Repsol Oil & Gas Canada (TLM) 40-F 2005 FY Annual report (Canada)

Exhibit 99.7

CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

March 13, 2006

Report of Independent Auditors

To the Shareholders of Talisman Energy Inc.

We have audited the Consolidated Balance Sheets of Talisman Energy Inc. as at December 31, 2005 and 2004 and the Consolidated Statements of Income, Retained Earnings and Cash Flows for each of the years in the three-year period ended December 31, 2005. 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 and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these Consolidated Financial Statements present fairly, in all material respects, the financial position of the Company as at December 31, 2005 and 2004 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2005 in conformity with Canadian generally accepted accounting principles.

As discussed in note 2 to the Consolidated Financial Statements, in 2005 the Company changed its method of accounting for preferred securities.

/s/ Ernst & Young LLP

Ernst & Young LLP

Chartered Accountants
Calgary, Canada

February 27, 2006

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Consolidated Balance Sheets

December 31 (millions of Canadian dollars)	2005		2004
			(restated) (note 2)
Assets
Current
Cash and cash equivalents	130		38
Accounts receivable (note 11)	1,311		836
Inventories (note 4)	170		78
Prepaid expenses	20		18
	1,631		970
Accrued employee pension benefit asset (note 18)	57		61
Other assets	74		64
Goodwill (note 3)	1,504		466
Property, plant and equipment (note 5)	15,073		10,847
	16,708		11,438
Total assets	18,339		12,408
Liabilities
Current
Accounts payable and accrued liabilities (notes 6, 8 and 9)	2,383		1,302
Income and other taxes payable	649		341
	3,032		1,643
Deferred credits (note 11)	74		70
Asset retirement obligations (note 6)	1,320		1,272
Other long-term obligations (notes 8 and 9)	217		35
Long-term debt (note 7)	4,263		2,457
Future income taxes (note 15)	3,638		2,100
	9,512		5,934
Non-controlling interest (note 3)	66		—
Contingencies and commitments (notes 11 and 12)
Shareholders’ equity
Common shares (note 8)	2,609		2,666
Contributed surplus (note 8)	69		71
Cumulative foreign currency translation (note 10)	(265	)	(76	)
Retained earnings	3,316		2,170
	5,729		4,831
Total liabilities and shareholders’ equity	18,339		12,408

See accompanying notes.

On behalf of the board:

/s/ Douglas D. Baldwin	/s/ Robert G. Welty
Douglas D. Baldwin	Robert G. Welty
Chairman of the Board	Director

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Consolidated Statements of Income

Years ended December 31 (millions of Canadian dollars except as otherwise noted)	2005	2004		2003
		(restated) (note 2)		(restated) (note 2)
Revenue
Gross sales	9,554	6,874		5,610
Less hedging loss	77	480		194
Gross sales, net of hedging	9,477	6,394		5,416
Less royalties	1,595	1,124		894
Net sales	7,882	5,270		4,522
Other (note 13)	165	85		76
Total revenue	8,047	5,355		4,598
Expenses
Operating	1,459	1,198		1,039
Transportation	206	192		181
General and administrative	201	183		152
Depreciation, depletion and amortization	1,843	1,650		1,435
Dry hole	241	311		251
Exploration	275	238		213
Interest on long-term debt	166	173		178
Stock-based compensation (note 8)	633	171		185
Other (note 14)	39	89		16
Total expenses	5,063	4,205		3,650
Gain on sale of Sudan operations (note 19)	—	—		296
Income before taxes	2,984	1,150		1,244
Taxes (note 15)
Current income tax	1,058	478		229
Future income tax (recovery)	176	(111	)	(53	)
Petroleum revenue tax	189	129		92
	1,423	496		268
Net income	1,561	654		976
Per common share (Canadian dollars) (note 17)
Net income	4.24	1.71		2.53
Diluted net income	4.14	1.68		2.50
Average number of common shares outstanding (millions)	368	383		386
Diluted number of common shares outstanding (millions)	377	390		391

See accompanying notes.

Consolidated Statements of Retained Earnings

Years ended December 31 (millions of Canadian dollars)	2005		2004		2003
			(restated) (note 2)		(restated) (note 2)
Retained earnings, beginning of year	2,170		1,852		1,088
Net income	1,561		654		976
Common share dividends	(125	)	(114	)	(90	)
Purchase of common shares (note 8)	(290	)	(222	)	(122	)
Retained earnings, end of year	3,316		2,170		1,852

See accompanying notes.

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Consolidated Statements of Cash Flows

Years ended December 31 (millions of Canadian dollars)	2005		2004		2003
			(restated) (note 2)		(restated) (note 2)
Operating
Net income	1,561		654		976
Items not involving cash (note 16)	2,836		2,024		1,502
Exploration	275		238		213
	4,672		2,916		2,691
Deferred gain on unwound hedges	—		—		(9	)
Changes in non-cash working capital (note 16)	199		203		(128	)
Cash provided by operating activities	4,871		3,119		2,554
Investing
Corporate acquisitions (note 3)	(2,549	)	—		—
Capital expenditures
Exploration, development and corporate	(3,206	)	(2,565	)	(2,218	)
Acquisitions (note 3)	(544	)	(317	)	(661	)
Proceeds of resource property dispositions (note 19)	17		75		1,075
Investments	(4	)	—		(11	)
Changes in non-cash working capital	142		50		105
Cash used in investing activities	(6,144	)	(2,757	)	(1,710	)
Financing
Long-term debt repaid	(1,294	)	(1,069	)	(791	)
Long-term debt issued	3,129		912		292
Common shares purchased	(352	)	(284	)	(184	)
Common share dividends	(125	)	(114	)	(90	)
Deferred credits and other	(9	)	164		28
Changes in non-cash working capital	(3	)	(10	)	—
Cash provided by (used in) financing activities	1,346		(401	)	(745	)
Effect of translation on foreign currency cash and cash equivalents	19		(21	)	(28	)
Net increase (decrease) in cash and cash equivalents	92		(60	)	71
Cash and cash equivalents, beginning of year	38		98		27
Cash and cash equivalents, end of year	130		38		98

See accompanying notes.

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Notes to the Consolidated Financial Statements

(tabular amounts in millions of Canadian dollars, except as noted)

1. SIGNIFICANT ACCOUNTING POLICIES

The Consolidated Financial Statements of Talisman Energy Inc. (“Talisman” or the “Company”) have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP). A summary of the differences between accounting principles generally accepted in Canada and those generally accepted in the United States (“US”) is contained in note 21 to these statements.

The Company is in the business of exploration, development, production and marketing of crude oil, natural gas and natural gas liquids.

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

a) Consolidation

The Consolidated Financial Statements include the accounts of Talisman and its subsidiaries. Substantially all of Talisman’s activities are conducted jointly with others and the Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities.

b) Inventories

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

c) Property, Plant and Equipment

The successful efforts method is used to account for oil and gas exploration and development costs. Under this method, acquisition costs of oil and gas properties and costs of drilling and equipping development wells are capitalized. Costs of drilling exploratory wells are initially capitalized and, if subsequently determined to be unsuccessful, are charged to dry hole expense. Exploration wells in areas requiring major capital before production can begin are capitalized as long as drilling efforts are underway or firmly planned. Exploration wells are assessed annually, or more frequently as evaluation conditions dictate, for determination of reserves and, as such, success. All other exploration costs, including geological and geophysical costs and annual lease rentals, are charged to exploration expense when incurred. Producing properties and significant unproved properties are assessed annually, or more frequently as economic events dictate, for potential impairment. Any impairment loss is the difference between the carrying value of the asset and its fair value. Fair value is calculated as the present value of estimated expected future cash flows from proved and probable reserves.

d) Depreciation, Depletion and Amortization

Capitalized costs of proved oil and gas properties are depleted using the unit of production method. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis at a ratio of six thousand cubic feet of natural gas for one barrel of oil.

Successful exploratory wells and development costs are depleted over proved developed reserves while acquired resource properties with proved reserves, including offshore platform costs, are depleted over proved reserves. Acquisition costs of probable reserves are not depleted or amortized while under active evaluation for commercial reserves. Costs are transferred to depletable costs as proved reserves are recognized. At the date of acquisition, an evaluation period is determined after which any remaining probable reserve costs associated with producing fields are transferred to depletable costs; costs not associated with producing fields are amortized over a period not exceeding the remaining lease term.

Costs associated with significant development projects are not depleted until commercial production commences. Unproved land acquisition costs that are individually immaterial are amortized on a straight-line basis over the average lease term until properties are determined to be productive or impaired. Gas plants, net of estimated salvage values, are depreciated on a straight-line basis over their estimated remaining useful lives, not to exceed the estimated remaining productive lives of related fields. Pipelines and corporate assets are depreciated using the straight-line method at annual rates of 7% and 4% to 33%, respectively. Gas plants and pipelines in the North Sea are depreciated using the unit of production method based on the related fields.

e) Asset Retirement Obligations

The fair value of the statutory, contractual or legal liability associated with the retirement and reclamation of tangible long-lived assets is recorded when the related assets are put into use, with a corresponding increase to the carrying amount of the related assets. The increase to capitalized costs is amortized to earnings on a basis consistent with depreciation, depletion and amortization of the underlying assets. Subsequent changes in the estimated fair value of the asset retirement obligations (ARO) are capitalized and amortized over the remaining useful life of the underlying asset. See note 6 for details.

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The ARO liabilities are carried on the Consolidated Balance Sheet at their discounted present value and are accreted over time for the change in their present value, with this accretion charge included in depreciation, depletion and amortization.

Actual expenditures incurred are charged against the accumulated obligation with the resulting difference recognized in income as a gain or loss.

f) Capitalized Interest

Interest costs associated with major development projects are capitalized until the necessary facilities are completed and ready for use. These costs are subsequently amortized to income with the related assets.

g) Royalties

Certain of the Company’s foreign operations are conducted jointly with the respective national oil companies. These operations are reflected in the Consolidated Financial Statements based on Talisman’s working interest in such activities. All other government stakes, other than income taxes, are considered to be royalty interests. Royalties on production from these joint foreign operations represent the entitlement of the respective governments to a portion of Talisman’s share of crude oil, liquids and natural gas production and are recorded using rates in effect under the terms of contracts at the time of production.

h) Petroleum Revenue Tax

United Kingdom Petroleum Revenue Tax (“PRT”) is accounted for using the life of the field method whereby total future PRT is estimated using current reserves and anticipated costs and prices and charged to income based on net operating income as a proportion of estimated future net operating income. Changes in the estimated total future PRT are accounted for prospectively.

i) Foreign Currency Translation

The Company’s functional currency is the US dollar. The Company’s financial results have been reported in Canadian dollars as explained below.

