EXHIBIT 2

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal
year ended December 31, 2002, including reconciliation to U.S. GAAP (Note 19)

AUDITORS’ REPORT

To the Shareholders of Suncor Energy Inc.

We have audited the consolidated balance sheets of Suncor Energy Inc. as at December 31, 2002 and 2001 and the consolidated statements of earnings, cash flows and changes in shareholders’ equity for each of the years in the three year period ended December 31, 2002. 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, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles.

PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta

January 17, 2003

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company’s financial statements, such as the change described in note 1 to the consolidated financial statements. Our report to the shareholders dated January 17, 2003 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors’ Report when the change is properly accounted for and adequately disclosed in the financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta

January 17, 2003

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Suncor Energy Inc. is an integrated Canadian energy company, comprised of three operating segments: Oil Sands, Natural Gas and Energy Marketing and Refining.

Oil Sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands mined in the Athabasca region of northeastern Alberta, and the marketing of these products in Canada and the United States.

Natural Gas includes the exploration, acquisition, development, production, transportation and marketing of natural gas and crude oil in Canada and the United States.

Energy Marketing and Refining includes the manufacture, transportation and marketing of petroleum and petrochemical products, primarily in Ontario and Quebec. Petrochemical products are also sold in the United States and Europe.

The significant accounting policies of the company are summarized below:

(a) Principles of Consolidation and the Preparation of Financial Statements

These consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles (GAAP), which differ in some respects from GAAP in the United States. These differences are quantified and explained in note 19.

The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint ventures.

The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. 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.

(b) Cash Equivalents and Investments

Cash equivalents consist primarily of term deposits, certificates of deposit and all other highly liquid investments with a maturity at the time of purchase of three months or less. Investments with maturities greater than three months to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments. Cash equivalents and short-term investments are stated at cost, which approximates market value.

(c) Revenues

Crude oil sales from upstream operations (Oil Sands and Natural Gas) to downstream operations (Energy Marketing and Refining) are based on actual product shipments. On consolidation, revenues and purchases related to these sales transactions are eliminated from operating revenues and purchases of crude oil and products.

The company also uses a portion of its natural gas production for internal consumption at its oil sands plant and Sarnia refinery. On consolidation, revenues from these sales are eliminated from operating revenues, crude oil and products purchases, and operating, selling and general expenses.

Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer and delivery has taken place. Revenues from oil and natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company’s net working interest.

(d) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

Expenditures to acquire and develop Oil Sands mining properties, and net costs relating to production during the development phase, are capitalized. Development costs to expand the capacity of existing mines or to develop mine areas substantially in advance of current production are also capitalized.

The company follows the successful efforts method of accounting for its conventional and in-situ oil sands crude oil operations and its natural gas operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are initially capitalized. If it is determined that the well does not contain proved reserves, the capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. Related land costs are expensed through the amortization of unproved properties as covered under the Natural Gas section of the depreciation, depletion and amortization policy on page 42.

Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs.

Costs incurred at the inception of operations are expensed.

Interest Capitalization

Interest costs relating to major capital projects in progress and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of property, plant and equipment. Capitalization of interest ceases when the capital asset is substantially complete and ready for its intended productive use.

Leases

Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as capital leases and classified as property, plant and equipment with offsetting long-term debt. All other leases are classified as operating leases under which leasing costs are expensed in the period incurred.

Gains and losses on the sale and leaseback of assets recorded as capital leases are deferred and amortized to earnings in proportion to the amortization of leased assets.

Depreciation, Depletion and Amortization

OIL SANDS Property, plant and equipment are depreciated over their useful lives on a straight-line basis, commencing when the assets are placed into service. Mine and mobile equipment is depreciated over periods ranging from three to 20 years and plant and other property and equipment, including leases in service, primarily over four to 40 years. Capitalized costs related to the in-progress phase of projects are not depreciated until the facilities are substantially complete and ready for commercial production to commence.

NATURAL GAS Acquisition costs of unproved properties that are individually significant are evaluated for impairment by management. Impairment of unproved properties that are not individually significant is provided for through amortization over the average projected holding period for that portion of acquisition costs not expected to become producing, based on historical experience.

Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight-line basis over their useful lives, which average 12 years.

ENERGY MARKETING AND REFINING Depreciation of property, plant and equipment is provided for on a straight-line basis over their useful lives. The refinery and additions are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and other facilities and equipment over three to 25 years.

Reclamation and Environmental Remediation Costs

Reclamation and environmental remediation costs for identified sites are estimated and charged against earnings when a regulatory or statutory requirement or contractual agreement exists, or when management has made a decision to decommission or restore a site, providing that assessments indicate that such costs are probable and reasonably estimable.

Estimated reclamation costs in the company’s upstream operations are accrued on the unit of production basis. Estimated environmental remediation costs, which are predominantly in the company’s downstream operations, are accrued during the period for those sites where assessments indicate that such work is required.

Costs are accrued based upon currently known information, estimated timing of remedial actions, and existing regulatory requirements and technology. Changes in these factors may result in material changes to estimated costs, which will be recognized prospectively when known.

Impairment

Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less related provisions for reclamation and environmental remediation costs and future income taxes, may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the estimated net recoverable amount is recognized during the period, with a charge to earnings.

Disposals

Gains or losses on disposals of non-oil and gas property, plant and equipment are recognized in earnings. For oil and gas property, plant and equipment, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of an unproved property surrendered or abandoned that is not individually significant, or a partial abandonment of a proved property, is charged to accumulated depreciation, depletion or amortization.

(e) Deferred Charges and Other

Overburden removal may precede mining of the oil sands deposit by as much as two years. In order to match expense with the oil sands mined in the year, the company employs a deferral method of accounting for overburden removal costs where all such costs are initially recorded as a deferred charge (see note 3), rather than expensing overburden removal costs as incurred. These deferred charges are allocated to the mining activity in the year on a last-in, first-out (LIFO) basis using a life-of-mine stripping ratio for each mine pit whereby all of the overburden to be removed is related to all of the oil sands proved and probable ore reserves. This expense is reported as part of the depreciation, depletion and amortization expense in the consolidated statements of earnings. Stripping ratios are regularly reviewed to reflect changes in operating experience and other factors.

The cost of major maintenance shutdowns is deferred and amortized on a straight-line basis over the period to the next shutdown, which varies from three to seven years. Normal maintenance and repair costs are charged to expense as incurred.

(f) Employee Future Benefits

The company’s employee future benefit programs consist of defined benefit and defined contribution pension plans, as well as other post-retirement benefits.

The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management’s best estimates of demographic and financial assumptions, and such cost is accrued ratably from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based upon a year-end market rate of interest. Company contributions to the defined contribution plan are expensed as incurred.

(g) Inventories

Inventories of crude oil and refined products are valued at the lower of cost using the LIFO method and net realizable value.

Materials and supplies are valued at the lower of average cost and net realizable value.

(h) Derivative Financial Instruments

The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products and to manage the exposure to fluctuations in its Canadian dollar earnings and cash flows due to adverse foreign currency exchange movements. The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage exposure to interest rate fluctuations.

These derivative contracts are initiated within the guidelines of the company’s risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions.

Derivative contracts accounted for as hedges are not recognized in the consolidated balance sheets. Gains or losses on these contracts, including realized gains and losses on hedging derivative contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.

Commencing in the fourth quarter of 2002, the company began to use energy derivatives, including physical and financial swaps, forwards and options to gain market information and to earn trading revenues. Trading activities are accounted for at fair value.

(i) Foreign Currency Translation

Monetary assets and liabilities in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. Other assets and related depreciation, depletion and amortization, other liabilities, and revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings.

(j) Stock-based Compensation Plans

Under the company’s common share option programs (see note 11), common share options are granted to executives, employees and non-employee directors. Compensation expense is not recognized at the initial grant of the common share options and consideration paid to the company on exercise of stock options is credited to share capital.

Stock-based compensation awards that are to be settled in cash are measured using the fair value based method of accounting.

(k) Recently Issued Accounting Standards

Hedging Relationships

Canadian Accounting Guideline 13 (AcG 13) “Hedging Relationships” is applicable to the company’s hedging relationships in 2004 and subsequent fiscal years. AcG 13 specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, as well as the discontinuance of hedge accounting. The Guideline does not specify hedge accounting methods. The company is evaluating the impact of implementing the standard.

Asset Retirement Obligations

A new Canadian standard “Asset Retirement Obligations” (ARO) substantially harmonizes Canadian GAAP with U.S. GAAP (see note 19). The standard requires that a liability associated with the retirement of property, plant and equipment be recognized when incurred. The liability would be measured initially at fair value and the resulting costs capitalized. Capitalized costs would be amortized according to normal amortization practices. Subsequent to initial recognition the ARO liability would be adjusted for the accretion of discount and changes in the amount or timing of the underlying future cash flows. The standard is effective no later than January 1, 2004. The company is evaluating the impact of implementing the standard.

CONSOLIDATED STATEMENTS OF EARNINGS
for the years ended December 31

($ millions)	2002		2001		2000
REVENUES
Operating revenues (notes 5, 15, 17 and 18)	4 902		4 194		3 385
Interest	2		5		3
	4 904		4 199		3 388

EXPENSES
Purchases of crude oil and products (note 15)	1 298		1 595		807
Operating, selling and general	1 292		1 012		918
Depreciation, depletion and amortization	585		360		365
Exploration (note 18)	26		22		53
Royalties	98		134		199
Taxes other than income taxes (note 18)	374		367		361
(Gain) on disposal of assets	(2	)	(7	)	(148	)
(Gain) on sale of retail natural gas marketing business (note 16)	(38	)	—		—
Project start-up costs	3		141		15
Write-off of oil shale assets	—		48		125
Restructuring (note 18)	—		(2	)	65
Financing expenses (note 13)	124		16		8
	3 760		3 686		2 768
EARNINGS BEFORE INCOME TAXES	1 144		513		620
Provision for income taxes (note 8)
Current	74		4		45
Future	309		121		198
	383		125		243
NET EARNINGS	761		388		377
Dividends on preferred securities, net of tax (note 10)	(28	)	(26	)	(26	)
Revaluation of US$ preferred securities, net of tax (note 1)	1		(11	)	(6	)
Net earnings attributable to common shareholders	734		351		345

See accompanying Summary of Significant Accounting Policies and Notes.

