Edgar Filing: TRANSALTA CORP

#564426 v1 - gj TransAlta 6-K October 2001

FORM 6-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16
of the Securities Exchange Act of 1934

For the month of January, 2003

TRANSALTA CORPORATION

(Translation of registrant's name into English)

110-12^th Avenue S.W., Box 1900, Station “M”, Calgary, Alberta, T2P 2M1

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F____ Form 40-F X

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ..... No ..X...

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-________

Evaluation of Disclosure Controls and Procedures

TransAlta has designed disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer by others within the Company, including its consolidated subsidiaries, on a regular basis, in particular during the period in which its Current Reports on Form 6-K relating to quarterly financial results are being prepared. The Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the disclosure controls and procedures as of a date within 90 days of the date of this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded, as of that evaluation date, that the Company's disclosure controls and procedures were effective to ensure that material information relating to the Company, including its consolidated subsidiaries, was made known to them by others within those entities during the period in which this report was being prepared. There have been no significant changes in the internal controls or in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation by the Chief Executive Officer and Chief Financial Officer, including any corrective action with regard to significant deficiencies and material weaknesses.

•

EXHIBITS

Exhibit 1	Press release dated January 31, 2003.
Exhibit 2	Quarterly report for the three-month period ended December 31, 2002, which includes Management's Discussion and Analysis and consolidated financials statements.

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TransAlta announces 2002 results and declares dividend

CALGARY, Alberta (Jan. 31, 2002) - TransAlta Corporation (TSX: TA; NYSE: TAC) today announced 2002 net earnings of $189.9 million ($1.12 per share) versus $214.6 million ($1.27 per share) in 2001. This reflects a one-time gain of $120.0 million ($0.71 per share) from the sale of the Transmission business in the second quarter, partially offset by the impact from one-time events announced in the fourth quarter:

Phased decommissioning of TransAlta's 569-megawatt (MW) coal-fired Wabamun power plant, with unit three removed from service on Nov. 29, 2002 and a pre-tax impairment charge of $110.0 million;
Advancement of 2003 maintenance on Alberta thermal facilities into fourth quarter 2002, reducing pre-tax earnings by $27.7 million; and
Cancellation of orders for four gas turbines, resulting in a pre-tax cancellation charge of $42.5 million.

Fourth quarter 2002 had a net loss applicable to common shareholders of $54.3 million (loss of $0.32 per share), compared to net earnings of $46.5 million ($0.27 per share) in fourth quarter 2001. The fourth quarter loss from continuing operations applicable to common shareholders was $64.3 million (loss of $0.38 per share), down from net earnings of $33.2 million ($0.19 per share) in the same quarter of the previous year.

"TransAlta's availability, production and cash flow performed very well in what continued to be difficult market conditions," said Steve Snyder, TransAlta's President and CEO. "We made some tough decisions in the fourth quarter that we believe will benefit the company in the future, including the development of a more proactive maintenance program in Alberta."

Revenue for the fourth quarter increased by $71.1 million over the same period in 2001, reflecting increased production from the Centralia plant, increased long-term contracted prices for electricity generation and higher Energy Marketing revenues. Plant availability was 87 per cent, down from 90 per cent in fourth quarter 2001 due to the accelerated maintenance in Alberta and an unplanned Wabamun unit three outage. Production was up 966 megawatt-hours (MWh) to 12,545 MWh, due to improved availability of the Centralia plant and incremental production from new power plants, and partially offset by lost production resulting from the accelerated Alberta maintenance.

Cash from operating activities including changes in working capital was $189.5 million, compared to $131.7 million in fourth quarter 2001. This increase was mainly due to lower working capital requirements, partially offset by lower earnings.

TransAlta consolidated financial highlights

(In millions except per share amounts)		3 months ended December 31								Year ended December 31
		2002				2001				2002				2001

	Amount		Per share		Amount		Per share		Amount		Per share		Amount		Per share

Revenue from continuing operations*	$	517.6			$	434.4			$	1,723.9			$	2,319.4

Net earnings (loss) from continuing	$	(64.3)	$	(0.38)	$	33.2	$	0.19	$	57.1	$	0.34	$	169.5	$	1.00
operations**
Discontinued operations		-		-	$	13.3	$	0.08	$	12.8	$	0.07	$	45.1	$	0.27
Gain on sale	$	10.0	$	0.06		-		-	$	120.0	$	0.71		-		-

Net earnings (loss)**	$	(54.3)	$	(0.32)	$	46.5	$	0.27	$	189.9	$	1.12	$	214.6	$	1.27

Cash flow from operating activities	$	189.5			$	131.7			$	437.7			$	715.6

*	Trading revenues are now being reported on a net basis
**	Applicable to common shareholders, net of preferred securities distributions

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TransAlta consolidated financial highlights (continued)

	3 months ended December 31		Year ended December 31
	2002	2001	2002	2001

Availability (%)	87.2	89.9	88.4	86.9
Production (GWh)	12,545	11,579	46,877	44,136
Electricity trading volumes (GWh)	31,786	15,121	103,076	27,619
Gas trading volumes (million GJ)	45.9	36.5	159.8	99.3

Discontinued operations in 2002 and 2001 include net earnings from the Transmission operation, sold in April 2002. Results for 2001 also include the Edmonton Composter operation, sold in June 2001.

In fourth quarter 2002, TransAlta:

Purchased the remainder of Vision Quest Windelectric Inc., an Alberta-based wind power generator, for $35.5 million in cash and common shares. Vision Quest has 44 MW of wind power under operation and is currently engaged in a joint venture with ENMAX to build the 75 MW McBride project in Pincher Creek, Alberta.
Finalized post-closing adjustments for the sale of its Transmission operation, resulting in an additional $10.0 million ($0.06 per share) after-tax gain.
Completed the purchase of Australia Gas and Light's (AGL) 15 per cent interest in the 250 MW Southern Cross Energy Partnership for AUD$8.5 million.

TransAlta today also declared a dividend of $0.25 per share on common shares payable April 1, 2003 to shareholders of record at the close of business on March 1, 2003.

TransAlta Corporation is Canada's largest non-regulated electric generation and marketing company, with approximately $9 billion in assets and over 9,000 megawatts of capacity either in operation or under construction. As one of North America's lowest-cost operators, our growth is focused on developing coal- and gas-fired generation in Canada, the U.S. and Mexico.

This news release may contain forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta Corporation. These statements are subject to a number of risks and uncertainties that may cause actual results to differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause such differences include legislative or regulatory developments, competition, global capital markets activity, changes in prevailing interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where TransAlta Corporation operates.

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For more information:

*Media inquiries:*	*Investor inquiries*:
Nadine Walz	Daniel J. Pigeon
Media Relations Specialist	Director, Investor Relations
Phone: (403) 267-3655	Phone:	1-800-387-3598 in Canada and U.S.
Pager: (403) 213-7041	Phone:	(403) 267-2520	Fax (403) 267-2590
Email: media_relations@transalta.com	E-mail:	investor_relations@transalta.com

T R A N S A L T A C O R P O R A T I O N

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Q4:2002

M A N A G E M E N T ' S D I S C U S S I O N A N D A N A L Y S I S

This discussion and analysis should be read in conjunction with the unaudited consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three and twelve months ended Dec. 31, 2002 and 2001, and should also be read in conjunction with the audited consolidated financial statements and Management's Discussion and Analysis contained in TransAlta's annual report for the year ended Dec. 31, 2001. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted.

F O R W A R D - L O O K I N G S T A T E M E N T S

This report contains forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta. In some cases, forward-looking statements can be identified by terms such as 'may', 'will', 'believe', 'expect', 'potential', 'enable', 'continue' or other comparable terminology. These statements are not guarantees of TransAlta's future performance and are subject to risks, uncertainties, and other important factors that could cause the corporation's actual performance to be materially different from those projected. Some of the risks, uncertainties, and factors include, but are not limited to: legislative and regulatory developments that could affect revenues, costs, the speed and degree of competition entering the market, global capital markets activity, timing and extent of changes in commodity prices, prevailing interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where TransAlta Corporation operates, results of financing efforts, changes in counterparty risk and the impact of accounting policies issued by Canadian and United States standard setters. Given these uncertainties, the reader should not place undue reliance on these forward-looking statements.

R E S U L T S O F O P E R A T I O N S

The results of operations are organized by consolidated results and by business segment. TransAlta has two business segments: Generation and Energy Marketing. A third business segment, Independent Power Projects (IPP), was combined with the Generation segment effective Jan. 1, 2002, following changes to TransAlta's organizational structure. A fourth segment, Transmission, was sold on April 29, 2002. Prior period amounts have been reclassified to reflect these changes. A corporate group provides finance, treasury, legal, human resources and other administrative support to the business segments. These overheads are allocated to the business segments if they are not directly attributable to discontinued operations.

Each business segment assumes responsibility for their operating results measured as earnings before interest, taxes and non-controlling interests (EBIT). EBIT should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with Canadian GAAP as an indicator of the corporation's performance or liquidity. TransAlta's EBIT is not necessarily comparable to a similarly titled measure of another company. EBIT is reconciled to net earnings applicable to common shareholders below:

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		3 months ended Dec. 31				Year ended Dec. 31
		2002		2001		2002		2001

EBIT	$	(67.0)	$	50.5	$	197.6	$	378.9
Other income		1.0		1.2		0.1		1.5
Foreign exchange gain		0.9		2.9		1.2		0.8
Net interest expense		(24.0)		(12.4)		(82.7)		(88.1)

Earnings (loss) from continuing operations before
income taxes and non-controlling interests		(89.1)		42.2		116.2		293.1
Income tax expense (recovery)		(35.1)		0.5		18.1		89.9
Non-controlling interests		5.6		5.0		20.1		20.6

Earnings (loss) from continuing operations		(59.6)		36.7		78.0		182.6
Earnings from discontinued operations		-		13.3		12.8		45.1
Gain on disposal of discontinued operations		10.0		-		120.0		-

Net earnings (loss)		(49.6)		50.0		210.8		227.7
Preferred securities distribution, net of tax		4.7		3.5		20.9		13.1

Net earnings (loss) applicable to common shareholders	$	(54.3)	$	46.5	$	189.9	$	214.6



H I G H L I G H T S
The following table depicts key financial results and statistical operating data:

*3 months ended Dec. 31*				2002				2001

Availability				87.2%				89.9%
Production (GWh)				12,545				11,579
Electricity trading volumes (GWh)¹				31,786				15,121
Gas trading volumes (million GJ)				45.9				36.5


		Amount	Per common			Amount	Per common
				share			share

Revenues²	$	517.6			$	434.4

Net earnings (loss) from continuing operations³		(64.3)		(0.38)		33.2		0.19
Earnings from discontinued operations⁴		-		-		13.3		0.08
Gain on disposal of discontinued operations, net of tax⁴		10.0		0.06		-		-

Net earnings (loss) applicable to common shareholders	$	(54.3)	$	(0.32)	$	46.5	$	0.27


Cash flow from operating activities	$	189.5			$	131.7



*Year ended Dec. 31*				2002				2001

Availability				88.4%				86.9%
Production (GWh)				46,877				44,136
Electricity trading volumes (GWh)¹				103,076				27,619
Gas trading volumes (million GJ)				159.8				99.3


		Amount	Per common			Amount	Per common
				share			share

Revenues²	$	1,723.9			$	2,319.4

Net earnings from continuing operations³		57.1		0.34		169.5		1.00
Earnings from discontinued operations⁴		12.8		0.07		45.1		0.27
Gain on disposal of discontinued operations, net of tax⁴		120.0		0.71		-		-

Net earnings applicable to common shareholders	$	189.9	$	1.12	$	214.6	$	1.27


Cash flow from operating activities	$	437.7			$	715.6

1	2001 electricity trading volumes have been restated to conform with current reporting practices and standards.
2	From continuing operations. In accordance with changes to U.S. and Canadian GAAP, revenues from energy trading activities are now presented on a net basis. Prior period amounts have been reclassified to reflect this change.
3	Continuing operations include the Generation and Energy Marketing segments plus corporate costs not directly attributable to discontinued operations, and are net of preferred securities distributions.
4	Discontinued operations include the Transmission operation and the Edmonton Composter operation. The Transmission operation was sold on April 29, 2002 and the Edmonton Composter was sold on June 29, 2001.

