms. Jill S. Davis
Branch Chief
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.W., Stop 7010
Washington, D.C. 20549

Re:

Imperial Oil Limited
Form 10-K for Fiscal Year ended December 31, 2005
Filed March 1, 2006
Form 10-Q for Fiscal Quarter ended March 31, 2006
Filed May 4, 2006
File No. 0-12014

Dear Ms. Davis:

On behalf of Imperial Oil Limited, please find enclosed our responses to your comments regarding the above filings set forth in your letter of July 21, 2006. We appreciate your agreement to extending the timing of our responses pursuant to the July 27, 2006 letter from Mr. Chris Jeans to yourself. Our responses are numbered to correspond to the numbered comments in your letter.

We acknowledge that:

•		the company is responsible for the adequacy and accuracy of the disclosure in the filing;

•		staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•		the company 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.

If you desire a clarification of our responses, please direct any questions to Mr. Chris Jeans, Assistant Controller,
at 403-237-4515.

Yours truly,

/s/ Paul A. Smith

Attachment

Imperial Oil Limited’s Response to the
Comments Included in the SEC Letter of July 21, 2006

Form 10-K for the year ended December 31, 2005

Item 1 Business

Natural Resources, page 7

1.		We note your discussion of the change in royalty arrangements with the Province of Alberta beginning in 2007 relating to your Cold Lake operations in which you expect there to be no material effect. Please expand your discussion to further clarify why the computations of a royalty calculated on gross production, as opposed to a royalty calculated as the greater of one percent on gross revenue or 25 percent of an amount based on revenue net of operating and capital costs would yield an immaterial difference. Please indicate any special adjustments to “operating and capital costs”, “gross production” and “gross revenue” contemplated in the royalty calculation, if any.

		The pre-transition royalty agreement, which applied through the end of 1999, provided for a royalty calculated at the greater of five percent of gross revenue or 30 percent of an amount based on revenue net of operating and capital costs. It also provided for a royalty waiver on equity natural gas produced in Alberta and deemed to be consumed in generating steam at the company’s Cold Lake operations. The post-transition royalty regulation, which will become effective in 2008, provides for a royalty calculated at the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs, but with no gas royalty waiver. A transition agreement, which is effective between 2000 and 2007 inclusive, makes provision for the differences between the two royalty regimes (higher bitumen royalties with gas royalty waiver vs. lower bitumen royalties and no gas royalty waiver). As previously disclosed on page 7 of our 2005 Form 10-K, this change in royalty arrangements, which became effective in 2000, is not expected to materially change the amount of royalties that the company would have otherwise paid under the pre-transition royalty agreement. As to the specific royalties to be paid in 2007, the last year of the transition agreement, and 2008, the first year under the post-transition royalty regulation, it is not possible to predict with certainty whether they would be materially different as a number of factors, including bitumen and gas prices, would have an impact on royalties in each of those years.

		Between 2000 and 2007, during which time the transition agreement is in effect, the terms of that agreement provide that allowable amounts for annual operating costs are increased such that there is no material change in the royalties that are paid as compared to the pre-transition agreement which was in effect prior to 2000. All royalty payments made under the pre-transition agreement and the transition agreement were fully consistent with the written agreements, and no special adjustments were made in the past, or are contemplated in the future.

		We will revise our disclosure in the 2006 Form 10-K to clarify these points.

Page 1 of 11

Government Regulations

Natural Gas, page 16

2.		We note your discussion regarding certain limitations imposed by regulatory bodies which constrain natural gas production. Please expand your disclosure to describe these limitations and the effect they have had and are expected to have, if any, on your operations.

		The regulations do not have any significant effect on Imperial Oil’s current production. However, we will revise our 2006 Form 10-K to better disclose the limitations placed by regulatory authorities as noted on page 15 of the 2005 Form 10-K as follows:

		“The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves, and did not have a significant impact on 2006 gas production rates. As well, these limitations do not apply to gas fields where there are no associated oil reserves.”

