Petro-canada 40-F 2004 FY Annual report (Canada)

Exhibit 99.1

PETRO-CANADA

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEAR ENDED

DECEMBER 31, 2004

MANAGEMENT’S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS

The preparation and presentation of the Company’s Consolidated Financial Statements and the overall quality of the Company’s financial reporting are the responsibility of management. The financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include estimates which are based on management’s best judgments. Information contained elsewhere in the Annual Report is consistent, where applicable, with that contained in the financial statements.

Management is also responsible for installing and maintaining a system of internal controls to provide reasonable assurance that assets are safeguarded and that reliable financial information is produced for preparation of financial statements, and believes that the system of internal controls they have installed has operated effectively in 2004.

Deloitte & Touche LLP, a firm of chartered accountants, were appointed by the shareholders as external auditors of the Company to conduct an independent examination and express their opinion on the Consolidated Financial Statements. The Auditors’ Report outlines the auditors’ opinion and the scope of their examination. The services provided to the Company by the external auditors are now restricted to the audit of the Consolidated Financial Statements and audit-related services. The only non-audit service provided was the licensing of access to industry databases and the Company cancelled those licences in 2004. The Company engaged PricewaterhouseCoopers LLP as contract auditor to provide internal audit services.

The Board of Directors is responsible for overseeing management’s performance of its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility with the assistance of the Audit, Finance and Risk Committee of the Board of Directors.

Ron A. Brenneman	E.F.H. Roberts
President and Chief Executive Officer	Executive Vice-President and Chief Financial Officer
February 16, 2005

AUDIT, FINANCE AND RISK COMMITTEE OF THE BOARD OF DIRECTORS

The Audit, Finance and Risk Committee, which is composed of not fewer than three (currently six) directors who are not employees of the Company, assists the Board of Directors in the discharge of its responsibility for overseeing management’s performance of the financial reporting and internal control responsibilities. The Committee reviews the annual and quarterly Consolidated Financial Statements, accounting policies and the overall quality of the Company’s financial reporting, and the financial information contained in prospectuses and in reports filed with regulatory authorities, as required. The Committee also reviews and makes recommendations to the Board of Directors regarding financial matters and oversees the process that management has in place to identify business risks.

With respect to the external auditors, the Committee reviews and approves the terms of engagement, the scope and plan for the external audit and reviews the results of the audit and the Auditors’ Report. The external auditors report to the Committee and to the Board of Directors. The Committee discusses the external auditors’ independence from management and the Company with the auditors and receives written confirmation of their independence. The Committee also recommends to the Board of Directors the external auditors to be appointed by the shareholders and approves in advance fees for the external auditors’ services.

With respect to the contract auditor’s engagement to provide internal audit services, the Committee reviews the engagement contract, reviews and approves the scope and plan for the internal audit, receives periodic reports and reviews significant findings and recommendations. The contract auditor reports to the Committee and to the Board of Directors.

Senior management, the external auditors and the contract auditor attend all Audit, Finance and Risk Committee meetings and each is provided with the opportunity to meet privately with the Committee.

Paul D. Melnuk

Chairman of the Audit, Finance and Risk Committee

February 16, 2005

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AUDITORS’ REPORTS

To the Shareholders of Petro-Canada:

We have audited the Consolidated Balance Sheet of Petro-Canada as at December 31, 2004 and 2003 and the Consolidated Statements of Earnings, Retained Earnings and Cash Flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these Consolidated Financial Statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.

The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Deloitte & Touche LLP

Chartered Accountants

Calgary, Alberta, Canada

February 16, 2005

COMMENTS BY AUDITORS ON CANADA-UNITED STATES OF AMERICA
REPORTING DIFFERENCE

In the United States of America, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have been implemented in the financial statements, such as the changes described in Note 2 to the Consolidated Financial Statements of Petro-Canada. Our report to the shareholders dated February 16, 2005 is expressed in accordance with Canadian reporting standards, which do not require a reference to such changes in accounting principles in the Auditors’ Report when the changes are properly accounted for and adequately disclosed in the financial statements.

Deloitte & Touche LLP

Chartered Accountants

Calgary, Alberta, Canada

February 16, 2005

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Consolidated Statement of Earnings

(stated in millions of Canadian dollars, except per share amounts)

For the years ended December 31,	2004			2003			2002
				(Note 2)			(Note 2)
REVENUE
Operating	$	14,687		$	12,887		$	10,374
Investment and other income (Note 4)	(310		)	12			—
	14,377			12,899			10,374
EXPENSES
Crude oil and product purchases	6,740			5,620			4,837
Operating, marketing and general (Note 5)	2,690			2,557			2,222
Exploration (Note 15)	235			271			301
Depreciation, depletion and amortization (Notes 5 and 15)	1,402			1,560			977
Foreign currency translation (Note 6)	(77		)	(251		)	52
Interest	142			182			187
	11,132			9,939			8,576
EARNINGS BEFORE INCOME TAXES	3,245			2,960			1,798
PROVISION FOR INCOME TAXES(Note 7)
Current	1,461			1,247			959
Future	27			63			(116		)
	1,488			1,310			843
NET EARNINGS	$	1,757		$	1,650		$	955
EARNINGS PER SHARE (Note 8)
Basic	$	6.64		$	6.23		$	3.63
Diluted	$	6.55		$	6.16		$	3.59

Consolidated Statement of Retained Earnings

(stated in millions of Canadian dollars)

For the years ended December 31,	2004			2003			2002
				(Note 2)			(Note 2)
RETAINED EARNINGS AT BEGINNING OF YEAR, as previously reported	$	3,943		$	2,380		$	1,511
Retroactive application of change in accounting for asset retirement obligations (Note 2)	(133		)	(114		)	(95		)
RETAINED EARNINGS AT BEGINNING OF YEAR, as restated	$	3,810		$	2,266		$	1,416
Net earnings	1,757			1,650			955
Dividends on common shares	(159		)	(106		)	(105		)
RETAINED EARNINGS AT END OF YEAR	$	5,408		$	3,810		$	2,266

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Consolidated Statement of Cash Flows

(stated in millions of Canadian dollars)

For the years ended December 31,	2004			2003			2002
				(Note 2)			(Note 2)
OPERATING ACTIVITIES
Net earnings	$	1,757		$	1,650		$	955
Items not affecting cash flow from operating activities before changes in non-cash working capital (Note 9)	1,755			1,451			1,020
Exploration expenses (Note 15)	235			271			301
Cash flow from operating activities before changes in non-cash working capital	3,747			3,372			2,276
Proceeds from sale of accounts receivable (Note 11)	399			—			—
(Increase) decrease in other non-cash working capital related to operating activities (Note 10)	133			(164		)	(226		)
Cash flow from operating activities	4,279			3,208			2,050
INVESTING ACTIVITIES
Expenditures on property, plant and equipment and exploration (Note 15)	(4,073		)	(2,315		)	(1,861		)
Proceeds from sales of assets	44			165			26
Increase in deferred charges and other assets	(36		)	(147		)	(72		)
Acquisition of Prima Energy Corporation (Note 12)	(644		)	—			—
Acquisition of oil and gas operations of Veba Oil & Gas GmbH (Note 12)	—			—			(2,234		)
(Increase) decrease in non-cash working capital related to investing activities (Note 10)	10			94			(16		)
	(4,699		)	(2,203		)	(4,157		)
FINANCING ACTIVITIES
Increase in short-term notes payable	314			—			—
Proceeds from issue of long-term debt	533			804			2,100
Repayment of long-term debt	(299		)	(1,352		)	(465		)
Proceeds from issue of common shares	39			50			30
Purchase of common shares (Note 20)	(447		)	—			—
Dividends on common shares	(159		)	(106		)	(105		)
Increase in non-cash working capital related to financing activities (Note 10)	(26		)	—			—
	(45		)	(604		)	1,560
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(465		)	401			(547		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	635			234			781
CASH AND CASH EQUIVALENTS AT END OF YEAR(Note 13)	$	170		$	635		$	234

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Consolidated Balance Sheet

(stated in millions of Canadian dollars)

As at December 31,	2004		2003
			(Note 2)
ASSETS
CURRENT ASSETS
Cash and cash equivalents (Note 13)	$	170	$	635
Accounts receivable (Note 11)	1,254		1,503
Inventories (Note 14)	549		551
Prepaid expenses	13		16
	1,986		2,705
PROPERTY, PLANT AND EQUIPMENT, NET(Note 15)	14,783		10,943
GOODWILL (Note 12)	986		810
DEFERRED CHARGES AND OTHER ASSETS (Note 16)	345		316
	$	18,100	$	14,774
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	2,223	$	1,822
Income taxes payable	370		300
Short-term notes payable	299		—
Current portion of long-term debt (Note 17)	6		6
	2,898		2,128
LONG-TERM DEBT  (Note 17)	2,275		2,223
OTHER LIABILITIES  (Note 18)	646		306
ASSET RETIREMENT OBLIGATIONS (Note 19)	834		773
FUTURE INCOME TAXES (Note 7)	2,708		1,756
COMMITMENTS AND CONTINGENT LIABILITIES (Note 25)
SHAREHOLDERS’ EQUITY (Note 20)	8,739		7,588
	$	18,100	$	14,774

Approved on behalf of the Board of Directors
Ron A. Brenneman	Brian F. MacNeill
Director	Director

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Notes to Consolidated Financial Statements

(stated in millions of Canadian dollars, unless otherwise stated)

Note 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of Presentation

The Consolidated Financial Statements include the accounts of Petro-Canada and of all subsidiary companies (the Company) and are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Differences between Canadian and United States GAAP are explained in Note 26 to the Consolidated Financial Statements.