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Net earnings from continuing operations for the three months ended Dec. 31, 2002 reflect the provision for the decommis-sioning of the Wabamun facility ($110.0 million pre-tax), cancellation fees on turbine contracts ($42.5 million pre-tax), and the impact of the accelerated Alberta thermal plant maintenance schedule ($27.7 million pre-tax), which are described in greater detail below. These costs were partially offset by higher contracted prices and lower purchased power costs. Net earnings from continuing operations for the year ended Dec. 31, 2002 were also influenced by the utilization and recognition of previously unrecognized tax losses ($11.2 million), the negative impact of the Wabamun unit four arbitration decision ($38.9 million plus interest of $2.7 million, pre-tax) and a prior period regulatory decision ($3.3 million pre-tax) described below. Net earnings attributable to common shareholders include the $120.0 million ($0.71 per common share) after-tax gain on disposal of the Transmission operation, which was sold on April 29, 2002.

Cash flow from operating activities for the three months ended Dec. 31, 2002 increased $57.8 million from the fourth quarter of 2001 due primarily to the non-cash impact of the asset impairment and equipment cancellation charges and lower working capital requirements offset by lower earnings. For the year ended Dec. 31, 2002, cash flow from operating activities was $277.9 million lower than in 2001 due to lower earnings, the impact of the collection in 2001 of accounts receivable relating to the Alberta Power Pool ($170.0 million) upon implementation of deregulation on Jan. 1, 2001, the payment in 2002 to the Alberta Power Pool relating to the ancillary services revenue settlement ($49.9 million) and the final installment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).

The corporation's existing financial reporting procedures and practices have enabled the certification of TransAlta's fourth quarter report to shareholders in accordance with the requirements of the Sarbanes-Oxley Act.

S I G N I F I C A N T O N E - T I M E I T E M S

Purchase of Vision Quest Windelectric Inc.

On Dec. 6, 2002, the corporation purchased the remaining interest in Vision Quest Windelectric Inc. (Vision Quest) for cash of $21.3 million plus a previous loan of $19.8 million and $14.2 million in common shares. This transaction increased the corporation's total investment in the wind power company to $68.8 million. Included in the purchase price was $27.2 million of goodwill. Vision Quest owns and operates 67 wind turbine power plants with 44 megawatts (MW) of capacity with a further 37.5 MW under construction and a substantial resource base available for further expansion. The purchase of Vision Quest reflects TransAlta's goal to increase the portion of total generation from renewable energy by 2010. Vision Quest's financial results for the period after acquisition ($0.6 million EBIT) are included in corporate results for segmented reporting purposes (Note 13).

Decommissioning of Wabamun plant

After a detailed unit-by-unit engineering assessment, a review of environmental issues and a review of short- and long-term market forecasts, the corporation decided to implement a phased decommissioning of its 569 MW coal-fired Wabamun facility. The power purchase arrangement (PPA) for the plant expires at the end of 2003. The 147 MW unit three was removed from service on Nov. 29, 2002 after an unplanned outage, as it was not considered economical to return the unit to service. The corporation plans to retire units one and two (69 MW and 67 MW, respectively) in 2004 and unit four (286 MW) in 2010 when its operating licence expires. As a result of this decision, the corporation recognized a pre-tax impairment charge of $110.0 million in the fourth quarter of 2002.

Turbine order cancellation

After examining expected market conditions and potential greenfield development opportunities against the corporation's risk profile, the corporation concluded that the likelihood of using all of the natural gas turbines in its pre-purchased turbine program was unlikely. The corporation therefore cancelled orders for four turbines and as a result recorded a pre-tax cancellation charge of $42.5 million for contract termination costs in the fourth quarter of 2002. The costs consist solely of progress payments made to date.

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Ancillary services revenue settlement

In July 2002, a dispute with the Balancing Pool of Alberta in respect of the allocation of hydro ancillary services revenue under the Hydro PPAs was resolved. TransAlta repaid $49.9 million it had received in advance from the Balancing Pool. The settlement had no earnings impact as the corporation had not previously recognized this amount as revenue.

Refinancing of foreign operations

TransAlta restructured the financing of certain foreign operations and as a result, the company was able to record the benefit of previously unrecognized foreign tax loss carryforward balances. This restructuring contributed $11.2 million to earnings in the third quarter of 2002.

Wabamun arbitration decision

On May 23, 2002, the corporation received the arbitrators' decision with respect to the 10-month outage at Wabamun unit four, which resulted from fatigue cracks within the waterwall tubing of its boiler. The arbitrators confirmed in their ruling that the outage qualified as a force majeure event, but also ruled that the corporation should have returned the unit to service more quickly. As a result of this decision, the corporation was required to pay $38.9 million plus interest of $2.7 million, all pre-tax. The payment was recorded as a reduction to revenue.

Gain on disposal of discontinued operations

On April 29, 2002, TransAlta's Transmission operation was sold for proceeds of $820.7 million, of which $818.0 million has been collected. The proceeds excluded $31.7 million in accounts receivable, which were retained and subsequently collected, and $4.4 million in accounts payable. The disposal resulted in a gain on sale of $120.0 million ($0.71 per common share), net of income taxes of $32.9 million. The previously reported gain included a number of estimates, therefore the gain was adjusted in the fourth quarter of 2002 to reflect agreed working capital adjustments and actual amounts paid and received.

Prior period regulatory decision

On April 16, 2002, the Alberta Energy and Utilities Board (EUB) rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding strategy in 2000.

N E W A C C O U N T I N G S T A N D A R D S

Effective Jan. 1, 2002, the corporation prospectively adopted the new Canadian Institute of Chartered Accountants (CICA) standard for goodwill and other intangibles. Under the new standard, goodwill and certain intangibles are no longer subject to amortization, but are instead tested for impairment at least annually. The adoption of this standard resulted in the reclassification of $29.3 million from acquired intangibles to goodwill, which will no longer be subject to amortization under the new standard. There was no impairment of goodwill upon adoption of this standard, nor was there an impairment at Dec. 31, 2002.

On Jan. 1, 2002, the corporation retroactively adopted the new CICA standard for stock-based compensation. The new standard requires that stock-based payments to non-employees, direct awards of stock and awards that call for settlement in cash or other assets be accounted for using the fair value method of accounting. The fair value method is encouraged for other stock-based compensation plans, but other methods of accounting, such as the intrinsic value method, are permitted. Under the fair value method, compensation expense is measured at the grant date and recognized over the service period. Under the intrinsic value method, compensation expense is determined as the difference between the market price of the underlying stock and the exercise price of the equity instrument granted. If the intrinsic value method is used, disclosure is made of earnings and per share amounts as if the fair value method had been used. The corporation has elected to use the intrinsic value method of accounting for its fixed stock option plans and its performance stock option plan. Accordingly, no compensation cost has been recognized for these plans. Had the fair value method been used, reported basic and diluted earnings per common share would have been reduced by $0.01 and $0.02 per common share for the three and twelve

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months ended Dec. 31, 2002, respectively (2001 - $nil and $0.01 per common share, respectively). Effective Jan. 1, 2003, TransAlta has elected to account for stock-based compensation in accordance with the fair value method and will expense stock-based compensation in respect of stock options granted after that date.

The CICA amended its standard on foreign currency translation effective Jan. 1, 2002. The changes require that translation gains and losses arising on long-term foreign currency denominated monetary items be included in income in the current period. Previously, these gains and losses were to be amortized over the life of the related item. As TransAlta designates long-term foreign currency denominated items as hedges of net investments in foreign operations, all gains and losses arising on the translation of these items are deferred and included in the cumulative translation adjustment account in shareholders' equity, therefore this amendment has no impact on TransAlta.

The CICA has amended its standard on the recognition, measurement, and disclosure of the impairment of long-lived assets. This standard is effective April 1, 2003 and requires that an impairment loss be recognized when the carrying amount of a long-lived asset exceeds the sum of the undiscounted cash flows expected from its use and eventual disposition. The impairment loss is measured as the amount that the long-lived asset's carrying value exceeds its fair value. TransAlta early adopted this standard in the fourth quarter of 2002. In accordance with the standard, the impairment calculation for the Wabamun plant resulted in the recognition of an impairment charge of $110.0 million, which is included in asset impairment and equipment cancellation charges.

In the third quarter of 2002, in response to changes in accounting standards in the U.S. with respect to energy trading activities, the corporation has adopted a policy that all gains and losses on energy trading contracts be shown net in the statement of earnings. Consistent with these recommendations, the corporation has chosen to disclose the gross transaction volumes for those energy trading contracts that are physically settled.

D I S C U S S I O N O F S E G M E N T E D R E S U L T S

GENERATION: Owns and operates hydro-, gas-, and coal-fired plants and related mining operations, with a total generating capacity of 7,516 MW.

Effective Jan. 1, 2002, TransAlta's organizational structure changed to combine the Generation and IPP business segments into one Generation segment. This was done to improve the corporation's operational capability and reliability through the sharing of resources and best practices across all generating assets. Prior period amounts have been reclassified to reflect the combination of these segments.

Available capacity increased during the year as a result of the scrubber installation at Centralia (32 MW), an upgrade at Sundance unit six (42 MW), and the commissioning of the Big Hanaford plant (248 MW) offset by the decommissioning of Wabamun unit three (147 MW) in the fourth quarter. In connection with the construction of the Sarnia Regional Cogeneration plant, TransAlta purchased existing operational assets during the fourth quarter with a current generating capacity of 135 MW plus 55 MW of backup capacity for $30.2 million. Construction of an additional 440 MW is expected to be completed in the first quarter of 2003.

The results of the Generation segment are as follows:

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			2002				2001
*3 months ended Dec. 31*		Total	Per MWh			Total	Per MWh

Revenues	$	498.7	$	39.75	$	431.8	$	37.29
Fuel and purchased power		(226.9)		(18.09)		(246.4)		(21.28)

Gross margin		271.8		21.66		185.4		16.01
Operating expenses:
Operations, maintenance and administration		115.3		9.19		68.7		5.93
Depreciation and amortization		57.4		4.58		41.4		3.58
Asset impairment and equipment cancellation charges		152.5		12.16		2.7		0.23
Taxes, other than income taxes		7.6		0.60		4.6		0.40
Prior period regulatory decision		-		-		(11.0)		(0.95)

EBIT before corporate allocations		(61.0)		(4.87)		79.0		6.82
Corporate allocations		(18.1)		(1.44)		(23.6)		(2.04)

EBIT	$	(79.1)	$	(6.31)	$	55.4	$	4.78



				2002				2001
*Year ended Dec. 31*		Total	Per MWh			Total	Per MWh

Revenues	$	1,673.9	$	35.71	$	2,158.4	$	48.90
Fuel and purchased power		(703.6)		(15.01)		(1,230.6)		(27.88)

Gross margin		970.3		20.70		927.8		21.02
Operating expenses:
Operations, maintenance and administration		346.3		7.39		290.6		6.58
Depreciation and amortization		196.3		4.19		156.5		3.55
Asset impairment and equipment cancellation charges		152.5		3.25		118.8		2.69
Taxes, other than income taxes		27.3		0.58		18.7		0.42
Prior period regulatory decision		3.3		0.07		(11.0)		(0.25)

EBIT before corporate allocations		244.6		5.22		354.2		8.03
Corporate allocations		(70.6)		(1.51)		(82.5)		(1.87)

EBIT	$	174.0	$	3.71	$	271.7	$	6.16

Generation's revenues are derived from the production of electricity, of which, on an annualized basis, approximately 90 per cent are based upon contracted prices, including capacity payments, and approximately 10 per cent are subject to market pricing. Revenues received under long-term contractual arrangements are not subject to major fluctuations in the spot price for electricity. In the fourth quarter of 2002, long-term contracts covered 91 per cent of production (2001 - 94 per cent) with the remaining nine per cent (2001 - six per cent) subject to market pricing. For the year ended Dec. 31, 2002, long-term contracts covered 90 per cent of total production (2001 - 92 per cent) with the remaining 10 per cent (2001 - eight per cent) subject to market pricing.

The existing contracts have remaining terms ranging from one to 22 years. Contracted production, as a percentage of existing production and forecasted production from assets currently under construction, over the next five years are as follows:

Contracted output

2003	2004	2005	2006	2007

88%	87%	87%	86%	85%

Generation also derives revenue from the provision of ancillary services such as steam and system support. Revenues are subject to seasonal variations: during the summer months, warmer temperatures result in less efficient fuel conversion rates (higher heat rates), and increased hydro production from spring run-off results in lower electricity prices.