The Company’s self-sustaining operations, which include the Canadian and UK operations, are translated into US dollars using the current rate method, whereby assets and liabilities are translated at period-end exchange rates while revenues and expenses are converted using average rates for the period. Gains and losses on translation to US dollars relating to self-sustaining operations are deferred and included in a separate component of shareholders’ equity described as cumulative foreign currency translation.

The remaining foreign operations are not considered self-sustaining and are translated using the temporal method. Under this method, monetary assets and liabilities denominated in foreign currencies are translated at exchange rates in effect at the balance sheet date. Non-monetary assets and liabilities denominated in foreign currencies are translated at rates in effect on the dates the assets were acquired or liabilities were assumed. Revenues and expenses are translated at rates of exchange prevailing on the transaction dates. Gains and losses on translation are reflected in income when incurred.

The Company’s financial results have been reported in Canadian dollars with amounts translated to Canadian dollars as follows: assets and liabilities at the rate of exchange in effect at the applicable balance sheet date and revenues and expenses at the average exchange rates for the periods. The Company’s share capital accounts, including its common shares and contributed surplus, are translated at rates in effect at the time of issuance. Unrealized gains and losses resulting from the translation to Canadian dollars are included in the cumulative foreign currency translation account.

j) Employee Benefit Plans

The cost of pensions and other retirement benefits earned by employees is determined using the projected benefit method prorated on service and management’s best estimate of expected plan investment performance, salary escalation and retirement ages of employees. There is uncertainty relating to the assumptions used to calculate the net benefit plan expense and accrued benefit obligation which are long term, consistent with the nature of employee future benefits.

The discount rate used to determine the accrued benefit obligation is determined by reference to market interest rates at the measurement date on high quality debt instruments with cash flows that match the timing and amount of expected benefit payments. For purposes of calculating the expected return on plan assets, those assets are valued at fair value. The excess of the cumulative unamortized net actuarial gain or loss over 10% of the greater of the accrued benefit obligation and the fair value of plan assets at the beginning of the year is amortized over the average remaining service life of active employees. The unamortized transitional assets and obligations, and past service costs are being amortized over the average remaining service period of active employees expected to receive benefits under the benefit plans.

k) Derivative Financial Instruments and Commodity Contracts

The Company may enter into derivative financial instruments to hedge against adverse fluctuations in foreign exchange rates, electricity rates, interest rates and commodity prices. Payments or receipts on derivative financial instruments that are designated and effective as hedges are recognized in income concurrently with the hedged transaction and are recorded in the Consolidated Statements of Income and Cash Flows in the line item associated with the hedged transaction. For example, gains and losses on commodity hedges are included in revenues.

If the derivative financial instrument that has been designated as a hedge is terminated or is no longer designated as part of the hedging relationship, the gain or loss on the hedge at that date is deferred and recognized concurrently with the anticipated transaction. If it is no longer probable that the anticipated transaction will occur substantially as and when identified at the inception of the hedging relationship, the gain or loss on the hedge at that date is recognized immediately. Subsequent changes in the value of the derivative financial instrument are reflected in income. Any derivative financial instrument that does not constitute a hedge is recorded at fair value with any resulting gain or loss reflected in income.

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All of the Company’s commodity derivative financial instruments outstanding during 2005 met the hedging requirements under Canadian GAAP. The hedging requirements as amended by Accounting Guideline 13 require the designation of a hedging relationship, including a hedged and a hedging item, identification of the risk exposure being hedged and reasonable assurance that the hedging relationship will be effective throughout its term. In addition, in the case of anticipated transactions, it must also be probable that the transaction designated as being hedged will occur. The Company assesses, both at the hedge’s inception and on an ongoing basis, whether the derivative financial instruments that have been designated as hedges are highly effective in offsetting changes in fair value or cash flows of the hedged items.

The Company enters into commodity contracts in the normal course of business including contracts with fixed terms. The contracts outstanding at December 31, 2005 are disclosed in notes 11 and 12 to the Consolidated Financial Statements. The Company’s production is expected to be sufficient to deliver all required volumes under these contracts. No amounts are recognized in the Consolidated Financial Statements related to these contracts until such time as the associated volumes are delivered.

l) Income Taxes

Talisman uses the liability method to account for income taxes. Under the liability method, future income taxes are based on the differences between assets and liabilities reported for financial accounting purposes from those reported for income tax. Future income tax assets and liabilities are measured using substantively enacted tax rates. The impact of a change in tax rate is recognized in net income in the period in which the tax rate is substantively enacted.

Certain of the Company’s contractual arrangements in foreign jurisdictions stipulate that income taxes are to be paid by the respective national oil company out of its entitlement share of production. Such amounts are included in income tax expense at the statutory tax rate in effect at the time of production.

m) Revenue Recognition

Revenues associated with the sale of crude oil, natural gas and liquids are recognized when title passes from the Company to the customer. Crude oil and natural gas produced and sold by the Company below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue. Amounts received under take-or-pay gas sales contracts in respect of undelivered volumes are accounted for as deferred income and recognized as revenue when volumes are delivered. Transportation expenses are reported as a separate expense and not netted off against revenue.

n) Stock-based Compensation

Talisman has stock options or stock appreciation rights, cash unit plans and deferred share units for employees and directors, which are described in note 8. In 2003, the option plans were amended to provide holders of stock options the choice upon exercise to receive a cash payment in exchange for surrendering the option. Commencing in 2003, as a result of the amendment to the stock option plans, the Company began to use the intrinsic-value method to recognize compensation expense associated with its stock appreciation rights. Obligations are accrued on a graded vesting basis on the difference between the market value of the Company’s common shares and the exercise price of the options. This obligation is revalued each reporting period based on the changes in the graded vested number of options outstanding and changes in the market value of the Company’s common shares. Prior to 2003, no amount of compensation expense was recognized in the Consolidated Financial Statements for stock-based compensation.

o) Goodwill

Goodwill represents the excess purchase price over the fair value of identifiable assets and liabilities acquired in business combinations. Goodwill is not amortized but is subject to ongoing annual impairment reviews, or more frequently as economic events dictate, based on the fair value of reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the goodwill impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s individual assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount. The Company’s reporting units are consistent with the geographic segments included in note 20.

p) Net Income and Diluted Net Income Per Share

Net income per share is calculated by dividing net income by the weighted-average number of common shares outstanding. Diluted net income per share is calculated giving effect to the potential dilution that could occur if stock options were exercised in exchange for common shares.

The Company uses the treasury stock method to determine the dilutive impact of options. This method assumes that any proceeds from the exercise of options would be used to purchase common shares at the average market price during the period.

q) Cash and Cash Equivalents

Cash and cash equivalents include short-term investments with an original maturity of three months or less. Cash and cash equivalents are stated at cost, which approximates market value.

r) Measurement Uncertainty

To facilitate the timely preparation of the Consolidated Financial Statements, management has made estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts.

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Amounts recorded for depreciation, depletion and amortization and amounts used for impairment calculations are based on estimates of oil and natural gas reserves and commodity prices and capital costs required to develop those reserves. By their nature, estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the Consolidated Financial Statements of future periods could be material.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

The values of pension assets and obligations and the amount of pension costs charged to net income depend on certain actuarial and economic assumptions which, by their nature, are subject to material measurement uncertainty.

s) Reclassification

Certain information provided for prior years has been reclassified to conform to the presentation adopted in the current year.

2. CHANGE IN ACCOUNTING POLICY

Preferred Securities

Effective January 1, 2005, the Company retroactively adopted certain changes to the Canadian Institute of Chartered Accountants (“CICA”) accounting standard for financial instruments. The change to this standard requires that the Company’s preferred securities, all of which were redeemed in 2004, be treated as debt rather than equity. Previously preferred securities charges were charged directly to retained earnings but, under these changes to the accounting standard, they would have been charged to interest expense. In addition, since the preferred securities would have been treated as debt, the balance would have been revalued at each balance sheet date with the offsetting movement reflected in the cumulative foreign currency translation account. As a result, there would not have been a gain on the redemption of the preferred securities. There was no impact to the 2005 results as the preferred securities were fully redeemed by the end of the second quarter in 2004.

The adjustment required to the December 31, 2004 Consolidated Balance Sheet to implement this change in accounting is as follows:

	As previously reported		Adjustments		As restated
Cumulative foreign currency translation	(150	)	74		(76	)
Retained earnings	2,244		(74	)	2,170

The adjustment to the Consolidated Statement of Income for the year ended December 31, 2004 is as follows:

	As previously reported		Adjustments		As restated
Interest on long-term debt	158		15		173
Future income tax (recovery)	(105	)	(6	)	(111	)
Net income	663		(9	)	654
Preferred securities charges, net of tax	(9	)	9		—
Gain on redemption of preferred securities, net of tax	23		(23	)	—
Net income available to common shareholders	677		(23	)	654
Per common share (Canadian dollars)
Net income	1.77		(.06	)	1.71
Diluted net income	1.74		(.06	)	1.68

The adjustment to the Consolidated Statement of Income for the year ended December 31, 2003 is as follows:

	As previously reported		Adjustments		As restated
Interest on long-term debt	137		41		178
Future income tax (recovery)	(48	)	(5	)	(53	)
Net income	1,012		(36	)	976
Preferred securities charges, net of tax	(22	)	22		—
Net income available to common shareholders	990		(14	)	976
Per common share (Canadian dollars)
Net income	2.56		(.03	)	2.53
Diluted net income	2.53		(.03	)	2.50

3. ACQUISITIONS

The following acquisitions have been accounted for using the purchase method and the results have been included in these Consolidated Financial Statements from the dates of acquisitions.

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Corporate Acquisitions

Paladin Resources plc In November 2005, Talisman acquired control (73%) of Paladin Resources plc (Paladin), an oil and gas exploration and development company. An additional 25% of the shares were acquired prior to year end resulting in a 98% ownership interest in Paladin at December 31, 2005. The 98% of Paladin was acquired for $2,560 million in cash and $74 million in long-term debt, net of cash acquired ($11 million). The acquisition has been accounted for using the purchase method and the Paladin results have been included in the Consolidated Financial Statements of the Company from the date of acquisition. The remaining 2% of Paladin was acquired in January 2006. The Company’s evaluation of the net assets and liabilities acquired has not yet been finalized.

Fair value of net assets acquired	North Sea		Southeast Asia and Australia		North Africa		Combined
Property, plant and equipment	2,956		324		14		3,294
Net non-cash working capital	(9	)	—		—		(9	)
Goodwill	891		26		4		921
Fair value of derivatives	(147	)	—		—		(147	)
Future income tax	(1,138	)	(48	)	(5	)	(1,191	)
Asset retirement obligations	(155	)	(13	)	—		(168	)
Non-controlling interest	(66	)	—		—		(66	)
	2,332		289		13		2,634

Other Acquisitions

During 2005, Talisman completed a number of oil and gas property and corporate acquisitions for a total cost of $536 million, comprised of $544 million in cash, assumed working capital ($12 million) and $4 million of properties exchanged. Four transactions accounted for the majority of the acquisitions and were acquired for a total cost of $515 million. These acquisitions included oil and gas properties in North America and the North Sea.