Substantially all of the Company’s exploration and development activities are conducted jointly with others. Only the Company’s proportionate interest in such activities is reflected in the Consolidated Financial Statements.

The preparation of the Consolidated Financial Statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingencies. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates used in the preparation of the financial statements include, but are not limited to, the estimates of oil and gas reserves, asset retirement obligations, income taxes and employee future benefits.

(b) Revenue Recognition

Revenue from the sale of crude oil, natural gas, natural gas liquids, purchased products and refined petroleum products is recorded when title passes to the customer. Inter-segment sales are accounted for at market values and included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer; these amounts are eliminated on consolidation.

International operations conducted pursuant to exploration and production-sharing agreements (EPSAs) are reflected in the Consolidated Financial Statements based on the Company’s working interest in such operations. Under the EPSAs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each EPSA establishes specific terms for the Company to recover these costs (Cost Recovery Oil) in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year and to share in the production profits (Profit Oil). Profit Oil is that portion of production remaining after deducting Cost Recovery Oil and is shared between the joint venture partners and the government of each country, varying with the level of production. Profit Oil that is attributable to the government includes an amount in respect of all deemed income taxes payable by the Company under the laws of the respective country. All other government stakes, other than income taxes, are considered to be royalty interests.

(c) Foreign Currency Translation

Monetary assets and liabilities are translated into Canadian dollars at rates of exchange in effect at the balance sheet date. With the exception of items pertaining to self-sustaining operations, the other assets and related depreciation, depletion and amortization, other liabilities, revenue and other expense items are translated into Canadian dollars at rates of exchange in effect at the respective transaction dates. The resulting exchange gains or losses are included in earnings.

The Company’s International business segment and the U.S. Rockies upstream operations included in the North American Natural Gas business segment are operated on a self-sustaining basis. Assets and liabilities of these segments, including associated long-term debt, are translated into Canadian dollars at period end exchange rates, while revenues and expenses are converted using average rates for the period. Gains and losses from the translation into Canadian dollars are deferred and included in the foreign currency translation adjustment as part of shareholders’ equity.

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(d) Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, future income taxes are recognized, using substantively enacted income tax rates, based on the differences between the carrying amounts of assets and liabilities reported in the financial statements and their respective tax bases. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period the change occurs.

(e) Earnings Per Share

Basic earnings per share are calculated by dividing the net earnings available to common shareholders by the weighted-average number of common shares outstanding. Diluted earnings per share reflect the potential dilution that would occur if stock options, excluding stock options with a cash payment alternative, were exercised. The treasury stock method is used in calculating diluted earnings per share, which assumes that any proceeds received from the exercise of in-the-money stock options would be used to purchase common shares at the average market price for the period.

(f) Cash and Cash Equivalents

Cash and cash equivalents comprise cash in banks, less outstanding cheques, and short-term investments with a maturity of less than 90 days when purchased. Short-term investments are recorded at the lower of cost or market value.

(g) Sale of Accounts Receivable

The transfers of accounts receivable are accounted for as sales, other than the retained interest, when the Company has surrendered control over the transferred receivables and received proceeds. Gains or losses are recognized as other income or expenses and are dependent upon the purchase discount as well as the previous carrying amount of the receivables transferred, which is allocated between the receivables sold and the retained interest, based on their relative fair values at the date of the transfer. Fair value is determined based on the present value of future expected cash flows.

(h) Inventories

Inventories are stated at the lower of cost and net realizable value. Cost of crude oil and product purchases is determined primarily on a “last-in, first-out” (LIFO) basis.

(i) Investments

Investments in companies over which the Company has significant influence are accounted for using the equity method. Other long-term investments are accounted for using the cost method.

(j) Property, Plant and Equipment

Investments in exploration and development activities are accounted for using the successful efforts method. Under this method, the acquisition cost of unproved acreage is capitalized. Costs of exploratory wells are initially capitalized pending determination of proved reserves. Costs of wells which are assigned proved reserves remain capitalized, while costs of unsuccessful wells are charged to earnings. All other exploration costs, including geological and geophysical costs, are charged to earnings as incurred. Development costs, including the cost of all wells, are capitalized.

The interest cost of debt attributable to the construction of major new facilities is capitalized during the construction period.

Producing properties and significant unproved properties are assessed annually, or as economic events dictate, for potential impairment. Impairment is assessed by comparing the estimated net undiscounted future cash flows to the carrying value of the asset. If required, the impairment recorded is the amount by which the carrying value of the asset exceeds its fair value.

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(k) Depreciation, Depletion and Amortization

Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using the unit of production method.

Depreciation of other plant and equipment is provided on either the unit of production method or the straight line method, based on the estimated service lives of the related assets, as appropriate.

Deferred financing costs are amortized over the term of the related liability.

Costs associated with significant development projects are not depleted until commencement of commercial production.

(l) Asset Retirement Obligations

The fair values of estimated asset retirement obligations are recorded as liabilities when incurred and the associated cost is capitalized as part of the cost of the related asset. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. The associated accretion is recorded in operating expense and the depreciation is included in depreciation, depletion and amortization expense.

Asset retirement obligations for Downstream sites are provided when the incurrence is established as a result of a legal obligation to restore the site or when the Company intends to restore the site.

Asset retirement obligations are not recorded for those assets which have an indeterminate useful life.

(m) Goodwill

Goodwill is the excess purchase price over the fair value of identifiable assets and liabilities acquired. Goodwill impairment is assessed annually at year end, or more frequently as economic events dictate, by comparing the fair value of the reporting unit to its carrying value, including goodwill. If the fair value of the reporting unit is less than its carrying value, a goodwill impairment loss is recognized as the excess of the carrying value of the goodwill over the fair value of the goodwill.

(n) Stock-Based Compensation

The Company maintains stock option, performance share unit and deferred stock unit plans as described in Note 21 to the Consolidated Financial Statements.

The Company accounts for stock options granted prior to 2003 based on the intrinsic value at the grant date, which does not result in a charge to earnings because the exercise price was equal to the market price at grant date.

Stock options granted in 2003 are accounted for using the fair value method. Fair values are determined, at the grant date, using the Black-Scholes option pricing model. The compensation expense associated with these options is charged to earnings over the vesting period with a corresponding increase in contributed surplus. On the exercise of stock options, consideration paid and the associated contributed surplus is credited to common shares.

Stock options granted subsequent to 2003, which provide the holder with a cash payment alternative, are accounted for based on the intrinsic value at each period end whereby a liability and expense are recorded over the vesting period in the amount by which the then current market price exceeds the option exercise price.

Performance share units (PSUs) are accounted for on a mark-to-market basis over the term of the PSUs whereby a liability and expense are recorded based on the number of PSUs outstanding, the current market price of the Company’s shares and the Company’s current total shareholder return relative to the selected industry peer group.

Deferred stock units (DSUs) are accounted for on a mark-to-market basis whereby a liability and expense are recorded each period based on the number of DSUs outstanding and the current market price of the Company’s shares.

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(o) Employee Future Benefits

The Company’s employee future benefit programs consist of both defined benefit and defined contribution pension plans, as well as other post-retirement benefits as described in Note 22 to the Consolidated Financial Statements.