A breakdown of revenues and average pricing applicable to each category are summarized in the following table:

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			2002				2001
*3 months ended Dec. 31*	Revenue		Per MWh		Revenue		Per MWh

Contract	$	405.3	$	34.53	$	373.8	$	33.96
Merchant		54.8		62.78		48.7		46.47
Ancillary services and other		38.6		-		9.3		-

	$	498.7	$	39.75	$	431.8	$	37.29


				2002				2001
*Year ended Dec. 31*	Revenue		Per MWh		Revenue		Per MWh

Contract	$	1,448.2	$	33.26	$	1,374.1	$	33.23
Merchant		171.0		51.64		681.2	142.91
Ancillary services and other		93.6		-		103.1		-
Wabamun arbitration decision		(38.9)		-		-		-

	$	1,673.9	$	35.71	$	2,158.4	$	48.90

A reconciliation between production, revenue and EBIT for the fourth quarter and year ended Dec. 31, 2002 compared to the same periods in 2001 is presented below:

	Production (GWh)		Revenue		EBIT

3 months ended Dec. 31, 2001	11,579	$	431.8	$	55.4
Increased production	868		32.4		23.5
New gas plants in service (Sarnia and Big Hanaford)	388		39.9		(11.7)
Accelerated Alberta thermal plant maintenance	(290)		(10.6)		(27.7)
Wabamun impairment and equipment cancellation charges	-		-		(152.5)
Higher market prices	-		5.3		5.3
Lower purchased power requirements	-		-		66.8
Increased operations, maintenance and administration expense	-		-		(24.9)
Increased depreciation	-		-		(11.2)
Wabamun unit four TSR settlement for 2000	-		-		(11.0)
Other	-		(0.1)		8.9

3 months ended Dec. 31, 2002	12,545	$	498.7	$	(79.1)


	Production (GWh)		Revenue		EBIT

Year ended Dec. 31, 2001	44,136	$	2,158.4	$	271.7
Net improved availability and production	2,538		91.1		53.5
New gas plants in service (Sarnia and Big Hanaford)	493		40.2		(13.1)
Accelerated Alberta thermal plant maintenance	(290)		(10.6)		(27.7)
Wabamun impairment and equipment cancellation charges	-		-		(152.5)
Lower market prices	-		(441.9)		(441.9)
Lower purchased power requirements	-		-		562.8
Wabamun arbitration decision	-		(38.9)		(38.9)
Impact of the Pierce Power plant monetization in 2001	-		(121.8)		(3.0)
Increased operations, maintenance and administration expense	-		-		(33.0)
Increased depreciation	-		-		(34.6)
Lower fuel costs per megawatt hour	-		-		39.4
Wabamun unit four TSR settlement for 2000 and prior period regulatory decision	-		-		(14.3)
Other	-		(2.6)		5.6

Year ended Dec. 31, 2002	46,877	$	1,673.9	$	174.0

As discussed in significant one-time items, the corporation recognized an impairment charge of $110.0 million relating to the Wabamun plant, as the carrying value was determined to be in excess of fair value. TransAlta also cancelled the order for four natural gas turbines resulting in a $42.5 million contract termination charge. In September 2001, TransAlta monetized its investment in the 154 MW Pierce Power plant as a result of weak economic conditions. Revenue hedges were realized resulting in the recognition of revenue of $121.8 million, offset by an asset impairment charge of $66.5 million and a recognition of anticipated future operating costs of $52.3 million.

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As a result of the corporation's forward view of the electricity market and its positive experience with improvements at the Centralia plant, the corporation accelerated its Alberta thermal plant maintenance schedule. This is being undertaken in order to improve reliability and increase availability when the economy turns around and electricity demand increases. This decision resulted in lower revenues and increased maintenance costs ($27.7 million pre-tax) in the fourth quarter of 2002.

As discussed in significant one-time items, the Wabamun arbitration decision resulted in a $38.9 million pre-tax payment that was recorded as a reduction of revenue in the second quarter of 2002.

As discussed in significant one-time items, the EUB rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding strategy in 2000, which was recorded in 2002 as a prior period regulatory decision.

Availability for the fourth quarter of 2002 was 87.2 per cent compared to 89.9 per cent in 2001, reflecting decreased availability at the Alberta thermal plants due to the accelerated maintenance schedule and the unplanned Wabamun unit three outage discussed previously. Availability for the year ended Dec. 31, 2002 was 88.4 per cent compared to 86.9 per cent in 2001 as a result of improved operational performance at the thermal and gas plants, partially offset by the accelerated maintenance at the Alberta thermal plants and the Wabamun outage. At various times during 2002, when the market price of electricity was lower than the variable costs of production at certain plants, the corporation reduced production at these plants, and purchased electricity from the market to fulfill contractual obligations (economic dispatch). During these periods of economic dispatch, the affected plants were available to generate the electricity if required.

In the three months ended Dec. 31, 2002, production increased by 966 GWh compared to the same period in 2001 as a result of incremental production from the Sarnia and Big Hanaford plants and increased production from the Centralia plant, offset by lost production resulting from accelerated Alberta thermal plant maintenance. There was no economic dispatch in the fourth quarter of 2002. In the year ended Dec. 31, 2002, total production increased by 2,741 GWh compared to 2001. This increase was the result of the items discussed above and the return to service of Wabamun unit four as well as increased thermal production and availability, partially offset by 731 GWh decreased production resulting from economic dispatch decisions.

As shown in the above graphs, electricity spot prices in the fourth quarter of 2002 in both the Alberta and Pacific Northwest markets increased compared to the same period in 2001; however on an annual basis, electricity spot prices were lower in 2002 than in 2001. In the fourth quarter, spark spreads (power price less cost of gas consumed) increased in the Alberta market and decreased in the Pacific Northwest market. For the year ended Dec. 31, 2002, spark spreads decreased in both the Alberta and Pacific Northwest markets. Within these markets, prices were softer in 2002 due to reduced demand as a result of lower economic activity, increased hydro production, and additional generating capacity added to these markets.

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Q U A R T E R L Y R E P O R T 2 0 0 2

Generation's revenue for the fourth quarter of 2002 increased by $66.9 million ($2.46 per MWh) compared to the same period in 2001. The increase is due to higher production, higher ancillary services revenue, increased long-term contracted prices and higher electricity spot prices. The increase in contracted prices is due to higher gas prices, which are recovered under the terms of certain contracts. Revenue for the year ended Dec. 31, 2002 decreased by $484.5 million ($13.19 per MWh) compared to 2001. Adjusted for the Wabamun arbitration and Pierce Power decisions, revenue was $1,712.8 million ($36.54 per MWh) in 2002 compared to $2,036.6 million ($46.14 per MWh) in 2001. The decline in revenue in 2002 reflects lower electricity spot prices, partially offset by improved production and availability.

Fuel and purchased power decreased by $19.5 million ($3.19 per MWh) in the fourth quarter of 2002 and by $527.0 million ($12.87 per MWh) for the year ended Dec. 31, 2002. Purchased power is the cost incurred to acquire electricity from the market to fulfill contracted commitments during planned and unplanned outages. Any electricity not required to fulfill these commitments is sold back into the market at spot prices.

Purchased power declined significantly in the fourth quarter and the year ended Dec. 31, 2002 to $5.1 million and $32.1 million, respectively (2001 - $71.9 million and $594.9 million). The purchased power in the fourth quarter was the result of plant outages, while the majority of the purchased power requirement for the remainder of 2002 was due to the economic dispatch decisions discussed earlier. Due to high market power prices in the fourth quarter of 2002, no economic dispatch occurred in the quarter. In the fourth quarter of 2001, expected lower availability at the Centralia plant resulted in the purchase of 551 GWh of electricity, totalling $71.9 million. In the year ended Dec. 31, 2001, 2,707 GWh of electricity was purchased totalling $594.9 million. Pre-tax losses as a result of these purchases in the three and twelve months ended Dec. 31, 2001 were US$28.0 million (approximately Cdn$47 million) and US$77.7 million (approximately Cdn$124 million), respectively.

Fuel costs, excluding purchased power, consist primarily of coal and natural gas costs. Total fuel costs, excluding purchased power, were $221.8 million ($17.68 per MWh) in the fourth quarter of 2002 compared to $174.5 million ($15.07 per MWh) in 2001. For the year ended Dec. 31, 2002, coal and natural gas costs totalled $671.5 million ($14.32 per MWh) compared to $635.7 million ($14.40 per MWh) in 2001. TransAlta's average fuel costs per MWh are shown below:

		3 months ended Dec. 31				Year ended Dec. 31
		2002		2001		2002		2001

Coal	$	12.40	$	13.91	$	11.70	$	12.34
Gas	$	40.51	$	21.87	$	27.86	$	26.16

Average fuel costs, excluding purchased power	$	17.68	$	15.07	$	14.32	$	14.40

TransAlta is subject to fluctuations in natural gas and coal costs, however the majority of the coal used in generation is from coal reserves owned by TransAlta. This allows the corporation to control the cost of coal. As a result of cost reduction programs, TransAlta reduced coal costs by 11 per cent in the fourth quarter of 2002 and five per cent for the year ended Dec. 31, 2002 compared to the same periods in 2001. The fourth quarter increase in fuel costs per MWh, excluding purchased power, is attributable to the 85 per cent increase in natural gas costs, partially offset by the decrease in coal costs. The increase in gas costs is due to higher natural gas market prices at the Big Hanaford plant and higher gas prices and heat rates at the Sarnia plant. For contracted plants, a portion of the gas costs have been hedged by the corporation, and in some cases, the corporation has hedged plants' spark spreads. In certain contracted plants the gas cost is a flow through to the customer and is not hedged by the corporation, therefore TransAlta is still subject to fluctuations in gas prices, but the increased gas costs are recovered through increased revenues. Gas costs for electricity to be sold in spot markets are matched to power sales and hedged accordingly. Fuel costs, excluding purchased power, on a per MWh basis, decreased for the year ended Dec. 31, 2002 as a result of the decrease in coal costs, partially offset by increased natural gas costs as discussed above.

In the fourth quarter of 2002, operations, maintenance and administration (OM&A) expenses increased by $46.6 million ($3.26 per MWh) over the same period in 2001. The increase represents the impact of the accelerated maintenance at the Alberta thermal plants, the commissioning of the Sarnia and Big Hanaford plants, increased business development costs, inventory obsolescence costs and increased project management costs related to plants under construction. For the year ended Dec. 31, 2002, OM&A increased by $55.7 million ($0.81 per MWh) from 2001. This reflects the impact of the items discussed above and increased insurance premiums partially offset by cost reduction initiatives.

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Q U A R T E R L Y R E P O R T 2 0 0 2

Depreciation and amortization increased by $16.0 million ($1.00 per MWh) for the fourth quarter of 2002 and $39.8 million ($0.64 per MWh) for the year ended Dec. 31, 2002 compared to the same periods in 2001. The increase is the result of the addition of the Big Hanaford plant and increased capital projects at thermal plants.

The increase in taxes other than income taxes in the three and twelve months ended Dec. 31, 2002 relates to higher property tax assessments by local municipalities on the majority of the corporation's plants.

ENERGY MARKETING: Derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives. These activities also provide critical market knowledge to help identify growth opportunities and support corporate investment decisions.

The results of Energy Marketing are as follows:

		3 months ended Dec. 31				Year ended Dec. 31
		2002		2001		2002		2001

Gross revenues	$	992.4	$	526.9	$	3,703.8	$	2,694.7
Trading purchases		(974.5)		(524.3)		(3,654.8)		(2,533.7)

Net revenues		17.9		2.6		49.0		161.0
Operations, maintenance and administration		3.6		1.6		15.1		36.2
Depreciation and amortization		0.5		4.0		2.5		11.0
Taxes, other than income taxes		-		-		0.1		-

EBIT before corporate allocations		13.8		(3.0)		31.3		113.8
Corporate allocations		(2.3)		(1.9)		(8.3)		(6.6)

EBIT	$	11.5	$	(4.9)	$	23.0	$	107.2



Gross physical and financial settled sales transactions are as follows:

		3 months ended Dec. 31				Year ended Dec. 31
Electricity (GWh)		2002		2001		2002		2001

Physical		18,619		10,131		63,015		18,504
Financial		13,167		4,990		40,061		9,115

		31,786		15,121		103,076		27,619



		3 months ended Dec. 31				Year ended Dec. 31
Gas (million GJ)		2002		2001		2002		2001

Physical		26.5		12.2		96.2		30.6
Financial		19.4		24.3		63.6		68.7

		45.9		36.5		159.8		99.3

The Energy Marketing group uses energy derivatives, including physical and financial swaps, forwards and options to earn trading revenues and gain market information. Energy contracts that meet the definition of a derivative in the Financial Accounting Standards Board (FASB) Statement 133, Accounting for Derivative Instruments and Hedging Activities, are accounted for at fair value in accordance with Canadian and U.S. GAAP.