CONSOLIDATED BALANCE SHEETS
as at December 31

($ millions)	2002	2001
ASSETS
Current assets
Cash and cash equivalents	15	1
Accounts receivable (notes 9(c) and 17)	403	306
Inventories (note 14)	266	258
Income taxes recoverable	—	28
Future income taxes (note 8)	38	29
Total current assets	722	622
Property, plant and equipment, net (note 2)	7 641	7 141
Deferred charges and other (note 3)	185	199
Future income taxes (note 8)	135	132
Total assets	8 683	8 094
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	—	31
Accounts payable and accrued liabilities (notes 6 and 7)	716	672
Income taxes payable	34	—
Taxes other than income taxes	37	42
Future income taxes (note 8)	10	28
Total current liabilities	797	773
Long-term debt (note 4)	2 686	3 113
Accrued liabilities and other (notes 6 and 7)	226	251
Future income taxes (note 8)	1 516	1 177
Total liabilities	5 225	5 314

Commitments and contingencies (note 9)

Shareholders’ equity
Preferred securities (note 10)	523	525
Share capital (note 11)	578	555
Retained earnings	2 357	1 700
Total shareholders’ equity	3 458	2 780
Total liabilities and shareholders’ equity	8 683	8 094

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board:


Rick George		Robert Korthals
Director		Director

CONSOLIDATED STATEMENTS OF CASH FLOWS
for the years ended December 31

($ millions)	2002		2001		2000
OPERATING ACTIVITIES
Cash flow provided from operations(a)	1 440		831		958
Decrease (increase) in operating working capital
Accounts receivable	(97	)	101		(130	)
Inventories	(8	)	(66	)	(31	)
Accounts payable and accrued liabilities	44		(37	)	93
Taxes payable	77		(17	)	18
Cash provided from operating activities	1 456		812		908
CASH USED IN INVESTING ACTIVITIES(a)	(861	)	(1 680	)	(1 607	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	595		(868	)	(699	)
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	(31	)	(33	)	32
Proceeds from issuance of long-term debt	797		500		—
Net increase (decrease) in other long-term debt	(1 245	)	486		792
Issuance of common shares under stock option plans	19		15		9
Dividends paid on preferred securities	(48	)	(48	)	(47	)
Dividends paid on common shares	(73	)	(72	)	(71	)
Cash provided from (used in) financing activities	(581	)	848		715
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	14		(20	)	16
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1		21		5
CASH AND CASH EQUIVALENTS AT END OF YEAR	15		1		21

(a) See Schedules of Segmented Data on pages 50 and 51.

See accompanying Summary of Significant Accounting Policies and Notes.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
for the years ended December 31

	Preferred		Share	Retained
($ millions)	Securities		Capital	Earnings
At December 31, 1999, as previously reported	514		524	1 070
Retroactive adjustment for change in accounting policy, net of tax (note 1)	(12	)	—	9
At December 31, 1999, as restated	502		524	1 079
Net earnings	—		—	377
Dividends paid on preferred securities, net of tax	—		—	(26	)
Dividends paid on common shares	—		—	(71	)
Issued for cash under stock option plans	—		9	—
Issued under dividend reinvestment plan	—		4	(4	)
Income taxes — impact of new standard	—		—	75
Revaluation of US$ preferred securities (note 1)	8		—	(6	)
At December 31, 2000, as restated	510		537	1 424
Net earnings	—		—	388
Dividends paid on preferred securities, net of tax	—		—	(26	)
Dividends paid on common shares	—		—	(72	)
Issued for cash under stock option plans	—		15	—
Issued under dividend reinvestment plan	—		3	(3	)
Revaluation of US$ preferred securities (note 1)	15		—	(11	)
At December 31, 2001, as restated	525		555	1 700
Net earnings	—		—	761
Dividends paid on preferred securities, net of tax	—		—	(28	)
Dividends paid on common shares	—		—	(73	)
Issued for cash under stock option plans	—		19	—
Issued under dividend reinvestment plan	—		4	(4	)
Revaluation of US$ preferred securities (note 1)	(2	)	—	1
At December 31, 2002	523		578	2 357

See accompanying Summary of Significant Accounting Policies and Notes.

SCHEDULES OF SEGMENTED DATA (a)
for the years ended December 31

	Oil Sands						Natural Gas						Energy Marketing and Refining
($ millions)	2002		2001		2000		2002		2001		2000		2002		2001		2000
EARNINGS
Revenues(b)
Operating revenues	2 284		1 227		544		255		382		237		2 361		2 585		2 604
Intersegment revenues (note 15)(c)	375		158		792		60		76		191		—		3		—
Interest	—		—		—		—		—		—		—		—		—
	2 659		1 385		1 336		315		458		428		2 361		2 588		2 604
Expenses
Purchases of crude oil and products (note 15)	149		99		3		16		9		—		1 564		1 721		1 783
Operating, selling and general	806		481		467		69		64		74		352		350		310
Depreciation, depletion and amortization	450		233		232		75		70		78		58		56		54
Exploration	9		—		—		17		22		53		—		—		—
Royalties	33		30		98		65		104		101		—		—		—
Taxes other than income taxes	23		12		12		2		3		3		348		351		345
(Gain) loss on disposal of assets	2		1		—		(4	)	(8	)	(147	)	—		—		(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		—		(38	)	—		—
Project start-up costs	3		141		15		—		—		—		—		—		—
Write-off of oil shale assets	—		—		—		—		—		—		—		—		—
Restructuring	—		—		—		—		(2	)	65		—		—		—
Financing expenses	—		—		—		—		—		—		—		—		—
	1 475		997		827		240		262		227		2 284		2 478		2 491
Earnings (loss) before income taxes	1 184		388		509		75		196		201		77		110		113
Provision for income taxes	(391	)	(105	)	(194	)	(40	)	(79	)	(103	)	(16	)	(30	)	(32	)
Net earnings (loss)	793		283		315		35		117		98		61		80		81

As at December 31
TOTAL ASSETS	6 896		6 409		5 079		765		722		762		968		934		911
CAPITAL EMPLOYED(d)	4 540		1 398		1 412		449		317		412		491		483		386

(a) The company currently has no foreign geographic segments. See note 18 for information on export sales. Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.

(b) One customer in the Oil Sands segment represented 10% or more ($641 million) of the company’s 2002 consolidated revenues (2001 —one customer represented 10% or more ($450 million); 2000 — two customers represented 10% or more ($493 million and $355 million)).

(c) Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties.

(d) Capital employed — the total of shareholders’ equity and short-term and long-term debt, less capitalized costs related to major projects in progress.

See accompanying Summary of Significant Accounting Policies and Notes.

SCHEDULES OF SEGMENTED DATA (a) (continued)
for the years ended December 31

	Corporate and Eliminations						Total
($ millions)	2002		2001		2000		2002		2001		2000
EARNINGS
Revenues(b)
Operating revenues	2		—		—		4 902		4 194		3 385
Intersegment revenues (note 15) (c)	(435	)	(237	)	(983	)	—		—		—
Interest	2		5		3		2		5		3
	(431	)	(232	)	(980	)	4 904		4 199		3 388
Expenses
Purchases of crude oil and products (note 15)	(431	)	(234	)	(979	)	1 298		1 595		807
Operating, selling and general	65		117		67		1 292		1 012		918
Depreciation, depletion and amortization	2		1		1		585		360		365
Exploration	—		—		—		26		22		53
Royalties	—		—		—		98		134		199
Taxes other than income taxes	1		1		1		374		367		361
(Gain) loss on disposal of assets	—		—		—		(2	)	(7	)	(148	)
(Gain) on sale of retail natural gas marketing business	—		—		—		(38	)	—		—
Project start-up costs	—		—		—		3		141		15
Write-off of oil shale assets	—		48		125		—		48		125
Restructuring	—		—		—		—		(2	)	65
Financing expenses	124		16		8		124		16		8
	(239	)	(51	)	(777	)	3 760		3 686		2 768
Earnings (loss) before income taxes	(192	)	(181	)	(203	)	1 144		513		620
Provision for income taxes	64		89		86		(383	)	(125	)	(243	)
Net earnings (loss)	(128	)	(92	)	(117	)	761		388		377

As at December 31
TOTAL ASSETS	54		29		81		8 683		8 094		6 833
CAPITAL EMPLOYED(d)	154		33		22		5 634		2 231		2 232