The Company records its obligations under employee benefit plans, net of plan assets where applicable. The costs of pensions and other post-retirement benefits are actuarially determined using the projected benefit method pro rated based on service and using management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. For the purpose of calculating the expected return on plan assets, those assets are measured at fair value. The accrued benefit obligation is discounted using a market rate of interest at the beginning of the year on high quality corporate debt instruments. Company contributions to the defined contribution plan are expensed as incurred.

(p) Hedging and Derivative Financial Instruments

The Company may use derivative financial instruments to manage its exposure to market risks resulting from fluctuations in foreign exchange rates, interest rates and commodity prices. These derivative financial instruments are not used for speculative purposes and a system of controls is maintained that includes a policy covering the authorization, reporting and monitoring of derivative activity.

The Company formally documents all derivative instruments designated as hedges, the risk management objective, and the strategy for undertaking the hedge.

Gains and losses on derivatives that are designated as and determined to be effective hedges are deferred and recognized in the period of settlement as a component of the related transaction. The Company assesses both at inception and over the term of the hedging relationship, whether the derivative instruments used in the hedging transactions are highly effective in offsetting changes in the fair value or cash flows of hedged items. If a derivative instrument ceases to be effective or is terminated, hedge accounting is discontinued. The accumulated gains and losses continue to be deferred and recognized in the Consolidated Statement of Earnings in the period of settlement of the related transaction; future gains or losses are recognized in the Consolidated Statement of Earnings in the period they occur.

Derivative instruments that are not designated as hedges for accounting purposes are recorded on the Consolidated Balance Sheet at fair value with any resulting gain or loss recognized in the Consolidated Statement of Earnings in the current period.

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Note 2 CHANGES IN ACCOUNTING POLICIES

Asset Retirement Obligations

Effective January 1, 2004, the Company retroactively adopted the new standard of the Canadian Institute of Chartered Accountants (CICA) on accounting for asset retirement obligations. The new standard requires the fair values of asset retirement obligations to be recorded as liabilities when incurred and the related assets be increased by the amount of these liabilities. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets. Asset retirement obligations are not recorded for those assets which have an indeterminate useful life. The change results in a decrease in net earnings of $4 million for the year ended December 31, 2004 (decrease in net earnings of $19 million for the year ended December 31, 2003 and $19 million for the year ended December 31, 2002). The change also resulted, at December 31, 2004, in an increase in asset retirement obligations of $403 million (increase of $391 million as at December 31, 2003), an increase in property, plant and equipment of $189 million (increase of $184 million as at December 31, 2003), a decrease in retained earnings of $137 million (decrease of $133 million as at December 31, 2003) and a decrease in future income taxes of $77 million (decrease of $74 million as at December 31, 2003).

Reclassification of Costs

Pursuant to the new CICA section 1100 “Generally Accepted Accounting Principles,” which provides guidance on the sources to consult when selecting accounting policies, the Company began accounting, effective January 1, 2004, for certain transportation costs, third-party gas purchases and diluent purchases as expenses in the Consolidated Statement of Earnings. Previously, these costs were netted against revenue. Prior years’ comparatives have been restated. The change in accounting has no effect on net earnings but has increased revenue and expenses as follows:

	2004		2003		2002
Operating revenue	$	801	$	678	$	457
Crude oil and product purchases	650		522		281
Operating, marketing and general	151		156		176
Net earnings	$	—	$	—	$	—

Hedging Relationships

Effective January 1, 2004, the Company adopted Accounting Guideline 13 (AcG 13) “Hedging Relationships” which resulted in changes to the conditions as to when hedge accounting may be obtained. As a result, certain of the Company’s risk management derivative instruments no longer qualify as accounting hedges and are accounted for as required under Emerging Issues Committee (EIC) 128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments.” EIC 128 requires that all derivative instruments that do not qualify or are not designated as a hedge under AcG 13 be recorded on the balance sheet at fair value as either an asset or liability with changes in fair value recognized in earnings (see Note 23 to the Consolidated Financial Statements).

Employee Future Benefits

The Company has adopted the amendments made to CICA handbook section 3461, “Employee Future Benefits.” The amendments require additional disclosures (see Note 22 to the Consolidated Financial Statements) and have no effect on the financial results of the Company.

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Note 3 SEGMENTED INFORMATION

The Company is an integrated oil and gas company with a portfolio of businesses spanning both the upstream and downstream sectors of the industry. The Company conducts its business through five major operating business segments along with Shared Services. Upstream activities are conducted through four business segments, which include North American Natural Gas, East Coast Oil, Oil Sands and International; Downstream operations comprise the fifth business segment.

Upstream operations include the exploration, development, production, transportation and marketing activities for crude oil, natural gas and natural gas liquids and oil sands. The North American Natural Gas segment includes activity in Western Canada, the U.S. Rockies, the Mackenzie Delta/Corridor, Offshore Nova Scotia and Alaska. The East Coast Oil segment comprises activity Offshore Newfoundland and Labrador, and includes interests in the Hibernia and Terra Nova oilfield operations as well as an interest in the White Rose oilfield currently under development. The Oil Sands segment includes an interest in the Syncrude oil sands mining operation as well as the MacKay River in situ oil sands operation. The International segment includes activity primarily in the United Kingdom, The Netherlands, Trinidad, Venezuela, Syria, Libya, Algeria and Tunisia.

The Downstream business segment includes the purchase and sale of crude oil, the refining of crude oil products and the distribution and marketing of these and other purchased products. Financial information by business segment is presented in the following table as though each segment were a separate business entity. Inter-segment transfers of products, which are accounted for at market value, are eliminated on consolidation. Shared Services includes investment income, interest expense, foreign currency translation and general corporate revenue and expense. Shared Services assets are principally cash and cash equivalents and other general corporate assets.

	UPSTREAM
	NORTH AMERICAN NATURAL GAS								EAST COAST OIL							OIL SANDS
	2004			2003		2002			2004		2003			2002		2004			2003			2002
Revenue(1), (2)
Sales to customers and other revenues	$	1,773		$	1,756	$	1,185		$	911	$	817		$	618	$	412		$	235		$	8
Inter-segment sales	215			190		183			527		482			379		548			391			406
Segment revenue	1,988			1,946		1,368			1,438		1,299			997		960			626			414
Expenses
Crude oil and product purchases	359			366		278			—		—			—		291			156			3
Inter-segment transactions	9			7		3			5		—			—		49			36			—
Operating, marketing and general	379			330		309			120		121			141		362			332			245
Exploration	119			146		206			2		47			17		16			23			23
Depreciation, depletion and amortization	321			269		264			268		267			225		69			179			30
Foreign currency translation	—			—		—			—		—			—		—			—			—
Interest	—			—		—			—		—			—		—			—			—
	1,187			1,118		1,060			395		435			383		787			726			301
Earnings before income taxes	801			828		308			1,043		864			614		173			(100		)	113
Provision for income taxes
Current	330			227		268			323		313			172		(71		)	(20		)	(26		)
Future	(29		)	109		(128		)	9		(46		)	14		124			(28		)	61
	301			336		140			332		267			186		53			(48		)	35
Net earnings	$	500		$	492	$	168		$	711	$	597		$	428	$	120		$	(52	)	$	78
Capital and exploration expenditures
Property, plant and equipment and exploration expenditures	$	724		$	560	$	530		$	278	$	344		$	289	$	399		$	448		$	462
Deferred charges and other assets	6			4		(3		)	1		4			—		—			—			—
Acquisition of oil and gas operations of Veba Oil & Gas GmbH, including goodwill	—			—		—			—		—			—		—			—			—
Acquisition of Prima Energy Corporation, including goodwill	644			—		—			—		—			—		—			—			—
	$	1,374		$	564	$	527		$	279	$	348		$	289	$	399		$	448		$	462
Cash flow from operating activities before changes in non-cash working capital	$	940		$	985	$	534		$	996	$	869		$	687	$	334		$	127		$	196
Total assets(3)	$	3,477		$	2,341	$	2,285		$	2,265	$	2,288		$	2,249	$	1,883		$	1,770		$	1,498