Derivatives are used to hedge the corporation's exposure to changes in electricity and natural gas prices. Under Canadian GAAP, settlement accounting is used for hedging activities if certain criteria are met. Under U.S. GAAP, hedging activities are accounted for in accordance with FASB Statement 133.

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Q U A R T E R L Y R E P O R T 2 0 0 2

Gross trading sales volumes during the fourth quarter of 2002 increased by 16,665 GWh of electricity and by 9.4 million giga-joules (GJ) of gas compared to 2001. In the year ended Dec. 31, 2002, trading volumes increased by 75,457 GWh of electricity and 60.5 million GJ of gas compared to 2001. Liquidity in the medium- to long-term markets remained low and as a result, Energy Marketing continued to have a low level of activity in these markets. Coincidently, activity levels in the short-term market increased. As expected, increased market liquidity and pricing efficiencies resulted in margins on individual trades being reduced. TransAlta's trading activity comprised mainly short-term transactions, the majority of which were settled within ninety days thereby limiting risk and maintaining low working capital requirements. Value at risk levels throughout 2002 were consistent with 2001 levels. The increase in gas trading volumes relates to the settlement of trading positions offset in early 2002 when the gas trading book was closed. In addition, the trading of heat rate swaps, which include a gas element and are therefore presented as settled gas transactions, increased in 2002.

Gross sales increased by $465.5 million in the three months ended Dec. 31 and increased by $1,009.1 million for the year ended Dec. 31, 2002 compared to 2001. Increased electricity trading volumes in 2002 more than offset lower market prices and the reduced gas trading activities in the first and second quarters of 2002.

Net revenues increased by $15.3 million for the fourth quarter of 2002 as a result of increased trading activity and higher percentage margins. Net revenues decreased by $112.0 million for the year ended Dec. 31, 2002 due to significantly lower market prices and margins compared to 2001, particularly in the Pacific Northwest. The 2001 Pacific Northwest prices were influenced by the process of deregulation in California, exacerbated by a drought in the Pacific Northwest and historically high natural gas prices.

In the fourth quarter of 2002, OM&A expense increased by $2.0 million due primarily to higher incentive compensation recognized during the quarter. Incentive compensation is based on net revenues which increased in the quarter, as discussed above. OM&A decreased by $21.1 million for the year ended Dec. 31, 2002 due to lower annual incentive compensation resulting from lower annual net revenue and one-time costs associated with the acquisition of the remaining 50 per cent of Merchant Energy Group of the Americas, Inc. (MEGA) in June 2001.

Depreciation and amortization decreased by $3.5 million in the fourth quarter of 2002 and by $8.5 million for the year ended Dec. 31, 2002. The decrease is due to $29.3 million of goodwill arising from the acquisition of MEGA, previously recorded as acquired intangibles, which is no longer being amortized. This treatment is in accordance with the new accounting standard issued by the CICA. There was no impairment of goodwill upon adoption of the standard on Jan. 1, 2002, nor was there an impairment at Dec. 31, 2002.

Energy Marketing's price risk management assets and liabilities represent the fair value of unsettled (unrealized) trading transactions. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of physical transmission contracts is based on quoted market prices and a spread option valuation model. The fair value of financial transmission contracts is based upon statistical analysis of historical data.

The following table illustrates movements in the fair value of the corporation's price risk management assets (liabilities) during the twelve months ended Dec. 31, 2002:

Fair value of net price risk management assets outstanding at Dec. 31, 2001	$	25.8
Fair value of new contracts entered into during the period		(2.7)
Changes in fair values attributable to market price and other market changes		7.6
Contracts realized or settled during the period		(36.6)
Changes in fair values attributable to changes in valuation techniques and assumptions		-

Fair value of net price risk management liabilities outstanding at Dec. 31, 2002	$	(5.9)

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Q U A R T E R L Y R E P O R T 2 0 0 2

The source of the valuations of the above contracts and maturities over each of the next five calendar years and thereafter is as follows:

											2008 and
		2003		2004		2005		2006		2007	thereafter			Total

Prices actively quoted	$	(17.6)	$	3.3	$	3.2	$	2.1	$	1.5	$	-	$	(7.5)
Prices based on models		1.6		-		-		-		-		-		1.6

Asset (liability)	$	(16.0)	$	3.3	$	3.2	$	2.1	$	1.5	$	-	$	(5.9)

In 2002, TransAlta responded to a number of inquiries from various U.S. State and Federal bodies regarding trading activities in California and states in the Pacific Northwest during 2000 and 2001. TransAlta believes it operated in accordance with all applicable laws, rules, regulations and tariffs. No significant developments have occurred on these issues as a result of TransAlta's responses.

In the fourth quarter of 2002, two class action lawsuits on behalf of all persons and businesses in the states of Oregon and Washington were initiated in respect of alleged unlawful practices in the purchase and sale of wholesale energy. TransAlta believes these are without merit and will vigorously defend its actions.

In 2000, TransAlta made a provision of US$28.8 million against US$58.0 million owing from the California Independent System Operator and the California Power Exchange. During 2001, US$5.0 million was collected. No change has been made to the provision due to the continuing uncertainty in California. The amount has been reclassified to long-term, as collection is no longer expected in 2003, although ultimate collection is still expected. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge proposed that TransAlta receive approximately US$44.0 million, however FERC has indicated that further adjustments in respect of power and gas prices may occur, which could result in further alterations of the amount TransAlta is to receive. As a result, TransAlta has not adjusted the amount receivable or the provision.

N E T I N T E R E S T E X P E N S E , O T H E R E X P E N S E , F O R E I G N E X C H A N G E , N O N - C O N T R O L L I N G I N T E R E S T S A N D P R E F E R R E D S E C U R I T I E S D I S T R I B U T I O N S

		3 months ended Dec. 31				Year ended Dec. 31
		2002		2001		2002		2001

Gross interest expense	$	46.7	$	42.4	$	172.9	$	170.3
Interest income		(1.7)		(8.7)		(8.7)		(24.2)
Interest allocated to discontinued operations		-		(0.6)		(2.4)		(9.7)
Capitalized interest		(21.0)		(20.7)		(79.1)		(48.3)

Net interest expense		24.0		12.4		82.7		88.1
Other income		(1.0)		(1.2)		(0.1)		(1.5)
Foreign exchange gain		(0.9)		(2.9)		(1.2)		(0.8)
Non-controlling interests		5.6		5.0		20.1		20.6
Preferred securities distributions, net of tax		4.7		3.5		20.9		13.1

	$	32.4	$	16.8	$	122.4	$	119.5

On June 20, 2002, the corporation issued US$300.0 million of senior notes under a US$1.0 billion shelf prospectus filed May 14, 2002. The proceeds of the issuance were used to repay short-term debt and U.S. denominated commercial paper. The notes are unsecured and bear interest at 6.75 per cent and mature on July 15, 2012.

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Q U A R T E R L Y R E P O R T 2 0 0 2

Net interest expense increased by $11.6 million in the three months ended Dec. 31, 2002 compared to the same period of 2001. The increase was primarily due to a higher proportion of debt subject to long-term interest rates and lower interest income due to the receipt of the $180.3 million receivable from Aquila Networks Canada (formerly UtiliCorp Networks Canada) that arose from the sale of the Alberta Distribution and Retail (D&R) operation. Net interest expense decreased by $5.4 million for the year ended Dec. 31, 2002 as a result of an overall decline in average debt levels and higher capitalized interest, offset by a higher proportion of debt subject to long-term interest rates and receipt of the interest-bearing receivable from Aquila Networks Canada.

The increase in earnings attributable to non-controlling interests in the fourth quarter of 2002 compared to 2001 is attributable to increased quarterly earnings relating to the 49.99 per cent non-controlling interest in TransAlta Cogeneration, L.P. The decrease for the year ended Dec. 31, 2002 compared to 2001 is the result of the redemption of the preferred shares of TransAlta Utilities Corporation for $121.6 million in September 2001, resulting in lower subsidiary preferred share dividends, offset by higher earnings from TransAlta Cogeneration, L.P.

The increases in preferred securities distributions, net of tax, reflect the issuance of $175.0 million of 7.75 per cent preferred securities in November 2001.

I N C O M E T A X E S

Income tax expense (recovery) Effective tax rate

	3 months ended Dec. 31				Year ended Dec. 31
	2002		2001		2002		2001

$	(35.1)	$	0.5	$	18.1	$	89.9
	39.4%		1.2%		15.6%		30.7%

An income tax recovery of $35.1 million was recorded for the three months ended Dec. 31, 2002, compared to income tax expense of $0.5 million for the same period in 2001. The recovery reflects the loss incurred in the current quarter. Income taxes decreased by $71.8 million for the year ended Dec. 31, 2002 due to lower earnings and the impact of the Wabamun decommissioning and the turbine cancellation charges, which were recognized at the marginal rate. The decrease also reflects the benefit of previously unrecognized tax losses that were recognized in the third quarter of 2002 as it became more likely than not that they would be utilized. The effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, decreased to 15.6 per cent in 2002 from 30.7 per cent in 2001. The effective tax rate in 2002 reflects the impact of the issues discussed above. Due to lower earnings in the three months ended Dec. 31, 2001, the 1.2 per cent effective rate reflects the impact of the financing arrangements of TransAlta's foreign operations. The benefits of these arrangements do not vary with earnings.

D I S C O N T I N U E D	O P E R A T I O N S
			3 months ended Dec. 31				Year ended Dec. 31
			2002		2001		2002		2001

Transmission operation		$	-	$	13.3	$	12.8	$	44.4
Gain on disposal of Transmission operation			10.0		-		120.0		-
Edmonton Composter operation			-		-		-		0.7

		$	10.0	$	13.3	$	132.8	$	45.1

As discussed in significant one-time items, TransAlta sold its Transmission operation in April 2002 for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $120.0 million ($0.71 per common share).

On June 29, 2001, TransAlta sold its Edmonton Composter for proceeds of $97.0 million, which approximated its book value.

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F I N A N C I A L P O S I T I O N

The following chart outlines significant changes in the consolidated balance sheet from Dec. 31, 2001 to Dec. 31, 2002:

	Increase / (decrease)		Explanation

Cash and cash equivalents	$	81.3	Refer to Consolidated Statements of Cash Flows.
Accounts receivable and other		(156.9)	Decrease primarily due to collection of receivable related to
			monetized Pierce Power hedges ($82.0 million),
			reclassification of California receivables to long-term
			(US$24.2 million) and the sale of the Transmission
			business, ($31.7 million).
Materials and supplies, at average cost		27.2	Higher coal inventory balances as a result of second and
			third quarter economic dispatch decisions, increased coal
			production and advanced maintenance at the Alberta
			thermal plants.
Long-term receivables		(181.5)	Receipt of amount due from Aquila (formerly UtiliCorp)
			relating to the sale of the discontinued D&R operation
			($180.3 million) and reclass of sulphur tax abatement ($45.0
			million) to current receivables, offset by reclassification of
			California receivables to long-term (US$24.2 million).
Property, plant and equipment, net of		(59.7)	Capital expenditures and construction activity during the
accumulated depreciation			period and acquisition of Vision Quest, more than offset by
			depreciation, the sale of the Transmission business, the
			impairment charge relating to the decommissioning of the
			Wabamun plant and equipment cancellation charges.
Goodwill		27.2	Acquisition of Vision Quest in December 2002.
Future income tax assets		56.6	2001 U.S. operating losses that will be recovered in future
			years.
Other assets		29.5	Long-term prepayments related to the Sarnia plant and
			financing costs related to US$300.0 million debt issuance
			and financing costs related to the Mexican projects.
Short-term debt		(247.2)	Repayment with a portion of the proceeds from US$300.0
			million debt issuance and proceeds from disposal of the
			Transmission operation.
Accounts payable and accrued liabilities		(155.3)	Decrease due to lower capital expenditures in the quarter.
Price risk management liabilities
(current and long-term)		41.3	Decrease in margins on energy trading activities.
Long-term debt (including current portion)		195.5	US$300.0 million debt issuance, offset by maturity of
			debentures of $100 million and net decrease in long-term
			commercial paper repaid with proceeds on disposal of the
			Transmission business.
Non-controlling interests		(18.0)	Acquisition of remaining interest in Southern Cross Energy
			($7.2 million) and decreased non-controlling interest in
			TransAlta Cogeneration, L.P. as a result of distributions in
			excess of net income.
Shareholders' equity		49.9	Net earnings and issuance of common shares for Vision
			Quest acquisition, partially offset by dividends and net
			redemption of common shares.