Management Discussion and Analysis of Financial Condition and Results of Operation

Results of Operation, page 22

3.		Please explain in further detail the arrangement entered into with the affiliate of Exxon Mobil to operate western Canada production properties as a single organization. Please clarify in your explanation the specific entities involved and the significance of this arrangement to your operations and reserves. Clarify how you have accounted for the formation of this entity and the business purpose for which it was formed. We may have further comment.

		The contractual arrangement is between (i) Imperial Oil Resources and its affiliates (collectively, IOR) and (ii) Exxon Mobil Canada Ltd. (EMCL), an indirect wholly owned subsidiary of Exxon Mobil Corporation. Under the terms of this contract, IOR operates the western Canada properties owned by EMCL. This contractual arrangement is designed to provide organizational efficiencies and to reduce costs. No separate legal entity was created from this arrangement. Separate books of account continue to be maintained for IOR and EMCL. IOR and EMCL retain ownership of their respective assets and there is no impact on operations or reserves.

Critical Accounting Policies

Hydrocarbon Reserves, page 29

The response to comments no. 4 and 9 is shown after comment no. 9

We note your disclosure indicating that 137 million oil-equivalent barrels were not included in reserves because of a seasonal price trough at year end, which pattern is similar to that in the prior year. We note these reserves were “restored” in January 2006. Please expand your disclosure to explain how you calculated this amount and address how often you revise your reserve quantity estimates. Additionally, please explain why the disclosure of these quantities is appropriate. Refer to Instruction 5 to Item 102 of Regulation S-K. We may have further comment.

Page 2 of 11

Financial Statement and Supplementary Data

Net Proved Developed and Undeveloped Reserves, page 34

The response to comments no. 5 and 6 is shown after comment no. 6

5.		Please revise your heading captions to clarify the nature of the oil and gas reserves in each column to avoid investor confusion. We note that you currently use the terms Conventional and Cold Lake.

6.		Please revise the title of “net proved developed and undeveloped reserves” to be consistent with Illustration 4 in Appendix A of SFAS 69.

		We will change the “Cold Lake” heading caption to “Heavy Oil” and improve the clarity of the title of the oil and gas reserves table. Exhibit 1 (attached) shows a revised table that incorporates the changes. We will use this new format for the table on oil and gas reserves in our 2006 Form 10-K.

7.		Please revise your tabular disclosure to present separately the components of your reserve quantity information including, but without limitation, improved recovery, sales of minerals in place and purchases of minerals in place. Refer to Illustration 4 in Appendix A of SFAS 69.

		There were no improved recoveries or purchases of minerals in place during the three-year period reported in the reserve quantity information table in our 2005 Form 10-K. Based on the above, we believe that it was warranted that these components of reserve quantity information were combined with other insignificant components and not separately shown.

8.		Please remove the subtotal of “Total before year end price/cost revisions” and include the effect of year end price/costs revisions within the applicable line item consistent with Illustration 4 in Appendix A of SFAS 69. Additionally, please explain how you calculated the amount reported in your revisions and improved recovery line item as compared to the year end price/cost revisions line item. We may have further comment.

		We believe that the disclosure of the effects of the year-end price/cost revisions was consistent with our reporting obligations. The inclusion of the line showing “Total before year end price/cost revisions” enhances the disclosure by providing additional information to the investor reflecting management’s basis for investment decisions.

		As previously disclosed on page 29 of our 2005 Form 10-K, the use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are required based on prices occurring on a single day. Imperial Oil believes that this approach is inconsistent with the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the company and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.

Page 3 of 11

		Additionally, we believe that the appropriateness of disclosure for this matter should be considered in the light of Paragraph 41 of the Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities”, which states that the illustrations present formats that may (underline added) be used to disclose certain information required by the statement. In this particular instance, we believe that the format in our 2005 Form 10-K provided more useful disclosure than that in Illustration 4 in Appendix A of SFAS 69.

