15. UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

These consolidated financial statements have been prepared in accordance with Canadian GAAP, which, in most respects, conform to U.S. GAAP. Significant differences between Canadian and U.S. GAAP are as follows:

A. Earnings and Earnings per share (EPS)
			3 months ended Sept. 30			9 months ended Sept. 30
	Reconciling
	items		2005		2004		2005		2004
Earnings from continuing operations - Canadian GAAP		$	52.1	$	35.8	$	128.6	$	98.5
Derivatives and hedging activities, net of tax	I		0.3		(0.4)		(1.5)		(2.4)
Start-up costs, net of tax	II		–		(0.1)		(0.1)		(0.1)
Amortization of pension transition adjustment	V		(1.0)		(1.2)		(3.0)		(3.5)
Earnings from continuing operations - U.S. GAAP			51.4		34.1		124.0		92.5
Net gain on disposal of discontinued operations - Canadian and U.S. GAAP			–		–		–		9.6
Net earnings - U.S. GAAP		$	51.4	$	34.1	$	124.0	$	102.1
Foreign currency cumulative translation adjustment	I,VII		9.1		0.2		8.0		23.8
Net (loss) gain on derivative instruments	I,VII		(214.1)		5.9		(274.7)		(5.7)
Comprehensive (loss) income - U.S. GAAP		$	(153.6)	$	40.2	$	(142.7)	$	120.2
Basic EPS - U.S. GAAP
Earnings from continuing operations		$	0.26	$	0.18	$	0.63	$	0.48
Net gain on disposal of discontinued operations			–		–		–		0.05
Net earnings		$	0.26	$	0.18	$	0.63	$	0.53
Diluted EPS - U.S. GAAP
Earnings from continuing operations		$	0.26	$	0.18	$	0.63	$	0.48
Net gain on disposal of discontinued operations			–		–		–		0.05
Net earnings		$	0.26	$	0.18	$	0.63	$	0.53

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B. Balance sheet information
			Sept. 30, 2005		Dec. 31, 2004
	Reconciling	Canadian	U.S.	Canadian	U.S.
	items	GAAP	GAAP	GAAP	GAAP 1
Assets
Price risk management assets, current	I	249.1	255.5	61.4	109.2
Accounts receivable	VIII	567.3	567.3	447.0	445.5
Income taxes receivable	I	62.2	84.3	60.1	75.1
Property, plant and equipment, net	II	5,572.9	5,569.8	5,702.6	5,680.7
Price risk management assets, long-term	I	38.9	205.0	32.5	220.2
Other assets (including current portion)	I, II	199.2	59.7	502.4	300.5
Liabilities
Accounts payable and accrued liabilities	V	561.0	545.1	462.5	387.6
Income taxes payable	II	–	–	6.1	0.7
Price risk management liabilities, current	I	230.3	483.9	49.9	82.1
Long-term debt	I	1,989.7	2,032.5	2,321.1	2,365.0
Deferred credits and other liabilities (including current portion)	I, XI	387.5	387.5	639.3	646.1
Price risk management liabilities, long-term	I	36.7	274.6	28.5	77.1
Future or deferred income tax liabilities	I, II, IV, V	754.9	606.3	715.0	705.9
(including current portion)
Non-controlling interest	I	597.3	596.7	616.4	615.4
Equity
Contributed surplus	X, XI	–	133.0	–	133.0
Retained earnings	I, II, V, XI	872.8	728.9	891.5	752.2
Cumulative translation adjustment	I	(59.2)	–	(52.2)	–
Accumulated other comprehensive income	I, V, VII	–	(359.3)	–	(92.6)

1
   Restated, reconciling items X and XI
C. Reconciling items
I. Derivatives and hedging activities

Under U.S. GAAP, trading and non-trading activities are accounted for in accordance with Statement 133, which requires that derivative instruments be recorded in the consolidated balance sheets at fair value as either assets or liabilities, and that changes in fair value be recognized currently in earnings, unless specific hedge accounting criteria are met. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in other comprehensive income (OCI), and the gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness relating to these hedges is recognized currently in earnings. The assets and liabilities related to derivative instruments for which hedge accounting criteria are met are reflected as price risk management assets and liabilities in the consolidated balance sheets. Many of the corporation’s electricity sales and fuel supply agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment. This exemption is available for the electricity industry as electricity cannot be stored in significant quantities and generators may be required to maintain sufficient capacity to meet customer demands. This exemption is also available for some physically settled commodity contracts if certain criteria are met. Non-derivatives used in trading activities are accounted for using the accrual method under U.S. GAAP.