SCHEDULES OF SEGMENTED DATA (a) (continued)
for the years ended December 31

	Oil Sands						Natural Gas						Energy Marketing and Refining
($ millions)	2002		2001		2000		2002		2001		2000		2002		2001		2000
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash provided from (used in) operating activities:
Cash flow provided from (used in) operations
Net earnings (loss)	793		283		315		35		117		98		61		80		81
Exploration expenses
Cash	—		—		—		6		12		12		—		—		—
Dry hole costs	—		—		—		11		10		41		—		—		—
Non-cash items included in earnings
Depreciation, depletion and amortization	450		233		232		75		70		78		58		56		54
Future income taxes	379		89		189		37		76		101		(35	)	18		(16	)
Current income tax provision allocated to Corporate	12		16		5		3		3		2		51		12		48
(Gain) loss on disposal of assets	2		1		—		(4	)	(8	)	(147	)	—		—		(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		—		(38	)	—		—
Write-off of oil shale assets	—		—		—		—		—		—		—		—		—
Restructuring	—		—		—		—		(3	)	56		—		—		—
Other	12		(4	)	(12	)	2		3		(4	)	9		2		6
Overburden removal outlays	(160	)	(31	)	(48	)	—		—		—		—		—		—
Overburden removal outlays —
Project Millennium (start-up period)	—		(88	)	(27	)	—		—		—		—		—		—
Increase (decrease) in deferred credits and other	(8	)	(13	)	1		(1	)	—		1		1		(3	)	2
Total cash flow provided from (used in) operations	1 480		486		655		164		280		238		107		165		174
Decrease (increase) in operating working capital	(121	)	(35	)	(169	)	22		44		27		(10	)	17		40
Total cash provided from (used in) operating activities	1 359		451		486		186		324		265		97		182		214
Cash provided from (used in) investing activities:
Capital and exploration expenditures	(617	)	(1 479	)	(1 808	)	(163	)	(132	)	(127	)	(60	)	(54	)	(45	)
Deferred maintenance shutdown expenditures	(9	)	(5	)	(3	)	—		(2	)	(1	)	(18	)	(9	)	(9	)
Deferred outlays and other investments	(4	)	(2	)	(5	)	—		(1	)	—		(18	)	(9	)	(7	)
Proceeds from disposals	—		10		101		5		22		314		62		1		2
Total cash provided from (used in) investing activities	(630	)	(1 476	)	(1 715	)	(158	)	(113	)	186		(34	)	(71	)	(59	)
Net cash surplus (deficiency) before financing activities	729		(1 025	)	(1 229	)	28		211		451		63		111		155

See accompanying Summary of Significant Accounting Policies and Notes.

SCHEDULES OF SEGMENTED DATA (a) (continued)
for the years ended December 31

	Corporate and Eliminations						Total
($ millions)	2002		2001		2000		2002		2001		2000
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash provided from (used in) operating activities:
Cash flow provided from (used in) operations
Net earnings (loss)	(128	)	(92	)	(117	)	761		388		377
Exploration expenses
Cash	—		—		—		6		12		12
Dry hole costs	—		—		—		11		10		41
Non-cash items included in earnings
Depreciation, depletion and amortization	2		1		1		585		360		365
Future income taxes	(72	)	(62	)	(76	)	309		121		198
Current income tax provision allocated to Corporate	(66	)	(31	)	(55	)	—		—		—
(Gain) loss on disposal of assets	—		—		—		(2	)	(7	)	(148	)
(Gain) on sale of retail natural gas marketing business	—		—		—		(38	)	—		—
Write-off of oil shale assets	—		48		125		—		48		125
Restructuring	—		—		—		—		(3	)	56
Other	(3	)	7		(7	)	20		8		(17	)
Overburden removal outlays	—		—		—		(160	)	(31	)	(48	)
Overburden removal outlays —
Project Millennium (start-up period)	—		—		—		—		(88	)	(27	)
Increase (decrease) in deferred credits and other	(44	)	29		20		(52	)	13		24
Total cash flow provided from (used in) operations	(311	)	(100	)	(109	)	1 440		831		958
Decrease (increase) in operating working capital	125		(45	)	52		16		(19	)	(50	)
Total cash provided from (used in) operating activities	(186	)	(145	)	(57	)	1 456		812		908
Cash provided from (used in) investing activities:
Capital and exploration expenditures	(37	)	(13	)	(18	)	(877	)	(1 678	)	(1 998	)
Deferred maintenance shutdown expenditures	—		—		—		(27	)	(16	)	(13	)
Deferred outlays and other investments	(2	)	(7	)	(1	)	(24	)	(19	)	(13	)
Proceeds from disposals	—		—		—		67		33		417
Total cash provided from (used in) investing activities	(39	)	(20	)	(19	)	(861	)	(1 680	)	(1 607	)
Net cash surplus (deficiency) before financing activities	(225	)	(165	)	(76	)	595		(868	)	(699	)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Change in Accounting Policy

Effective January 1, 2002, the company retroactively adopted the new Canadian accounting standard for Foreign Currency Translation, and as a result, all prior periods have been restated. This new standard applies to the company’s foreign currency denominated long-term debt and preferred securities (see notes 4 and 10). The impact of this new standard on the consolidated balance sheets and statements of earnings is as follows:

Change in Consolidated Balance Sheets

($ millions, increase (decrease))	2002		2001
Future income taxes — long-term liabilities	3		(4	)
Preferred securities	(2	)	15
Retained earnings	9		(11	)

Change in Consolidated Statements of Earnings

($ millions, increase (decrease))	2002		2001		2000
Financing expenses	(10	)	—		—
Future income taxes	2		—		—
Net earnings	8		—		—
Revaluation of US$preferred securities, net of tax	1		(11	)	(6	)
Net earnings attributable to common shareholders	9		(11	)	(6	)
Per common share — basic and diluted (dollars)	$0.02		($0.02	)	($0.01	)

2. Property, Plant and Equipment

	2002		2001
		Accumulated		Accumulated
($ millions)	Cost	Provision	Cost	Provision
Oil Sands
Plant	5 340	691	1 744	557
Mine and mobile equipment	1 154	381	1 008	337
Pipeline costs	81	26	81	23
Capital leases	121	12	109	6
Major projects in progress
Project Millennium	—	—	3 618	8
Firebag and other	702	—	275	—
	7 398	1 110	6 835	931
Natural Gas
Proved properties	1 053	480	931	423
Unproved properties	150	41	148	48
Pipeline	20	18	20	17
Other support facilities and equipment	16	11	14	8
	1 239	550	1 113	496
Energy Marketing and Refining
Refinery	800	417	771	391
Marketing and transportation	461	229	434	209
	1 261	646	1 205	600
Corporate	55	6	19	4
	9 953	2 312	9 172	2 031
Net property, plant and equipment		7 641		7 141

3. Deferred Charges and Other

($ millions)	2002		2001
Oil sands overburden removal costs (see below)	68		101
Deferred maintenance shutdown costs	44		34
Other	73		64
Total deferred charges and other	185		199

Oil sands overburden removal costs
Balance — beginning of year	101		76
Outlays during the year	160		119
Depreciation on equipment during year	9		9
	270		204
Amortization during year	(202	)	(103	)
Balance — end of year	68		101

4. Long-term Debt

($ millions)	2002	2001
Fixed-term debt, redeemable at the option of the company
7.15% Notes, denominated in U.S. dollars, due in 2032 (a)	790	—
6.70% Series 2 Medium Term Notes, due in 2011 (b)	500	500
6.80% Medium Term Notes, due in 2007 (b)	250	250
6.10% Medium Term Notes, due in 2007 (b)	150	150
7.40% Debentures, Series C, due in 2004	125	125
	1 815	1 025

Revolving-term debt, with interest at variable rates (see Credit Facilities)
Commercial Paper, interest at December 31, 2002 — 2.9% (2001 — 2.5%) (b,c)	548	861
Bank debt, interest at December 31, 2002 — 3.5% (2001 — 2.6%) (b)	199	1 112
Total unsecured long-term debt	2 562	2 998
Other secured long-term debt with interest rates averaging 6.1% (2001 — 7.1%)	5	6
Capital leases (d,e)	119	109
Total long-term debt	2 686	3 113

(a) In 2002, the company issued 7.15% Notes with a principal amount of US$500 million (Cdn$ equivalent of $790 million at December 31, 2002). The net proceeds received were used to repay commercial paper and bank debt.

(b) The company has entered into various interest rate swap transactions at December 31, 2002. The swap transactions result in an average effective interest rate that is different from the stated interest rate of the related underlying long-term debt instruments.

	Principal
	Swapped	Swap	2002 Effective
Description of Swap Transactions	($ millions)	Maturity	Interest Rate
Swap of 6.70% Series 2 Medium Term Notes to floating rates	200	2011	4.0	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	4.5	%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	3.8	%
Swap of floating rate Commercial Paper to fixed rates	110	2003	5.3	%
Swap of U.S. dollar denominated floating rate debt to Canadian dollar denominated floating rates	US$126	2003	3.2	%

(c) The company is authorized to issue commercial paper to a maximum of $900 million having a term not to exceed 364 days. Commercial paper is supported by unutilized credit and term loan facilities.

(d) Obligations under capital leases are as follows:

($ millions)	2002	2001
Energy services assets lease with interest at 6.82%, maturing in 2004	101	101
Other equipment leases with interest rates between prime plus 0.5% and 6.25%, and maturity dates ranging from 2008 to 2010	18	8
	119	109

(e) Future minimum amounts payable under capital leases and other long-term debt are as follows:

	Capital	Other Long-
($ millions)	Leases	term Debt
2003	10	3
2004	110	324
2005	3	—
2006	3	550
2007	3	400
Later years	9	1 290
Total minimum payments	138	2 567
Less amount representing imputed interest	19
Present value of obligation under capital leases	119

Credit Facilities

At December 31, 2002, the company had available credit and term loan facilities of $1,948 million, of which $1,139 million was undrawn, as follows:

($ millions)
Facility that is fully revolving for 364 days, has a term period of three years and expires in 2006	600
Facility for US$126 million that is non-revolving, has been fully drawn and expires in 2004	199
Facility that is fully revolving and expires in 2004	1 058
Undrawn facilities that can be terminated at any time at the option of the lenders	91
Total available credit facilities	1 948
Drawn from credit facilities	(199	)
Credit facilities supporting commercial paper program and standby letters of credit	(610	)
Total undrawn credit facilities	1 139

At December 31, 2002, the company had issued $62 million in letters of credit to various third parties.

5. Financial Instruments

Derivatives are financial instruments that either imitate or counter the price movements of stocks, bonds, currencies, commodities and interest rates. Suncor uses derivatives to reduce (hedge) its exposure to fluctuations in commodity prices and foreign currency exchange rates and to manage interest or currency-sensitive assets and liabilities. Suncor also uses derivatives for trading purposes. When used in a trading activity, the company is attempting to realize a gain on the fluctuations in the market value of the derivative.