		“Revisions” line items are calculated based on evaluation or revaluation of already available and/or new geologic, reservoir or production data as well as changes to royalty rates and underlying price assumptions. These underlying price assumptions are the same assumptions that are used by management for capital investment decisions and in the company’s annual planning and budgeting processes. There were no changes to report for improved recovery.

		The amounts shown on the “Year end price/cost revisions” line represent the difference in reserves volume from calculating reserves based on price and cost assumptions used by management for capital investment decisions and in the company’s annual planning and budget process and those reserves volumes calculated on the basis of December 31 prices.

9.		We note your disclosure that at Cold Lake proved bitumen and associated natural gas reserves were reduced by about 137 million oil-equivalent barrels as a result of using December 31, 2005 prices. Please clarify how this quantity was calculated and explain why you believe it is appropriate given Instruction 5 to Item 102 of Regulation S-K which states that estimates of oil or gas reserves other than proved are not permitted to be disclosed in any document publicly filed with the Commission.

		During the year, Imperial Oil calculates reserves based on the company’s long term projections of oil and gas prices. In January, when the December 31 price is available, Imperial Oil updates its reserves calculations to reflect that price. For example, based on December 31, 2005 prices, Cold Lake proved bitumen and associated natural gas reserves were reduced by about 137 million oil-equivalent barrels.

		Other than at year end, reserve quantity estimates are evaluated for price changes only if there has been a significant change in the price. In both 2005 and 2006, there was a significant change at Cold Lake due to the difference in price in January versus December 31. For example, in January 2006, the bitumen price increased 49% compared to December 31, 2005. This price resulted in an addition of 137 million oil-equivalent barrels (132 MB of bitumen and 28 BCF of associated natural gas; natural gas is converted to oil equivalent at a ratio of 6,000 cubic feet of gas to 1 barrel of oil). We note that both the lower reserves quantity as of December 31 and the higher reserves quantity as of January were proved reserves.

		We included the disclosure related to the impact of the January price change on reserves because we believed it was meaningful information to our investors that should not be delayed until the first quarter Form 10-Q was issued.

		Consistent with our reporting obligations, we indicated in the MD&A that the use of prices from a single date is not relevant to the investment decisions made by the company and annual variations in reserves based on such year end prices are not of consequence to how the business is managed.

Page 4 of 11

Net Proved Developed Reserves of Crude Oil and Natural Gas, page 36

10.		Please revise your disclosure of proved developed reserves to show beginning and ending of year amounts consistent with Illustration 4 in Appendix A of SFAS 69.

		The reserves quantities shown in the table of proved developed reserve were as of December 31 of each of the years reported. We will clearly indicate this on the table for proved developed reserves in our 2006 Form 10-K.

11.		Please remove your reference to “certain resources” as this may be confusing to investors.

		We will remove the reference to “certain resources” from our 2006 Form 10-K.

General

12.		Please revise your document to include Schedule II Valuation and Qualifying Accounts or tell us where this schedule can be located. Refer to Rule 5-04 of Regulation S-X.

		Allowance for doubtful accounts was Can$10 million and Can$12 million in 2005 and 2004 respectively and was less than one percent of accounts receivable in both years. As disclosed in note 4 on page F-13 in the 2005 Form 10-K, the company did not have any valuation allowance against deferred tax assets in 2005 and 2004. There were no other reserves that meet the requirements for disclosure in Schedule II. Based on the above, we do not believe Schedule II is required.

Auditor’s Report, page F-2

13.		We note your auditors’ report opines on the balance sheets and related consolidated statement of income, shareholders’ equity and cash flows appearing on pages F-3 through F-23, although these statements are only presented on pages F-3 through F-6 with the accompanying notes presented on pages F-7 through F-23. Please have your auditors revise their report to remove these page references.

		Our auditors, PricewaterhouseCoopers LLP, have advised us that they will remove page references in their report in the 2006 Form 10-K.