(i) Fair value hedging stategy

The corporation enters into forward exchange contracts to hedge certain firm commitments denominated in foreign currencies to protect against adverse changes in exchange rates and uses interest rate swaps to manage interest rate exposure. The swaps modify exposure to interest rate risk by converting a portion of the corporation’s fixed-rate debt to a floating rate.

There was no ineffectiveness related to these hedges in the three and nine months ended Sept. 30, 2005 and 2004.

(ii) Cash flow hedging strategy

At Sept. 30, 2005, cash flow hedges of the forecasted sale of power and the forecasted purchase of natural gas for the corporation’s plants resulted in the recognition of an after-tax unrealized loss in OCI of $284.2 million. These hedges are accounted for on an accrual basis under Canadian GAAP but have been recorded on the balance sheet at fair value for US GAAP.

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In the three and nine months ended Sept. 30, 2005, the corporation’s cash flow hedges resulted in an after-tax gain of $0.3 million and an after-tax loss of $1.5 million (2004 – loss of $0.4 million and loss of $2.4 million respectively) related to the ineffective portion of its hedging instruments, and an after-tax gain of $nil for the three and nine months ended Sept. 30, 2005 and 2004 related to the portion not designated as a hedge.

In November 2003, forward starting swaps with a notional amount of US$200.0 million and treasury and spread locks with a notional amount of $100.0 million were settled and debt was issued, resulting in an after-tax loss of $25.3 million. The loss is being reclassified from accumulated other comprehensive income (AOCI) into income as interest expense is recognized on the debt.

Over the next 12 months, the corporation estimates that $234.9 million of after-tax losses that arose from cash flow hedges will be reclassified from AOCI to net earnings. The corporation also estimates that $3.7 million of after-tax losses on cash flow hedging instruments that arose on adoption of Statement 133 will be reclassified from AOCI to earnings. These estimates assume constant gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors. Therefore, management is unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months.

(iii) Net investment hedges

The company uses cross-currency interest rate swaps, forward foreign currency contracts and direct foreign currency debt to hedge its exposure to changes in the carrying value of its investments in its foreign subsidiaries in the U.S., Australia and Mexico. Realized and unrealized gains and losses from these hedges are included in OCI, with the related amounts due to or from counterparties included in long-term price risk management assets and liabilities and long-term debt.

In the three and nine months ended Sept. 30, 2005, the corporation recognized an after-tax gain of $215.9 million and $277.4 million, respectively, (2004 – $5.0 million loss and $8.4 million gain respectively) on its net investment hedges, included in OCI.

In the three and nine months ended Sept. 30, 2005, the corporation did not recognize any ineffectiveness related to net investment hedges.

(iv) Trading activities

The corporation markets energy derivatives to optimize returns from assets, to earn trading revenues and to gain market information. Derivatives, as defined under Statement 133, are recorded on the consolidated balance sheets at fair value under both Canadian and U.S. GAAP. Non-derivative contracts entered into subsequent to the rescission of EITF 98-10 are accounted for using the accrual method.

II. Start-up Costs

Under U.S. GAAP, certain start-up costs, including revenues and expenses in the pre-operating period, are expensed rather than capitalized to deferred charges and property, plant and equipment under Canadian GAAP, which also results in decreased depreciation and amortization expense under U.S. GAAP.

III. Debt extinguishment

Under U.S. GAAP, the premium on redemption of long-term debt related to the 1998 limited partnership transaction was recorded when incurred, whereas for Canadian GAAP, the loss was being amortized to earnings over the period of the limited partnership (20 years). As the buyback option was terminated in connection with the sale of the Sheerness plant, the deferred amount was recognized in earnings in 2003.

IV. Income taxes

Future income taxes under Canadian GAAP are referred to as deferred income taxes under U.S. GAAP.

Deferred income taxes under U.S. GAAP are as follows:

		Sept. 30		Dec. 31
		2005		2004
Future income tax liabilities (net) under Canadian GAAP	$	(588.2)	$	(561.5)
Derivatives		160.6		23.2
Start-up costs		(2.3)		(2.3)
Employee future benefits		(9.7)		(11.8)
	$	(439.6)	$	(552.4)
Comprised of the following:		Sept. 30		Dec. 31
		2005		2004
Current deferred income tax assets	$	22.7	$	21.5
Long-term deferred income tax assets		144.0		132.0
Current deferred income tax liabilities		(17.0)		(11.1)
Long-term deferred income tax liabilities		(589.3)		(694.8)
	$	(439.6)	$	(552.4)

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V. Employee Future Benefits

U.S. GAAP requires that the cost of employee pension benefits be determined using the accrual method with application from 1989. It was not feasible to apply this standard using this effective date. The transition asset as at Jan. 1, 1998 was determined in accordance with elected practice prescribed by the Securities and Exchange Commission (SEC) and is amortized over 10 years.