Fair value of net assets acquired	North America		North Sea		Combined
Property, plant and equipment	218		486		704
Goodwill	—		177		177
Asset retirement obligations	—		(81	)	(81	)
Future income tax	(70	)	(215	)	(285	)
	148		367		515

During 2004, Talisman completed a number of oil and gas property and corporate acquisitions for a total cost of $330 million, comprised of $317 million in cash, ($1 million) of assumed working capital and $14 million of properties exchanged. Three of the transactions account for the majority of the acquisitions and were acquired for a total cost of $288 million. These three acquisitions included oil and gas properties in North America and the North Sea.

Fair value of net assets acquired	North America	North Sea		Combined
Property, plant and equipment	93	374		467
Asset retirement obligations	—	(101	)	(101	)
Future income tax	—	(78	)	(78	)
	93	195		288

Goodwill Continuity

	2005		2004
Opening balance at January 1	466		473
Acquired during year	1,098		—
Foreign currency translation effect	(60	)	(7	)
Closing balance at December 31	1,504		466

4. INVENTORIES

December 31	2005	2004
Materials and supplies	99	75
Product	71	3
	170	78

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5. PROPERTY, PLANT AND EQUIPMENT

	Cost	Accumulated DD&A	Net book value
December 31, 2005
Oil and gas properties	13,542	5,662	7,880
Gas plants, pipelines and production equipment	10,339	3,277	7,062
Corporate assets	342	211	131
	24,223	9,150	15,073
December 31, 2004
Oil and gas properties	9,789	4,730	5,059
Gas plants, pipelines and production equipment	8,795	3,102	5,693
Corporate assets	275	180	95
	18,859	8,012	10,847

In the year ended December 31, 2005, interest costs of $19 million (2004 – $13 million; 2003 – $24 million) were capitalized.

Included in property, plant and equipment are the following costs that were not subject to depreciation, depletion or amortization (DD&A) as at December 31:

Non-depleted capital at December 31	2005	2004
Acquired unproved reserve costs (1)
North America – associated with producing fields	34	38
North Sea – associated with producing fields	823	—
Southeast Asia and Australia – associated with producing fields	63	—
North Sea – not associated with producing fields	465	54
Other – not associated with producing fields	164	41
Exploration costs (2)	450	284
Development Projects (3)
North America	30	16
Southeast Asia and Australia	369	345
North Sea	826	117
Trinidad and Tobago	—	255
	3,224	1,150

(1)Acquisition costs of unproved reserves are not depleted or amortized while under active evaluation for commercial reserves.

(2)Exploration costs consist of drilling in progress and wells awaiting determination of proved reserves, approval of development plans or commencement of production.

(3)Development projects are not depleted pending initial production.

				Greater than
Summary of exploration costs	Total	Less than 1 year	1 to 3 years	3 years
North America	328	276	52	—
North Sea	16	16	—	—
Southeast Asia and Australia	10	4	6	—
North Africa	23	1	—	22
Trinidad and Tobago	45	27	18	—
Other	28	22	6	—
	450	346	82	22

In North America, the non-depleted exploration costs increased by $126 million as $112 million was reclassified to depletable capital, $38 million expensed to dry hole, and $276 million spent during the year was added to non-depleted exploration capital. Costs of $52 million relating to 10 wells drilled prior to 2005 continue to be capitalized, as management’s ongoing assessment includes further development activity planned for 2006.

In the North Sea, the non-depleted exploration costs decreased by $3 million as $18 million was reclassified to depletable capital, $1 million expensed to dry hole, and $16 million in additional capital was added to non-depleted exploration capital.

In Southeast Asia and Australia, the non-depleted exploration costs increased by $2 million as $2 million was reclassified to depletable capital and $4 million spend during the year was added to non-depleted exploration capital. Costs of $6 million relating to one well drilled prior to 2005 continue to be capitalized, as management’s ongoing assessment includes further development activity planned for 2006.

In North Africa, the non-depleted exploration costs did not change as $1 million in new capital spending was offset by foreign exchange movements on the previously existing balances. During the year, the Company approved plans for the Phase 2 development of the MLN fields involving injection of gas and drilled two additional wells. The EMK unit development plan project sanction is expected in 2006. The costs associated with the MLSE and EMK unit wells continue to be capitalized as the Company actively pursues development, including drilling additional wells.

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In Trinidad and Tobago, the non-depleted exploration costs increased by $25 million as $1 million was reclassified to depletable capital, $2 million expensed to dry hole and $26 million spent during the year was added to non-depleted exploration capital, with the remaining $2 million increase resulting from foreign exchange movements. Costs of $18 million relating to three wells drilled prior to 2005 continue to be capitalized, as management’s ongoing assessment includes further development activity planned for 2006.

In other exploration areas, the non-depleted exploration costs increased by $16 million as $5 million was expensed to dry hole, and $21 million spend during the year was added to non-depleted exploration capital. Costs of $6 million relating to one well drilled prior to 2005 continue to be capitalized, as management’s ongoing assessment includes further development activity planned for 2006.

6. ASSET RETIREMENT OBLIGATIONS

Total accretion for year ended December 31, 2005 of $76 million (2004 – $70 million; 2003 – $58 million) has been included in depreciation, depletion and amortization. At December 31, 2005, the estimated total undiscounted asset retirement obligations were $3.1 billion (2004 – $2.6 billion). These obligations will be settled based on the estimated useful lives of the underlying assets, the majority of which are expected to be settled within the next 30 years. The ARO has been discounted using credit-adjusted risk free rates of 5.5% in the North Sea and 6.5% in North America and rest of world. No amount of market risk premium has been included in the estimate of the Company’s ARO liability as management does not believe there to be sufficient evidence in the oil and gas industry to estimate any such market premium.

During the years the Company’s asset retirement obligations changed as follows:

	2005		2004
ARO liability at January 1	1,295		1,177
Liabilities incurred during the year	279		126
Liabilities settled during the year	(32	)	(29	)
Accretion expense	76		70
Revisions in estimated cash flows	(111	)	(44	)
Foreign currency translation	(159	)	(5	)
ARO liability at December 31(1)	1,348		1,295

(1)Included in December 31, 2004 and December 31, 2005 liabilities are $23 million and $28 million respectively of short-term reclamation costs recorded in accounts payable on the balance sheet for a net long-term ARO liability of $1,272 million and $1,320 million, respectively.

7. LONG-TERM DEBT

December 31	2005	2004
Bank Credit Facilities (1)
5.39% Bank Credit Facilities	43	328
5.29% Acquisition Credit Facility (2)	1,848	—
Debentures and Notes (Unsecured) (3)
6.96% notes (US$200 million), due 2005	—	241
6.89% notes (US$50 million), Series B, due 2006 (2), (4)	58	60
5.80% medium term notes, due 2007	385	385
7.125% debentures (US$175 million), due 2007	204	211
6.68% notes (US$100 million), due 2008	117	120
8.06% medium term notes, due 2009	174	174
5.125% notes (US$375 million), due 2015 (5)	437	—
6.625% notes (£250 million), due 2017 (6)	501	577
7.25% debentures (US$300 million), due 2027	350	361
5.75% notes (US$125 million), due 2035	146	—
	4,263	2,457

(1)Rates reflect the weighted-average interest rate of instruments outstanding at December 31. Rates are floating rate-based and vary with changes in short-term market interest rates.

(2)The amounts outstanding at December 31, 2005 have been classified as long-term debt since the Company has the ability and intention to replace this debt with long-term borrowings under the revolving bank credit facilities and through the long-term notes issued subsequent to year end. At year end, £725 million had been effectively swapped into US$1,272 million. See note 11 to the Consolidated Financial Statements.

(3)Interest on debentures and notes is payable semi-annually except for interest on the 6.625% notes (£250 million) which is payable annually, and the 6.68% notes (US$100 million) which is paid quarterly.

(4)Repayable in five equal annual instalments commencing 2006.

(5)The interest rate on US$300 million of this debenture has been swapped to a floating rate obligation bearing interest at three-month LIBOR plus 0.433% (4.97% at December 31, 2005). See note 11 to the Consolidated Financial Statements.

(6)Prior to January 1, 2004, the £250 million Eurobond was effectively swapped into US$364 million indebtedness. Effective January 2004 this debt is no longer swapped into US dollars and is now revalued based on the Canadian dollar to pound sterling exchange rate. See note 11 to the Consolidated Financial Statements.

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Bank Credit Facilities

At December 31, 2005, Talisman had unsecured credit facilities totaling $1,345 million, consisting of facilities of $585 million (Facility No. 1), $510 million (Facility No. 2), $150 million (Facility No. 3), $50 million (Facility No. 4) and $50 million (Facility No. 5). The maturity dates of Facilities No. 1 and 2 are June 30, 2008 and June 30, 2010, respectively and September 30, 2008 for Facilities 3, 4 and 5, although these dates may be extended from time to time upon agreement between the Company and the respective lenders. Prior to the maturity date, the Company may borrow, repay and reborrow at its discretion. All facilities must be repaid on their maturity dates.

Borrowings under Facilities No. 1 and 2 are available in the form of prime loans, Canadian or US dollar bankers’ acceptances, US dollar base rate loans or LIBOR-based loans. In addition, drawings to a total of $548 million are available in the form of letters of credit. Borrowings under Facility No. 3 are available in the form of prime loans, Canadian or US dollar bankers’ acceptances, US dollar base rate loans, LIBOR-based loans and letters of credit. Borrowings under Facility No. 4 are available in the form of prime loans, Canadian or US dollar guaranteed notes, US dollar base rate loans and LIBOR-based loans. Borrowings under Facility No. 5 are available in the form of prime loans, Canadian or US dollar banker’s acceptances, US dollar base rate loans and LIBOR-based loans. See note 12 for summary of letters of credit.

Subsequent Event

Subsequent to year end, Talisman completed a US$500 million offering of 5.85% notes due February 1, 2037 and a $350 million offering of 4.44% notes due January 27, 2011. Interest on both notes is paid semi-annually. The $350 million offering was immediately swapped into US$304 million 5.054% debt. The proceeds from these note offerings were used to repay a portion of the outstanding acquisition credit facility.