General

14.		We note the related party matters disclosed on page 49. Please present on the face of your financial statements related party amounts. Refer to Rules 5-02 and 5-03 of Regulation S-X.

		We believe that Note 15 to the consolidated financial statements on transactions with related parties disclosed on page F-22 of our 2005 Form 10-K complied with the intent of Rules 5-02 and 5-03 of Regulation S-X. However, beginning in the 2006 Form 10-K, we will disclose appropriate related party amounts on the face of the financial statements as shown in Exhibit 2 (attached).

Page 5 of 11

Consolidated Balance Sheet, page F-5

15.		Please state on the face of your balance sheet the number of issued and outstanding shares. Refer to Rule 5-02 of Regulation S-X.

		We believe that Note 12 to the consolidated financial statements on common shares disclosed on page F-21 of our 2005 Form 10-K complied with the intent of Rule 5-02 of Regulation S-X. However, beginning in the third quarter 2006 Form 10-Q, we will disclose the number of issued and outstanding shares on the face of the balance sheet as shown in Exhibit 2 (attached).

Consolidated Statement of Shareholders’ Equity, page F-6

16.		Please revise the component title “Nonowner changes in equity” to clarify the nature of this line item and avoid investor confusion.

		A minimum pension liability adjustment is the only item in other nonowner changes in equity for Imperial Oil. Beginning in our 2006 Form 10-K, we will add to the disclosure of other nonowner changes in equity in the consolidated statement of shareholders’ equity to clearly indicate the nature of that item, consistent with the requirements from the Financial Accounting Standards Board’s pending revised standard on “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”.

Note 1 Summary of Significant Accounting Policies

Property, Plant and Equipment, page F-8

17.		We note your disclosure that depreciation and depletion are calculated using the units of production method for producing properties based on proved developed reserves. Please explain the units you use to amortize your acquisition costs of proved properties. Refer to paragraph 30 of SFAS 19.

		Our existing accounting practice of amortizing acquisition costs of proved properties based on total proved oil and gas reserves meets the requirements of paragraph 30 of the Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”. In light of your comment, we will add the following disclosure to the summary of significant accounting policies in our 2006 Form 10-K.

		“Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves.”

		Beginning in our 2006 Form 10-K, we will also modify the disclosure on depreciation and depletion of producing properties on page F-8 to the following:

Page 6 of 11

		“Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas.”

18.		Please explain what you mean by your statement that your accounting policies for your tar sands operations are the same as those for your crude oil and natural gas operations. Note that these represent mining operations and accordingly it is not appropriate to use the successful efforts method to account for these operations. Refer to paragraph 6 of SFAS 19. Accordingly please revise your disclosure to clarify your accounting policies for your mining operations.

		Beginning in our 2006 Form 10-K, we will modify the disclosure to summarize the applicable accounting policies for the company’s tar sands operations and will delete the reference that equates these to the accounting policies for crude oil and natural gas operations.

19.		We note that you expense your stripping costs as incurred. Please expand your disclosure to address the impact, if any, of your adoption of EITF 04-06.

		We considered the applicability of EITF 04-6 to Imperial Oil’s 25-percent participating share in Syncrude’s tar sands operations and concluded that its impact was not material. Imperial Oil’s share of stripping costs was Can$19 million in 2005. When compared to the company’s share of cost of sales of Can$470 million in 2005 and closing inventories of Can$13 million and Can$20 million at December 31, 2004 and 2005, respectively, the impact of capitalizing stripping costs into inventory values would have been less than Can$1 million. Accordingly, we concluded that application of EITF 04-6 was immaterial to the company’s results. Based on the above, we do not believe any changes to the current disclosure are needed.

Asset Retirement Obligations and Other Environmental Liabilities, page F-9

20.