As a result of the corporation’s plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2004, the corporation was required under U.S. GAAP to recognize an additional minimum liability. The liability was recorded as a reduction in common equity through a charge to OCI, and did not affect net income for 2004. The charge to OCI will be restored through common equity in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.

VI. Joint Ventures

In accordance with Canadian GAAP, joint ventures are required to be proportionately consolidated regardless of the legal form of the entity. Under U.S. GAAP, incorporated joint ventures are required to be accounted for by the equity method. However, in accordance with practices prescribed by the SEC, the corporation, as a Foreign Private Issuer, has elected for the purpose of this reconciliation to account for incorporated joint ventures by the proportionate consolidation method.

VII. Other comprehensive income (loss)
The changes in the components of OCI were as follows:
	3 months ended Sept. 30				9 months ended Sept. 30
		2005		2004		2005		2004
Net gain on derivative instruments:
Unrealized gain, net of taxes of $152.3 million	$	(215.9)	$	5.0	$	(277.4)	$	(8.4)
Reclassification adjustment for gains included in net income,
net of taxes of $1.5 million		1.8		0.9		2.7		2.7
Net gain on derivative instruments		(214.1)		5.9		(274.7)		(5.7)
Translation adjustments		9.1		0.2		8.0		23.8
Other comprehensive (loss) income	$	(205.0)	$	6.1	$	(266.7)	$	18.1
The components of AOCI were:
						Sept. 30		Dec. 31
						2005		2004
Net loss on derivative instruments					$	(335.5)	$	(60.8)
Translation adjustments						(22.1)		(30.1)
Registered pension alternate minimum liabilities						(1.7)		(1.7)
Accumulated other comprehensive loss					$	(359.3)	$	(92.6)
VIII. Right of Offset Agreement

The corporation had a New Zealand bank deposit that had been offset with a New Zealand bank facility under a right of offset agreement. The arrangement did not qualify for offsetting under U.S. GAAP. During the second quarter of 2004, the corporation refinanced certain foreign operations and the bank deposit was used to settle the bank facility in full.

IX. Asset Retirement Obligations

FASB issued Statement 143, Asset Retirement Obligations, which requires asset retirement obligations to be measured at fair value and recognized when the obligation is incurred. A corresponding amount is capitalized as part of the asset’s carrying amount and depreciated over the asset’s useful life. TransAlta adopted the provisions of Statement 143 effective Jan. 1, 2003.

In accordance with Canadian GAAP, the asset retirement obligations standard was adopted retroactively with restatement of prior periods. Under U.S. GAAP, the impact of adopting Statement 143 was recognized as a cumulative effect of a change in accounting principle as of Jan. 1, 2003, the beginning of the fiscal year in which the Statement was first applied. The change resulted in an after-tax increase in net earnings of $52.5 million ($82.7 million pre-tax).

X. Limited Partnership Transaction

In 1998, the Corporation transferred generation assets to its subsidiary TA Cogen. TA Power, an unrelated entity, concurrently subscribed to a minority interest in TA Cogen. The fair value paid by TA Cogen for the assets exceeded their historical carrying values. For Canadian GAAP, the Corporation recognized a portion of this difference, to the extent it was funded by TA Power’s investment in TA Cogen, as a gain. As TA Power held an option to resell their interest in TA Cogen to the Corporation in 2018, this gain under Canadian GAAP was initially deferred and amortized over a 30 year period. In 2003, TA Power’s option to resell these units was eliminated and the unamor-tized balance of the gain was recognized in income.

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Under U.S. Securities and Exchange Commission Staff Accounting Bulletin No. 51, the option initially held by TA Power to potentially resell TA Cogen units to the Corporation in 2018 causes the excess of the consideration paid by TA Power over the Corporation’s historical carrying value in these assets to be characterized as contributed surplus in 1998. This amount of contributed surplus is reduced by the related tax effect. As a result, under U.S GAAP, there is no amortization of the gain into income in the period from 1998 to 2002 and no recognition of the unamortized balance of the gain in 2003.