Acquisition Credit Facility

In connection with the funding of the acquisition of Paladin, the Company arranged a $2,605 million (£1,300 million), unsecured non-revolving acquisition credit facility maturing in October 2006. At December 31, 2005, $1,848 million was drawn on this facility. Subsequent to year end, the proceeds from the note offerings were used to repay a portion of the amounts outstanding under the acquisition credit facility. Following this repayment, the amounts drawn were approximately US$850 million. Borrowings are available in US dollars or pounds sterling in the form of bankers’ acceptances or LIBOR-based loans.

Paladin Credit Facility

At the time of Talisman’s acquisition of Paladin, Paladin was party to a US$600 million senior credit facility secured by the assets of Paladin. At year end, draws under this facility were $43 million, and were repaid subsequent to year end. Talisman is currently in the process of cancelling this credit facility.

Repayment Schedule

The Company’s contractual minimum repayments of long-term debt are as follows:

Year
2006 (1)	12
2007	601
2008	571
2009	186
2010	521
Subsequent to 2010	2,372
Total	4,263

(1)The portion of long-term debt payable in 2006 has been classified as long-term debt since the Company has the ability and intention to replace this debt with long-term borrowings under the revolving bank credit facilities.

8. SHARE CAPITAL

Talisman’s authorized share capital consists of an unlimited number of common shares without nominal or par value and first and second preferred shares. No preferred shares have been issued.

	2005				2004				2003
Continuity of common shares	Shares		Amount		Shares		Amount		Shares		Amount
Balance, beginning of year	375,185,290		2,666		383,996,184		2,725		393,118,305		2,785
Issued on exercise of options	165,125		8		182,900		5		884,679		11
Purchased during year	(9,089,100	)	(65	)	(8,987,400	)	(64	)	(10,006,800	)	(71	)
Cancelled pursuant to terms of plans of arrangements	—		—		(6,394	)	—		—		—
Balance, end of year	366,261,315		2,609		375,185,290		2,666		383,996,184		2,725

During the year ended December 31, 2005, Talisman repurchased 9,089,100 common shares of the Company pursuant to a NCIB for a total of $355 million (2004 – 8,987,400 for $286 million; 2003 – 10,006,800 for $194 million). The cost to repurchase common shares in excess of their average book value has been charged to retained earnings, contributed surplus and cumulative foreign currency translation.

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In 2005, Talisman did not cancel any common shares of the Company (2004 – 6,394; 2003 – nil shares) pursuant to the terms of the offering agreements of certain past corporate acquisitions.

a) Stock Option Plans

Talisman has stock option plans that grant options to employees and directors. All options issued by the Company permit the holder to purchase one common share of the Company at the stated exercise price or, effective July 1, 2003, to receive a cash payment equal to the appreciated value of the stock option. Options granted under the plans are generally exercisable after three years and expire 10 years after the grant date. Option exercise prices approximate the market price for the common shares on the date the options were granted.

	2005			2004			2003
Continuity of stock options	Number of Options		Average Exercise Price ($)	Number of Options		Average Exercise Price ($)	Number of Options		Average Exercise Price ($)
Outstanding at January 1	20,788,375		19.58	23,599,596		17.55	22,152,162		15.51
Granted	5,921,130		42.16	3,695,580		25.68	7,184,097		19.83
Exercised for common shares	(165,125	)	16.57	(182,900	)	12.74	(884,679	)	11.27
Exercised for cash payment	(4,832,109	)	17.67	(6,023,241	)	15.49	(4,260,711	)	11.84
Forfeited	(217,032	)	30.88	(300,660	)	21.12	(591,273	)	19.60
Outstanding at December 31	21,495,239		26.14	20,788,375		19.58	23,599,596		17.55
Exercisable at December 31	5,873,954		17.37	7,731,478		15.73	7,742,865		12.46
Options available for future grants pursuant to the Company’s Stock Option Plans	15,791,886			16,663,875			14,035,554

The range of exercise prices of the Company’s outstanding stock options is as follows:

December 31, 2005	Outstanding Options			Exercisable Options
Range of exercise prices ($)	Number of options	Weighted-average exercise price($)	Weighted-average years to expiry	Number of options	Weighted-average exercise price($)
8.59 – 19.99	10,446,152	18.10	6	4,438,052	15.81
20.00 – 29.99	5,203,152	24.32	8	1,399,072	21.69
30.00 – 39.99	43,425	32.55	9	—	—
40.00 – 49.99	5,761,260	42.08	9	36,830	42.06
50.00 – 57.05	41,250	57.05	10	—	—
8.59 – 57.05	21,495,239	26.14	7	5,873,954	17.37

The mark-to-market liability for the stock option plans as at December 31, 2005 was $657 million (2004 – $214 million).

b) Cash Unit Plan

In addition to the Company’s stock option plans, Talisman’s subsidiaries issue stock appreciation rights under the cash unit plans. Cash units are similar to stock options except that the holder does not have a right to purchase the underlying share of the Company.

	2005			2004			2003
Continuity of cash units	Number of units		Average exercise price ($)	Number of units		Average exercise price ($)	Number of units		Average exercise price ($)
Outstanding at January 1	1,526,640		21.34	1,153,515		19.83	—		—
Granted	997,310		42.22	399,075		25.63	1,170,165		19.82
Exercised	(9,900	)	19.80	—		—	—		—
Forfeited	(63,695	)	27.62	(25,950	)	19.80	(16,560	)	19.80
Outstanding at December 31	2,450,355		29.68	1,526,640		21.34	1,153,515		19.83
Exercisable at December 31	—		—	—		—	—		—

At December 31, 2005, the weighted-average years to expiry was eight years and the mark-to-market liability was $56 million (2004 – $9 million).

c) Deferred Share Units

Talisman also issues deferred share units to directors in lieu of cash compensation. Each deferred share unit (DSU) represents the right to receive a cash payment on retirement equal to the market value of the Company’s share at the time of surrender. Dividends are credited as additional DSU’s when paid. As at December 31, 2005, there were 67,444 (2004 – 57,275) units outstanding. The mark-to-market liability of $4 million (2004 – $2 million) is included in accrued liabilities on the balance sheet.

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d) Stock-based Compensation

For the year ended December 31, 2005, the Company recorded stock-based compensation expense of $633 million (2004 – $171 million; 2003 – $185 million) relating to its stock option and cash unit plans. Of the total expense, $153 million (2004 – $82 million; 2003 – $47 million) relates to options and cash units exercised for cash, the remaining $480 million (2004 – $89 million; 2003 – $138 million) is primarily a result of the 90% (2004 – 32%; 2003 – 29%) increase in the Company’s share price during the year. In addition the Company capitalized $15 million (2004 – $nil; 2003 – $nil) of stock-based compensation during the year.

Year ended December 31	2005		2004		2003
Average exercise price	$	49.22	$	29.06	$	22.81
Average grant price	17.67		15.49		11.84
Average gain per exercise	$	31.55	$	13.57	$	10.97
Number of options and cash units exercised	4,842,009		6,023,241		4,260,711
Cash expense ($millions)	153		82		47

Of the combined mark-to-market liability for the stock option and cash unit plans of $713 million as at December 31, 2005 (2004 – $223 million), $630 million (2004 – $223 million) is included in accrued liabilities on the Consolidated Balance Sheet.

9. OTHER LONG-TERM OBLIGATIONS

The balance in other long-term obligations consists of the following:

	2005	2004
Pensions and other post-retirement benefits	40	33
Mark-to-market liability for stock-based compensation	83	—
Fair value of commodity price derivatives acquired	47	—
Discounted obligations on capital leases	40	—
Other	7	2
Closing balance at December 31	217	35

As a result of the acquisition of Paladin, Talisman acquired commodity price derivative contracts which extend to the end of 2008. The mark-to-market liability recorded on acquisition will be amortized to revenue over the remaining life of the underlying derivative contracts. Of the total liability acquired, $84 million is included in accounts payable and accrued liabilities.

During the second quarter of 2005, the Company entered into a leasing arrangement for the modification, refitting and use of a floating storage and offloading vessel (FSO). This vessel has been deployed on the South Angsi development in Malaysia.

The modifications to the FSO have been completed and an element of the leasing arrangement has been defined by the Company as a capital lease. The future minimum lease payments are US$5 million for each of the next five years and US$28 million for the remainder of the lease. The imputed rate of interest on the lease is 6% and the lease expires in 2016. Of the total discounted liability of $46 million, $6 million is included in accounts payable and accrued liabilities.

10. CUMULATIVE FOREIGN CURRENCY TRANSLATION

In accordance with the Company’s foreign exchange translation accounting policy, as disclosed in note 1(i), foreign exchange gains or losses on translation of self-sustaining foreign operations and the translation of the Company’s financial results into Canadian dollars for reporting purposes are included in shareholders’ equity in the cumulative foreign currency translation account.

The following components give rise to the exchange gains or (losses) included in the cumulative foreign currency translation account as at December 31:

	2005		2004
			(restated) (1)
Property, plant and equipment	(1,218	)	(586	)
Future tax liabilities (including PRT)	202		44
Asset retirement obligations	160		1
Long-term debt	634		520
Working capital	49		(23	)
Goodwill	(92	)	(32	)
	(265	)	(76	)

(1)Prior years have been retroactively restated to reflect the retroactive adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

11. FINANCIAL INSTRUMENTS

Commodity Price Derivative Contracts

The Company enters into crude oil and natural gas price derivative contracts to reduce the volatility of the Company’s cash flows associated with anticipated sales of these commodities. The Company’s outstanding commodity price derivative contracts have been designated as hedges of the Company’s anticipated future commodity sales and, as such, gains and losses on these contracts are realized in income over the terms of the contracts.

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During the year, the Company entered into natural gas price derivative contracts and acquired various crude oil and natural gas derivative contracts as a result of the acquisition of Paladin. The fair value of derivative contracts acquired was a liability of $147 million. This amount will be amortized into income over the remaining term of the contracts. Virtually all of the acquired derivative contracts qualify for hedge accounting and, as such, subsequent unrealized changes in the fair value of these contracts are deferred and realized in income over the remaining term of the contracts. The Company had the following commodity price derivative contracts outstanding at December 31, 2005.