We note your disclosure indicating that you do not record asset retirement obligations for assets with indeterminate useful lives which you identify to be manufacturing, distribution and marketing facilities. We further note that you have determined estimated service lives for these assets, as disclosed on page F-8. Please address the following in detail:

	•		Explain to us whether you have planned maintenance scheduled at regular intervals which affects asset retirement costs and how you considered planned maintenance activities in estimating you asset retirement obligation.

	•		Explain and disclose the specific legal obligations associated with your manufacturing, distribution, and marketing facilities and how you concluded the economic useful lives were indeterminate in light of the assigned service lives. Refer to paragraph 22 of SFAS 143.

All of Imperial Oil’s currently operated manufacturing, distribution and marketing sites are designated for industrial use and so there are no current legal obligations for remediation. The company believes that there are potential future legal obligations for soil remediation and removal of facilities in the event these sites are retired per the definition of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”. However, these sites have indeterminate lives and, as such, potential legal obligations cannot be measured since it is impossible to estimate the future settlement dates of such obligations.

Page 7 of 11

While individual site assets are depreciated on the basis disclosed on page F-8 in our 2005 Form 10-K, the useful life of each site to the company is indeterminate as noted above. Indeterminate site lives have been made possible through proactive annual capital investments that replace or expand existing facilities. For example, capital investment in the petroleum products segment, to which most of these facilities belong, averaged over Can$430 million per year in the period 2001 to 2005. As a further example, capital investments over time have enabled the company’s Sarnia refinery in Ontario, Canada, to be in continuous operations since 1897. There are no plans to retire this facility at any time in the future.

Note 2 Business Segments, page F-11

21.		We note you have aggregated operations associated with conventional oil and gas with operations associated with Bitumen and oil sand extraction, including those associated with your interest in Syncrude, within a single reporting segment. Because the extraction method and refinement process for oil sands and bitumen differ from that of conventional oil and gas, it is unclear how you concluded that aggregating these operations into a single reporting segment is appropriate. In this regard, please provide us your analysis supporting your segment presentation including the authoritative literature underlying your conclusions.

		The natural resources, petroleum products and chemicals functions best define the operating segments of the company because they are the segments

	(a)		that engage in business activities from which revenues are earned and expenses are incurred;

	(b)		whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and

	(c)		for which discrete financial information is available.

		The factors used to identify these operating segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The natural resources segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The petroleum products segment is organized and operates to refine crude oil into petroleum products and to distribute and market these products. The chemicals segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries.

		The definition of the company’s operating segments is based on paragraphs 10 to 15 of the Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information”. We note that the above operating segments, which are regularly reviewed internally by our chief operating decision maker, are identical to our external reporting segments. We also note that there are no requirements in SFAS No.131 to consider the nature of the underlying production or manufacturing processes in making the initial determination of appropriate operating segments. Consideration of the underlying production processes is only applicable if a company is considering aggregating for external reporting two or more of the segments that are regularly reviewed by the company’s chief operating decision maker.

Page 8 of 11

22.		We were unable to locate certain general information disclosures regarding your segment presentation as set-forth in paragraphs 26 of SFAS 131. Please expand your disclosures accordingly or tell us why the information would not be required.

		We have disclosed the basis for our segment reporting in Note 1 to the consolidated financial statements, summary of significant accounting policies, on page F-7 of our Form 10-K.

		However, in light of your comment, beginning in our 2006 Form 10-K, we will expand our current disclosure on segment reporting with the following:

		“The natural resources, petroleum products and chemicals functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The natural resources segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The petroleum products segment is organized and operates to refine crude oil into petroleum products and the distribution and marketing of these products. The chemicals segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries.”

		Beginning in our 2006 Form 10-K, we will move all disclosures related to segment reporting to the note entitled “Business segments” to associate them directly with the segment information reported in that note.