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S T A T E M E N T S O F C A S H F L O W S :

3 months ended Dec. 31		2002		2001

Cash and cash equivalents,
beginning of period	$	120.6	$	61.5
Provided by (used in):
Operating activities		189.5		131.7


Investing activities		(261.0)		(366.1)







Financing activities		96.7		230.9






Translation of foreign currency cash		(2.5)		4.0

Cash and cash equivalents,
end of period	$	143.3	$	62.0



Year ended Dec. 31		2002		2001

Cash and cash equivalents,
beginning of period	$	62.0	$	53.8
Provided by (used in):
Operating activities		437.7		715.6







Investing activities		(36.2)	(1,076.9)













Financing activities		(320.9)		368.7






Translation of foreign currency cash		0.7		0.8

Cash and cash equivalents,
of period	$	143.3	$	62.0

Explanation

Lower cash operating earnings offset by decreased working capital requirements due to collection of income taxes receivable related to U.S. operations in 2001.

In 2002, capital expenditures of $194.6 million relating primarily to construction of Sarnia and the Mexico plants, acquisition of Vision Quest for $41.1 million (less cash acquired of $8.2 million) and acquisition of remaining interest in Southern Cross Energy (SCE) for $7.2 million. In 2001, capital expenditures included the installation of the scrubber at the Centralia plant and construction of the Big Hanaford plant.

In 2002, net increase in short-term debt, offset by $100.0 million debenture maturity, net repayment of commercial paper and cash dividends of $29.5 million.

In 2001, debt issuances of $125.0 million and $169.4 million proceeds on issuance of preferred securities, offset by dividends of $28.7 million and redemption of common shares of $14.2 million.

Explanation

Lower cash operating earnings as a result of the impact of the Wabamun arbitration and prior period regulatory decisions, offset by increased working capital requirements due to the timing of the ancillary revenue settlement ($49.9 million), timing of accounts receivable relating to the Alberta Power Pool for Generation due to deregulation on Jan. 1, 2001 ($170.0 million), and the final instalment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).

In 2002, proceeds on the disposal of the Transmission operation and collection of amounts receivable from Aquila (formerly UtiliCorp) related to the sale of the discontinued Alberta D&R operation in 2000, offset by capital expenditures relating to the construction of the Sarnia, Big Hanaford, Campeche and Chihuahua plants, the acquisition of Vision Quest and the remaining portion of SCE as well as the installation of the scrubber at the Centralia plant during the second quarter.

In 2001, capital expenditures relating primarily to the installation of the scrubber at the Centralia plant and construction of the Sarnia, Big Hanaford and Campeche plants were offset by proceeds on the disposal of the Edmonton Composter, Mildred Lake, Fort Nelson and Fort Saskatchewan plants.

In 2002, the issuance of US$300.0 million in long-term notes offset by the repayment of short- and long-term debt, payment of common share and preferred securities distributions, and repurchase of common shares.

In 2001, net long-term borrowings offset by redemption of preferred shares of a subsidiary, common and preferred share dividends and repurchase of common shares.

:P15

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Q U A R T E R L Y R E P O R T 2 0 0 2

O U T L O O K

The key factors affecting the financial results for 2003 continue to be the megawatt capacity in place, the availability of and production from generating assets, the pricing applicable to non-contracted production, the costs of production, and the volumes traded and margins achieved on Energy Marketing activities.

Generating capacity in 2003 will be higher than in 2002 due to the addition of the 575 MW Sarnia plant which will commence commercial operations in the first quarter of 2003. 55 MW of added capacity at Sarnia is forecasted for 2005. The acquisition of Vision Quest in December 2002 added 44 MW of capacity with a further 37.5 MW scheduled to commence operation in the second quarter of 2003. The 252 MW Campeche and 259 MW Chihuahua plants in Mexico are scheduled to commence commercial operations in the first and third quarters of 2003, respectively. These increases will be partially offset by the shutdown in November 2002 of unit three at the Wabamun facility (147 MW). Availability for 2003 is expected to be similar to 2002, however production is expected to be higher than in 2002 due to the increased capacity.

Electricity spot prices in 2003 are expected to be similar to those in 2002 for the Alberta market and higher in the Pacific Northwest. However, spark spreads (the difference between electricity prices and cost of gas consumed) are expected to compress due to the proportionately higher increase in the cost of natural gas. Expected electricity demand compared to levels of supply is expected to prevent prices from materially increasing over the medium term.

Legislation was passed in Ontario in late 2002 capping retail market prices at $43 per MWh. However, wholesale market prices have not been directly impacted by this decision. Some of the legislation has not yet been clarified and as a result, revenues for merchant capacity at the Sarnia plant may be affected.

Exposure to volatility in electricity prices is substantially mitigated through firm price long-term electricity sales contracts. Exposure to volatility in gas prices is substantially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts. For 2003, approximately 88 per cent of output will be contracted, a significant portion of which relates to the Alberta PPAs which are capacity related based on achieving agreed availability rates. The corporation will continue to focus on the maximization of revenues from these contracts. For non-contracted sales, the historic correlation between natural gas and electricity prices is expected to weaken in 2003, resulting in a compression of spark spreads for non-contracted plants compared to 2002.

TransAlta is continuing its focus on reducing coal costs and ongoing operating (OM&A) expenses. The areas for reductions were identified in the fourth quarter of 2001 and have been, and continue to be, implemented. The benefits of these initiatives are beginning to be realized, and are expected to become fully apparent in 2003 and beyond. However, it is expected there will be more planned maintenance in the Alberta thermal plants in 2003 than in 2002.

Energy Marketing anticipates that short-term markets will continue to be active. Liquidity in the medium- and longer-term markets continues to be low, however there is a need for the types of products offered in these markets and the corporation hopes that additional creditworthy counterparties will begin to emerge and thereby increase liquidity. The financial performance of Energy Marketing activities is expected to be similar to that achieved in 2002.

In 2003, capital expenditures will be approximately $830 million, of which approximately $275 million will be spent on the Genesee Phase three project, described below, approximately $170 million will be spent to complete the two Mexican plants, $60 million on other growth projects and approximately $325 million on maintenance and productivity expenditures as a result of the planned outages and preventative maintenance. Included in the maintenance and productivity expenditures is $25 million in respect of CE Generation LLC (CE Gen), described below. Financing for these expenditures is expected to come from a combination of cash flow from operations, monetization of selected assets, issuance of common shares and the issuance of debt. TransAlta has access to a wide variety of sources of capital including: a $1.5 billion medium-term note program; a US$1.0 billion shelf prospectus; a $1.0 billion commercial paper program; and approximately $2.0 billion of bank credit facilities.

:P16

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Q U A R T E R L Y R E P O R T 2 0 0 2

On Jan. 24, 2003 the corporation announced the acquisition of 50 per cent of the membership interests in CE Gen for US$205.0 million (approximately Cdn$312 million) plus approximately US$35.0 million of working capital (approximately Cdn$53 million) and the assumption of non-recourse debt of approximately US$500.0 million (approximately Cdn$762 million). MidAmerican Energy Holdings Company is the other 50 per cent member of CE Gen. CE Gen, through its subsidiaries, is primarily engaged in the development, ownership and operation of independent power production facilities in the United States utilizing geothermal and natural gas resources. CE Gen has 13 facilities with an aggregate operating capacity of 820 MW. The transaction closed on Jan. 29, 2003.

On Jan. 13, 2003, TransAlta and EPCOR Utilities Inc. (EPCOR) announced an agreement for TransAlta to acquire a 50 per cent interest in EPCOR's Genesee Phase three project for $395.0 million. On the same date, TransAlta paid EPCOR $157.0 million for TransAlta's share of project costs incurred to date. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta. The two corporations will own and share costs for Genesee Phase 3 equally. EPCOR will continue to manage the project's construction and will operate the plant upon commercial operation in early 2005. Both parties will independently dispatch and market their share of the electrical output from the unit through the Alberta Power Pool. Included in the arrangement is an option for EPCOR to purchase a 50 per cent interest in TransAlta's Centennial one project described below. The option expires Dec. 31, 2005. EPCOR also has the option to purchase a 50 per cent interest in TransAlta's Sarnia plant, which may be exercised between January 2003 and March 2004.

In February 2002, the EUB approved the previously announced Centennial project, which is a 900 MW merchant expansion at the Keephills site. Phase one of the project is now part of the arrangement with EPCOR and the two corporations will jointly proceed with the development phase of the project. The decision to construct phase one will be made in sufficient time to ensure that the plant is operational when market conditions are appropriate. EPCOR has an option to participate in the construction and ownership of the project.

TransAlta will continue to focus on exploring strategic acquisitions and additional greenfield opportunities. Growth will only be undertaken to the extent that is affordable and supported by the balance sheet.

On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol. The Kyoto Protocol will have no impact on TransAlta's U.S., Mexican or Australian operations as these countries have not ratified the Protocol. TransAlta is not able to estimate the full impact the Protocol will have on its Canadian operations, as the Canadian government has not yet established an implementation plan. However, the PPAs for TransAlta's coal-fired plants in Alberta contain 'Change in Law' provisions that provide an opportunity to recover compliance costs from the PPA customers. As a member of the Canadian Clean Power Coalition, TransAlta, along with its peers, is exploring other means to reduce greenhouse gas emissions, including the purchase of offset credits. The acquisition of Vision Quest and its prospects for further developments has resulted in the additional amounts of zero-emissions facilities consistent with the strategy of the corporation. Since 1990 the corporation has reduced net emissions by 18 per cent and is on track to reach zero net emissions by 2024.