Crude Oil Derivatives

Fixed price swaps	Hedge type	Term		(bbls/d)	US$/bbl
Dated Brent oil index	cash flow	2006	Jan – Jun	8,287	33.11
Dated Brent oil index	cash flow	2006	Jul – Dec	7,337	32.23
Dated Brent oil index	cash flow	2007	Jan – Jun	6,630	41.65
Dated Brent oil index	cash flow	2007	Jul – Dec	6,522	40.90
Dated Brent oil index	cash flow	2008	Jan – Jun	2,473	59.63
Dated Brent oil index	cash flow	2008	Jul – Dec	815	60.00

Natural Gas Derivatives

Forward sales	Hedge type	Term		mcf/d	£/mcf
Fixed price swaps (IPE/Heron index)	cash flow	2006	Jan – Mar	4,838	5.88
Fixed price swaps (IPE/Heron index)	cash flow	2006	Apr – Jun	2,419	3.41
Fixed price swaps (IPE/Heron index)	cash flow	2006	Jul – Sep	2,419	3.22

Natural Gas Derivatives

Two-way collars	Hedge type	Term		mcf/d	Floor CDN$/mcf		Ceiling CDN$/mcf
Two-way collars (IPE/Heron index)	cash flow	2006	Jan – Mar	2,419	6.72 (£/mcf	)	9.30 (£/mcf	)
Two-way collars (AECO index)	cash flow	2006	Feb – Mar	36,697	11.69		12.72
Two-way collars (AECO index)	cash flow	2006	Apr – Oct	64,220	8.82		10.98
Two-way collars (AECO index)	cash flow	2006	Nov – Mar 07	59,633	9.61		11.98
Two-way collars (AECO index)	cash flow	2007	Apr – Oct	41,284	7.41		9.71

Interest Rate and Foreign Exchange Derivative Contracts

In order to hedge a portion of the fair value risk associated with the US$375 million 5.125% notes due 2015, the Company entered into fixed to floating interest rate swap contracts with a total notional amount of US$300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three-month US$ LIBOR plus 0.433% while receiving payments of 5.125% semi-annually. These contracts have been designated as a hedge of the fair value of a portion (US$300 million) of the total US$375 million notes issued in May 2005.

In order to facilitate the exchange of the acquisition credit facility from pounds sterling into the Company’s functional currency (USD) the Company entered into forward contracts to buy UK pounds sterling (GBP) and sell US dollars. At December 31, 2005 foreign currency contracts were in place for £725 million at a rate of 1.7543US$/£; subsequent to year end additional contracts were executed and the amounts outstanding under the acquisition facility (£938 million) were exchanged for US$1,646 million resulting in an average exchange rate of 1.7552.

As a result of the acquisition of Paladin, Talisman acquired a foreign exchange derivative contract to swap US$15.1 million to NOK at a rate of 6.4475 NOK/US on March 31, 2006. The fair value of the contract acquired was less than $1 million; the contract is not designated as a hedge and is therefore recorded at fair value.

Effective January 1, 2004, certain US dollar cross currency swap contracts and interest rate swap contracts were no longer designated as hedges of the Eurobond and the Company recorded a deferred gain of $17 million, which is being amortized over the period to 2009, the original term of the contracts.

In December 1994, in anticipation of issuing the US$175 million 7.125% debentures, Talisman entered into interest rate swap contracts to hedge against possible adverse interest rate fluctuations. These contracts required Talisman to pay interest at 8.295% in exchange for receiving payments at the three-month LIBOR rate on a notional principal amount of US$100 million. These contracts expired on May 16, 2005.

The Company’s operations in the UK and Canada are largely self-sufficient (self-sustaining) and their economic exposure is more closely tied to their respective domestic currencies. Accordingly, these operations are measured in UK pounds sterling and Canadian dollars, respectively. Currently, the Company’s foreign exchange translation exposure principally relates to US dollar denominated UK and Canadian oil sales.

As part of the adoption by the Company as at January 1, 2004, of the new accounting guideline on Hedging Relationships, AcG 13 and effective January, 2004, the Eurobond debt denominated in UK pounds sterling, and the Company’s Canadian dollar debt were designated as hedges of the Company’s net investments in the UK and Canadian self-sustaining operations, respectively. As such the unrealized foreign exchange gains and losses resulting from the translation of this debt are deferred and included in a separate component of shareholders’ equity described as cumulative foreign currency translation.

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Carrying Amounts and Estimated Fair Values of Financial Instruments

	2005						2004
Asset (liability) at December 31	Carrying Value		Fair Value		Unrecognized		Carrying Value		Fair Value		Unrecognized
Long-term debt	(4,263	)	(4,423	)	(160	)	(2,457	)	(2,659	)	(202	)
Cross currency and interest rate swaps	(1	)	(7	)	(6	)	(3	)	(3	)	—
Natural gas derivatives	(4	)	9		13		—		—		—
Crude oil derivatives	(126	)	(163	)	(37	)	—		(41	)	(41	)

Borrowings under bank credit facilities are for short terms and are market rate based, thus, carrying value approximates fair value. The fair value of debentures and notes is based on market quotations, which reflect the discounted present value of the principal and interest payments using the effective yield at December 31 for instruments having the same term and risk characteristics. Fair values for interest rate derivative instruments are determined based on the estimated cash payment or receipt necessary to settle the contract at December 31. Cash payments or receipts are based on discounted cash flow analysis using current market rates and prices. Fair values for commodity and foreign exchange derivatives are based on forward pricing curves as at December 31.

The fair values of other financial instruments, including cash and cash equivalents, accounts receivable and accounts payable approximate their carrying values.

Interest Rate Risk

Drawings under the Company’s bank credit facilities are at floating interest rates and expose the Company to interest rate risk. The Company is also exposed to interest rate risk on maturity and refinancing of its fixed rate debt.

Credit Risk

A significant portion of the Company’s accounts receivable is due from entities in the oil and gas industry. Concentration of credit risk is mitigated by having a broad domestic and international customer base, which includes a significant number of companies engaged in joint operations with Talisman. The Company routinely assesses the financial strength of its partners and customers, including parties involved in marketing or other commodity arrangements. At December 31, 2005, the Company’s largest credit exposure to a single party was approximately $154 million.

The Company is exposed to credit risk associated with possible non-performance by derivative instrument counterparties. The Company actively limits the total exposure to individual counterparties.

12. CONTINGENCIES AND COMMITMENTS

From time to time, Talisman is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below, may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on the Company’s financial position.

Talisman continues to be subject to a lawsuit brought by the Presbyterian Church of Sudan and others commenced in November 2001 under the Alien Tort Claims Act in the United States District Court for the Southern District of New York (the Court). The lawsuit, which is seeking class action status, alleges that the Company conspired with, or aided and abetted, the Government of Sudan to commit violations of international law in connection with the Company’s now disposed of interest in oil operations in Sudan. On August 30, 2005, the Court denied Talisman’s motion for Court approval to appeal the Court’s prior denial of Talisman’s motion for judgment on the pleadings, which sought dismissal of the lawsuit. Also on August 30, 2005, the Court declined to dismiss the lawsuit in response to the filing of a Statement of Interest by the US Department of Justice, expressing the US government’s view that the lawsuit interferes with US-Canada relations. On September 20, 2005, the Court denied, for the second time, the plaintiffs’ motion to certify the lawsuit as a class action. On October 5, 2005, the plaintiffs filed papers to appeal the decision denying class action status. The Company has filed papers opposing the plaintiffs’ appeal. Talisman believes the lawsuit is entirely without merit and is continuing to vigorously defend itself. Talisman does not expect the lawsuit to have a material adverse effect on it.

Talisman’s estimated total undiscounted future ARO at December 31, 2005 was $3.1 billion (2004 – $2.6 billion), approximately 66% of which is denominated in UK pounds sterling. At December 31, 2005, Talisman had accrued $1,348 million (2004 – $1,295 million) of this liability. The Company has provided letters of credit, effective January 1, 2006 in an amount of $467 million of which majorities were provided as security for the costs of future dismantlement, site restoration and abandonment obligations in the North Sea ($336 million). The remaining outstanding letters of credit primarily relate to a retirement compensation arrangement, guarantees of minimum work commitments and abandonment obligations in other areas. In addition, the Company has issued guarantees as security for certain minimum work, future dismantlement, site restoration and abandonment obligations in lieu of letters of credit.

Talisman leases certain of its ocean-going vessels and corporate offices, all of which, with the exception of the leasing arrangement as described in note 9 to the Consolidated Financial Statements, are accounted for as operating leases. In addition to the minimum lease payments, Talisman has ongoing operating commitments associated with the vessels. The term of the Ross Floating Production, Storage and Offloading vessel (FPSO) lease depends on the expected life of the Ross and Blake fields.

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Estimated Future Minimum Commitments (1)

	2006	2007	2008	2009	2010	Subsequent to 2010	Total
Office leases	28	26	22	21	23	87	207
Vessel leases (2)	59	14	6	6	6	33	124
Transportation and processing commitments (3)	155	106	87	71	68	557	1,044
Minimum work commitments	319	53	—	19	—	—	391
Abandonment obligations	40	28	28	16	18	2,984	3,114
Other service contracts (4)	311	364	226	93	23	26	1,043
Total	912	591	369	226	138	3,687	5,923

(1)Future minimum payments denominated in foreign currencies have been translated into Canadian dollars based on the December 31, 2005 exchange rate.

(2)Includes the future minimum lease payments of the FSO under capital lease.

(3)Certain of the Company’s transportation commitments are tied to firm gas sales contracts.

(4)Other service contracts consist primarily of drilling rig commitments to meet a portion of the Company’s future drilling requirements.

During 2004, the Company signed a long-term contract to sell 810 bcf of Corridor natural gas to West Java, over a 17-year period with gas sales commencing in 2007, at a price of US$1.91/mcf, with no associated transportation costs. The Company anticipates having sufficient production to meet all future delivery commitments.

Talisman has firm commitments for gathering, processing and transportation services that require the Company to pay tariffs to third parties for processing or shipment of certain minimum quantities of crude oil and liquids and natural gas. The Company anticipates having sufficient production to meet these commitments.

The Company has also entered into sales contracts for a portion of its future North American natural gas production. The following are the average volumes under contract and the weighted-average contract price in each of the years shown. The company has sufficient future production to meet these fixed price sales contracts as the volumes represent less than 2% of the anticipated future North American production.

Natural Gas (North America)

Fixed price sales	2006	2007	2008	2009	2010	2011
Volumes (mcf/d)	14,650	12,208	3,552	3,552	3,552	3,552
Weighted-average price ($/mcf)	3.82	3.96	3.31	3.41	3.51	3.62

13. OTHER REVENUE

Years ended December 31	2005	2004	2003
Pipeline and custom treating tariffs	141	73	63
Investment income	14	9	9
Marketing income	10	3	4
	165	85	76

14. OTHER EXPENSES

Years ended December 31	2005		2004		2003
Net (gain) loss on asset disposals	(3	)	30		(14	)
Foreign exchange (gain) loss	(7	)	30		7
Property impairments	31		31		30
Gain on derivatives settlement	—		(15	)	—
Other expense (income)	18		13		(7	)
	39		89		16

42

15. TAXES

Income Taxes

The current and future income taxes for each of the three years ended December 31 are as follows:

	2005		2004		2003
			(restated) (1)		(restated) (1)
Current income taxes
North America (2)	95		43		21
North Sea	558		266		99
Southeast Asia and Australia	291		134		84
North Africa	47		33		—
Trinidad and Tobago	64		—		—
Sudan	—		—		17
Other	3		2		8
	1,058		478		229
Future income taxes (recovery)
North America	160		(64	)	(52	)
North Sea	72		(28	)	23
Southeast Asia and Australia	(34	)	9		(13	)
North Africa	8		8		4
Trinidad and Tobago	2		(1	)	(10	)
Sudan	—		—		9
Other	(32	)	(35	)	(14	)
	176		(111	)	(53	)
Income taxes	1,234		367		176

(1)Prior years have been retroactively restated to reflect the retroactive adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

(2)Current North America income taxes include the Canadian federal tax on large corporations, net of Alberta royalty tax credits.