23.		We note your disclosure indicating that incentive compensation previously included in your operating segments has been presented within the corporate and other segment. Please confirm whether employees or management within your natural resource, petroleum, and chemical segments participate in the incentive compensation arrangements and quantify by segment the associated compensation that would have been allocated to each segment. To the extent segment employees participate in the incentive compensation programs, please explain how exclusion of stock based compensation expense from the related segment is appropriate while other compensation is included in your segment presentation. Please also indicate whether or not these costs are included in your disclosure of results of operations for oil and gas producing activities required by paragraph 24 of SFAS 69.

		We believe the reporting of Imperial Oil’s incentive program expenses in the corporate and other segment is more appropriate than the previous allocation of expenses to each operating segment. Imperial Oil’s incentive programs are administered as corporate-wide programs whose objectives are to align the interests of employees with the interests of the company’s shareholders. The programs are intended to promote the general interest of the company as a whole, and not the interests of any individual operating segments. The programs are not intended to compensate for individual segment performance. As a result of these objectives, the programs are standardized for all employee recipients, regardless of which segment they are employed when the awards are granted or settled. This

Page 9 of 11

		standardization reflects the company’s employee development practice of moving employees between segments during the course of their careers. It also reflects the fact that a large number of employees belong to corporate staff and/or service organizations that provide services to multiple operating segments. As such, there is no permanent segment affiliation for any employee.

		For internal reporting to the company’s chief operating decision maker, the costs of these programs are stewarded centrally and not in the segments.

		Except for incentive stock options, which were granted only in 2002, Imperial Oil’s incentive compensation programs are liability awards. Expenses related to the units of these liability-award programs are measured each reporting period based on the company’s current share price. With the volatility of the company’s share prices over the last few years, the reclassification of these costs into the corporate and other segment has provided the investment community with improved transparency and comparability of segment operating results from period to period.

		In response to your request, using the previous allocation methodology, we would have allocated the following after-tax incentive program expenses to each segment in 2005: natural resources Can$84 million, petroleum products segment Can$130 million, chemicals segment Can$24 million.

		We confirm that the costs of the incentive programs have not been included in our disclosure of the results of operations for oil and gas producing activities on page 32 of our 2005 Form 10-K.

Note 11 Commitments and Contingent Liabilities, page F-20

24.		We note your disclosure indicating various lawsuits are pending against the company. Please expand your disclosure to include assessments of the likelihood of these loss contingencies using terms as defined in paragraph 3 of SFAS 5. Confirm whether you have disclosed all reasonably possible contingent losses which could individually or in the aggregate have a material impact on your financial condition.

		The following expanded disclosure will be included in our 2006 Form 10-K “Commitments and contingent liabilities” footnote:

		“The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is determined to be probable and the amount can be reasonably estimated.”

		We confirm that we have disclosed all reasonably possible contingent losses which could individually or in the aggregate have a material impact on Imperial Oil’s financial condition.

Page 10 of 11

Exhibit 1

Oil and Gas Reserves


	Crude oil and natural gas liquids									Natural Gas

	Conventional			Heavy Oil			Total			Total

	(millions of cubic metres)									(billions of
										cubic metres)
Proved developed and undeveloped reserves (1)
Beginning of year 2004		20			121			141			29

Revisions and improved recovery		1			(3	)		(2	)		1
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			—
Production		(3	)		(6	)		(9	)		(5	)

Total before year end price/cost revisions		18			112			130			25
Year end price/cost revisions		—			(75	)		(75	)		(3	)

End of year 2004		18			37			55			22

Remove 2004 year end price/cost revisions		—			75			75			3

Total before 2004 year end price/cost revisions		18			112			130			25

Revisions and improved recovery		(1	)		1			—			2
(Sale)/purchase of reserves in place		(2	)		—			(2	)		—
Discoveries and extensions		—			3			3			—
Production		(3	)		(7	)		(10	)		(5	)

Total before 2005 year end price/cost revisions		12			109			121			22
Year end price/cost revisions		1			(21	)		(20	)		(1	)

End of year 2005		13			88			101			21

Revisions and improved recovery
(Sale)/purchase of reserves in place
Discoveries and extensions
Production

Total before 2006 year end price/cost revisions

Year end price/cost revisions

End of year 2006


(1)		Proved developed and undeveloped reserves reported on this table represent net reserves. Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 101.325 kilopascals absolute at 15 degrees Celsius.