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	UPSTREAM
	INTERNATIONAL							DOWNSTREAM									SHARED SERVICES									CONSOLIDATED
	2004			2003		2002		2004			2003			2002			2004			2003			2002			2004			2003			2002
Revenue(1), (2)
Sales to customers and other revenues	$	1,851		$	1,945	$	1,239	$	9,420		$	8,145		$	7,318		$	10		$	1		$	6		$	14,377		$	12,899		$	10,374
Inter-segment sales	—			—		—		14			7			3			—			—			—
Segment revenue	1,851			1,945		1,239		9,434			8,152			7,321			10			1			6			14,377			12,899			10,374
Expenses
Crude oil and product purchases	—			—		—		6,093			5,099			4,556			(3		)	(1		)	—			6,740			5,620			4,837
Inter-segment transactions	—			—		—		1,241			1,027			968			—			—			—
Operating, marketing and general	437			407		288		1,328			1,293			1,179			64			74			60			2,690			2,557			2,222
Exploration	98			55		55		—			—			—			—			—			—			235			271			301
Depreciation, depletion and amortization	466			444		249		277			400			208			1			1			1			1,402			1,560			977
Foreign currency translation	—			—		—		—			—			—			(77		)	(251		)	52			(77		)	(251		)	52
Interest	—			—		—		—			—			—			142			182			187			142			182			187
	1,001			906		592		8,939			7,819			6,911			127			5			300			11,132			9,939			8,576
Earnings before income taxes	850			1,039		647		495			333			410			(117		)	(4		)	(294		)	3,245			2,960			1,798
Provision for income taxes
Current	727			644		413		226			204			242			(74		)	(121		)	(110		)	1,461			1,247			959
Future	(52		)	88		9		(45		)	(119		)	(84		)	20			59			12			27			63			(116		)
	675			732		422		181			85			158			(54		)	(62		)	(98		)	1,488			1,310			843

Net earnings	$	175	$	307	$	225	$	314	$	248	$	252	$		(63	)	$			58		$	(196	)	$	1,757	$	1,650	$	955
Capital and exploration expenditures
Property, plant and equipment and exploration expenditures	$	1,824	$	525	$	221	$	839	$	424	$	344	$		9		$		14			$	15		$	4,073	$	2,315	$	1,861
Deferred charges and other assets	—		—		—		26		53		27		3				86					48			36		147		72
Acquisition of oil and gas operations of Veba Oil & Gas GmbH, including goodwill	—		—		2,234		—		—		—		—				—					—			—		—		2,234
Acquisition of Prima Energy Corporation, including goodwill	—		—		—		—		—		—		—				—					—			644		—		—
	$	1,824	$	525	$	2,455	$	865	$	477	$	371	$		12		$	100				$	63		$	4,753	$	2,462	$	4,167
Cash flow from operating activities before changes in non-cash working capital	$	1,027	$	890	$	583	$	556	$	601	$	380	$		(106	)	$	(100			)	$	(104	)	$	3,747	$	3,372	$	2,276
Total assets(3)	$	5,954	$	3,973	$	3,544	$	4,462	$	3,827	$	3,836	$	59			$	575				$	132		$	18,100	$	14,774	$	13,544

(1)There were no customers that represented 10% or more of the Company’s consolidated revenues for the periods presented.

(2)North American Natural Gas revenue for 2004 includes $54 million (2003 – nil; 2002 – nil) attributable to the U.S. Rockies operations.

(3)North American Natural Gas assets include $919 million (2003 – $6 million; 2002 – $7 million) attributable to the U.S. Rockies and Alaska operations.

53

Note 4 INVESTMENT AND OTHER INCOME

Investment and other income includes $329 million (2003 – nil; 2002 – nil) for unrealized losses on derivative contracts, of which $333 million (2003 – nil; 2002 – nil) relates to the outstanding Buzzard derivative contracts (see Note 23 to the Consolidated Financial Statements), and $12 million (2003 – $42 million; 2002 – $(2) million) for net gains (losses) on disposal of assets.

Note 5 ASSET WRITEDOWNS

Following a review of its Eastern Canada refining and supply operations, Petro-Canada announced in September 2003 it will be ceasing its Oakville refining operations and expanding the existing terminalling facilities. The total charge to earnings related to the shutdown, which is now expected to occur in the first half of 2005, is approximately $200 million after-tax. The following expenses have been recorded in the Downstream segment:

	2004				2003
	Pre-Tax		After-Tax		Pre-Tax		After-Tax
Operating, marketing and general expense (de-commissioning and employee related costs)	$	3	$	2	$	54	$	32
Depreciation and amortization expense (asset write-downs and increased depreciation)	71		44		196		119
	$	74	$	46	$	250	$	151

Depreciation, depletion and amortization expense for the year ended December 31, 2003 also includes $136 million ($82 million after-tax) relating mainly to engineering costs incurred in finalizing the Company’s strategy for converting the Edmonton refinery to process an oil sands feedstock and charges of $46 million ($46 million after-tax) relating to the impairment of assets in Kazakhstan. The charges were recorded in the Oil Sands and International business segments respectively.

Note 6 FOREIGN CURRENCY TRANSLATION

Foreign currency translation consists of:

	2004			2003			2002
Gain on translation of foreign currency denominated long-term debt(1)	$	(77	)	$	(251	)	$	(11	)
Loss on translation of International business segment(2)	—			—			63
	$	(77	)	$	(251	)	$	52

(1)Gains or losses on foreign currency denominated long-term debt associated with the self-sustaining International business segment and the U.S. Rockies operations included in the North American Natural Gas business segment are deferred and included as part of shareholders’ equity.

(2)Prior to 2003, the International business segment did not operate on a self-sustaining basis. Gains and losses from translation of its financial statements and associated long-term debt into Canadian dollars were included in the Consolidated Statement of Earnings.

54

Note 7 INCOME TAXES

The computation of the provision for income taxes, which requires adjustment to earnings before income taxes for non-taxable and non-deductible items, is as follows:

	2004			2003			2002
Earnings before income taxes	$	3,245		$	2,960		$	1,798
Add (deduct):
Non-deductible royalties and other payments to provincial governments, net	352			392			277
Resource allowance	(512		)	(542		)	(467		)
Equity in earnings of affiliates	(15		)	(11		)	(9		)
Non-taxable foreign exchange	(40		)	(237		)	52
Other	5			28			(3		)
Earnings as adjusted before income taxes	$	3,035		$	2,590		$	1,648
Canadian Federal income tax rate	38.0		%	38.0		%	38.0		%
Income tax on earnings as adjusted at Canadian
Federal income tax rate	$	1,153		$	984		$	626
Large Corporations Tax	17			16			16
Provincial income taxes	271			194			130
Federal – abatement and other credits	(274		)	(167		)	(102		)
Future income taxes (decrease) increase due to federal and provincial rate changes	(13		)	(45		)	4
Higher foreign income tax rates	357			337			176
Income tax credits and other	(23		)	(9		)	(7		)
Provision for income taxes	$	1,488		$	1,310		$	843
Effective income tax rate on earnings before income taxes	45.9		%	44.3		%	46.9		%

Future income taxes consists of the following future income tax liabilities (assets) relating to temporary differences for:

	2004			2003
Property, plant and equipment	$	2,961		$	2,010
Partnership income(1)	404			381
Inventories	(184		)	(134		)
Asset retirement obligations and other liabilities	(318		)	(333		)
Deferred charges and other assets	55			43
Resource allowance and other	(210		)	(211		)
	$	2,708		$	1,756

(1)Taxable income for certain Canadian Upstream activities are generated by a partnership and the related taxes will be included in current income taxes in the next year.

Deferred distribution taxes associated with International business operations have not been recorded. Based on current plans, repatriation of funds in excess of foreign reinvestment will not result in material additional tax expense.

Complex income tax issues, which involve interpretations of continually changing regulations, are encountered in computing the provision for income taxes. Management believes that adequate provision has been made for all such outstanding issues and that the resolution of these issues would not materially affect the financial position of the Company.

55

Note 8 EARNINGS PER SHARE

The weighted-average number of common shares outstanding used in the calculation of basic earnings per share and diluted earnings per share, assuming that all dilutive outstanding stock options were exercised, was:

	2004	2003	2002
Average shares outstanding (millions)
Basic	264.6	264.9	262.8
Diluted	268.1	267.9	265.7

For the year ended December 31, 2004, no stock options (2003 – nil stock options; 2002 – 375,700 stock options with an exercise price of $45.68) were excluded from the diluted earnings per share calculation. Stock options are excluded when the exercise price exceeds the average share price in a respective period. The average share price in 2002 was $42.70.