Forwards and futures are contracts to purchase or sell a specific item at a specified date and price. When used as hedges, forwards and futures manage the exposure to losses that could result if commodity prices or foreign currency exchange rates change adversely.

An option is a contract where its owner, for a fee, has purchased the right (but not the obligation) to buy or sell a specified item at a fixed price during a specified period. Options used as hedges can protect against adverse changes in commodity prices, interest rates, or foreign currency exchange rates.

A costless collar is a combination of two option contracts that limits the holder’s exposure to changes in prices to within a specific range. The “costless” nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).

A swap is a contract where two parties exchange commodity, currency, interest or other payments in order to alter the nature of the payments. For example, fixed interest rate payments on debt may be converted to payments based on a floating interest rate, or vice versa; a domestic currency debt may be converted to a foreign currency debt.

See next page for more technical details and amounts.

(a) Balance Sheet Financial Instruments

The company’s financial instruments recognized in the consolidated balance sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, investments in Southern Pacific Petroleum (SPP), substantially all current liabilities (except for income taxes payable and future income taxes), and long-term debt.

The estimated fair values of recognized financial instruments have been determined based on the company’s assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

(i) The fair values of cash and cash equivalents, accounts receivable and current liabilities approximate their carrying amounts due to the short-term maturity of these instruments.

(ii) The fair value of the company’s investment in the shares of SPP is determined based on quoted market prices of these shares.

(iii) At December 31, 2002, the company had outstanding crude oil and U.S. dollar swap contracts maturing in 2004, fixing the purchase price of 2,130,000 barrels of crude oil at Cdn$49 million. These derivative contracts, which have not been accounted for as hedges, had a fair value and carrying value of $22 million at December 31, 2002 (2001 — $13 million; 2000 — $10 million) (see note 9c).

The following table summarizes estimated fair value information about the company’s long-term debt at December 31:

	2002		2001
	Carrying		Carrying
($ millions)	Amount	Fair Value	Amount	Fair Value
Long-term Debt
Fixed-term	1 815	1 991	1 025	1 047
Revolving-term	747	747	1 973	1 974
Other	5	5	6	6
Capital leases	119	119	109	109

The fair values of the company’s fixed and revolving-term long-term debt, capital leases, and other long-term debt were determined through comparisons to similar debt instruments.

(b) Unrecognized Derivative Financial Instruments

The company periodically is also a party to certain derivative financial instruments, which are not recognized in the consolidated balance sheets, as follows:

Revenue and Margin Hedges

The company periodically enters into crude oil and foreign currency swap and option contracts to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable Canadian/U.S. dollar exchange rate. These contracts reduce fluctuations in sales revenues by locking in fixed prices, or a range of fixed prices, and exchange rates on the portion of its crude oil sales covered by the contracts. The company also enters into crude oil, gasoline and heating oil swap contracts to lock in fixed margins on the portion of refined product sales covered by the contracts. While these contracts reduce the risk of exposure to adverse changes in commodity prices and exchange rates, they also reduce the potential benefit of favourable changes in commodity prices and exchange rates.

The contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company’s sales revenues or crude oil purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.

Contracts outstanding at December 31 were as follows:

		Average	Revenue
	Quantity	Price (a)	Hedged		Hedge
Crude Oil Hedges	(bbl/day)	(US$/bbl)	(Cdn$millions)		Period
As at December 31, 2002
Crude oil swaps	10 000	30	57	(c)	2003	(b)
Crude oil swaps	15 000	24	208	(c)	2003
Costless collars	60 000	21 - 26	726 - 899	(c)	2003
Crude oil swaps	25 000	23	332	(c)	2004
Costless collars	11 000	21 - 24	133 - 152	(c)	2004
Crude oil swaps	21 000	22	266	(c)	2005
As at December 31, 2001
Crude oil swaps	40 576	20	444	(d)	2002
Crude oil swaps	424	21	5	(c)	2002
Costless collars	43 000	22 - 27	550 - 675	(c)	2002
Costless collars	44 000	21 - 26	537 - 665	(c)	2003
Costless collars	11 000	21 - 24	134 - 153	(c)	2004
Crude oil swaps	15 000	22	192	(c)	2005
As at December 31, 2000
Crude oil swaps	42 710	20	436	(d)	2001
Crude oil swaps	4 790	20	52	(c)	2001
Costless collars	10 000	26 - 32	142 - 175	(c)	2001
Crude oil swaps	41 000	20	426	(d)	2002
Costless collars	7 000	22 - 26	84 - 1003	(c)	2002

		Average	Margin
	Quantity	Margin	Hedged(c)	Hedge
Margin Hedges	(bbl/day)	(US$/bbl)	(Cdn$ millions)	Period
Refined product sales and crude purchase swaps
As at December 31, 2002	20 700	5	9	2003	(e)
As at December 31, 2001	—	—	—	—
As at December 31, 2000	13 300	5	18	2001	(f)

(a) Average price for crude oil swaps is WTI per barrel at Cushing, Oklahoma.

(b) For the period January to April 2003, inclusive. All other crude oil positions are for the full year.

(c) The revenue and margin hedged is translated to Cdn$ at the year-end exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(d) The revenue hedged was fixed in Cdn$ as the company had foreign exchange swaps in place for these crude oil swaps.

(e) For the period January and February 2003.

(f) For the period January to June 2001.

Interest Rate Hedges

The company enters into interest rate and cross-currency interest rate swap contracts as part of its risk management strategy to manage its exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and investment grade counterparties. The cross-currency swap contracts involve an exchange of Canadian dollar interest payments and U.S. dollar interest payments, and an exchange of Canadian and U.S. dollar principal amounts at the maturity date of the underlying borrowing to which the swaps relate. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense.

The notional amounts of interest rate and cross-currency interest rate swap contracts outstanding at December 31, 2002 are detailed in note 4, Long-term Debt.

Fair Value of Derivative Financial Instruments

The fair value of hedging derivative financial instruments is the estimated amount, based on brokers’ quotes, that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:

($ millions)	2002		2001
Revenue hedge swaps and options	(133	)	54
Margin hedge swaps	1		(2	)
Interest rate and cross-currency interest rate swaps	35		4
	(97)		56

The fair value of the derivative financial instruments related to the company’s trading activities are determined based on actively traded, quoted market prices. For the period ended December 31, 2002, gains or losses resulting from trading activities were not significant.

(c) Counterparty Credit Risk

The company may be exposed to certain losses in the event that counterparties to the derivative financial instruments are unable to meet the terms of the contracts. The company’s exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. The company minimizes this risk by entering into agreements only with investment grade counterparties, and through regular management review of potential exposure to, and credit ratings of, such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2002	2001
Derivative contracts not accounted for as hedges	28	12
Unrecognized derivative contracts	23	93
	51	105

6. Accrued Liabilities and Other

(a) Reclamation and Environmental Remediation Costs

Total accrued reclamation and environmental remediation costs also include $32 million in current liabilities (2001 —$23 million). Payments during 2002 totalled $15 million (2001 — $28 million; 2000 — $15 million), while expense recorded in 2002 was $20 million (2001 — $15 million; 2000 — $13 million).

(b) Employee and Director Incentive Plans

Included in accrued liabilities and other is accrued compensation expense related to the company’s employee long-term incentive plan (see note 11b). Accrued liabilities and other also include accrued compensation expense in the form of deferred share units received under the directors’ compensation plan. Accrued directors’ compensation expense is not significant.

7. Employee Future Benefits

Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire. The related Benefit Obligation or commitment that Suncor had to employees and retirees at December 31, 2002 was $586 million.

As required by government regulations and plan performance, Suncor sets aside funds, with an independent trustee, to meet certain of these obligations. At the end of December, 2002, Plan Assets to meet the Benefit Obligation were $273 million.

The excess of the Benefit Obligation over Plan Assets of $313 million represents the Net Unfunded Obligation.

See below for more technical details and amounts.

Defined Benefit Pension Plans and Other Post-retirement Benefits

The company’s defined benefit pension plans provide a pension benefit at retirement based on years of service and final average earnings. These obligations are met through a funded registered retirement plan and through unfunded, unregistered supplementary benefits that are paid directly to recipients. Company contributions to the funded plan are deposited with an independent trustee who acts as custodian of the funded pension plan assets, as well as the disbursing agent of the benefits to recipients. Plan assets are managed by an employee pension committee on behalf of beneficiaries. The committee retains independent managers and advisers.

Funding of the registered retirement plan complies with federal and provincial pension legislation that requires an actuarial valuation of the pension funds be performed at least once every three years. As a result of a recent triennial valuation of the registered plan, company funding of current and past service costs for 2003 is anticipated to be $45 million to $50 million (2002 — $14 million).

The company’s other post-retirement benefits program, which is unregistered and unfunded, includes certain health care and life insurance benefits provided to retired employees and eligible surviving dependants. Retirees share in the cost of providing these benefits.