The components of the net future tax liability at December 31 are as follows:

	2005	2004
Future tax liabilities
Property, plant and equipment	4,156	2,531
Pension assets	19	21
Other	169	146
	4,344	2,698
Future tax assets
Provision for asset retirement obligations	578	517
Other	128	81
	706	598
Net future tax liability	3,638	2,100

Future distribution taxes associated with operations in the UK have not been recorded because, based on current plans, repatriation of funds in excess of foreign reinvestment will not result in material amounts of tax expense. Unremitted earnings in other foreign jurisdictions are not material.

Income taxes vary from the amount that would be computed by applying the Canadian statutory income tax rate of 34.13% for the year ended December 31, 2005 (2004 – 34.13%; 2003 – 35.36%) as follows:

Years ended December 31	2005		2004		2003
			(restated) (1)		(restated) (1)
Income taxes calculated at the Canadian statutory rate	1,018		392		449
Increase (decrease) in income taxes resulting from:
Non-deductible royalties, mineral taxes and expenses	84		104		158
Resource allowances	(63	)	(84	)	(122	)
Change in statutory tax rates	—		(50	)	(160	)
Non-taxable expense (income)	22		17		(80	)
Deductible PRT expense	(27	)	(43	)	(32	)
Higher (lower) foreign tax rates (net)	173		26		(2	)
Provincial rebates and credits	(7	)	1		(12	)
Federal tax on large corporations	9		9		10
Other	25		(5	)	(33	)
Income taxes	1,234		367		176

(1)Prior years have been retroactively restated to reflect the retroactive adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

43

Petroleum Revenue Taxes

Petroleum Revenue Tax (PRT) expense primarily relates to the UK and is comprised of current tax expense of $150 million (2004 – $124 million; 2003 – $72 million) and deferred tax expense of $39 million (2004 – $5 million; 2003 – $20 million). The measurement of PRT expense and the related provision in the Consolidated Financial Statements is subject to uncertainty associated with future recovery of oil and gas reserves, commodity prices and the timing of future events, which could result in material changes to deferred amounts.

16. CONSOLIDATED STATEMENTS OF CASH FLOWS

Selected cash flow information:

Years ended December 31	2005		2004		2003
			(restated) (1)		(restated) (1)
Net income	1,561		654		976
Items not involving cash
Depreciation, depletion and amortization	1,843		1,650		1,435
Property impairments	31		31		30
Dry hole	241		311		251
Net (gain) loss on asset disposals	(3	)	30		(14	)
Gain on sale of Sudan operations	—		—		(296	)
Stock-based compensation	480		89		138
Future taxes and deferred petroleum revenue tax (recovery)	215		(106	)	(33	)
Other	29		19		(9	)
	2,836		2,024		1,502
Exploration	275		238		213
	4,672		2,916		2,691
Deferred gain on unwound hedges	—		—		(9	)
Changes in non-cash working capital	199		203		(128	)
Cash provided by operating activities	4,871		3,119		2,554
Cash interest paid (net of capitalized interest)	171		165		177
Cash income taxes paid	757		289		168

(1)Prior years have been retroactively restated to reflect the retroactive adoption of the change in accounting policy for Preferred Securities. See note 2 for details. Changes in operating non-cash working capital consisted of the following:

Years ended December 31	2005		2004		2003
Accounts receivable	(175	)	(72	)	(32	)
Inventories	(64	)	19		32
Prepaid expenses	(2	)	—		4
Asset retirement obligations expenditures	(32	)	(29	)	(24	)
Accounts payable and accrued liabilities	254		103		(63	)
Income and other taxes payable	218		182		(45	)
Net source (use) of cash	199		203		(128	)

17. NET INCOME AND DILUTED NET INCOME PER SHARE

The following table summarizes the calculation of basic net income and diluted net income per share.

	2005	2004	2003
		(restated) (1)	(restated) (1)
Net income available to common shareholders	1,561	654	976
Weighted-average number of common shares outstanding (millions) – basic	368	383	386
Dilution effect of stock options (millions)	9	7	5
Weighted-average number of commons shares outstanding (millions) – diluted	377	390	391
Net income per share ($/share)
Basic	4.24	1.71	2.53
Diluted	4.14	1.68	2.50

(1)Prior years have been retroactively restated to reflect the adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

Outstanding stock options are the only instruments that are currently dilutive to earnings per share. For 2005, 1,796,624 stock options that were antidilutive have been excluded from the computation of diluted earnings per share (2004 – 29,100; 2003 – 3,504,630).

44

18. EMPLOYEE BENEFITS

The Company sponsors both defined benefit and defined contribution pension arrangements covering substantially all employees. Defined benefit pension plans are based on years of service and final average salary. The defined pension benefits in the UK and Norway, which account for 30% of the accrued benefit obligation as at December 31, 2005, will increase at the rate of inflation. Although the Company has no commitment to provide for increases related to inflation on the remainder of its defined benefit pension plans, the benefits have increased annually by one-half of the rate of inflation.

The Company uses actuarial reports prepared by independent actuaries for funding and accounting purposes. The Company uses a December 31 measurement date for the majority of its defined benefit pension plans. The most recent actuarial valuation of the benefit plans for funding purposes was as of December 31, 2004, with the next valuation as of December 31, 2005, planned for the second quarter of 2006. The following significant actuarial assumptions were employed to determine the periodic pension expense and the accrued benefit obligations:

	2005	2004	2003
Accrued benefit obligation
Discount rate (%)	4.9	5.6	6.1
Rate of compensation increase (%)	4.3	4.3	4.5
Benefit expense
Discount rate (%)	5.6	5.9	6.4
Expected long-term rate of return on plan assets (%)	7.0	7.0	7.5
Assumed health care cost trend rates
Initial health care cost trend rate (%)	10.0	10.0	10.0
Health care cost trend rate declines to (%)	5.0	5.0	5.0
Year that the cost trend rate reaches final rate	2018	2018	2018

The Company’s net benefit plan expense is as follows:

	2005		2004		2003
Current service cost – defined benefit	10		10		7
Current service cost – defined contribution	8		8		7
Interest cost	10		10		8
Plan amendments	—		3		—
Actual return on plan assets	(16	)	(17	)	(17	)
Actuarial loss on accrued benefit obligation	19		6		15
Costs arising in the period	31		20		20
Differences between costs arising in the period and net benefit plan expense
Return on plan assets	4		6		8
Plan amendments	—		(3	)	—
Actuarial (gain) loss	(14	)	7		(13	)
Amortization of net transitional asset	(2	)	(2	)	(1	)
Net benefit plan expense	19		28		14

45

Information about the Company’s defined pension benefit plans is as follows:

	2005 Pension plans grouped by funded status				2004 Pension plans grouped by funded status
	Surplus		Deficit (1)		Surplus		Deficit (1)
Accrued benefit obligation
Accrued benefit obligation, beginning of year (2)	95		80		93		47
Current service cost	6		4		6		4
Interest cost	5		5		6		4
Actuarial losses (gains)	10		9		(2	)	8
Plan participants’ contributions	1		—		1		—
Benefits paid	(3	)	(2	)	(4	)	(1	)
Plan amendments	—		—		—		3
Other	—		(1	)	—		10
Accrued benefit obligation, end of year (2)	114		95		100		75
Plan assets
Fair value of plan assets, beginning of year (2)	152		29		136		10
Actual gain on plan assets	16		1		16		2
Employer contributions	6		4		17		4
Plan participants’ contributions	1		—		1		—
Surplus applied to defined contribution plan	(8	)	—		(8	)	—
Benefits paid	(3	)	(2	)	(4	)	(1	)
Expenses	(1	)	—		(1	)	—
Other	—		(3	)	—		9
Fair value of plan assets, end of year (2)	163		29		157		24
Funded status – surplus (deficit) (3)	49		(66	)	57		(51	)
Unamortized net actuarial losses	14		30		12		17
Unamortized prior service cost	—		3		—		5
Unamortized net transitional (asset) obligation	(6	)	3		(8	)	4
Net accrued benefit asset (liability)	57		(30	)	61		(25	)

(1)The net accrued benefit liability for pension plans with a deficit funding status is included in other long-term obligations on the Consolidated Balance Sheet.

(2)During 2005, the executive pension plan changed from a surplus to a deficit status. As a result, the 2005 opening balances have been adjusted to give effect to this reclassification as follows: accrued benefit obligation increased by $5 million and fair value of plan assets increased by $5 million. At December 31, 2004, the plan was in a surplus status and, accordingly, the 2004 balances have not been reclassified.

(3)The funding deficit on the retirement compensation agreement is secured by letters of credit.

The net benefit plan expense of $19 million for the year ended December 31, 2005 (2004 – $28 million; 2003 – $14 million) is determined by using actuarial assumptions including expected return on plan assets and includes the amortization of net actuarial losses and net transitional assets and obligations as described in note 1(j).

The composition of the plan assets as a percentage of fair value is as follows:

	2005	2004	2003
Equity securities (%)	76	76	70
Fixed income (%)	24	23	30
Cash (%)	—	1	—
	100	100	100

The approximate target allocation percentage for the Canadian employee and executive plans that account for 58% of total plan assets is 70% equities, 30% bonds and expected return on assets is 8.2% equities and 4.8% bonds. The Company’s plan assets do not include any common shares of Talisman.

The projected future benefit payments are as follows:

2006	2007	2008	2009	2010	2011 – 2015
6	7	7	8	8	52

At December 31, 2005, the actuarial net present value of the accrued benefit obligation for other post-retirement benefit plans was $13 million (2004 – $12 million; 2003 – $8 million). The other post-retirement benefit plans provide medical, dental and life benefits for active and retired employees. The effect of a one-percentage point change in the assumed health care cost trend rates on accrued benefit obligations and benefit costs would be immaterial.