Note 9 ITEMS NOT AFFECTING CASH FLOW FROM OPERATING ACTIVITIES BEFORE CHANGES IN NON-CASH WORKING CAPITAL

	2004			2003			2002
Depreciation, depletion and amortization	$	1,402		$	1,560		$	977
Future income taxes	27			63			(116		)
Accretion of asset retirement obligations	50			64			37
Unrealized gain on translation of foreign currency denominated long-term debt	(77		)	(251		)	(11		)
(Gain) loss on disposal of assets	(12		)	(42		)	2
Amortization of debt issue costs	6			22			14
Unrealized loss associated with the Buzzard derivative contracts	333			—			—
Unrealized foreign currency losses	—			—			90
Other	26			35			27
	$	1,755		$	1,451		$	1,020

Note 10 (INCREASE) DECREASE IN NON-CASH WORKING CAPITAL

	2004			2003			2002
Operating activities
Accounts receivable	$	(88	)	$	93		$	(268	)
Inventories	4			34			(74		)
Prepaid expenses	6			3			9
Accounts payable and accrued liabilities	247			(219		)	467
Income taxes payable	71			37			(313		)
Current portion of long-term liabilities and other	(107		)	(112		)	(47		)
	$	133		$	(164	)	$	(226	)
Investing activities
Accounts payable and accrued liabilities	$	10		$	94		$	(16	)
Financing activities
Accounts payable and accrued liabilities	$	(26	)	$	—		$	—

Non-cash working capital is comprised of current assets and current liabilities, other than cash and cash equivalents and the current portion of long-term debt.

56

Note 11 SECURITIZATION PROGRAM

In June 2004, the Company entered into a securitization program, expiring in 2009, to sell an undivided interest of eligible accounts receivable up to $400 million to a third party, on a revolving and fully serviced basis. The service liability has been estimated to be insignificant. The Company also retains an interest in the transferred accounts receivable equal to the required reserves amount.

The Company accounts for the securitization program as a sale, as control over the transferred accounts receivable is relinquished once proceeds from the third party have been received. Gains or losses from the sale are recognized in investment and other income.

As at December 31, 2004, $400 million of outstanding accounts receivable had been sold under the program for net proceeds of $399 million.

Note 12 BUSINESS ACQUISITIONS

Prima Energy Corporation

On July 28, 2004, the Company acquired all of the common shares of Prima Energy Corporation (Prima), an oil and gas company with operations in the U.S. Rockies, for a total acquisition cost of $644 million, net of cash acquired. The results of operations are included in the Consolidated Financial Statements from the date of acquisition. Funding for the acquisition was provided by a $400 million US underwritten credit facility, cash and cash equivalents and existing committed bank credit lines.

Veba Oil & Gas GmbH

On May 2, 2002, the Company acquired the shares of companies holding the majority of the international oil and gas operations of Veba Oil & Gas GmbH (Veba) and on December 10, 2002, the Company acquired certain of the remaining operations which were subject to rights of first refusal. The total acquisition cost, consisting of cash consideration and acquisition costs, was $2,234 million and the results of these operations have been included in the Consolidated Financial Statements from the dates of acquisition. Funds for the acquisition were provided from credit facilities arranged with certain banks and from cash and cash equivalents.

Both acquisitions were accounted for by the purchase method of accounting. The allocations of fair values to the assets acquired and liabilities assumed were:

	2004		2002
	Prima		Veba
Property, plant and equipment	$	688	$	2,012
Goodwill	193		709
Current assets(1)	36		640
Deferred charges and other assets	2		6
Total assets acquired	919		3,367
Current liabilities	41		634
Future income taxes	217		387
Asset retirement obligations and other liabilities	17		112
Total liabilities assumed	275		1,133
Net assets acquired	$	644	$	2,234

(1)Current assets exclude cash of $74 million for Prima and $15 million for Veba.

Goodwill, which is not tax deductible, was assigned to the Company’s North American Natural Gas business segment for Prima and to the Company’s International business segment for Veba.

57

Note 13 CASH AND CASH EQUIVALENTS

	2004			2003
Cash	$	169		$	60
Less: outstanding cheques	(65		)	(39		)
	104			21
Short-term investments	66			614
	$	170		$	635

Cash payments for interest and income taxes were as follows:

	2004		2003		2002
Interest	$	165	$	156	$	178
Income taxes	$	1,477	$	1,232	$	1,172

Note 14 INVENTORIES

	2004		2003
Crude oil, refined products and merchandise	$	383	$	394
Materials and supplies	166		157
	$	549	$	551

Note 15 PROPERTY, PLANT AND EQUIPMENT

			2004								2003						2004			2003
			Accumulated								Accumulated									Expenditures
			Depreciation,								Depreciation,									on Property,
			Depletion and								Depletion and									Plant and
	Cost		Amortization			Net		Cost			Amortization			Net						Equipment(1), (2)
Upstream
North American Natural Gas	$	5,521	$		2,491	$	3,030	$		4,299	$	2,184		$		2,115	$	605		$	414
East Coast Oil	3,274		1,094			2,180		2,993			837			2,156			276			297
Oil Sands	2,417		628			1,789		2,218			568			1,650			383			425
International	5,471		1,011			4,460		2,988			549			2,439			1,726			470
	16,683		5,224			11,459		12,498			4,138			8,360			2,990			1,606
Downstream
Refining	3,372		1,220			2,152		3,178			1,690			1,488			662			303
Marketing and other	2,358		1,218			1,140		2,284			1,225			1,059			177			121
	5,730		2,438			3,292		5,462			2,915			2,547			839			424
Other property, plant and equipment	458		426			32		449			413			36			9			14
	$	22,871	$	8,088		$	14,783	$	18,409		$		7,466	$	10,943		$		3,838	$	2,044

(1)Exploration expenses of $235 million (2003 – $271 million; 2002 – $301 million) charged to earnings are reclassified from operating activities and included with expenditures on property, plant and equipment and exploration under investing activities in the Consolidated Statement of Cash Flows.

(2)Expenditures on property, plant and equipment and exploration for the year ended December 31, 2004 include the Company’s purchase of a 29.9% interest in the Buzzard field and nearby exploration blocks in the U.K. sector of the North Sea for $1,218 million ($887 million US), net of cash received.

Property, plant and equipment net cost includes asset retirement costs of $297 million (2003 – $292 million).

Interest capitalized during 2004 amounted to $20 million (2003 – $7 million; 2002 – $4 million).

Costs of $577 million (2003 – $422 million) relating to non-producing East Coast Oil projects, $2,587 million (2003 – $314 million) relating to the International operations and $338 million (2003 – nil) relating to U.S. Rockies operations are currently not being depleted.

Capital leases at a net cost of $67 million (2003 – $70 million) and $27 million (2003 – $29 million) are included in the assets of East Coast Oil and Oil Sands, respectively (see Note 17 to the Consolidated Financial Statements).

58

Note 16 DEFERRED CHARGES AND OTHER ASSETS

	2004		2003
Investments	$	78	$	72
Deferred pension funding	71		49
Deferred financing costs	98		97
Other long-term assets	98		98
	$	345	$	316

Note 17 LONG-TERM DEBT

	Maturity	2004			2003
Debentures and notes
5.35% unsecured senior notes(1) ($300 million US)	2033	$	361		$	388
7.00% unsecured debentures ($250 million US)	2028	301			323
7.875% unsecured debentures ($275 million US)	2026	331			355
9.25% unsecured debentures ($300 million US)	2021	361			388
5.00% unsecured senior notes(2) ($400 million US)	2014	481			—
4.00% unsecured senior notes(1) ($300 million US)	2013	361			388
Capital leases (Note 15)(3)	2007-2017	85			94
Acquisition credit facilities(4)	2005	—			293
		2,281			2,229
Current portion		(6		)	(6		)
		$	2,275		$	2,223

(1)In anticipation of issuing these senior notes, the Company entered into interest rate derivatives which resulted in effective interest rates of 6.073% for the 5.35% notes due in 2033 and 4.838% for the 4.00% notes due in 2013.

(2)The Company established a $400 million US underwritten credit facility to partially fund the acquisition of Prima Energy Corporation (see Note 12 to the Consolidated Financial Statements). On November 8, 2004, the Company issued these senior notes, the proceeds of which were used to repay the credit facility.

(3)The Company is party to a transportation agreement to transport bitumen from the MacKay River production facilities to the Athabasca Pipeline Terminal. The agreement is for an initial term of 15 years ending in 2017 and is extendable at the Company’s option for an additional 10 years.

The Company is party to an agreement for the time charter and operation of a vessel for the transportation of East Coast Oil crude oil production. The agreement is for an initial term of 10 years ending in 2007 and extendable at the Company’s option for up to an additional 15 years.