The expense and obligations for both funded and unfunded benefits are determined in accordance with Canadian generally accepted accounting principles and actuarial procedures. Obligations are based on the projected benefit method of valuation that includes employee service to date and present pay levels, as well as a projection of salaries and service to retirement. Obligations are based on the following assumptions:

The following table presents information about the funded status of the plans and obligations recognized in the consolidated balance sheets at December 31:

	Pension Benefits					Other Post-retirement Benefits
($ millions)		2002		2001			2002		2001
Change in benefit obligation
Benefit obligation at beginning of year		461		404			93		79
Service costs		17		14			4		3
Interest costs		30		28			6		6
Plan participants’ contribution		4		3			—		—
Amendments		—		—			(34	)	—
Actuarial (gain) loss		(1	)	34			30		7
Benefits paid		(22	)	(22	)		(2	)	(2	)
Benefit obligation at end of year		489		461			97		93
Change in plan assets(a)
Fair value of plan assets at beginning of year		301		322			—		—
Actual (loss) on plan assets		(24	)	(14	)		—		—
Employer contribution		14		12			—		—
Plan participants’ contribution		4		3			—		—
Benefits paid		(22	)	(22	)		—		—
Fair value of plan assets at end of year		273		301			—		—
Net unfunded obligation		(216	)	(160	)		(97	)	(93	)
Items not yet recognized in earnings:
Unamortized net actuarial loss (b)		142		109			46		19
Unamortized past service costs (c)		—		—			(34	)	—
Accrued benefit liability		(74	)	(51	)		(85	)	(74	)
Current portion		(16	)	(15	)		(2	)	(2	)
Long-term portion (note 6)		(58	)	(36	)		(83	)	(72	)
		(74	)	(51	)		(85	)	(74	)

(a) Assets in the pension plan consist of investments in marketable equity securities, government and corporate bonds, and short-term notes. Pension plan assets are not the company’s assets and therefore are not included in the consolidated balance sheets.

(b) The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 13 years for pension benefits and over the expected average future service life to full eligibility age of 11 years for other post-retirement benefits. As a result of a recent triennial valuation, effective 2003, the expected average remaining service life of employees and the expected average future service life to full eligibility age will be 12 years and 10 years respectively.

(c) Effective April 1, 2003, the company will implement amendments to its existing post-retirement benefits program. Certain of the company’s employees and all retirees will continue to receive post-retirement benefits under the current plan provisions. These plan amendments have reduced the company’s other post-retirement benefits obligation at December 31, 2002, by $34 million.

The above benefit obligation at year-end includes funded and unfunded plans, as follows:

	Pension Benefits		Other Post-retirement Benefits
($ millions)	2002	2001	2002	2001
Funded plan	423	377	—	—
Unfunded plans	66	84	97	93
Benefit obligation at end of year	489	461	97	93

The components of net periodic benefit cost are as follows:

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2002		2001		2000		2002	2001	2000
Current service costs	17		14		12		4	3	3
Interest costs	30		28		26		6	6	5
Expected return on plan assets (a)	(22	)	(23	)	(22	)	—	—	—
Amortization of transitional asset	—		(8	)	(8	)	—	—	—
Amortization of net actuarial loss	15		9		6		2	1	1
Net periodic benefit cost	40		20		14		12	10	9

(a) The expected return on plan assets is the expected long-term rate of return on plan assets for the year based on plan assets at the beginning of the year that have been adjusted on a weighted average basis for contributions and benefit payments expected for the year. The expected return on plan assets is included in the net periodic benefit cost for the year to which it relates, while the difference between it and the actual return realized on plan assets in the same year is amortized over the expected average remaining service life of employees of 13 years for pension benefits, and over the expected average future service life to full eligibility age of 11 years for other post-retirement benefits. As a result of a recent triennial valuation, effective 2003, the expected average remaining service life of employees and the expected average future service life to full eligibility age will be 12 years and 10 years, respectively.

A 1% change in the assumptions at which pension benefits and other post-retirement benefits liabilities could be effectively settled is as follows:

	Rate of Return on Plan Assets			Discount Rate			Rate of Compensation Increase
	1%		1%	1%		1%	1%	1%
($ millions)	increase		decrease	increase		decrease	increase	decrease
Effect on net periodic benefit cost	(3	)	3	(8	)	10	4	(3	)
Effect on benefit obligation	—		—	(71	)	81	18	(16	)

In order to measure the expected cost of other post-retirement benefits, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002. Based upon recent experience, an assumption of 12% will be used for 2003, and then it is assumed this rate will decrease annually by a rate of 0.5% to 5% for 2017, and remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts reported for other post-retirement benefit obligations. A 1% change in assumed health care cost trend rates would have the following effects:

($ millions)	1% increase	1% decrease
Effect on total of service and interest cost components of net periodic post-retirement health care benefit cost	2	(2	)
Effect on the health care component of the accumulated post-retirement benefit obligation	9	(8	)

Defined Contribution Pension Plan

The company has a defined contribution plan, under which both the company and employees make contributions. Company contributions and related expense totalled $5 million in 2002 (2001 — $4 million; 2000 — $4 million).

8. Income Taxes

The assets and liabilities shown on Suncor’s balance sheets are calculated using accounting rules known as generally accepted accounting principles. Suncor’s income taxes are calculated according to government tax laws and regulations, which results in different values for certain assets and liabilities for income tax purposes. These differences are known as temporary differences, because eventually these differences will reverse.

The amount shown on the balance sheets as future income taxes represent income taxes that will eventually be payable or recoverable in future years when these temporary differences reverse.

See below for more technical details and amounts.

The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the two rates and the dollar effect is as follows:

	2002				2001				2000
($ millions)	Amount		%		Amount		%		Amount		%
Federal tax rate	435		38		195		38		236		38
Provincial abatement	(114	)	(10	)	(51	)	(10	)	(62	)	(10	)
Federal surtax	13		1		6		1		7		1
Provincial tax rates	150		13		69		14		96		16
Statutory tax and rate	484		42		219		43		277		45
Add (deduct) the tax effect of:
Crown royalties	39		3		48		9		83		13
Resource allowance	(34	)	(3	)	(28	)	(5	)	(45	)	(8	)
Temporary difference in resource allowance	(120	)	(10	)	(49	)	(10	)	(56	)	(9	)
Large corporations tax	17		1		16		3		10		2
Tax rate changes on future income taxes	(10	)	(1	)	(52	)	(11	)	(13	)	(2	)
Attributed Canadian royalty income	(2	)	—		(6	)	(1	)	(13	)	(2	)
Non-deductible foreign expenses	—		—		(17	)	(3	)	3		—
Assessments and adjustments	10		1		(11	)	(2	)	(3	)	—
Other	(1	)	—		5		1		—		—
Income taxes and effective rate	383		33		125		24		243		39

In 2002 net income tax refunds totalled $8 million (2001 — $23 million payment; 2000 — $22 million payment).

The resource allowance is a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by generally accepted accounting principles in Canada, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate (currently 25%) applied to those temporary differences that are factored into the determination of the resource allowance.

For the three years ended December 31, 2002, the resource allowance resulted in a net decrease in the company’s effective tax rate due primarily to the difference between depreciation for tax and accounting purposes. To the extent that these temporary differences reverse in future years and are not offset by the effect of new capital expenditures, the company’s effective tax rate will increase.

At December 31, future income taxes are comprised of the following:

	2002		2001
($ millions)	Current	Non-current	Current	Non-current
Future income tax assets:
Employee future benefits	4	48	4	30
Reclamation and environmental remediation costs	10	17	8	19
Alberta royalties	—	43	—	44
Employee incentive plans	—	16	—	29
Inventories	18	—	11	—
Other	6	11	6	10
	38	135	29	132
Future income tax liabilities:
Depreciation	—	1 473	—	1 105
Overburden removal costs	—	20	—	30
Maintenance shutdown costs	—	15	—	10
Inventories	—	—	10	—
Other	10	8	18	32
	10	1 516	28	1 177

9. Commitments and Contingencies

(a) Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2002, future minimum amounts payable under these leases and agreements were as follows:

	Pipeline
	Capacity and	Operating
($ millions)	Energy Services (a)	Leases
2003	162	54
2004	161	46
2005	167	39
2006	176	34
2007	177	22
Later years	4 108	61
	4 951	256

(a) Includes annual tolls payable under a transportation service agreement with a major pipeline company to use a portion of its pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreement commenced in 1999 and extends to 2028. As the initial shipper on the pipeline, Suncor’s tolls payable under the agreement could be subject to annual adjustments.

To meet the energy needs of its oil sands operation, Suncor has a commitment under long-term energy agreements to obtain a portion of the power and all of the steam generated by a cogeneration facility owned by a major energy company. Since October 1999, this company has managed the operations of Suncor’s existing energy services facility.

(b) Contingencies

The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated reclamation and environmental remediation costs. These costs are accrued at the company’s Natural Gas and Oil Sands operations on the unit of production basis. A provision is not made for currently operated facilities such as the Oil Sands processing facilities, the Sarnia refinery and service stations until cessation of operations and completion of site investigations. Any changes in environmental remediation estimates (net of estimated gains on sale of sites) will affect future earnings. These estimates could change significantly based upon such factors as operating experience, changes in legislation and regulations and cost.

To mitigate its exposure to property and business interruption losses, the company has purchased insurance policies with a combined coverage of up to US$1,150 million, net of deductible amounts. The policies stipulate a property loss deductible of US$10 million per incident, and a business interruption loss deductible per incident, based on the greater of US$50 million or 30 days of gross earnings lost (as defined in the respective insurance policies). Gross earnings can be influenced by such factors as production levels and commodity prices.

The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The company believes that any liabilities that might arise pertaining to such matters would not be expected to have a material effect on the company’s consolidated financial position.

Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded from the company’s cash provided from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, the impact may be material.

(c) Special Purpose Entities and Guarantees

At December 31, 2002, the company had various off-balance sheet arrangements with Special Purpose Entities and indemnification agreements with third parties as described below.

The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable having a maturity of 45 days or less to a third party. The third party is a multiple party securitization vehicle that provides funding for numerous asset pools. As at December 31, 2002, $170 million in outstanding accounts receivable had been sold under the program. Under the recourse provisions, the company will provide indemnification against credit losses to a maximum of $53 million. A liability has not been recorded for this indemnification as the company believes it has no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2002, were approximately $4 million and $2,421 million, respectively. The company recorded an after-tax loss of approximately $3 million on the securitization program in each of the last three years.

In 1999, the company sold 2,130,000 barrels of its crude oil inventory for $49 million to a third party while retaining the right to use the inventory for its operations through a usage agreement for a five-year period. The third party’s sole asset is the inventory sold to it by the company. The company pays an annual usage fee of $7 million to the third party and receives a $4 million annual storage fee. The company has the right, but is not obligated, to repurchase the inventory at the spot price at the end of the agreement in 2004. In order to reduce the exposure to the spot price should it elect to repurchase the inventory, the company had, at December 31, 2002, crude oil and U.S. dollar swap contracts fixing the purchase price of the crude oil at Cdn$49 million.