46

19. SALE OF SUDAN OPERATIONS

On March 12, 2003, the Company completed the sale of its 25% indirectly held interest in the Greater Nile Oil Project in Sudan. Total gross proceeds were $1.13 billion (US$771 million), including interest and cash received by Talisman during the interim period between September 1, 2002 and closing on March 12, 2003. The gain on sale is as follows:

Gross proceeds on sale of Sudan operations (US$ 771 million)	1,135
Less interim adjustments	(123	)
	1,012
Property, plant and equipment	687
Working capital and other assets	72
Future income tax liability	(59	)
Net carrying value at March 12, 2003	700
Closing costs	16
Gain on disposal	296

20. SEGMENTED INFORMATION

Talisman’s activities are conducted in six geographic segments: North America, the North Sea, Southeast Asia and Australia, North Africa, Trinidad and Tobago and other international locations.  The Sudan operations were sold in 2003.  North America includes operations in Canada and the US. The North Sea includes operations in the United Kingdom, the Netherlands, Norway and Denmark. The Southeast Asia and Australia segment includes operations in Indonesia, Malaysia, Vietnam and Australia. The North Africa segment includes operations in Algeria and Tunisia. All activities relate to the exploration, development, production and transportation of oil, liquids and natural gas.

47

	North America (2)					North Sea (3)				Southeast Asia and Australia (4)				North Africa (5)
	2005		2004	2003		2005		2004	2003	2005	2004		2003	2005	2004	2003
Revenue
Gross sales
Oil and liquids	1,029		838	744		3,049		2,154	1,639	865	669		369	349	254	94
Natural gas	3,021		2,213	2,073		271		231	190	662	451		244	—	—	—
Synthetic oil	69		57	42		—		—	—	—	—		—	—	—	—
Sulphur	10		7	6		—		—	—	—	—		—	—	—	—
Total gross sales	4,129		3,115	2,865		3,320		2,385	1,829	1,527	1,120		613	349	254	94
Hedging	78		151	85		(1	)	329	83	—	—		21	—	—	5
Royalties	816		599	587		56		37	8	553	391		156	135	97	46
Net sales	3,235		2,365	2,193		3,265		2,019	1,738	974	729		436	214	157	43
Other	76		62	54		88		23	23	1	—		—	—	—	—
Total revenue	3,311		2,427	2,247		3,353		2,042	1,761	975	729		436	214	157	43
Segmented expenses
Operating
Oil and liquids	142		135	131		808		627	498	56	73		64	24	17	12
Natural gas	300		257	237		36		23	14	31	25		22	—	—	—
Synthetic oil	30		23	22		—		—	—	—	—		—	—	—	—
Pipeline	6		6	5		15		12	16	—	—		—	—	—	—
Total operating expenses	478		421	395		859		662	528	87	98		86	24	17	12
Transportation	75		75	78		79		66	63	43	42		36	9	9	4
DD&A	946		785	688		670		661	616	144	174		95	36	30	17
Dry hole	122		128	135		53		109	69	11	25		9	—	4	1
Exploration	128		123	87		53		28	21	40	20		17	—	—	—
Other	(10	)	18	(28	)	54		30	26	1	(9	)	9	—	—	—
Total segmented expenses	1,739		1,550	1,355		1,768		1,556	1,323	326	350		252	69	60	34
Segmented income (loss) before taxes	1,572		877	892		1,585		486	438	649	379		184	145	97	9
Non-segmented expenses
General and administrative
Interest on long-term debt
Gain on sale of Sudan operations
Stock-based compensation
Currency translation
Total non-segmented expenses
Income before taxes
Capital expenditures
Exploration	658		590	453		165		150	99	74	54		70	2	—	4
Development	879		821	629		867		357	397	231	201		246	25	8	30
Midstream	72		41	27		—		—	—	—	—		—	—	—	—
Exploration and development	1,609		1,452	1,109		1,032		507	496	305	255		316	27	8	34
Property acquisitions (1)
Midstream acquisitions
Proceeds on dispositions
Other non-segmented
Net capital expenditures
Property, plant and equipment	6,985		6,214	5,767		6,072		3,074	2,995	1,465	1,050		1,084	177	178	202
Goodwill	291		291	291		1,086		75	74	123	100		108	4	—	—
Other	663		419	403		614		347	386	348	221		217	43	36	27
Segmented assets	7,939		6,924	6,461		7,772		3,496	3,455	1,936	1,371		1,409	224	214	229
Non-segmented assets
Total assets

(1) Excluding corporate acquisitions.

(2) North America

		2005	2004	2003
Revenues	Canada	2,965	2,199	2,095
	US	346	228	152
		3,311	2,427	2,247
Property, plant and equipment	Canada	6,551	5,738	5,356
	US	434	476	411
		6,985	6,214	5,767

(3) North Sea

		2005	2004	2003
Revenues	United Kingdom	2,683	1,897	1,699
	Netherlands	56	36	26
	Norway	604	109	36
	Denmark	10	—	—
		3,353	2,042	1,761
Property, plant and equipment	United Kingdom	4,620	2,858	2,777
	Netherlands	45	41	40
	Norway	1,149	175	178
	Denmark	258	—	—
		6,072	3,074	2,995

48

	Trinidad and Tobago					Sudan				Other						Total
	2005	2004		2003		2005	2004	2003		2005		2004		2003		2005		2004		2003
Revenue
Gross sales
Oil and liquids	229	—		—		—	—	209		—		—		—		5,521		3,915		3,055
Natural gas	—	—		—		—	—	—		—		—		—		3,954		2,895		2,507
Synthetic oil	—	—		—		—	—	—		—		—		—		69		57		42
Sulphur	—	—		—		—	—	—		—		—		—		10		7		6
Total gross sales	229	—		—		—	—	209		—		—		—		9,554		6,874		5,610
Hedging	—	—		—		—	—	—		—		—		—		77		480		194
Royalties	35	—		—		—	—	97		—		—		—		1,595		1,124		894
Net sales	194	—		—		—	—	112		—		—		—		7,882		5,270		4,522
Other	—	—		—		—	—	(1	)	—		—		—		165		85		76
Total revenue	194	—		—		—	—	111		—		—		—		8,047		5,355		4,598
Segmented expenses
Operating
Oil and liquids	11	—		—		—	—	18		—		—		—		1,041		852		723
Natural gas	—	—		—		—	—	—		—		—		—		367		305		273
Synthetic oil	—	—		—		—	—	—		—		—		—		30		23		22
Pipeline	—	—		—		—	—	—		—		—		—		21		18		21
Total operating expenses	11	—		—		—	—	18		—		—		—		1,459		1,198		1,039
Transportation	—	—		—		—	—	—		—		—		—		206		192		181
DD&A	47	—		—		—	—	19		—		—		—		1,843		1,650		1,435
Dry hole	21	12		—		—	—	—		34		33		37		241		311		251
Exploration	5	21		35		—	—	5		49		46		48		275		238		213
Other	—	1		—		—	—	—		1		19		2		46		59		9
Total segmented expenses	84	34		35		—	—	42		84		98		87		4,070		3,648		3,128
Segmented income (loss) before taxes	110	(34	)	(35	)	—	—	69		(84	)	(98	)	(87	)	3,977		1,707		1,470
Non-segmented expenses
General and administrative																201		183		152
Interest on long-term debt																166		173		178
Gain on sale of Sudan operations																—		—		(296	)
Stock-based compensation																633		171		185
Currency translation																(7	)	30		7
Total non-segmented expenses																993		557		226
Income before taxes																2,984		1,150		1,244
Capital expenditures
Exploration	51	33		58		—	—	7		134		125		93		1,084		952		784
Development	21	158		72		—	—	(5	)	—		—		—		2,023		1,545		1,369
Midstream	—	—		—		—	—	—		—		—		—		72		41		27
Exploration and development	72	191		130		—	—	2		134		125		93		3,179		2,538		2,180
Property acquisitions (1)																536		330		638
Midstream acquisitions																—		—		130
Proceeds on dispositions																(22	)	(88	)	(1,112	)
Other non-segmented																28		26		38
Net capital expenditures																3,721		2,806		1,874
Property, plant and equipment	275	182		137		—	—	—		99		149		8		15,073		10,847		10,193
Goodwill	—	—		—		—	—	—		—		—		—		1,504		466		473
Other	24	11		11		—	—	—		13		—		7		1,705		1,034		1,051
Segmented assets	299	193		148		—	—	—		112		149		15		18,282		12,347		11,717
Non-segmented assets																57		61		63
Total assets																18,339		12,408		11,780

(4) Southeast Asia and Australia

		2005	2004	2003
Revenues	Indonesia	408	346	340
	Malaysia	539	363	85
	Vietnam	28	20	11
	Australia	—	—	—
		975	729	436
Property, plant and equipment	Indonesia	371	327	384
	Malaysia	818	701	677
	Vietnam	23	22	23
	Australia	253	—	—
		1,465	1,050	1,084

(5) North Africa

		2005	2004	2003
Revenues	Algeria	212	157	43
	Tunisia	2	—	—
		214	157	43
Property, plant and equipment	Algeria	162	178	202
	Tunisia	15	—	—
		177	178	202

49

21. INFORMATION REGARDING UNITED STATES GAAP DIFFERENCES

Accounting Principles Generally Accepted in the United States

The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (Canadian GAAP) which, in most respects, conform to accounting principles generally accepted in the United States (US GAAP). Significant differences between Canadian and US GAAP follows:

Net Income in Accordance with US GAAP

Years ended December 31 (millions of Canadian dollars)	Notes	2005		2004		2003
				(restated) (1)		(restated) (1)
Net income – Canadian GAAP		1,561		654		976
Foreign exchange loss	4	—		—		(62	)
Depreciation, depletion and amortization	1,2,3,7	(41	)	(35	)	(19	)
(Loss) gain on derivative instruments	4	(19	)	85		(17	)
Deferred income taxes	2	(6	)	(16	)	14
Gain on sale of Sudan operations	7	—		(296	)
Interest on long-term debt	4	1		6		—
Results of discontinued operations, net of tax	7	—		—		(57	)
		(65	)	40		(437	)
Income from continuing operations		1,496		694		539
Results of discontinued operations, net of tax	7	—		—		330
Income before cumulative effect of changes in accounting principles		1,496		694		869
Cumulative effect of changes in accounting principles, net of tax	8	—		—		53
Net income – US GAAP		1,496		694		922
Income per common share (Canadian dollars)
Basic
Continuing operations		4.07		1.81		1.40
Discontinued operations		—		—		0.85
Before cumulative effect of changes in accounting principles		4.07		1.81		2.25
Cumulative effect of changes in accounting principles, net of tax		—		—		0.14
Net income		4.07		1.81		2.39
Diluted
Continuing operations		3.97		1.78		1.38
Discontinued operations		—		—		0.84
Before cumulative effect of changes in accounting principles		3.97		1.78		2.22
Cumulative effect of changes in accounting principles, net of tax		—		—		0.14
Net income		3.97		1.78		2.36

(1)Prior years have been retroactively restated to reflect the adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