The transportation and time charter agreements are accounted for as capital leases and have implicit rates of interest of 14.65% and 11.90%, respectively. The aggregate remaining repayments under the transportation and time charter agreements are $85 million, including the following amounts in the next five years: 2005 – $6 million; 2006 – $7 million; 2007 – $7 million; 2008 – $2 million; 2009 – $3 million.

(4)The Company established two unsecured credit facilities with certain banks for the acquisition of the oil and gas operations of Veba Oil & Gas GmbH (see Note 12 to the Consolidated Financial Statements). The credit facilities totaled $3,320 million, of which $2,100 million was drawn in the form of floating rate Canadian dollar bankers’ acceptances in 2002. At December 31, 2003, the amount of the facilities was $743 million, of which $293 million was outstanding. During 2004, the Company sold $400 million under a new accounts receivable securitization program (see Note 11 to the Consolidated Financial Statements) and a portion of the proceeds was used to repay the remaining $293 million of advances.

Interest on long-term debt, net of capitalized interest, was $132 million in 2004 (2003 – $177 million; 2002 – $182 million).

The Company’s syndicated operating credit facilities totaled $1,500 million to be used for general corporate purposes.

Note 18 OTHER LIABILITIES

	2004		2003
Post-retirement benefits	$	164	$	153
Unrealized loss on Buzzard derivative contracts	333		—
Other long-term liabilities	149		153
	$	646	$	306

59

Note 19 ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations are recorded for obligations where the Company will be required to retire tangible long-lived assets such as well sites, offshore production platforms, natural gas processing plants and marketing sites. Obligations are currently not recorded for assets, principally refineries, upgrading assets and certain gas plants, which have an indeterminate life.

The following table summarizes the changes in the asset retirement obligations:

	2004			2003
Asset retirement obligations at beginning of year	$	773		$	642
Obligations incurred	67			97
Abandonment expenditures	(44		)	(33		)
Accretion expense	50			64
Other	(12		)	3
Asset retirement obligations at end of year	$	834		$	773

In determining the fair value of the asset retirement obligations, the estimated cash flows have been discounted at 6.5%. The total undiscounted amount of the estimated cash flows required to settle the obligations is $2,417 million (2003 – $2,121 million). The obligations will be settled on an ongoing basis over the useful lives of the operating assets, which extend up to 45 years in the future.

Note 20 SHAREHOLDERS’ EQUITY

	2004		2003
Common shares	$	1,314	$	1,308
Contributed surplus	1,743		2,147
Retained earnings	5,408		3,810
Foreign currency translation adjustment	274		323
	$	8,739	$	7,588

The authorized share capital is comprised of an unlimited number of:

(a) Preferred shares issuable in series designated as Senior Preferred Shares.

(b) Preferred shares issuable in series designated as Junior Preferred Shares.

(c) Common shares.

Changes in common shares and contributed surplus were as follows:

						2004						2003
						Contributed						Contributed
	Shares		Amount			Surplus			Shares	Amount		Surplus
Balance at beginning of year	265,586,093		$	1,308		$	2,147		263,594,977	$	1,258	$	2,138
Issued for cash under employee stock option and share purchase plans	1,246,000		39			—			1,991,116	50		—
Repurchases of common shares	(6,868,082	)	(34		)	(413		)	—	—		—
Stock-based compensation	—		1			9			—	—		9
Balance at end of year	259,964,011		$	1,314		$	1,743		265,586,093	$	1,308	$	2,147

Under the terms of a normal course issuer bid (NCIB), the Company is entitled to purchase up to 21 million of its common shares during the period from June 22, 2004 to June 21, 2005, subject to certain conditions. During 2004, the Company repurchased 6,868,082 common shares under the NCIB at an average price of $65.02 per common share for a total cost of approximately $447 million. The excess of purchase cost over the carrying amount of the shares purchased was recorded as a reduction of contributed surplus.

60

Note 21 STOCK BASED COMPENSATION

Stock Options

The Company maintains a stock option plan whereby options can be granted to officers and certain employees for up to 22 million common shares. Stock options have a term of 10 years if granted prior to 2004 and seven years if granted subsequent to 2003. All stock options vest over periods of up to four years and are exercisable at the market prices for the shares on the dates that the options were granted.

During 2004, the Company amended the option plan to provide the holder of stock options granted subsequent to 2003 the alternative to exercise these options as a cash payment alternative (CPA). Where the CPA is chosen, vested options can be surrendered for cancellation in return for a direct cash payment from the Company based on the excess of the then market price over the option exercise price.

Changes in the number of outstanding stock options were as follows:

			2004				2003				2002
			Weighted-Average				Weighted-Average				Weighted-Average
	Number		Exercise Price		Number		Exercise Price		Number		Exercise Price
			(dollars)				(dollars)				(dollars)
Balance at beginning of year	8,620,593		$	37	8,225,984		$	30	7,216,770		$	26
Granted	1,836,700		58		2,481,000		51		2,482,700		36
Exercised	(1,246,000	)	31		(1,991,116	)	25		(1,403,936	)	22
Cancelled	(173,944	)	45		(95,275	)	41		(69,550	)	30
Balance at end of year	9,037,349		$	42	8,620,593		$	37	8,225,984		$	30

The following stock options were outstanding as at December 31, 2004:

				Options Outstanding			Options Exercisable
	Range of		Weighted-Average	Weighted-Average			Weighted-Average
Number	Exercise Prices		Life	Exercise Price		Number	Exercise Price
	(dollars)		(years)	(dollars)			(dollars)
419,677	$	11 to 18	1.1	$	16	419,677	$	16
758,925	19 to 25		4.5	21		758,925	21
1,976,832	26 to 35		6.5	33		1,175,957	32
1,850,025	36 to 46		6.3	39		1,305,550	38
2,217,690	47 to 56		8.1	51		554,423	51
1,814,200	57 to 67		6.2	57		—	—
9,037,349	$	11 to 67	6.4	$	42	4,214,532	$	33

During 2004, the Company recorded compensation expense of $10 million (2003 – $9 million) relating to the 2003 stock options and $3 million (2003 – nil) relating to options with a CPA.

61

The following table presents the pro forma net earnings and the pro forma earnings per share computed assuming the fair value based accounting method had been used to account for the compensation cost of stock options granted in 2002.

	2004		Earnings per Share				2003		Earnings per Share				2002		Earnings per Share
	Net Earnings		Basic		Diluted		Net Earnings		Basic		Diluted		Net Earnings		Basic		Diluted
			(dollars)		(dollars)				(dollars)		(dollars)				(dollars)		(dollars)
Net earnings as reported	$	1,757	$	6.64	$	6.55	$	1,650	$	6.23	$	6.16	$	955	$	3.63	$	3.59
Pro forma adjustment	9		0.03		0.03		8		0.03		0.03		6		0.02		0.02
Pro forma net earnings	$	1,748	$	6.61	$	6.52	$	1,642	$	6.20	$	6.13	$	949	$	3.61	$	3.57

The estimated fair value of stock options granted in 2003, which is charged to earnings, was $17.50 per share. The estimated weighted-average fair value of stock options granted in 2002, which is incorporated in the pro forma earnings information above, was $12.74 per share. The fair values have been determined using the Black-Scholes option-pricing model with the following assumptions:

	2003		2002
Risk-free interest rate	4.4	%	4.9	%
Expected hold period to exercise	6 years		6 years
Volatility in the market price of common shares	32	%	33	%
Estimated annual dividend	1.4	%	1.4	%

Performance Share Units

During 2004, the Company implemented a Performance Share Unit (PSU) plan for officers and other senior management employees. Under the PSU program, notional share units are awarded and settled in cash at the end of a three-year period based upon the Company’s share price at that time, the value of notional dividends applied during the period and the Company’s total shareholder return relative to a peer group of North American industry competitors.

Changes in the number of outstanding PSUs were as follows:

	Number
Balance at beginning of year	—
Granted	284,880
Expired	—
Cancelled	(1,950	)
Balance at end of year	282,930

All PSUs outstanding at the end of the year have a performance period ending in 2007. Based on the mark-to-market value at December 31, 2004, no compensation expense relating to PSUs was recorded.

Deferred Share Units

The Company maintains a Deferred Stock Unit (DSU) plan where executive officers can elect to receive all or a portion of their annual incentive compensation in the form of DSUs. Under the officer DSU program, notional share units are issued for the elected amount, which is based on the then current market price of the Company’s common shares. Upon termination or retirement, the units are settled in cash which includes an amount for the value of notional dividends earned over the period the units were outstanding.