In 1999, the company entered into an equipment sale and leaseback arrangement with a third party for proceeds of $30 million. The third party’s sole asset is the equipment sold to it and leased back by the company. The initial lease term covers a period of seven years and is accounted for as an operating lease. The company has provided a residual value guarantee on the equipment of up to $7 million should it elect not to repurchase the equipment at the end of the lease term. An early termination purchase option allows for the repurchase of the equipment at specified dates in 2003, 2004 and 2005. Had the company elected to terminate the lease at December 31, 2002, the total cost would have been $32 million. Lease payments by the company in each of the last three years were $2 million per year.

The company has agreed to indemnify lenders of the 9.125% preferred securities, the 7.15% notes and the company’s credit facilities (see note 4) for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to the receivables securitization program, the crude oil inventory monetization agreement and certain facility and equipment leases.

There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, Suncor has the option to redeem or terminate these contracts if additional costs are incurred.

10. Preferred Securities

During 1999, the company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of US$162.5 million of 9.125% preferred securities for net proceeds of Cdn$507 million after issue costs of $17 million ($10 million after income taxes). The preferred securities are comprised of unsecured junior subordinated debentures, due in 2048 and redeemable at the company’s option on or after March 15, 2004 for proceeds equal to the original principal amount of the preferred securities plus any accrued and unpaid interest as at the date of redemption. Subject to certain conditions, the company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly periods. Deferred interest and principal amounts are payable in cash, or, at the option of the company, from the proceeds on the sale of equity securities of the company delivered to the trustee of the preferred securities. Accordingly, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends. Proceeds from the offerings were used to repay commercial paper debt.

In 2002, dividends of $48 million were paid on the preferred securities (2001 — $48 million; 2000 — $47 million).

11. Share Capital

(a) Authorized:

Common Shares

The company is authorized to issue an unlimited number of common shares without nominal or par value.

Preferred Shares

The company is authorized to issue an unlimited number of preferred shares in series, without nominal or par value.

(b) Issued:

The number of common shares and common share options outstanding, common share prices and per share calculations, for both current and prior periods, reflect a two-for-one split of the company’s common shares during 2002.

	Common Shares
($ millions)	Number	Amount
Balance as at December 31, 2000	443 801 158	537
Issued for cash under stock option plans	2 096 138	15
Issued under dividend reinvestment plan	59 194	3
Balance as at December 31, 2001	445 956 490	555
Issued for cash under stock option plans	1 776 433	19
Issued under employee long-term incentive plan	1 089 888	—
Issued under dividend reinvestment plan	148 732	4
Balance as at December 31, 2002	448 971 543	578

Common Share Options

A stock option gives the holder the right, but not the obligation, to purchase common shares at a predetermined price over a specified period of time.

After the date of grant, employees that hold options must earn the rights to exercise them. This is done by the employee fulfilling a time requirement for service to the company, and with respect to certain options, subject to accelerated vesting should the company meet predetermined performance criteria. Once this right has been earned, these options are considered vested. Options granted to non-employee directors vest and are exercisable immediately.

The predetermined price at which an option can be exercised is generally equal to or greater than the market price of the common shares on the date the options are granted.

See below for more technical details and amounts on the company’s stock option plans:

(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 1,802,650 common share options in 2002 to non-employee directors and certain executives and other senior employees of the company. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted to non-employee directors have a 10-year life and are exercisable immediately. Options granted to employees have a 10-year life and vest annually over a three-year period.

(ii) EMPLOYEE LONG-TERM INCENTIVE PLAN Suncor’s employee long-term incentive plan was adopted in 1997 and matured on April 1, 2002. At maturity, employees received 1,089,888 common shares from treasury for nil cash consideration, along with aggregate cash payments of $34 million. In addition, 2,131,517 common share options, previously granted to senior employees, vested and became exercisable. The company expensed the cash payments to employees of $34 million as pretax compensation expense over the five-year life of the plan. No compensation expense was recorded related to the employees’ receipt of common shares from treasury as these common shares were treated as stock option grants.

Concurrently, 1,461,886 deferred share units (DSUs) with a cash settlement value of $42 million, which had previously been granted to certain executives, vested. These executives also received cash payments of $44 million. As of April 1, 2002, the company had recorded total pretax compensation expense of $86 million related to the executive portion of the company’s long-term incentive plan over the five-year life of the plan.

DSUs are only redeemable at the time a unitholder ceases employment. Subsequent to April 1, 2002, 220,347 DSUs were redeemed for cash consideration of $6 million, resulting in total cash payments made to executives during 2002 of $50 million. Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments. From April to December of 2002, an additional 6,495 DSUs were issued pursuant to this dividend reinvestment feature.

Final DSU redemption amounts are subject to change depending on the company’s share price at the time of exercise. Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period. As at December 31, 2002, 1,248,034 DSUs were outstanding with a total liability of $31 million, of which $27 million was classified as long-term (see note 6).

During 2002, total pretax compensation expense recorded under the company’s long-term incentive plans to employees, senior management and executives was $10 million (2001 — $42 million; 2000 — $32 million). For the five-year period ended April 1, 2002, total pretax compensation expense was $120 million.

(iii) SUNSHARE PERFORMANCE STOCK OPTION PLAN During 2002, the company granted 8,937,992 options to all eligible permanent full-time and part-time employees, both executive and non-executive, under its new employee stock option incentive plan (“SunShare”). Under SunShare, meeting specified performance targets may accelerate the vesting of some or all options, such that 20% of outstanding options may vest as early as 2004, up to an additional 20% of outstanding options may vest as early as 2005 and the remaining 60% of outstanding options may vest on April 30, 2008. All unvested options which have not previously expired or been cancelled will automatically vest on January 1, 2012.

The following tables cover all common share options granted by the company for the years indicated:

				Weighted-
				average
	Number		Exercise Prices	Exercise Price
Outstanding, December 31, 1999	11 715 972		2.38 - 15.09	9.01
Granted	1 900 032		13.04 - 19.28	15.65
Exercised	(1 474 404	)	2.38 - 12.28	6.29
Cancelled	(419 850	)	10.13 - 16.52	13.02
Outstanding, December 31, 2000	11 721 750		2.38 - 19.28	10.28
Granted	2 180 720		15.94 - 21.35	17.63
Exercised	(2 028 668	)	2.38 - 16.48	7.30
Cancelled	(105 732	)	10.13 - 20.20	14.21
Outstanding, December 31, 2001	11 768 070		2.38 - 21.35	12.12
Granted	10 740 642		23.93 - 28.14	27.08
Exercised	(1 776 433	)	2.38 - 17.45	10.42
Cancelled	(406 028	)	13.04 - 27.65	26.48
Outstanding, December 31, 2002	20 326 251		3.80 - 28.14	19.89

Exercisable, December 31, 2002	8 580 913		3.80 - 28.14	11.85

Common shares authorized for issuance by the Board of Directors that remain available for the granting of future options, at December 31:

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2002:

	Outstanding			Exercisable
		Weighted-	Weighted-		Weighted-
		average Remaining	average		average
Exercise Prices	Number	Contractual Life	Exercise Price	Number	Exercise Price
3.80 - 7.85	2 248 328	3 years	6.37	2 248 328	6.37
10.13 - 14.41	4 183 137	5 years	11.93	4 183 130	11.93
15.09 - 19.28	3 435 486	8 years	16.70	1 888 504	16.48
20.20 - 28.14	10 459 300	9 years	27.02	260 951	24.35
Total	20 326 251	7 years	19.89	8 580 913	11.85

(iv) FAIR VALUE OF OPTIONS GRANTED The fair values of all common share options granted are estimated as at the grant date using the Black-Scholes option-pricing model. The weighted-average fair values of the options granted during the year and the weighted-average assumptions used in their determination are as noted below:

	2002			2001			2000

Annual dividend per share	$	0.17		$	0.17		$	0.17
Risk-free interest rate	5.39		%	5.07		%	6.45		%
Expected life	8 years			5 years			7 years
Expected volatility	31		%	35		%	37		%
Weighted-average fair value per option	$	12.08		$	6.41		$	7.12

The company does not recognize any compensation costs related to stock options granted to employees and non-employee directors. Had compensation cost been determined based on the fair values at the grant dates, the cost of which is recognized over the vesting periods of the options granted, the company’s net earnings and earnings per share would have been reduced to the amounts below:

($ millions, except per share amounts)	2002	2001	2000
Net earnings attributable to common shareholders — as reported	734	351	345
Less: compensation cost under the fair value method	32	9	7
Pro forma net earnings attributable to common shareholders	702	342	338
Basic earnings per share
As reported	1.64	0.79	0.78
Pro forma	1.57	0.77	0.76
Diluted earnings per share
As reported	1.61	0.78	0.77
Pro forma	1.54	0.76	0.75

12. Earnings Per Common Share

The following is a reconciliation of basic and diluted earnings per common share:

($ millions)	2002		2001		2000
Net earnings attributable to common shareholders	734		351		345
Dividends on preferred securities, net of tax	28		—	(a)	—	(a)
Revaluation of US$ preferred securities, net of tax	(1	)	—	(a)	—	(a)
Adjusted net earnings attributable to common shareholders	761		351		345

(millions of common shares)
Weighted-average number of common shares	448		445		443
Dilutive securities:
Options issued under stock-based compensation plans	5		6		4
Redemption of preferred securities by the issuance of common shares	20		—	(a)	—	(a)
Weighted-average number of diluted common shares	473		451		447

(dollars per common share)
Basic earnings per share (b)	1.64		0.79		0.78
Diluted earnings per share	1.61	(c)	0.78	(a)	0.77	(a)

Common share and earnings per common share amounts in the above table reflect a two-for-one share split effective May 15, 2002.