:P17

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Q U A R T E R L Y R E P O R T 2 0 0 2

T R A N S A L T A C O R P O R A T I O N

C O N S O L I D A T E D S T A T E M E N T S O F E A R N I N G S A N D R E T A I N E D E A R N I N G S

(in millions of Canadian dollars except per share amounts)
		3 months ended Dec. 31				Year ended Dec. 31
		Unaudited			Unaudited			Audited*
		2002		2001	2002			2001

Revenues	$	517.6	$	434.4	$	1,723.9	$	2,319.4
Fuel and purchased power		(226.9)		(246.4)		(703.6)		(1,230.6)

Gross margin		290.7		188.0		1,020.3		1,088.8

Operating expenses
Operations, maintenance and administration		135.1		89.4		420.5		392.2
Depreciation and amortization		62.5		51.8		219.0		191.2
Asset impairment and equipment cancellation charges (Note 6)		152.5		2.7		152.5		118.8
Taxes, other than income taxes		7.6		4.6		27.4		18.7

		357.7		148.5		819.4		720.9

Operating income (loss)		(67.0)		39.5		200.9		367.9
Other income		1.0		1.2		0.1		1.5
Foreign exchange gain		0.9		2.9		1.2		0.8
Net interest expense		(24.0)		(12.4)		(82.7)		(88.1)

Earnings (loss) from continuing operations before regulatory
decisions, income taxes and non-controlling interests		(89.1)		31.2		119.5		282.1
Prior period regulatory decisions (Note 10)		-		11.0		(3.3)		11.0

Earnings (loss) from continuing operations before income taxes
and non-controlling interests		(89.1)		42.2		116.2		293.1
Income tax expense (recovery)		(35.1)		0.5		18.1		89.9
Non-controlling interests		5.6		5.0		20.1		20.6

Earnings (loss) from continuing operations		(59.6)		36.7		78.0		182.6
Earnings from discontinued operations (Note 3)		-		13.3		12.8		45.1
Gain on disposal of discontinued operations (Note 3)		10.0		-		120.0		-

Net earnings (loss)		(49.6)		50.0		210.8		227.7
Preferred securities distributions, net of tax		4.7		3.5		20.9		13.1

Net earnings (loss) applicable to common shareholders	$	(54.3)	$	46.5	$	189.9	$	214.6
Common share dividends		(42.3)		(41.7)		(169.0)		(168.4)
Adjustment arising from normal course issuer bid		-		(14.1)		(27.0)		(34.8)
Retained earnings
Opening balance		928.8		847.6		838.3		826.9

Closing balance	$	832.2	$	838.3	$	832.2	$	838.3


Weighted average common shares outstanding in the period		169.3		168.9		169.6		168.9


Basic earnings (loss) per share
Continuing operations	$	(0.38)	$	0.19	$	0.34	$	1.00
Earnings from discontinued operations		-		0.08		0.07		0.27

Net earnings (loss) from operations		(0.38)		0.27		0.41		1.27
Gain on disposal of discontinued operations, net of tax		0.06		-		0.71		-

Net earnings (loss)	$	(0.32)	$	0.27	$	1.12	$	1.27


Diluted earnings (loss) per share
Earnings (loss) from continuing operations	$	(0.38)	$	0.19	$	0.34	$	0.98
Earnings from discontinued operations		-		0.08		0.07		0.27

Net earnings (loss) from operations		(0.38)		0.27		0.41		1.25
Gain on disposal of discontinued operations, net of tax		0.06		-		0.71		-

Net earnings (loss)	$	(0.32)	$	0.27	$	1.12	$	1.25

See accompanying notes.

* Derived from the audited Dec. 31, 2001 consolidated financial statements.

:P18

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T R A N S A L T A C O R P O R A T I O N
C O N S O L I D A T E D S T A T E M E N T S OF CASH FLOWS
(in millions of Canadian dollars)
			3 months ended Dec. 31				Year ended Dec. 31
			Unaudited			Unaudited		Audited*
			2002		2001	2002		2001

Operating activities
Net earnings		$	(49.6)	$	50.0	$	210.8	$	227.7
Depreciation and amortization			79.7		82.6		314.8		312.3
Asset impairment and equipment cancellation charges			152.5		-		152.5		66.5
Non-controlling interests			5.6		5.0		20.1		20.6
Loss (gain) on sale of property, plant and equipment			12.3		2.1		15.6		(5.4)
Site restoration costs incurred			(3.5)		(4.6)		(15.6)		(14.8)
Future income taxes (recovery)			(43.8)		33.2		(60.4)		39.9
Unrealized (gain) loss from energy marketing activities			(10.9)		6.0		(5.9)		(6.3)
Gain on disposal of Transmission operation	(Note 3)		(10.0)		-		(120.0)		-
Other non-cash items			(17.2)		(0.7)		(24.8)		9.5

			115.1		173.6		487.1		650.0
Change in non-cash operating working capital balances			74.4		(41.9)		(49.4)		65.6

Cash flow from operating activities			189.5		131.7		437.7		715.6

Investing activities
Additions to property, plant and equipment			(194.6)		(419.0)		(945.8)	(1,246.5)
Acquisitions (Note 2)			(40.1)		-		(40.1)		(9.8)
Proceeds on sale of property, plant and equipment to Limited Partnership			-		35.0		-		35.0
Disposals (Note 3)			-		-		818.0		-
Proceeds on sale of property, plant and equipment			2.3		0.2		2.3		201.6
Long-term receivables			(5.4)		20.3		165.3		(46.3)
Long-term investments (Note 5)			-		-		(6.1)		-
Deferred charges and other			(23.2)		(2.6)		(29.8)		(10.9)

Cash flow used in investing activities			(261.0)		(366.1)		(36.2)	(1,076.9)

Financing activities
Net increase (decrease) in short-term debt			289.3		(7.8)		(247.1)		61.9
Issuance of long-term debt			-		125.0		611.3		789.9
Repayment of long-term debt			(149.4)		(0.8)		(454.5)		(292.7)
Redemption of preferred shares of a subsidiary			-		-		-		(122.1)
Issuance of common shares			-		0.1		1.8		14.1
Redemption of common shares			-		(14.2)		(49.9)		(44.4)
Distributions on preferred securities			(8.2)		(6.2)		(34.9)		(23.4)
Dividends on common shares			(29.5)		(28.7)		(115.5)		(149.6)
Net proceeds on issuance of preferred securities			-		169.4		-		169.4
Dividends to subsidiary's non-controlling preferred shareholders			-		-		-		(8.3)
Distributions to subsidiary's non-controlling limited partner			(5.5)		(6.0)		(24.5)		(26.3)
Deferred financing charges and other			-		0.1		(7.6)		0.2

Cash flow from (used in) financing activities			96.7		230.9		(320.9)		368.7

Cash flow from (used in) operating, investing and financing activities			25.2		(3.5)		80.6		7.4
Effect of translation on foreign currency cash			(2.5)		4.0		0.7		0.8

Increase in cash and cash equivalents			22.7		0.5		81.3		8.2
Cash and cash equivalents, beginning of period			120.6		61.5		62.0		53.8

Cash and cash equivalents, end of period		$	143.3	$	62.0	$	143.3	$	62.0

See accompanying notes.

* Derived from the audited Dec. 31, 2001 consolidated financial statements.

:P19

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T R A N S A L T A C O R P O R A T I O N
C O N S O L I D A T E D B A L A N C E SHEETS
(in millions of Canadian dollars)

	Dec. 31,			Dec. 31,
	2002			2001
	Unaudited			Audited*

ASSETS
Current assets
Cash and cash equivalents	$	143.3	$	62.0
Accounts receivable and other		468.4		625.3
Price risk management assets (Note 4)		157.8		137.6
Future income tax assets		18.7		16.9
Income taxes receivable		111.5		128.3
Materials and supplies at average cost		112.7		85.5

		1,012.4		1,055.6

Investments (Note 5)		32.2		37.3
Long-term receivables (Note 7)		39.9		221.4
Property, plant and equipment (Note 3)
Cost		8,124.9		8,766.7
Accumulated depreciation		(2,089.8)		(2,671.9)

		6,035.1		6,094.8
Goodwill (Note 2)		56.5		29.3
Future income tax assets		72.2		15.6
Price risk management assets (Note 4)		60.7		71.3
Other assets		110.6		81.1

Total assets	$	7,419.6	$	7,606.4


LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt	$	290.0	$	537.2
Accounts payable and accrued liabilities		472.2		627.5
Price risk management liabilities (Note 4)		173.8		114.1
Future income tax liabilities		17.1		11.8
Dividends payable		42.9		42.8
Current portion of long-term debt (Note 8)		355.4		104.3

		1,351.4		1,437.7

Long-term debt (Note 8)		2,351.2		2,406.8
Deferred credits and other long-term liabilities		540.2		560.5
Future income tax liabilities		371.9		409.1
Price risk management liabilities(Note 4)		50.6		69.0
Non-controlling interests		263.0		281.0
Preferred securities		451.7		452.6
Common shareholders' equity
Common shares (Note 9)		1,226.2		1,170.9
Retained earnings		832.2		838.3
Cumulative translation adjustment		(18.8)		(19.5)

		2,039.6		1,989.7

Total liabilities and shareholders' equity	$	7,419.6	$	7,606.4


Contingencies (Note 11)

See accompanying notes.
* Derived from the audited Dec. 31, 2001 consolidated financial statements.

:P20

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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

( U N A U D I T E D )

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

1 . A C C O U N T I N G P O L I C I E S

These unaudited interim consolidated financial statements do not include all of the disclosures included in the corporation's annual consolidated financial statements. Accordingly, these unaudited interim consolidated financial statements should be read in conjunction with the corporation's most recent annual consolidated financial statements.

The accounting policies used in the preparation of these unaudited interim consolidated financial statements conform with those used in the corporation's most recent annual consolidated financial statements, except for accounting for goodwill, stock-based compensation, exchange gains and losses on translation of long-term foreign currency denominated monetary items, impairment of long-lived assets and the presentation of energy-trading activities.

Net income and earnings per share for the three and twelve months ended Dec. 31, 2001 adjusted to exclude the amortization of the above amount are as follows:

	3 months ended		Year ended
	Dec. 31, 2001		Dec. 31, 2001

Reported net earnings applicable to common shareholders	$	46.5	$	214.6
Amortization of acquired intangibles		2.3		7.7

Adjusted net earnings applicable to common shareholders	$	48.8	$	222.3


Reported basic earnings per share	$	0.27	$	1.27
Amortization of acquired intangibles per share		0.01		0.05

Adjusted basic earnings per share	$	0.28	$	1.32


Reported diluted earnings per share	$	0.27	$	1.25
Amortization of acquired intangibles per share		0.01		0.05

Adjusted diluted earnings per share	$	0.28	$	1.30

On Jan. 1, 2002, the corporation retroactively adopted the new CICA standard for stock-based compensation. The new standard requires that stock-based payments to non-employees, direct awards of stock and awards that call for settlement in cash or other assets be accounted for using the fair value method of accounting. The fair value method is encouraged for other stock-based compensation plans, but other methods of accounting, such as the intrinsic value method, are permitted. Under the fair value method, compensation expense is measured at the grant date and recognized over the service period. Under the intrinsic value method, compensation expense is determined as the difference between the market price of the underlying stock and the exercise price of the equity instrument granted. If the intrinsic value method is used, disclosure is made of earnings and per share amounts as if the fair value method had been used. The corporation has elected to use the intrinsic value method of accounting for its fixed stock option plans and its performance stock option plan. Accordingly, no compensation cost has been recognized for these plans. The following table provides pro forma measures of net earnings (loss) and earnings (loss) per share had compensation expense been recognized based on the estimated fair value of the options on the grant date in accordance with the fair value method of accounting for stock-based compensation:

:P21

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Q U A R T E R L Y R E P O R T 2 0 0 2

		3 months ended Dec. 31				Year ended Dec. 31
		2002		2001		2002		2001

Reported net earnings (loss) applicable to common shareholders	$	(54.3 )	$	46.5	$	189.9	$	214.6
Compensation expense		1.0		0.5		3.7		2.0

Pro forma net earnings (loss) applicable to common shareholders	$	(55.3 )	$	46.0	$	186.2	$	212.6


Reported basic earnings (loss) per share	$	(0.32 )	$	0.27	$	1.12	$	1.27
Compensation expense per share		0.01		-		0.02		0.01

Pro forma basic earnings (loss) per share	$	(0.33 )	$	0.27	$	1.10	$	1.26


Reported diluted earnings (loss) per share	$	(0.32 )	$	0.27	$	1.12	$	1.25
Compensation expense per share		0.01		-		0.02		0.01

Pro forma diluted earnings (loss) per share	$	(0.33 )	$	0.27	$	1.10	$	1.24

Options were granted only in the first quarter of 2002. The estimated fair value of these stock options was determined using the binomial model using the following assumptions, resulting in a weighted-average fair value of $4.25 per option (2001 - $4.35):

	2002	2001

Risk-free interest rate	5.9%	5.4%
Expected hold period to exercise (years)	7.0	7.0
Volatility in the price of the corporation's shares	28.3%	28.2%

The accounting treatment for the corporation's performance share ownership plan remains unchanged from the year ended Dec. 31, 2001. Under this plan, compensation expense recognized in the three and twelve months ended Dec. 31, 2002 was $1.0 million and $5.3 million, respectively (2001 - $1.2 million and $6.6 million, respectively). Compensation expense is included in operations, maintenance and administration (OM&A) in the statements of earnings. Effective Jan. 1, 2003, TransAlta has elected to account for stock-based compensation in accordance with the fair value method, and will expense stock-based compensation in respect of stock options on a prospective basis.

The CICA has amended its standard on the recognition, measurement, and disclosure of the impairment of long-lived assets. This standard is effective April 1, 2003 and requires that an impairment loss be recognized when the carrying amount of a long-lived asset exceeds the sum of the undiscounted cash flows expected from its use and eventual disposition. The impairment loss is measured as the amount that the long-lived asset's carrying value exceeds its fair value. TransAlta early adopted this standard in the fourth quarter of 2002. In accordance with the standard, the impairment calculation for the Wabamun plant resulted in the recognition of an impairment loss of $110.0 million, which is included in asset impairment and equipment cancellation charges in the statements of earnings.