The Company’s Board of Directors receives a portion of their compensation in the form of DSUs and can also elect to receive all or a portion of their non-DSU compensation in the form of DSUs. Under the Director program, notional share units are issued and settled in cash or common shares, including the value of notional dividends, upon ceasing to be a Director.

During 2004, no compensation expense relating to DSUs was recorded (2003 – $6 million; 2002 – $3 million).

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Note 22 EMPLOYEE FUTURE BENEFITS

The Company maintains pension plans with defined benefit and defined contribution provisions, and provides certain health care and life insurance benefits to its qualifying retirees. The actuarially determined cost of these benefits is accrued over the estimated service life of employees. The defined benefit provisions are generally based upon years of service and average salary during the final years of employment. Certain defined benefit options require employee contributions and the balance of the funding for the registered plans is provided by the Company, based upon the advice of an independent actuary. The accrued benefit obligations and the fair value of plan assets are measured for accounting purposes at December 31 of each year. The most recent actuarial valuation of the pension plan for funding purposes was as of December 31, 2002 and the next required valuation will be as of December 31, 2004.

The defined contribution option provides for an annual contribution of 5% to 8% of each participating employee’s pensionable earnings.

	Pension Plans									Other Post-Retirement Plans
Benefit Plan Expense	2004			2003			2002			2004			2003			2002
(a) Defined benefit plans
Employer current service cost	$	31		$	27		$	25		$	4		$	4		$	3
Interest cost	81			78			74			13			12			11
Actual return on plan assets	(91		)	(115		)	91			—			—			—
Actuarial losses (gains)	97			99			12			(15		)	17			7
Elements of employee future benefit plan expenses before adjustments to recognize the long-term nature of employee future benefit plan expenses	118			89			202			2			33			21
Difference between actual and expected return on plan assets	12			50			(174		)	—			—			—
Difference between actual and recognized actuarial losses in year	(67		)	(73		)	(5		)	16			(17		)	(7		)
Amortization of transitional (asset) obligation	(5		)	(5		)	(5		)	2			2			2
	58			61			18			20			18			16
(b) Defined contribution plans	13			11			10
Total expense	$	71		$	72		$	28		$	20		$	18		$	16
Benefit Plan Funding
Defined contribution	13			11			10
Defined benefit	$	80		$	75		$	12		$	9		$	8		$	7

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	Pension Plans						Other Post- Retirement Plans
Financial Status of Defined Benefit Plans	2004			2003			2004			2003
Fair value of plan assets	$	1,157		$	1,052		$	—		$	—
Accrued benefit obligation	1,487			1,344			204			211
Funded status – plan deficit(1)	(330		)	(292		)	(204		)	(211		)
Unamortized transitional (asset) obligation	(29		)	(34		)	17			19
Unamortized net actuarial losses	430			375			23			39
Accrued benefit asset (liability)	$	71		$	49		$	(164	)	$	(153	)
Reconciliation of Plan Assets
Fair value of plan assets at beginning of year	$	1,052		$	927		$	—		$	—
Contributions	80			75			9			8
Benefits paid	(67		)	(63		)	(9		)	(8		)
Actual gain (loss) on plan assets	91			115			—			—
Other	1			(2		)	—			—
Fair value of plan assets at end of year	$	1,157		$	1,052		$	—		$	—
Reconciliation of Accrued Benefit Obligation
Accrued benefit obligation at beginning of year	$	1,344		$	1,206		$	211		$	186
Current service cost	31			27			4			4
Interest cost	81			78			13			12
Benefits paid	(67		)	(63		)	(9		)	(8		)
Actuarial losses (gains)	97			99			(15		)	17
Other	1			(3		)	—			—
Accrued benefit obligation at end of year	$	1,487		$	1,344		$	204		$	211

(1)The pension and other post-retirement plans included in the financial status information are not fully funded.

Defined Benefit and Other Post-Retirement Plans Assumptions	2004		2003		2002
Year-end obligation discount rate(1)	5.7	%	6.0	%	6.5	%
Accrued benefit obligation discount rate(1)	6.0	%	6.5	%	6.5	%
Long-term rate of return on plan assets	7.5	%	7.5	%	8.0	%
Rate of compensation increase, excluding merit increases	3.0	%	3.0	%	3.0	%

(1)Assumption used in both pension and other post-retirement benefit plans.

Assumed Health and Dental Care Cost Trend Rates at December 31 are as follows:	2004		2003
Dental care cost trend rate(1)	3.5	%	3.5	%
Health care cost trend rate	8.5	%	7.5	%
Health care cost trend rate declines to	4.5	%	4.5	%
Year that health care cost trend rate reaches the rate which it is expected to remain at	2014		2009

(1)Dental care cost trend rate assumed to remain constant.

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Sensitivity Analysis

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects for 2004:

	Increase		Decrease
Total of service and interest cost	$	2	$	(2	)
Accrued benefit obligation	$	24	$	(22	)

The Plan Assets consist of:

	Percentage of Plan Assets at December 31,
Asset Category	2004		2003
Equity	44	%	42	%
Bonds	56	%	58	%
Total	100	%	100	%

Note 23 FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the course of its normal business operations. The Company monitors its exposure to market fluctuations and may use derivative instruments to manage these risks, as it considers appropriate.

Crude Oil and Products

The Company enters into forward contracts and options to reduce exposure to Downstream margin fluctuations, including margins on fixed-price product sales, and short-term price fluctuations on the purchase of foreign and domestic crude oil and refined products.

The Company has also entered into a series of forward sales contracts for the future sale of Brent crude oil in connection with its 2004 acquisition of an interest in the Buzzard field in the U.K. sector of the North Sea (see Note 15 to the Consolidated Financial Statements).

The Company’s outstanding contracts for derivative instruments and the related fair values at December 31, 2004 were as follows:

	Quantity	Maturity	Average Price		Unrealized Gain/(Loss)
			US$/bbl
Crude Oil and Products (millions of barrels)
Crude oil purchase	2.7	2005	$	40.33	$	4
Buzzard crude oil sales	35.8	2007-2010	$	25.98	$	(333	)
					$	(329	)

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As at December 31, 2004, the unrealized loss on derivative contracts has decreased investment and other income by $329 million and increased accounts receivable, accounts payable and accrued liabilities, and other liabilities by $5 million, $1 million and $333 million, respectively.

The fair value of these derivative instruments is based on quotes provided by brokers, which represents an approximation of amounts that would be received or paid to counterparties to settle these instruments prior to maturity. The Company plans to hold all derivative instruments outstanding at December 31, 2004 to maturity.

Derivative and financial instruments involve a degree of credit risk. The Company manages this risk through the establishment of credit policies and limits which are applied in the selection of counterparties. Market risk relating to changes in value or settlement cost of the Company’s derivative instruments is essentially offset by gains or losses on the hedged positions.

In addition to the derivative instruments described above, the Consolidated Balance Sheet includes other items considered to be financial instruments, such as cash, accounts receivable, accounts payable and accrued liabilities and notes payable. The fair values of these other financial instruments included in the Consolidated Balance Sheet are as follows:

				2004						2003
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Financial instruments included in current assets and current liabilities	$	(1,098	)	$	(1,098	)	$	316		$	316
Long-term debt	$	(2,281	)	$	(2,538	)	$	(2,229	)	$	(2,432	)

The fair value of financial instruments included in current assets and current liabilities, excluding the current portion of long-term debt, approximates the carrying amount of these instruments due to their short maturity. The fair value of long-term debt is based on publicly quoted market values.

Note 24 RELATED PARTY TRANSACTIONS

On September 29, 2004, the Government of Canada completed its offering to the public of its entire remaining interest in Petro-Canada. Transactions with the Government of Canada and its agencies prior to the sale were in the normal course of business and on the same terms as those accorded to non-related parties.

Note 25 COMMITMENTS AND CONTINGENT LIABILITIES

(a) The Company has leased property and equipment under various long-term operating leases for periods up to 2013. The minimum annual rentals for non-cancellable operating leases are estimated at $122 million in 2005, $102 million in 2006, $80 million in 2007, $68 million in 2008, $61 million in 2009 and $217 million thereafter.

(b) The Company is involved in litigation and claims in the normal course of operations. In addition, the Company may provide indemnifications, in the course of normal operations, that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid. Management is of the opinion that any resulting settlements relating to the litigation matters or indemnifications would not materially affect the financial position of the Company.