Note: An option will have a dilutive effect under the treasury stock method only when the average market price of the common stock during the period exceeds the exercise price of the option.

(a) For the years ended December 31, 2001 and 2000, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares. Dividends on preferred securities, the revaluation of US$ preferred securities and the redemption of preferred securities by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share.

(b) Basic earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of common shares.

(c) Diluted earnings per share is the adjusted net earnings attributable to common shareholders, divided by the weighted-average number of diluted common shares.

13. Financing Expenses

($ millions)	2002		2001		2000
Interest on debt	155		143		112
Capitalized interest	(22	)	(125	)	(104	)
Net interest expense	133		18		8
Foreign exchange (gain) on long-term debt and other	(9	)	(2	)	—
Total financing expenses	124		16		8

Cash interest payments in 2002 totalled $134 million (2001 — $129 million; 2000 — $104 million).

14. Inventories

The replacement cost at December 31, 2002, of crude oil and refined product inventories valued at LIFO exceeded their carrying value by $84 million (2001 — $5 million).

15. Accounting for Intersegment Revenues

In 2001, the company changed the methodology of accounting for sales from its upstream operations to its downstream operations from a deeming concept to one based on actual product shipments.

The impact of this prospective change in methodology on 2002 was to increase both operating revenues and purchases of crude oil and products by $1,164 million (2001 — $473 million). There was no impact on consolidated and segmented net earnings.

16. Sales of the Retail Natural Gas Marketing Business and Oil Shale Project

(a) In 2002, the company sold its retail natural gas marketing business in the Energy Marketing and Refining segment for cash consideration of $62 million, net of related closing costs and adjustments of $4 million, resulting in an after-tax gain of $35 million.

(b) In 2001, the company sold its interest in the Stuart Oil Shale Project for consideration of $5 million comprised of common shares and share options in SPP. During 2002, the company reduced the carrying value of the SPP shares by $1 million (2001 — $3 million) to reflect the decline in their value.

17. Related Party Transactions

The following table summarizes the company’s related party transactions before eliminations for the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.

($ millions)	2002	2001	2000
Operating revenues
Sales to Energy Marketing and Refining segment joint ventures:
Refined products	612	602	600
Petrochemicals	142	131	128

The company has exclusive supply agreements with two Energy Marketing and Refining segment joint ventures for the sale of refined products. The company also has a non-exclusive supply agreement with an Energy Marketing and Refining segment joint venture for the sale of petrochemicals.

Sales to and balances with Energy Marketing and Refining segment joint ventures are established and agreed to by the related parties and approximate fair value.

At December 31, 2002, amounts due from Energy Marketing and Refining segment joint ventures were $46 million (2001 — $33 million).

18. Supplemental Information

($ millions)	2002	2001	2000
Export sales (a)	501	590	478

Exploration expenses
Geological and geophysical	13	11	10
Other	2	1	2
Cash costs	15	12	12
Dry hole costs	11	10	41
Cash and dry hole costs (b)	26	22	53
Leasehold impairment (c)	10	9	10
	36	31	63

Taxes other than income taxes
Excise taxes (d)	340	343	336
Production, property and other taxes	34	24	25
	374	367	361

Allowance for doubtful accounts	3	3

(a) Sales of crude oil, natural gas and refined products to customers in the United States and sales of petrochemicals to customers in the United States and Europe.

(b) Included in exploration expenses in the Consolidated Statements of Earnings.

(d) Included in operating revenues in the Consolidated Statements of Earnings.

In 2000, the carrying values of certain assets of the company’s Natural Gas business were written down to their net estimated recoverable amount and a provision for estimated restructuring costs was recorded. During 2001, some of these properties that were previously written down were sold and provisions for estimated restructuring costs were revised to reflect increased employee termination costs. The impact of these adjustments on 2002 is nil (2001 — increased net earnings by $1 million; 2000 — decreased net earnings by $30 million).

19. Differences Between Canadian and United States Generally Accepted Accounting Principles

The consolidated financial statements have been prepared in accordance with Canadian GAAP. The application of United States GAAP (U.S. GAAP) would have the following effects on earnings and comprehensive income as reported:

($ millions)	Notes	2002		2001		2000
Net earnings as reported, Canadian GAAP		761		388		377
Adjustments net of applicable income taxes
Stock-based compensation	(b)	(12	)	(14	)	(22	)
Preferred securities	(c)	(29	)	(27	)	(22	)
Start-up costs	(d)	—		10		8
Income taxes	(e)	—		6		(6	)
Write-off of oil shale assets	(f)	—		64		(64	)
Derivatives and hedging activities	(a)	6		(55	)	—
Cumulative effect of change in accounting principles	(a)	—		47		—
Net (earnings) loss attributable to discontinued operations	(g)	(56	)	5		5
Net earnings from continuing operations, U.S. GAAP		670		424		276
Net earnings (loss) from discontinued operations, U.S. GAAP	(g)	56		(5	)	(5	)
Minimum pension liability, net of income taxes of $10 (2001 — $11; 2000 — $1)	(h)	(20	)	(26	)	(2	)
Derivatives and hedging activities, net of income taxes of $54 (2001 — $16)	(a)	(118	)	29		—
Comprehensive income, U.S. GAAP		588		422		269

Per common share (dollars)
Net earnings per share from continuing operations
Basic	1.50	0.95		0.62
Diluted	1.47	0.94		0.62
Net earnings per share from discontinued operations
Basic	0.12	(0.01	)	(0.01	)
Diluted	0.12	(0.01	)	(0.01	)

The application of U.S. GAAP would have the following effects on the consolidated balance sheets as reported:

		2002			2001
		As	U.S.		As	U.S.
($ millions)	Notes	Reported	GAAP		Reported	GAAP
Total current assets	(a)	722	767		622	694
Property, plant and equipment, net	(c)	7 641	7 674		7 141	7 174
Deferred charges and other	(a,c,h)	185	231		199	210
Future income taxes	(a,c,h)	135	165		132	159
Total assets		8 683	8 837		8 094	8 237
Total current liabilities	(a)	797	933		773	806
Long-term debt	(a,c)	2 686	3 251		3 113	3 649
Accrued liabilities and other	(b,h)	226	306		251	336
Future income taxes	(a,c)	1 516	1 539		1 177	1 220
Preferred securities	(c)	523	—		525	—
Share capital and additional paid-in capital	(b)	578	626		555	555
Retained earnings		2 357	2 319		1 700	1 670
Accumulated other comprehensive income	(a,h)	—	(137	)	—	1
Total liabilities and shareholders’ equity		8 683	8 837		8 094	8 237

(a) Derivative Financial Instruments

The company accounts for its derivative financial instruments under Canadian GAAP as described in note 5 to the Consolidated Financial Statements. Statement 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended by Statement 138, (the Standards), establishes U.S. GAAP accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk, are recognized in the statements of earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income (“OCI”) and are recognized in the statements of earnings when the hedged item is recognized. Accordingly, ineffective portions of changes in the fair value of hedging instruments are recognized in earnings immediately for both fair value and cash flow hedges. Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same earnings statement caption as the hedged item. Gains or losses from derivative instruments for which hedge accounting is not applied are reported in other income.

Adoption of the Standards

For U.S. GAAP purposes, the company’s adoption of Statement 133 effective January 1, 2001 would have increased assets by $176 million, increased liabilities by $302 million, decreased OCI by $173 million, net of income taxes of $87 million, and increased net income due to the cumulative effect of a change in accounting principles by $47 million, net of income taxes of $28 million.

Commodity Price Risk

The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products. The company manages its Canadian dollar crude price exposure by entering into U.S. dollar WTI derivative transactions and in some instances combines U.S. dollar WTI derivative transactions and Canadian/U.S. foreign exchange derivative contracts. As at December 31, 2002 the company had hedged a portion of its future cash flows subject to commodity price risk for up to three years.

Interest Rate Risk

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest-bearing debt. At December 31, 2002 the company has interest rate derivatives classified as cash flow hedges outstanding for one year and fair value hedges outstanding for nine years.

During 2001, the company terminated the cross-currency interest rate swaps related to its Series C 7.4% Debentures. For Canadian GAAP purposes, the resulting gain of $4 million, net of income taxes of $2 million, has been deferred and is being amortized over the term to maturity of the Debentures, resulting in a decrease in interest expense during the year ended December 31, 2002 of $1 million, net of income taxes of $1 million. For U.S. GAAP purposes, the entire $4 million gain would have been recognized during 2001.

Non-designated Hedging Instruments

In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting as the company does not have purchase price risk associated with the repurchase of the inventory. This derivative does not represent a U.S. GAAP difference as the company records this derivative at fair value for Canadian purposes.

During the fourth quarter of 2001, the company made a payment of $29 million to terminate a long-term natural gas contract. The contract had been designated as a hedge under Canadian GAAP, and the resulting settlement loss of $18 million, net of income taxes of $11 million, was to be deferred and recognized as the hedged item was settled. During 2002, in connection with the sale of the company’s retail natural gas marketing business (see note 19g), the company disposed of the related hedged item. Accordingly, for Canadian GAAP purposes, the company recognized the entire settlement loss of $18 million during 2002. For U.S. GAAP purposes, the long-term contract would have been designated as a normal purchase and sale transaction, and the after-tax loss of $18 million would have been recognized in 2001 on the initial settlement of the contract.

The company has entered into a cross-currency interest rate swap related to US$126 million of variable rate debt. Although the swap transaction could have qualified as a fair value hedge of the related foreign currency risk had it been designated as such, the company chose not to designate it. Accordingly, the company has valued the swap at fair value and the debt has been revalued at the rate in effect at the related balance sheet date. Had the swap been designated as a fair hedge, the net effect on the company’s net income would have been the same.