XI. Restatement

During the third quarter of 2005, the Corporation determined, as described in footnote X above, that the gain recognized under Canadian GAAP arising from 1998 transactions involving TA Cogen and TA Power is a capital transaction under U.S. GAAP. The Corporation has retroactively corrected its reconciliation to U.S. GAAP. The impact of this adjustment on amounts previously reported under U.S. GAAP is as follows:

(In millions of dollars expect per share amounts)		2004		2003		2002
Decrease in:
Earnings from continuing operations	$	–	$	102.7	$	6.3
Net earnings	$	–	$	102.7	$	6.3
Net earnings per share in accordance with U.S. GAAP
Continuing operations	$	–	$	0.56	$	0.04
Discontinued operations	$	–	$	–	$	–
Basic	$	–	$	0.56	$	0.04
Diluted	$	–	$	0.56	$	0.04
The impact on previously reported balance sheet amounts for U.S. GAAP purposes is as follows:
				2004		2003
Increase (decrease) in:
Contributed surplus			$	133.0	$	133.0
Retained earnings			$	(133.0)	$	(133.0)
For U.S. GAAP purposes, the correction had no impact on total shareholders' equity at Dec. 31, 2004 and Dec. 31, 2003.
SUPPLEMENTAL INFORMATION
				Sept 30		Dec 31
(Annualized)				2005		2004
					Restated
Closing market price			$	23.03	$	18.05
Price range (last 12 months)		High	$	23.66	$	18.79
		Low	$	15.80	$	15.25
Debt/invested capital (including non recourse debt)				44.5%		46.6%
Debt/invested capital (excluding non recourse debt)				40.8%		42.5%
Return on common shareholders' equity				8.1%		6.6%
Return on invested capital				8.4%		7.6%
Book value per share			$	12.59	$	12.63
Cash dividends per share			$	1.00	$	1.00
Price/earnings ratio (times)				23.5 x		21.7 x
Dividend payout ratio				97.8%		120.0%
Dividend coverage (times)				3.1 x		3.2 x
Dividend yield				4.3%		5.5%
Cash flow to debt				21.5%		19.0%

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RATIO FORMULAS

Debt/invested capital = (short-term debt + long-term debt – cash and interest-earning investments) / (debt + preferred securities + non-controlling interests + common equity)

Return on common shareholders’ equity = net earnings excluding gain on discontinued operations / average of opening and closing common equity

Return on invested capital = (earnings before non-controlling interests and income taxes + net interest expense) / average annual invested capital

Book value per share = common shareholders’ equity / common shares outstanding

Price/earnings ratio = current year’s close / basic earnings per share from continuing operations

Cash flow to total debt = cash flow from operations before changes in working capital / two-year average of total debt Dividend payout = dividends / net earnings excluding gain on discontinued operations Dividend coverage = cash flow from operating activities / common share dividends Dividend yield = dividend per common share / current period’s close price

GLOSSARY OF KEY TERMS

Availability - A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year, that a generating unit is capable of generating electricity, whether or not it is actually generating electricity.

Btu (British Thermal Unit) - A measure of energy. The amount of energy required to raise the temperature of one pound of water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit.

Capacity - The rated continuous load-carrying ability, expressed in megawatts of generation equipment.

Gigawatt - A measure of electric power equal to 1,000 megawatts.

Gigawatt hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Heat rate - A measure of conversion, expressed as Btu/MW, of the amount of thermal energy required to generate electrical energy.

Megawatt - A measure of electric power equal to 1,000,000 watts.

Megawatt hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Net maximum capacity - The maximum capacity or effective rating, modified for ambient limitations that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.

Spark spread - A measure of gross margin per MW (sales price less cost of fuel).

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TransAlta Corporation

Box 1900, Station “M” 110 - 12th Avenue S.W.

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website www.transalta.com

CIBC Mellon Trust Company

P.O. Box 7010 Adelaide Street Station Toronto, Ontario Canada M5C 2W9

Phone

Toll-free in North America: 1.800.387.0825 Toronto or outside North America: 416.643.5500

Fax

416.643.5501

Website www.cibcmellon.com

FOR MORE INFORMATION

Media inquiries

Sneh Seetal

Senior Media Relations Advisor

Phone

403.267.7330

Pager

403.213.7041

E-mail media_relations@transalta.com

Investor inquiries

Daniel J. Pigeon

Director, Investor Relations

Phone

1.800.387.3598 in Canada and United States or 403.267.2520

Fax

403.267.2590

E-mail investor_relations@transalta.com

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