:P22

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Q U A R T E R L Y R E P O R T 2 0 0 2

In the third quarter of 2002, in response to changes in accounting standards in the U.S. with respect to energy trading activities, the corporation has adopted a policy that all gains and losses on energy trading contracts be shown in the statement of earnings. Consistent with these recommendations, the corporation has chosen to disclose the gross transaction volumes of those energy trading contracts that are physically settled.

TransAlta's results are seasonal in nature due to the nature of the electricity market and related fuel costs.

2 . A C Q U I S I T I O N S

On Dec. 6, 2002, the corporation completed a step acquisition of Vision Quest Windelectric Inc. (Vision Quest). The initial steps resulted in 41 per cent ownership of Vision Quest for $13.5 million, accounted for using the equity method. Book values approximated fair values. The final step brought TransAlta's ownership to 100 per cent and TransAlta's total investment in Vision Quest to $68.8 million. The results of Vision Quest's operations have been included in the corporate segment of the consolidated financial statements since the date of acquisition. Vision Quest owns and operates 67 wind power turbine power plants with a total capacity of 44 MW with a further 37.5 MW under construction.

The aggregate purchase price includes the previous investments of $13.5 million, plus $21.3 million of cash and 745,791 common shares valued at $14.2 million. In addition, a loan of $19.8 million was previously advanced to Vision Quest. The value of the common shares issued was determined based on the average market price of TransAlta's common shares for the five days before and after the terms of the acquisition were agreed to and announced. 136,287 of the shares will be issued over the next three years.

The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition. Due to the timing of the purchase, it was impractical to complete the allocations process satisfactory without causing undue delay in issuing the financial statements for the period in which the combination occurred. Therefore, the purchase price allocation was prepared based on the best allocations that could be made in the time available and, if necessary, the allocations in the purchase equation may be adjusted when the process is completed in the first quarter of 2003.

Net assets acquired at assigned values:
Working capital, including cash of $8.2 million	$	6.5
Property, plant and equipment		70.1
Goodwill		27.2
Power Purchase Arrangement		2.5
Short-term debt		(32.2)
Future income tax liability		(4.7)
Interest rate swaps		(0.6)

Total	$	68.8


Consideration:
Initial investments	$	13.5
Cash, including previous advances of $19.8 million		41.1
Common shares		14.2

Total	$	68.8

On Dec. 6, 2002, the corporation purchased the remaining 15 per cent interest in the Southern Cross Energy Partnership, located in western Australia, for AUD$8.5 million (Cdn$7.2 million). At the time of acquisition, book values approximated fair values.

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3 . D I S C O N T I N U E D O P E R A T I O N S

On July 4, 2001, the corporation signed a purchase and sale agreement for the disposal of its Transmission operation. Regulatory approval was received on March 28, 2002. On April 29, 2002, the Transmission operation was sold for proceeds of $820.7 million, of which $818.0 million has been collected. The proceeds excluded accounts receivable of $31.7 million, which were retained and collected by TransAlta, and accounts payable of $4.4 million. The disposal resulted in a final gain on sale of $120.0 million ($0.71 per common share), net of income taxes of $32.9 million. The previously reported gain included a number of estimates, therefore the gain was adjusted in the fourth quarter of 2002 to reflect agreed working capital adjustments and actual amounts paid and received.

For reporting purposes, the results of the Transmission operation have been presented as discontinued operations in the statement of earnings.

					2002		2001
3 months ended Dec. 31					Transmission		Transmission

Revenues					$	-	$	42.8
Operating expenses						-		(19.1)

Operating income						-		23.7
Net interest expense						-		(0.6)

Earnings before income taxes						-		23.1
Income taxes						-		9.8

Earnings before gain on disposal						-		13.3
Gain on disposal						10.0		-

Earnings from discontinued operations					$	10.0	$	13.3



		2002				2001
					Edmonton
Year ended Dec. 31	Transmission		Transmission		Composter			Total

Revenues	$	55.8	$	171.1	$	6.6	$	177.7
Operating expenses		(30.8)		(84.6)		(5.4)		(90.0)

Operating income		25.0		86.5		1.2		87.7
Net interest expense		(2.4)		(9.7)		-		(9.7)

Earnings before income taxes		22.6		76.8		1.2		78.0
Income taxes		9.8		32.4		0.5		32.9

Earnings before gain on disposal		12.8		44.4		0.7		45.1
Gain on disposal		120.0		--		-		-

Earnings from discontinued operations	$	132.8	$	44.4	$	0.7	$	45.1

At Dec. 31, 2002, all of the corporation's discontinued operations had been sold. At Dec. 31, 2001, all of the corporation's discontinued operations had been sold with the exception of the Transmission operation. Balance sheet amounts are as follows:

	Dec. 31, 2002		Dec. 31, 2001

Current assets	$	-	$	36.1
Capital assets		-		637.5
Other assets		-		3.3
Current liabilities		-		(15.5)

Net assets	$	-	$	661.4

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4 . P R I C E R I S K M A N A G E M E N T A S S E T S A N D L I A B I L I T I E S

The Energy Marketing group uses energy derivatives, including physical and financial swaps, forwards and options to optimize returns from assets, earn trading revenues and gain market information. Energy contracts that meet the definition of a derivative in FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities, are accounted for at fair value in accordance with Canadian and U.S. generally accepted accounting principles (GAAP). Derivatives are used to hedge the corporation's exposure to changes in electricity and natural gas prices. Under Canadian GAAP, settlement accounting is used for hedging activities if certain criteria are met. Under U.S. GAAP, hedging activities are accounted for in accordance with FASB Statement 133.

	Dec. 31, 2002		Dec. 31, 2001


Price risk management assets
Current	$	157.8	$	137.6
Long-term		60.7		71.3
Price risk management liabilities
Current		(173.8)		(114.1)
Long-term		(50.6)		(69.0)

	$	(5.9)	$	25.8

The following table illustrates movements in the fair value of the corporation's price risk assets and liabilities during the year ended Dec. 31, 2002:

Fair value of net price risk management assets outstanding at Dec. 31, 2001	$	25.8
Fair value of new contracts entered into during the period		(2.7)
Changes in fair values attributable to market price and other market changes		7.6
Contracts realized or settled during the period		(36.6)
Changes in fair values attributable to changes in valuation techniques and assumptions		-

Fair value of net price risk management liabilities outstanding at Dec. 31, 2002	$	(5.9)

The source of the valuations of the above contracts and maturities over each of the next five calendar years and thereafter is as follows:

											2008 and
		2003		2004		2005		2006		2007	thereafter			Total

Prices actively quoted	$	(17.6)	$	3.3	$	3.2	$	2.1	$	1.5	$	-	$	(7.5)
Prices based on models		1.6		-		-		-		-		-		1.6

Asset (liability)	$	(16.0)	$	3.3	$	3.2	$	2.1	$	1.5	$	-	$	(5.9)

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5 . I N V E S T M E N T S

In January 2002, an additional $2.9 million was invested in Vision Quest. In December 2002, the corporation purchased the remaining interest in Vision Quest as described in Note 2.

In April 2002, an additional $2.5 million was invested in a distributed generation company. This investment is accounted for using the equity method.

In April 2002, an initial $0.2 million was invested in a biomass generation company. An additional $0.5 million was invested in September 2002. The investment is accounted for using the cost method.

A foreign exchange revaluation of $1.9 million occurred during the twelve months ended Dec. 31, 2002 on the investment in the Australian gas transmission pipeline.

6 . A S S E T I M P A I R M E N T A N D E Q U I P M E N T C A N C E L L A T I O N C H A R G E S

After a detailed engineering assessment, a review of environmental issues and a review of short- and long-term market forecasts, the corporation decided to implement a phased decommissioning of its 569 MW coal-fired Wabamun facility in November 2002. As a result of this decision, the corporation recorded an impairment charge of $110.0 million during the quarter. The impairment charge was calculated as the excess of carrying value over fair value. The fair value of the facility was determined by estimating the present value of future cash flows.

In November 2002, the corporation cancelled orders for four natural gas turbines and as a result recorded a cancellation charge of $42.5 million for contract termination costs. The costs consist of progress payments made to date.

In September 2001, the corporation monetized its investment in the 154 MW Pierce Power plant, resulting in the recognition of revenue of $121.8 million, an impairment charge of $66.5 million and $52.3 million in anticipated future operating costs.

7 . L O N G - T E R M R E C E I V A B L E S

In August 2002, the remaining $180.3 million due from Aquila Networks Canada (formerly UtiliCorp Networks Canada) that arose from the August 2000 sale of the discontinued Alberta Distribution and Retail operation was collected in full.

The net California accounts receivable of US$24.2 million has been reclassified to long-term receivables, as collection is no longer expected in 2003, although ultimate collection of the net receivable is expected.

On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that TransAlta be entitled to receive approximately US$44.0 million for electricity sales to California. However, FERC has proposed further adjustments in respect of power and gas prices, which could result in further adjustments to the amount to be received by TransAlta. Until a final ruling is made with respect to these issues, TransAlta will maintain the provision for these receivables.

8 . L O N G - T E R M D E B T

On June 20, 2002, the corporation issued debt of US$300.0 million under a US$1.0 billion shelf prospectus filed

May 14, 2002. The notes are unsecured and bear interest at 6.75 per cent, and mature on July 15, 2012. Net proceeds on the issuance were $456.9 million.

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9 . C O M M O N S H A R E S I S S U E D A N D O U T S T A N D I N G

TransAlta Corporation is authorized to issue an unlimited number of voting common shares without nominal or par value. At Dec. 31, 2002, the corporation had 169.8 million (Dec. 31, 2001 - 168.3 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.2 million shares (Dec. 31, 2001 - 2.8 million).

In February 2002, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation. For the year ended Dec. 31, 2002, 2.0 million common shares had been repurchased under the normal course issuer bid.

On Dec. 6, 2002, the corporation issued 609,504 common shares as a portion of the aggregate purchase price of Vision Quest (Note 2).

1 0 .. P R I O R P E R I O D R E G U L A T O R Y D E C I S I O N S

Financial results for 2002 were affected by Alberta Energy and Utilities Board (EUB) decisions related to other reporting periods. The impact of such regulatory decisions is recorded when the effect of such decisions is known, without adjustment to the financial statements of prior periods.

On April 16, 2002, the EUB rendered a negative decision of $3.3 million pre-tax with respect to TransAlta's hydro bidding strategy in 2000.

In December 2001, the EUB ruled that the Wabamun unit four outage qualified for relief under the Temporary Suspension Regulation (TSR) and ordered that TransAlta would receive $11.0 million ($7.0 million after-tax) to compensate the corporation for obligation payments incurred in 2000 as a result of the outage.

1 1 .. C O N T I N G E N C I E S

In August 2000, a single thermal generating unit at the Wabamun plant was shut down due to safety concerns related to possible corrosion fatigue cracks within the waterwall tubing of its boiler. Repairs were completed late in the second quarter of 2001 and the unit returned to service in June 2001.

Since Jan. 1, 2001, the unit has been subject to the terms of a power purchase arrangement (PPA). Under the PPA's force majeure article, the corporation is not obligated to supply electricity during the period of repair, subject to confirmation by the administrator of the PPAs. Had such confirmation not occurred, the corporation would have been obligated to pay a penalty equal to the cost of obtaining an alternative source of electricity to fulfill its PPA supply obligations during the affected period. The force majeure decision went to arbitration in July 2001. On May 23, 2002, the arbitrators confirmed in their ruling that the outage qualified as a force majeure event, but also ruled that the corporation should have returned the unit to service more quickly. As a result of the decision, the corporation was required to pay $38.9 million plus interest of $2.7 million, all pre-tax. The payment was recorded as reduction to revenue.

On May 8, 2002, FERC requested that 150 sellers of wholesale electricity and ancillary services to the California electricity market, including TransAlta, respond to questions regarding their trading strategies in California during 2000 and 2001. TransAlta has responded to the FERC request and believes it operated in accordance with all applicable laws, rules, regulations and tariffs.