Accumulated OCI

A reconciliation of changes in accumulated OCI to derivative hedging activities for the years ended December 31 is as follows:

($ millions)	2002		2001
Accumulated OCI attributable to derivatives and hedging activities, beginning of period, net of income taxes of $13	29		—
Net hedging losses arising from implementation of the Standards, net of income taxes of $87	—		(173	)
Current period net hedging losses arising from cash flow hedges, net of income taxes of $57 (2001 — $38)	(123	)	79
Net hedging losses at beginning of the period reclassified to earnings during the period, net of income taxes of $3 (2001 — $62)	5		123
Accumulated OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $41 (2001 — $13)	(89	)	29

During the year ended December 31, 2002, assets increased by $87 million and liabilities increased by $178 million as a result of recording all derivative instruments at fair value.

The loss associated with hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $19 million, net of income taxes of $9 million (2001 — $32 million, net of income taxes of $15 million). The company estimates that $72 million of hedging losses will be reclassified from OCI to current period earnings within 2003 as a result of forecasted sales occurring.

(b) Stock-based Compensation

Under Canadian GAAP, compensation expense has not been recognized for common share options granted in connection with the company’s new SunShare long-term incentive plan. Under U.S. GAAP, certain of these options would have been accounted for using the variable method of accounting for employee stock compensation. As at December 31, 2002 no compensation expense would have been recognized on these options for U.S. GAAP purposes.

Under Canadian GAAP, compensation expense has not been recognized for common share options, including the common shares received by employees as described in note 11b under the company’s previous long-term employee incentive plan that matured April 1, 2002. Under U.S. GAAP, compensation expense would have been recognized ratably over the life of the incentive plan for these options and common shares. For the year ended December 31, 2002, net earnings would have been reduced by $12 million (2001 — $14 million; 2000 — $22 million). As settlement of the incentive plan was made through issuance of options and common stock from treasury, share capital and additional paid-in capital was increased by $48 million.

Under Canadian GAAP, had the company accounted for its stock options using the fair value method, pro forma net earnings and pro forma basic earnings per share for the year ended December 31, 2002 would have been reduced by $32 million (2001 — $9 million; 2000 — $7 million) and $0.07 per share (2001 — $0.02; 2000 — $0.02), respectively. Under U.S. GAAP, had the company accounted for its options using the fair value method (excluding the SunShare and long-term employee incentive options identified above), pro forma net earnings and pro forma basic earnings per share for the year ended December 31, 2002 would have been reduced by $24 million (2001 — $9 million; 2000 — $7 million) and $0.05 per share (2001 — $0.02; 2000 — $0.02), respectively.

(c) Preferred Securities

Under Canadian GAAP, preferred securities are classified as share capital and the interest distributions thereon, net of income taxes, are accounted for as dividends. Under U.S. GAAP, the preferred securities would have been classified as long-term debt and the interest distributions thereon would have been accounted for as financing expenses. Preferred securities denominated in U.S. dollars of US$ 163 million would have been revalued at the rate in effect at the related balance sheet date, with any foreign exchange gains (losses) recognized in the statements of earnings. Further, under U.S. GAAP the interest distributions would have been eligible for interest capitalization.

Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, are charged against share capital. Under U.S. GAAP, these issue costs would have been deferred and amortized to earnings over the term of the related long-term debt.

The impact of these differences would have reduced net earnings for U.S. GAAP purposes for the year ended December 31, 2002 by $29 million, net of income taxes of $20 million (2001 — $27 million, net of income taxes of $18 million; 2000 — $22 million, net of income taxes of $17 million).

Under Canadian GAAP, the 2002 interest distributions on the preferred securities for the year ended December 31, 2002 of $48 million (2001 — $48 million; 2000 — $47 million) are classified as financing activities in the consolidated statements of cash flows. Under U.S. GAAP, the interest distributions and the amortization of issue costs for the year ended December 31, 2002 of $3 million (2001 — $3 million; 2000 — $7 million) would have been classified as operating activities.

The preferred securities, which are publicly traded, had a fair value, based on quoted market prices, of $568 million at December 31, 2002 (2001 — $575 million; 2000 — $544 million).

(d) Start-up Costs

In 2001, under Canadian GAAP, all remaining capitalized start-up costs associated with the Stuart Oil Shale Project were written down. Under U.S. GAAP, these start-up costs would have been fully expensed in 1999. As a result, net earnings for U.S. GAAP purposes for 2001 would have been increased by $10 million, net of income taxes of $7 million (2000 — increased net earnings by $8 million, net of income taxes of $6 million).

(e) Income Taxes

Under Canadian GAAP, changes in tax laws and rates are recognized when they are considered substantially enacted, whereas under U.S. GAAP, changes in tax laws and rates are only considered after they have been enacted into law. The impact of this GAAP difference would have been to increase U.S. GAAP net earnings for the year ended December 31, 2001 by $6 million (2000 — decrease net earnings by $6 million).

(f) Asset Impairment

Under Canadian GAAP, the company reduced the carrying amount of its interest in the Stuart Oil Shale Project in 2000, based on a non-discounted cash flow analysis. Had the carrying amount been determined using a discounted cash flow analysis as required under U.S. GAAP, an additional write-down of $64 million, net of income taxes of $55 million, would have been recorded in 2000. Effective April 5, 2001, the company sold its interest in the project. Due to the difference in determining the carrying value of the project for Canadian and U.S. GAAP purposes in 2000, net earnings for U.S. GAAP purposes for the year ended December 31, 2001 would have increased by $64 million.

(g) Discontinued Operations

During 2002, the company disposed of its retail natural gas marketing business for net proceeds of $62 million, and recognized a $35 million after-tax gain on the sale for Canadian GAAP purposes. The retail natural gas marketing business was not considered significant to the company’s overall business operations, and was not classified as a business segment for the purposes of discontinued operations reporting. Accordingly, financial results of the retail natural gas marketing business were not segregated from the financial results of the company’s other operations prior to the date of disposal of the business.

For U.S. GAAP purposes, the company would have adopted Statement 144 “Accounting for the Impairment and Disposal of Long-Lived Assets,” effective January 1, 2002. For the purposes of Statement 144, the retail natural gas marketing business would have been considered a distinguishable component of the company, and reflected as a discontinued operation for the three years ended December 31, 2002. For segmented reporting purposes, the retail natural gas marketing business was included in the Energy Marketing and Refining operating segment in 2002, 2001 and 2000.

Selected financial information regarding the discontinued retail natural gas marketing business for U.S. GAAP purposes is as follows for the years ended December 31:

($ millions)	2002	2001		2000
Revenues from discontinued operations	81	196		116
Income (loss) from discontinued operations, net of income taxes of $4 (2001 — $3; 2000 — $3)	8	(5	)	(5	)
Gain on disposal of discontinued operations, net of income taxes of $10	48	—		—

Assets and liabilities related to the discontinued operations as at December 31 were comprised as follows:

($ millions)	2002	2001
Accounts receivable	—	20
Accounts payable	—	54

(h) Minimum Pension Liability

Under U.S. GAAP, recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. No such adjustment is required under Canadian GAAP.

Under U.S. GAAP, at December 31, 2002, the company would have recognized a minimum pension liability of $80 million (2001 — $52 million; 2000 — $3 million), an intangible asset of $10 million (2001 — $12 million; 2000 — nil) and other comprehensive loss of $48 million, net of income taxes of $22 million (2001 — $28 million, net of income taxes of $12 million). Other comprehensive income for the year ended December 31, 2002, would have been reduced by $20 million, net of income taxes of $10 million (2001 — $26 million, net of income taxes of $11 million; 2000 — $2 million, net of income taxes of $1 million).

(i) Shipping and Handling Costs

The company reports upstream shipping and handling costs billed to customers as a reduction of operating revenues. Under U.S. GAAP, amounts billed to customers for shipping and handling are classified as revenues. The related shipping and handling costs are classified as expenses.

This impact is one of reclassification only and does not affect net earnings. The result would have been to increase operating revenues and operating, selling and general expenses for the year ended December 31, 2002 by $128 million (2001 — $95 million; 2000 — $96 million), respectively.

Recently Issued Accounting Standards

Asset Retirement Obligations

In August 2001, Statement 143, “Accounting for Asset Retirement Obligations,” was issued. This statement changes the method and timing of accruing for costs arising from legal obligations associated with the retirement of tangible capital assets and the associated asset retirement costs. The company is continuing to evaluate the U.S. GAAP impact of implementing Statement 143, effective January 1, 2003.

Exit or Disposal Activities

In June 2002, Statement 146, “Accounting for Costs Associated with Exit or Disposal Activities,” was issued. Statement 146 supercedes previous accounting guidance, principally Emerging Issues Task Force (EITF) No. 94-3. Statement 146 applies to exit and disposal activities initiated after December 31, 2002 and requires that the fair value of a liability for a cost associated with an exit or disposal activity be recognized in the period in which the liability is incurred. Under EITF 94-3, a liability was to be recognized at the date of the company’s commitment to an exit plan. The company is not currently engaged in any exit or disposal activities.

Stock-based Compensation, Transition and Disclosure

Statement 148, “Accounting for Stock-based Compensation, Transition and Disclosure,” issued in December 2002, provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. Statement 148 also requires that disclosures of the pro forma effect of using the fair value method be displayed in a tabular format in both annual and interim reports. Statement 148 is effective for the company’s 2002 fiscal year. The company has no current plans to adopt the fair value method of accounting for stock-based compensation. The pro forma effect of using the fair value method is disclosed in (b) Stock-based Compensation above.

Variable Interest Entities

Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities” (VIE), was issued in January 2003 (see Special Purpose Entities as described in note 9c). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the other equity investors do not have a controlling financial interest in, or do not have sufficient equity at risk to allow the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the company’s third quarter 2003 interim report. The company is currently evaluating the effect that possible consolidation of these VIEs may have on its results of operations and financial condition.