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Note 26 GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN THE UNITED STATES

The Company’s Consolidated Financial Statements have been prepared in accordance with Canadian GAAP, which differ in some respects from those applicable in the United States. The following are the significant differences in accounting principles as they pertain to the accompanying Consolidated Financial Statements:

(a) Income Taxes

The liability method followed by the Company differs from United States GAAP due to the application of transitional provisions upon adoption, the use of substantively enacted versus enacted tax rates and the accounting for certain Canadian income tax credits and allowances.

(b) Interest Capitalization

United States GAAP requires that interest be capitalized as part of the cost of certain assets while they are being prepared for their intended use. The Company capitalizes interest attributable to the construction of major new facilities and does not capitalize interest on all assets that would require interest capitalization under United States GAAP.

(c) Contributed Surplus

In prior years, the Company transferred amounts from contributed surplus to the accumulated deficit. Under United States GAAP, these transfers would not have occurred.

(d) Derivative Instruments and Hedging

Under United States GAAP, the accounting for derivative instruments and hedging activities is contained in the Statement of Financial Accounting Standards No. 133 (SFAS 133). SFAS 133 establishes accounting and reporting standards requiring that all derivative instruments be recorded in the balance sheet as either an asset or a liability measured at fair value and requires that changes in the fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The recently amended Canadian rules, Accounting Guideline 13 (AcG 13) “Hedging Relationships” and EIC 128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments” (see Note 2 to the Consolidated Financial Statements), have eliminated the GAAP difference for all derivatives that are not accounted for as hedges for 2004 and future years. A GAAP difference still exists for the treatment of cash flow hedges as changes in the fair value of cash flow hedges are included in other comprehensive income under United States GAAP.

(e) Minimum Pension Liability

United States GAAP requires a minimum pension liability be recorded for underfunded pension plans. The change in the minimum liability, representing the excess of unfunded accumulated benefit obligations over previously recorded pension cost liabilities, is recognized in other comprehensive income.

(f) Comprehensive Income

United States GAAP utilizes the concept of comprehensive income, which includes net earnings and other comprehensive income. There is no similar concept under Canadian GAAP. Other comprehensive income represents the change in equity during the period from transactions and other events from non-owner sources and includes such items as changes in the fair value of cash flow hedges, minimum pension liability adjustments and certain foreign currency translation adjustments.

(g) Asset Retirement Obligations

Under United States GAAP, the accounting for asset retirement obligations is contained in the Statement of Financial Accounting Standards No. 143 (SFAS 143) which was effective January 1, 2003. Changes to the equivalent Canadian accounting standards were effective January 1, 2004 (see Note 2 to the Consolidated Financial Statements) which has eliminated this GAAP difference in 2004 and in future years. Under United States GAAP, the cumulative effect adjustment from initial application is required to be charged to net earnings in the year the standard became effective. Canadian GAAP requires the change in accounting policy be applied retroactively and that prior periods presented for comparative purposes be restated.

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The application of United States GAAP would have the following effects on earnings as reported:

	2004			2003			2002
Net earnings as reported in the Consolidated Statement of Earnings	$	1,757		$	1,650		$	955
Adjustments, before income taxes
Capitalization of interest and related amortization	8			21			25
Accounting for income taxes	(27		)	(9		)	(111		)
Asset retirement obligations	—			—			30
Other	1			—			(3		)
Income taxes on above items	9			13			(1		)
Net earnings, as adjusted before cumulative effect of change in accounting policy	1,748			1,675			895
Cumulative effect of change in accounting policy, net of income taxes	—			(114		)	—
Net earnings, as adjusted	$	1,748		$	1,561		$	895
Earnings, as adjusted before cumulative effect of change in accounting policy per share
Basic	$	6.61		$	6.32		$	3.41
Diluted	$	6.52		$	6.25		$	3.37
Earnings, as adjusted per share
Basic	$	6.61		$	5.89		$	3.41
Diluted	$	6.52		$	5.83		$	3.37
Comprehensive income
Net earnings, as adjusted	$	1,748		$	1,561		$	895
Unrealized gain (loss) on financial derivatives	(5		)	8			4
Minimum pension liability	(36		)	(11		)	(111		)
Foreign currency translation adjustment	(49		)	323			—
	$	1,658		$	1,881		$	788

The application of United States GAAP would have the following effects on the Consolidated Balance Sheets as reported:

			December 31, 2004				December 31, 2003
	As Reported		United States GAAP		As Reported		United States GAAP
Current assets	$	1,986	$	1,986	$	2,705	$	2,705
Property, plant and equipment, net	14,783		15,337		10,943		11,521
Goodwill	986		965		810		789
Deferred charges and other assets	345		344		316		314
Current liabilities	2,898		2,898		2,128		2,119
Long-term debt	2,275		2,275		2,223		2,223
Other liabilities	646		910		306		436
Asset retirement obligations	834		834		773		773
Future income taxes	2,708		2,894		1,756		2,058
Common shares	1,314		1,314		1,308		1,308
Contributed surplus	1,743		2,865		2,147		3,269
Retained earnings	5,408		4,526		3,810		2,937
Foreign currency translation adjustment	274		—		323		—
Accumulated other comprehensive income	$	—	$	116	$	—	$	206

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Note 27 RECENT ACCOUNTING PRONOUNCEMENTS

Canadian

Variable Interest Entities (VIEs)

The Accounting Standards Board (ACSB) issued Accounting Guideline AcG 15, “Consolidation of Variable Interest Entities,” to harmonize the Guideline with the equivalent United States Standard Financial Accounting Standards Board (FASB) Interpretation No. 46R, “Consolidation of Variable Interest Entities.” The Guideline provides criteria for identifying VIEs and further criteria for determining what entity, if any, should consolidate them. The Guideline is effective for annual and interim periods beginning on or after November 1, 2004, and upon adoption, will not materially impact the Consolidated Financial Statements.

Financial Instruments – Disclosure and Presentation

The ACSB approved a revision to section 3860 “Financial Instruments – Disclosure and Presentation,” to require certain obligations that must or could be settled with an entity’s own equity instruments to be represented as liabilities. The revision is effective for fiscal years beginning on or after November 1, 2004. The Company does not expect there to be any impact on the Consolidated Financial Statements upon adoption of this revised standard.

United States

Exchanges of Non-Monetary Assets

The FASB issued Statement of Financial Accounting Standards No. 153 (SFAS 153), “Exchanges of Non-Monetary Assets” as an amendment to Accounting Principles Board Opinion No. 29 (APB 29), “Accounting for Non-Monetary Transactions.” APB 29 prescribes that exchanges of non-monetary transactions should be measured based on the fair value of the assets exchanged, while providing an exception for non-monetary exchanges of similar productive assets. SFAS 153 eliminates the exception provided in APB 29 and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. SFAS 153 is to be applied prospectively and is effective for all non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not expect there to be any material effect on the Consolidated Financial Statements upon adoption of the new standard.

Inventory Costs

The FASB issued SFAS 151, “Inventory Costs” as an amendment to Accounting Research Bulletin No. 43 (ARB 43). Under ARB 43, certain expenses might be considered to be so abnormal that, under certain circumstances, they would require treatment as current period charges. SFAS 151 eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. SFAS 151 is to be applied prospectively and is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the standard.

Share-Based Payment

The FASB issued SFAS 123(R), “Share-Based Payment,” a revision to SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) eliminates the intrinsic value accounting option in APB Opinion 25, “Accounting for Stock Issued to Employees,” and generally requires the use of the fair-value based method of accounting for share based payment transactions with employees. In addition, the standard no longer permits entities to account for forfeitures as they occur but requires this amount to be estimated. SFAS 123(R) is effective for the reporting periods that begin after June 15, 2005 and may be applied under a modified prospective approach or a modified retrospective approach. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of this revised standard under the modified prospective approach or the modified retrospective approach.

Discontinued Operations

The Emerging Issues Task Force issued EITF Abstract 03-13 (EITF 03-13) to provide guidance on applying SFAS 144, “Determining Whether to Report Discontinued Operations.” SFAS 144 discusses when an entity should disclose a ‘component’ as discontinued operations. Under SFAS 144, a component should be disclosed as discontinued operations when continuing cash flows are eliminated and when there is no significant continuing involvement with the component. EITF 03-13 provides additional guidance on factors to consider in evaluating what constitutes continuing cash flows and continuing significant influence. This Statement is effective for fiscal periods beginning after December 15, 2004. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the guidance.

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