Comprehensive Income in Accordance with US GAAP

Years ended December 31 (millions of Canadian dollars)	Notes	2005		2004		2003
Net income – US GAAP		1,496		694		922
Other comprehensive income
Foreign exchange gain on translation unrealized of self-sustaining operations	6	40		288		650
Minimum pension liability, net of tax	10	(8	)	—		—
Unrealized change in fair value of financial instruments, net of tax	4	(20	)	(40	)	—
Comprehensive income – US GAAP		1,508		942		1,572

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Statement of Cash Flow Items in Accordance with US GAAP follows:

Years ended December 31 (millions of Canadian dollars)	Notes	2005		2004		2003
				(restated) (1)		(restated) (1)
Operating
Cash provided by operating activities	9	4,596		2,881		2,341
Investing
Cash used in investing activities	9	(5,869	)	(2,519	)	(1,497	)
Financing
Cash provided by (used in) financing activities		1,346		(401	)	(745	)
Effect of translation on foreign currency cash		19		(21	)	(28	)
Net increase (decrease) in cash and cash equivalents		92		(60	)	71
Cash and cash equivalents beginning of year		38		98		27
Cash and cash equivalents end of year		130		38		98

(1)Prior years have been retroactively restated to reflect the adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

Balance Sheet Items in Accordance with US GAAP follows:

		2005				2004
December 31 (millions of Canadian dollars)	Notes	Canadian GAAP		US GAAP		Canadian GAAP		US GAAP
						(restated) (1)
Current assets		1,631		1,631		970		970
Property, plant and equipment	1-3	15,073		15,343		10,847		11,158
Other non-current assets	4,10	1,635		1,562		591		521
		18,339		18,536		12,408		12,649
Current liabilities		3,032		3,032		1,643		1,643
Long-term debt		4,263		4,263		2,457		2,457
Future income taxes	2	3,638		3,574		2,100		2,045
Other non-current liabilities	4,10	1,611		1,616		1,377		1,366
		12,544		12,485		7,577		7,511
Non-controlling interest		66		66		—		—
Shareholders’ equity
Common shares		2,609		2,609		2,666		2,666
Contributed surplus	5	69		86		71		88
Cumulative foreign currency translation	4,6	(265	)	(1,397	)	(76	)	(1,169	)
Accumulative other comprehensive income	4,6,10	—		1,121		—		1,068
Retained earnings	1-7	3,316		3,566		2,170		2,485
Total liabilities and shareholders’ equity		18,339		18,536		12,408		12,649

(1)Prior years have been retroactively restated to reflect the adoption of the change in accounting policy for Preferred Securities. See note 2 for details.

21.1 Gains on Property Exchanges Under both US and Canadian GAAP, property exchanges are recorded at the carrying value of the assets given up unless the exchange transaction includes significant cash consideration, in which case it is recorded at fair value. Under US GAAP, asset exchange transactions are recorded at fair value if cash consideration is greater than 25% (10% under Canadian GAAP) of the fair value of total consideration given or received. The resulting differences in the recorded carrying values of these properties result in differences in depreciation, depletion and amortization expense in subsequent years. During 2005, the Company early adopted the new standards for Canadian GAAP which were effective January 1, 2006, to coincide with the new US standards, as effective in the third quarter of 2005. The new standard will eliminate this US GAAP difference on a go forward basis. There was no impact in 2005.

21.2 Income Taxes and Depreciation, Depletion and Amortization Expense In 2000, the Company adopted the liability method to account for income taxes. The change to the liability method has eliminated a difference between Canadian and US GAAP, however, in accordance with the recommendations of the CICA, the effect of the adoption under Canadian GAAP resulted in a charge to retained earnings, whereas, under US GAAP, the future tax costs that gave rise to the Canadian GAAP adjustment have already been reflected in property, plant and equipment. As a result of the implementation method, further differences in depreciation, depletion and amortization expense result in subsequent years. Other adjustments to the Canadian GAAP net income required under US GAAP, as disclosed in this note, have been tax effected as necessary.

21.3 Impairments In 2004, the Company adopted a new standard that eliminated a US GAAP reconciling item in respect to impairments on a go forward basis. Under both US and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under US GAAP, and effective in 2004 Canadian GAAP as disclosed in note 1(c), if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated expected future cash flows. Prior to 2004, under Canadian GAAP, the impairment loss was the difference between the carrying value of the asset and its net recoverable amount (undiscounted). Previous impairment charges not required under Canadian GAAP have resulted in differences in depreciation, depletion and amortization expense in subsequent years.

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21.4 Forward Foreign Exchange Contracts and Other Financial Instruments The Company has designated, for Canadian GAAP purposes, its derivative financial instruments as hedges, as described in note 11. In accordance with Canadian GAAP, payments or receipts on these contracts are recognized in income concurrently with the hedged transaction. The fair values of the contracts deemed to be hedges are not reflected in the Consolidated Financial Statements.

Effective January 1, 2001, for US GAAP purposes, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. Effective with the adoption of this standard, every derivative instrument, including certain derivative instruments embedded in other contracts, is recognized on the balance sheet at fair value. The statement requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Prior to January 1, 2004, management had not designated any of the currently held derivative instruments as hedges for US GAAP purposes and, accordingly, these derivatives were recognized on the balance sheet at their fair value with the change in their fair value recognized in earnings. Subsequent to January 1, 2004, management has designated its commodity derivative financial instruments as hedges for US GAAP purposes and, accordingly, the changes in their fair value are now recognized in other comprehensive income (OCI) with any ineffective portion recognized in earnings. The ineffective portion was not significant in 2005 (2004 – $1 million). In 2005 the change in the fair value of derivative financial instruments decreased OCI by $20 million, net of income tax of $10 million. For fair value hedges, such as cross currency and interest rate swaps, both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both is reflected in income.

21.5 Appropriation of Contributed Surplus In 1992, concurrent with a change in control of the Company, $17 million of contributed surplus was appropriated to retained earnings to eliminate the deficit at June 30, 1992. This restatement of retained earnings is not permitted under US GAAP as the events that precipitated it did not constitute a quasi-reorganization.

21.6 Foreign Exchange Gains and Losses on Translation of Self-sustaining Foreign Operations Under US GAAP, foreign exchange gains and losses on translation of self-sustaining foreign operations are added to or deducted from net income, net of tax, in determining comprehensive income. Under Canadian GAAP, such gains and losses are included as a separate component of shareholders’ equity referred to as cumulative translation adjustment.

21.7 Discontinued Operations Under US GAAP, effective November 1, 2002, the Sudan assets were classified as Assets Held For Sale with the Sudan operating results, net of tax, classified on the Statement of Income as results of operations held for sale. No depreciation, depletion or amortization has been recorded commencing November 1, 2002 related to these assets. The sale closed March 12, 2003.

21.8 Asset Retirement Obligations Effective January 1, 2003, for US GAAP purposes, and January 1, 2004, for Canadian GAAP purposes, the Company adopted SFAS No. 143 and CICA 3110, respectively, which changes the method of accruing for costs associated with the retirement of fixed assets which an entity is legally obligated to incur. These standards require entities to record the fair value of a liability for an asset retirement obligation in the period it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. The adoption of the new standard in Canada in 2004 eliminated a US GAAP reconciling item in respect to accounting for these obligations, however, a difference is created in how the transition amounts are recorded.

US GAAP requires the cumulative impact of a change in an accounting policy to be presented in the current year Statement of Earnings in the year of adoption, 2003, and prior periods are not to be restated. Canadian GAAP requires retroactive restatement of prior year financial statements.

The following table presents the pro forma effects of the retroactive application of this change in accounting principle. There was no pro forma effect on income from discontinued operations.

	2005	2004	2003
Pro forma net income (1)	1,496	694	869
Pro forma per common share
Basic	4.07	1.81	2.25
Diluted	3.97	1.78	2.22

(1)Pro forma net income for 2003 has been adjusted to remove the $53 million cumulative effect of a change in accounting principle attributable to SFAS No. 143.

21.9 Cash Provided by Operating Activities Presentation Under US GAAP, exploration expense is treated as an operating item.

21.10 Additional minimum benefit obligation – Under US GAAP, the amount by which the accumulated benefit obligation exceeds the fair value of the plan assets, must be recognized as an additional minimum liability. In addition, an intangible asset is recognized equal to the lesser of the additional minimum liability and the unrecognized prior service costs. The excess of the additional minimum liability over the unrecognized prior service costs is reported in comprehensive income, net of tax. As a result, other non-current liabilities are higher by $16 million and other assets are higher by $4 million. In 2005, OCI decreased by $8 million net of $4 million of income tax.

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Newly Issued US Accounting Standards

Share-based Payments

The Financial Accounting Standards Board (FASB) issued a revised Statement No. 123, Share-based Payment. FAS 123(R) establishes a standard for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. FAS 123(R) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award – usually the vesting period. FAS 123(R) eliminates the alternative to use the intrinsic value method of accounting that was provided in Statement 123 as originally issued. The Company will continue to record expense in its Consolidated Financial Statements as described in note 1(n) but in addition to those expense items there will be a need for an additional expense amount, under the FAS 123(R), relating to the fair value of the options as at the grant date. The impact of this additional expense amount on the Company’s financial position, operating results or cash flow is uncertain given the volatility of the assumptions needed to determine the new fair value amount. FAS 123(R) is effective for public companies as of the beginning of 2006.

Conditional Asset Retirement Obligations

During 2005, the FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligations as used in the FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on the Company’s results of operations or financial position.

Accounting Changes and Error Corrections

In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. In the absence of explicit transition provisions provided for in new or existing accounting pronouncements, Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to do so. The Statement is effective for fiscal years beginning after December 15, 2005. The Company does not expect the adoption of this statement will have a material impact on its results of operations or financial position.

Summary US Dollar Information

Unless otherwise noted, all amounts in the Consolidated Financial Statements, including Accounting Principles Generally Accepted in the United States above, are reported in millions of Canadian dollars. The following information reflects summary financial information prepared in accordance with US GAAP translated from Canadian dollars to US dollars at the average exchange rate prevailing in the respective year.

US$ million (except as noted)	2005	2004	2003
Total revenue	6,642	4,116	3,281
Net income	1,235	533	658
Net income per common share (US$/share)	3.36	1.39	1.71
Average exchange rate (US$/C$)	0.8258	0.7686	0.7135

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CONSOLIDATED FINANCIAL RATIOS

The following financial ratios are provided in connection with the Company’s shelf prospectus, filed with Canadian and US securities regulatory authorities, and are based on the Company’s Consolidated Financial Statements that are prepared in accordance with accounting principles generally accepted in Canada.

The interest coverage ratio is for the 12 month period ended December 31, 2005.

December 31, 2005 (unaudited)
Interest coverage (times)
Income (1)	16.00

(1)Net income plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

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