On May 21 and 22, 2002, FERC issued two additional requests for information regarding 'round-trip' trading activities, to which TransAlta responded, stating that the corporation does not believe it participated in any round-trip trades during 2000 and 2001. In addition, Reliant Energy Inc. issued a statement that it engaged in round-trip trades in 1999 with Merchant Energy Group of the Americas, Inc. (MEGA). TransAlta acquired an initial 50 per cent interest in MEGA in June 2000, and acquired the remaining 50 per cent in June 2001. TransAlta contends that no round-trip trading occurred between Reliant Energy Inc. and MEGA during any period in which TransAlta had an ownership interest in MEGA. TransAlta will continue to cooperate with the regulators and supply all information requested.

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On May 30, 2002, the California Attorney General's Office (CAGO) filed civil complaints in the state court of California against eight additional wholesale power companies, including TransAlta. The complaint alleges violations of California's unfair business practices law in connection with rates charged for wholesale electricity sales. TransAlta believes that it has complied with applicable laws in regard to this complaint. In particular, the company is of the view that the basis of the complaint is a matter of federal rather than state jurisdiction. FERC has previously rejected allegations made by CAGO that TransAlta's subsidiaries violated rate filing requirements. On June 26, 2002, TransAlta filed a Notice of Motion to dismiss the complaint.

On Sept. 9, 2002, the Commodities Futures Trading Commission requested information on similar issues. TransAlta has provided the requested information.

On Dec. 16 and 20, 2002, two class action lawsuits on behalf of all persons and businesses in the states of Oregon and Washington were initiated in respect of alleged unlawful practices in the purchase and sale of wholesale energy. TransAlta believes these are without merit and will vigorously defend its actions. No amount has been accrued in these financial statements as neither the amount of the claim nor the outcome was determinable at the reporting date.

On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol. The Kyoto Protocol will have no impact on TransAlta's U.S., Mexican or Australian operations as these countries have not ratified the Protocol. TransAlta is not able to estimate the full impact the Protocol will have on its Canadian operations, as the Canadian government has not yet established an implementation plan. However, the PPAs for TransAlta's coal-fired plants in Alberta contain 'Change in Law' provisions that provide an opportunity to recover compliance costs from the PPA customers. As a member of the Canadian Clean Power Coalition, TransAlta, along with its peers, is exploring other means to reduce greenhouse gas emissions, including the purchase of offset credits. The acquisition of Vision Quest and its prospects for further development has resulted in additional amounts of zero-emissions facilities consistent with the strategy of the corporation. Since 1990, the corporation has reduced net emissions in Canada by 18 per cent and is on track to reach zero net emissions by 2024.

1 2 .. C O M P A R A T I V E F I G U R E S

Certain comparative figures have been reclassified to conform with the current period's presentation.

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1 3 .. S E G M E N T E D D I S C L O S U R E S

Effective Jan. 1, 2002, the Generation and Independent Power Projects business segments were combined into one Generation segment to reflect changes in TransAlta's organizational structure. Prior period amounts have been reclassified.

I. Earnings information
				Unaudited
			Energy
*3 months ended Dec. 31, 2002*	Generation		Marketing		Corporate			Total

Revenues	$	498.7	$	992.4	$	1.0	$	1,492.1
Trading purchases		-		(974.5)		-		(974.5)

Net segment revenues		498.7		17.9		1.0		517.6
Fuel and purchased power		(226.9)		-		-		(226.9)

Gross margin		271.8		17.9		1.0		290.7
Operations, maintenance and administration		115.3		3.6		16.2		135.1
Depreciation and amortization		57.4		0.5		4.6		62.5
Asset impairment and equipment cancellation charges (Note 6)		152.5		-		-		152.5
Taxes, other than income taxes		7.6		-		-		7.6

EBIT before corporate allocations		(61.0)		13.8		(19.8)		(67.0)
Corporate allocations		(18.1)		(2.3)		20.4		-

EBIT	$	(79.1)	$	11.5	$	0.6		(67.0)

Other income								1.0
Foreign exchange gain								0.9
Net interest expense								(24.0)

Earnings from continuing operations before income taxes and non-controlling interests							$	(89.1)



				Unaudited
				Energy
3 months ended Dec. 31, 2001	Generation		Marketing		Corporate			Total

Revenues	$	431.8	$	526.9	$	-	$	958.7
Trading purchases		-		(524.3)		-		(524.3)

Net segment revenues		431.8		2.6		-		434.4
Fuel and purchased power		(246.4)		-		-		(246.4)

Gross margin		185.4		2.6		-		188.0
Operations, maintenance and administration		68.7		1.6		19.1		89.4
Depreciation and amortization		41.4		4.0		6.4		51.8
Asset impairment and equipment cancellation charges (Note 6)		2.7		-		-		2.7
Taxes, other than income taxes		4.6		-		-		4.6
Prior period regulatory decisions (Note 10)		(11.0)		-		-		(11.0)

EBIT before corporate allocations		79.0		(3.0)		(25.5)		50.5
Corporate allocations		(23.6)		(1.9)		25.5		-

EBIT	$	55.4	$	(4.9)	$	-		50.5

Other income								1.2
Foreign exchange gain								2.9
Net interest expense								(12.4)

Earnings from continuing operations before income taxes and non-controlling interests							$	42.2

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Earnings information
						Unaudited
					Energy
*Year ended Dec. 31, 2002*			Generation		Marketing		Corporate			Total

Revenues			$	1,673.9	$	3,703.8	$	1.0	$	5,378.7
Trading purchases				-		(3,654.8)		-		(3,654.8)

Net segment revenues				1,673.9		49.0		1.0		1,723.9
Fuel and purchased power				(703.6)		-		-		(703.6)

Gross margin				970.3		49.0		1.0		1,020.3
Operations, maintenance and administration				346.3		15.1		59.1		420.5
Depreciation and amortization				196.3		2.5		20.2		219.0
Asset impairment and equipment cancellation charges		(Note 6)		152.5		-		-		152.5
Taxes, other than income taxes				27.3		0.1		-		27.4
Prior period regulatory decisions (Note 10)				3.3		-		-		3.3

EBIT before corporate allocations				244.6		31.3		(78.3)		197.6
Corporate allocations				(70.6)		(8.3)		78.9		-

EBIT			$	174.0	$	23.0	$	0.6		197.6

Other income										0.1
Foreign exchange gain										1.2
Net interest expense										(82.7)

Earnings from continuing operations before income taxes and non-controlling interests									$	116.2



						Audited
						Energy
Year ended Dec. 31, 2001			Generation		Marketing		Corporate			Total

Revenues			$	2,158.4	$	2,694.7	$	-	$	4,853.1
Trading purchases				-		(2,533.7)		-		(2,533.7)

Net segment revenues				2,158.4		161.0		-		2,319.4
Fuel and purchased power				(1,230.6)		-		-		(1,230.6)

Gross margin				927.8		161.0		-		1,088.8
Operations, maintenance and administration				290.6		36.2		65.4		392.2
Depreciation and amortization				156.5		11.0		23.7		191.2
Asset impairment and equipment cancellation charges		(Note 6)		118.8		-		-		118.8
Taxes, other than income taxes				18.7		-		-		18.7
Prior period regulatory decisions (Note 10)				(11.0)		-		-		(11.0)

EBIT before corporate allocations				354.2		113.8		(89.1)		378.9
Corporate allocations				(82.5)		(6.6)		89.1		-

EBIT			$	271.7	$	107.2	$	-		378.9

Other income										1.5
Foreign exchange gain										0.8
Net interest expense										(88.1)

Earnings from continuing operations before income taxes and non-controlling interests									$	293.1




II. Selected balance sheet information
				Energy			Discontinued
*Dec. 31, 2002 (unaudited)*	Generation		Marketing		Corporate		Operations			Total

Goodwill	$	-	$	29.3	$	27.2	$	-	$	56.5
Other assets		6,353.4		315.3		694.4		-		7,363.1

Total segment assets	$	6,353.4	$	344.6	$	721.6	$	-	$	7,419.6


Dec. 31, 2001 (audited)

Goodwill	$	-	$	29.3	$	-	$	-	$	29.3
Other assets		5,873.2		384.0		643.0		676.9		7,577.1

Total segment assets	$	5,873.2	$	413.3	$	643.0	$	676.9	$	7,606.4

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III. Selected cash flow information
			Energy				Discontinued
*3 months ended Dec. 31, 2002*	Generation		Marketing		Corporate		Operations				Total

Capital expenditures	$	190.8	$	2.1	$	1.7	$	-	$		194.6

3 months ended Dec. 31, 2001

Capital expenditures	$	415.5	$	2.0	$	(6.3)	$	7.8	$		419.0

*Year ended Dec. 31, 2002*

Capital expenditures	$	909.1	$	4.2	$	10.7	$	21.8	$		945.8

Year ended Dec. 31, 2001

Capital expenditures	$	1,147.6	$	43.8	$	15.1	$	40.0	$	1,246.5


IV. Reconciliation
Depreciation and amortization (D&A) expense per statement of cash flows
			3 months ended Dec. 31				12 months ended Dec. 31
				2002		2001		2002			2001

D&A expense for reportable segments			$	62.5	$	51.8	$	219.0	$		191.2
Discontinued operations				-		12.9		15.6			46.5
Mining equipment depreciation, included in fuel and purchased power				9.3		7.0		37.1			31.8
Site restoration accrual, included in fuel and purchased power				7.7		9.1		38.9			37.3
Other				0.2		1.8		4.2			5.5

			$	79.7	$	82.6	$	314.8	$		312.3

1 4 .. U N I T E D S T A T E S G E N E R A L L Y A C C E P T E D A C C O U N T I N G P R I N C I P L E S

These interim consolidated financial statements have been prepared in accordance with Canadian GAAP and follow the same accounting policies and methods of computation as, and should be read in conjunction with, the most recent annual financial statements.

In connection with the corporation's May 12, 2002 shelf debt prospectus, TransAlta is required to reconcile these interim consolidated financial statements to U.S. GAAP. This reconciliation will be included with the corporation's annual report, and it shall be deemed to be incorporated by reference into these interim consolidated financial statements.

1 5 .. S U B S E Q U E N T E V E N T S

On Jan. 13, 2003, TransAlta and EPCOR Utilities Inc. (EPCOR) announced an agreement whereby TransAlta will acquire a 50 per cent interest in EPCOR's Genesee Phase three project for $395.0 million. On the same date, TransAlta made a $157.0 million payment to EPCOR for TransAlta's share of project costs incurred to date. A 450 MW addition to the existing Genesee Generating station is currently under construction and expected to commence commercial operations in early 2005. Included in the arrangement is an option for EPCOR to puchase a 50 per cent interest in TransAlta's Centennial one project, formerly referred to as Keephills three. The option expires Dec. 31, 2005. EPCOR also has the option to purchase a 50 per cent interest in TransAlta's Sarnia plant, which may be exercised between January 2003 and March 2004.

On Jan. 24, 2003, the corporation announced the acquisition of 50 per cent of the membership interests in CE Generation LLC (CE Gen) for US$205.0 million (approximately Cdn$312 million) plus approximately US$35.0 million (approximately Cdn$53 million) and the assumption of debt of approximately US$500.0 million (approximately Cdn$762 million). The acquisition will be accounted for using the purchase method of accounting. CE Gen is controlled jointly by TransAlta and MidAmerican Energy Holdings Company. As such, the financial results of CE Gen will be proportionately consolidated with those of TransAlta. The transaction closed on Jan. 29, 2003.

:P31

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TransAlta Corporation

(Registrant)

By:/s/ Alison T. Love

(Signature)

Alison T. Love, Corporate Secretary

Date: January 31, 2003

CERTIFICATIONS

I, Stephen G. Snyder, certify that:

I have reviewed this Report of Foreign Private Issuer on Form 6-K of TransAlta Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the “Evaluation Date”); and

c) presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weakness in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

The registrant's other certifying officer and I have indicated in this report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date:

January 31, 2003

/s/ Stephen G. Snyder

Stephen G. Snyder

President and Chief Executive Officer

I, Ian Bourne, certify that:

I have reviewed this Report of Foreign Private Issuer on Form 6-K of TransAlta Corporation;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this report (the “Evaluation Date”); and

c) presented in this report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Date: January 31, 2003

/s/ Ian Bourne

Ian Bourne

Executive Vice President and Chief Financial Officer