Exhibit 2

Consolidated statement of income


millions of Canadian dollars
For the years ended December 31	2006	2005		2004

Revenues and other income
Operating revenues (a) (b) (c)			27,797		22,408
Investment and other income (note 10)			417		52

Total revenues and other income			28,214		22,460


Expenses
Exploration			43		59
Purchases of crude oil and products (b) (d)			17,168		13,094
Production and manufacturing (e)			3,327		2,820
Selling and general (f)			1,577		1,281
Federal excise tax (a)			1,278		1,264
Depreciation and depletion			895		908
Financing costs (note 14)			8		7

Total expenses			24,296		19,433


Income before income taxes			3,918		3,027

Income taxes (note 4)			1318		975


Net income			2,600		2,052


Per-share information (Canadian dollars)
Net income per common share — basic (note 12)			2.54		1.92
Net income per common share — diluted (note 12)			2.53		1.91
Dividends			0.31		0.29

(a)		Operating revenues include federal excise tax of $xxx million (2005 — $1,278 million, 2004 — $1,264 million).

(b)		Operating revenues include amounts for purchase / sale contracts with the same counterparty (associated costs are included in “purchases of crude oil and products”) of $xxx million (2005 — $4,894 million, 2004 — $3,584 million).

(c)		Operating revenues include amounts from related parties of $xxx million (2005 — $1,357 million, 2004 — $1,176 million)

(d)		Purchases of crude oil and products include amounts from related parties of $xxx million (2005 — $3,599 million, 2004 — $3,133 million)

(e)		Production and manufacturing expenses include amounts from related parties of $xx million (2005 — $xx million, 2004 — $xx million)

(f)		Selling and general expenses include amounts from related parties of $xx million (2005 — $xx million, 2004 — $xx million)

Page 1 of 2

Exhibit 2

Consolidated balance sheet


millions of Canadian dollars
At December 31	2006	2005

Assets
Current assets
Cash			1,661
Accounts receivable, less estimated doubtful amounts			2,040
Inventories of crude oil and products (note 13)			481
Materials, supplies and prepaid expenses			130
Deferred income tax assets (note 4)			654

Total current assets			4,966
Investments and other long-term assets			127
Property, plant and equipment, less accumulated depreciation and depletion (note 2)			10,132
Goodwill (note 2)			204
Other intangible assets, net			153

Total assets (note 2)			15,582


Liabilities
Current liabilities
Short-term debt			99
Accounts payable and accrued liabilities (note 15) (a)			3,170
Income taxes payable			1,399
Current portion of long-term debt (b)			477

Total current liabilities			5,145
Long-term debt (note 3) (c)			863
Other long-term obligations (note 7)			1,728
Deferred income tax liabilities (note 4)			1,213
Commitments and contingent liabilities (note 11)

Total liabilities			8,949


Shareholders’ equity
Common shares at stated value (note 12) (d)			1,747
Earnings reinvested			5,466
Accumulated other nonowner changes in equity			(580	)

Total shareholders’ equity			6,633


Total liabilities and shareholders’ equity			15,582

(a)		Accounts payable and accrued liabilities include amounts to related parties of $xxx million (2005 — $224 million)

(b)		Current portion of long-term debt include amounts to related parties of $xxx million (2005 — Nil)

(c)		Long-term debt include amounts to related parties of $xxx million (2005 — $818 million)

(d)		Number of common shares outstanding was xxx million ( 2005 — 333 million)

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25.		Please revise your interim report on Form 10-Q as necessary to comply with all applicable comments written on your annual report above.

		To the extent applicable, we have indicated in our responses above the revised disclosures that will be included in our third quarter 2006 Form 10-Q.